E

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/R Incorporated Providing Environmental Technical Support Since 1989

501 Eastowne Drive, Suite 250  Chapel Hill, North Carolina 27514

Telephone: (919)484-0222  Fax: (919) 484-0122

MEMORANDUM

Date: October 14, 2010

Subject: Summary of the October 12, 2010 Meeting between the Environmental 

Protection Agency (EPA) and American Petroleum Institute (API)

From: Denise Grubert, EC/R Incorporated

To: Bruce Moore, EPA/OAQPS/SPPD/CCG

I. PURPOSE

This memorandum summarizes the October 12, 2010 meeting between the EPA and industry 

representatives from API. The meeting was requested by API as a follow-up to a September 9, 

2010 conference call. The intent of the assembly was to further discuss current informational 

needs, methodology, and as an opportunity for EPA to inquire information in regards to control 

technologies. 

II. DATE

The meeting took place on October 12, 2010 from 1p.m. to 4:45 p.m. at the United States 

Environmental Protection Agency in Research Triangle Park, North Carolina. 

III. ATTENDEES

The following individuals were present at the meeting. Please note this may not be an extensive 

list, but represents the names of people who signed the attendance sheet. 

Industry Representatives

American Petroleum Institute: Matt Todd

Kathy Kalisz (Phone Call-In)

British Petroleum: Jeffrey A. Adams

Chevron: Clay Fleeberg,

 Janet Bounds (Phone Call-In)

 Shankar Ananthakrishna (Phone Call-In)

ConocoPhillips: Clint Gill

ExxonMobil: Tom Monahan

Marathon Oil: Jenny Yang

Shell: George Deeley
E

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/R Incorporated Providing Environmental Technical Support Since 1989

501 Eastowne Drive, Suite 250  Chapel Hill, North Carolina 27514

Telephone: (919)484-0222  Fax: (919) 484-0122

U.S. Environmental Protection Agency (EPA/OAQPS/SPPD/CCG)

Bruce Moore

Nick Parsons

Anne Pope

David Salman

EC/R Incorporated

Heather Brown

Denise Grubert

Phil Norwood

IV. SUMMARY OF DISCUSSION

The meeting was scheduled in response to the phone conference between EPA and API on 

September 9, 2010. This meeting provided EPA an additional opportunity to ask specific 

questions regarding control options for various emissions sources. Prior to the meeting, Rachel 

Agnew of EPA, e-mailed Matt Todd of API directed questions to facilitate the discussion 

regarding closed-loop systems, pneumatic controllers/valves, and centralized gathering systems

for produced water. API provided written response which is provided as Attachment I.

Bruce Moore of EPA reiterated EPA’s position on finding cost-effective controls that reduce air 

pollutants; as there is growing public concern on air emission sources from Oil and Gas drilling 

and production, which is rapidly expanding in the public’s backyard.

API then began discussion on specified control topics. In regards to centralized liquid gathering 

systems, the decision to install a system varies based on field parameters, volume of the 

produced water and economics. Ideally, centralized liquid gathering systems would appear at 

new fields at the time of production.

API clarified their interpretation of the term “closed-loop.” Closed-loop systems capture gas and 

funnel gas back towards the sales line. This must occur at very low pressure. 

EPA mentioned Uniform Standards were likely to impact what and how we regulate certain 

sources in the future. Several uniform standards that could eventually impact this rulemaking 

include: wastewater treatment, storage tanks, leak detection and repair (LDAR) including 

ancillary equipment, heat exchangers, and closed vent systems (includes flares). It was noted that 

applicability would have a major role in determining the sources regulated and what level of 

regulation. 

Phil Norwood from EC/R asked API to comment on flare technology including efficiency, the 

current use of portable flare devices, and limitations of flares as a control device. API responded 

that VMAX is a concern under 40 CFR 60.18. John Zinck is currently working on an issue paper 
E

C

/R Incorporated Providing Environmental Technical Support Since 1989

501 Eastowne Drive, Suite 250  Chapel Hill, North Carolina 27514

Telephone: (919)484-0222  Fax: (919) 484-0122

regarding VMAX and flares and API has commented that they will send EPA the study. It was 

noted that Sonic flares, which have high efficiency, are not allowed under 40 CFR 60.18 due to 

the continuous pilot requirement. Continuous pilots are also a hindrance because in some 

applications, i.e. unmade remote locations, electric ignitions would be preferable. In instances 

that do not apply to the rule, sonic flares have successfully controlled emissions. 

