Warren R. True
Pipeline/Gas Processing Editor
Regulatory pressures by the U.S. government and several individual states are forcing gas processors to examine their operations for sources of toxic emissions.
Of specific concern are emissions from the reboiler still vents of glycol dehydration units. These emissions are being analyzed to determine levels of benzene, toluene, ethyl benzene, and the xylene isomers (BTEX) and other volatile organic compounds (VOC).
Enactment of the U.S. Clean Air Act Amendments in 1990 has been the catalyst for industry's efforts made more pressing by the potential magnitude of the problem: the Gas Research Institute (GRI), Chicago, estimates that more than 30,000 glycol reboiler units operate in the U. S.
Concern over BTEX/VOC emissions from these units has been surfacing at industry meetings, such as the recent Gas Processors Association 72nd Annual Convention, and prompted a technical conference on the subject last year sponsored by GRI.
Its siting--New Orleans--was intentional Louisiana has led states' efforts to quantify and control toxic emissions from glycol reboiler stacks.
This is the first of three articles which derive from that GRI conference.
A series of presentations by individual state regulators reviewed major impetus for greater control of reboiler hydrocarbon emissions. Another series of presentations related efforts by gas processors to measure and control the emissions and recover marketable hydrocarbons from glycol streams.
The concluding two articles present operators with two different methods for estimating emissions from their existing units.
Oryx Energy Co., Dallas, describes development and use of an emissions-estimating procedure that employs measurement of total condensation.
GRI and Radian Corp., Austin, jointly have developed a personal computer program for estimating emissions from reboiler stacks. This program, described in the conclusion to this series, is available free of charge to the industry.
Additionally, there are commercially available process simulator tools which assist an operator in analyzing reboiler vent stack emissions for excessive BTEX and VOC.
REGULATORY PUSH
The U.S. Clean Air Act (CAA) Amendments of 1990 have spurred the gas-processing industry more closely to examine air emissions from the vent stacks of glycol reboilers.
Radian Corp.'s P. J. Falzone said that under Title V of the CAA, many glycol units will for the first time be required to obtain a permit to operate. This permit program implements all CAA requirements applicable to stationary sources of air pollutants.
Title III of the CAA amendments lists 189 hazardous air pollutants. Among these, glycol dehydration units emit BTEX components as well as ethylene glycol, formaldehyde, and acetaldehyde. Falzone said that glycol dehydration units that emit 10 tons/year (tpy) of any of these or 25 tpy of any combination of hazardous air pollutants are subject to regulation under CAA, requiring the use of maximum achievable control technology.
LOUISIANA LEADS
It is generally agreed that Louisiana has led the way in efforts to monitor and reduce levels of harmful emissions from glycol reboilers. That state's efforts pre-date CAA.
In the 1980s, said T. L. Starrett of Louisiana's Department of Environmental Quality (DEQ), the department's air-quality division field inspectors initially raised concerns about emissions from glycol (triethylene glycol--TEG, or ethylene glycol) dehydrators.
They found significant amounts of VOCS, especially BTEX compounds, were being emitted from the reboiler stacks of many dehydration units operating in the state.
In cooperation with members of the Mid-Continent Oil & Gas Association, the DEQ compiled a list of glycol unit operators in the state which, in November 1989, received written notice of the agency's concerns.
The agency set up a database of facilities, limiting its attention to plants processing 5 MMscfd or more. Nonetheless, some data, Starrett said indicated significant sources of toxic emissions among plants processing less than 5 MMscfd.
Owners and operators were requested to test facilities for BTEX and total non-methane/ethane hydrocarbons. This information compiled with other data--throughput (actual and design), glycol circulation rate (actual and design), and type of glycol used--was added to the database.
This initial survey revealed that many tested units emitted VOC exceeding 100 tpy, according to a report issued in January 1991. Emissions per unit ranged from I tpy to approximately 1,300 tpy of total hydrocarbons (THC).
Later, the number of units reported to the database increased but the THC emitted declined, reflecting installation of controls at several sites, said Starrett.
Units found to emit more than 100 tpy violated the state's Waste Gas Disposal Rule. A compliance order issued as a result required companies to submit control plans to the DEQ detailing their schedules for installing needed controls.
The order also required owner-operators to apply for a new permit or to modify any existing permit for their units. And it required each owner-operator to submit an emission inventory questionnaire or update an existing one for a given facility.
TWO REGULATIONS
Starrett said that hydrocarbon emissions from glycol dehydration units are currently regulated under two state regulations: the Waste Gas Disposal Rule, as mentioned, or Chapter 51 of its Air Toxic Program.
