INTRODUCTION TO THE
OIL AND GAS
INDUSTRY
Chapter 1
1
WHAT IS
NATURAL GAS???
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1 - Intro to Oil and Gas
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What Isn’t Natural Gas?
This Photo by
Unknown Author
is licensed under
CC BY-SA
This Photo by Unknown Author is
licensed under CC BY-SA
This Photo by
Unknown Author
is licensed under
CC BY-SA
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Natural Gas
• Colorless, shapeless, and
odorless mixture of
hydrocarbon gases
• Highly combustible
• When burned, it gives off a high
amount of energy
• Cleaner than many other fossil
fuels
• Emits lower levels of potentially
harmful biproducts into the air
This Photo by Unknown Author is licensed under CC BY
• Abundant in the United States
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1 - Intro to Oil and Gas
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What is that smell?
The smell we associate with
natural gas is actually an
odorant called mercaptan!
Natural gas is odorless!
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Components of Natural Gas
• What is a hydrocarbon?
Methane
CH4
• An organic compound consisting
Ethane
C2H6
entirely of hydrogen and carbon
Propane
C3H8
• Natural gas consists primarily
Butane
C4H10
Carbon
Dioxide
CO2
0 – 10 %
Oxygen
O2
0 – 0.2%
Nitrogen
N2
0 – 5%
Hydrogen
Sulfide
H2S
0 – 5%
Rare gases
Ar, He, Ne, Xe
trace
of methane (CH4)
• Composition variable, but
makeup generally similar
based on location of
origination (i.e., northeast
U.S. vs. southern U.S.)
70 – 90%
0 – 20%
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“Dry” Natural Gas
• “Dry” natural gas is at least 85% methane, but often more
• Dry natural gas can be transported via pipelines across the
country for home heating and electric generation
• AKA “pipeline quality natural gas” or “consumer-grade natural gas”
• Dry natural gas can also be used at natural gas extraction and
transportation sites
• Used to power vehicles, drilling rigs, and other operations
• Reduces the need for using other fuels like gasoline and diesel
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“Wet” Natural Gas
• “Wet” natural gas contains higher percentages of compounds
like ethane and butane
• These natural gas liquids (NGLs) can be separated from the
methane and sold as individual compounds
• Ethane is widely used in petrochemical plants and to also manufacture
consumer goods (like plastics)
• Butane can be blended into gasoline to fuel vehicles
• Propane is used for home heating and cooking
• The propane and other lighter compounds found in the liquid natural
gasses (LNGs) may be marketed as liquefied petroleum gas (LPG), and
heavier hydrocarbons may be made into gasoline
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1 - Intro to Oil and Gas
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What is crude oil and what are
petroleum products?
• Crude Oil: a naturally
occurring liquid beneath the
Earth’s surface
• Petroleum covers both
naturally occurring
unprocessed crude oil and
petroleum products made up
of refined crude oil
• Commonly refined into various
fuels, or petroleum products
This Photo by Unknown Author is licensed under CC BY-SA
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Products Made from Crude Oil
• Once crude oil is removed from
the ground, it is sent to a
refinery where the oil is distilled
to create petroleum products
• Most refineries focus on
producing transportation fuels
• From a 42-gallon barrel of
crude oil, refineries produce
approximately 19 gallons on
motor gasoline, 11 gallons of
distillate fuel, and 4 gallons of
jet fuel
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Composition of Crude Oil
Paraffins
• Crude oil is primarily
hydrocarbons
• Commonly alkanes (paraffins),
cycloalkanes (naphthenes),
aromatic hydrocarbons, or more
complicated chemicals like
asphaltenes
• The more hydrocarbons are in
the oil, the lighter the oil is
Hydrocarbons
CH4,
C2H6,
C3H8, etc.
Naphthenes C3H6
Aromatics
50 – 98%
C6H6
Asphaltenes
-
Sulfur
-
-
0 – 10%
Nitrogen
-
-
0 – 1%
Oxygen
-
-
0 – 5%
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1 - Intro to Oil and Gas
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Oil Wells vs. Gas Wells
• Oil wells are predominantly crude oil, with some natural gas
dissolved in it
• Associated gas: gas produced as a byproduct of the production of crude
oil
• Gas wells are predominantly natural gas
• Natural Gas Condensate: a mixture of light liquid hydrocarbons, similar to
a very light crude oil
• Condensate is typically separated out of stream at the point of
production when the temperature and pressure of the gas is dropped to
atmospheric conditions
https://certmapper.cr.usgs.gov/data/apps/noga-drupal/
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Source: https://www.eia.gov/state/maps.php
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How are oil and natural gas measured?
• Typically measured in terms of volume
• Standard Cubic Feet (scf) for natural gas (at 60°F and 1 atm)
• Barrels or Gallons for oil wells
• Also measured by potential energy output
• British thermal units (Btu)
• Therms = 100,000 Btu = 97 scf
• Barrels of oil equivalent (BOE) = A unit of energy equal to 5.8-million
British thermal units (5.8 MMBtu) based on the approximate energy
released be burning one barrel of crude oil. 1 BOE = 5,650 scf natural gas
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U.S. Oil and Gas Production
• U.S. Energy Information
Administration (EIA) publishes
monthly energy reviews which
include production, consumption,
and trade for petroleum, natural
gas, coal, electricity, nuclear
energy, renewable energy, and
international petroleum
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How did oil and natural gas form?
• The remains of plants, animals, and microorganisms that lived
millions of years ago
• Formed when organic matter is compressed under the earth as high
pressures for long periods of time
• “Thermogenic methane”
• Higher the temperature, more natural gas
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Source: https://www.eia.gov/energyexplained/index.php?page=natural_gas_home
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How else can you create methane?
• Natural gas can also be created:
• Through the breakdown of organic
matter by microorganisms
• Ex., Landfill Gas
• As hydrogen-rich gases and carbon
molecules rise from deep under Earth’s
surface
• Combines with minerals underground
to create elements and compounds
found in the atmosphere
• Forms methane deposits as they move
toward the surface of the earth
This Photo by Unknown Author is licensed under CC BY-NC-ND
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Oil and Natural Gas Deposits
• After oil and natural gas forms, it rises towards the surface
through rock pore spaces because of its low density
• Most of the oil and natural gas deposits occur where gas
migrated into a highly porous and permeable rock underneath
an impervious cap rock layer, thus becoming trapped before it
could reach the surface and escape into the atmosphere
• Reservoir: location where large volumes of oil and/or natural gas
are trapped in the subsurface of the earth.
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Conventional vs. Unconventional Wells
• Two categories of petroleum and
natural gas deposits: conventional
and unconventional
• Conventional natural gas
deposits are commonly found in
association with oil reservoirs,
with the gas either mixed with the
oil or buoyantly floating on top
• Unconventional deposits include
sources like shale gas, tight gas
sandstone, and coalbed methane
Source: https://www.eia.gov/energyexplained/index.php?page=natural_gas_home
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Where is the gas and oil located?
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Marcellus Shale Formation
• One of the largest shale
formations in the United
States
• Underlies parts of New York,
Pennsylvania, Ohio, West
Virginia, and small portions
of Maryland and Virginia
• Contains about 84 trillion
cubic feet of natural gas
(according to USGS)
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https://www.youtube.com/watch?v=hnzOEWVAVlk
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Where Our Oil Comes From
• The United States is one of the
largest crude oil producers
• Five states accounted for 68% of total
U.S. crude oil production in 2018:
• Texas—40.5%
• North Dakota—11.5%
• New Mexico—6.3%
• Oklahoma—5.0%
• Alaska—4.5%
• In 2018, nearly 16% of U.S. crude oil
produced from offshore wells in the
federally administered waters of the
Gulf of Mexico
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Where Our Natural Gas Comes From
• The United States now produces
nearly all of the natural gas that it
uses
• Five states accounted for 65% of total
U.S. dry natural gas production in
2017:
• Texas—23%
• Pennsylvania—20%
• Oklahoma—8%
• Louisiana—8%
• Ohio—6%
• 4% of U.S. dry natural gas was
produced offshore in the Federal Gulf
of Mexico in 2017
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Natural Gas Imports and Exports
• Most U.S. natural gas imports
are from Canada (~97%)
• Natural gas imports have been
declining since 2007
• Natural gas exports are
increasing
• In 2018, the United States
exported natural gas to 33
countries
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Petroleum Imports and Exports
• Most of U.S. petroleum imports
are from Canada (~43%)
• In 2018, net imports of petroleum
averaged 2.3 MMb/d, the
equivalent to 11% of total U.S.
petroleum consumption
• The lowest percentage since 1957
• In 2018, total U.S. petroleum
exports averaged about 7.6
MMb/d, including about 2.0
MMb/d of crude oil or about
26% of total petroleum exports
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International Oil and Gas Production
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1 - Intro to Oil and Gas
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How much oil and gas is left?
• Oil and natural gas are non-
renewable resources
• It is difficult to determine how
much oil and natural gas is left
in the ground to be extracted
• Estimates are becoming more
reliable with updated technologies
• There is a vast amount of oil
and natural gas estimated to
still be in the ground
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Proved Reserves
• Proved reserves: volumes of hydrocarbon resources that
analyses of geological and engineering data demonstrate to be
recoverable under existing economic and operating conditions
• U.S. proved reserves of oil and natural gas increased nearly every
year since 2000
• Undiscovered technically recoverable resources are reserves that
are expected to exist, but have not been proven
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Proved Reserves Trends
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Where are the proved reserves located?
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1 - Intro to Oil and Gas
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U.S. Geological Basins
• Map of geological basins, or “provinces,” in the United States
was created by the American Association of Petroleum
Geologists (AAPG) in 1968 (updated in 1991).
• Adopted by the U.S. Geological Survey (USGS), and used in most
federal programs
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AAPG U.S.
GEOLOGICAL
BASINS MAP
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World Crude Oil and Natural Gas
Reserves
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Natural Gas Consumption in the U.S.
• In 2018, the U.S. consumed ~30 Tcf of natural gas (approx. 31%
of total energy consumption)
• Natural gas use by U.S. consuming sectors by amount and share
of total U.S. natural gas consumption in 2018:
• Electric power—10.63 Tcf—35%
• Industrial—10.04 Tcf—34%
• Residential—4.97 Tcf—17%
• Commercial—3.48 Tcf—12%
• Transportation—0.84 Tcf—3%
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Uses of Natural Gas by Sector
• Electric power sector –
generate electricity
• Industrial sector –
• fuel for process heating
• in combined heat and power
systems
• as a raw material (feedstock) to
produce chemicals, fertilizer, and
hydrogen
• Residential sector
• heat buildings and water
• cook
• dry clothes
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Uses of Natural Gas by Sector
• Commercial sector –
• heat buildings and water
• operate refrigeration and cooling
equipment
• cook, dry clothes, and provide
outdoor lighting
• Transportation sector uses
natural gas as a fuel to operate
compressors that move natural
gas through pipelines and as a
vehicle fuel in the form of
compressed natural gas and
liquefied natural gas
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Petroleum Consumption in the U.S.
• In 2017, U.S. petroleum consumption averaged about 19.96
million barrels per day (b/d), which included about 1 million b/d
of biofuels
• Petroleum use by U.S. consuming sectors by amount and share
of total U.S. natural gas consumption in 2017:
• Transportation – 14.02 MMb/d – 71%
• Industrial – 4.76 MMb/d – 24%
• Residential – 0.52 MMb/d – 3%
• Commercial – 0.47 MMb/d – 2%
• Electric power – 0.10 MMb/d – 1%
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What are the petroleum products
people consume most?
• Gasoline is most consumed
petroleum product in U.S.
(about 47% of total U.S.
petroleum consumption in
2017)
• Distillate fuel oil (includes diesel
fuel and heating oil) is second
most-consumed petroleum
product in U.S. (about 20% of
the total U.S. petroleum
consumption in 2017)
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1-20
Where Petroleum and Natural Gas is
Used
• The five largest natural gas consuming states in 2017 were:
• Texas—14.3%
• California—7.8%
• Louisiana—5.9%
• Florida—5.1%
• Pennsylvania—4.7%
This Photo by Unknown Author is licensed under CC BY-NC-ND
• The five largest gasoline consuming states in 2017 were:
• Texas—11%
• California—11%
• Florida—5%
• New York—4%
• Georgia—4%
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NATURAL GAS – FROM
WELLHEAD TO BURNER
TIP
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1 - Intro to Oil and Gas
1-21
Generally…
• Exploration and Production: Taking raw natural gas and crude oil from underground
formations.
• Gathering and Processing: Once natural gas is extracted from the earth, some processing
happens at the wellhead, but complete processing happens at a plant. Natural gas is
transported to the processing plants through a gathering system, which is a network of
small-diameter, low-pressure pipelines. Almost all raw natural gas must be processed in
some way to meet quality standards and regulations. In addition, natural gas is processed
to separate the heavier hydrocarbon liquids from the gas, which are valuable by-products
of gas processing (NGLs).
• Transmission and Storage: Delivery of natural gas from the wellhead and processing plant
to city gate stations or industrial end users. Transmission occurs through a vast network of
high-pressure pipelines. Natural gas storage falls within this sector. Natural gas is typically
stored in depleted underground reservoirs, aquifers, and salt caverns.
• Distribution: Delivery of natural gas from the major pipelines to the end users (e.g.,
residential, commercial and industrial).
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Oil and Gas Industry - An Overview
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Source: https://www.epa.gov/natural-gas-star-program/overview-oil-and-natural-gas-industry
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Upstream vs. Midstream vs.
Downstream
• Upstream: Exploration and Production
• Midstream: Gathering and Boosting, Processing
• Downstream: Transmission and Storage*, Distribution
*Transmission and Storage is can be considered part of
Midstream
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U.S. Natural Gas Pipeline Network, 2009
Interstate
natural gas
pipelines
operate and
transport
natural gas
across state
borders.
Intrastate
natural gas
pipelines
operate and
transport
natural gas
within a state
border.
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Regulation of the Oil and Gas Industry
• Only pipelines and local distribution companies (LDCs) are
directly regulated with respect to the services they provide
• The Federal Energy Regulatory Commission (FERC) has jurisdiction over
the regulation of interstate pipelines and is concerned with overseeing
the implementation and operation of the natural gas transportation
infrastructure
• Local distribution companies are regulated by state utility commissions
• Natural gas producers and marketers are not directly regulated
• Production and marketing companies must still operate within the
confines of the law, but the prices they charge are a function of
competitive markets
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QUESTIONS?
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INTRODUCTION TO OIL
AND GAS AIR
EMISSIONS
Chapter 2
1
1970 Clean Air Act (CAA)
• National Ambient Air Quality Standards (NAAQS) for criteria
pollutants (i.e., SO2, NOX, PM, ozone, CO, and lead)
• State Implementation Plans (SIP)
• New Source Performance Standards (NSPS)
• National Emission Standards for Hazardous Air Pollutants
(NESHAP)
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2 – CAA, Combustion, Eq Lks
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1977 CAA amendments
• Expanded NSPS program
• Prevention of significant deterioration (PSD)
• New source review (NSR)
• Nonattainment provisions applicable to areas not meeting the NAAQS
• Required EPA to review the air quality criteria and NAAQS every 5 years
• Recent review led to:
• New NAAQS for PM fine
• 35 micrograms per cubic meter (μg/m3) 24-hour average
• 15 μg/m3 annual average
• Revised NAAQS for ozone = 0.075 parts per million (ppm) 8-hour average
• Revised NAAQS for lead = 0.15 μg/m3
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1990 CAA amendments
• Title I: Strengthened NAAQS and NSPS program
• Title II: Mobile Sources and Clean Fuels
• Title III: Air Toxics (Hazardous Air Pollutants)
• Title IV: Acid Deposition Control
• Title V: Operating Permits
• Title VI: Stratospheric Ozone Protection
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2 – CAA, Combustion, Eq Lks
2-2
Standard
Size and Type of Unit,
Process, or Facility
Applicability Criteria
Pollutants Regulated
NSPS – New Source
Performance Standards (40
CFR Part 60)
Standards generally focus on
emission units or processes
that are called “affected”
facilities. The affected facility
may be at a major or minor
source.
NSPS standards apply to the
“affected facility.”
Standards generally regulate
criteria pollutants. Some
standards may regulate noncriteria pollutants (e.g., H2S,
CH4)
Pre-1990 NESHAP – National
Emission Standards for
Hazardous Air Pollutants (40
CFR Part 61)
Standards focus on sources
that emit certain levels of
specific hazardous air
pollutants. Standards could
apply to either area or major
sources.
Applies to both new and
Focus on specific HAPs (premodified sources. Upon
1990s) list identified in §61.01.
modification, an existing
source shall become a new
source for each HAP for which
the rate of emissions
increases.
Post-1990 NESHAP a.k.a.
MACT standards (40 CFR Part
63)
Standards generally focus on
emission units/processes that
are called “affected facilities.”
Most standards affect major
HAP sources; several
standards established for area
sources.
Applies to existing, new, and
reconstructed major HAP
“affected sources” as defined
in §63.2. Each standard
defines affected source as it
relates to specific standard.
Focus on specific HAPs (post1990) list identified in §112(b).
List includes pre-1990
NESHAPs.
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Major Federal Regs for Oil and Gas
1.
40 CFR Part 60, Subpart JJJJ – Standards of Performance for
Stationary Spark Ignition Internal Combustion Engines
• Establishes emission standards and compliance requirements for the control of
emissions from stationary spark ignition internal combustion engines that
commenced construction, modification or reconstruction after June 12, 2006,
where the SI-RICE are manufactured on or after specified manufacture trigger
dates
2.
40 CFR Part 60, Subpart KKKK – Standards of Performance for
Stationary Combustion Turbines
• Establishes emission standards and compliance schedules for the control of
emissions from stationary combustion turbines with a heat input at peak load
equal to or greater than 10 million British thermal units per hour (MMBtu/h) that
commenced construction, modification or reconstruction after February 18,
2005
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Major Federal Regs for Oil and Gas
3.
40 CFR Part 60, Subpart OOOO – Standards of Performance for Crude Oil
and Natural Gas Production, Transmission, and Distribution for which
Construction, Modification, or Reconstruction Commenced after August 23,
2011, and on or before September 18, 2015
• Establishes emission standards and compliance schedules for the control of VOC and SO2
emissions from affected facilities
4.
40 CFR Part 60, Subpart OOOOa – Standards of Performance for Crude Oil
and Natural Gas Facilities for which Construction, Modification, or
Reconstruction Commenced After September 18, 2015
• Establishes emission standards and compliance schedules for the control of the pollutant
GHGs
• The GHG standard in this subpart is in the form of a limitation on emissions of methane
• This subpart also establishes emission standards and compliance schedules for the control of
VOC and SO2 emissions.
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Major Federal Regs for Oil and Gas
5.
40 CFR Part 63, Subpart HH – National Emission Standards for Hazardous
Air Pollutants from Oil and Natural Gas Production Facilities
• Applies to the owners and operators of affected units located at natural gas production
facilities that are major or area sources of HAPs and that process, upgrade, or store natural
gas prior to the point of custody transfer, or that process, upgrade, or store natural gas prior
to the point at which natural gas enters the natural gas transmission and storage source
category or is delivered to a final end user, and that are major sources of hazardous air
pollutants (HAP) emissions
6.
40 CFR Part 63, Subpart HHH – National Emission Standards for Hazardous
Air Pollutants From Natural Gas Transmission and Storage Facilities
• Applies to owners and operators of natural gas transmission and storage facilities that
transport or store natural gas prior to entering the pipeline to a local distribution company or
to a final end user (if there is no local distribution company), and that are major sources of
hazardous air pollutants (HAP) emissions
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Major Federal Regs for Oil and Gas
7.
40 CFR Part 63, Subpart ZZZZ – National Emission Standards for
Hazardous Air Pollutants for Stationary Reciprocating Internal
Combustion Engines (RICE)
• Establishes national emission limitations and operating limitations for HAPs
emitted from stationary RICE
• Applies to owners or operators of new and reconstructed stationary RICE of any
horsepower rating which are located at a major or area source of HAP emissions
8.
40 CFR Part 63, Subpart YYYY – National Emission Standards for
Hazardous Air Pollutants for Stationary Combustion Turbines
• Establishes national emission limitations and operating limitations HAP
emissions from stationary combustion turbines located at major sources of HAP
emissions
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Oil and Gas Pollutants of Concern
1.
Oxides of Nitrogen (NOx):
• A byproduct of the combustion of fuel and air
• The heat of combustion causes the molecular nitrogen (N2) in the
combustion air to disassociate and oxidize, forming NO and NO2
2.
Carbon Monoxide (CO):
• Results from the incomplete combustion of carbon
• Formed when insufficient oxygen or poor mixing interferes with the
combustion reaction to produce CO2
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Oil and Gas Pollutants of Concern
3.
Volatile Organic Compounds (VOC):
• Any compound of carbon, excluding carbon monoxide (CO), carbon dioxide
(CO2), carbonic acid, metallic carbides or carbonates, and ammonium
carbonate, which participates in atmospheric photochemical reactions
• VOCs may be defined as non-methane non-ethane hydrocarbons (NMNEHC)
4.
Hazardous Air Pollutants (HAP):
• Air pollutants known to cause cancer or to have other serious health impacts
• Released through combustion, fugitive emissions, venting, and the processing
of natural gas
• HAPs of primary concern are n-hexane; benzene, toluene, ethylbenzene,
xylenes (collectively known as BTEX); and formaldehyde
• Also known as “air toxics”
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Oil and Gas Pollutants of Concern
5.
Oxides of Sulfur (SOx or SO2):
• Produced as the byproduct of combustion of a fuel that contains sulfur
6.
Particulate Matter (PM):
• Classifications of particulate matter based on size (i.e., PM10 and PM2.5)
and state (i.e., filterable and condensable)
• Primary particles – PM emitted directly from a source, such as
construction sites, unpaved roads, or combustion
• Secondary particles – PM formed in complicated reactions in the
atmosphere from SO2 and NOx
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Oil and Gas Pollutants of Concern
7.
Carbon Dioxide (CO2):
• Sometimes present in natural gas in significant quantities
• A primary byproduct of combustion
• CO2 is a greenhouse gas (GHG)
8.
Methane (CH4):
• The primary component of natural gas
• Represents a major portion of the emissions from oil and gas sites
• Methane is also a GHG and a precursor to ground level ozone
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Types of Emissions
PROCESS
COMBUSTION
FUGITIVES
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STATIONARY
COMBUSTION SOURCES
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Stationary Combustion at Oil and Gas
Sites
• Primary fuels used are natural gas, diesel, gasoline, and propane
• Natural gas – fuel-specific information based on measurements are
preferred over default values
• Diesel, gasoline, and propane – fuel-specific information may be
available from fuel suppliers or from MSDS for purchased fuel
• The main pollutants emitted from the exhaust of combustion
devices are NOX, CO, VOC, formaldehyde (HAP), SOX, PM, and
GHGs, depending on the composition of the fuel used
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Combustion Emission Sources
• Boilers/steam generators
• Glycol dehydrator reboilers
• Heater treaters
• Generators
• Fire pump
• Compressor drivers (SI RICE, turbines)
• Well drilling drivers (SI RICE)
• Control Devices: Flares, Incinerators/Combustors
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Combustion Emissions Estimation
Approaches
1.
