Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW

Washington, DC 

20005-4070 USA

Telephone: 202-682-8319

Fax: 202-682-8031

Email: ToddM@api.org

www.api.org

February 23, 2011

Mr. Bruce Moore

U.S. Environmental Protection Agency

Mail Code: E143-03

Research Triangle Park, NC 27711

via e-mail

Ref.: Review of Federal Air Regulations for the Oil and Natural Gas Sector

40 CFR Part 60, Subparts KKK and LLL

40 CFR Part 63, Subparts HH and HHH

The American Petroleum Institute (API) is a national trade association with over 400 member companies 

that are involved with all aspects of the oil and natural gas industry. We are writing to provide 

commentary on issues pertaining to the pending review by the U.S. Environmental Protection Agency 

(EPA) of federal air regulations for the Oil and Natural Gas Sector, specifically:

40 CFR Part 60 Subpart KKK, Standards of Performance for Equipment Leaks of VOC From 

Onshore Natural Gas Processing Plants,

40 CFR Part 60 Subpart LLL, Standards of Performance for Onshore Natural Gas Processing: 

SO2 Emissions,

40 CFR Part 63 Subpart HH, National Emission Standards for Hazardous Air Pollutants From 

Oil and Natural Gas Production Facilities, and

40 CFR Part 63 Subpart HHH, National Emission Standards for Hazardous Air Pollutants 

From Natural Gas Transmission and Storage Facilities.

The attached comments are provided to assist EPA in understanding issues that are critical to the 

operations of oil and natural gas facilities that would be potentially affected by the pending rulemaking.

We appreciate your consideration of our comments. If you have any questions, please contact me at 202-

682-8319 or toddm@api.org.

Sincerely, 

/s/ Matthew Todd

Matthew Todd
1

Contents

1. WORKER SAFETY MUST BE CONSIDERED ................................................................... 2

2. THE FLOORS DO NOT NEED TO BE FIXED .................................................................... 2

2.1. Adjustments to Floors are Limited by Statute.................................................................. 2

2.2. One ton/year Threshold for Benzene is an Effective Standard ........................................ 3

3. GREEN COMPLETIONS HAVE LIMITED FEASIBILITY ................................................ 3

3.1. Background on Well Completion, Flow-Back, and Clean-up ......................................... 3

3.2. Conditions Necessary for Green Completions................................................................. 4

4. THE EFFECTIVE DATE MUST BE REASONABLE.......................................................... 6

4.1. Allow One Year for Equipment Supplies to Meet Demand............................................. 6

4.2. NSPS Compliance Should be Triggered by the Final Rule, Not the Proposed Rule ....... 7

5. A WELL WORKOVER DOES NOT CONSTITUTE A NSPS MODIFICATION............... 7

6. THIEF HATCH REQUIREMENTS APPLY ONLY TO CONTROLLED TANKS ............. 8

7. FLARE REQUIREMENTS NEED TO BE CLARIFIED....................................................... 8

7.1. Flare Continuous Pilots and Vmax Limits....................................................................... 8

7.2. Enclosed Combustors Need To Be Distinguished From Flares....................................... 9

7.3. Provisions are Needed for Approval of New Control Technologies ............................... 9

8. NSPS RULES SHOULD RETAIN THE VOC 10% EXEMPTION .................................... 10

9. INCREASED REGULATION WILL DECREASE OIL AND GAS PRODUCTION ........ 10

10. ALLOW FLEXIBILITY FOR WELL-BORE DELIQUIFICATION CONTROLS......... 11

10.1. Background on Well-bore Deliquification (liquids unloading).................................. 12

10.2. Background on Plunger Lift ....................................................................................... 15

10.3. Industry Research on Well-Bore Deliquification ....................................................... 16
2

1. WORKER SAFETY MUST BE CONSIDERED

EPA needs to consider worker safety in this rulemaking. These requirements will mandate 

control technologies and practices be applied to equipment and/or activities that have never 

before been regulated and therefore the risk of performing this work has not been fully 

evaluated. EPA needs to avoid instances where the requirements contained in this rule expose 

workers unnecessarily to dangers including but not limited to fire and explosion, toxic 

atmospheres, falling, equipment rupture, and rotating equipment injury. 