LDAR was presented as a topic. API stated that the “Drill and tap” is not a typical practice as 

defined in another rulemaking and most companies must use costly third-party contractors. This 

becomes highly expensive when performed in remote areas. In addition, API mentioned the 15 

day time period is not long enough when in remote areas with contractors. In addition, API

restated their preference for Audio, Visual Olfactory (AVO) versus EPA’s Method 21, especially 

at remote locations. FLIR cameras are a great option, but costly (Capital over $100,000 and 

annual costs of $1,000) and there are limited contractors with proper training. API is highly 

concerned with keeping track of tags [required in Method 21 when leak is detected]. EPA 

questioned the efficiency of AVO at production facilities when odor has not been added to the 

gas stream. API mentioned due to pressure, you can hear and sometimes see vapors raising off 

pipes much like heat. Bubble solution already incorporated into normal work practices. 

EPA asked API for comments on compressor seals, which are exempt under the standard engine 

rule. Specifically, EPA wanted to know the time between rod packing replacements. API 

responded that it was variable and they would need to discuss with the operators in regards to 

maintenance plans. It was suggested a potential for a phone call with a few engineers could be 

possibly, but was not scheduled at this time. API suggested sending all questions through e-mail 

and written responses could be returned. 

API raised concern about potential pneumatic controls. It seems as though EPA is focusing on 

high greenhouse gas emissions and low VOC emissions, rather than sources with high VOCs and 

HAP. EPA stated methane is currently being reduced as a co-benefit, but it was possible to 

redefine VOC service within the rule. API stated subpart KKK and subparts VV/GGG have 

different definitions, currently. 

API was concerned that Oil and Gas would be the first industry regulated under 111(d). There 

was concern on the basis for cost-benefit, as it is arguable hard to justify anything other than the 

use of current market prices. 

Under new ozone designations, API feels many counties will be non-attainment when monitors 

are in place. CTG may be more affective in non-attainment areas. API mentioned it could be 

more effective to include remote rule burden, much like the current HH regulation. 

EPA discussed the potential emission floor of 1 ton of benzene could potentially be used. API 

raised questions on record keeping for facilities above and below the emission floor. EPA 

responded that nothing has been officially decided. 
E

C

/R Incorporated Providing Environmental Technical Support Since 1989

501 Eastowne Drive, Suite 250  Chapel Hill, North Carolina 27514

Telephone: (919)484-0222  Fax: (919) 484-0122

In regards to Risk Assessment, have data from NEI database with 17,000 major emission 

sources. After coordinates are assessed, could API potentially help locate if incorrect? API 

agreed. It was also noted that EPA has formulated dose-response levels for ethyl-benzene, which 

were not included in risk assessments prior so this could change outcomes. API can check EPA’s 

website for more information. 

EPA raised a question regarding tanks and emission calculations. Texas has a study where they 

summarize acceptable methodologies. API ranked the following (1) Prosym, (2) E & P Tanks, 

(3) GOR method, (4) Vasquez-Beggs (limited applicability). API stated they feel AMINECALC 

does a pretty good job at simulating amine treaters. API also provided information, including a 

handout which has been included as Attachment 2, on the geographical database for E & P 

Tanks. TCEQ does not allow this in Texas, currently. Working and breathing losses from tanks 

are better estimated using TANKS 4.09d. It could be appropriate for E & P Tanks to analyze C5 

and higher. API raised a question from the prior meeting in July regarding thief hatches on tanks. 

API has their own standards for tanks, but not thief hatches. Thief hatches need strong gasket 

material appropriate for field parameters. To ensure proper repair of gaskets there should be 

enough time to perform repair. This only matters if the tank is controlled, and many are not 

under control and vent to atmosphere. 

API raised questions regarding gas composition formulated to estimate nationwide emissions. 

Each basin is extremely variable within itself that API feels skeptical by just one estimate. EPA 

explained the profile itself is not used to make decisions but gather information on average 

emissions. EPA stated it would forward API more information regarding the composition. 

EPA also provided API with emissions sources that are being considered for regulation, 

however, no final decision has been made. These sources may not include water pits, land farms, 

pipelines. It was restated that no official decision has been made final. 

API agrees with EPA that multi-well sites are more effective for air emission controls, however, 

there are many reason to discontinue use of multiple wells sites. API mentioned the new 1-hour 

NOX is hurting centralized facilities. 

API also stated they would send technical comments submitted to TCEQ that may be relevant to 

emission sources under consideration by EPA. 

