California Code of Regulations
Title 17 - Public Health
Division 3 - Air Resources
Chapter 1 - Air Resources Board
Subchapter 10 - Climate Change
Article 4 - Regulations to Achieve Greenhouse Gas Emission Reductions
Subarticle 13 - Greenhouse Gas Emission Standards for Crude Oil and Natural Gas Facilities
Appendix C - 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 Standard 2174-93 Sections 2.1 c and 2.1a. 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 (US 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 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 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 percent 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 sample liquid is gathered.
6.5 Pressure gauge 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
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
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 percent 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
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 Standard 2174-93, GPA Standard 2261-00 and GPA Standard 2177-03.
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 two (2) hours or until a change of no more than one (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 two (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 Standard 2286-95. 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:
Equation 1
Where:
Vapor std = Standard cubic feet of vapor at 60°F and 14.696 psia.
Volume Lab = 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:
Equation 2
Where:
Liquid std = Standard volume of post-flash liquid at 60°F, barrels.
Mass Liquid = Mass of liquid at laboratory conditions, grams.
Density 60F = 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:
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 Standard 2286-95, ASTM D1945-03, and ASTM D 3588-98.
(b) BTEX: Evaluate per US EPA Method 8021B (GC/FID) or use ASTM D7096-16, GPA Standard 2286-95, US EPA Method 8260B, US EPA Method TO-14A, and US EPA Method TO-15 as alternate methods.
(c) API Gravity of whole oil at 60°F by ASTM D 287-92 (Hydrometer Method), ASTM D4052-09 (Densitometer), ASTM D5002-16 (Densitometer), or ASTM D70-09 (Pycnometer). Note: if water is entrained in sample, use ASTM D 287-92. 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 D4052-09 (Densitometer), ASTM D5002-16 (Densitometer), or ASTM D70-09 (Pycnometer). 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.
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:
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:
Equation 5
Where:
Mass Gas /Year = pounds of gas per year
Ft3/Year = cubic feet of gas produced per year (Equation 1)
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:
Equation 6
Where:
Mass Methane /Year = metric tons of methane
Mass Gas /Year = pounds of gas per year (Equation 5)
WT% Methane = Weight percent 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.
13.1 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.
13.2 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 D70-09 Standard Test Method for Density of Semi-Solid Bituminous Materials (Pycnometer Method), which is incorporated herein by reference. 2009.
ASTM D 287-92 Standard Test Method for API Gravity of Crude Petroleum and Petroleum Products (Hydrometer Method), which is incorporated herein by reference. Reapproved 2000.
ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography, which is incorporated herein by reference. Reapproved 2010.
ASTM D 3588-98 Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, which is incorporated herein by reference. Reapproved 2003.
ASTM D4052-09 Standard Test Method for Density, Relative Density, and API Gravity of Liquids by Digital Density Meter, which is incorporated herein by reference. 2009.
ASTM D5002-16 Standard Test Method for Density and Relative Density of Crude Oils by Digital Density Analyzer, which is incorporated herein by reference. 2016.
ASTM D7096-16 Standard Test Method for Determination of the Boiling Point Range Distribution of Gasoline by Wide Bore Capillary Gas Chromatography, which is incorporated herein by reference. 2016.
US EPA Method 8021B Aromatic and Halogenated Volatiles by Gas Chromatography Using Photoionization and/or Electrolytic Conductivity Detectors, which is incorporated herein by reference. 2014.
US EPA Method 8260B Volatile Organic Compounds by Gas Chromatography/Mass Spectrometry (GC/MS), which is incorporated herein by reference. 1996.
US EPA Method TO-14A Determination of Volatile Organic Compounds (VOCs) In Ambient Air Using Specially Prepared Canisters with Subsequent Analysis By Gas Chromatography, which is incorporated herein by reference. 1999.
US 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), which is incorporated herein by reference. 1999.
GPA Standard 2174-93 Obtaining Liquid Hydrocarbon Samples for Analysis by Gas Chromatography, which is incorporated herein by reference. 2000.
GPA Standard 2177-03 Analysis of Natural Gas Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography, which is incorporated herein by reference. 2003.
GPA Standard 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, which is incorporated herein by reference. 2000.
GPA Standard 2286-95 Tentative Method for the Extended Analysis of Natural Gas and Similar Gaseous Mixtures by Temperature Program Gas Chromatography, which is incorporated herein by reference. Reprinted 1999.
FORM 1
Flash Analysis Testing Field Data Form
1. New Appendix C filed 7-17-2017; operative 10-1-2017 (Register 2017, No. 29).
