Water Resources and Natural Gas Production from the Marcellus Shale
Daniel J. Soeder Hydrologist U.S. Geological Survey So who is Dan Soeder, and what does he know about shale? • I grew up in northeastern Ohio, in the Devonian shale outcrop area.
• BS degree 1976 and MS degree in 1978, both in geology
• Field/laboratory work on DOE Eastern Gas Shales Project from 1979- 1981 in Morgantown, WV
• Unconventional natural gas supply research at the Institute of Gas Technology in Chicago, including tight gas sand, coal bed methane, and Devonian shale: 1981-1990
• Hydrology/environmental science, U.S. Geological Survey: geology and hydrology of Yucca Mountain, NV: 1990-1998; MD-DE-DC Water Science Center: 1998-present
• This talk: Overview of natural gas resources and eastern gas shales; historical studies of shale gas potential; current interest in the Marcellus Shale; water-resource concerns; research needs; questions and discussion NATURAL GAS RESOURCES
Most natural gas is currently recovered from secondary deposits concentrated in conventional oil and gas fields. “Unconventional natural gas” • coalbed methane • western tight gas sands • eastern gas shales • secondary gas recovery • geopressured deep gas
Unconventional = more abundant = more difficult = more $$ Other kinds of gas: • biofuel methane • coal gasification • hydrogen Conventional Petroleum Geology
1. Source rock: 1-2% organics (kerogen) a) Types I and II kerogen form petroleum and natural gas b) Type III kerogen forms coal and natural gas
2. Thermal maturation: heat and pressure over geologic time 3. Reservoir rock – high porosity and permeability 4. Migration pathway from source to reservoir 5. Seal and Trap – structural or stratigraphic
Thermal Maturity: Low: wet gas, lignite Medium: gas, oil, bituminous coal High: dry gas, anthracite
Resource Distribution Examples Eastern Gas Shales
Devonian-age shales occur in the Appalachian, Michigan and Illinois Basins in the eastern United States. Shale is a rock formed from mud deposited in a low water-energy environment. Shale gas has been produced for over a century, but generally slowly and in small quantities. Eastern Gas Shales Project (1976 to 1981) U.S. Department of Energy investigation of this resource. The EGSP recovered 17,000 feet of Devonian Shale drill core, and engineered tests in 63 wells.
Cleveland Shale exposure along Tinkers Creek, Ohio Eastern Gas Shales Project
Appalachian Basin Devonian Stratigraphy Natural Gas from Shale
• Shale comes in two types: organic- rich (black) and organic lean (gray). • Shale porosity is typically around 10%, but permeability is very low. • In order to produce gas from these rocks, a well must connect to higher permeability pathways, such as natural or artificial fractures. • Creating artificial fractures in a rock formation is called “stimulation.” Shale gas engineering in 1979
- Black shales + fractures = gas - EGSP characterized shale cores for fractures, and developed new stimulation technology - Stimulations were focused on intercepting natural fractures. EGSP Gas Production Concepts
Gas 3 > Gas 2 > Gas 1
Hydrofractures from vertical wells are limited to about 1000 ft in length
It is difficult to intercept natural fractures with hydrofractures Results of the EGSP Study
• Analysis of 95 stimulations carried out in 63 wells reported in 1982 by Andrea Horton, U.S. Department of Energy
• DOE tried: – Massive hydraulic fracturing (100,000 gallons +) – Conventional hydraulic fracturing – Foam fracturing with nitrogen – Cryogenic fracturing with liquid CO2 – Explosives of several designs – Gas fracturing with pressurized nitrogen – Fracturing using oil assisted with nitrogen – Hydraulic fracturing using kerosene
• Conclusions: – “Stimulation alone is insufficient to achieve commercial shale gas production.” – Cleanup is difficult with some of the treatments – Better success could be obtained by targeting specific formations in specific locations The IGT Investigation
• In the mid 1980’s, the Institute of Gas Technology in Chicago (now called GTI) carried out a petrophysical investigation of eastern gas shale rock properties.
• Petrophysical data on shale are difficult to collect because of the low porosity and very low permeability.
• Nothing had been published in the literature.
• A precision core testing apparatus developed for tight gas sands and coal bed methane was used for testing shale.
• Seven samples of the Huron Member of the Ohio Shale, and one sample of Marcellus Shale were analyzed for gas porosity and permeability using nitrogen and methane as test gases.
• Confining pressures and differential pressures were varied to simulate a range of in-situ conditions. IGT Eastern Gas Shale Samples
EGSP cores had been shipped to various state geological surveys.
Shale cores were hard to find, and many had deteriorated.
Most available cores were from the western part of the basin.
Operation of the Permeameter Ohio Shale gas permeability Ohio Shale liquid phase
Capillary blockage by oil in these shales prevents gas from flowing easily through the pores.