The meeting adjourned at 4:45pm (EST). No additional meeting or phone call has been officially 

scheduled at this time. 
treatment

versus the practice of hauling water from smaller and more numerous tank

batteries. The benefits the agency currently sees in centralization are:

-Reduced vehicle miles travelled (loading and unloading)-Fewer control devices are needed-Reduction in leaks

- Smaller footprint

The oil and gas industry uses the terms water storage and disposal instead of centralized

water treatment. Decisions regarding water storage and treatment are business driven

based on operational needs, flexibility, feasibility considerations, cost effectiveness,

proximity to wells and production rates. Other limiting factors include availability and

location of disposal wells with adequate capacity, lease requirements, pipeline capacity,

and right-of-ways. Economics and operability need to remain the primary drivers

influencing the need for central location of facilities. Furthermore, it will be very

difficult, if not impossible, to establish a clear definition ofthe geographic boundary for

any central facility requirement.

The best time to determine feasibility and design of a central produced water facility is

during the development planning of a new producing field. The hurdles discussed beloware most prominent when looking at the feasibility of centralizing an existing field or anin-field development program.

Typically, central facility consideration using pipeline feeds makes the most sense where

operators have exclusive lease rights or are able to secure joint interest agreementsamong other operators that allow sharing of a central facility for produced water storage.

The limitation is that lease rights change, do not remain exclusive and may become joint

agreements. Joint interest agreements for central processing facilities can also have
If there are lease, distance, and/or pipeline right

of

way problems, a central facility with

pipeline feeds is not possible. The footprint and emissions will increase due to increased

pipeline right-of-ways, and additional compressor and pump stations may be needed. A

central facility might still be constructed, but smaller tank batteries would still need to

truck water throughout the producing area to the centralized water storage and disposal

site; thereby increasing the vehicle miles travelled.Consideration must be given to how and where the water will be disposed. The optimal

situation that would meet the EPA benefit expectations is if the disposal well(s) is/are

close to the central facility and can adequately handle the throughput volume at the

facility. In this ideal scenario, water could be separated near the weilsite, pumped to the

central tank facility, and then injected directly from central storage to the disposal well(s)

which eliminates produced water trucking.

On the other hand, if produced water disposal can be sent to a third party disposal site, or

the disposal wells needed to handle the volume are scattered across the field and distantly

apart, direct injection from the central facility is less feasible and water may have to be

trucked to the disposal wells or lengthy pipelines may have to be constructed to reach the

disposal wells. Economics and practicality might then favor trucking from or near thepoint of initial separation.

Pipeline construction either to or from the central facility presents potential challenges

that make it infeasible. Miles of additional rights-of-way must be secured separate from

lease rights-of-way from product flowlines and pipelines. These rights-of-way negate

any footprint reduction that is perceived from constructing a central facility as vegetation

must be cleared for construction and maintenance access. Depending on the topography

and distance between locations, additional pump capacity and/or pump stations may be

required to maintain adequate pressure to move liquids to a central processing facility.
exposure to environmentally sensitive areas (e.g., rivers, creeks, wetlands, and wildlife).

Closed Loop Systems

Several control technologies listed on the Oil and Gas VOC Emission Control Options

table can be considered “closed ioop systems”. API did not specifically use the term

“closed loop system”. Depending on the use and design, the Emission ControlTechnologies listed below and having the same identifier on the subject table, can beconsidered a “closed loop system”:

• “Collection of low pressure gases into fuel supply”

• “Vapor Recovery Unit”• “Glycol Dehydrator Rich Glycol Flash Separator”• “Secondary Separator for liquid stream”

Leak Detection and Repair Program for Oil & GasExisting Subpart KKK for Natural Gas Processing PlantsThe existing Subpart KKK requirements are still protective and the best demonstratedcontrol technology. The more stringent leak rate definitions promulgated for the refiningand SOCMI industries are not reasonable because of the light average MW of the

substances in the natural gas processing industry. The definition of VOC service was

changed to include unprocessed natural gas (wet gas) that is often over 90% methane andethane. It is difficult to stop leaks of these light gases to the low levels maintained in

refineries and SOCMI facilities.

Additionally, the “drill and tap method” of injecting valve sealant has been proposed to

be a technically feasible on-line repair method for refining and SOCMI facilities by EPA
However, O&G facilities are located in rural areas of Colorado, Kansas, New 

e

co,

Oklahoma, Texas, Wyoming, Alaska, etc. where these contractors are not available. For

the O&G industry, the “drill and tap method” is still an “extraordinary repair method”because of the distance contract personnel and equipment would have to travel to make

the repairs.

Oil and Gas Production FacilitiesWhen promulgating NSPS, Subpart KKK, EPA rightfully recognized that the

requirement for fugitive monitoring by Method 21 using instruments to measure a leak

rate would be burdensome for even small gas processing facilities, thus provided an

exemption for these small facilities (see 4OCFR6O.633(d)). O&G production facilities

would be even more burdened by this type of monitoring requirements.However, if EPA believes that LDAR is required for new (after proposal of the rule)

O&G production operations, then API believes that auditory, visual, and olfactory (AVO)inspections (similar to those required by 4OCFR6O.502(j) for Bulk Gasoline Terminals)with by exception documentation represents BDCT (Best Demonstrated ControlTechnology. By-exception documentation would consist of immediately tagging any

leak found until the leaking component has been repaired within 15 days. The leak willalso require documentation in a leaking component log andlor work order.

