California Code of Regulations › Title 17 - Public Health › Division 3 - Air Resources › Chapter 1 - Air Resources Board › Subchapter 10 - Climate Change › Article 2 - Mandatory Greenhouse Gas Emissions Reporting › Subarticle 5 - Reporting Requirements and Calculation Methods for Petroleum and Natural Gas Systems › Appendix B - to the Regulation for the Mandatory Reporting of Greenhouse Gas Emissions

Current through Register 2024 Notice Reg. No. 28, July 12, 2024
TEST PROCEDURE for Determining Annual Flash Emission
						  Rate of Gaseous Compounds from Crude Oil, Condensate, and Produced Water
1. PURPOSE AND APPLICABILITY
In crude oil and natural gas production, flash
						  emissions may occur when gas dissolved in crude oil, condensate, or produced
						  water is released from the liquids due to a decrease in pressure or increase in
						  temperature, such as when the liquids are transferred from an underground
						  reservoir to the earth's surface. This procedure is used for determining the
						  annual flash emission rate from tanks used to separate, store, or hold crude
						  oil, condensate or produced water. The laboratory methods required to conduct
						  this procedure are used to measure methane and other gaseous compounds.
2. PRINCIPLE AND SUMMARY OF TEST
						  PROCEDURE
This procedure is conducted by collecting samples of
						  crude oil or condensate and produced water upstream of a separator or tank
						  where flashing may occur. Samples must be collected under pressure and
						  according to the methods specified in this procedure. If a pressure separator
						  is not available for collecting samples, sampling shall be conducted using a
						  portable pressurized separator.
Two sampling methods are specified for collecting
						  liquid samples and are referenced in GPA 2174-93 2.1c and 2.1a, which are
						  hereby incorporated by reference and fully identified in section
						  14 of this appendix, under
						  References. The first method requires a double valve cylinder and the second
						  requires a piston-type constant pressure cylinder. Both methods shall be
						  conducted as specified in this procedure.
The laboratory methods specified for this procedure are
						  based on American Standards and Testing Materials (ASTM), US Environmental
						  Protection Agency (EPA), and Gas Processor Association (GPA) methods. These
						  laboratory methods measure the volume and composition of gases that flash from
						  the liquids, including a Gas-Oil or Gas-Water Ratio, as well as the molecular
						  weight and weight percent of the gaseous compounds. Included are procedures for
						  measuring the bubble point pressure and conducting a laboratory flash analysis.
						  The laboratory results are used with the crude oil or condensate or produced
						  water throughput to calculate the mass of emissions that are flashed from the
						  liquids per year.
3. DEFINITIONS
For the purposes of this procedure, the following
						  definitions apply:
3.1
"Air Resources Board or ARB" means the
						  California Air Resources Board.
3.2
"API Gravity" means a scale used to
						  reflect the specific gravity (SG) of a fluid such as crude oil, condensate,
						  produced water, or natural gas. The API gravity is calculated as [(141.5/SG) -
						  131.5], where SG is the specific gravity of the fluid at 60°F, and where
						  API refers to the American Petroleum Institute.
3.3
"Bubble point pressure" means the
						  pressure, at the pressurized sample collection temperature, at which the first
						  bubble of gas comes out of solution.
3.4
"Condensate" means hydrocarbon and
						  other liquid either produced or separated from crude oil or natural gas during
						  production and which condenses due to changes in pressure or
						  temperature.
3.5
"Crude oil" means any of the naturally
						  occurring liquids and semi-solids found in rock formations composed of complex
						  mixtures of hydrocarbons ranging from one to hundreds of carbon atoms in
						  straight and branched chain rings.
3.6
"Double valve cylinder" means a metal
						  cylinder equipped with valves on either side for collecting crude oil,
						  condensate, or produced water samples.
3.7
"Emissions" means the discharge of
						  natural gas into the atmosphere.
3.8
"Emulsion" means any mixture of crude
						  oil, condensate, or produced water with varying amounts of natural gas
						  contained in the liquid.
3.9
"Flash or flashing" means a process
						  during which gas dissolved in crude oil, condensate, or produced water under
						  pressure is released when subject to a decrease in pressure, such as when
						  liquids are transferred from an underground reservoir to a tank on the earth's
						  surface or from a pressure vessel to an atmospheric tank.
3.10
"Floating Piston cylinder" means a
						  metal cylinder containing an internal pressurized piston for collecting crude
						  oil, condensate or produced water samples.
3.11
"Gas-Oil Ratio (GOR)" means a
						  measurement used to describe the volume of gas that is flashed from a barrel of
						  crude oil or condensate in a separator and tank system.
3.12
"Gas-Water Ratio (GWR)" means a
						  measurement used to describe the volume of gas that is flashed from a barrel of
						  produced water in a separator and tank system.