Some gray shales in Ohio under black shales appear to be gas-productive. Composition typical of light, paraffinic petroleum Marcellus Shale
IGT analyzed ONE sample of Marcellus Shale core from ONE well in West Virginia.
A solvent extraction GC showed that the Marcellus core sample contained no oil.
Porosity was measured with nitrogen gas and also with methane gas.
Permeability was measured at pore pressures and net confining pressures approximating conditions at the depth of the core.
IGT was never funded to repeat the analyses, or to run any other samples of Marcellus. IGT Marcellus Petrophysical Data
200 100 50 200 100 66 50 Marcellus Gas-in-Place
Empirical function fit: vol/vol/psi=(0.224)p1/2 Reservoir pressure in WV-6 = 3500 psi Findings published by Society of Petroleum Engineers in SPE Formation Evaluation, March, 1988
“…the measured initial reservoir pressure of the Marcellus Shale in EGSP Well WV-6 was 3500 psi…(which) results in a potential in-situ gas content of 26.5 scf/ft3…”
National Petroleum Council had previously assessed the gas potential of Appalachian Basin shales at 0.1 to 0.6 scf/ft3
Who was excited about this in 1988? Hardly anyone but me…
Shale gas engineering in 1989
Not all fractured black shales will produce gas.
Not all shale gas is produced by black shales.
However, some black shales have enormous gas potential.
Stimulations should be targeted to specific formations and locations. FAST FORWARD 20 YEARS: GAS PRODUCTION FROM THE MARCELLUS SHALE IN 2009
Why all the interest now? How to move down the Resource Triangle
Economics: External economic conditions may increase the price of conventional resources, making the unconventional resource more cost-competitive.
Engineering: New technology might be developed that exploits the resource more efficiently, making it competitive with cheaper conventional resources. Better Economics
The wellhead price of natural gas was under $2.00 per 1000 cubic feet (MCF) around 1980. In July 2008, natural gas reached a peak of $10.82 per MCF. The economic downturn caused gas to drop to $5.15 per MCF in January 2009; still higher than the 1990s. Better Engineering
Horizontal drilling and hydraulic fracturing, developed for the Barnett Shale in Texas, have greatly increasing gas production from shale wells.
Range Resources found the 1988 SPE paper, and decided to try applying the Barnett technology to the Marcellus Shale in 2005.
At 80-acre spacings, these wells may produce 4 MMCF/day.
Production costs are reported to be $1.00/MCF
Visit http://www.pamarcellus.com/ to see the drilling process video Marcellus Gas Estimates • January, 2008: Engelder (Penn State) and Lash (SUNY-Fredonia) estimated 500 TCF of gas in the Marcellus, with 50 TCF recoverable.
• Note: one trillion cubic feet is considered to be a significant gas field.
• November, 2008: Based on Chesapeake Energy production data, Terry Engelder revised Marcellus estimate to 363 TCF recoverable.
• The Marcellus play has the potential to be the biggest gas field in the United States (Range Resources)
• Marcellus Shale could contain enough gas to meet the entire nation’s natural gas supply needs for 15 years (@ 23 MMCF/yr). Marcellus Shale Thickness
From Milici, 2005 Western Maryland
• Significant acreage has been leased for drilling. • Marcellus Shale is present in the subsurface throughout Garret Co. • The Marcellus also underlies much of Allegany County. • There is a gas storage field and transmission pipeline at Accident.
Hamilton Group > Future gas demand
• Energy Independence: – Natural gas is an abundant domestic resource. – Expensive to import; must cross oceans as a cryogenic liquid – Most efficiently transmitted over land through a gas pipeline.
• Infrastructure: A nationwide infrastructure for natural gas already exists, unlike other resources such as hydrogen or ethanol.
• Greenhouse Gas Reduction and Air Quality Improvements:
– Gas is the cleanest fossil fuel in terms of emissions (CH4 + 2O2= CO2+2H2O), also has lowest carbon dioxide emission per BTU of any hydrocarbon fuel. – CNG is a bridge fuel to offset imported oil for transportation needs - western Canada has used CNG vehicles since the 1980’s, and the technology is well-developed. – Natural gas is far lower in carbon emissions per kilowatt hour for electrical generating than any coal or “clean coal” technology. WATER-RESOURCE CONCERNS
Marcellus Shale natural gas drilling operations Hydraulic Fracturing • Hydraulic fracturing as a production technique for gas and oil has been around since the 1950’s.
• A hydrofrac is used to create high-permeability pathways into a formation.
• Low rates of gas flow per unit area can be gathered up by a natural and artificial fracture network and transported to a well.
• Hydraulic fractures are created by filling the well with fluid and increasing the pressure until the rock strength is exceeded.
• The orientation of the fracture generally follows pre-existing planes of weakness along the direction of greatest extension – in other words, parallel to the natural fractures.