The former stipulates that if a facility emits more than 100 tpy of THC, each of the waste-gas streams must not exceed 100 lb of THC in any continuous 24-hr period. If the 100 lb/24 hr-period standard is exceeded, controls must be installed.
Under a regulation passed in November 1990, any controls must achieve at least 95% or more removal efficiency if the unit was constructed before Jan. 20, 1985, or 98% efficiency if constructed after this date.
Under Chapter 51, a facility is a major source if it has either 10 tons of one toxic air pollutant (TAP) or 25 tons of any combination of TAPs listed in Tables 1 and 2 of Chapter 51.
If the facility is a major source (under Chapter 51), maximum achievable control technology must be installed if the facility's emissions exceed the minimum emission rate for any Class 1 or Class 2 compounds.
Both the state's Waste Gas Disposal Rule and Chapter 51 require that the waste-gas stream must be condensed and that noncondensibles must be burned at the final vent in a flare or rerouted to the reboiler burner as a supplemental fuel source.
OTHER STATES' EFFORTS
Publicity of Louisiana's efforts prompted officials in other states to re-examine their glycol-based gas-dehydration facilities as possible sources of toxic emissions, according to Nancy Pees Coleman and Bradley Cook of Oklahoma's Department of Health.
In Oklahoma, the scrutiny widened to include fugitive emissions from pumps, valves, and flanges and evaporation of liquids (glycol and condensates) that are often difficult to measure as well as "working/breathing" losses from condensate storage tanks.
Cone-roof tanks, which vent directly to atmosphere without emissions controls, are often used in conjunction with glycol units, they said.
The Air Quality Service (AQS) of the Oklahoma Department of Health, assisted by the Mid-Continent Oil & Gas Association, conducted an informal inventory of facilities and developed a rich-lean glycol sampling and analysis protocol for use in the state.
The inventory revealed that more than 1,000 glycol units were in service in gas-producing fields in Oklahoma. Most of the units were located upstream of lease-custody transfer points and therefore under jurisdiction of the Oklahoma Corporation Commission.
Results of an emission inventory conducted for 1991 by operators of AQS-regulated facilities are shown in Table 1.
Coleman and Cook said that toxic emissions from glycol dehydration units located downstream of lease custody transfer are potentially subject to state regulation. Currently, all such facilities must evaluate their emissions, report emissions on an annual emission inventory, and maintain compliance with maximum acceptable ambient concentration standards.
In July, functions formerly conducted by the AQS as a unit of the state's Department of Health will move to the newly created Department of Environmental Quality.
Chad Schlicktemeier, air-quality engineer, Wyoming Department of Environmental Quality's air-quality division, reported that in February 1992, the division surveyed approximately 50 companies which owned or operated glycol units in the state.
Of the 1,221 units reporting, 14 indicated emissions from glycol reboiler stacks were being controlled; of these, 13 were on units at which more than 10 MMcfd of gas was being processed; 7 were on units processing more than 100 Mcfd.
The division's intention was to focus its attentions on facilities which actually processed more than 10 MMcfd.
Schlicktemeier said that any unit constructed after May 29, 1974, with a VOC-emission rate determined to be significant by an as-yet undetermined method will be required to obtain an air-quality permit for operation. Significant levels currently kick in at 40 tpy of VOC per individual unit.
Wyoming will use the constraints set out in Title III of the 1990 CAA to govern hazardous air pollutants (HAPs): 10 tpy of any one pollutant on the list of 189 or 25 tpy for any combination of pollutants on the list.
Schlicktemeier indicated that Wyoming may, given certain operational schemes, examine emissions from sources collectively. The focus here would be on a gas field which may contain a glycol dehydration unit, condensate storage tanks, and other sources of VOC emission at the well head.
On an individual basis, the emissions may be insignificant, he said. But some Wyoming counties have more than 1,000 wells, and emissions from all operations taken collectively have been shown to be alarming.
COMPANY ACTIVITIES
Most gas processors have begun to modify existing glycol reboiler equipment to reduce or eliminate VOC emissions. Two such companies related their strategies and experiences.
Natural Gas Pipeline Co. of America, Lombard, Ill. (NGPL), reported on two installations at which it has addressed the problem of VOC emission from glycol dehydration units.
One is at the company's storage field near Longview, Tex.; the other is at the pipeline facilities near Cameron, La., associated with the Stingray Pipeline.
INCINERATING VAPORS
In Texas in 1991, NGPL added a fifth glycol dehydration unit to four that were already operating on site. These latter had combined inlet capacity of 725 MMscfd; the new one added 300 MMscfd.
The construction permit issued by the Texas Air Control Board required reduction of VOC emissions from the existing four glycol dehydration units as well as the new unit.
