Determining the Extent of Hydrocarbon Leakage from a Gas Fractionation Plant using Conventional Methods and Optical Gas Imaging

Table of Content

Introduction
Facility Description
Methodology
    Emissions Survey
    Component Screening
    Leak-Rate Measurements
    Leak Statistics
Emission Reduction Opportunities
Leak Detection Methodology Comparison
Conclusions

Introduction

The article presents all of the details and the outcome of a targeted emission survey that was conducted in 2004 at a Canadian Gas Fractionation Factory. The investigation’s key objectives were to detect and measure hydrocarbon emissions resulting fugitive equipment leaks, and to emphasize the potential economical opportunities to decrease the emissions.

Additionally, the investigation aimed to compare the total performance of the Hawk passive IR camera optical leak detection technique against traditional leak detection techniques. An evaluation of fugitive emissions and the detection techniques is provided based on the data that was collected.

A synopsis of the optimized emissions inventory, including methane and greenhouse gases (GHG) and total hydrocarbons (THC), was presented. The conditions noted during the visit to the factory formed the basis for the results. Component type and process area were taken into consideration as well. These factors were compared with corresponding values, and the outcome was published by the U.S. EPA for gas facilities (1996) and for refineries (1995), and by CAPP for upstream gas facilities (1999).

Qualitative comparisons of conventional leak detection methods to optical gas imaging are made. The investigation was possible due to the use of Leak Survey Inc. (LSI) Hawk passive IR camera.

Facility Description

The Gas Fractionation Factory is a large natural gas liquids fractionation, storage and shipping unit capable of manufacturing propane, normal butane, isobutane, condensate and a mixed ethane/propane product. The factory gets feedstock from gas plants, local refineries, and chemical plants, however the greater part of the NGL feedstock is procured by pipeline from Shell and Enbridge. Rail tanker cars, pipeline, and tank truck are utilized to distribute fractionated products to customers.

The facility’s current processing capacity is more than 22,000 m3/day. Twelve salt caverns and twenty-one horizontal storage bullets provide product storage for propane, normal butane, isobutane and the ethane/propane mix, while synthetic crude and condensate are stored in two above-ground floating-roof tanks. The greater portion of the fractionated products leaves the factory via pipeline, however some products are shipped to customers by tank truck and rail tanker. There are thirty-six rail tanker loading spots on two rail racks and four tank truck lading racks, each with a capacity to load propane, normal butane and isobutene.

Methodology

The methodology used by the team to detect and test cost-effective emission-reduction opportunities at upstream oil and gas facilities is described below.

Emissions Survey

The key elements of the site survey are listed below:

  • Screening of equipment components for leak detection
  • Measurement of emissions from continuous vents and residual flows from emergency vents during passive periods
  • Measurement of emission rates from equipment components that have leaks
  • Developing counts of the surveyed equipment parts
  • Determination of site-specific average emission factors
  • Development of the emissions inventory
  • Cost-effective evaluation of the detected control opportunities

Component Screening

Equipment parts used in all of the processing systems were screened for leaks. The types of parts analyzed included; threaded and flanged connections (connectors), pressure-relief devices, open-ended lines, valves, instrument fittings, blowdown vents (during passive periods), regulator and actuator diaphragms, engine and compressor crankcase vents, compressor seals, sump, tank hatch seals, and drain tank vents.

Parts in heavy-liquid service were typically not screened as they do not add greatly to total hydrocarbon losses at oil and gas units, due to their low average leak rates (US EPA, 1995) and relative numbers. Conventional leak detection was performed with the aid of bubble tests with soap solution, CGI-211 and a GMI Gas Surveyors), an ultrasonic leak detector (SDT International, SDT-120), and portable hydrocarbon gas detectors (Bascom-Turner Gas Sentry CGI-201.

Bubble tests (Figure 1) were conducted on several parts including pipe threads, valves, and tubing connections as it is considered the fastest screening method. Parts that cannot be screened with bubble tests are in any high-temperature service, open-ended lines and specific flanged connections. Gas detectors were used to screen them.

Figure 1. Bubble test on leaking valve

Ultrasonic detectors are valuable for leak detection in areas with low levels of background noise in the ultrasonic range. A screening value of 10,000 ppm or greater was utilized in all cases as the leak definition. If a part was established to be emitting by one of the alternative methods - the ultrasonic leak detector or bubble tests - it was then screened using the hydrocarbon vapor analyzer to establish if the part met this leak definition.