3.13
"Natural gas" means a naturally
						  occurring mixture or process derivative of hydrocarbon and non-hydrocarbon
						  gases, of which its constituents include methane, carbon dioxide, and heavier
						  hydrocarbons. Natural gas may be field quality (which varies widely) or
						  pipeline quality.
3.14
"Operating pressure" means the
						  pressure of the vessel from which a sample is collected. If no vessel pressure
						  gauge is available or the difference between the sampling train pressure gauge
						  and vessel pressure gauge readings is greater than +/- 5 psig, the sampling
						  train pressure gauge reading shall be used to record the pressure on Form
						  1.
3.15
"Operating temperature" means the
						  temperature of the vessel from which a sample is collected. If no vessel
						  temperature gauge is available or the difference between the sampling train
						  temperature gauge reading and the vessel temperature gauge reading is greater
						  than +/- 4°F, then the sampling train temperature gauge reading shall be
						  used to record the temperature on Form 1.
3.16
"Portable pressurized separator"
						  means a sealed vessel that can be moved from one location to another by
						  attachment to a motor vehicle without having to be dismantled and is used for
						  separating and sampling crude oil, condensate, or produced water at the
						  temperature and pressure of the separator and tank system required for
						  sampling.
3.17
"Pressure separator" means a pressure
						  vessel used for the primary purpose of separating crude oil and produced water
						  or for separating natural gas and produced water.
3.18
"Pressure vessel" means any vessel
						  rated, as indicated by an American Society of Mechanical Engineers (ASME)
						  pressure rating stamp, and operated to contain normal working pressures of at
						  least 15 psig without vapor loss to the atmosphere and may be used for the
						  separation of crude oil, condensate, produced water, or natural gas.
3.19
"Produced water" means water
						  recovered from an underground reservoir as a result of crude oil, condensate,
						  or natural gas production and which may be recycled, disposed, or re-injected
						  into an underground reservoir.
3.20
"Separator" means any tank or
						  pressure separator used for the primary purpose of separating crude oil and
						  produced water or for separating natural gas, condensate, and produced water.
						  In crude oil production a separator may be referred to as a Wash Tank or as a
						  three-phase separator. In natural gas production a separator may be referred to
						  as a heater/separator.
3.21
"Separator and tank system" means the
						  first separator in a crude oil or natural gas production system and any tank or
						  sump connected directly to the first separator.
3.22
"Tank" means any container
						  constructed primarily of non-earthen materials used for the purpose of storing,
						  holding, or separating emulsion, crude oil, condensate, or produced water and
						  that is designed to operate below 15 psig normal operating pressure.
3.23
"Target temperature" means the
						  temperature at which a pressurized hydrocarbon liquid is flashed, and is
						  therefore the temperature of the first atmospheric separator or tank.
3.24
"Throughput" means the average volume
						  of crude oil, condensate, or produced water expressed in units of barrels per
						  day.
4. BIASES AND INTERFERENCES
4.1
The sampling method used to collect a
						  liquid sample will have an impact on the final results reported. Liquid samples
						  shall be collected in accordance with the sampling procedures specified in this
						  procedure.
4.2
The location from where a sample is
						  collected will have an impact on the final results reported. Liquid samples
						  shall be collected from a pressure separator or portable pressurized separator
						  as specified in this procedure.
4.3
Collecting liquid samples from a
						  pressure separator or portable pressurized separator that periodically drains
						  liquids will have an impact on the final results reported. Samples shall not be
						  collected from a pressure separator or portable pressurized separator while it
						  periodically drains liquids and shall only be taken when a drain valve is
						  closed.
4.4
Collecting liquid samples using an
						  empty double valve cylinder will allow gases to flash from the cylinder and
						  will have an impact on the final results reported. Samples collected using a
						  double valve cylinder shall be collected as specified in this procedure.
4.5
Displacing liquids from a double valve
						  cylinder that are reactive and not immiscible with the sample liquid collected
						  will result in gas composition or volume errors and will affect the final
						  results reported. Displacement liquids shall be pre-tested by a laboratory to
						  verify that the liquid is non-reactive and is immiscible with the sample liquid
						  collected.
4.6
Non-calibrated equipment including
						  pressure or temperature gauges will have an impact on the final results
						  reported. All pressure and temperature measurements shall be conducted with
						  calibrated gauges as specified in this procedure and shall be calibrated at
						  least twice per year.
4.7
Conducting laboratory procedures other
						  than those specified in this procedure will have an impact on the final results
						  reported. All laboratory methods and quality control and quality assurance
						  procedures shall be conducted as specified in this procedure.
4.8
The collection of duplicate samples is
						  recommended to verify reported results.