Thomas J. Kresse of NGPL said that the company installed incinerators completely to combust the overhead vapors from the glycol reboiler still columns.
One (42 in. X 31 ft stack) was installed to burn vapors from the existing four glycol units whose regenerator skids are all located adjacent each other in a row. The fifth, newer skid lies about 75 ft from the others and was installed with its own incinerator (24 in. X 29 ft stack).
Both were supplied by Sivalls Inc., Houston.
Each incinerator (Fig. 1) is installed with a flame arrestor in both the inlet vapor line from the glycol reboiler still columns and the air inlet.
Each stack is installed with a main fuel-gas burner, pilot-gas burner, an ultraviolet (UV) flame detector, and a temperature controller that controls the fuel-gas rate to maintain a temperature in the incinerator of approximately 2,300 F.
A flame-failure signal causes the flame-failure panel to vent the inlet vapor line from the still column to an existing storage tank while also shutting off the vapor line to the incinerator and the main fuel gas to the incinerator.
The flame-failure panel will then attempt to relight the pilot and automatically start incinerating the vapors again after the pilot is relit.
Kresse said that when the incinerators were first started up in December 1991, they experienced problems with incomplete combustion. This condition produced periods of smoke in the stack gas.
NGPL determined that liquids were condensing in the inlet vapor lines and causing combustion problems.
The inlet vapor lines were insulated and an internal tray was installed to collect liquids inside the incinerator and allow them to vaporize and burn. The incinerators continue to experience problems with incomplete combustion, however.
Kresse said that a new naturally aspirated smokeless burner was installed in March. The inlet vapors and liquids from the still column move into the new smokeless burner tip and are aspirated with air to provide complete combustion.
The existing main fuel-gas burner acts as a pilot for the new smokeless burner. These revisions have been engineered by Sivalls and will be tested by mid-year.
CONDENSING VAPORS
At the Stingray pipeline facilities in Louisiana, NGPL operates two glycol dehydration units. One is rated at 300 MMscfd; the other, at 200 MMscfd.
In 1990, the Louisiana Department of Environmental Quality (DEQ) required glycol dehydration units with more than 100 tpy of VOC emissions to submit a plan to reduce these emissions. In June 1991, the DEQ accepted NGPL's control plan; abatement equipment was installed in February 1992.
Also purchased from Sivalls Inc., the VOC abatement equipment at the Stingray facilities consists of a vapor condenser unit. Since the liquids condensed from the glycol reboiler still-column vapors are a liquid product and can be combined with other liquids collected in the shore facilities, the installation of a vapor condenser unit was considered the best unit for this location.
The vapor condenser unit (Fig. 2) consists of an aerial fin-fan cooler that cools the gas to 60-100 F., depending on the ambient temperature.
The vapors and condensed liquids then flow to a three-phase separator where the hydrocarbon condensate is separated from the water in a bucket-weir arrangement in the separator.
The hydrocarbon condensate and the water are then pumped to be combined with other liquids collected in the shore facilities. The noncondensable vapors flow to low-pressure burners in the glycol reboiler's fireboxes.
Flame failure in either glycol-reboiler firebox causes the noncondensable vapors to shutoff to that firebox. Flame failure in both glycol-reboiler fireboxes causes the noncondensable vapors to be vented to an existing storage tank.
A high-level shutdown in the three-phase separator causes the inlet vapors from the still columns to vent to the existing storage tank and shuts off flow to the vapor condenser unit.
The vapor condenser unit started up in March 1992.
Kresse said that attempting to bum the noncondensable vapors from the three-phase separator in the glycol reboiler's fireboxes caused soot to form on the inside of the reboiler's firetubes. The low-pressure burners were unable completely to combust the noncondensable vapors.
To correct this problem, a vapor compressor will be added to the unit to compress the noncondensable vapors to 20 psig. They will then be injected into the existing main fuel-gas burners. Burning the noncondensable vapors in the main fuel-gas burner should provide complete combustion of the vapors.
The vapor condenser unit is now operating by condensing as much liquid from the vapors as possible and not burning the noncondensable vapors until the vapor compressor is installed.
NGPL has experienced several problems with the VOC-abatement units for its glycol dehydration units. Both the incinerators and the vapor condenser unit need further modifications before they are ready for proper operation. Modifications should be completed later this summer.
ROCKY MOUNTAIN CONDITIONS
Amoco Production Co.'s Overthrust gas-processing plants require dehydration of gas that runs at relatively high temperatures and contains hundreds of ppm of aromatic components, according to Phil Archer of Amoco. These conditions, he said, result in high VOC emissions.
Amoco's approach of condensation, vapor recovery, and incineration has proven economical in eliminating 100% of regenerator emissions.