AP-42 Emission Factors
Sources: AP 42, Fifth Edition, Volume I, Chapter 1: External Combustion
Sources; AP-42 Fifth Edition, Volume I, Chapter 3: Stationary Internal
Combustion Sources
https://www.epa.gov/air-emissions-factors-and-quantification/ap-42compilation-air-emissions-factors
Calculation:
Emissions [lb/yr] = EF [lb/MMscf] x Fuel Consumption [MMscf/hr] x Op Hours [hr/yr]
or
Emissions [lb/yr] = EF [lb/mmbtu] x Heat Input Capacity [mmbtu/hr] x Op Hours [hr/yr]
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Combustion Emissions Estimation
Approaches
2.
Manufacturer Documentation
Source: Manufacturer-provided emissions data sheet
Calculation:
Emissions [lb/hr] = EF [g/KW-hr] x Engine Power [KW] x Op Hours [hr/yr] x 0.0022
[g/lb]
Example:
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Combustion Emissions Estimation
Approaches
Part 98 Subpart C Emission Factors for GHG Emissions
Source: EPA’s Greenhouse Gas Reporting Program – Part 98, Subpart C,
Tiers 1 – 3 methodologies (98.33)
Calculation:
Tier 1:
3.
Tier 2:
Tier 3:
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Control Technologies For Combustion
Sources
• Control technologies vary by sources, but may include:
• Process controls (ex., fuel switching, fuel denitrification, coal cleaning,
etc.)
• Combustion controls (ex., low NOx burners, water/stream injection, flue
gas recirculation, etc.)
• Post-process controls (ex. Selective catalytic reduction (SCR), Selective
noncatalytic reduction (SNCR), Nonselective catalytic reduction (NSCR),
Catalytic oxidizers
22
22
2 – CAA, Combustion, Eq Lks
2-11
Pollution Control Efficiency
• Control efficiency is a measure of emission reductions achieved
by a control technology, whether it is a pollution prevention
measure or an add on control device
• Control efficiencies are typically specified by the manufacturer
of the control technology and vary by pollutant
• Example – for a combustion device with a Selective Catalytic
Reduction (SCR), NOx emissions may be reduced by 95%
• Calculated uncontrolled NOx emissions should then be reduced by 95%
23
23
Actual Combustion Emissions
• Actual emissions calculated using actual fuel use and/or actual operating
hours
• If the emission factor is in units of pounds per quantity of fuel (gallons or
cubic feet):
Actual emissions (tpy) = Emission Factor (lb/unit) x Actual Annual Fuel Use
(unit) x ([100 - Control Efficiency]/100)
• If the emission factor is in units of pounds per hp-hr power output or
pounds per MMBtu heat input:
Actual Emissions (tpy) = Emission Rate [lb/hr] x Actual Operating Hours [hr] x
0.005 [ton/lb] x ((100 – Control Efficiency)/100)
24
24
2 – CAA, Combustion, Eq Lks
2-12
EQUIPMENT LEAKS
25
25
Equipment Leaks
• Equipment leaks are typically low-level, unintentional losses of
process gas from the sealed surfaces of process equipment
• Leak emissions are primarily CH4 and VOCs
• Typical leaking components:
• Valves
• Flanges and other connectors
• Pump Seals
• Compressor Seals
• Pressure Relief Valves
• Open-ended lines
• Sampling Connections
26
26
2 – CAA, Combustion, Eq Lks
2-13
This Photo by Unknown Author is licensed under CC BY
This Photo by Unknown Author is licensed under CC BY-SA
This Photo by Unknown Author is licensed under CC BY-SA
This Photo by Unknown Author is licensed under CC BY-SA
27
27
Why do leaks happen?
• Leaks occur due to:
• Changes in pressure, temperature
This Photo by Unknown Author is licensed under CC BY-SA
and mechanical stresses on
equipment
• Loose connections
• Wear on seals and gaskets during
normal operation of equipment
• Weather conditions
• Equipment that is not operating
correctly, such as storage vessel
thief hatches that are left open or
separator dump valves that are
stuck open
28
28
2 – CAA, Combustion, Eq Lks
2-14
Control Techniques for Equipment Leaks:
LDAR Programs
• A Leak Detection and Repair (LDAR) program is a facility’s system of
procedures to minimize fugitive VOC, HAP, and GHG emissions from
leaking components
• A portable detection device is used to identify leaking equipment above a
specified threshold (e.g., 10,000 ppmv) and these leaks are then repaired
• Most LDAR requirements include:
• Approved methods for detecting natural gas leaks
• Definition of a leak
• Equipment and components required to be monitored
• Monitoring frequency (e.g., monthly, quarterly, semiannually, annually)
• Leak repair requirements
• Recordkeeping and reporting
29
29
LDAR Using EPA Method 21
• When performing Method 21
source screening, the portable
analyzer probe opening is placed
at the leak to obtain a "screening"
value
• The screening value is the
concentration level of leaking
natural gas
• Example instrument detector
types for meeting EPA Method 21
criteria include flame ionization
detectors (FID) and photo
ionization detectors (PID)
This Photo by Unknown Author is licensed under CC BY-SA
30
30
2 – CAA, Combustion, Eq Lks
2-15
LDAR Using Optical Gas Imaging
• An optical gas imaging (OGI) camera can be considered a highly specialized
version of an infrared or thermal imaging camera
• OGI cameras are used to visualize leaks
This Photo by Unknown Author is licensed under CC BY-SA
31
31
https://www.youtube.com/watch?v=N5hA_x3BHuw
32
32
2 – CAA, Combustion, Eq Lks
2-16
https://www.youtube.com/watch?v=N5hA_x3BHuw
33
33
Audio/Visual/Olfactory (AVO)
Inspections
• Combines three inspection
methods:
• Audio (to hear leaking gas)
• Visual (to see visible ruptures in
equipment)
• Olfactory (to smell odor added
to methane for safety)
This Photo by Unknown Author is licensed under CC BY-NC
34
34
2 – CAA, Combustion, Eq Lks
2-17
What defines a leak in a LDAR
inspection?
• Leaks are defined in each regulation, and may differ between
regulations
• Typical leak definitions:
• Using an OGI Camera: any visible emission detected by an OGI camera
calibrated according to 40 CFR 60.18 and a detection sensitivity level of 60 g/h
• Using Method 21: a concentration greater than or equal to the applicable
regulatory leak definition, calibrated as methane, detected by an instrument
that meets the requirements of 40 CFR Part 60, Appendix A-7, Method 21
• Using AVO: any positive indication, whether audible, visual, or odorous,
determined during an AVO inspection
35
35
Repairing the Leak
• If a leak is detected, the owner/operator typically must tag the leak location
and repair the leak
• For example, NSPS OOOOa requires that the owner or operator make a first attempt of
repair within 30 days of the detection of the leak and the leak be repaired no later than
60 days after the leak is detected
• A leak is typically considered repaired if one of the following can be
demonstrated:
• No detectable emissions consistent with 40 CFR Part 60, Appendix A-7, Method 21
Section 8.3.2
• A concentration of less than 500 ppm calibrated as methane is detected when the gas
leak detector probe inlet is placed at the surface of the component
• No visible leak image when using an OGI camera calibrated in accordance with 40 CFR
§60.18 with a detection sensitivity of 60 g/h
• No bubbling at leak interface using a soap solution bubble test specified in Section 8.3.3
of 40 CFR Part 60, Appendix A-7, Method 21
36
36
2 – CAA, Combustion, Eq Lks
2-18
LDAR Frequency
• Monitoring frequency varies depending on the regulatory programs.
This can include:
• Weekly audio, visual, olfactory (AVO) methods
• Quarterly, semiannual or annual monitoring using Method 21 or OGI camera
• Operators may reduce monitoring frequency if the leak rates are less
than a set percentage of the total number of components; this can
vary from 2% to 5% of the total
• For most programs, if the monitored leak percentage is below the set
percentage for a certain amount of time, the operator can skip a
monitoring period
37
37
LDAR Recordkeeping and Reporting
• Monitoring records must be kept on location or other approved
location and available for inspection by the regulatory agency
• Typical recordkeeping includes all monitoring records such as:
• Monitoring dates
• Monitoring equipment used
• Calibration records
• Listing of components monitored
• Number of leaks detected
• Date(s) of successful repair of the leak(s)
• Deviations from the monitoring plan
38
38
2 – CAA, Combustion, Eq Lks
2-19
Federal Regulations with LDAR
Requirements
• Examples of regulations and programs that require, may require
or encourage the use of LDAR for O&G facilities include:
• 40 CFR 60 Subpart OOOO – tank hatches and closed vent system for
storage tank emission controls
• 40 CFR 60 Subpart OOOOa
• 40 CFR 98 Subpart W – Mandatory Greenhouse Gas (GHG) Reporting rule
• 40 CFR 60 Subpart KKK
39
39
Equipment Leak Estimation Approaches
• Two general approaches: population emission factors and leaker emission
factors
1995 Protocol for Equipment Leak Emission Estimates
Source: U.S. EPA https://www3.epa.gov/ttnchie1/efdocs/equiplks.pdf
Calculation:
Emissions [kg/hr] = EF [kg/hr/source] × Weight Fraction of Pollutant × Number
of Equipment x Op Hours
Emissions [kg/hr] = (EF [kg/hr/source] × Leaker Count × Weight Fraction of
Pollutant) + (EF [kg/hr/source] × Non-Leaker Count × Weight Fraction of
Pollutant)
1.
40
40
2 – CAA, Combustion, Eq Lks
2-20
41
41
Equipment Leak Estimation Approaches
2.
Emission Factors from Other Research Sources
42
42
2 – CAA, Combustion, Eq Lks
2-21
43
Source: Control Techniques Guidelines for the Oil and Natural Gas Industry, 2016
43
QUESTIONS?
44
44
2 – CAA, Combustion, Eq Lks
2-22
EXPLORATION AND
DRILLING
Chapter 3
1
Overview
• How is natural gas and petroleum found?
• How do companies decide where to drill wells?
• Understand the process of drilling a well
• What is horizontal drilling?
2
2
3 - Drilling
3-1
Steps of Oil and Natural Gas
Development
• Finding the right geology
• Leasing
• Geologic evaluation
• Complying with regulatory
requirements
• Drilling
• Completing the well, which
may include hydraulic
fracturing
• Getting the product to market
This Photo by Unknown Author is licensed under CC BY-SA
3
3
HOW IS NATURAL GAS
AND PETROLEUM
FOUND?
4
4
3 - Drilling
3-2
Conventional vs. Unconventional Wells
• Conventional Oil and Natural Gas
Production: Crude oil and natural gas
that is produced by a well drilled into
a geologic formation in which
reservoir and fluid characteristics
permit oil and natural gas to readily
flow to the wellbore
• Unconventional oil and natural gas
production: An umbrella term for oil
and natural gas that is produced by
means that do not meet criteria for
conventional production
• Hydrocarbon reservoirs that have low
permeability and porosity
Source: https://www.eia.gov/energyexplained/index.php?page=natural_gas_home
5
5
Oil and Gas Exploration
• Exploration: the search by petroleum geologists and
geophysicists for deposits of hydrocarbons, particularly
petroleum and natural gas, in the Earth using petroleum geology
• Visible surface features such as oil seeps, natural gas seeps,
pockmarks (underwater craters caused by escaping gas) provide
basic evidence of hydrocarbon generation (be it shallow or deep
in the Earth)
• Anticlinal slopes: areas where the Earth has folded up on itself, forming a
dome shape that is characteristic of a great number of reservoirs
6
6
3 - Drilling
3-3
Surface Features
• Geologists make inferences
from outcroppings of rocks
on the surface or in valleys
and gorges, geologic
information attained from
the rock cutting, and samples
obtained from digging of
irrigation ditches, water
wells, and other oil and gas
wells
This Photo by Unknown Author is licensed under CC BY-SA
7
7
Mapping Underground Formations
• Once the geologist has
determined an area where it is
geologically possible for a natural
gas or petroleum formation to
exist, a geophysicist will use
technology to find and map
underground rock formations
• Geophysicists often use
seismology to determine the
layers under the Earth’s surface
• Seismology: the study of how energy,
in the form of seismic waves, moves
through Earth’s crust and interacts
differently with various types of
underground formations
This Photo by Unknown Author is licensed under CC BY-SA
8
8
3 - Drilling
3-4
9
9
Other Tools Used to Map the Subsurface
• The magnetic properties of underground formations can be
measured to generate geological and geophysical data
• Magnetometers: devices that can measure the small differences in the
Earth’s magnetic field
• Geophysicists can also measure and record the difference in the
Earth’s gravitational field to gain a better understanding of what
is underground using gravimeters
• Different underground formations and rock types all have a slightly
different effect on the gravitational field that surrounds the Earth
10
10
3 - Drilling
3-5
HOW DO COMPANIES
DECIDE WHERE TO
DRILL WELLS?
11
11
Leasing
• Leasing allows exploration and
production on a tract of land
• Companies will enter into lease
or purchase agreements with
private landholders, local and
state governments, the
Department of Interior’s Bureau
of Land Management (BLM) for
onshore federal land, and the
Bureau of Ocean Energy
Management (BOEM) for
offshore federal land
This Photo by Unknown Author is licensed under CC BY-SA
12
12
3 - Drilling
3-6
Exploratory Wells
• With lease in hand, companies move quickly to select the best drilling
target
• The best way to gain a full understanding of subsurface geology and the
potential for natural gas deposits to exist in a given area is to drill an
exploratory well
• Exploratory well: a well drilled with the intent to discover a new petroleum
reservoir
• Exploratory wells are also known as “wildcat wells” or “exploration wells”
• Drilling an exploratory well is an expensive, time consuming effort
• Exploratory wells are only drilled in areas where other data has indicated a high
probability of petroleum formations
• Exploratory wells are usually drilled only vertically, with horizontal drilling only occurring
if the well is believed to be productive
13
13
Logging
• Logging refers to performing tests during or after the drilling process to
allow geologists and drill operators to monitor the progress of the well
drilling and to gain a clearer picture of subsurface formations
• Various types of tests include standard, electric, acoustic, radioactivity,
density, induction, caliper, directional and nuclear logging
• Standard logging: examining and recording the physical aspects of a well
• The drill cuttings (pieces of rock displaced by the drilling of the well) are all examined
and recorded, allowing geologists to physically examine the subsurface rock
• Electric logging consists of lowering a device used to measure the electric
resistance of the rock layers in the down hole portion of the well
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14
3 - Drilling
3-7
Producing Formations
• Geologists evaluate logging data to determine whether it
matches their geological model
• If there is no oil and gas when the drill reaches the targeted rock
layer, then the well is considered a “dry hole”
• Dry holes must be plugged and abandoned
• If oil and gas is found, it’s called a “discovery”
15
15
Appraisal and Delineation Phase
• If oil or gas is discovered from an exploratory well, companies
will assess the potential of the discovery – the “Appraisal Phase”
or “Delineation Phase”
• Appraisal/delineation wells may be drilled to collect more
information to assess the size and viability of the new reservoir
• Appraisal wells are nearly identical to exploration wells, except that they
are drilled into a newly discovered reservoir
• Reservoir engineers will provide recommendations on the
number and positioning of future production wells
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3 - Drilling
3-8
Development Phase
• During the development phase, wells are drilled with the
primary objective of hydrocarbon production
• Development well: A well drilled within the proved area of an oil
or gas reservoir to the depth of a stratigraphic horizon known to
be productive
• Also known as a “production well”
17
17
THE DRILLING PROCESS
18
18
3 - Drilling
3-9
Onshore Drilling Methods
• Two main types of onshore drilling: percussion drilling and rotary
drilling
• Percussion, or “cable tool” drilling: process of raising and dropping a
heavy metal bit into the ground, effectively punching a hole down
through the Earth
• Rotary drilling: a sharp, rotating metal bit is used to drill through the
Earth’s crust
• Torque (rotation) is applied to the Drill Pipe or Drill String (hollow steel tubing)
with a drill bit attached to the end of the Bottom-Hole Assembly (BHA)
19
19
Drilling Rigs
• Drilling Rig: a machine which
creates the holes (usually called
boreholes) and/or shafts in the
ground.
• The term “rig” generally refers to the
complete complex of equipment that
is used to make a well
• Five major components of a
drilling rig:
1.
2.
3.
4.
5.
Power System
Hoisting System
Rotating System
Circulating System
Blowout Prevention System
Source: https://www.e-education.psu.edu/png301/node/704
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3 - Drilling
3-10
The Power System
• Power System: provides the power for
the other systems on the rig (e.g.,
electrical systems, pumps, etc.)
• Consists of:
• A prime mover: component of the power
system that generates raw power
• A means to transmit the power – either
mechanical, direct current (DC) electrical
generator, or alternating current (AC)
electrical generator with silicon-controlled
rectifier (SCR) to direct current (DC)
• Fuel storage
• Electric control house
This Photo by Unknown Author is licensed under CC BY-SA-NC
21
21
The Hoisting System
• Hoisting system: used to raise, lower,
and suspend the drill string and lift
casing and tubing for installation into
the well
• Consists of:
• Derrick (or mast): provides structural support
for the hoist system
• Crown block & travel block: form a Block and
Tackle System on rig
• Drawworks: a winch that reels the drilling
line in or out causing the traveling block to
move up or down
This Photo by Unknown Author is licensed under CC BY-SA-NC
22
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3 - Drilling
3-11
Conventional Rotary Table Rigs
• A conventional rotary rig is a
drilling rig where the rotation
of the drill string and bit is
applied from a rotary table
on the rig floor
• Also known as a “rotary table
rig” or “kelly drive rig”
• The kelly is a hollow square
or hexagonal piece of pipe in
which the drill pipe can be
passed through
This Photo by Unknown Author is licensed under CC BY-SA
23
This Photo by Unknown Author is licensed under CC BY-SA-NC
24
23
Top-Drive Rig
• A top-drive rig is a drilling rig that
which uses a top drive (a motor
that is suspended from the
derrick) to rotate the drill string
during the drilling process
• The advantages of a top-drive rig
are that longer sections of drill
pipe can be either:
1.
2.
3.
connected to the drill string when
the rig crew is drilling ahead
connected to the drill string when
tripping into the hole
unconnected from the drill string
when tripping out of the hole
24
3 - Drilling
3-12
The Rotary System
• The Rotary System: the
rotating equipment on a
rotary drilling rig consists of
the components that actually
serve to rotate the drill bit,
which, in turn, sends the hole
deeper and deeper into the
ground
This Photo by Unknown Author is licensed under CC BY-NC
This Photo by Unknown Author is licensed under CC BY-SA
25
25
Drill Bit
• A drill bit is a rotating apparatus
that usually consists of two or
three cones made up of the
hardest of materials (usually
steel, tungsten carbide, and/or
synthetic or natural diamonds)
and sharp teeth that cut into
the rock and sediment below
This Photo by Unknown Author is licensed
under CC BY-SA
This Photo by Unknown Author is licensed under CC BY-SA
• It is what actually cuts into the rock
when drilling an oil or gas well
• Types of drill bits:
• Roller Cone (or Tri-Cone) Bits
• Fixed Cutter Bits
This Photo by Unknown Author is licensed under CC BY-NC-ND
26
26
3 - Drilling
3-13
https://www.youtube.com/watch?v=Su3Rf5pFQyM
27
27
The Circulation System
• The Circulation System: the
system that allows for
circulation of the Drilling Fluid
(or “Mud”) down through the
hollow drill string and up
through the annular space
between the drill string and
wellbore
• Mud: a mixture of water, clay,
weighting material, and
chemicals
Source: https://www.osha.gov/SLTC/etools/oilandgas/drilling/mud_system.html
28
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3 - Drilling
3-14
Uses of Mud
• lift drill cuttings from the bottom of the
• minimize reservoir damage (assure low skin
wellbore to the surface
• suspend cuttings to prevent them from falling
downhole if circulation is temporarily ceased
• cool the drill bit during drilling operations
• lubricate the drill bit during drilling operations
• release the cuttings when they are brought to
the surface
• allow for pressure signals from Logging While
• stabilize the borehole during drilling operations
• control formation pore pressures to assure
desired well control
• deposit an impermeable filter cake onto the
wellbore walls to further prevent fluids from
permeable formations from entering the
wellbore
values) when drilling through the reservoir
section of the well
Drilling (LWD) or Measurement While Drilling
(MWD) tools to be transmitted to the surface
• allow for pressure signals to be sent to the
bottom of the well to pressure actuate certain
downhole equipment
• minimize environmental impact on subsurface
natural aquifers
29
29
What actually is “mud”?
• Options for mud:
• Water-based muds (WBM) (most
frequently used)
• Base may be either fresh water or
saltwater
• Oil-based muds (OBM)
• Synthetic materials
• Foams
• Air
• Drilling muds typically have
several additives (weighting
materials, corrosion inhibitors,
dispersants, etc.)
Source: OSHA, https://www.osha.gov/SLTC/etools/oilandgas/drilling/drillingfluid.html
30
30
3 - Drilling
3-15
Mud and Drill Cuttings Disposal
• Drilling mud is recirculated, which helps decrease waste by
reusing as much mud as possible
• Drilling mud is classified as “special waste,” which means they
are exempt from many federal regulations
• Pit burial is a common disposal technique for water-based mud
and cuttings
• Oil- and synthetic-based muds can be recycled at other well sites
31
31
The Blowout Prevention System
• The Blowout Prevention
System on a drilling rig is the
system that prevents the
uncontrolled, catastrophic
release of high-pressure
fluids (oil, gas, or salt water)
from subsurface formations
• Blowouts: uncontrolled flow
of formation fluids from a
well
This Photo by Unknown Author is licensed under CC BY-SA
32
32
3 - Drilling
3-16
Blowout Preventer
• Common types of valves in a
blowout preventer:
• Annual preventer - used to prevent
This Photo by Unknown Author is
licensed under CC BY-SA
This Photo by Unknown Author is licensed under CC BY-SA
flow through the annular space
between the drill string or casing
and the annular preventer
• Blind rams - isolate both the pipe
and the annular space by crushing
the pipe and it pinching-off when
closed
• Pipe rams - isolate the annular
space by wrapping around the pipe
when closed
• Shear rams - isolate both the pipe
and the annular space by shearingoff the pipe when closed
This Photo by Unknown Author is
licensed under CC BY-SA
33
33
Kicks
• Kick: a flow of formation fluids into the wellbore during drilling
operations
• A kick is physically caused by the pressure in the wellbore being less than
that of the formation fluids, thus causing flow
• Kick can be caused in two ways:
1.