4.9
Failure to perform the bubble point
						  pressure and sample integrity check may affect the reported results.
4.10
Performing a flash analysis by a
						  means other than the method specified in this procedure may affect the reported
						  results.
5. SAMPLING EQUIPMENT
						  SPECIFICATIONS
5.1
An intrinsically safe pressure gauge
						  capable of measuring liquid pressures of up to 2,000 pounds per square inch
						  absolute within +/- 0.1% accuracy.
5.2
A temperature gauge capable of reading
						  liquid temperature within +/- 2°F and within a range of 32°F to
						  250°F.
5.3
A graduated cylinder capable of
						  measuring liquid in at least five (5) milliliter increments with at least the
						  same capacity as the double valve cylinder used for liquid sampling.
5.4
A portable pressurized separator that
						  is sealed from the atmosphere and is used for collecting crude oil, condensate,
						  and produced water samples at the temperature and pressure of the separator and
						  tank system being sampled.
6. SAMPLING EQUIPMENT
6.1
A double valve cylinder or a piston
						  cylinder of at least 300 milliliters in volume for collecting crude oil or
						  condensate samples or at least 800 milliliters in volume for collecting
						  produced water samples.
6.2
A graduated cylinder for use with
						  double valve cylinder.
6.3
A waste container suitable for
						  capturing and disposing sample liquid.
6.4
High-pressure rated metal components
						  and control valves that can withstand the temperature and pressure of the
						  pressure separator from which the sample liquid is gathered.
6.5
Pressure gauges with minimum
						  specifications listed in section
						  5.
6.6
Temperature gauge with minimum
						  specifications listed in section
						  5.
6.7
If required, a portable pressurized
						  separator with minimum specifications listed in section
						  5.
7. DATA REQUIREMENTS
7.1
The data required to conduct this
						  procedure shall be provided by the facility owner or operator prior to
						  conducting the sampling methods specified in this procedure. Field sampling
						  shall not be performed until all data requirements are provided as listed in
						  section 7.2 and as specified on Form
						  1.
7.2
For each sample collected, the
						  following data shall be recorded on the sample cylinder identification tag and
						  on Form 1 prior to conducting a sample collection method:
(a) The separator identification number or
						  description.
(b) The separator temperature and pressure if
						  available.
(c) First downstream atmospheric tank or separator
						  temperature.
8. DOUBLE VALVE CYLINDER SAMPLING
						  METHOD
8.1
Fill the double valve cylinder with
						  non-reactive liquid that is immiscible with the liquid to be collected to
						  prevent flashing within the cylinder and to prevent the displacement liquid
						  from mixing or attaining homogeneity with the sample liquid.
(a) As an alternative for collecting produced water
						  samples, the double valve cylinder may be filled with sample water under the
						  same pressure as the vessel to be sampled and then purged according to the
						  procedure specified in section
						  8.6.
8.2
Identify a pressure separator
						  immediately upstream of the separator or tank required for testing. If no
						  pressure separator is available, install a portable pressurized separator
						  immediately upstream of the separator or tank that can be used to collect crude
						  oil, condensate, and produced water samples.
8.3
Record the sample collection data
						  requirements specified in section
						  7 on the cylinder identification
						  tag and on Form 1.
8.4
Locate the sampling port(s) for
						  collecting liquid samples.
8.5
Connect the sampling train as
						  illustrated in Figure 1 to the sampling port on the pressure separator or
						  portable pressurized separator while minimizing tubing between the purge valve
						  and cylinder as shown. Bushings or reducers may be required.
8.6
Purge the sampling train: Place the
						  outlet of valve B into the waste container. With valves B, C and D closed,
						  slowly open valve A completely, and then slowly open valve B to purge the
						  sample train until a steady stream of liquid without gas pockets is observed,
						  and then close valve B.
8.7
Prepare for sampling: Orient the
						  double-valve cylinder in the vertical position so that displacement liquid can
						  readily be discharged from the cylinder. Note that the orientation of valves C
						  and D depend on the type of sample being collected and the liquid used for
						  displacement. Based on density differences in liquids, the heaviest liquid must
						  be introduced or expelled from the bottom of cylinder. See Figure 2.
(a) If the alternative method for collecting a produced
						  water sample is chosen, the cylinder must be purged at a rate not to exceed 60
						  milliliters per minute until at least 1600 milliliters (two cylinder volumes)
						  are purged through the cylinder that has been previously filled with
						  pressurized sample water prior to proceeding further.
8.8
Slowly open valve C to the full open
						  position and place the outlet of valve D into the graduated
						  cylinder.