2. THE FLOORS DO NOT NEED TO BE FIXED

EPA has indicated that it intends to ―fix the floors‖ for some units in the Subpart HH 

standards and, in particular, the 1 ton/year (or 0.9 megagram per year) of benzene exemption 

threshold. When EPA says ―floor‖ we assume that means the Clean Air Act requirement 

where the MACT control level must set at least at the average of the best 12% performing 

sources in that source category. However, these standards have been in effect for some years

and never challenged. The values do not need to be ―fixed‖. Indeed, as explained below, 

EPA’s authority under the current review is prescribed by the terms of § 112(d)(6).

2.1. Adjustments to Floors are Limited by Statute

Once EPA establishes a MACT standard for a particular source category, the Agency 

has the authority (and the obligation) under § 112(d)(6) to ―review and revise as 

necessary (taking into account developments in practices, processes, and control 

technologies), emissions standards promulgated under this section no less often than 

every 8 years.‖ In other words, EPA does not have unfettered discretion to revisit a 

prior MACT determination once that determination has been issued. Rather, EPA 

may revise a prior determination only ―as necessary‖ according to explicit statutory 

criteria.

In 2006, NRDC filed a multi-faceted challenge to EPA’s final residual risk and § 

112(d)(6) determinations for the Hazardous Organic NESHAP (―HON‖) in the D.C. 

Circuit. Among numerous other claims, NRDC argued that EPA is required to make 

a new MACT determination each time an existing standard is reviewed pursuant to § 

112(d)(6). The court quickly dispensed with this argument, concluding that ―the 

words ―review and revise as necessary‖ [cannot] be construed reasonably as imposing 

any such obligation.‖ NRDC v. EPA, 529 F.3d 1077, 1083 (D.C. Cir. 2008).

More specifically, NRDC also asserted that EPA was obligated under § 112(d)(6) to 

re-determine MACT for certain source types because cost had been considered in 
3

determining the MACT ―floor‖ in the original HON rule. The D.C. Circuit disagreed, 

reasoning that ―EPA squarely found that there were no ―significant developments in 

practices, processes and control technologies‖ and ―[s]ince that is the core 

requirement of subsection 112(d)(6) and EPA’s finding satisfies that requirement, it is 

irrelevant whether EPA considered costs in arriving at the initial MACT floor and 

reaffirming that standard in the residual risk rulemaking.‖ Id. at 1084.

In short, this holding clearly establishes EPA is not required to redetermine MACT 

under § 112(d)(6) and that EPA cannot be forced pursuant to § 112(d)(6) to revise an 

existing MACT determination in order to ―correct‖ an alleged deficiency in that 

determination based on subsequent judicial decisions.

2.2. One ton/year Threshold for Benzene is an Effective Standard

Lastly, the 1 ton/year (or 0.9 megagram per year) of benzene exemption threshold 

should be considered an ―emission standard.‖ An exemption tied to an emission has 

the advantage of encouraging the over-control of affected sources (validated by State 

NSR permits so that the PTE limitation is federally enforceable) to avoid the 

complexities and continuous monitoring burden of NESHAP regulations. This 

practice was recognized in the January 3, 2007 proposed revision of the Once-InAlways-In policy. Thus, even at major sources, the use of emission limits to exempt 

affected sources from regulation under NESHAP is beneficial to the environment.

3. GREEN COMPLETIONS HAVE LIMITED FEASIBILITY

API wishes to reiterate the conditions and criteria that enable ―green completions‖ to be used 

when completing or re-completing an oil and/or gas well. As context, we are including a 

short description of well flow-back and clean-up.

3.1. Background on Well Completion, Flow-Back, and Clean-up

As EPA is aware, most oil and gas development in the onshore US is in nontraditional reservoirs, such as shales, coal-beds, and tight sands, and the majority of 

wells require fracture stimulation to enable production. Hydraulic fracturing is the 

most common stimulation technique and requires pumping a fluid (such as gelled 

water or inert gas) carrying a proppent (such as sand) into the well-bore at a high flow 

rate and pressure to enhance fractures in the reservoir rock which are then propped 

open by the proppent material and provide a flow path for oil and gas to flow to the 

low pressure zone created by a well-bore. 