2.
If the mud weight is too low, then the hydrostatic pressure exerted on
the formation by the fluid column may be insufficient to hold the
formation fluid in the formation
dynamic and transient fluid pressure effects, usually due to motion of
the drillstring or casing, effectively lower the pressure in the wellbore
below that of the formation
34
34
3 - Drilling
3-17
https://www.youtube.com/watch?v=9NQ8LehUWSE
35
35
How to Drill a Well – A Step by Step
Guide
Step #1: Plan the Well
• Develop detailed drilling proposals
• Obtain all necessary permits
• Permits to drill typically require an application to
the appropriate state, including evidence of
mineral rights ownership/lease, a plan of
operation, a site plan, and a fee to drill
• Permits typically must be renewed annually until
reclamation is complete
Step #2: Perform a Shallow Gas Survey
• A shallow gas survey is performed to identify
the locations and depths of any potential
shallow gas hazards
This Photo by
Unknown Author is
licensed under CC
BY-SA
36
36
3 - Drilling
3-18
Step #3: Land Drilling Preparation
• Before an onshore well can be drilled:
• The site must be prepared, including
leveling the land on which the derrick
will be assembled
• Access roads must be created so workers
and equipment can get to/from the rig
• Reserve pits need to be dug or large
metal bins brought in so cuttings,
material, and used mud can be properly
disposed of
• Cellar: A pit in the ground to provide
additional height between the rig floor and
the well head to accommodate the
installation of blowout preventers, ratholes,
mouseholes, etc.
Source: Mallone, Samantha. Rig in operation (currently drilling) in WV. 09/26/2013. Provided by
FracTracker Alliance, fractracker.org/photos.
37
37
Step #4: Set the Conductor Casing
• Before the drill rig arrives, a
conductor hole is drilled
approximately 100-200 ft
deep
• Conductor hole is then lined
with conductor casing and
cemented into place
• Conductor casing is typically set
through the topsoil and loose
rocks to the bed rock
Source: https://www.osha.gov/SLTC/etools/oilandgas/glossary_of_terms/glossary_of_terms_c.html
38
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3 - Drilling
3-19
Step #5: Moving In and Rigging Up
• “Rigging-up” begins as the rig is
hoisted into position and the
equipment substructure is
centered over the conductor pipe
• The mast or derrick is raised over
the substructure and other
equipment such as engines,
pumps, and rotating and hoisting
equipment are aligned and
connected
• Water and fuel tanks are filled
• Additives for the drilling mud are
stored on location
Source: Donnan, Bob. Drilling pad, PA. 12/22/2014. Provided by FracTracker Alliance, fractracker.org/photos.
39
39
Step #6: Spudding In
• “Spudding a Well” refers to
starting the rotary drilling
operations for that well
This Photo by Unknown Author is licensed under CC BY-NC
40
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3 - Drilling
3-20
Step #7: Drill Down to the Surface Casing
Depth
• The first section of the well to
be drilled is the section that
goes down to the surface casing
point
• Installation of surface casing
puts the environmentally
sensitive water table behind
pipe and protecting it from
future well (drilling and
production) activities
• Typically drilled with the most
environmentally-friendly mud and
cased and cemented ASAP
Source: https://prd-wret.s3-us-west-2.amazonaws.com/assets/palladium/production/s3fspublic/Steel_Pipe_for_Gas_Well.jpg
41
41
Step #8: Run and Cement the Surface
Casing
• Once the surface casing point is reached,
surface casing is run into wellbore and
cemented into place
• This process is performed by:
• Pulling Out of Hole (POOH): Tripping out of the
hole with the drill pipe to remove it from wellbore
during cementing operations
• Running the surface casing
• Pumping a cement slurry down the interior of the
casing
• Chasing cement with drilling fluid to displace the
cement up into the annular space between casing
string and the wellbore (rock)
• Allowing time for the cement to cure
This Photo by Unknown Author is licensed under CC BY-NC-ND
42
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3 - Drilling
3-21
Step #9: Continue this Process to Drill
to Each of the Next Casing Points
• Drilling process is continued to the
next pre-determined casing point
to create intermediate casing
strings
• The objectives of the intermediate
casing strings are:
• Isolate unstable hole sections behind
pipe
• Isolate lost circulation zones behind
pipe
• Isolate under-pressured zones behind
pipe (prevent lost circulation)
• Isolate over-pressured zones behind
pipe (prevent a kick)
• Isolate multiple producing zone
This Photo by Unknown Author is licensed under CC BY-SA-NC
43
43
Final Steps
Step #10: Continue this Process
to Drill to Total Depth
• Once final intermediate casing
string is run and cemented, drilling
process is continued until well
reaches the TD (Total Depth) of well
Step #12: Run and Cement
Production Casing String or Liner
Step #13: Complete the Well
Step #14: Rig Down and Move
Out
Step #11: Log Well with OpenHole Logs
• Open-hole logs are used to
measure certain properties of
subsurface formation
44
44
3 - Drilling
3-22
WHAT IS HORIZONTAL
DRILLING?
45
45
Horizontal Drilling
• Horizontal drilling: involves
deliberately shifting a well’s path from
the vertical until they are running
horizontally
• “Directional drilling” or “deviated drilling”
• Reasons for horizontal drilling:
• To avoid a surface site that is operationally
difficult or environmentally sensitive
• Drilling an offshore well from an onshore
site
• Reducing costs or surface impact by drilling
several wells in different directions from
the one surface location
• Enhancing oil and gas production by
drilling in a way that exposes more of the
reservoir to the wellbore
This Photo by Unknown Author is licensed under CC BY-NC-ND
46
46
3 - Drilling
3-23
How to Horizontally Drill
• Vertical well is drilled to the
Source: https://www.dmr.nd.gov/ndgs/documents/newsletter/2008Winter/pdfs/Horizontal.pdf
kickoff point located just above
targeted oil or gas layer
• Curved section of a horizontal
well is drilled using a hydraulic
motor mounted directly above
the bit and powered by drilling
fluid
• Steering of the hole is
accomplished through
employment of a slightly bent
or “steerable” downhole motor
47
47
https://www.youtube.com/watch?v=eBOtXD_UQSo
48
48
3 - Drilling
3-24
QUESTIONS?
49
49
3 - Drilling
3-25
OIL AND GAS
COMPLETIONS
Chapter 4
1
Overview
• What is the process of a well completion?
• What is hydraulic fracturing and why is it controversial?
• What is artificial lift and why is it needed?
• What is a workover?
2
2
4 - Completions and Workovers
4-1
What is a well completion?
• Well completion: the activities and methods of preparing a well
for the production of oil and gas or for other purposes, such as
injection
• Purposes of a well completion are to:
• Connect reservoir to surface so that fluids can be produced from or
injected into reservoir
• Provide a conduit for well stimulation treatments
• Isolate producing reservoir from other zones
• Protect integrity of reservoir, especially in unconsolidated formations
• Provide a conduit to measure changes in flow rate and pressure needed
to run a well test
3
3
Phases of Well Completions
1.
Casing - many consider the setting of the casing to be the first
step in a well completion
2.
Perforation – where holes are blasted through the casing at
precise locations for stimulation and production flow; often
done in conjunction with tubing, packing, and setting up the
Christmas tree
3.
Stimulation – hydraulic fracturing, acidizing; preparing the
rock formation for optimal flow
4
4
4 - Completions and Workovers
4-2
Three Types of Completion Methods
• Open-Hole Completions: a well
that is drilled to the top of the
hydrocarbon reservoir; the well
is then cased at this level, and
left open at the bottom
• Although not common in most
areas, open hole completions are
still used today in certain situations
• Casing is set prior to drilling into
the producing interval; a
nondamaging fluid can then be
used to drill into the pay section
5
This Photo by Unknown Author is licensed under CC BY-SA
5
Three Types of Completion Methods
• Liner Completions: Many
conventional well designs include a
production liner set across the
reservoir interval; this reduces the
cost of completing the well and
allows some flexibility in the design
of the completion in the upper
wellbore, such as when the fluid
characteristics make it beneficial to
increase the diameter of the conduit
and components
• Liner: any string of casing in which
the top does not extend to the
surface but instead is suspended from
inside the previous casing string
This Photo by Unknown Author is licensed under CC BY-NC-ND
6
6
4 - Completions and Workovers
4-3
Gravel Packing and Screens
• To prevent sand from entering the
wellbore, companies may also opt for
a sand control technique – or
combination of techniques – that
include various types of sand screens
and gravel packing systems
• Wire screens and gravel pack work
together to filter out sand that might
have otherwise entered the
wellstream with the hydrocarbons
This Photo by Unknown Author is licensed under CC BY
7
7
Three Types of Completion Methods
• Perforated Cased-Hole Completions: production casing is run
along the entire length of the well and through the reservoir
• The cased hole acts as a control mechanism for safe production
of desired hydrocarbons and as a barrier preventing the
reintroduction of unwanted fluids, gases, and solids into the
wellbore
• Casing must be perforated to stimulate production from viable
sections of the reservoir called “pay zones”
8
8
4 - Completions and Workovers
4-4
Perforating the Casing
• Purpose of perforating the
production casing is to provide
effective flow communication
between the wellbore and the
reservoir
• Majority of wells use a shaped
charge perforating system
• Perforating guns can be
expendable, semi-expendable,
or retrievable
Source: USGS, https://www.usgs.gov/media/images/perforating-gun-hydraulic-fracturing
9
9
Well Stimulation Techniques
• Acidizing: injection of chemicals to
eat away at any skin damage,
"cleaning up" the formation,
thereby improving the flow of
reservoir fluids
• Fracturing: creating and extending
fractures from perforation tunnels
deeper into the formation,
increasing surface area for
formation fluids to flow into well,
as well as extending past any
possible damage near the wellbore
This Photo by Unknown Author is licensed under CC BY-SA
10
10
4 - Completions and Workovers
4-5
Production String
• Production String: primary conduit
through which reservoir fluids are
produced to surface
• Production string is typically
assembled with tubing and
completion components in a
configuration that suits the wellbore
conditions and the production
method
• An important function of production
string is to protect primary wellbore
tubulars, including the casing and
liner, from corrosion or erosion by the
reservoir fluid
This Photo by Unknown Author is licensed under CC BY-ND
11
11
Production Tubing
• Production Tubing: along with other
components that constitute the
production string, provides a continuous
bore from the production zone to the
wellhead through which oil and gas can be
produced
• Tubing is usually between five and ten
centimeters in diameter
• Purpose and design of production tubing is to
enable quick, efficient, and safe installation,
removal and re-installation
• Tubing Packer: a sealing device that
isolates and contains produced fluids and
pressures within the tubing string
12
This Photo by Unknown Author is licensed under CC BY-NC-ND
12
4 - Completions and Workovers
4-6
Wellhead and Christmas Tree
• Wellhead: surface termination of a
wellbore that incorporates facilities for
installing casing hangers during the well
construction phase
• Consists of the casing head, the tubing head,
and the christmas tree
• Christmas Tree: An assembly of valves,
spools, pressure gauges and chokes fitted
to wellhead of a completed well to control
production
• Primary function of a tree is to control flow into
or out of the well
• Additional functions include chemical injection
points, well intervention means, pressure relief
means, and well monitoring points
This Photo by Unknown Author is licensed under CC BY-SA
13
13
14
https://www.youtube.com/watch?v=iXdq65xzsus
14
4 - Completions and Workovers
4-7
HYDRAULIC
FRACTURING
15
15
What is hydraulic fracturing?
• Hydraulic Fracturing: making use
of a liquid to fracture the reservoir
rocks by pumping the fracturing
fluid into the wellbore at a rate
sufficient to increase pressure
downhole to exceed the strength
of the rock
• Also known as “Fracking” or “Frac”
• Fracking can be completed on
both horizontal and vertical wells
• Multiple fracking intervals may be
performed along the length of the
well (“stages”)
This Photo by Unknown Author is licensed under CC BY
16
16
4 - Completions and Workovers
4-8
The Hydraulic Fracturing Process Preparing
• Before fracking begins, operators perform several tests to
confirm that the well and associated equipment can withstand
the pressures of the fracturing operation
• A perforating tool is then lowered into the wellbore to create
small holes in the production casing
• Next the frac job begins
• On a well with a long horizontal section in the hydrocarbon-bearing
formation, the well is not perforated and fracked all at once; rather it is
done in a series of stages each being several hundred feet in length
17
17
The Hydraulic Fracturing Process –
Equipment
• Wellhead: pipe extending up from the ground with a shut off
valve above it and pipelines attached to carry a specific formula
of water, sand, and chemicals to frac well
• Pump trucks: positioned next to the well; powerful (1,200 to
2,500 horsepower) pumps move the materials into the formation
• Blender truck: pulls together the material needed to frac the
well; a long mixing machine that takes sand, or ceramic bead
propping agent, water, and chemicals to prepare a gel that
carries the propping agent into the formation as deeply as
possible
18
18
4 - Completions and Workovers
4-9
The Hydraulic Fracturing Process –
Equipment
• Chemical supply trucks: a stake-body truck with placards
showing if and what types of hazardous chemicals are on board
• Sand hogs: sand or proppant multi-compartment containers;
connected to the blender by an auger or conveyor
• Water storage: ponds (“impoundments”) or tanks (“frac tanks”)
• Frac operator van: has computers, electronic monitoring and
communications equipment from which to direct all fracturing
operations
• Flowback tanks: collect flowback water
19
19
Fracturing Fluids
• In general, a fracturing fluid can be thought
as the sum of three main components:
Fracturing Fluid = Base Fluid + Additives + Proppant
• Base Fluids: Water, Foams, Oils, Emulsions,
etc.
• Additives: serve a variety of purposes to
optimize the performance of the injected
fluid, including viscosity control, corrosion
inhibition, and control of microbial activity
• Proppant: used to prop open the fractures,
predominantly consists of quartz sand
• The sand proppant is sometimes coated with
resins to improve performance, and ceramic
materials can also be used instead of sand
Source: https://prd-wret.s3-us-west2.amazonaws.com/assets/palladium/production/s3fspublic/Hydraulic_Fracturing_Sand.jpg
20
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4 - Completions and Workovers
4-10
Typical Chemical Additives
21
21
Typical Chemical Additives
• Frac fluids typically contain 3-12 chemical
additives, depending on the characteristics
of the water and the shale formation being
fractured
• Typical additives include:
• friction reducers to allows fracturing fluids and
proppants to be pumped to the target zone at a
higher rate and reduced pressure
• biocides to prevent microorganism growth and
to reduce biofouling of the fractures
• oxygen scavengers and other stabilizers to
prevent corrosion of metal pipes
• acids that are used to remove drilling mud
damage within the near-wellbore area
22
22
4 - Completions and Workovers
4-11
Source: https://prd-wret.s3-us-west-2.amazonaws.com/assets/palladium/production/s3fspublic/Withdrawing_Water_for_Hydraulic_Fracturing.jpg
Water Use in Hydraulic Fracturing
• Drilling and hydraulic fracturing of a horizontal shale gas well
typically requires 2 - 6 million gallons of water
• Water sources include groundwater, surface water, treated
wastewater, and flowback or produced water
• Although water needed for drilling an individual well may represent a
small volume over a large area, withdrawals may have a cumulative
impact to watersheds over the short term
• Affects water availability during periods of low stream flow, which could affect
fish and other aquatic life, fishing and other recreational activities, municipal
water supplies, and other industries such as power plants
• Companies may be required to provide a water management plan
prior to withdrawals from water resources
23
23
Steps of Hydraulic Fracturing
1.
Acid Stage: several thousand
gallons of water mixed with a
dilute acid are pumped into
the well
• Clears cement debris in wellbore
and provide an open conduit for
other frac fluids by dissolving
carbonate minerals and opening
fractures near wellbore
2.
Pad stage: approximately
100,000 gallons of slickwater
without proppant material
are pumped into the well
• High-pressure of the frac fluids and
continual pumping increases
pressure in the well, overcoming
strength of the reservoir rocks to
break them apart
• Creates fractures and opens
formation; helps to facilitate the
flow and placement of proppant
material
24
24
4 - Completions and Workovers
4-12
Steps of Hydraulic Fracturing
3.
Prop sequence stage: water
combined with proppant
material are introduced into
well to extend breaks and
pack them with proppants
4.
Flushing stage: consisting of
a volume of fresh water
sufficient to flush excess
proppant from the wellbore
• Stage may collectively use several
hundred thousand gallons of water
• Proppant material may vary from a
finer particle size to a coarser
particle size throughout this
sequence
25
25
Fracturing and Fracture Monitoring
• Fracking produces a break in the
rock
• Usually 2 to 3 mm in width (1/10th to
1/8th inch)
• Formed in the direction perpendicular to
the least stress
• At depths < ~ 2000 ft, horizontal fractures
are more likely (parallel to the plane of
the formation)
• At depths > 2000 ft, vertical fractures are
more likely
• Length/height of a fracture is
This Photo by Unknown Author is licensed under CC BY-SA-NC
controlled by upper confining zone
or formation, and volume, rate, and
pressure at which frac fluid is
pumped
26
26
4 - Completions and Workovers
4-13
https://www.youtube.com/watch?v=qjP-K1VaI1k
27
27
Flowback Water
• Flowback: fluid that initially returns to the surface after hydraulic fracturing
after injection pressure applied to oil or gas production well is released
• Flowback water is primarily fracking fluid, mixed with natural formation
water and natural gas
• Generally, flowback water has been found to contain:
• Salts, including those composed from chloride, bromide, sulfate, sodium, magnesium,
and calcium;
• Metals, including barium, manganese, iron, and strontium;
• Naturally-occurring organic compounds, including methane, benzene, toluene,
ethylbenzene, xylenes (BTEX), VOCs, and oil and grease;
• Radioactive materials, including radium; and
• Hydraulic fracturing chemicals and their chemical transformation products
28
28
4 - Completions and Workovers
4-14
Flowback Water Volumes
• Flowback water volumes vary by
well, rock formation, and time after
hydraulic fracturing
• Hundreds of thousands to millions
of gallons of flowback water need
to be collected and handled at the
well site
• Volume of water produced per day
generally decreases with time
• Flowback water and produced
water flows from well to on-site
tanks or pits through a series of
pipes before being transported
offsite for disposal or reuse
Source: Stern, Pete. Loyalsock State Forest, Flyover - PA 2013. 10/9/2013. Provided by
FracTracker Alliance, fractracker.org/photos
• Spills can occur, which may affect
drinking water
29
29
Flowback Water Disposal
• Dependent on each state’s regulations for disposal, energy
companies often have four different methods to choose from:
• Deep well injection - involves blasting of fluids deep into the earth’s core
at high pressures
• Injection wells are structurally similar to natural gas and oil wells with cement
casings and pipe that run thousands of meters down into rock layers
• Open air pits - flowback fluid is collected and often sent through pipelines
to bodies of water which would appear to be man-made ponds to the
untrained eye
30
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4 - Completions and Workovers
4-15
Flowback Water Disposal
• Dependent on each state’s regulations for disposal, energy
companies often have three different methods to choose from:
• Treatment of the water - the removal of any solids and dissolved
inorganic substances, desalination, and special procedures for any
radioactive or carcinogenic materials at a wastewater treatment plant
(most expensive)
• Reuse and recycle – wastewater that is going to be reused for the
intended purpose of fracking
• The wastewater must be treated initially and then combined with water to
balance out the high salt concentrations
• Newer and more expensive method
31
31
https://www.youtube.com/watch?v=qjP-K1VaI1k
32
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4 - Completions and Workovers
4-16
ARTIFICIAL LIFT
33
33
Artificial Lift
• Artificial lift: the application of
pumps or gas injection to assist the
lifting of the heavier reservoir
liquids; a process used on oil wells
to increase pressure within the
reservoir and encourage oil to the
surface
• ~96% of oil wells in the US require
artificial lift from the start of production
• Even those wells that initially posses
natural flow to the surface, that pressure
depletes over time, and artificial lift is
then required
• Two main categories of artificial lift:
pumping systems and gas lifts
This Photo by Unknown Author is licensed under CC BY
34
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4 - Completions and Workovers
4-17
Beam Pumps
• Beam pumping: an artificial-lift
pumping system using a surface
power source to drive a downhole
pump assembly
• A beam and crank assembly (pumpjack)
creates reciprocating motion in a
sucker-rod string that connects to the
downhole pump assembly
• The pump contains a plunger and valve
assembly to convert the reciprocating
motion to vertical fluid movement
This Photo by Unknown Author is licensed under CC BY-SA
35
35
https://www.youtube.com/watch?v=X0Dpd52pfp0
36
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4 - Completions and Workovers
4-18
Hydraulic Pumps and Electric Submersible
Pumps
• Hydraulic Pumping: An
• Electric Submersible Pump
• A surface hydraulic pump
• The pump typically comprises
artificial-lift system that
operates using a downhole
pump that is hydraulically
driven
pressurizes crude oil called power
oil, which drives the bottom pump
• The power oil is pumped down the
tubing and a mixture of the
formation crude oil and power oil
are produced through the casingtubing annulus
System: An artificial-lift system
that utilizes a downhole
pumping system that is
electrically driven
several staged centrifugal pump
sections that can be specifically
configured to suit the production
and wellbore characteristics of a
given application
• Electrical submersible pump
systems are a common artificial-lift
method, providing flexibility over a
range of sizes and output flow
capacities
37
37
Gas Lift
• Gas Lift: An artificial-lift method in which
gas is injected into the production tubing to
reduce hydrostatic pressure of the fluid
column; resulting reduction in bottomhole
pressure allows the reservoir liquids to
enter wellbore at a higher flow rate
• Injection gas is typically conveyed down the
tubing-casing annulus and enters the production
train through a series of gas-lift valves
• Gas-lift valve position, operating pressures and
gas injection rate are determined by specific well
conditions
This Photo by Unknown Author is licensed under CC BY-SA 38
38
4 - Completions and Workovers
4-19
Enhanced Oil Recovery
• Enhanced oil recovery (EOR): the
process of recovering oil not
already extracted from an oil
reservoir through primary
(natural) or secondary (gas or
water injection) recovery
techniques; EOR methods alter
the chemical composition of the
oil itself, to make it easier to
extract.