Figure 1: Double Valve Cylinder Sampling Train
Click
						  here to view image
8.9
Collect liquid sample: Slowly open
						  valve D to allow a slow displacement of the non-reactive displacement liquid at
						  a rate not to exceed 60 milliliters per minute to prevent the sample liquid
						  from flashing. Continue until approximately 70 percent of the displacement
						  liquid is measured in the graduated cylinder. Then close valves D and C.
8.10
Record the pressure and temperature
						  on Form 1.
Figure 2: Double Valve Cylinder Orientation
Click
						  here to view image
8.11
Record the double valve cylinder
						  volume and the volume of liquid sampled on the cylinder identification tag and
						  on Form 1.
8.12
Drain approximately 20% of the
						  remaining displacement liquid into the graduated cylinder to take outage and
						  record the actual volume of liquid drained on Form 1. This is required for
						  safety and to prevent a pressurized cylinder from exploding during
						  transport.
8.13
Disconnect the sample cylinder from
						  the sampling train and verify that both valves are sealed.
8.14
Remove sampling train: With valves D
						  and C closed, purge any remaining liquid in the sampling train through valve B.
						  Then close valves A and B. Disconnect the sampling train from the pressure
						  separator or portable pressurized separator.
8.15
Verify that all of the data
						  requirements are recorded on the cylinder identification tag and on Form
						  1.
8.16
Transport the cylinder to the
						  laboratory for conducting the laboratory methods specified in section
						  12.
9. PISTON CYLINDER SAMPLING METHOD
9.1
Identify a pressure separator
						  immediately upstream of the separator or tank required for testing. If no
						  pressure separator is available, install a portable pressurized separator
						  immediately upstream of the separator or tank that can be used to collect crude
						  oil, condensate, and produced water samples.
9.2
Record the sample collection data
						  requirements specified in section
						  7 on the cylinder identification
						  tag and on Form 1.
9.3
Locate the sampling port(s) for
						  collecting liquid samples.
9.4
Connect the sampling train as
						  illustrated in Figure 3 to the pressure separator or pressurized portable
						  separator while minimizing tubing between the purge valve and cylinder as
						  shown. Bushings or reducers may be required.
9.5
Purge the sampling train: Place the
						  outlet of valve B into the waste container. With valves B, C and D closed,
						  slowly open valve A completely, and then slowly open valve B to purge the
						  sample train until a steady stream of liquid without gas pockets is observed,
						  and then close valve B.
Figure 3: Piston Cylinder Sampling
						  Train
Click
						  here to view image
9.6
Prepare for sampling: Verify that the
						  gas pressure in the piston cylinder is greater than the pressure of sample
						  liquid. If not, additional gas pressure must be applied to the piston.
9.7
With valve B closed and valve A open,
						  slowly open valve C to the full open position, then slowly open valve D until
						  the pressure indicated on Gauge N is equal to Gauge M and then close valve D
						  momentarily.
9.8
Collect liquid sample: Slowly open
						  Valve D to allow liquid to enter the piston cylinder at a rate not to exceed 60
						  milliliters per minute by using the indicator and scale on the piston cylinder.
						  Continue until a maximum of 80 percent of the cylinder is filled with liquid.
						  Then close valves C and D.
9.9
Record the pressure and temperature on
						  Form 1.
9.10
Record the cylinder volume and volume
						  of liquid sampled on the cylinder identification tag and on Form 1.
9.11
Disconnect the sample cylinder from
						  the sampling train and verify that both valves are sealed.
9.12
Remove sampling train: Place the
						  outlet of valve B into the waste container and slowly open valve B to purge all
						  liquid from the sampling train. Then close valves A and B. Disconnect the
						  sampling train from the pressure separator or portable pressurized
						  separator.
9.13
Verify that all of the data
						  requirements are recorded on the cylinder identification tag and on Form
						  1.
9.14
Transport the cylinder to the
						  laboratory for conducting the laboratory methods as specified in section
						  12.
10. LABORATORY REQUIREMENTS AND
						  METHODS
10.1 Quality Control, Quality Assurance, and
						  Field Records
(a) Quality control requirements shall be performed in
						  accordance with the laboratory methods specified in this test procedure.
(b) Each day of sampling, at least one field duplicate
						  sample shall be collected per matrix type (crude oil, condensate, produced
						  water). The field duplicate samples are collected to demonstrate acceptable
						  method precision. Through this process the laboratory can evaluate the
						  consistency of sample collection and analytical measurements as well as matrix
						  variation. The laboratory should establish control limits based on relative
						  percent difference to evaluate the validity of the measured results.
(c) Laboratory procedures shall be in place for
						  establishing acceptance criteria for field activities described in sections
						  7,
						  8 and
						  9 of this procedure. All
						  deviations from the acceptance criteria shall be documented. Deviations from
						  the acceptance criteria may or may not affect data quality.