After stimulation, a well must be ―flowed back‖ at a rate sufficient to lift fluids and 

solids in the well-bore to the surface. Wells must be adequately cleaned-up to enable 
4

production and avoid long term reservoir damage caused by foreign fluids and 

accumulated solids which stay in the formation. The ability of a well to flow back at 

a pressure and rate sufficient to lift the fluids and adequately clean-up the formation is 

dictated by the reservoir pressure/energy, the reservoir flow potential, the depth of the 

well, and the physical characteristics of the fracture fluids. 

A common well clean-up technique is a clean-out where a high pressure gas is 

injected into the wellbore to jet debris from the wellbore and transport the solids to 

surface along with the gas. This technique is very common and works best with 

homogenous gases like air, CO2, nitrogen, or methane. Gases with a wide range of 

components (like many natural gases) are less effective than homogenous gases due 

to condensation effects.

The flow rate up a well bore is dependent on the reservoir pressure being higher than 

the sum of flowing friction losses up the well-bore, the weight of any vertical column 

of fluid in the well bore, surface equipment and piping pressure losses, and any 

collection system/flow-line back-pressure. When green completions are used, this 

resistance to flow is much higher than the resistance observed in traditional 

completions (that flow against atmospheric pressure rather than collection 

system/flow-line pressure), which can reduce the flow rate to values inadequate to 

properly lift liquids and solids from the wellbore.

In the initial stages of a completion flow-back most of the flow is comprised of 

introduced fluids and proppent with little formation fluids or gas. As a well cleansup, more formation fluid and gas enters the well-bore and the fluid column in the 

well-bore becomes ―lighter‖ with less back-pressure on the formation. 

3.2. Conditions Necessary for Green Completions

Green completions are the use of surface equipment, often purpose-designed and operated, to 

separate the introduced fluids, proppent, hydrocarbon liquids, and gas – with the gas routed to 

a collection line for sales and the hydrocarbon liquids routed to on-site storage for sales. To 

enable the use of green completion techniques a number of conditions/criteria must be met:

3.2.1. Availability of specialized equipment and personnel. Adequate equipment and qualified 

personnel must be in-place or available to allow the safe implementation of green 

completion techniques. Often, this will require that sufficient ―purpose designed and 

constructed‖ surface equipment be available. Equipment and procedures for green 

completions must be able to safely handle the erosive forces of high rate flow with 

abrasive proppent without cutting through the surface piping and/or equipment.

3.2.2. Not feasible with air, CO2, or nitrogen. The mixture of gases produced from the 

wellbore must be such that they can meet gathering-system quality requirements with 

simple mechanical separation equipment. When air, CO2, or nitrogen is used in well 

operations, these gases would require extensive chemical and/or thermodynamic 
5

processes to extract natural gas from the gas stream. This equipment is inappropriate and 

unsafe for wellsite use, and any of the processes that cannot be done without using these 

gases must be excluded from any green-completion requirement.

Meeting the gas composition specifications to enable sales is problematic where an inert 

gas or air is used to ―jet‖ a well for clean-up, where an inert gas, such as CO2 or N2 is 

used to ―energize‖ a hydraulic fracture, and where an inert gas, such as CO2, is used as 

the stimulation fluid. In all of these cases, flow-back gas cannot be routed to a collection 

system for sales until it meets the system operator’s composition specifications and green 

completions is not an option.

3.2.3. Not viable for low pressure reservoirs. The reservoir must have sufficient flow potential 

and energy to lift fluids and adequately clean-up against the back pressure imposed by 

flowing to a gas collection line for sales. If the reservoir pressure/energy is too low to lift 

fluids and overcome the collection line back-pressure the well will not flow to a pipeline. 

Often in the early stages of a well clean-up, the flow-back is predominantly fracture fluid 

and the well will not be able to flow to a pipeline until it has partially cleaned-up. For 

some low pressure and depleted reservoirs green completions is not an available option.

3.2.4. Not viable unless collection infrastructure is in place. There must be a collection line in 

place to receive the flow-back gas. This is only common in in-fill situations where the 

risk of a dry hole is low and gas collection infrastructure is close. Exploration wells, 

flank extension wells, and wells having a high risk of being dry typically will not have a 

flow line in place to receive the gas. 

If all of these conditions are met, then green completions may be a valid practice for a 

particular well. If any of these conditions cannot be overcome, then green 

completions cannot be used on a particular well. 