• AKA “tertiary recovery”
• Three types of EOR: thermal
recovery, gas (CO2) injection,
chemical injection
This Photo by Unknown Author is licensed under CC BY-SA-NC
39
39
Gas Well Liquids Unloading
• Many gas wells produce some liquids at some stage in their life cycles
• When the accumulation of liquid results in the slowing or cessation of
gas production, removal of fluids (i.e., liquids unloading) is required in
order to maintain production
• Common courses of action to improve gas flow include:
• Shutting in the well to allow bottom hole pressure to increase, then venting the
well to the atmosphere (well blowdown)
• Swabbing the well to remove accumulated fluids
• Installing a plunger lift
• Installing velocity tubing
• Installing an artificial lift system
40
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4 - Completions and Workovers
4-20
WORKOVERS
41
41
Workovers
• Workover: Any work on the wellbore which changes the flowing
characteristics of the well or repairs a problem within the wellbore
• Some of the work and treatments which may be performed on a well
are:
• re-perforation job
• complete the well in a different zone
• stimulation treatments (acid, frac)
• remedial cementing
• chemical treatments to remove various types of deposits (dewaxing,
asphaltenes (tar like oil compound), scale, sand, sulphur or hydrates (freezing
off))
• repair leaking tubing or casing
• parted or broken sucker rods
• repair to a bottomhole pump
42
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4 - Completions and Workovers
4-21
Reasons for Workovers
• Workovers may be required for one or more of the following
reasons:
• Unsatisfactory production or injection rates
• Supplemental recovery project requirements
• Regulatory requirements
• Competitive drainage
• Reservoir data gathering
• Lease requirements
• Abandonments
43
43
Kill the Well
• Before a workover can begin, the well usually has to be killed
• This means that the pressure of the formation has to be equaled by
pressure from above, usually by injecting treated water, oil, or formation
water into the well
• This brings the flow of formation fluid to a temporary halt
• Well must be swabbed to unload liquids from the production tubing to reinitiate flow from the reservoir.
44
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4 - Completions and Workovers
4-22
Refracturing a Well
• Refracturing is a workover technique that involves reinvigorating
wells by performing secondary or tertiary hydraulic fracture
stimulation treatments
• Declining production rates from shale wells usually are more
rapid than wells in conventional reservoirs because of their
ultralow permeability, limited reservoir contact, and the original
completion strategy
• Companies either use the original access points to the reservoir
to extend existing fractures, or reperforate between the original
access points to create new fractures
45
45
Types of Workover Rigs
• Conventional Service Rig: looks very
much like a small drilling rig except
the conventional service rig is usually
a truck mounted mobile unit with a
derrick, which can be folded down for
transporting
• The conventional service rig performs
basic workover jobs usually involved
with the tubing
• For well work to be conducted with a
conventional service rig, the well
must be "dead"
• Coiled Tubing Units (CTU): are usually
trucks or trailers mounted with a
large reel containing a continuous coil
of thin-walled, small diameter tubing
(OD 20 to 38 mm, 3/4 to 1.5 ") which
will fit inside the existing tubing of
most wells
• The coiled tubing is fed to the injector
head, which will push the continuous
tubing string down into the well.
• The work which can be performed by
the CTU can be done without
removing the tubing
• Tubing units can work on "live" wells
(pressure at surface).
46
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4 - Completions and Workovers
4-23
Types of Workover Rigs
• Snubbing Units: also known as
hydraulic workover rigs, they
are set-up on top of the
wellhead and can push, pull or
rotate the tubing
• Once a joint of tubing has been
raised into the cylinder it can be
isolated from the well and
removed
• Snubbing units are designed
specially to handle work on
"live" wells
• Wireline Units: are typically
mounted on the back of a truck
with a wire on a reel
• The wire is run into the well
through a lubricator mounted
on the top of the wellhead,
which allows the wire to be run
in or out of a “live” well
• Three main types of units:
• Slickline
• Braided wireline
• Electric wireline
47
47
48
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4 - Completions and Workovers
4-24
EMISSIONS FROM
EXPLORATION
49
49
Combustion Sources
• Drilling rig engines, hydraulic
fracturing pump engines,
artificial lift engines
• Process characteristics
needed to estimate
emissions:
• Engine size and type (HP or KW)
• Operating hours
• AP-42 Emission Factors
Auch, Ted. Pump jack and flaring from well site off of Starvation Lake Road in NE Michigan.05/20/2016.
Provided by FracTracker Alliance, fractracker.org/photos.
50
50
4 - Completions and Workovers
4-25
Mud Degassing Emissions
• A degasser is used to remove
entrained gas in the drilling mud
• Electric motor will power a vacuum
pump which is applied to the vapor
space in horizontal, vertical or round
vessel
• Extracted gas is then either vented to
atmosphere or to a flare
• Emissions can be estimated on a daily
basis per EPA’s “Atmospheric
Emissions from Offshore Oil and Gas
Development and Production” (1977)
This Photo by Unknown Author is licensed under CC BY-SA
0.4 Mg NG/day = 882 lb NG/day
51
51
Well Venting from
Completions/Workovers
• Emissions are generated as gas is vented before well brought
into production
• Emissions are generated as gas entrained in the flowback fluid is
emitted through open vents at the top of flowback tanks
• Gas released from the liquids is vented to the atmosphere or
flared depending on regulatory requirements or other factors
• If the gas is vented, this may generate a significant amount of CH4, VOC,
and HAP emissions to the atmosphere
• Flaring generates a significant amount of combustion emissions
52
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4 - Completions and Workovers
4-26
Completions Control Techniques Green Completions
• Green Completions: an alternate practice that captures gas produced
during well completions and well workovers following hydraulic
fracturing
• Also known as “reduced emissions completions (RECs)”
• Green completions involves installing portable equipment that is
specially designed and sized for the initial high rate of water, sand,
and gas flowback during well completion.
• The objective is to capture and deliver gas to the sales line rather than
venting or flaring this gas
• 40 CFR 60 Subpart OOOOa requires use of green completion
methods
53
53
Well Venting from Liquids Unloading
• Well blowdowns involve the intentional manual venting of the well to
the atmosphere to improve gas flow
• The sales line connection is manually shut-off and well production is
routed to an atmospheric tank with lower back-pressure than the
production system
• This allows reservoir (gas) pressure to lift the liquid from the well
• The entrained gas is vented to the atmosphere at the tank, resulting in high
CH4, HAP, and VOC emissions
• Emission can be mitigated by using foaming agents or surfactants,
velocity tubing, plunger lift, and/or downhole pumps rather than
blowing down the well
54
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4 - Completions and Workovers
4-27
Liquids Unloading Control Technologies
- Plunger Lifts
• Plunger Lift: an artificial-lift method
principally used in gas wells to unload
relatively small volumes of liquid
• An automated system mounted on the
wellhead controls the well on an
intermittent flow regime
• When the well is shut-in, a plunger is
dropped down the production string;
when the control system opens the well
for production, the plunger and a column
of fluid are carried up the tubing string
• The surface receiving mechanism detects
the plunger when it arrives at surface
and, through the control system,
prepares for the next cycle
55
Source: EPA, https://www.epa.gov/sites/production/files/2016-06/documents/ll_plungerlift.pdf
55
https://www.youtube.com/watch?v=tF2-HL_Yxtc
56
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4 - Completions and Workovers
4-28
STATE REGULATIONS
ON HYDRAULIC
FRACTURING
Chapter 5
1
Pennsylvania Exemption 38
• All Exemption 38 categories ((a), (b), and (c)) are not required to
obtain a plan approval or operating permit
• Exemptions 38(a) and 38(b) apply to wells drilled before August
7, 2018
• Exemption 38(a) to wells drilled before August 10, 2013 and Exemption
38(b) to wells drilled on or after August 10, 2013 but before August 8, 2018
2
2
5 - State Fracking Regulations
5-1
Pennsylvania Exemption 38(c)
• Exemption 38(c)
• Reduced emission completions (i.e., green completions) at hydraulically fractured well
sites
• LDAR – semiannually
• Methane Emissions – Less than 200 tpy from each individual source
• VOC Emissions – Less than 2.7 tpy facility-wide
• Hazardous Air Pollutants (HAPs) – 0.5 tpy of individual HAP or 1 tpy of all HAPs facilitywide
• NOx emissions from engines – Less than 100 lbs/hr, 1000 lbs/day, 2.75 tons per ozone
season, and 6.6 tpy
• Compliance Demonstration through recordkeeping and reporting - Operator must keep
adequate records demonstrating compliance with the exemption criteria
• Showing compliance with the exemption criteria is additional to the recordkeeping and
reporting requirements of 40 CFR Part 60, Subparts OOOO and OOOOa
3
3
Pennsylvania GP-5A Permit
• GP-5A is a new general permit that is applicable to unconventional well sites and remote
pigging stations that do not meet Exemption 38
• Applicability: The GP-5A authorizes the construction, modification, and/or operation of
sources listed below at an unconventional natural gas well site or remote pigging station:
• Glycol Dehydration Units
• Stationary Natural Gas-Fired Spark Ignition Internal Combustion Engines
• Reciprocating Compressors
• Storage Vessels
• Tanker Truck Load-Out Operations
• Fugitive Emissions Components
• Natural Gas-Driven Pneumatic Controllers
• Natural Gas-Driven Pneumatic Pumps
• Enclosed Flares and Other Emission Control Devices
• Pigging Operations
• Wellbore Liquids Unloading Operations
4
4
5 - State Fracking Regulations
5-2
Pennsylvania GP-5A Permit Standards
• Establishes state BAT determinations for compressors, engines
• Incorporates state BAT and federal New Source Performance Standards
(NSPS) requirements for LDAR
• Incorporates state BAT for pigging operations
• Incorporates emission control threshold for methane (200 tpy) for each
glycol dehydration unit, storage vessel, natural gas-driven pump, and
pigging operation
• Applies indirectly to tanker truck load-out operations in that load-out operations must
meet the control requirements if connected to a storage vessel that has reached the
methane, VOC, or HAP emission threshold
• Incorporates federal NSPS and state requirements for other sources (e.g.
tanks, dehydrators, wellbore liquids unloading operations)
5
5
Pennsylvania GP-5A Permit –
Recordkeeping and Reporting
• Records retained for 5 years on site or at the nearest local field
office
• Records that demonstrate that the facility is not Title V
• Records of all written notifications
• Recordkeeping:
• Submit copies of applicable NSPS and NESHAP requests, reports,
applications, submittals, and other communications
• Submit EPA reports via CEDRI
• Annual reporting
6
6
5 - State Fracking Regulations
5-3
Pennsylvania Oil and Gas Surface
Regulations
• Chapter 78 – Conventional Wells
• Chapter 78a – Unconventional Wells
• Chapter 78 - Emergency Response Planning at Unconventional Well
Sites
• Chapter 79 - Oil and Gas Conservation
• Chapter 91 - General Provisions
• Chapter 95 - Wastewater Treatment Requirements
• Chapter 102 - Erosion and Sediment Control
• Chapter 105 - Dam Safety and Waterway Management
7
7
West Virginia Rule 13
• An air quality permit may be required prior to construction and operation of any air
emissions units under 45CSR13 (Rule 13)
• DAQ has developed General Permit G70-D, which covers a wide variety of emission
sources at a well pad
• “Rule of thumb” – brand new well sites that produce “Condensate” generally require an air
permit – 0.5 bbl (21 gallons/day production triggers a permit)
• Storage Tanks are considered “permanent” if they are “intended” to be located at a site for 180
consecutive days or more and could trigger Rule 13 permitting
• Air emissions units may be “stored/ received” on-site prior to an air permit being issued, but you may
not “install/erect” air emission units
• Permanent flares, enclosed combustors, or other incinerators automatically trigger a Rule
13 permit (other than temporary flowback flares/combustors used for 30 days or less)
• Rule 13 permitting threshold are facility-wide 6 lbs/hr VOC PTE or if the benzene
emissions are greater than or equal to 1,000 lbs/year PTE
• WVDAQ utilizes federal requirements (e.g., NSPS OOOOa) for completion activities
8
8
5 - State Fracking Regulations
5-4
West Virginia Horizontal Well Act
• Horizontal Well Act
• Passed December 14, 2011
• Regulates permitting, drilling, and fracking of horizontal wells
• Applicability: Applies to any natural gas well, other than a
coalbed methane well, drilled [after 12/4/2011] using a horizontal
drilling method, and which disturbs three acres or more of
surface, excluding pipelines, gathering lines and roads, or utilizes
more than two hundred ten thousand gallons of water in any
thirty day period.
9
9
West Virginia Horizontal Well Act –
General Requirements
• Obtain a horizontal well permit
• Prepare a soil erosion and sediment control plan
• Prepare a well site safety plan
• Prepare a site construction plan
• Prepare an after management plan
• Well location must be > 250 ft from existing water well or spring
• Meet minimum casing and cement standards
• Follow plugging requirements (when abandoning well)
10
10
5 - State Fracking Regulations
5-5
West Virginia Horizontal Well Act –
Recordkeeping and Reporting
• Retain following records for 3 years
• For production activities:
• Quantity of flowback water from hydraulic fracturing the well;
• Quantity of produced water from the well; and
• Method of management or disposal of the flowback and produced water
• For transportation activities:
• Quantity of water transported;
• Collection and delivery or disposal locations of water; and
• Name of the water hauling company
11
11
West Virginia Horizontal Well Act
• Enforcement by WV Department of Environmental Protection
(DEP) oil and gas inspectors
• The Horizontal Well Act required WV DEP to:
• Perform an air quality study and rulemaking (if necessary)
• Perform an impoundment and pit safety study and rulemaking (if
necessary)
• Studies were required to be completed by 2013
• In these reports, WV DEP determined that no additional
rulemaking was necessary
12
12
5 - State Fracking Regulations
5-6
Virginia Hydraulic Fracturing Standards
• The Oil and Gas Division within the Virginia Department of Mines, Minerals,
and Energy (DMME) is responsible for regulating fracking in Virginia
• The division enforces regulations on the following:
• Well construction, casing, and cementing
• Protection of underground and surface water
• The reporting and disclosure of the types of fluids used in fracking and at what volume
and a description of each chemical additive used in fracking
• The maximum amount of surface and injecting pressure used during the process
• Spill prevention and clean-up
• All other information considered necessary for the regulation of fracking for safety and
environmental protection
• Virginia does not have gas-specific air quality regulations, rely on federal
requirements
13
13
Virginia – Production Areas
• Marcellus Shale (west side of state) and Taylorsville Basin (coastal
plain)
• Special requirements apply to wells drilled in the Tidewater region
(coastal plain)
• An application for a drilling permit must be accompanied by an Environmental
Impact Assessment, which shall be reviewed by the Department of
Environmental Quality, distributed to all appropriate state agencies, and be
made available for public comment
• DMME cannot issue a permit to drill until the recommendations of DEQ have
been considered
• As of early 2014, the only producing gas and oil wells in Virginia are in
the southwestern part of the Commonwealth (Marcellus Shale).
14
14
5 - State Fracking Regulations
5-7
Virginia – Well Drilling / Groundwater
Requirements
• Independent lab test of any water well or spring within 500 feet of a
proposed well bore before drilling begins (baseline) and ongoing
groundwater testing
• Water used in drilling must be equal to or better than any groundwater
found within 500 feet of a proposed well
• Water used to drill through fresh groundwater horizons is required to meet
state water quality standards set by DEQ
• The well casing/cementing program for each well must be designed to
protect ground water resources and coal seams below the surface
• Virginia's casing program is a multi-casing and cementing program with the cement
circulated to surface
• This prevents contamination of groundwater, protects the coal resources, and isolates
the gas production
15
15
Virginia – Produced Water and Fracking
Fluid Requirements
• All waters and fluids produced during drilling and fracking must be captured in an
approved and properly constructed pit or approved tank for temporary storage.
• The Virginia Gas and Oil Act and Regulations do not allow off-site impacts or
discharges to surface waters.
• Virginia regulations provide for the option of ground application of fluids if lab tests,
conducted by an independent lab, show the fluids meet water quality standards.
• If the produced fluids do not meet quality standards, the operator is required to transport
fluids to an approved Class II EPA waste disposal well or other properly permitted facility for
permanent disposal.
• As of March 2017, Virginia regulations required fracking operators to complete and
submit a list of chemicals used during the fracking process on the website
FracFocus.org.
• Operators that consider a chemical or the concentration of a chemical to be a trade secret
are allowed to withhold these chemicals from public disclosure and thus disclosure to
potential competitors.
16
16
5 - State Fracking Regulations
5-8
North Carolina
• North Carolina lifted a ban on horizontal drilling and hydraulic fracturing in
March 2015
• Finalized oil and gas standards in November 2014, which included the
following hydraulic fracturing requirements:
• Well stimulation operations must be approved by the state through application
• Treating pressure cannot exceed 80% of the minimal internal pressure of production
casing
• Non-cemented portions of well must be tested to confirm that the wellbore can meet
70% of the activating pressure for sleeve completions or 70% of formation integrity for
open-hole completions
• Notification to the DENR by phone and mail of commencement of stimulation
operations
• Monitoring of pressure and flow that would be indicative of a potential loss of wellbore
integrity
17
17
North Carolina (Cont.)
• Finalized oil and gas standards in November 2014, which included the
following hydraulic fracturing requirements:
• Monitoring and installation of a PRD for well treatments that do not allow the
surface casing annulus to be open to atmosphere
• Monitoring and recording, at all times, the following parameters: surface
injection pressure, in pounds per square inch (psi), fluid injection rate in barrels
per minute (BPM), proppant concentration in pounds per thousand gallons, fluid
pumping rate in BPM, identities, rates, and concentrations of additives used,
and all annuli pressures.
• Submission of well stimulation report 30 days after conclusion
• Chemical disclosure data on fracfocus.org
• Fracking fluids cannot include BTEX, diesel, fuel oil, or kerosene
18
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5 - State Fracking Regulations
5-9
New Jersey & Delaware
• On November 30, 2017 the
DRBC released proposed rules
that would ban fracking in all
shale formations in the
Delaware River Basin
• Delaware River Basin Commission
(DRBC) includes PA, NY, NJ, & DE
• New Jersey and Delaware
otherwise do not have specific
regulations regarding well
completions
Source: Delaware River Basin Commission, https://www.state.nj.us/drbc/programs/natural/
19
19
Maryland
Fracking ban since October 1, 2017
This Photo by Unknown Author is licensed under CC BY
20
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5 - State Fracking Regulations
5-10
OIL AND GAS
OPERATIONS
Part 1
Chapter 6
1
Overview
• Well Pad Equipment Operation and Emissions
• Combustors
• Separators and Heater Treaters
• Atmospheric Storage Tanks
2
2
6 - Oil and Gas Ops Pt 1
6-1
3
Donnan, Bob. Drilling pad, PA. 12/22/2014. Provided by FracTracker Alliance, fractracker.org/photos
3
Donnan, Bob. Five wells on one pad, PA. 12/22/2014. Provided by FracTracker Alliance, fractracker.org/photos
4
4
6 - Oil and Gas Ops Pt 1
6-2
5
Donnan, Bob. Cross Creek County Park 41-44H well pad, PA. 12/22/2014. Provided by FracTracker Alliance, fractracker.org/photos
5
Equipment On a Well Pad
•
•
•
•
•
•
Wellheads
Separation Units
Tanks
Combustors
Lease Automatic Custody
Transfer (LACT) Unit
Remote Telemetry Unit
(RTU)
Stern, Pete. Loyalsock State Forest, Flyover - PA 2013. 10/9/2013. Provided by FracTracker Alliance, fractracker.org/photos
6
6
6 - Oil and Gas Ops Pt 1
6-3
Basic Crude Oil Process
Gas to
Gathering Line
or Flare
Separator
Associated Gas
Oil to Truck
Oil Stock Tanks
Water to Truck
7
Produced Water Tank(s)
7
Basic Natural Gas Process
Separator
Dehydration;
Compression
Water/Condensate
to Truck
Water/Condensate Tank(s)
Gas to Gathering
and Boosting
8
8
6 - Oil and Gas Ops Pt 1
6-4
https://www.youtube.com/watch?v=lWBhk6BAIao
9
9
Key Terms in Oil and Gas Production
API Gravity: measured as the inverse of the density of a petroleum
liquid relative to water
• The higher the API gravity, the lower the density of the petroleum liquid,
so light oils and condensates have high API gravities
Gas/Oil Ratio (GOR): amount of gas dissolved in oil
• Heavy oils (lower API gravity) has lower capacity to contain dissolved gas
than lighter oils
Gas Hydrates: ice-like solids that form when free water and
natural gas combine at high pressure and low temperature
10
10
6 - Oil and Gas Ops Pt 1
6-5
Associated Gas Venting
• Associated gas: a form of natural gas which is found with
deposits of petroleum, either dissolved in oil or as a free "gas
cap" above the oil in reservoir
• Associated gas is generally regarded as an undesirable
byproduct, which is either reinjected, flared, or vented
• Flaring is most common way of disposing of associated gas
11
11
Control Techniques –
Flares and Combustors
• Flaring is the controlled burning of natural
gas
• A flare system consists of a flare stack and
pipes that feed gas to the stack
• Emissions of SO2, CO2 and NOX are formed
as products of combustion
• Emissions of VOC and CH4 emissions may
result from incomplete combustion
• Typical control efficiency of a flare is 98-99.5%
Auch, Ted. Flare on well pad, Belmont County, Ohio May 2017. 5/3/2017. Provided by FracTracker Alliance,
fractracker.org/photos
12
12
6 - Oil and Gas Ops Pt 1
6-6
Control Techniques –
Flares and Combustors
• Combustors utilize a high-
temperature oxidation
process to destroy
hydrocarbons and VOCs
• Certain types of “enclosed
flares” and thermal oxidizers
are other examples of
combustors
This Photo by Unknown Author is licensed under CC BY-SA
13
13
Flares
This Photo by Unknown Author is licensed under CC BY
This Photo by Unknown Author is licensed under CC BY-ND
14
14
6 - Oil and Gas Ops Pt 1
6-7
Flare Emissions Estimation Methods
1.
Conversion of flare gas carbon to CO2
Calculation:
where
Molar volume conversion = conversion from molar volume to mass (379.3 scf/lbmole or 23.685
m3/kgmole);
MW CO2 = CO2 molecular weight;
Mass conversion = tonnes/2204.62lb or tonne/1000 kg;
A = the number of moles of Carbon for the particular hydrocarbon; and
B = the moles of CO2 present in the flared gas stream.
15
15
Flare Emissions Estimation Methods
1.
CH4 emissions from flares
Calculation:
where
CH4 E = emissions of CH4 (lb);
V = volume Flared (scf);
% residual CH4 = noncombusted fraction of flared stream (default =0.5% or 2%);
Molar volume conversion = conversion from molar volume to mass, (379.3 scf/lbmole or 23.685
m3/kgmole); and
MW CH4 = CH4 molecular weight.
16
16
6 - Oil and Gas Ops Pt 1
6-8
SEPARATORS &
HEATER TREATERS
17
17
What is a separator?
• Separator: A cylindrical or spherical vessel used to separate oil, gas
and water from the total fluid stream produced by a well
• AKA “Free water knockout” or “Trap”
• Separators can be classified into two-phase and three-phase
separators
• Two-phase type deals only with oil and gas; three-phase type handles oil, water
and gas
• Separators work on the principle that the three components have
different densities, which allows them to stratify when moving slowly
with gas on top, water on the bottom and oil in the middle
• Any solids such as sand will also settle in the bottom of the separator
18
18
6 - Oil and Gas Ops Pt 1
6-9
Horizontal vs. Vertical Separators
• Separators can be either
horizontal or vertical
• Horizontal – used to separate
mixtures with a high GOR; more
efficient at handling large
volumes of gas; better phase
separation capability
• Vertical – used to separate
mixtures with a low GOR; good
at solids handling; requires less
space
This Photo by Unknown Author is licensed under CC BY-SA-NC
19
This Photo by Unknown Author is licensed under CC BY-SA
19
How does a separator work?