All detected leaking parts were tagged, and the exact source of leakage and date was noted on each tag. The emissions rate from all of the leakers in hydrocarbon service was then established. All leaker tags were put in place after the leak rate was measured to allow for follow-up action by factory personnel.

The following basic data was recorded for each leaking component:

  • Component type
  • Model or style of component
  • Process stream
  • Service
  • Size
  • Process unit
  • Temperature
  • Pressure

Leak-Rate Measurements

The HiFlow Sampler (Figure 2) was the primary technique applied to measure emission rates from leaking equipment parts.

Figure 2. HiFlow Sampler

The HiFlow Sampler was not used in certain cases where components are leaking at rates above the upper limit of the unit - about 14 m3/h - and most open-ended lines and vents. As required, either bagging or direct measurement methods were used in these cases. The following is a short description of the HiFlow Sampler developed by GTI. The HiFlow Sampler’s operating rule is simple. It is a variable-rate induced-flow sampling system for 100% trapping of the emissions from a leaking part. The HiFlow Sampler establishes the mass rate of emissions by measuring flow rate and THC concentration.

Leak Statistics

The component count identified 77,800 equipment parts in pressurized gas/vapor service used in process gas and fuel gas service. Table 1 shows the synopsis of the parts encountered, and the fraction within each part category that was leaking.

Table 1. Fraction of leaking components and average component emission rates for data collected at the Gas Fractionation Plant (October 18 to 22, 2004).

Component Number of Components Surveyed Number of Leakers Percentage of Components Leaking Average Emission Rate (kg/h/source) 95 % Confidence Limits
Lower Upper
Connectors 68,670 107 0.14 0.000211 0.000092 0.000331
Block Valves 7,471 284 3.80 0.006452 0.00495 0.00796
Control Valves 579 27 4.66 0.01665 0.0113 0.0220
Open-Ended Lines 667 19 2.85 0.05554 0.000 0.148
Pressure Regulators 18 1 5.56 0.000040 0.000039 0.000042
Pump Seals 107 6 5.61 0.122 0.000340 0.244
Crank Case Vents 2 2 100.00 0.518 0.000092 0.000331
Orifice Meters 26 0 0.00 0.0 N/A N/A
Compressor Seals 3 0 0.00 0.0 N/A N/A
Pressure Relief Valves 257 1 0.39 0.00479 0.0000 0.0129
Total 77,880 447 0.56      

While there are presently no guidelines about the allowable percentage of leaking components at gas processing units, such regulations do exist for VOC emissions from chemical plants and refineries.

These rules specify that fugitive equipment leaks are measured as well controlled when the percentage of leaking parts for each component type (except pump seals or compressor) is 2% or less. For compressor and pump seals, the allowable percentage of leaking parts is 10% or less. Site-specific average emission factors are compared with other published average emission factors for a variety of component source categories is illustrated in Table 2.

Table 2. Comparison of average emission factors derived from collected data to other published values (kg/h/source).

Source Gas Fractionation Plant1 CAPP2 Gas Facilities U.S. EPA Gas Facilities3 U.S. EPA Refineries4
Connectors 2.11e-04 2.53e-03 3.048e-04 2.5e-04
Block Valves 6.45e-03 4.351e-02 3.400e-03 2.68e-02
Control Valves 1.67e-02 N/A N/A N/A
Open-Ended Lines 5.55e-02 3.73e-03 9.015e-04 2.30e-03
Pressure Regulators 4.05e-05 N/A N/A N/A
Pump Seals 1.22e-01 2.139e-01 N/A 1.14e-01
Crank Case Vents 5.18e-01 N/A N/A N/A
Orifice Meters ND N/A N/A N/A
Compressor Seals ND 8.049e-01 1.172e-00 6.36e-01
Pressure Relief Valves 4.79e-03 1.210e-01 2.238e-03 1.60e-01

Note:

N/A Average emission factor for this source type is not available.
ND Leaks for this type of component not detected at the Gas Fractionation Facility.
1 Based on data collected at the Gas Fractionation Plant October 18 to 22, 2004.
2 Source: Canadian Association of Petroleum Producers. 1999. A Detailed Inventory of CH4 and VOC Emissions from Upstream Oil and Gas Operations in Canada. Volume 2: Development of the Upstream Emissions Inventory. Calgary, AB.
3 Source: U.S. EPA and GRI. 1996. Methane Emissions from the Natural Gas Industry. Volume 8: Equipment Leaks. Research Triangle Park, NC 27711
4 Source: U.S. EPA and GRI. 1995. Protocol for Equipment Leak Emission Estimates. Table 2-2: Refinery Average Emission Factors, pg. 2-13.