(d) Laboratory procedures shall be in place to ensure
						  that field staff have been trained on the sampling methods specified in this
						  procedure and retrained on sampling methods if this procedure changes.
(e) Field records shall provide direct evidence and
						  support necessary for technical interpretations, judgments, and discussions
						  concerning project activities and shall, at a minimum, include a completed copy
						  of Form 1 as provided in this procedure for each sample collected.
10.2 Laboratory Equipment
(a) All laboratory equipment used to conduct
						  measurements shall be calibrated in accordance with the manufacturer
						  specifications and in accordance with the laboratory methods specified in this
						  procedure.
(b) Any chromatograph system that allows for the
						  collection, storage, interpretation, adjustment, or quantification of
						  chromatograph detector output signals representing relative component
						  concentrations may be used to conduct this procedure. All test methods and
						  quality control requirements shall be conducted in accordance with each
						  laboratory method specified.
(c) The minimum reporting limit of the instruments used
						  for reporting gaseous compounds must be at least 100 parts per million (ppm)
						  for both hydrocarbon and fixed gases.
(d) The laboratory equipment, including sample lines,
						  must be temperature controlled and allow for the independent control of the
						  sample cylinder and flash analysis equipment temperatures.
(e) A gas volume meter with the capability of measuring
						  volume in increments of one (1) milliliter minimum is required.
(f) Laboratory vessels (e.g., glassware, cylinders,
						  etc.) and equipment for collecting flash gas without sample degradation and
						  without compromising the integrity of the sample are required.
(g) A metering pump for introducing deionized water
						  into a sample cylinder that can meter the water in precise increments (e.g.,
						  0.01 milliliters) is required.
(h) Additional sample preparation guidance can be found
						  in GPA 2174-93, GPA 2261-00 and GPA 2177-03, all of which are hereby
						  incorporated by reference, and fully identified in section
						  14 of this appendix, under
						  References.
10.3 Bubble Point Pressure and Sample Integrity
						  Check.
This procedure is used to determine the bubble point
						  pressure at sample collection temperature of a pressurized hydrocarbon liquid
						  prior to conducting a flash or any compositional analysis. These results
						  determine the integrity of the sample and provide a means of verifying the
						  sampling conditions reported on Form 1. When heating is required, safety
						  precautions must be taken due to thermal expansion within a pressurized
						  cylinder. This procedure is performed with the use of a Double Valve cylinder
						  and is not applicable for Floating-Piston cylinders. Samples gathered with the
						  use of a Floating-Piston cylinder must be transferred to a Double Valve
						  cylinder using a water displacement method prior to conducting this
						  procedure.
(a) Fix the cylinder in an upright vertical position
						  using a ring stand or similar device. This ensures that headspace gas remains
						  at the top of the cylinder.
(b) Connect a pressure gauge and source of pressurized
						  deionized water to the bottom of the sample cylinder using a metering pump for
						  measuring the volume of water introduced into the sample cylinder.
(c) Slowly condition the cylinder to the measured
						  sample collection temperature reported on Form 1 while monitoring pressure for
						  a minimum of 2 hours or until a change of no more than 1 psi in pressure over
						  15 minutes is observed.
(d) Introduce deionized water while slowly mixing the
						  sample by tilting the cylinder no more than 60 degrees from vertical in either
						  direction to ensure that headspace gas remains at the top of the cylinder and
						  liquid remains on the bottom. Continue adding deionized water to increase the
						  pressure to above the pressure reported on Form 1, while mixing to ensure the
						  sample returns to a single phase liquid.
(e) Record the stabilized pressure reading on the
						  laboratory report.
(f) Remove a small increment of deionized water
						  (approximately 0.5 milliliters) to reduce the pressure and allow it to
						  stabilize. Document the sample pressure and the volume of deionized water (pump
						  volume) on the laboratory report. Repeat until at least three (3) pressure
						  readings above and three (3) pressure readings below the reported value on Form
						  1 are gathered.
(g) Graph the results of sample pressure and volume of
						  deionized water (pump volume). Draw a line between the points above the
						  measured value on Form 1. Draw a second line between the points below the
						  measured value on Form 1. The intercept of the two lines denotes the bubble
						  point pressure.
(h) Record the bubble point pressure on the laboratory
						  report.
(i) Any sample that fails to achieve the following
						  Pass/Fail criteria, which is the percentage difference between the bubble point
						  pressure and the sample collection pressure reported on Form 1, shall be
						  discarded:
Pass/Fail Criteria
									 for Bubble Point Pressure Measurements
+/- 5% for > 500 psig
+/- 7% for 250 - 499 psig
+/- 10% for 100 - 249 psig
+/- 15% for 50 - 99 psig
+/- 20% for 20 - 49 psig
+/- 30% for < 20 psig
10.4 Laboratory Flash Analysis
						  Procedure
This procedure is used to determine the volume and
						  composition of gas flashed from a pressurized liquid. This procedure is
						  conducted after performing the bubble point pressure measurement to verify
						  sample integrity.