Requirements to tag all fugitive components or document AVO inspections where leaksare not found will be excessively burdensome because of the remote and dispersed nature

of most O&G production facilities. It is important that the LDAR program requirements

be designed such that operators can complete these requirements within their normal

inspection and monitoring routines. Otherwise, added vehicle miles will offset any

potential reductions that may be realized.
‘I

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C Stable O Tank C HYP Distillation Column

Known Separator Stream lnlormatisn Control Etlicrency

C 1. Low Pressure Dl F Use Conrrol Etticrency

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H2S 0.0000

02 0.0000

C02 0.0100

N2 0.0100

Cl 4.3300

2.5800

3.4200

3.4300

3.7300

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1 4.6500

13.2600

7.8000

13.6300

0.5400

1.9200

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MW 196.00

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4 60 9.4 750 SO

5 61 70 85 85

6 61 9.8 730 84

7 62 10.4 57 82

8_ 63 7.0 72 80

9 63 11.9 730 80

00 64 6.4 580 77

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02 66 11.8 807 96

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9 nC4 812

10 CS 7215

11 nC5 7215

12C6 8816

13 C7___________ 100.21)

14 C8 114.23

15 9 12828

16 C10+ 16600

17 Bensene 78.11

18 Toluene 8213

19 E8enzene 10617

20 Xylenes 106.17

21 n•C6 86.18

22 224Trimethy 114.24

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0 0100 0.0012 0.0006 0.0764 00628 0 0760

0.0100 0.0001 0.0000 0.0848 0.0002 0.3822

4. 8300 0.2285 0. 0247 40.5828 9 1 644 38.6108

2.5800 0.5927 0.41 28 17.6576 20.3686 17 7424

34200 1 8651 1.6803 15.2168 23.2087 154666

3 4300 2.7565 2.6664 8 5398 14 3538 8 7215

3.7300 3.2826 3.2255 7.0488 12.1981 7.2098

5.5500 5.6805 5.6681 4 5601 8.3507 4.6786

3.6500 3.8346 3.8379 2.2492 4.2080 2.3104

8.0700 8 8085 8.8688 1.7007 3.3540 1 7524

146500 16.4468 165891 1 0169 2.1185 1 0514

13.2600 14.8703 151102 0.2843 0.6264 0.2948

7 8000 8.8206 8.8050 0 0564 0.1310 0.3587

19.6300 22.2172 224324 0.0008 0.0023 0.0008

0 5400 0.6005 0.6050 0.0811 0.1620 0 0836

1 9200 2 1626 2.1822 0.0794 0,1685 0.0821

01700 0.1821 0.1839 0.0023 0 0051 0 0023

2.2200 2.5092 2.5331 0.0255 0.0576 0.0265

4 4300 4.91 82 4.9541 0.7261 t 4561 0 7488

0 0000 0.0000 0.0000 0.0000 0.0000 0.0000

106.20 15.44 115.84 36.16 4989 3658

1.0000 0.8835 0.8798 0 1165 0.0038 0.1202

2081 33 2802.89 2103.87

1.25 1.72 126

18214 21 07 1343

316.85 85.54 71 87

0.681 0.692 0.693

tStartl I “ 1’ Toni P Ml fl Final Co... I fl AcJnh A... I SMv Yahn... II ii FR,P TA... lDnrtinie... I Desktnn >> Air >> 
Oil and Gas Flaring and Issues with 40 CFR §60.18

Introduction

For emissions control in oil and gas production operations, flare design and purpose is varied. Oil 

and gas flares generally serve one or a combination of several different purposes. Uses include 

continuous control for process operations, standby for backup to primary control systems, and 

blowdowns for maintenance startup shutdown (MSS) events or emergency upset events. Each 

use requires a flare design that is fit for purpose for optimum operational efficiency.

In many cases, especially at newer, larger natural gas compressor stations and gas processing 

plants, flares are designed to meet 40 CFR §60.18 requirements. Even if there is no applicable 

NSPS Subpart, permits often refer to §60.18 for flare design. However, depending on operating 

conditions, additional operating efficiencies would be possible if these sites were not restricted to 

the continuous pilot and Vmax provisions of §60.18. 