A synopsis of the relative quantity of THC emissions from the fugitive equipment leaks is illustrated in Figure 3. The leaking block valves were the major source of THC emissions, accounting for 37.7% of THC emissions from leaking sources, followed by open-ended lines at 25.0% and connectors at 14.7%.

Figure 3. Relative distribution, on a volumetric basis, of total hydrocarbon (THC) emissions from leaking equipment components at the Gas Fractionation Plant.

Emission Reduction Opportunities

Total gas losses from detected leaking equipment parts at the site (parts with a screening value of 10,000 ppm or greater) amounted to 470.8 x 103 m3/y worth an estimated Can. $386,465 yearly. 423 components contributed to the leaks; 320 of these are estimated to be cost-effective to repair.

The top 10 economic repairs are illustrated in Table 3. The majority of losses from fugitive equipment leaks are linked to a comparatively small number of parts. The 320 parts that were estimated to be economic to repair stand for 0.4% of the parts in hydrocarbon service, yet account for about 73.7% of fugitive total hydrocarbon emissions.

Implementing all economical equipment repairs that are identified would result in net present savings of Can. $1,055,850 and decrease hydrocarbon losses by 465.0 x 103 m3/y and GHG emissions by 826.5 tons per year CO2E. Extra emission reductions would incur great repair costs.

Table 3. Summary of emissions from top 10 economic-to-repair leaking equipment components surveyed at the Gas Fractionation Plant (October 18 to 22, 2004).

CEL Tag ID (Yellow) LSI Tag ID (Blue and Yellow) Process Unit / Location Component Type Emission Rate (103 m3/y) Value of Gas (Can.$/y ear) GHG Emission Rate (CO2E t/year Estimated Repair Cost (Can.$) NPV (Can.$)
  Y133 CM-12.201/Splitter Compressor -0.5" Gate valve seat Open-ended line - 4'' 111.920 115494 0.000 190 400008
  B22 PM-18.204/LPG Transfer Pump -GREATER THAN 18.4% Gate valve - 4'' 13.246 12620 0.063 190 43541
5305   HT -16.207AB/Depropanizer Overhead Condenser - Gate valve - 6'' 13.697 10624 0.195 245 36569
5641 Y200 PV-17.11/Butane Treater - union Threaded connection - 1'' 8.678 8955 0.000 30 16388
  B77 PM-18.15/Propane Loading Pump - GREATER THAN 18.4% Pump seal - 6'' 22.397 17373 0.319 500 15889
5213 B238 PM-18.209/Debutanizer Reflux Pump - Gate valve - 8'' 2.672 3919 0.000 350 13229
5637A B194A Next to PV-17.11 - union Threaded connection - 1'' 6.942 7164 0.000 30 13104
  B97 PM-18.702/Propane Loading Pump Gate valve - 10'' 4.327 3356 0.062 500 11129
5371   CM-12.02/Regen Gas Recycle Compressor - B11 (GREATER THAN 18.42%) Valve cover - 1'' 30.293 6026 405.720 200 10847
  Y141 PM-18.401/EP to Pump -FLAMEOUT Pump seal 12.471 12007 0.107 500 10827

Leak Detection Methodology Comparison

Traditional leak detection methods including bubble tests, acoustic ultrasonic leak detection equipment, and handheld organic vapor analyzers have conventionally been used to screen equipment parts for leaks in agreement with Method 21 (US EPA, 1997). The conventional leak detection methods are strenuous and time-consuming. Recently optical gas imaging technology, such as the LSI Hawk camera, has been developed in an effort to optimize the effectiveness of the leak detection method. Optical IR cameras have performed well during several field trials. Optical gas imaging technology can screen hard to observe parts more easily than conventional screening methods. Both methods rely on operator experience and attentiveness for an applicable and complete leak screening evaluation.