• To remove oil from gas in separators:
• Gravity separation: particles of liquid
This Photo by Unknown Author is licensed under CC BY-SA
hydrocarbon in a stream of natural gas will settle
out if the velocity of the gas is sufficiently slow
• Impingement: Mist is impinged against a surface
and the liquid mist may adhere to and coalesce
on the surface
• Change of flow direction: When the direction of
gas flow is changed abruptly, inertia causes the
liquid to continue in the original direction of flow
• Change of flow velocity: A sudden increase or
decrease in gas velocity, using the difference in
inertia of gas and liquid
• Centrifugal force: Centrifugal force throws the
liquid mist outward against the walls of the
20
container
20
6 - Oil and Gas Ops Pt 1
6-10
How does a separator work?
• Methods used to remove gas
from crude oil in separators:
• Agitation: Agitation usually will
cause the gas bubbles to coalesce
and to separate from the oil
• Heat: This reduces surface tension
and viscosity of the oil and thus
assists in releasing gas that is
hydraulically retained in the oil
• Centrifugal force: Centrifugal force
throws the oil mist outward
against the walls of the container
21
This Photo by Unknown Author is licensed under CC BY
21
Heater Treater
• Heater treaters are heated vertical
or horizontal separators that are
typically used for the following
purposes:
• Break up emulsions to separate the oil
from produced water and inorganic
salts
• Solids (sediment) removal
• Stabilize the crude oil or condensate by
separating volatile, lighter hydrocarbon
fraction (C1-C4) from the heavy, less
volatile fraction (C5+) for safety
reasons
• Prevents the formation of ice and
natural gas hydrates
Donnan, Bob. 7 'heater treaters' and a vapor destruction unit (left), PA. 12/22/2014. Provided by
FracTracker Alliance, fractracker.org/photos
22
22
6 - Oil and Gas Ops Pt 1
6-11
How does a heater treater work?
• Mixture of hydrocarbon liquids,
gases, and water from the wellbore
enters top of the treater into a gas
separation section
• Oil and water travel down through
vessel to the heated section where
heat breaks the emulsion, allowing
water and oil to separate
• The water settles to the bottom of
vessel while the oil rises to the top
23
Source: TCEQ,
https://www.tceq.texas.gov/assets/public/implementation/air/am/contracts/reports/ei/5821199776FY131720130831-erg-upstream_oil_gas_heaters_boilers.pdf
23
GPUs
• Gas Production Units (GPUs)
consist of an indirect heater and
separator, skid mounted with
interconnecting piping and
instrumentation, ready for
operation
• AKA “Gas Processing Units”
• It is self-contained; GPUs arrive
on a skid and are prepared to
begin processing once they are
tied into the flowline, stock
tanks, and sales line
Leiter, Leann. Equipment near Johnston Compressor Station, Chartiers Twp. PA, April 2017.
4/23/2017. Provided by FracTracker Alliance, fractracker.org/photos
24
24
6 - Oil and Gas Ops Pt 1
6-12
Emissions from Separators, Heater
Treaters, and GPUs
• Separators do not have any direct emission points
• Separated gas flows to gas line
• Oil/condensate and water flows to storage tanks through dump valve
• Separator temperature and pressure affect emissions quantities
from storage tanks
• Heater Treaters and GPUs have combustion emissions from the
burner used to provide heat
• Combustion emissions (NOX, CO, PM, VOC, HAP, etc.)
25
25
ATMOSPHERIC
STORAGE TANKS
26
26
6 - Oil and Gas Ops Pt 1
6-13
Atmospheric Storage Tanks
• Oil and condensate produced from the
separator are piped to storage tanks
until they can be transported offsite
• Tanks may also store produced water
(water occurring naturally from
underground formations and brought to
the surface during exploration and
production)
• During storage, light hydrocarbons
dissolved in the crude oil or condensate
vaporize or "flash out" and collect in
the space between the liquid and the
roof of the tank
• As liquid level in the tank fluctuates,
these vapors are often vented to
atmosphere
Auch, Ted. Morrow Co. Ohio Clinger Nelson Class II Injection Well.10/16/2015. Provided by
FracTracker Alliance, fractracker.org/photos.
27
27
Type of Storage Tanks
• Fixed roof (vertical and
horizontal)
• External floating roof
• Domed external (or covered)
floating roof
• Internal floating roof
• Variable vapor space
• Pressure (low and high)
This Photo by Unknown Author is licensed under CC BY
28
28
6 - Oil and Gas Ops Pt 1
6-14
Tank Batteries
• A group of tanks that are connected to receive crude oil or
condensate production from a well or a producing lease
• In the tank battery, the oil volume is measured and tested before
pumping the oil into the pipeline system
29
This Photo by Unknown Author is licensed under CC BY
29
Types of Storage Tank Emissions
• Process Emissions:
• Flashing Losses: emissions that occur when a liquid with entrained gases
goes from a higher-pressure to a lower-pressure
• Working Losses: emissions due to displacement of the vapors within the
storage tank as a tank is filled or emptied
• Breathing Losses: emissions due to displacement of vapor within the
storage tank due to changes in the tank temperature and pressure
throughout the day and throughout the year
• Also known as “standing losses”
• Leaks: Open or leaking thief hatches are a significant source of
emissions
30
30
6 - Oil and Gas Ops Pt 1
6-15
Storage Tank Emissions
• The largest component of tank vapors is methane, but also may
include ethane, butane, propane, CO2 and HAP such as BTEX and nhexane
• Emissions are generally affected by the separator temperature,
separator pressure, annual average daily throughput, reid vapor
pressure (RVP), stream composition
• Last stage separator will have direct impact on storage tank emissions
• Throughput may be determined based on well production or turnover in tank
• The higher the separator pressure, the larger the pressure drop the separator
liquid experiences when reaching the storage tank, the more emissions
expected
• The higher the RVP of the final liquid, the more volatile it is, and the higher the
emissions
31
31
Storage Tank Emissions Estimation
Methods
Flashing Emissions - Laboratory GOR
• A pressurized liquid sample is collected from a point between the last stage
separator and the first storage tank, and then analyzing the sample in a laboratory
to determine the gas-oil ratio (GOR)
• The pressurized sample is allowed to flash in the laboratory to ambient conditions,
and the relative volumes of gas and oil are measured to determine the GOR
• GOR may then be multiplied by the number of barrels produced from that well site
for a given time period in order to determine the volume of flash gas generated
during that time period
• Laboratory speciation of the flash gas is conducted to determine the molecular
weight of the gas, as well as to determine the contribution of individual
constituents to arrive at a value of VOC gas per barrel of oil produced
1.
32
32
6 - Oil and Gas Ops Pt 1
6-16
Storage Tank Emissions Estimation
Methods
Flashing Emissions - Direct Measurement
• Tank vent emissions can be measured directly, providing accurate
emissions estimates for the measured tanks, but this approach is
generally expensive and time consuming for large numbers of tanks
3. Flashing Emissions - Computer Simulation Modeling
• E&P Tanks – Calculates flashing, working, and breathing losses
• EPA TANKS – Calculates working and breathing losses
• Other software (Promax, Aspen HYSYS, etc.) – Calculated flashing,
working, and breathing losses
• Requires site-specific sampling of separator liquids & operational data
2.
33
33
E&P Tanks Example
http://content.4cmarke
tplace.com/presentatio
ns/TanksWastewater1Nesvacil_
Tanks_UpstreamO_GE
missionsInventoryCalc
ulationsStorageTanks.pdf
http://vibe.cira.colostate.edu/oge
c/docs/meetings/2015-0312/NationalOGEmissionWorkGro
up_031215_GLYCalc_EPTank4.pd
f
34
34
6 - Oil and Gas Ops Pt 1
6-17
Storage Tank Emissions Estimation
Methods
4.
Flashing Emissions - Vasquez-Beggs Equation
Calculation:
Step 1 – Calculate the specific gravity of the gas at 100 psig:
SGX = SGi x [1.0 + 0.00005912 x API x Ti x Log(Pi+14.7/114.7)
where
SGX = dissolved gas gravity at 100 psig;
SGi = dissolved gas gravity at initial conditions, where air = 1. A suggested default value for SGi is 0.90
API = API gravity of liquid hydrocarbon at final condition;
Ti = temperature of initial conditions (°F); and
Pi = pressure of initial conditions (psig).
35
35
Storage Tank Emissions Estimation
Methods
4.
Flashing Emissions - Vasquez-Beggs Equation
Calculation:
Step 2 – Calculate the flash GOR:
RS = C1 x SGX x (Pi + 14.7)C2 x exp(C3 x API/Ti + 460)
where
RS = ratio of flash gas production to standard stock tank barrels of oil produced, in scf/bbl oil (barrels of oil corrected
to 60°F);
SGX = dissolved gas gravity, adjusted to 100 psig. Calculated using Equation 5-16;
Pi = pressure in separator, in psig;
API = API gravity of stock tank oil at 60°F; and
Ti = temperature in separator, °F.
For API ≤ 30°API: C1 = 0.0362; C2 = 1.0937; and C3 = 25.724
For API > 30°API: C1 = 0.0178; C2 = 1.187; and C3 = 23.931
36
36
6 - Oil and Gas Ops Pt 1
6-18
Storage Tank Emissions Estimation
Methods
Working & Breathing Emissions - Calculations using AP-42
Equations
Source: EPA’s AP-42 Emission Factors, Chapter 7, Section 1, “Organic
Liquid Storage Tanks”
1.
Calculations: Several detailed equations, see AP-42 Chapter 7.1
Use EPA TANKS or E&P Tanks to calculate Working and Breathing
Losses!
37
37
Applicable Federal Regulations
• Tanks requirements can be found in:
• 40 CFR Part 60, Subpart Kb: Requires either fixed roof and internal
floating roof, external floating roof, or closed vent system and a control
device that reduces VOC emissions by 95%
• 40 CFR Part 60, Subpart OOOO & Subpart OOOOa: Maintain actual VOC
emissions < 4 tpy, or control VOC by 95% if PTE VOC > 6 tpy
• 40 CFR Part 63, Subpart HH: 95% control and inspect/monitor using
Method 21
• Part 98 Subpart W: GHG emissions reporting for atmospheric storage
tanks
38
38
6 - Oil and Gas Ops Pt 1
6-19
Storage Tank Control Techniques
• Generally two options for
controlling emissions from
storage tanks:
• Vapor Recovery Units
• Combustion/Flaring
This Photo by Unknown Author is licensed under CC BY-SA
39
39
Storage Tank Control Techniques –
Vapor Recovery Unit (VRU)
• Hydrocarbon vapors are drawn
out of the storage tank under lowpressure and are first piped to a
separator (suction scrubber) to
collect any liquids that condense
out
• The liquids are usually recycled
back to the storage tank
• From the separator, the vapors
flow through a compressor that
provides the low-pressure suction
for the VRU system.
• The vapors are then metered and
removed from the VRU system for
pipeline sale or onsite fuel supply.
Source: EPA Natural Gas Star, “Installing Vapor Recovery Units on Storage Tanks”
40
40
6 - Oil and Gas Ops Pt 1
6-20
Potential Additional Equipment on a
Well Pad
• Lease Automatic Custody Transfer (LACT) Unit: used to meter oil
into a pipeline if it is not trucked
• Dehydrators: remove water from gas stream before entering
gathering pipeline
• Compressors: pressure of gas may need to be increased before
entering gathering pipeline
• Pneumatic Controllers: used to control equipment onsite
• Remote Telemetry Unit: equipment to remotely monitor gas
production
41
41
QUESTIONS?
42
42
6 - Oil and Gas Ops Pt 1
6-21
OIL AND GAS
OPERATIONS
Part 2
Chapter 7
1
Overview
• What is a compressor station?
• Natural Gas Compressors and Drivers
• Blowdowns
• Generators
2
2
7 - Oil and Gas Operations Pt 2
7-1
U.S. Natural Gas Pipeline Network, 2009
3
3
U.S. Natural Gas Pipeline Compressor
Stations Illustration, 2008
4
Source: Energy Information Administration, Office of Oil & Gas, Natural Gas Division, Natural Gas Transportation Information System.
4
7 - Oil and Gas Operations Pt 2
7-2
What is a compressor station?
5
Lenker, Savanna. Compressor station within Loyalsock State Forest, PA.06/01/2016. Provided by FracTracker Alliance, fractracker.org/photos.
5
Components of a Compressor Station
• Separators
• Piping
• Compressors & Compressor Engines
• Generators
• Pigging Operations
• Storage Tanks
• Line Heaters
• Dehydrators
• Pneumatic Pumps
Donnan, Bob. Redd Compressor Station, PA. 12/22/2014. Provided by FracTracker Alliance,
fractracker.org/photos.
• Pneumatic Controllers
6
6
7 - Oil and Gas Operations Pt 2
7-3
Yard Piping and Suction Scrubber
• As the pipeline enters the
compressor station the
natural gas passes through
scrubbers, strainers or filter
separators (coalescing filter)
• Yard piping is used to move
the gas from the separators
to the gas compressors
• Leak emissions from valves,
flanges, connectors, etc.
This Photo by Unknown Author is licensed under CC BY
7
7
NATURAL GAS
COMPRESSORS AND
DRIVERS
8
8
7 - Oil and Gas Operations Pt 2
7-4
Natural Gas Compressors
• Two main types of compressors at an oil and gas compressor
station:
• Reciprocating Compressor: A piece of equipment that increases the
pressure of a process gas by positive displacement, employing linear
movement of the driveshaft
• Centrifugal Compressor: Any machine for raising the pressure of a natural
gas by drawing in low pressure natural gas and discharging significantly
higher pressure natural gas by means of mechanical rotating vanes or
impellers
• Other compressor types include screw compressors and axial
compressors
9
9
Reciprocating Compressors
• In a reciprocating
Source: US EPA Natural Gas Star, “Reducing Methane Emissions From Compressor Rod Packing Systems”
compressor, natural gas
enters the suction manifold,
and then flows into a
compression cylinder where
it is compressed by a piston
• Piston is driven in a
reciprocating motion by the
crankshaft powered by an
internal combustion engine
10
This Photo by Unknown Author is licensed under CC BY-SA
10
7 - Oil and Gas Operations Pt 2
7-5
11
https://www.youtube.com/watch?v=ITCu7gNMicc
11
Types of Reciprocating Compressors
• Separable vs. Integral
Compressors
• Separable Compressors: the
compressor and engine are two
separate pieces of equipment
• Integral Compressors: the
compressor and engine are one
single piece of equipment
• Single Stage vs. Multi Stage
Compressors
This Photo by Unknown Author is licensed under CC BY-NC-ND
12
12
7 - Oil and Gas Operations Pt 2
7-6
Emissions from Reciprocating
Compressors
• Leaks occur when high pressure
gas escapes through the rod
packing (“rod packing vent” and
“doghouse vent”)
• The piston is connected to its prime
mover by a rod, and the rod utilizes
rod packings to reduce wear on the
compressor components and to
seal in the gas pressure
• Emissions of CH4, VOC, and HAP
• Equipment leaks from flanges,
valves, connectors, etc.
• Identified using OGI camera
Source: US EPA Natural Gas Star, “Reducing Methane Emissions From Compressor Rod Packing Systems”
13
13
14
Source: http://www.gaselectricpartnership.com/GArielFugitiveEmissions.pdf
14
7 - Oil and Gas Operations Pt 2
7-7
Reciprocating Compressor Control
Techniques & Federal Regulations Req’s
• Regular replacement of rod
packing greatly reduces emissions
• Schedule of rod packing
replacement required by NSPS
OOOO (for gathering & boosting
compressor stations) and NSPS
OOOOa (for transmission
compressor stations)
• Must replace rod packing before either
of the following occur:
• Compressor has operated for 26,000
hours
• 36 months from the last replacement
Lenker, Brook. Compressor station within Loyalsock State Forest,
PA.06/01/2016. Provided by FracTracker Alliance,
fractracker.org/photos.
15
15
Reciprocating Compressor Drivers RICE
• Reciprocating compressors are typically
driven by natural gas-powered reciprocating
internal combustion engines (RICE)
• RICE are grouped into two categories: richburn and lean-burn
• Rich-burn engines operate with a minimum amount
of air required for combustion
• Lean-burn engines use 50% to 100% more air than is
necessary for combustion
• 2-stroke vs. 4-stroke
• 2-stroke: power cycle completed in 1 revolution of
crankshaft
• 4-stroke: power cycle completed in 2 revolutions of
crankshaft
This Photo by Unknown Author is licensed under CC BY-SA
16
16
7 - Oil and Gas Operations Pt 2
7-8
https://www
.youtube.co
m/watch?v=
LuCUmQ9F
xMU
17
17
https://www.youtube.com/watch?v=OGj8OneMjek
18
18
7 - Oil and Gas Operations Pt 2
7-9
RICE Emissions and Control Techniques
• Combustion emissions - NOX, CO, VOC, formaldehyde, SOX, PM, and
GHGs
• AP-42 Chapter 3.2 (Natural Gas-fired Reciprocating Engines)
• Control methods involve combustion control and post-combustion
control
• Combustion control – temperature control
• Higher temperatures favor complete consumption of the fuel and lower residual
hydrocarbons and CO but result in increased NOX formation
• Lean combustion dilutes the fuel mixture and reduces combustion temperatures and
therefore reduces NOX formation, but increases CO and VOC emissions
• Post-combustion controls: NSCR, SCR, Oxidation Catalyst
19
19
RICE Control Techniques - NSCR
• Nonselective catalytic reduction (NSCR) is an add-on NOX
control technology for exhaust streams with low O2 content
(rich-burn engines)
• Nonselective catalytic reduction uses a catalyst reaction to
simultaneously reduce NOX, CO, and hydrocarbon to water,
carbon dioxide, and nitrogen
• The catalyst is usually a noble metal
• Reduction level for NOX is > 95%, CO is >95%, and VOC is >50%
20
20
7 - Oil and Gas Operations Pt 2
7-10
RICE Control Techniques – Oxidation
Catalyst
• Oxidation catalysts convert CO and hydrocarbons to CO2 and
H2O
• Applied to lean-burn engines – conversion requires oxygen
• Catalysts are usually platinum or palladium
21
21
RICE Control Techniques - SCR
• Selective Catalytic Reduction (SCR) systems are add-on controls that
specifically target NOX
• Converts NOX to N2 and H2O
• SCR uses ammonia or urea injected into the exhaust stream upstream
of a catalyst
• SCR systems reduce NOX emissions by 90%
• Best suited for lean-burn engines
• Ammonia slip: emissions of unreacted ammonia that result from
incomplete reaction of the NOX and the reagent
• Permitted ammonia slip levels are typically 2 to 10 ppm (10 ppmvd in PADEP)
22
22
7 - Oil and Gas Operations Pt 2
7-11
RICE Applicable Federal Regulations –
40 CFR Part 60, Subpart JJJJ
23
23
RICE Applicable Federal Regulations –
40 CFR Part 63, Subpart ZZZZ
24
24
7 - Oil and Gas Operations Pt 2
7-12
Centrifugal Compressors
• Centrifugal compressors use a rotating
disk or impeller to increase the velocity
of the natural gas where it is directed
to a divergent duct section that
converts the velocity energy to
pressure energy
• These compressors are primarily used
for continuous, stationary transport of
natural gas in the processing and
transmission systems
• Single stage vs. Multi stage centrifugal
compressors
This Photo by Unknown Author is licensed under CC BY-SA
25
25
26
https://www.youtube.com/watch?v=s-bbAoxZmBg
26
7 - Oil and Gas Operations Pt 2
7-13
Components of a Centrifugal
Compressor
• Inlet: typically a simple pipe
• Centrifugal impeller: contains a
rotating set of vanes (or blades) that
gradually raises the energy of the
working gas
• Diffuser: downstream of the
impeller in the flow path; converts
the kinetic energy (high velocity) of
the gas into pressure by gradually
slowing (diffusing) the gas velocity
• Collector: gathers the flow from the
diffuser discharge annulus and
delivers this flow to a downstream
pipe
This Photo by Unknown Author is licensed under CC
BY-SA
27
This Photo by Unknown Author is licensed under CC BY-SA
27
Emissions from Centrifugal
Compressors
• The majority of methane
emissions occur through seal oil
degassing which is vented to the
atmosphere
• Centrifugal compressor wet seals: high
pressure seal oil circulates between
rings around the compressor shaft
• Oil absorbs the gas on the inboard side
• Little gas leaks through the oil seal
• Seal oil degassing vents to the
atmosphere (heaters, flash tanks, and
degassing techniques)
Source: EPA Natural Gas STAR, https://www.epa.gov/sites/production/files/201606/documents/ll_wetseals.pdf
• Equipment leaks from flanges,
valves, connectors, etc.
28
28
7 - Oil and Gas Operations Pt 2
7-14
29
Source: EPA Natural Gas STAR, “Routing Centrifugal Compressor Seal Oil De-gassing Emissions to Fuel Gas as an Alternative to Installing Dry Seal,” October 10, 2012.