API is aware that the addition of compression between the outlet of the surface green 

completion separation equipment and the gas pipeline has been tried in the past to 

lower back pressure on a well and broaden the pressure range where green 

completions can be accomplished. In fact, several of our member companies were 

the operators that piloted these trials – some for multiple years. Due to the unstable 

flow-back rates and pressures during a well clean-up coupled with compressor’s 

sensitivity to suction pressure and rate changes these pilots have not been successful 

yet. API does not consider the addition of compression to a green completion 

operation to be proven technology and EPA should not consider it as proven or 

available technology. 

In crafting a regulatory program addressing well completions and flow-back, EPA 

must consider these physical and operational facts and provide the necessary 

regulatory clarity/ certainty and flexibility to enable companies to continue 

developing US oil and gas resources while complying with any regulation 

promulgated. 
6

4. THE EFFECTIVE DATE MUST BE REASONABLE

4.1. Allow One Year for Equipment Supplies to Meet Demand

An appropriate effective date will lessen the production and cost impacts caused by 

competition for limited supplies of control equipment. API anticipates that 

compliance with this proposal will place heavy demands on limited supplies of 

control equipment and this will have significant negative consequences on production 

and drive up the cost of compliance. The EPA must avoid mandating control 

requirements before equipment supplies can meet demand. 

Emission control equipment is in limited supply because many of the proposal’s 

performance requirements will impact source types that have never before been 

regulated. It will take time for the supply of this equipment to match demand since 

the equipment is specialized and only available from a limited number of suppliers. If 

the EPA does not establish an appropriate effective date for controls, competition for 

limited supplies of control equipment will drive up cost and will negatively impact 

production. 

As an example, if the proposal contained a requirement for all of industry to begin 

―green completing‖ their wells where practical (see ―Green Completions‖ Section) at 

a time when specialized flowback equipment is in short supply, the result would be a 

bottleneck, affecting the industry’s ability to bring on new production. The economic 

consequences of this will be significant. Further, in some cases, fluid-caused damage 

to the reservoir will occur if a company was delayed in flowing back wells because 

equipment wasn’t available. This would result in permanent impacts to production 

and reserves.

Similarly, when demand for vent and fugitive emission control equipment outpaces 

supply, a producer’s ability to begin operation of new production facilities will be 

impacted. 

To avoid the negative consequences stemming from competition for control 

equipment, EPA should consider making control requirements effective at least one 

year after rule promulgation for equipment installed after the proposal date. Relocated 

equipment should not be considered a new source subject to the rule.

Emission control requirements should also become effective at least one year after 

rule promulgation for activities such as well flowback or well venting that aren’t 

directly related to the installation of production equipment.

It is anticipated that equipment suppliers will need at least one year to ramp up 

production to meet demand.
7

4.2. NSPS Compliance Should be Triggered by the Final Rule, Not the 

Proposed Rule

Under the NSPS program, typically, any affected unit constructed, modified or 

reconstructed after the rule proposal date must comply with the NSPS rule. This 

approach will not work for many oil and gas operations because of the short-term or 

temporary nature of the operation. For example, if the upcoming O&G NSPS rule 

includes requirements to control well completion operations, it is unreasonable to 

require all well-completion jobs carried out between rule proposal date and the final 

rule date to adopt the control measures in the proposed rule. For the completion jobs 

performed shortly after the rule is proposed, it is most likely they will be completed 

or terminated before the final rule takes effect. In addition, the final rule may contain 

a vastly different requirement than the proposal. To expect and require such well 

completion projects to comply with the rule while the rule takes effect after the 

project is concluded is extremely unreasonable. Therefore, EPA should use the final 

rule effective date as the rule applicability threshold date. 

5. A WELL WORKOVER DOES NOT CONSTITUTE A NSPS 

MODIFICATION

Because the O&G industry’s operations are driven by the geology of the reservoirs that they 

are harvesting, impacts of NSPS and NESHAP General Provisions and definitions can have 

unintended consequences. The common interpretation of ―modification‖ may be an example 

of this. EPA has already recognized at least part of this issue by stating that a well workover 

does not constitute a modification of a facility, even though it will increase the production 

(O&G flow) of the well. API sees this as a valid approach, since the purpose of a workover 

is to regain at least some of the original production flow of the well that has been lost to 

reservoir depletion. 