• Horizontal wells can be drilled perpendicular to the strike of the natural fractures and intercept them. Water Sources
• Water for hydraulic fracturing has been taken from streams, lakes and ground-water wells.
• The Barnett Shale production in Texas generally uses ground water from the Trinity aquifer.
• One Barnett Shale well uses approximately 3 million gallons of water. About 2.6 billion gallons (or 8,000 acre-feet) of water were used in 2005 for Barnett Shale hydrofracs. Susquehanna River below Conowingo Dam
• Hydrofrac water does not have to be finished quality. Virtually any raw water will work, including treated wastewater. Sustainable Drilling • In the spring of 2008, a consortium of energy companies formed the Appalachian Shale Water Conservation and Management Committee (ASWCMC).
• This group engaged the Gas Technology Institute (GTI) to develop best management practices for shale gas drilling in the Appalachian Basin.
• Goal was to work cooperatively with regulatory agencies to ensure that water resources were managed in an efficient and environmentally responsible manner.
• Approach was to: – determine current and future water needs in production areas – develop water quality specifications for drilling and hydrofracs – identify technologies that provide solutions for water management and water conservation. Hydrofracture Logistics
• It can require 3 to 4 million gallons of water to fracture a well.
• The needed water must be transported to the drill site.
• Proppant (sand) and chemical additives must also be transported to the drill site.
• Many drill pads are in remote locations, only accessible by unimproved rural roads.
• Small watersheds and headwater streams may be at risk from erosion, sedimentation and spills. Marcellus Shale hydrofrac : at least 150 pieces of heavy equipment on site Fracture fluids
The fracture fluid contains proppant, usually sand, designed to keep the fracture open after the pressure is released and the fluid recovered.
Proprietary chemicals called “cross-linked gels” are added to the fracture fluid to increase the viscosity so proppant will be carried into the fracture.
The gels are designed to break down after a short time period, usually hours, to allow the fluid to be recovered from the well. Components of Hydrofrac Fluid
A 3 million gallon hydrofrac with 0.44% additives will contain over 13,000 gallons of chemicals (including 3,300 gal of acid and 30 gal of biocide). Formation Water
• Hydrofrac fluid in contact with the rock will contain chemicals from the formation and the porewater.
• The regional aspects of the bulk rock and porewater geochemistry of the Marcellus Shale are not well understood.
• The organic matter in black shale has an affinity for radioactive materials.
• Pennsylvania DEP ran a water-quality analysis of fluids recovered from a Marcellus Shale well in southwestern Pennsylvania: – chloride at more than 100 g/L – total dissolved solids of almost 200 g/L (arsenic, barium, bromide) – heavy metal concentrations of hundreds of mg/L – radioactivity well above drinking water standards Disposal Options
• Options include surface water discharge after treatment, re- injection into the ground, or evaporation from a holding tank.
• In Pennsylvania, spent frac fluids have been trucked to wastewater disposal facilities. – Dissolved solids (brine) are not readily removed by standard WWT – Episodes of high salinity in Appalachian rivers (esp. the Mon) have been linked to Marcellus frac fluid disposal.
• Barnett water is re-injected, but the Appalachian Basin has many shallow aquifers used for drinking water that must be protected • . • Disposal by deep injection into formations below the Marcellus, such as the Oriskany Sandstone, would protect aquifers.
• Disposal by evaporation is probably not a workable option in the humid Appalachian Basin RESEARCH QUESTIONS
1. How do the bulk geochemistry and porewater geochemistry of the Marcellus Shale vary regionally with depth and facies changes?
2. What is the mechanism responsible for “adsorbing” such large volumes of natural gas in the Marcellus? Is it a property of the organic carbon in the shale, or something else? What is the ratio of adsorbed gas to free gas in other shales? Are there any that contain even more gas than the Marcellus?
3. How will the fractures and pores in the Marcellus Shale react to an increase in net stress during drawdown?
4. Can the impermeable, oil-bearing black shales of the western basin act as stratigraphic traps for gas in underlying gray shales?
5. Can the horizontal drilling and hydrofracturing technique be applied to other low-permeability, unconventional gas reservoirs, such as tight gas sands and coalbed methane? Questions for discussion
How many Marcellus Shale gas wells could be drilled in Maryland? (100,000 acres/80 acre spacing = 1250 wells) What are the possible sources for water to be used for horizontal drilling and hydraulic fracturing? Groundwater? Surface water? Wastewater?
What is a sustainable drilling rate that doesn’t strain local water resources?
Can drilling mud and hydrofrac fluids be recycled from well to well?
What contaminants might be in the recovered hydrofrac fluids from the chemical additives and from the formation?
How will the frac fluids be disposed of? Will treatment be required? Monitoring?
How will this needed research and monitoring be funded?