(a) Condition the sample cylinder to the collection
						  temperature recorded on Form 1 for a minimum of 2 hours. This step may be
						  expedited by performing in conjunction with the Bubble Point
						  determination.
(b) Connect a pressure gauge and source of pressurized
						  deionized water to the bottom of the sample cylinder using a metering pump for
						  measuring the volume of water introduced into the sample cylinder.
(c) Connect the top of the sample cylinder to a
						  temperature controlled flash chamber that can be heated or cooled independently
						  from the sample cylinder. The chamber shall be of sufficient volume to allow
						  for the flash process and the collection of the flashed liquid. Located at the
						  top of the chamber will be an inlet for the liquid, and an outlet for the gas.
						  The gas vent line will allow the flash gas to be routed through a constant
						  volume gas cylinder and on to a gas meter (e.g., gasometer).
(d) Throughout the flash process, maintain the transfer
						  lines, flash chamber, and constant volume gas cylinder and gas meter at the
						  target temperature.
(e) Before introducing pressurized liquid into the
						  flash chamber, evacuate the entire system and purge with helium. Vent the
						  helium purge gas to atmosphere through the meter and then re-zero the gas
						  meter.
(f) Introduce deionized water into the bottom of the
						  liquid sample cylinder to increase the pressure to a start pressure above the
						  bubble point pressure. This step ensures that the sample remains single phase
						  when introduced into the flash chamber.
(g) Document the start pressure. The flash study will
						  be performed at this pressure and not at the field recorded sample
						  pressure.
(h) Partially open (
crack-open
) the
						  liquid sample inlet valve to allow for a slight drip of liquid into the flash
						  chamber. It is critical to maintain the pressurized liquid as close as possible
						  to the start pressure.
(i) After liquid hydrocarbon and gas have been
						  observed, terminate the flash procedure by closing the liquid inlet valve.
						  Document the volume and/or weight of the residual liquid and the volume of gas
						  collected. Document the volume of pressurized liquid sample introduced into the
						  system.
(j) Isolate the gas sample in the constant volume gas
						  cylinder by closing both valves. Detach the cylinder and analyze via GPA 2286.
						  Before analyzing, condition the gas sample for a minimum of two hours at a
						  temperature of at least 30°F above the target temperature. Assure that the
						  GC inlet line is heat traced to maintain sample integrity upon
						  injection.
(k) Measure the pressurized liquid density at the start
						  pressure and temperature. Also measure the density at a second pressure also
						  above the bubble point pressure and the start pressure. Extrapolate the density
						  of the pressurized liquid at the collection pressure recorded on Form 1.
(
l
) Correct the pressurized liquid
						  volume from the start pressure to the sample collection pressure recorded on
						  Form 1 using the density measurements.
(m) Document corrected liquid volume.
(n) Perform all necessary calculations including that
						  of the GOR or GWR.
(o) A mass balance (analytical integrity check) may be
						  performed by comparing the weight of pressurized liquid used for the flash
						  (determined from the corrected volume used and the density at sample
						  conditions) to the sum of the weight of the liquid and the weight of the
						  gas.
10.5 Gas-Oil and Gas-Water Ratio Calculation
						  Methodology
(a) Convert the volume of gas vapor measured during the
						  laboratory flash analysis procedure to standard atmospheric conditions as
						  derived from the Ideal Gas Law as follows:
Click
						  here to view image
Equation 1
Where:
VaporStd = Standard cubic feet
						  of vapor at 60°F and 14.696 psia.
VolumeLab = Volume of vapor
						  measured at laboratory conditions.
TLab = Temperature of vapor at
						  laboratory conditions, °F.
PLab = Pressure of vapor at
						  laboratory conditions, psia.
459.67 = Conversion from Fahrenheit to Rankine
60F = Standard temperature of 60°F.
14.696 = Standard atmospheric pressure, psia.
(b) Convert the volume of crude oil, condensate, or
						  produced water measured after conducting the laboratory flash analysis
						  procedure to standard conditions as follows:
Click
						  here to view image
Equation 2
Where:
LiquidStd = Standard volume of
						  post-flash liquid at 60°F, barrels.
MassLiquid = Mass of liquid at
						  laboratory conditions, grams.
Density60F = Density of liquid
						  at 60°F, grams/milliliter.
3785.412 = Conversion from milliliter to US
						  gallons.
STB = Stock Tank Barrel.
42 gallons = Volume of a stock tank barrel at
						  60°F.