For situations or sites that don’t presently require a §60.18 compliant flare, flares may not operate

with a continuous 24/7 pilot or they may have “sonic” high velocity flare tips that exceed the 

Vmax of 400 ft/sec in §60.18. In either case, if properly designed, these flares can meet or 

exceed the control efficiencies of a §60.18 compliant flare. With new NSPS rules that increase 

the scope of regulated facilities, the default reference to §60.18 for flare design will be 

impractical and detrimental to many oil and gas sites. Allowances need to be made for alternative 

flare designs.

Attached to this document is a short white paper from John Zink, a large, well known vendor for 

flare systems as well as the test study referenced in the Zink paper. The paper argues the value of 

allowing sonic flare designs for oil and gas applications where high BTU gas will be flared. 

Sonic flares have destruction efficiencies that exceed conventional flares and are used worldwide 

in the oil and gas industry. However, due to NSPS limitations from §60.18, efficient sonic flare 

designs are in limited use in the U. S. You will note that at the end of the Zink paper is a table of 

recent test results witnessed by the TCEQ in October, 2010 in which all but one of 8 tests 

achieved 100% destruction efficiency. The one lone test achieved a destruction efficiency of > 

99%.

Below is a discussion for making allowances for flares that do not have continuous pilots (24

hours a day/7 days a week). 

Flare Pilots

There are a number of operating scenarios where use of a continuous 24/7 pilot is not desirable, 

and is inefficient. In these cases, pilot fuel gas may be in limited supply or not available, or 

flaring events are so infrequent, that use of continuous pilot gas is wasteful and creates 

unnecessary emissions. Unnecessary wear also occurs to the flare tip when a pilot is needlessly 

lit continuously. Listed below are a few examples of flare uses where these conditions would 

apply:

Emergency Only/Planned MSS Flare: Flare is designed for control of emergency upsets only, 

planned MSS events only or both. No continuous process streams are routed to the flare. Use of 

flare is intermittent with long periods between flaring events that could be less than once per year. 

A separate conventional flare system may exist to handle process streams.
Low Pressure Backup Flare: Flare is designed for low pressure, low volume burning and may 

serve as a backup to a primary emissions control or recycling device such as a vapor recovery 

unit (VRU). Use is intermittent with potentially long periods of time in between uses (e.g., 

during periods of maintenance or downtime to the primary control or recycling system). 

Intermittent Low Pressure Process Control Flare: Flare is designed for controlling intermittent 

emission periods such as during truck loading when operating conditions warrant emissions

control of vapors. Truck loading is a manual operation, so emissions are generated manually, and 

flare is used only as needed when a truck pulls up to be loaded. This type of flare may have a 

dual use as a Low Pressure Backup Flare. 

Storage Tank Vapor Flare1: Another low pressure flare that burns storage tank vapors. Pilot gas 

may not be available due to insufficient produced gas volume associated with oil production and 

a gas delivery system is unavailable. Purchased gas may have to be used for ignition gas as a 

substitute for produced gas.

In cases where a 24/7 pilot is not used, it is recognized that a good pilot flame is necessary to 

ensure combustion efficiency during flaring events. Consequently, a good flare design will have 

a stream detection system tied to an auto ignition system so that the pilot lights as needed to 

combust the waste stream going to flare. When the waste stream stops, the pilot shuts off. In 

effect, the pilot is continuously lit, but only during the flare event itself.

In cases where pilot gas is not available, or use of a separate pilot gas stream is undesirable due to 

intermittent flaring events, low pressure flare designs exist where the flare stream itself operates 

as its own pilot so that a separate pilot fuel stream is unnecessary. As an example, below is a 

technical description from John Zink of how this type of flare might work. Other vendors should 

have equivalent designs.

Model EFF-ZFF Flaring System: The ZFF is a gas-assisted, pre-mix flare for smokeless 

burning of waste gas. The flare is highly efficient for the combustion of small waste gas 

flows; the ZFF is capable of combusting hydrocarbons, low BTU, and toxic gases. An 

additional feature of the ZFF is that the flare acts as its own pilot. The pre-mix feature 

allows the ZFF to be utilized in applications with very low available pressure. 

Purge Gas Reduction: The ZFF induces a vacuum in the knockout drum when initially 

being ignited. This reduces the need for venting purge gas continuously through the 

system, which makes the ZFF more economic during normal operations because gas will 

not be continuously vented to the atmosphere.

Purge Gas: During operations the ZFF will utilize 1000 scfh of pilot gas.

Ignition Gas: During ignition the ZFF will utilize 250 scfh of ignition gas.

Purge Gas Seal: Due to the aspirating mixer drawing a vacuum on the waste line it is not 

necessary to have a seal on the flaring system. This is ideal for installing a flare system 

on a VRU system; The VRU system generally operates at 3-6 ounces. 