29
Centrifugal Compressor Control
Techniques & Federal Requirements
• Centrifugal compressor dry seals
• Dry seal springs press stationary ring in seal
housing against rotating ring when compressor is
not rotating
• At high rotation speed, gas is pumped between
seal rings by grooves in rotating ring creating a high
pressure barrier to leakage
• 2 seals are often used in tandem
• Vent oil degassing vent to control device
• Per NSPS OOOO (for gathering & boosting
compressor stations) and NSPS OOOOa (for
transmission compressor stations) –
centrifugal compressors using wet seals
must reduce emissions by 95%
30
Source: EPA Natural Gas STAR, https://www.epa.gov/sites/production/files/2016-06/documents/ll_wetseals.pdf
30
7 - Oil and Gas Operations Pt 2
7-15
Centrifugal Compressor Drivers –
Turbines
• Natural gas-fired turbines are
used mainly as prime movers
to drive centrifugal
compressors
• Turbine is composed of three
major components:
• Compressor
• Combustor
• Power turbine
This Photo by Unknown Author is licensed under CC BY-SA
31
31
Turbine Emissions and Control
Techniques
• Combustion emissions - NOX, CO, VOC, formaldehyde, SOX, PM, and
GHGs
• AP-42 Chapter 3.1 (Stationary Gas Turbines)
• Control methods involve combustion control and post-combustion
control
• Combustion Controls:
• Steam or Water Injection - increases the thermal mass by dilution and thereby reduce
peak temperatures in the flame zone, reduces NOX emissions by >60%, increases CO
and VOC emissions
• Dry Controls - either lower the combustor temperature using lean mixtures of air and
fuel, fuel staging (Dry-Low NOX (DLN), Dry-Low Emissions (DLE), or SoLoNOX), or
decreasing the residence time of the combustor
• Post-Combustion Controls:
• Oxidation Catalyst (for CO, VOC, and HAP reduction)
• SCR (for NOX reduction)
32
32
7 - Oil and Gas Operations Pt 2
7-16
Turbine Applicable Federal Regulations
• NSPS Subpart KKKK:
• Regulates stationary combustion turbines with a heat input at peak load
of ≥ 10 MMBtu per hour that commence construction, modification, or
reconstruction after Feb 18, 2005
• NOX limits and SO2 limits
• Annual performance testing and fuel testing
• NESHAP Subpart YYYY
• Only applies to stationary combustion turbines located at major sources
of HAP
• Formaldehyde limit of 91 ppbvd (currently only for oil-fired turbines)
• Annual performance testing
33
33
BLOWDOWNS
34
34
7 - Oil and Gas Operations Pt 2
7-17
Compressor Blowdowns
• Natural gas compressors cycled on- and offline to match fluctuating
gas demand
• Peak and base load compressors
• When compressor units are shut down, typically the high pressure gas
remaining within the compressors and associated piping between
isolation valves is vented to the atmosphere (‘blowdown’) or to a flare
• Emissions are calculated based on the volume of piping blown down
35
Source: EPA Natural Gas STAR, https://www.epa.gov/sites/production/files/2016-06/documents/ll_compressorsoffline.pdf
35
Suction Header
Blowdown Gas to Atmosphere
Blowdown Valve
Discharge Header
Isolation Valve
Isolation Valve
36
36
7 - Oil and Gas Operations Pt 2
7-18
https://www.youtube.com/watch?v=IIqYh-OF4aA
37
37
Isolation and Blowdown
Valve Leaks
• Leaks from isolation or
blowdown valve identified
during LDAR survey (OGI)
• Isolation valves are closed to
isolate the compressor from
the pipeline
• Blowdown valves are closed
during normal operations and
when the compressor is
pressurized
38
Source: EPA Natural Gas STAR, https://www.epa.gov/sites/production/files/2016-06/documents/ll_compressorsoffline.pdf
38
7 - Oil and Gas Operations Pt 2
7-19
Blowdown and Valve Leaks Control
Techniques
• Significant reduction in emissions from compressors taken off-
line can be done in the following ways:
1. Maintain pipeline pressure on the compressor during
shutdown
2. Keep the compressor at fuel gas pressure and connect to the
fuel gas system
3. Keep the compressor at pipeline pressure and install a static
seal on the compressor rods
4. Install Ejector
39
39
https://www.youtube.com/watch?v=WtSH5V1YQvQ
40
40
7 - Oil and Gas Operations Pt 2
7-20
Pipeline Blowdowns and Pigging
• Pipelines can require repairs or maintenance throughout their lifetime as a
result of interior and exterior corrosion, gasket and weld leaks, failures of
defective materials, and damage caused by external factors
• Pipeline repairs and maintenance activities typically require depressurizing the affected
section of the pipeline
• Companies block off impacted pipeline segment and vent the gas in that segment to
atmosphere
• Pigging operations remove accumulated water and condensate liquids in
natural gas gathering pipelines or conduct pipeline integrity checks
• The “pig” is a spherical or bullet-shaped device that travels through the pipeline to push
liquids to their eventual destination
• When pig is launched and recovered, some of the natural gas in the chamber is vented
to the atmosphere
41
41
https://www.youtube.com/watch?v=IkQK4zhMM6w
42
42
7 - Oil and Gas Operations Pt 2
7-21
GENERATORS
43
43
Power Generators
• Generators provide power to
the compressor station
• If station is not connected to power
grid, generators provide power at
all times
• If station is connected to power
grid, generators provide power only
when there is a disruption of
primary electrical service to station
• Powered by reciprocating
engines or microturbines
This Photo by Unknown Author is licensed under CC BY-SA
• Combustion emissions - NOX, CO,
VOC, formaldehyde, SOX, PM, and
GHGs
44
44
7 - Oil and Gas Operations Pt 2
7-22
QUESTIONS?
45
45
7 - Oil and Gas Operations Pt 2
7-23
OIL AND GAS
OPERATIONS
Part 3
Chapter 8
1
Components of a Compressor Station
• Separators
• Piping
• Compressors & Compressor Engines
• Generators
• Pigging Operations
• Storage Tanks
• Line Heaters
• Dehydrators
• Pneumatic Pumps
Donnan, Bob. Redd Compressor Station, PA. 12/22/2014. Provided by FracTracker Alliance,
fractracker.org/photos.
• Pneumatic Controllers
2
2
8 - Oil and Gas Operations Pt 3
8-1
Storage Tanks
• Storage tanks are used at
compressor stations to:
• Collect and store condensate
liquids from separators on pipeline,
compressors, dehydrators, etc.
• Store chemicals for use in on site
processes (e.g., triethylene glycol,
methanol, mercaptan, etc.)
• Vented VOC, HAP, GHG
emissions
• Emissions calculated using
modeling programs
Leiter, Leann. Tanks near Johnston Compressor Station, Canonsburg PA, April 2017 . 04/26/2017.
Provided by FracTracker Alliance, fractracker.org/photos.
3
3
Indirect Line Heaters
• Line heaters: used to maintain temperatures as pressure decreases to
prevent formation of hydrates
• A line heater typically consists of three components: shell, firetube,
and coil
• Process stream flows through the coil, which is immersed in upper portion of the
liquid media bath (typically water) of the shell
• Coil preheats the flow stream before reducing pressure across a restricting
choke followed by post-heating coils
• Fuel is burned in firetube and indirectly transfers heat to media, then to coil, and
finally to process stream
• Combustion emissions from natural gas burner
4
4
8 - Oil and Gas Operations Pt 3
8-2
https://www.youtube.com/watch?v=qTP4JkQru2I
5
5
DEHYDRATORS
6
6
8 - Oil and Gas Operations Pt 3
8-3
Natural Gas Dehydrators
• Dehydrators are devices used
to remove excess water from
natural gas through contact
with a dewatering agent
• Dewatering agents may be
triethylene glycol (TEG) (most
common), diethylene glycol (DEG),
or ethylene glycol (EG)
• Both liquid and solid desiccants
can be used for dehydration
• Water content in pipeline
quality natural gas should not
exceed 7 lbs/MMscf
This Photo by Unknown Author is licensed under CC BY-SA
7
7
Dehydration Process
Lean glycol is pumped
through top of contact
tower
Hot lean glycol is pumped
through a heat exchanger
Wet natural gas is
pumped through
the bottom of
contact tower
Glycol absorbs water from
the natural gas stream
and becomes rich glycol
GHGs, HAP (BTEX), VOC
Rich glycol enters the
reboiler where the glycol
is heated to boil off water
to become lean glycol
Rich glycol leaves the
bottom of the contact
tower and is pumped
through a heat exchanger
Dry natural gas
leaves the top of the
contact tower
8
8
8 - Oil and Gas Operations Pt 3
8-4
Dehydrator Equipment
• Contact Tower: the vessel in which the
mass transfer of the water occurs from the
gas to the glycol
• AKA “Contactor” or “Absorber”
• Bubble cap trays or packing inside
• Stripping gas may be used to remove water
• Reboiler: heats the glycol to near its
boiling point which releases all of the
absorbed water and any other compounds
This Photo by Unknown Author is licensed under CC BY-SA
• AKA “Regenerator” or “Still”
• Rich glycol is preheated through heat exchanger
before entering reboiler
• Heat is supplied through fire tubes in reboiler
• Fire tube heat is provided by burning natural gas
9
This Photo by Unknown Author is licensed under CC BY-SA
9
Dehydrator Equipment
• Flash tank: allows light
hydrocarbons to flash off from
rich glycol prior to regenerator
• Flash gas typically routed to
reboiler burner or fuel line, but may
be flared or vented to atmosphere
• Glycol Pump: either gas-
assisted pumps or electric
pumps move glycol through the
dehydration system
• Gas-assisted pumps send more gas
to be boiled off in the reboiler,
resulting in more emissions
Source: EPA Natural Gas STAR, https://www.epa.gov/sites/production/files/2016-06/documents/ll_flashtanks3.pdf
10
10
8 - Oil and Gas Operations Pt 3
8-5
https://www.youtube.com/watch?v=SZIr2Esnp-E
11
11
Dehydrator Emissions &
Control Techniques
• 3 dehydrator emission sources:
still vent, flash tank vent, and
reboiler burner
• Emissions of GHGs, BTEX, and VOC
from still vent and flash tank vent
• Combustion emissions from reboiler
burner
• Control techniques include
process optimization (installation
of a flash tank, optimization of
glycol circulation rate) and add-on
controls (condensers,
flares/combustion, and vapor
recovery units)
This Photo by Unknown Author is licensed under CC BY-SA
12
12
8 - Oil and Gas Operations Pt 3
8-6
Dehydrator Control Techniques –
Process Optimization
1.
2.
Adding a Flash Tank
Reduce Glycol Circulation Rate
• Emissions from a glycol dehydrator are directly proportional to the
amount of TEG circulated through the system
• Over-circulation of glycol results in more emissions without significant
and necessary reduction in gas moisture content
• Minimum Glycol Circulation Rate:
∗ ∗
Given:
24 ℎ/
F = gas flow rate (MMcf/d)
I = Inlet water content (lb/MMcf)
O = Outlet water content (lb/MMcf) (Rule-of-thumb is 4)
G = Glycol-to-water ratio (gal TEG/lb water) (Rule-of-thumb 3)
L(min) = minimum TEG circulation rate (gal/hr)
13
13
Dehydrator Control Techniques –
Process Optimization
3.
Replace Gas-Assisted Glycol Pumps with Electric Pumps
• Electric motor driven pumps have less design-inherent emissions and no
pathway for contamination of lean TEG by the rich stream
• Using electric glycol pumps reduces methane emissions by > 33%
14
Source: EPA Natural Gas STAR, https://www.epa.gov/sites/production/files/2016-06/documents/ll_glycol_pumps3.pdf
14
8 - Oil and Gas Operations Pt 3
8-7
Dehydrator Control Techniques –
Condenser
• Condensers can be natural convection air cooled (NCAC), fan
cooled, or use a liquid cooling medium such as rich TEG
• The liquids condensed from a condenser are primarily water and
are usually routed to a storage tank
• Hydrocarbon liquids are decanted and sold, water is decanted
and routed for disposal
• The uncondensed vapors from a condenser are routed to the
atmosphere, or to a flare or burner box
15
15
Absorption vs. Adsorption
• Absorption occurs when water vapor is taken out by a
dehydrating agent
• Glycol dehydration is an example
• Glycol solution will absorb water from wet gas
• Adsorption occurs when water vapor is condensed and collected
on the surface of a dehydrating agent
• Solid-desiccant dehydration is primary form of dehydrating natural gas
using adsorption
16
16
8 - Oil and Gas Operations Pt 3
8-8
Desiccant Dehydrators
• Desiccant dehydrators use moisture-
absorbing salts to remove water from the
gas
• Salts naturally attract and adsorb moisture,
gradually dissolving to form a brine solution
• Process:
• Wet gas flows upward through a drying bed of
desiccant salts
• Desiccant salts mix with water vapor to form
brine, which collects at the bottom of the unit
• The only gas emissions occur during
desiccant vessel depressurizing for salt
refilling, typically one vessel volume per
week
17
Source: EPA Natural Gas STAR, https://www.epa.gov/sites/production/files/2016-06/documents/ll_desde.pdf
17
Dehydrator Federal Regulations
• NESHAP Subpart HH:
• Includes both major and area sources
of HAP at production sites
• Major source dehydration unit: 95%
control; inspect and monitor using
Method 21
• Area source TEG dehydration units:
• In urban areas, use same control as for
major sources
• In rural areas, operate at optimal
glycol recirculation rate
• NEHSAP Subpart HHH:
• Only major sources of HAP at
transmission sites
• Large units must route emissions to a
control device
• reduce TOC/HAP by 95%, or
• reduce outlet concentration of
TOC/HAP to 20 ppmv, or
• reduce benzene emissions to less than
0.90 Mg/year (1 tpy)
• Small units must limit BTEX emissions
• route emissions to a control device, or
• meet an emissions limit through
process modifications
18
18
8 - Oil and Gas Operations Pt 3
8-9
PNEUMATIC PUMPS
19
19
Pneumatic Pumps
• Pneumatic pumps are primarily used for glycol circulation or for
injecting chemicals used in normal operations
• AKA “Kimray pumps”
• Two common types of pneumatic pump: piston and diaphragm
• Pressurized gas provides energy to driver side of pump, which
operates a piston or flexible diaphragm to draw fluid into pump
• Motive side of pump delivers energy to fluid being moved in order to
discharge fluid from the pump
• The pressurized natural gas, after being used to operate the pump, is
often vented to atmosphere through an exhaust port
• Emissions of CH4, VOC, and HAP
20
20
8 - Oil and Gas Operations Pt 3
8-10
https://www.youtube.com/watch?v=Y6To-bgL4GE
21
21
Pneumatic Pump Control Techniques &
Federal Regulations
Replace pneumatic pumps with electric pumps, including solar
electric pumps for smaller applications such as chemical and
methanol injection
2. Routing natural gas-driven pump emissions to an existing
combustion device or vapor recovery unit
1.
• Emissions from natural gas-driven chemical/methanol pumps and
diaphragm pumps can be reduced by 95 percent if an existing control
device is already available on site
• Control of pneumatic pumps is required by NSPS OOOOa
• Zero bleed rate at natural gas processing facilities
• 95% reduction if control or process available onsite at well sites
22
22
8 - Oil and Gas Operations Pt 3
8-11
PNEUMATIC
CONTROLLERS
23
23
Controllers
• Controllers are automated instruments used for maintaining liquid
levels, pressure, and temperature at gas sites
• Controllers are either pneumatic, electrical, or mechanical
• Majority are pneumatic controllers using high-pressure natural gas
• Variables most commonly controlled in upstream oil and gas are:
• Fluid level
• Pressure
• Temperature
• Differential pressure
• Position
• Safety
24
24
8 - Oil and Gas Operations Pt 3
8-12
This Photo by Unknown Author is licensed under CC BY-SA
This Photo by Unknown Author is licensed under CC BY-SA
25
25
How does a pneumatic controller work?
• Clean, dry, pressurized natural gas
is regulated to a constant
pressure, usually around 20 psig
• A small stream is sent to a device
that measures a process condition
(liquid level, gas pressure, flow,
temperature)
• This device regulates pressure of this
small gas stream (from 3 to 15 psig) in
proportion to process condition
• Stream flows to pneumatic valve
controller, where its variable
pressure is used to regulate a
valve actuator
Source: EPA Natural Gas STAR, https://www.epa.gov/sites/production/files/2016-06/documents/ll_pneumatics.pdf
26
26
8 - Oil and Gas Operations Pt 3
8-13
Classifying Pneumatic Controllers
• Is controller used for on/off control, or does it throttle the process?
• On/off controllers: when controller senses a change in a process variable, valve is
either fully opened or fully shut
• Throttling controllers: controller is required to control an end device in an
intermediate position
• Does controller bleed supply gas continuously (continuous bleed), or
does it vent actuation gas at the end of on cycle (intermittent bleed)?
• Continuous bleed devices: used to modulate flow, liquid level, or pressure and
will generally vent gas at a steady rate
• Intermittent bleed devices: release gas only when they stroke a valve open or
closed or as they throttle gas flows
• Zero-Bleed, self-contained devices: release gas into downstream pipeline, not to
atmosphere
27
27
https://www.youtube.com/watch?v=FzpmciSfOa0
28
28
8 - Oil and Gas Operations Pt 3
8-14
https://www.youtube.com/watch?v=9djN5ukONAc
29
29
High Bleed vs. Low Bleed
• Bleed rate of a pneumatic
controller defines standard to
which device is applicable
• High bleed pneumatic
controller: ≥ 6 scf/hr bleed
rate
• Low bleed pneumatic
controller: <6 scf/hr bleed
rate
30
Source: EPA Natural Gas STAR, https://www.epa.gov/sites/production/files/2016-06/documents/ll_instrument_air.pdf
30
8 - Oil and Gas Operations Pt 3
8-15
Pneumatic Controller Emissions &
Control Techniques
• When natural gas is vented or bled from a pneumatic controller, emissions
of CH4, VOCs, and HAP are produced
• Emissions determined by exhaust rate (continuous bleed) and actuation
volume and frequency (intermittent bleed)
• To reduce emissions from pneumatic devices:
1.
2.
3.
4.
5.
Replacement of high-bleed devices with low-bleed devices having similar
performance capabilities
Installation of low-bleed retrofit kits on operating devices
Enhanced maintenance, cleaning and tuning, repairing/replacing leaking gaskets,
tubing fittings, and seals
Convert gas pneumatic controls to instrument air, nitrogen gas, electric valve
controllers, or mechanical control systems
Implement a lower supply pressure
31
31
Pneumatic Controller Federal
Regulations
• Applicable federal regulations for pneumatic controllers include:
• NSPS Subpart OOOO/OOOOa:
• Pneumatic controllers at natural gas processing plants must have a bleed rate
of zero
• Typically done by converting to instrument air
• Pneumatic controllers located elsewhere must have a bleed rate less than or
equal to 6 scf/hr
32
32
8 - Oil and Gas Operations Pt 3
8-16
QUESTIONS?
33
33
8 - Oil and Gas Operations Pt 3
8-17
OIL AND GAS
OPERATIONS
Part 4
Chapter 9
1
Oil and Gas Industry - An Overview
2
Source: https://www.epa.gov/natural-gas-star-program/overview-oil-and-natural-gas-industry
2
9 - Oil and Gas Operations Pt 4
9-1
What is Natural Gas Processing?
• A natural gas processing plant is a
facility designed to “clean” raw
natural gas by separating
impurities and various nonmethane hydrocarbons and fluids
to produce what is known as
'pipeline quality' dry natural gas
• A gas processing plant is also used
to recover natural gas liquids
(condensate, natural gasoline and
liquefied petroleum gas) and
sometimes other substances such
as sulfur
This Photo by Unknown Author is licensed under CC BY-SA
3
3
Stages of Natural Gas Processing
• Gas-oil-water separators
• Condensate separator
• Dehydration
• Contaminant removal
• Nitrogen extraction
• Methane separation
• Fractionation
4
4
9 - Oil and Gas Operations Pt 4
9-2
Condensate and Water Removal
• Gas-oil-water separators: Pressure relief in a single-stage or
multi-stage separator causes a natural separation of the liquids
from gases in natural gas
• Condensate separator: Natural gas flows into the separator comes
directly from the wellhead; extracted condensate is sent to storage tanks
• Dehydration: A dehydration process removes water that may
cause formation of undesirable hydrates and water
condensation in pipelines
5
5
Contaminant Removal
• Contaminant removal: Nonhydrocarbon gases—such as hydrogen
sulfide, carbon dioxide, water vapor, helium, nitrogen, and oxygen—
must also be removed from the natural gas stream
• Sour gas: Natural gas that contains more than 4 ppmv of hydrogen
sulphide (H2S)
• AKA “Acid gas”
• The removal of H2S from sour gas is called “sweetening“
• Although most sour gas sweetening involves an amine absorption
process, it is also possible to use solid desiccants like iron sponges to
remove the sulfide and carbon dioxide
• Sulfur can be sold and used if reduced to its elemental form
6
6
9 - Oil and Gas Operations Pt 4
9-3
Acid Gas Removal Units (AGRUs)
• Acid gas removal refers to processes that
use aqueous solutions of amines to remove
H2S and CO2 from gases
• AKA “amine gas treating,” “amine scrubbing,”
and “gas sweetening” units
• Many different amines are used in gas
treating
• E.g., Diethanolamine (DEA),
Monoethanolamine (MEA),
Methyldiethanolamine (MDEA)
• Amine gas treating process includes an
absorber unit/tower and a regenerator unit
• CO2 (with methane) is typically vented to
atmosphere or injected for EOR
• H2S is typically flared or sent to sulfur
recovery
7
This Photo by Unknown Author is licensed under CC BY-SA
7
Sulfur Recovery Units (SRUs)
• Sulfur recovery: conversion of H2S
to elemental sulfur
• Claus Process: multistage catalytic
oxidation of H2S to create SO2
• Tailgas treatment is added to
achieve higher recovery
• Elemental sulfur is collected and
sold
• SO2 emissions can be estimated
This Photo by Unknown Author is licensed under CC BY
using AP42 emission factors,
Chapter 8.13 (Sulfur Recovery)
8
8
9 - Oil and Gas Operations Pt 4
9-4
Nitrogen Extraction
• Nitrogen is inert and lowers energy value per volume of natural
gas
• Cryogenic nitrogen rejection units (NRUs) in gas processing
plants are used to remove inert components from sales gas to
meet transmission pipeline standards
• Separated nitrogen, plus a small percentage of methane, is
often vented to atmosphere through a reject stream
9
9
NGLs vs. LPGs
10
Source: EIA, https://www.eia.gov/conference/ngl_virtual/eia-ngl_workshop-anne-keller.pdf
10
9 - Oil and Gas Operations Pt 4
9-5
NGL Extraction
• There are two principle techniques
for removing NGLs from natural gas
stream:
• Absorption method: absorbing oil is used
in an absorption tower to remove NGL,
which are boiled off in a reboiler
downstream
• Cryogenic expander process: consist of
dropping the temperature of the gas
stream to around -120 degrees
Fahrenheit
• Produces both cleaner, purer natural
gas, as well the NGLs themselves
This Photo by Unknown Author is licensed under CC BY-SA
11
11
Fractionation
• Fractionation uses the different boiling points of
different hydrocarbons to separate NGLs into their
base components
• Particular fractionators are used in the following
order:
1.
Deethanizer – this step separates ethane from
the NGL stream
2.
Depropanizer – the next step separates propane
3.
Debutanizer – this step boils off butanes,
leaving pentanes and heavier hydrocarbons in
the NGL stream
4.