The Directed Inspection and Maintenance (DI&M) survey carried out at the Gas Fractionation Plant did not provide sufficient data to perform a quantitative comparison of conventional leak detection and screening methods to the LSI Hawk passive IR camera leak detection technique. However, the work provided sufficient data for a qualitative comparison of the performance of the two leak detection methodologies.

It is proven that both methods are vulnerable to operator error and are only as dependable as the training, care, and attention of the operator. Additionally, neither traditional leak detection methods nor the infrared camera can offer a quantitative emission estimate. In order to measure emissions, technicians have to continue to depend on bagging methods, and devices such as the HiFlow Sampler. Table 4 illustrates observed positives and negatives of each technique.

Table 4. Qualitative comparison of traditional leak detection techniques and the optical infrared LSI Hawk camera technology.

Parameter Conventional Leak Detection Techniques Optical Infrared LSI Hawk Camera
Speed Screening speed:
Typically 1,200 components/person/day For a two person team:
2,400 components/day or 240 components/hour. Screening technicians that are not familiar with the process and appropriately trained may needlessly screen non-target components (e.g., electrical conduit and components in water service).
Screening speed:
For a two person team:
23,000 components/day or 2,300 components/hour. However, greater time is required to tag the identified leakers since the camera operator must communicate the leak location to his/her assistant. Similar potential for needlessly screening non-target components.
Mobility Size:
Gas detectors and spray bottles are small and light-weight and allow the operator to be very mobile in all areas.
Difficult to access components:
Depending on component, ladders or other access points must be found. Extension poles may be used to screen roofline vents and other elevated sources.
Size:
Size and weight make the camera difficult to maneuver in elevated areas. Operating in congested areas is not practical. Size and weight have been reduced in the Flir GasFindIR camera.
Difficult to access components:
Using the camera elevated components and other difficult access locations can be screened from the ground or at a distance.
Cost Conventional Screening Equipment: $5,000 - $10,000 (USD)
Charge for experienced two person contract team: $1,200 per day (USD) plus expenses. Cost would be much less if the work is performed by summer students.
Camera: commercially-available FLIR GasFindIR camera now $75,000 (USD), ~$93,000 with additional lenses
Change for experienced two person contract team: $3,000 per day (USD) plus expenses
Potential Application for Routine LDAR Screening Traditional techniques are simple to learn and require limited expertise. Suitable for use by summer students as part of a seasonal LDAR survey. Use of the camera requires individuals with specific training. The new Flir GasFindIR camera has automatic contrast control and is easier to use the HAWK camera but still requires training and experience.
Weather Operators are limited by very inclement weather and cold (less than -15°C). Screening equipment is not affected by poor weather other than extreme cold. Camera cannot be used during rain or fog and is not as effective during overcast skies. Similarly camera cannot be used in extreme cold.
Leak Identification Application of Leak Definition:
An objective leak definition (i.e., US EPA definition of 1 percent hydrocarbon concentration in vicinity of leaker) can be applied using gas detectors.
Leak Isolation:
It is sometimes difficult to identify a leaking component where there are high background readings due to interference from other nearby leaking sources and in congested areas.
Unconventional Leakers:
Traditional techniques focus in on expected sources and locations (e.g., seal vents, mechanical connections, covers, etc). Leakage at other points on a component or on piping (e.g., due to corrosion and mechanical damage) may not be identified.
Missed Sources:
The reliability of the method is highly dependent on the care and attention used by the screening technician.
Application of Leak Definition:
The camera operator is able to qualitatively assess the size of each leaker (i.e., small, medium, large), but the technology currently does not apply an objective leak definition.
Leak Isolation:
Camera can more clearly ‘see’ a source of leakage in close proximity of other leaking and non-leaking components.
Unconventional Leakers:
The camera is more apt to pick up leaking equipment components in unconventional places since a wide field of view is used.
Missed Sources:
Less sensitive to, but still dependent on, the level of care and attention applied by the screening technician.
Safety Intrinsic Safety:
All traditional screening equipment is rated intrinsically safe.
Slips, trips and falls:
Traditional leak detection techniques require the screening technician to be in close contact with the process equipment which poses a risk of slips, trips and falls. Other injuries resulting from burns and pinched fingers more likely.
Exposure to Vapors:
Operators must be in close proximity to equipment components in order to identify leakers, therefore, there is a greater chance of operator exposure to hazardous compounds in the gas (e.g., H2S and benzene).
Intrinsic Safety:
HAWK camera not intrinsically safe, hot work permit required. Flir camera designed to meet NEC Class 1 Div. 2 criteria.
Slips, trips and falls:
The size and weight of the camera, coupled with the operator’s restricted view when using the camera may contribute to slips, trips and falls. Furthermore, once leaks are detected, the operator must still get in amongst the equipment to install leaker tags.
Exposure to Vapors:
Risk considered minor given that leaking equipment components are viewed at some distance.
Ancillary Benefits Air Leaks:
Leaks of instrument air, nitrogen and other non-hydrocarbon gases may be detected.
Quantify Emissions:
Emission quantification from identified leakers is typically provided as part of the leak detection program.
Identification of Operational Issues:
Given the close scrutiny that equipment receives during the application of traditional leak detection techniques, other concerns or problems can be identified. For instance, internal leakage into a flare header can be identified by noting frosted valves.
Air Leaks: The cameras are designed to only see hydrocarbon leaks.
Quantify Emissions:
Camera crews to date do not offer the service of quantifying emissions from leaking equipment components. LSI may be offering quantification in the near future.
Identification of Operational Issues:
The IR camera is capable of seeing any number of items in the IR range. For instance, the camera is capable of visualizing the solids level in tanks.