Non-continuous Ignition/ Purge Gas Flare: The ZFF is not a conventional flare. The 

flare neither requires continuous purge gas or a seal mechanism to ensure that air does

not become entrained in the system. The lack of continuous purge gas or a seal 

mechanism is possible because of the pre-mix feature. Also, the ZFF does not have 

continuous ignition, this is possible because the flare acts as its own pilot.

ZFF Control Panel Logic: Once the vapor pressure reaches 5 ounces, and the control 

valve will send a signal to the control panel to ignite the ZFF. Then the panel will send a 

signal to the fuel gas control valves to allow pilot gas and ignition gas to the flare. The

igniter will continue sparking approximately every ten seconds until the thermocouple 
senses it is lit. Once the pilot is lit, the control panel will send a signal to close the 

ignition gas control valve. The flare will operate until the control valve senses that the 

system pressure is below 5 ounces. 

While the above describes the operation for a low pressure vapor flare application, the control 

panel logic described in the last paragraph can be applied to more conventional flare designs as 

well. Intermittent flare streams can be detected by sensors that trigger lighting of the pilot.

 

1 To avoid confusion, the flare described here refers to a conventional flare with a flare tip at the end of a 

vertical stack designed to promote efficient burning. Another type of combustion unit known within 

industry as a vapor combustor to control tank emissions is sometimes misnamed as an enclosed flare. 

This is not really a flare in the conventional sense. Vapor combustors generally consist of an

enclosure/stack, a burner array (typically a ring burner), a pilot (some have dual pilots), a backflash 

preventer, and a thermal well for temperature monitoring that is mostly tied into the automation system for 

data archiving and alarms when the combustor fails for any number of reasons. A fair number of these

units have a "hot point" element (a metal probe with a high heat holding capacity) which provides "re-light" 

for momentary flame outages. A much smaller number have UV fire detection and electronic re-light 

capabilities. These units are generally naturally aspirated with no air or gas assist. Many of these units

have been "stack tested" in the Jonah/Pinedale area of Wyoming and have DRE's north of 98-99%. 

Attachment 1 provides a diagram showing how combustor systems are typically designed.

This rulemaking needs to allow for the use of combustors without reference §60.18.
System Description:

1. Maximum flow conditions are detailed in adjacent text box. 400 BBL is sometimes seen on new 5 pad wells, but normal

production is less than 100 BBL/day.

2. All lines from the condensate tank to the combustor are 4” pipe.

3. The tank Enardo is set at 12-14 oz. The tank Thief Hatch is set at 16 oz.

4. The knock out tank prevents any liquid head in the underground line

5. The combustor is generally set with 300 feet of the tank.

6. Additional pressure drop – other than piping associated with the combustor system, there is an additional pressure drop at the 

combustor consisting of an orifice, burner and flash back arrestor, with the majority of the drop across the orifice. If excessive 

pressure is encountered on the orifice, the orifice size is increased to eliminate any venting of the Enadros.

Condensate Tank

Combustor

Double Walled 

Knock out Tank

Berm

Enardo vent set at 12-14 oz 

Pressure Drop Profile for Combustor System

Example Design

Thief Hatch set at 16 oz 
© 2010 by John Zink Company 1

 

Applicability of the 40CFR 60.18 Requirements for 

Upstream Oil & Gas Flares 

Kevin Leary 

Product Director – Flare Systems 

John Zink Company LLC 

November 14, 2010 
© 2010 by John Zink Company 2

I. Introduction 

The purpose of this paper is to examine the design and operation of flares used in the 

Upstream Oil & Gas Industry as related to compliance with 40CFR 60.18 and the 

destruction efficiency requirements of such flares. In particular we will examine the 

currently available documentation related to the 40 CFR 60.18 requirements for a 

maximum velocity (Vmax) limits for flares used in upstream oil & gas industries. 

II. Vmax Requirements for Upstream Oil & Gas Production Flares 

The minimum BTU values and Vmax requirements are the result of analysis of a series of 

flare efficiency tests that were sponsored by the EPA and Chemical Manufacturers 

Association and summarized in the following EPA publications: 

• Flare Efficiency Study, EPA-600/2-83-052, July 1983 

• Evaluation of the Efficiency of Industrial Flares: Test Results, EPA-600/2-84-

095, May 1984. 

• Evaluation of the Efficiency of Industrial Flares: Flare Head Design and Gas 

Composition, EPA-600/2-85-106, September 1986 

These studies measured the emissions from flares for the determination of destruction 

efficiency of primarily steam assisted, air assisted and nonassisted flares under various 

operating conditions. These tests utilized natural gas, propane / nitrogen and propylene / 

nitrogen gas mixtures of varying heating value, flaring rates and assist medium rates. 