(c) Calculate the Gas-Oil or Gas-Water Ratio as
						  follows:
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						  here to view image
Equation 3
Where:
G = The Gas-Oil or Gas-Water Ratio.
Vapor Std = Standard cubic feet
						  of vapor at 60°F and 14.696 psia.
Liquid Std = Standard volume of
						  post-flash liquid at 60°F, barrels.
10.6 Analytical Laboratory Methods and
						  Requirements
The following methods are required to evaluate and
						  report flash emission rates from crude oil, condensate, and produced
						  water.
(a) Oxygen, Nitrogen, Carbon Dioxide, Methane, Ethane,
						  Propane, i-Butane, n-Butane, i-Pentane, n-Pentane, Hexanes, Heptanes, Octanes,
						  Nonanes, Decanes+: Evaluate per GPA 2286-95, ASTM D-1945-03, and ASTM
						  D-3588-98, all of which are hereby incorporated by reference, and fully
						  identified in section
						  14 of this appendix, under
						  References.
(b) BTEX: Evaluate per EPA 8021B (GC/FID) or use ASTM
						  D-7096-16, GPA 2286-95, EPA 8260B, EPA TO-14A, and EPA TO-15 as alternate
						  methods, all of which are hereby incorporated by reference, and fully
						  identified in section
						  14 of this appendix, under
						  References.
(c) API Gravity of whole oil at 60°F by ASTM D
						  287-92 (Hydrometer Method), ASTM D-4052-09 (Densitometer), ASTM D 5002-16
						  (Densitometer), or ASTM D-70-09 (Pycnometer), all of which are hereby
						  incorporated by reference, and fully identified in section
						  14 of this appendix, under
						  References. Note: if water is entrained in sample, use ASTM D 287-92, which is
						  hereby incorporated by reference and fully identified in section
						  14 of this appendix, under
						  References. If needed calculate Specific Gravity 60/60°F = 141.5 / (131.5 +
						  API Gravity at 60°F).
(d) Specific Gravity of Produced Water at 60°F by
						  ASTM D 287-92 (Hydrometer Method), ASTM D 4052-09 (Densitometer), ASTM D
						  5002-16 (Densitometer), or ASTM D 70-09 (Pycnometer), all of which are hereby
						  incorporated by reference, and fully identified in section
						  14 of this appendix, under
						  References. If needed calculate API at 60°F = (141.5 / SG at 60°F) -
						  131.5
(e) Molecular Weight of gaseous phase by calculation
						  per ASTM D-3588-98, which is hereby incorporated by reference, and fully
						  identified in section
						  14 of this appendix, under
						  References
11. CALCULATING RESULTS
The following calculations are performed by the owner
						  or operator in conjunction with the laboratory reports specified in section
						  12. The same calculations are used
						  for crude oil, condensate, and produced water.
11.1
Calculate the volume of gas flashed
						  from the liquid per year using the Gas Oil or Gas Water Ratio obtained from the
						  laboratory report as follows:
Click
						  here to view image
Equation 4
Where:
Ft3/Year = standard cubic
						  feet of gas produced per year
G = Gas Oil or Gas Water Ratio (from laboratory
						  report)
Barrels/Day = barrels per day of liquid (DOGGR
						  certified reports
Days/Year = days of operation per year
						  (owner/operator)
11.2
Convert the gas volume to pounds as
						  follows:
Click
						  here to view image
Equation 5
Where:
Mass Gas /Year = pounds of gas
						  per year
Ft3/Year = cubic feet of gas
						  produced per year (Equation 4)
Gram/Gram-Mole = Molecular weight (from laboratory
						  report)
23.690 l/gr-mole = molar volume of ideal gas at 14.696
						  psi and 60°F
11.3
Calculate the annual mass of methane
						  as follows:
Click
						  here to view image
Equation 6
Where:
Mass Methane /Year = metric tons
						  of methane
Mass Gas /Year = pounds of gas
						  per year (Equation 5)
WT% Methane = Weight % of methane (from laboratory
						  report)
12. LABORATORY REPORTS
12.1
The results of this procedure are
						  used by owners or operators of separator and tank systems to report annual
						  methane flash emissions to ARB. The following information shall be compiled as
						  a report by the laboratory conducting this procedure and provided to the owner
						  or operator each time flash analysis testing is conducted:
(a) A sketch or diagram of the separator and tank
						  system depicting the sampling location; and,
(b) A copy of Form 1 as specified in this procedure for
						  each liquid sample collected; and,
(c) The laboratory results for each liquid sample
						  evaluated as specified in section
						  12.4; and,
(d) Other documentation or information necessary to
						  support technical interpretations, judgments, and discussions.
12.2
Reports shall be made available to
						  the owner or operator no later than 60 days from the date of liquid
						  sampling.