Butane Splitter or Deisobutanizer – this step
separates the iso and normal butanes
This Photo by Unknown Author is licensed under CC BY-SA
12
12
9 - Oil and Gas Operations Pt 4
9-6
Oil and Gas Industry - An Overview
13
Source: https://www.epa.gov/natural-gas-star-program/overview-oil-and-natural-gas-industry
13
Underground Natural Gas Storage
• Storage of natural gas during
periods of low demand helps to
ensure that sufficient supplies
of natural gas are available
during periods of high demand
• Natural gas is typically stored
underground under pressure in
three types of facilities:
• Depleted reservoirs
• Aquifers
• Salt caverns
14
14
9 - Oil and Gas Operations Pt 4
9-7
Underground Storage Facilities
• Owners/operators of
underground storage facilities
are interstate pipeline
companies, intrastate pipeline
companies, local distribution
companies, and independent
storage service providers
• Owners/operators of storage
facilities are not necessarily the
owners of the natural gas held in
storage
• Typical equipment at storage
facilities includes compressors,
dehydrators, and separators
Source: EIA
15
15
https://www.youtube.com/watch?v=QgtSoEJD9HE
16
16
9 - Oil and Gas Operations Pt 4
9-8
Liquified Natural Gas
• Liquefied natural gas (LNG): natural gas that has been cooled to
a liquid state, at about -260° Fahrenheit, for shipping and
storage
• Where natural gas pipelines are not feasible or do not exist,
liquefying natural gas is a way to move natural gas from
producing regions to markets
• LNG is shipped in special ocean-going ships (tankers) between
export terminals, where natural gas is liquefied, and import
terminals, where LNG is returned to its gaseous state or
regasified
17
17
LNG Process - Liquefication
• Liquefaction Plants: where natural gas is treated to remove impurities
and higher molecular weight hydrocarbons, and then liquefied and
stored for subsequent shipment
• Liquefaction process GHG emissions are primarily due – but not
limited to:
• Fuel gas combustion to power refrigeration compressors and electrical
generators
• Fired heaters, flares, incinerators, and other fired process heat generators
• Venting of low pressure carbon dioxide
• Fugitive losses of natural gas from the process due to leakage
• Fugitive losses of other GHG’s used in the facility (i.e., SF6 used for switchgear)
18
18
9 - Oil and Gas Operations Pt 4
9-9
LNG Process - Storage
• LNG Storage - Storage tanks that
are designed to store LNG at
atmospheric pressure
• LNG storage tanks are typically
double-walled tanks (i.e., a tank
within a tank), with the annular
space between the two tank walls
filled with insulation
• Emissions are minimal since tanks
This Photo by Unknown Author is licensed under CC BY
do not vent, leaks are captured,
piping is welded, and there is
minimal pressure difference
19
19
LNG Process – Loading, Shipping, and
Unloading
• Loading and Unloading - Marine
or inland terminals designed for
loading LNG onto tankers, or
other carriers or unloading it for
regasification
• Fugitive emissions associated with
ship loading or unloading process are
minimal due primarily to the welding
of all associated piping systems
• Shipping - LNG tankers used for
transporting LNG
• Emissions are associated with the
This Photo by Unknown Author is licensed under CC BY
moving ship
20
20
9 - Oil and Gas Operations Pt 4
9-10
LNG Process - Regasification
• Regasification Plants: typically
co-located with unloading
terminals, where LNG is
pressurized, regasified, and
injected into pipelines, or other
receiving systems, for delivery
of natural gas to end users
• Emissions from combustion
processes and venting from
compressor operations
This Photo by Unknown Author is licensed under CC BY-SA
21
21
Oil and Gas Industry - An Overview
22
Source: https://www.epa.gov/natural-gas-star-program/overview-oil-and-natural-gas-industry
22
9 - Oil and Gas Operations Pt 4
9-11
Natural Gas Distribution
• Local Distribution Companies
(LDCs): regulated utilities
involved in the delivery of
natural gas to consumers within
a specific geographic area
• LDCs typically transport natural
gas from delivery points located
on interstate and intrastate
pipelines to households and
businesses
23
This Photo by Unknown Author is licensed under CC BY-SA
23
Distribution Network
• City Gate: the delivery point
where natural gas is transferred
from a transmission pipeline to
the local gas utility
• Natural gas moves through
larger diameter “mains” and
smaller diameter “services”
until it reaches the customer’s
meter
• LDCs monitor flow rates and
pressures at various points in
the system
This Photo by Unknown Author is licensed under CC BY-SA
24
24
9 - Oil and Gas Operations Pt 4
9-12
QUESTIONS?
25
25
9 - Oil and Gas Operations Pt 4
9-13
FEDERAL OIL & GAS AIR
REGULATIONS
Chapter 10
1
Federal Oil and Gas Air Regulations
• New Source Performance Standards (NSPS)
• Applies to new or modified sources
• Subparts Kb, KKK, LLL, OOOO, and OOOOa
• Subparts IIII, JJJJ (engines)
• National Emissions Standards for Hazardous Air Pollutants
(NESHAP)
• Applies to sources of hazardous air pollutants
• Subparts HH, HHH, ZZZZ
• Part 98 Subpart W
2
2
10 - Federal Oil & Gas Air Regulations
10-1
Major vs. Area Sources
• A major source has actual or potential emissions at or above the
major source threshold for any air pollutant
• The major source threshold for any air pollutant is 100 tpy
• Lower thresholds apply in non-attainment areas (but only for the
pollutant that is in non-attainment)
• Major source thresholds for “hazardous air pollutants” (HAP) are
10 tons/year for a single HAP or 25 tons/year for any
combination of HAP
3
3
New Source Performance Standards
(NSPS)
• Regulates Criteria Pollutants (e.g., VOC, NOx, CO, PM, SO2)
• OOOOa adds GHG (as does Subpart TTTT)
• Affected facilities at all types of sites
• Only regulates New, Modified, or Reconstructed Sources
• Proposal date is effective date
• Established under CAA section 111
4
4
10 - Federal Oil & Gas Air Regulations
10-2
National Emission Standards for
Hazardous Air Pollutants (NESHAP)
• Regulates Hazardous Air Pollutants (HAP)
• e.g., Formaldehyde, BTEX, etc.
• Affected facilities at “major” or “area” sources
• Major Sources must implement MACT (Maximum Achievable Control Technology)
• Area Sources must implement GACT (Generally Available Control Technology)
• Regulates both new and existing sources
• Proposal date is effective date
• More stringent requirements for new sources than existing sources, and
more stringent requirements for major sources than area sources
• Established under CAA section 112
5
5
NESHAP Risk and Technology Review
• CAA requires EPA to conduct 2 types of reviews of NESHAPs for
Major Sources:
1.
Residual Risk – One time review 8 years after standard is
initially developed
2.
Technology Review – Every 8 years after standard is initially
developed
6
6
10 - Federal Oil & Gas Air Regulations
10-3
NSPS Subpart Kb - Storage Vessels
• Applicability
• Tanks modified/constructed after 7/23/1984
• Storage vessels (tanks) ≥ 75 m3 (19,812 gal) containing volatile organic liquids
• Tank size and vapor pressure cutoffs
• Does not apply to vessels with a design capacity less than or equal to 1,590 m3
(420,000 gal) used for petroleum or condensate stored, processed, or treated
prior to custody transfer
• Requirements
• Fixed roof and internal floating roof; or
• External floating roof; or
• Closed vent system and a control device that reduces VOC emissions by 95%
7
7
NSPS Subpart KKK –
VOC Equipment Leak Standards Onshore Natural
Gas Processing Plants
• Applicability
• Modified/constructed between 1/20/1984 and 8/23/2011
• Process units (dehydration, sweetening, storage tanks, etc.)
• Requirements
• Establishes standards for VOC
• Refers to equipment leak standards in 40 CFR 60 Subpart VV (LDAR)
• Leak = ≥10,000 ppm, 15 days to repair leak, attempt after 5 days
• Closed vent systems and control devices used for compliance must
achieve 95% VOC control
8
8
10 - Federal Oil & Gas Air Regulations
10-4
NSPS Subpart LLL- SO2 Standards for
Onshore Natural Gas Processing
• Applicability
• Modified/constructed between 1/20/1984 and 8/23/2011
• Sweetening units and sulfur recovery units
• Requirements
• Establishes standards for SO2
• Achieve SO2 emissions reduction efficiency on a continuous basis
• Monitor sulfur production rate, H2S concentration in the acid gas, acid
gas flow rate, and sulfur dioxide emission reduction efficiency
• If compliance is achieved via oxidation or reduction control systems,
continuous monitoring of the sulfur emission rate is required
9
9
NSPS Subpart IIII – Stationary Compression
Ignition Internal Combustion Engines
• Applicability
• Modified/constructed after 7/11/2005 (earliest date)
• Stationary engines (not mobile)
• Diesel engines
• Requirements
• NOx, Hydrocarbons (HC), CO, PM limits
• Requirements depend on size, date, location, function (emergency)
• Except for engines > 30 liters per cylinder (l/cyl) displacement, performance
testing is not required - you achieve compliance by:
• purchasing a new engine that has been certified by EPA, and
• installing, configuring, operating, and maintaining the engine per the manufacturer’s
instructions
10
10
10 - Federal Oil & Gas Air Regulations
10-5
NSPS Subpart JJJJ – Stationary Spark
Ignition Internal Combustion Engines
• Applicability
• Modified/constructed after 6/12/2006 (earliest date)
• Stationary engines (not mobile)
• Natural gas and gasoline-fired engines
• Requirements
• Operators may comply by purchasing an engine certified by the manufacturer
• For spark ignition engines, operators comply by meeting emission limits for an engine
not certified by the manufacturer
• NOx, CO, VOC limits
• Fuel sulfur limits for gasoline
• Requirements depend on size, type, and date
• Performance testing
• Performance/emissions monitoring
• Recordkeeping/Notifications/Reporting
11
11
NESHAP Subpart HH- Oil and Natural
Gas Production Facilities
• Applicability
• Proposal Date: 8/23/2011
• Covers major and area sources of HAP that process, upgrade, or store
hydrocarbon liquids or that process, upgrade, or store natural gas
• Major sources: Glycol dehydration units, storage vessels w/ potential to flash, and
equipment in volatile HAP service (>10% by weight VHAP) not covered by another
NSPS
• Area sources: Triethylene glycol (TEG) dehydration units
• Exemptions:
• Facilities that exclusively process, store, or transfer black oil
• A major source facility with a facility-wide actual annual average natural gas throughput less than
18,400 scm/d (~650,000 scf/d) and a facility-wide actual annual average hydrocarbon liquid
throughput less than 39,700 L/d (~10,500 gal/d)
12
12
10 - Federal Oil & Gas Air Regulations
10-6
NESHAP Subpart HH- Oil and Natural
Gas Production Facilities (Cont.)
• Requirements
• Glycol dehydration units
• All large units (>3 MMscfd and >1.0 tpy benzene)
• Send still vent emissions to a control device via a closed vent system achieving 95% reduction, or
20 ppmv TOC/HAP; or to control device via a closed vent system and reduce benzene emissions to
< 1tpy
• Small dehy units constructed before 8/23/2011 are existing; small dehy units
constructed after 8/23/2011 are new
• Use the equation in the rule to establish the emission limit; meet the limit through a control
device, process changes, or show it meets the standard without control
• All storage tanks with potential to flash: closed vent systems and 95% control
• All equipment in volatile HAP service must comply with Subpart VV (LDAR)
• Area source TEG dehydration units
• In urban areas, use same control as for major sources
• In rural areas, operate at optimal glycol recirculation rate
13
13
NESHAP Subpart HHH - Natural Gas
Transmission and Storage Facilities
• Applicability
• Applies to major sources of HAP
• New and existing glycol dehydration units
• Exemptions:
• A major source facility with a facility-wide actual annual average natural gas throughput less than
28,300 scm/d (~1,000,000 scf/d) where glycol dehydration units are the only HAP emission source
• Requirements
• All large units (>10 MMscfd and >1.0 tpy benzene) must route emissions to a
control device
• reduce TOC/HAP by 95%, or reduce outlet concentration of TOC/HAP to 20 ppmv, or
reduce benzene emissions to less than 0.90 Mg/year (1 tpy)
• Small dehy units constructed before 8/23/2011 are existing; small dehy units
constructed after 8/23/2011 are new
• Must limit BTEX emissions by routing emissions to a control device or meeting an
emissions limit through process modifications
14
14
10 - Federal Oil & Gas Air Regulations
10-7
NESHAP Subpart ZZZZ - Stationary
Reciprocating Internal Combustion Engines
• Applicability
• Applies to major and area sources of HAP
• Applies to new and existing reciprocating engines
• Tighter requirements for new engines
• Exempt: existing emergency engines located at residential, institutional, or commercial
area sources
• Requirements
• Includes emissions standards and O&M requirements
• Oil and filter change, air filter, spark plugs
• Formaldehyde, CO limitations
• Oxidation catalysts or NSCR
• Requirements complicated, dependent on major/minor status, size, type, location,
function (emergency, limited use)
15
15
Part 98 Subpart W
• Annual GHG reporting program
• Facilities use uniform methods
prescribed by the EPA to
calculate GHG emissions, such
as direct measurement,
engineering calculations, or
emission factors derived from
direct measurement
• In some cases, facilities have a
choice of calculation methods for
an emission source
• Direct reporting to EPA
electronically
Source: EPA, https://www.epa.gov/ghgreporting/ghgrp-and-oil-and-gas-industry
16
16
10 - Federal Oil & Gas Air Regulations
10-8
Part 98 Subpart W Sources
2017 Reported Process Emission Sources
Pneumatic Devices
31
Misc Equipment Leaks
14
Acid Gas Removal Units
12
Associated Gas Venting and Flaring
9
Other Flare Stacks
9
Atmospheric Storage Tanks
1
1
6
4
Distribution Mains
9
Blowdown Vent Stacks
7
Distribution Services
4
Reciprocating Compressors
3
Well Compl. and Work. with HF
2
1
Dehydrators
2
Pneumatic Pumps
3
Centrifugal Compressors
2
Liquids Unloading
2
Offshore Sources
2
Distribution M-R Stations
Transmission Tanks
Gas Well Compl. and Work. without HF
Well Testing
CO2 Emissions
Enhanced Oil Recovery Liquids
CH4 Emissions
N2O Emissions
Enhanced Oil Recovery Pumps
0
5
10
15
Emissions, MMT CO2e
20
25
30
35
17
Source: EPA, 2018 Stakeholder Presentation for Subpart W
17
10 - Federal Oil & Gas Air Regulations
10-9
NSPS SUBPART OOOO
& SUBPART OOOOA
Chapter 11
1
General NSPS Requirements
• Regulates criteria pollutants (e.g., VOC, NOx, CO, PM, SO2)
• NSPS Subpart OOOOa adds GHG
• “Affected facilities” at all types of sites
• Proposal date is effective date
• Proposal/effective date for Subpart OOOO is August 23, 2011
• Proposal/effective date for Subpart OOOOa is September 19, 2015
2
2
11 - NSPS OOOO/OOOOa
11-1
General NSPS Requirements
• Applies only to “new, modified or reconstructed sources”
• Does not apply to existing sources
• Requirements typically consist of:
• Emissions limitations
• Performance testing (e.g., stack testing)
• Parametric and/or emissions monitoring
• Recordkeeping
• Notification
• Reporting
• The rules typically apply to the owner/operator
3
3
Construction/Affected Facility
Definitions
Construction means fabrication, erection, or installation of an
affected facility.
Affected facility means, with reference to a stationary source, any
apparatus to which a standard is applicable.
• e.g., a compressor, a storage tank, gas well completion
• Relocating an affected facility is not construction, modification,
or reconstruction under NSPS and does not trigger the rule
4
4
11 - NSPS OOOO/OOOOa
11-2
Modification Definition
Modification means any physical or operational change to an
existing facility (e.g., the engine) which results in an increase in
the emission rate of any pollutant to which a standard applies (40
CFR 60.14)
• Definition and concepts of “modification” in other subparts can
be different if defined within another subpart
5
5
Modification Details
“increase the amount of any pollutant”
• Hourly emissions rate change (60.14(b))
• Interpreted as increase in short-term potential emissions
• Increasing hours of operation alone without an increase in hourly emissions
rate does not constitute a modification (60.14(e)(3))
“to which a standard applies”
• An increase in emissions of a pollutant not regulated by the NSPS Subpart
is not a modification
• Applicability is pollutant-specific: the only applicable sections of an NSPS
Subpart are those which regulate the pollutant whose emissions increased
due to the modification (60.14(a))
6
6
11 - NSPS OOOO/OOOOa
11-3
NSPS Modification Exemptions
• Routine maintenance, repair, and replacement
• An increase in production rate without a capital expenditure
• An increase in hours of operation
• Use of an alternative fuel or raw material if source could
accommodate it prior to the standard
• Addition of air pollution control device
• Change in ownership
7
7
Capital Expenditure per Subpart A
Capital expenditure means an expenditure for a physical or
operational change to an existing facility which exceeds the
product of the applicable “annual asset guideline repair allowance
percentage” specified in the latest edition of Internal Revenue
Service (IRS) Publication 534 and the existing facility's basis, as
defined by section 1012 of the Internal Revenue Code. However,
the total expenditure for a physical or operational change to an
existing facility must not be reduced by any “excluded additions”
as defined in IRS Publication 534, as would be done for tax
purposes.
8
8
11 - NSPS OOOO/OOOOa
11-4
Capital Expenditure per Subpart
OOOOa
Capital expenditure means, in addition to the definition in 40 CFR 60.2, an
expenditure for a physical or operational change to an existing facility that
exceeds P, the product of the facility’s replacement cost, R, and an adjusted
annual asset guideline repair allowance, A, as reflected by the following
equation: P = R × A, where:
1. The adjusted annual asset guideline repair allowance, A, is the product of
the percent of the replacement cost, Y, and the applicable basic annual
asset guideline repair allowance, B, divided by 100 as reflected by the
following equation: A = Y × (B ÷ 100);
2. The percent Y is determined from the following equation: Y = 1.0 – 0.575
log ×, where × is 2015 minus the year of construction; and
3. The applicable basic annual asset guideline repair allowance, B, is 4.5.
9
9
NSPS VVa Applicability through NSPS
OOOO
• NSPS Subpart OOOO gas processing plant fugitives (leaks) are addressed
through Subpart VVa
• Addition or replacement of equipment for the purpose of process
improvement which is accomplished without a capital expenditure shall not
by itself be considered a modification under this subpart
• Process improvement means routine changes:
• Safety and occupational health requirements
• Energy savings
• Ease of maintenance and operation
• Correction of design deficiencies
• Bottleneck removal
• Changing product requirements
• Environmental control
10
10
11 - NSPS OOOO/OOOOa
11-5
Reconstruction Definition
• Reconstruction means the replacement of components of an
existing facility to such an extent that:
• The fixed capital cost of the new components exceeds 50 percent of the
fixed capital cost that would be required to construct a comparable
entirely new facility, and
• It is technologically and economically feasible to meet the applicable
standards set forth in this part
• Effects on emissions are not considered
• “Fixed capital costs” = capital needed to provide all the
depreciable components
11
11
Subpart OOOO vs. Subpart OOOOa
• NSPS OOOO covers new, modified and reconstructed sources between
8/23/2011 and on or before 9/18/2015
• NSPS OOOOa covers new, modified and reconstructed sources after
9/18/2015
• Compliance with OOOOa is considered compliance with OOOO
NSPS OOOO
NSPS OOOOa
August 23, 2011 ‐ September 18, 2015
September 19, 2015 ‐‐>
12
12
11 - NSPS OOOO/OOOOa
11-6
Subpart OOOO Affected Facilities
• OOOO only regulated VOCs (not GHGs)
• Affected facilities in Subpart OOOO:
• Each natural gas well that is hydraulically fractured
• Each centrifugal compressor using wet seals
• Each reciprocating compressor
• Each continuous bleed natural-gas driven pneumatic controller
• Each storage vessel with a >6 tpy VOC PTE
• Group of equipment (pump, pressure relief device, open-ended valve or line,
valve, and flange or other connector in VOC or wet gas service), within a process
unit located at onshore natural gas processing plants
• Sweetening units located at onshore natural gas processing plants
13
13
Affected Facility Exceptions
• Pneumatic controllers with a natural gas bleed rate ≤6 scfh not
at gas processing plants are not affected
• Intermittent pneumatic controllers are not affected
• Centrifugal compressors using dry seals are not affected
• Centrifugal and reciprocating compressors located at a well site
are not affected
• Well site means one or more areas that are directly disturbed during the
drilling and subsequent operation of, or affected by, production facilities
directly associated with any oil well, gas well, or injection well and its
associated well pad.
14
14
11 - NSPS OOOO/OOOOa
11-7
15
15
16
16
11 - NSPS OOOO/OOOOa
11-8
OOOO Standards and Compliance
Schedule
NSPS OOOO Affected Facility
Hydraulically fractured wildcat and delineation wells
Hydraulically fractured low pressure non-wildcat and
non-delineation wells
Other hydraulically fractured wells
Other hydraulically fractured wells
Centrifugal compressors with wet seals
Reciprocating compressors
Pneumatic controllers at NG processing plants
Pneumatic controllers between wellhead and NG
processing plants
Group 2 and 1 Storage Vessels
Equipment Leaks
Sweetening Units
Standard
Completion combustion
Compliance Date
October 15, 2012
Completion combustion
Completion combustion
October 15, 2012
Before 1/1/2015
REC and completion combustion After 1/1/2015
95% reduction
October 15, 2012
Change rod packing
October 15, 2012
Zero bleed rate
October 15, 2012
6 scfh bleed rate
October 15, 2013
95% reduction
LDAR program
Reduce SO2 as calculated
April 15, 2014/2015
October 15, 2012
17
October 15, 2012
17
NSPS Subpart OOOOa
This subpart establishes emission standards and compliance schedules for the
control of [GHG], volatile organic compounds (VOC) and sulfur dioxide (SO2)
emissions from affected facilities in the crude oil and natural gas source
category that commence construction, modification or reconstruction after
September 18, 2015.
18
18
11 - NSPS OOOO/OOOOa
11-9
Definition of the Source Category
• Crude oil and natural gas source category means:
1.
Crude oil production, which includes the well and extends to
the point of custody transfer to the crude oil transmission
pipeline or any other forms of transportation
2.
Natural gas production, processing, transmission, and storage,
which include the well and extend to, but do not include, the
local distribution company custody station
19
19
Definition of Custody Transfer
[60.5430a]
Custody transfer means the transfer of crude oil or natural gas after
processing and/or treatment in the producing operations, or from storage
vessels or automatic transfer facilities or other such equipment, including
product loading racks, to pipelines or any other forms of transportation.