But the costs involved, he said, are only suitable for application in large gas plants' TEG units. In addition, any operator should be cautious in selecting a unit that will run under a vacuum in the presence of traces of either H2S or CO2 or both.
TESTING
In early 1991 Amoco saw the need to determine VOC emissions from major plant TEG systems in its northwestern business unit.
Amoco's environmental and safety group, along with the Wyoming DEQ, devised a stack-testing method to quantify TEG regenerator-stack emissions. The testing method involved two separate elements: stack velocity determination and sample recovery.
Western Environmental Services and Testing, Casper, Wyo., contracted to perform stack tests for plants at Anschutz Ranch East, Painter complex Whitney Canyon, and Ryckman Creek. Western devised a sample-recovery method.
For stack velocity, the procedure followed outlines in the Code of Federal Regulations (CFR), Title 40, Part 60, Appendix A, EPA Methods 1 and 2.
In addition to the stack samples, a rich-lean glycol material balance was included as part of the tests at Anschutz Ranch East.
Data from the rich-lean glycol tests were inconsistent, however, and emissions estimates could not be calculated based on the tests, said Archer. The results were so inconsistent that they had to be thrown out. The summary of results for the TEG stack tests appear in Fig. 3. Composition of TEG stack vapors for Whitney Canyon alone appear in Fig. 4.
The stack tests established unacceptable VOC emission levels at Whitney Canyon, Ryckman Creek, and both units at Anschutz Ranch East.
The TEG process conditions are shown in Table 2.
Noting that the greatest contributor to VOC emissions is the TEG circulation rate, Archer said that the high TEG circulation rate at Whitney Canyon indicates the presence of high emissions.
But at the other four units, emission levels are not directly proportional to TEG circulation rates. Other factors, such as the aromatic content of the gas stream, contactor-tray efficiency, rich TEG-water loading, stream temperatures, and stream pressures all contribute to this discrepancy.
Archer said also that the stack samples themselves are subject to wide variations because of the sampling method itself and reboiler temperature cycling.
SOLUTIONS
Amoco determined that at Ryckman Creek, the TEG unit was unnecessary for plant operation and removed it from service.
At Whitney Canyon and Anschutz Ranch East, eliminating the TEG units was not an option. Installation of TEG stack vapor-recovery units (VRUs) was therefore deemed necessary.
The system consists primarily of an inlet condenser followed by a screw compressor for the noncondensables. The system allows the noncondensable vapors to be re-introduced into the plant process.
Vapors leaving the TEG still are recovered at 11 psia (atmospheric pressure for the 8,000 ft elevation at Whitney Canyon). The 180' F. vapors flow through a fin-fan cooler and leave typically at 85 F. and 9 psia.
The vapors at a vacuum condition enter a blow case-style inlet separator which contains two different chambers. The liquids drop into the bottom chamber of the inlet separator which pressures up and dumps when full, twice per minute in the design case.
The noncondensables enter a screw compressor where they are mixed with an oil stream and compressed to 70 psia.
The dual-phase stream enters a lube-oil separator where the lubricant is separated from the process stream. The lube oil passes through a small section of the fin-fan cooler and an oil filter before it is re-introduced to the compressor inlet. The process stream continues into the after-cooler section of the fin-fan cooler then through a discharge separator and out of the system.
The 65-psia vapor product is used as fuel gas for the incinerator at Whitney Canyon and is sent to the flare from both units at Anschutz Ranch East.
AMOCO'S EXPERIENCE
Archer said that Amoco has learned several lessons since these units have been operating:
- The first lesson is in seal, gasket, and valve-seat selection.
Start up of the first unit was plagued with problems from sections of the unit which contained Buna-n parts.
Because Buna-n is incompatible with aromatic components, this problem cannot be overlooked in any TEG regenerator vapor-recovery application.
- The second problem is the operation of the screw compressor itself. The compressor is sensitive to fluctuations in lube-oil separator temperature.
When the temperature is allowed to get too high, significant oil loss from vaporization will occur. Conversely, when the temperature gets too low, water vapor from the process stream will condense in the lube-oil separator.
Water condensation causes severe oil-dilution problems because the specially formulated oil is approximately as heavy as water and cannot easily be separated from the lubrication stream once it has condensed.
- A third problem is particular to sour-gas plants.
Problems are experienced at Whitney Canyon with H2S and CO2 residuals that enter the TEG system and end up in the TEG VRU. The levels of H2S and CO2 are not high enough to cause problems under normal conditions, but because sections of the VRU experience vacuum conditions, some oxygen enters the system.
The presence of water and oxygen along with traces of H2S and CO2 cause extreme corrosion levels.
Copyright 1993 Oil & Gas Journal. All Rights Reserved.