The results of these studies were used to develop the minimum heating value and Vmax 

requirements in 40CFR 60.18. It was concluded that flares operated within these 

guidelines would produce minimum destruction efficiencies of greater than 98%. 

The testing that was performed in the studies referenced above was limited in its study of 

high velocity nonassisted and air assisted flares and high BTU content flares that are 

common in the Upstream O&G industry. This was due primarily to the limits of the 

testing methods available at that time. High velocity, high BTU content flares of any 

appreciable size produce tall flames. It is unfeasible to collect the combustion products 

from such tall flames with the test methods that were used in these studies. 

A substantial amount of data for low BTU flares (200 – 1000 BTU/SCF) gas streams was 

collected in these tests for relatively low velocity flares. The Vmax requirements of 

40CFR 60.18 are fairly substantiated for this region of gases. The 400 ft/sec limitation 

for steam assisted and unassisted flares greater than 1000 BTU/SCF is likely based of the 

lack of data for high BTU / high velocity flares. The limit of available data from these 

tests does not allow extrapolation into this region. Similarly the Vmax limitation for air 

assisted flares (much less than 400 ft/sec) is due to the lack of test data in this operating 

region. 
© 2010 by John Zink Company 3

The data presented in several of the studies noted above suggests that if flares are 

operated safely above the minimum heating value for stability, high combustion 

efficiencies are achieved. Although years of study of flares indicates that stable flare 

flames from high BTU gases can be observed at exit velocities well above Vmax, there 

is no published data to confirm this for air assisted, steam assisted or nonassisted flares. 

There is reluctance in the regulatory community to extrapolate beyond the available test 

data. Although many flare designers are producing nonassisted and air assisted flares that 

are designed to maintain stable flare flames above Vmax on high BTU gases, this is 

based on visual observation of flame properties. If the regulatory community were to 

accept visual observation alone as the determination of flame stability, these designs 

could be proven through a series of testing. Currently approved methods of 

measurements of flare efficiency are not practical to apply to these designs 

III. Pressure Assisted Flares in Upstream Oil & Gas Industry 

As noted earlier, pressure assisted flares are a separate class of flares that are used 

extensively in the O&G Production industry. Hundreds (perhaps thousands) of pressure 

assisted flares are currently in use in O&G production facilities around the world. This 

class of flare is also used extensively in staged ground flare configurations in many 

refineries and petrochemical plants. Currently 40CFR 60.18 does not address use of this 

class of flare to meet the requirements of this regulation. Pressure assisted flares are the 

optimum choice of design for high pressure flares in the O&G industry when low 

radiation, smokeless flaring is desired / required. Pressure assisted flares have the unique 

ability to provide smokeless flaring without the need for operator attention to adjust the 

air rates or steam rates that are required with air assisted and steam assisted flares. 

If the industry were forced to design these flares to the current requirements of 40CFR 

60.18 it would be not be feasible. Offshore flares, for instance, would require longer 

flare booms or taller flare towers that could not practically be retrofitted on existing 

structures. Retrofitting existing onshore high pressure flares to air assisted flares would 

likewise be impractical. 

There is however currently available certified test data on the efficiency of some types of 

pressure assisted flares. During several of the tests of the 1983-1986 flare testing 

referenced above there was flare efficiency testing conducted on several pressure assisted 

flare head designs. This testing concluded that these pressure assisted flares can 

effectively provide high combustion efficiencies when flaring high BTU gases at 

velocities above Vmax. 

There are many different configurations of pressure assisted flare head designs currently 

used in the industry. The geometry of these flare heads and methods of flame 

stabilization vary widely in these designs. Consequently, there is reluctance in the 

regulatory community to certify pressure assisted flares as a whole class. Certified flare 
© 2010 by John Zink Company 4

efficiency testing has, in several cases, been required to permit use of these flares to meet 

the minimum destruction efficiency requirements that 40CFR 60.18 specifies. 

Many pressure assisted designs can produce short compact flames at high exit velocities. 

These designs therefore lend themselves to use of similar test protocols used in the EPA 

flare efficiency studies from the 1980’s. In addition to the pressure assisted flare 

efficiency data presented in these studies, there is additional recent certified test data that 

was collected on specific pressure assisted flare head designs. One such test is 

summarized in the paper Pressure-Assisted Flare Emissions Testing presented at the 

American-Japanese Flame Research Committees International Symposium, October 

2007. This report concludes that a well designed and properly operated pressure assisted 

flare burner will achieve greater than 99% DRE under operating conditions including 

sonic velocity (>> Vmax) with high BTU gas streams. This testing was performed on 

multiport high pressure flare nozzles commonly used in multi-point flare systems. 