The top 10 economical to repair emitters are illustrated in order of decreasing magnitude in Table 5.

Table 5. Summary of 10 largest cost-effective emission reduction opportunities.

CEL Tag ID (Yellow) LSI Tag ID (Blue and Yellow) Process Unit / Location Component Type Emission Rate (103 m3/y) Value of Gas (Can.$/yr) Payout Period (years)
  Y133 CM-12.201/Splitter Compressor -0.5" Gate valve seat Open-ended line - 4'' 111.920 115,494 0.002
  B22 PM-18.204/LPG Transfer Pump - Gate valve - 4'' 13.246 1,2620 0.02
5305   HT -16.207AB/Depropanizer Overhead Condenser - Gate valve - 6'' 13.697 1,0624 0.02
5641 Y200 PV-17.11/Butane Treater - union Threaded connection -1'' 8.678 8,955 0.003
  B77 PM-18.15/Propane Loading Pump Pump seal - 6'' 22.397 17,373 0.03
5213 B238 PM-18.209/Debutanizer Reflux Pump - Gate valve - 8'' 2.672 3,919 0.1
5637A B194A Next to PV-17.11 - union Threaded connection -1'' 6.942 7,164 0.004
  B97 PM-18.702/Propane Loading Pump Gate valve - 10'' 4.327 3,356 0.1
5371   CM-12.02/Regen Gas Recycle Compressor - B11 Valve cover - 1'' 30.293 6,026 0.03
  Y141 PM-18.401/EP to Pump -FLAMEOUT Pump seal 12.471 12,007 0.04

Conclusions

The conclusions derived from the targeted emission survey are listed below:

  • Usually emissions from leaking equipment parts were well-controlled and this is due to a superior maintenance program. Few large leakers were detected, and less than 0.6% of all equipment parts in gas service were established to be leaking. Normally, fugitive equipment leaks are considered to be sufficiently controlled when a leak frequency of less than 2% percent is attained. The average emission factors derived from the site-specific data commonly compare satisfactorily to corresponding factors for the upstream oil and gas sector in Canada and US EPA published factors for gas plants and refineries.
  • The emission survey has provided: An evaluation of total hydrocarbon, greenhouse gas and methane emissions at the factory; An estimate of the emissions from rail car spit tubes during filling; Average site-specific emission factors for potential estimation of emissions from fugitive equipment leaks; and a ranked listing of identified leak control opportunities.
  • There was 320 cost-effective emission control opportunities identified. This represents a potential reduction in fugitive THC emissions of 465.0 x 103 m3/yr (83% of THC emissions from fugitive equipment leaks) and a posisble savings of up to Can. $383,500 per year in avoided product loss.
  • Table 5 illustrates 10 largest emission points, out of which five were found using conventional screening techniques and eight were found by optical gas imaging. The two leaks that were not detected by the optical gas imaging camera were large enough to be identified by the camera but were overlooked by the camera operator.

This information has been sourced, reviewed and adapted from materials provided by FLIR Commercial Systems.

For more information on this source, please visit FLIR Commercial Systems.

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