12.3
Reports shall be maintained by the
						  laboratory conducting this procedure for a minimum of five (5) years from the
						  date of liquid sampling and additional copies shall be made available at the
						  request of the owner or operator.
12.4
Laboratory reports shall include, at
						  minimum, a listing of results obtained using the laboratory methods specified
						  in this procedure and as specified in Table 1.
Table 1: Laboratory Data
						  Requirements
WT% CO2, CH4
WT% C2-C9, C10+
WT% BTEX
WT% O2
WT% N2
Molecular Weight of gas sample
								  (gram/gram-mole)
Liquid phase specific gravity of produced
								  water
Gas Oil or Gas Water Ratio (scf/stock tank
								  barrel)
API gravity of whole oil or condensate at
								  60°F
Post-Test Cylinder Water Volume
Post-Test Cylinder Oil Volume
13. ALTERNATIVE TEST PROCEDURES, SAMPLING METHODS
						  OR LABORATORY METHODS
Alternative test procedures, sampling methods, or
						  laboratory methods other than those specified in this procedure shall only be
						  used if prior written approval is obtained from ARB. In order to secure ARB
						  approval of an alternative test procedure, sampling method, or laboratory
						  method, the applicant is responsible for demonstrating to the ARB's
						  satisfaction that the alternative test procedure, sampling method, or
						  laboratory method is equivalent to those specified in this test
						  procedure.
(1) Such approval shall be granted on a case-by-case
						  basis only. Because of the evolving nature of technology and procedures and
						  methods, such approval shall not be granted in subsequent cases without a new
						  request for approval and a new demonstration of equivalency.
(2) Documentation of any such approvals,
						  demonstrations, and approvals shall be maintained in the ARB files and shall be
						  made available upon request.
14. REFERENCES
ASTM D-70-09
Standard Test Method for Density
						  of Semi-Solid Bituminous Materials (Pycnometer Method). 2009.
ASTM D-287-92
Standard Test Method for API
						  Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method).
						  Reapproved 2000.
ASTM D-1945-03
Standard Test Method for
						  Analysis of Natural Gas by Gas Chromatography. Reapproved 2010.
ASTM D-3588-98
Standard Practice for
						  Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous
						  Fuels. Reapproved 2003.
ASTM D-4052-09
Standard Test Method for
						  Density, Relative Density, and API Gravity of Liquids by Digital Density Meter.
						  2009.
ASTM D-5002-16
Standard Test Method for Density
						  and Relative Density of Crude Oils by Digital Density Analyzer.
						  2016.
ASTM D-7096-16
Standard Test Method for
						  Determination of the Boiling Point Range Distribution of Gasoline by Wide Bore
						  Capillary Gas Chromatography.
EPA Method 8021B
Aromatic and Halogenated
						  Volatiles by Gas Chromatography Using Photoionization and/or Electrolytic
						  Conductivity Detectors. 2014.
EPA Method 8260B
Volatile Organic Compounds by
						  Gas Chromatography/Mass Spectrometry (GC/MS). 1996.
EPA Method TO-14A
Determination of Volatile
						  Organic Compounds (VOCs) In Ambient Air Using Specially Prepared Canisters with
						  Subsequent Analysis By Gas Chromatography. 1999.
EPA Method TO-15
Determination of Volatile
						  Organic Compounds (VOCs) In Air Collected In Specially-Prepared Canisters and
						  Analyzed By Gas Chromatography/Mass Spectrometry (GC/MS). 1999.
GPA 2174-93
Analysis Obtaining Liquid
						  Hydrocarbon Samples for Analysis by Gas Chromatography. 2000.
GPA 2177-03
Analysis of Natural Gas Liquid
						  Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography.
						  2003.
GPA 2261-00
Analysis for Natural Gas and
						  Similar Gaseous Mixtures by Gas Chromatography. 2000.
GPA 2286-95
Tentative Method for the Extended
						  Analysis of Natural Gas and Similar Gaseous Mixtures by Temperature Program Gas
						  Chromatography. Reprinted 1999.
FORM 1
Flash Analysis
						  Testing Field Data Form
Click
						  here to view image
1. New
						  Appendix B filed 12-31-2013; operative 1-1-2014 pursuant to Government Code
						  section
						  11343.4(b)(3)
						  (Register 2014, No. 1).
2. Amendment of Appendix B, items 2.,
						  10.1(c) and 12.3(d)-(e) filed 12-31-2014; operative 1-1-2015 pursuant to
						  Government Code section
						  11343.4(b)(3)
						  (Register 2015, No. 1).
3. Repealer and new appendix B filed
						  9-1-2017; operative 1-1-2018 (Register 2017, No.
						  35).