20
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11 - NSPS OOOO/OOOOa
11-10
21
21
22
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11 - NSPS OOOO/OOOOa
11-11
OOOOa Standards and Compliance
Schedule
NSPS OOOOa Affected Facility
Hydraulically fractured wildcat wells,
delineation wells, or low pressure wells
Standard
Compliance Date
Completion combustion
August 2, 2016
August 2, 2016
November 30, 2016 for REC
standard for non-gas wells
REC, completion combustion unless
GOR < 300 scf/bbl
95% reduction (P.E. Certification if
equipped with CVS)
Change rod packing or route emissions
Reciprocating compressors (not on well sites, to process (P.E. Certification if equipped
up to the LDC)
with CVS)
Pneumatic controllers at NG processing
plants
Zero bleed rate
Continuous bleed pneumatic controllers
between wellhead and the LDC (not at gas
processing plants)
≤6 scfh bleed rate
Other hydraulically fractured wells
Centrifugal compressors with wet seals (not
on well sites, up to the LDC)
August 2, 2016
August 2, 2016
August 2, 2016
August 2, 201623
23
OOOOa Standards and Compliance
Schedule
NSPS OOOOa Affected Facility
Standard
Compliance Date
Zero bleed rate
November 30, 2016
Pneumatic pumps at well sites
95% reduction if control or process
available onsite (P.E. Certification if
equipped with CVS)
November 30, 2016
Storage vessels
95% reduction (P.E. Certification if
equipped with CVS)
August 2, 2016
Equipment leaks at gas processing plants
Equipment leaks at well sites and
compressor stations
Leak Detection and Repair (LDAR) program
August 2, 2016
LDAR program
June 3, 2017
Sweetening units at gas processing plants
Reduce SO2 as calculated
August 2, 2016
24
Pneumatic pumps at gas processing plants
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11 - NSPS OOOO/OOOOa
11-12
WELL REQUIREMENTS
25
25
Subpart OOOOa Flowback Definitions
Flowback means the process of allowing fluids and entrained solids to flow from a well
following a treatment, either in preparation for a subsequent phase of treatment or in
preparation for cleanup and returning the well to production. The term flowback also means
the fluids and entrained solids that emerge from a well during the flowback process. The
flowback period begins when material introduced into the well during the treatment returns
to the surface following hydraulic fracturing or refracturing. The flowback period ends when
either the well is shut in and permanently disconnected from the flowback equipment or at
the startup of production. The flowback period includes the initial flowback stage and the
separation flowback stage.
Initial flowback stage means the period during a well completion operation which begins at
the onset of flowback and ends at the separation flowback stage.
Separation flowback stage means the period during a well completion operation when it is
technically feasible for a separator to function. The separation flowback stage ends either at
the startup of production, or when the well is shut in and permanently disconnected from
the flowback equipment.
26
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11 - NSPS OOOO/OOOOa
11-13
Subpart OOOOa Recovered Gas/Liquids
Definitions
Recovered gas means gas recovered through the separation process
during flowback.
Recovered liquids means any crude oil, condensate or produced water
recovered through the separation process during flowback.
27
27
Well Affected Facility
• The gas well requirements of subpart OOOO/OOOOa apply to
well completion operations at each well affected facility.
• A single well is an affected facility if:
• It conducts a well completion operation after hydraulically fracturing of a
well; or
• It conducts a well completion operation after hydraulically refracturing
• NSPS OOOOa added oil well completions requirements
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11 - NSPS OOOO/OOOOa
11-14
Low Gas to Oil Ratio (GOR) Well
Standards
• A low GOR well is a well affected facility with less than 300 scf of gas
per stock tank barrel of oil produced
• No control or work practice requirements
• Make the determination that the well has a GOR of less than 300 and
maintain records that verify the determination of the GOR for the
well
• Safely maximize resource recovery and minimize releases to the
atmosphere during flowback and subsequent recovery
• Maintain a daily log for each well completion operation for the
duration of the well completion
29
29
Low Pressure Wells
• Calculation methods to determine if well is “low pressure” are in 60.5432a
• Low pressure well: a well that satisfies at least one of the following
conditions:
1.
The static pressure at the wellhead following fracturing but prior to the
onset of flowback is less than the flow line pressure at the sales meter;
2.
The pressure of flowback fluid immediately before it enters the flow line,
as determined under 60.5432a, is less than the flow line pressure at the
sales meter; or
3.
Flowback of the fracture fluids will not occur without the use of artificial
lift equipment
30
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11 - NSPS OOOO/OOOOa
11-15
Well Completion Standards –
Wildcat, Delineation, & Low Pressure Wells
• The operator is not required to have a separator onsite
• Either:
1.
2.
Route all flowback to a completion combustion device with a continuous pilot flame; or
Route all flowback into one or more well completion vessels and commence operation of a
separator unless it is technically infeasible for a separator to function
• Any gas present in the flowback before the separator can function is not subject to
control under OOOOa
• Capture and direct recovered gas to a completion combustion device with a
continuous pilot flame
• For both options (1) and (2), combustion is not required in conditions that may
result in a fire hazard or explosion, or where high heat emissions from a
completion combustion device may negatively impact tundra, permafrost or
waterways
31
31
Well Completion Standards –
Non-Wildcat & Non-Delineation Wells
• Reduced emissions completion (REC) (AKA GREEN COMPLETION) in combination
with a completion combustion device; venting in lieu of combustion where
combustion would present safety hazards
• Initial flowback stage: Route to a storage vessel or completion vessel (frac tank,
lined pit, or other vessel) and separator
• Separation flowback stage: Route all salable gas from the separator to a flow line
or collection system, re-inject the gas into the well or another well, use the gas as
an onsite fuel source or use for another useful purpose that a purchased fuel or
raw material would serve.
• If technically infeasible to route recovered gas as specified above, recovered gas must be
combusted
• All liquids must be routed to a storage vessel or well completion vessel, collection system, or
be re-injected into the well or another well
• The operator is required to have a separator onsite during the entire flowback
period
32
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11 - NSPS OOOO/OOOOa
11-16
COMPRESSOR
REQUIREMENTS
33
33
Centrifugal Compressor Affected
Facility
• A single centrifugal compressor using wet seals is an affected
facility
• NSPS OOOO: between the wellhead and the point of custody transfer to
the natural gas transmission and storage segment
• NSPS OOOOa: between the well site and up to (but not including) the
point of custody transfer to the Local Distribution Company
• If the centrifugal compressor is located at a well site, or an
adjacent well site and services more than one well site, it is not
considered an affected facility
• Dry seal centrifugal compressors are not affected facilities
34
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11 - NSPS OOOO/OOOOa
11-17
Centrifugal Compressor Standards
• CH4 and VOC emissions from each centrifugal compressor wet
seal fluid degassing system must be reduced by 95 percent
• Equip with P.E. certified closed vent system to a control device
(not required in Subpart OOOO)
• Conduct initial inspection
• Install and operate continuous parameter monitoring system
(CPMS) on control device
• Initial performance test required
35
35
Compliance Demonstration for
Centrifugal Compressors
• For centrifugal compressors with wet seals using control devices:
• Initial performance test and periodic performance test within 60 months of
previous test for certain control devices
• Manufacturer tests can be used to replace on-site initial and periodic performance
tests
• Design analyses are allowed in lieu of a performance test for certain control
devices (e.g., open flare, boiler, condensers, carbon adsorbers)
• Maintain daily average control device parameters above (or below) the minimum
(or maximum) level established during the performance test
• Prepare site-specific monitoring plan for continuous monitoring system
• Conduct initial and annual inspections of covers and closed vent systems for leaks
or defects
36
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11 - NSPS OOOO/OOOOa
11-18
Reciprocating Compressor Affected
Facility
• A reciprocating compressor affected facility is each single
reciprocating compressor
• NSPS OOOO: between the wellhead and the point of custody transfer to
the natural gas transmission and storage segment
• NSPS OOOOa: between the well site and up to (but not including) the
point of custody transfer to the Local Distribution Company
• A reciprocating compressor located at a well site, or an adjacent
well site and servicing more than one well site, is not an affected
facility
37
37
Reciprocating Compressor Standards
• Primary requirement is to replace the rod packing or otherwise
collect vapors
• You can choose to replace rod packing before either of the
following occur:
• the compressor has operated for 26,000 hours; or
• 36 months from the last replacement
38
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11 - NSPS OOOO/OOOOa
11-19
PNEUMATIC
CONTROLLERS
39
39
Pneumatic Controller Affected Facility
• NSPS OOOO/OOOOa applies to each, continuous bleed, natural gas-
driven pneumatic controllers as follows:
• Each pneumatic controller affected facility located at a natural gas processing
plant, which is a single continuous bleed natural gas-driven pneumatic controller
• Each pneumatic controller affected facility located at other than a natural gas
processing plant, which is a single, continuous bleed natural gas-driven
pneumatic controller operating at a natural gas bleed rate greater than 6 scfh
• Intermittent or snap-action pneumatic controllers and non-natural
gas-driven pneumatic controllers are not affected facilities under
Subpart OOOO/OOOOa
40
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11 - NSPS OOOO/OOOOa
11-20
Pneumatic Controller Standards
• Each affected continuous bleed pneumatic controller at natural gas processing
plants must have a bleed rate of zero
• Applies to those pneumatic controllers that are new, modified, or reconstructed after August
23, 2011
• Effective October 15, 2012
• OOOO: Each affected continuous bleed pneumatic controller between the
wellhead and the natural gas transmission segment (excluding natural gas
processing plants) must have a bleed rate of ≤6 scfh
• Anything modified, constructed or reconstructed on or after October 15, 2013 between the
wellhead and a natural gas processing plant
• OOOOa: Each pneumatic controller located between the well site and up to (but
not including) the point of custody transfer to the Local Distribution Company
(excluding natural gas processing plants) must have a bleed rate of ≤6 scfh
41
41
Pneumatic Controller Standards
• Each pneumatic controller not meeting the standard must be
tagged with the month and year of installation and identification
information
• Pneumatic controllers required to have a greater bleed rate due
to “functional needs” (positive actuation, safety, and response
time) are exempt from the < 6 scfh limitation
• These must be identified in the annual report, tagged, and justified
42
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11 - NSPS OOOO/OOOOa
11-21
PNEUMATIC PUMPS
43
43
Pneumatic Pump Affected Facility
• Each natural gas-driven diaphragm pump constructed, modified or
reconstructed after September 18, 2015 and located at a natural gas
processing plant or at a well site is an affected facility
• Pneumatic pumps are a new source category in NSPS OOOOa
• There are no requirements under the rule for pumps located in the
gathering and boosting or transmission and storage segments
• These requirement do not apply to piston pumps or pumps that are driven
by means other than natural gas
• Pumps located at a well site that operate for any period of time each day
for less than a total of 90 days per year is a limited-use pneumatic pump
and is not an affected facility
• Lean glycol circulation pumps are not affected facilities.
44
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11 - NSPS OOOO/OOOOa
11-22
Pneumatic Pump Standards
• Natural gas pneumatic diaphragm pumps located at a gas processing
facility must have a bleed rate of 0 scf/h
• Natural gas pneumatic pumps at greenfield well sites must reduce
emissions by 95%
• If control device cannot meet 95% reduction, must still connect to the control
device & report reduction efficiency; or
• If no control device is on-site and unable to route to a process, maintain records
and “report”
Greenfield site means a site, other than a natural gas processing plant,
which is entirely new construction. Natural gas processing plants are
not considered to be greenfield sites, even if they are entirely new
construction.
45
45
Pneumatic Pump Standards
• Natural gas pneumatic diaphragm pumps at non-greenfield well
sites must reduce emissions by 95%
• If control device cannot meet 95% reduction, must still connect
to the control device & report reduction efficiency; or
• If no control device is on-site and unable to route to a process,
maintain records and report; or
• If infeasible to route to control or process, submit P.E.
certification to support claim of infeasibility
• Infeasibility could be based on safety, distance, pressure
losses/differentials, or the ability of the control to handle pump emissions
46
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11 - NSPS OOOO/OOOOa
11-23
STORAGE TANKS
47
47
NSPS OOOO Storage Tanks Affected
Facility
• NSPS OOOO/OOOOa applies to individual tanks that emit >6
tpy VOC PTE that:
• were constructed, modified, or reconstructed after August 23, 2011;
• are located in the:
• oil and natural gas production segment
• natural gas processing segment
• natural gas transmission and storage segment
• Contain crude oil, condensate, produced water or intermediate
hydrocarbon liquids
48
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11 - NSPS OOOO/OOOOa
11-24
NSPS OOOOa Storage Tanks Affected
Facility
• Exemptions:
• A storage vessel with a capacity greater than 100,000 gallons used to recycle water that
has been passed through two stage separation is not a storage vessel affected facility
• Storage vessels subject to and controlled in accordance with the requirements for
storage vessels in 40 CFR part 60, subpart Kb, 40 CFR part 63, subparts G, CC, HH, or WW
• A storage vessel affected facility that subsequently has its potential for
VOC emissions decrease to less than 6 tpy remains an affected facility
• A storage vessel that is removed from service and subsequently
reconnected to the original source of liquids is subject to the same
requirements that applied before being removed from service
• Any storage vessel that is used to replace a storage vessel affected facility is subject to
the same requirements that apply to the storage vessel being replaced
49
49
Storage Tank Control Requirements
• Tanks with emissions >6 tpy:
• Reduce VOC emissions by ≥ 95.0 percent through use of a control device
or floating roof
• If using a control device, equip with specified cover and connect through
a closed vent system to a control device
• If constructed, modified or reconstructed after 9/18/2015, P.E.
certification on CVS (Subpart OOOOa)
• Tanks have 30 days from startup to calculate emissions and 60
days from startup to meet control requirements
50
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11 - NSPS OOOO/OOOOa
11-25
Storage Tank Off Ramp
• Once uncontrolled emissions drop <4 tpy, the control device can
be removed from the storage vessel;
• Must be demonstrated through 12 consecutive month demonstration of
emissions less than 4 tpy
• Must re-calculate emissions monthly to ensure not >4 tpy
• Must take into account anything that could increase emissions
(e.g., fracking of a nearby well)
51
51
GAS PROCESSING
PLANTS
Leaks & Sweetening Units
52
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11 - NSPS OOOO/OOOOa
11-26
Equipment Leaks at NG Processing
Plants Affected Facility
• NSPS OOOO/OOOOa apply to the group of all equipment (except
single compressors) within a process unit that is located at an
onshore natural gas processing plant in VOC or wet gas service
• and that commenced construction, reconstruction or modification after
September 18, 2015
Process unit means components assembled for the extraction of
natural gas liquids from field gas, the fractionation of the liquids into
natural gas products, or other operations associated with the
processing of natural gas products. A process unit can operate
independently if supplied with sufficient feed or raw materials and
sufficient storage facilities for the products.
53
53
VOC & Wet Gas Service
In VOC service means that the piece of equipment contains or contacts a
process fluid that is at least 10 percent VOC by weight.
For a piece of equipment to be considered in wet gas service, it must be
determined that it contains or contacts the field gas before the extraction
step in the process.
Field gas means feedstock gas entering the natural gas processing plant.
54
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11 - NSPS OOOO/OOOOa
11-27
Natural Gas Processing Definition
Natural gas processing plant (gas plant) means any processing site
engaged in the extraction of natural gas liquids from field gas,
fractionation of mixed natural gas liquids to natural gas products, or both.
A Joule-Thompson valve, a dew point depression valve, or an isolated or
standalone Joule-Thompson skid is not a natural gas processing plant.
55
55
Equipment Leaks at NG Processing
Plants Standards
• Comply with NSPS Subpart VVa
• Leak definitions:
Component
Leak Definition (ppm)
Pumps in light liquid service
2,000
Valves in gas/vapor service
500
Valves in light liquid service
500
Connectors
Pumps, valves, and connectors in heavy liquid service;
pressure relief devices in light liquid or heavy liquid service
500
AVO/10,000
56
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11 - NSPS OOOO/OOOOa
11-28
Sweetening Unit Affected Facility
• NSPS OOOOa applies to each sweetening unit that process natural
gas or each sweetening unit that processes natural gas followed by a
sulfur recovery unit
• Sweetening units that have a design capacity less than 2 long tons
per day (LT/D) of hydrogen sulfide (H2S) in the acid gas are required
to comply only with recordkeeping and reporting requirements
outlined in 60.5423a(c) and have no control or emission reduction
requirements
• Sweetening facilities producing acid gas that is completely reinjected into oil-or-gas-bearing geologic strata or that is otherwise
not released to the atmosphere are exempt from the rule
requirements
57
57
Sweetening Unit Standards
• Comply with percent reduction requirements based on sulfur feed rate and
hydrogen sulfide (H2S) content of acid gas
• Initial performance test required
• Must show compliance with required minimum initial SO2 emission reduction efficiency:
Where
X = The sulfur feed rate from the sweetening unit (i.e., the H2S in the acid gas), expressed as sulfur, Mg/D(LT/D), rounded to one decimal place
Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H2S (dry basis) rounded to one decimal place
58
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11 - NSPS OOOO/OOOOa
11-29
Sweetening Unit Standards
• Monitoring of sulfur product accumulation, H2S content, and acid gas
flow rate to show continual compliance with minimum SO2 emission
reduction efficiency:
Where
X = The sulfur feed rate from the sweetening unit (i.e., the H2S in the acid gas), expressed as sulfur, Mg/D(LT/D), rounded to one decimal place
Y = The sulfur content of the acid gas from the sweetening unit, expressed as mole percent H2S (dry basis) rounded to one decimal place
59
59
WELL SITES &
COMPRESSOR
STATIONS
Fugitive Emissions
60
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11 - NSPS OOOO/OOOOa
11-30
Fugitives at Well Sites and
Compressor Stations Affected Facility
• Affected facilities are oil or natural gas well site or a compressor
station for which the owner/operator commenced construction,
modification, or reconstruction after September 18, 2015
• Equipment leaks at well sites and compressor stations are a new source
category in NSPS OOOOa
61
61
Fugitive Emission Components
• “Fugitive emission components” required to be monitored include:
• valves
• connectors
• pressure relief devices
• open-ended lines
• flanges
• compressors
• instruments
• meters
• covers and closed vent systems (i.e., piping) not subject to NSPS OOOOa monitoring
• storage thief hatches or other openings on a controlled storage vessel
• Pneumatic controllers and pumps designed to vent as normal part of
operations are not defined as fugitive emission sources
62
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11 - NSPS OOOO/OOOOa
11-31
Fugitives at Well Sites and
Compressor Stations Standards
• Monitor fugitive emission components with an optical gas imaging
(OGI) device or using Method 21
• Conduct surveys semi-annually at new or modified well sites
• Low production wells not exempted
• Conduct surveys quarterly at new or modified compressor stations
• Stations located in an area where average monthly temperature is <0 degrees
for two consecutive months of a quarterly period can be waived – but not for
two consecutive quarterly periods
• Owner/operator must prepare a fugitive emissions monitoring plan
for the collection of fugitive emissions components at well sites or
compressor stations within each company defined area
• Plans are not required to be submitted, but must be provided upon request
63
63
Fugitives at Well Sites and
Compressor Stations Standards
• Conduct leak surveys within 60 days of startup of production or
modification or by June 3, 2017 (whichever is later)
• Leaks are:
• Any visible emission from a component using OGI; or
• Reading of 500 ppm or more using Method 21
• Repair leaks within 30 days
• Exceptions for repairs that would require a blowdown, shutdown, shut-in and
other exceptions
• Documentation requirements for such exceptions
• Re-survey within 30 days of repair using Method 21, OGI, or
alternative screening procedure
64
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11 - NSPS OOOO/OOOOa
11-32
Definition of Well Site
Well site means one or more surface sites that are constructed for the drilling
and subsequent operation of any oil well, natural gas well, or injection well.
For purposes of the fugitive emissions standards at 60.5397a, well site also
means a separate tank battery surface site collecting crude oil, condensate,
intermediate hydrocarbon liquids, or produced water from wells not located
at the well site (e.g., centralized tank batteries).
• Well sites are not subject to the requirements in subpart OOOOa if the well
site contains only one or more wellheads (i.e., the well site does not have
any equipment associated with the wellheads such as separators,
compressors, heaters, or dehydrators)
• A modification occurs when either: a new well is drilled at an existing well
site, a well at an existing well site is hydraulically fractured, or a well at an
existing well site is hydraulically refractured
65
65
Definition of a Compressor Station
Compressor station means any permanent combination of one or more
compressors that move natural gas at increased pressure through
gathering or transmission pipelines, or into or out of storage. This
includes, but is not limited to, gathering and boosting stations and
transmission compressor stations. The combination of one or more
compressors located at a well site, or located at an onshore natural gas
processing plant, is not a compressor station for purposes of 60.5397a.
• A modification to a compressor station occurs when an additional
compressor is installed at the compressor station or when one or
more compressors are replaced by compressors with a greater
horsepower
• If one or more compressors are replaced with compressors with equal or less
horsepower, then installation of the compressors does not trigger a modification
66
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11 - NSPS OOOO/OOOOa
11-33
GENERAL
REQUIREMENTS
67
67
Notification Requirements
• Hydraulically fractured wells
• 2-day notification for completion activities
• Also include in the annual report
• Pneumatic controllers, pneumatic pumps, storage vessels,
reciprocating compressors, and centrifugal compressors
• Only include in annual report
• Normal Subpart A notices for equipment leaks and sweetening
units
68
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11 - NSPS OOOO/OOOOa
11-34
Reporting Requirements
• Annual report deadline is 90 days after the end of the reporting
period
• Subsequent reports due on the same date as initial report
• Can combine reports for multiple affected facilities
• Semiannual reports are required for equipment leaks (Subpart
VVa)
• Reporting will be required electronically once EPA has CEDRI
forms available for 90 days
69
69
Recordkeeping
• All information required in annual reports
• Date, location, and manufacturer’s specifications for pneumatic
controllers
• Emission calculations for storage vessels
• Number of days a skid mounted or mobile source mounted
storage vessel is located on site
• All instances of alarm of bypass to a control device
70
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11 - NSPS OOOO/OOOOa
11-35
LITIGATION
71
71
NSPS OOOOa – 90 Day Stay
• May 26, 2017: A 90-day stay for limited provisions of the rule
(August 31, 2017 compliance deadline)
• Pneumatic pump requirements (not at gas processing plants)
• Closed vent system (CVS) design certification
• Leak detection and repair (LDAR) surveys
• Vacated by D.C. Circuit Court on July 3, 2017
• Court required “immediate enforcement”
72
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11 - NSPS OOOO/OOOOa
11-36
NSPS OOOOa – 2-year Stay
• June 12, 2017: EPA proposes a rulemaking to delay the following:
• LDAR requirements for well sites and compressor stations
• P.E. Certification for Closed Vent Systems (CVS)
• Pneumatic pump requirements
• Also proposed another 90-day stay that would apply after the initial
stay expired until the two-year stay took effect
• Comment period closed August 9, 2017
• D.C. Court decision does not impact EPA’s authority to implement a
2-year stay
• The proposed 2‐year stay was never finalized
73
73
NSPS OOOOa – 2019 Proposed
Revisions
• August 28, 2019: EPA proposed amendments to the 2012 and 2016
New Source Performance Standards for the Oil and Natural Gas
Industry that would “remove regulatory duplication and save the
industry millions of dollars in compliance costs each year, while
maintaining health and environmental protection from oil and gas
sources that the Agency considers appropriate to regulate.”
• The proposed amendments would remove all sources in the
transmission and storage segment of the oil and natural gas industry
from regulation under the NSPS, both for VOCs and GHGs
• The amendments also would rescind the methane requirements in
the 2016 NSPS that apply to sources in the production and processing
segments of the industry
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11 - NSPS OOOO/OOOOa
11-37
QUESTIONS?
75
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11 - NSPS OOOO/OOOOa
11-38