In order to expand the available certified test data on pressure assisted flares, John Zink 

recently conducted testing on another pressure assisted flare burner that is commonly 

used in Upstream O&G production flares. Variable slot Coanda based flares are 

currently used extensively in O&G production facilities. These flares are proven to 

provide very stable smokeless flaring in these applications, however this class of flare 

had never been tested for combustion efficiency. 

The Texas Commission on Environmental Quality (TCEQ) recently commissioned the 

University of Texas to perform additional certified testing on air assisted and steam 

assisted flares. The results of this testing are scheduled to be reported in 2011. During 

this testing, which was performed at John Zink’s Tulsa Flare Research Center, John Zink 

utilized the same certified test protocols and third party data collection techniques to test 

a variable slot Coanda based pressure assisted flare head under a wide variable of 

operating conditions. This pressure assisted head was tested on variant flare gas 

compositions including 100% natural gas and 100% propane. Flow rates from very low 

purge rates through sonic flow conditions (approximately 1400 ft/sec for natural gas), 

were also tested. 

The results of this series of tests on the pressure assisted flare design are summarized in 

Table 1 (see appendix). These tests show that this type of pressure assisted flare head 

design can effectively provide >99% destruction efficiency over the full range of 

operating conditions from low flow rates through sonic velocity over a wide range of gas 

compositions. 

We believe that pressure assisted flare heads that have been designed and tested to meet 

the DRE targets established by 40CFR 60.18 should be excluded from the Vmax 

requirements of this regulation. This type of flare is already used extensively in the 

Upstream O&G industry and could easily be retrofitted on many existing air assisted and 

nonassisted flares in these applications. 
© 2010 by John Zink Company 5

IV. References 

1. McDaniel, Flare Efficiency Study, EPA-600/2-83-052, July 1983 

2. Pohl, J.H., Payne, R., and Lee, J., Evaluation of the Efficiency of Industrial 

Flares: Test Results, EPA-600/2-84-095, May 1984. 

3. Pohl, J.H. and Soelberg, N.R. Evaluation of the Efficiency of Industrial Flares: 

Flare Head Design and Gas Composition, EPA-600/2-85-106, September 1986 

4. Varner, V., Fox, S., Schwartz, R., Wozniak, R., Pressure-Assisted Flare 

Emissions Testing presented at the American-Japanese Flame Research 

Committees International Symposium, October 2007. 
© 2010 by John Zink Company 6

V. Appendix 












Thief Hatch Work Practices 

Research indicates there are no API or ASTM standards that address specific inspection 

and maintenance practices for thief hatches. However, API RP 12R may come the 

closest to being a technical reference for thief hatch work and maintenance practices.

From what has been found in engineering and vendor literature, four general work 

practices for thief hatches on tanks controlled for emissions can be listed as the 

following:

Operator needs to select the appropriate gasket material based on fluid composition

of the storage tank and weather conditions. 

Inspect in a regularly scheduled preventive maintenance (PM) program. Annual 

inspection of thief hatch seal is the most common suggestion although some sites 

inspect on a more or less frequent basis. When applicable, inspection should occur 

in conjunction with thieving or gauging tank to minimize additional periods of an open 

hatch. 

Replace gasket within 30 days if inspection shows evidence of deterioration or

cracking. In the interim, grease the gasket if deterioration or leakage is found to 

improve seal while waiting on replacement gasket.

Keep thief hatch in good working order. Verify thief hatch seal is capable of holding 

pressure in excess of the pressure/vacuum relief device (PRD). The thief hatch 

spring or weight relief set point should be greater than the set point on the PRD, and 

both the thief hatch and PRD set points need to be greater than the back pressure 

set point of the control system.

Standard practice is to implement preventative maintenance during routine inspections 

including cleaning surfaces and seals, greasing the gasket to improve the seal, and 

repairing or replacing springs. If a leaking gasket is discovered during inspection, the 

temporary initial fix is to grease the gasket to improve the seal. If unable to verify a good 

seal, then replace the gasket within 30 days unless a custom gasket must be fabricated 

for replacement (e.g. older storage tanks). 

Gasket selection

Elastomers nitrile and neoprene appear to be the “standard” gasket materials for oil 

storage, with Fluoroelastomers for H2S service. Thermoplastic seals are not commonly 

used, but can be. There are various grades of seals within each material category for 

selection in the proper fluid composition and temperature environment the gasket will be 

used.

Any rulemaking should not mandate specific gasket materials but rather specify gasket 

material appropriate for type of chemical service and operating conditions including 

weather. 

References

www.jayco.org

www.enardo.com

API RP 12R