API would like to assure that this approach is extended to other equipment both at the facility

and downstream in the gathering system. The actual emissions of equipment (tank, 

dehydrator, compressor, etc.) decreases as the production flow depletes and correspondingly

increases when the production rises due to a workover. API believes that a modification as 

defined in the NSPS is not triggered when the flow from the well and in the equipment 

downstream of the well increases as the result of well workover. API also believes that a 

modification as defined in NSPS is not triggered for equipment in a gathering system when 

there is an increase of flow from the workover of a well, or even the addition of new wells. 

Gathering system equipment should be subject to the rule based on the date of construction 

or the definition of reconstruction. 
8

6. THIEF HATCH REQUIREMENTS APPLY ONLY TO 

CONTROLLED TANKS

In a short one page brief submitted to EPA in early December, a strawman was provided for 

developing work practice requirements to maintain thief hatches on storage tanks being 

controlled for emissions. Four key items were presented for consideration. These were: 

gasket selection, inspection schedule, replacement/repair of gasket material, and the proper 

pressure seal of the hatch in relation to the tank PRD or Enardo valve. The key limitation in 

recommending these practices was to apply them at tanks being controlled for emissions 

only. Maintaining a good seal at the thief hatch improves efficiency of the control device 

connected to the tank vent 

Applying these practices to uncontrolled tanks will have no impact on reducing emissions 

and will only increase maintenance costs. If a tank’s vent is uncontrolled, no control 

efficiency is gained by mandating work practices for the thief hatch. Depending on the 

condition of the hatch, the full stream of uncontrolled emissions will either exit through the 

tank vent or partial emissions may exit through the thief hatch instead of the vent. In either 

case, all tank emissions will be vented to atmosphere. No vapors are being captured, 

condensed, or burned to limit emissions.

7. FLARE REQUIREMENTS NEED TO BE CLARIFIED

7.1. Flare Continuous Pilots and Vmax Limits

Among the several papers provided to EPA in December was a short white paper 

discussing the various types of flares and their use in the oil and gas industry. 

Included as an attachment, was a study by John Zink for the TCEQ that demonstrates 

the efficiency of high velocity sonic flares. The key issues pointed out in the paper 

were the flare design limitations of 40 CFR §60.18. In particular the requirements of 

most concern are continuous pilots and Maximum velocity (Vmax). Our request is 

that continuous pilot requirements be clarified to mean ―continuously lit pilot only 

during flaring events‖. Additionally, we ask that upper Vmax limits be removed so 

that more efficient sonic flares can be used for high BTU waste streams.

Changes to NSPS rules that widen the scope of applicability to oil and gas emission 

sources may also increase the applicability of §60.18 to flares used in the industry. 

While there is a rulemaking team established to modify flare requirements as a part of 

the uniform standard effort, the schedule for the oil and gas NSPS rules precedes any 

new flare standards. Consequently, it’s our understanding that any changes to flaring 

requirements will need to be included in the oil and gas rulemaking directly.
9

7.2. Enclosed Combustors Need To Be Distinguished From Flares

API would also like to emphasize again that the ―enclosed combustor‖ type of 

thermal device should be classified as a ―burner‖, not a ―flare‖ and should not be

subject to the requirements of §60.18. These devices are completely different from 

flares in their design and operation which renders the requirements of §60.18 

inappropriate. EPA has recognized this in several past determinations where they 

have determined that enclosed flame combustors are not flares even if they are termed 

(enclosed) flares by the manufacturer. 

These enclosed combustor types of devices are increasingly being deployed for 

emission control of streams that would historically have been burned in flares or not 

controlled. We would also like to emphasize that the type of units typically deployed 

in the E&P industry are quite different than those which might be deployed at 

industrial facilities. Specifically, the combustors typically deployed in the E&P 

segment do not have electricity available and hence depend on natural draft rather 

than forced air (blower) for combustion, tend to be less complex, and tend to have 

limited instrumentation. Although simpler in design and dependent on natural draft 

these units have been shown able to consistently deliver destruction efficiencies in the 

98 – 99%+ range in Wyoming areas.

Given the design of these enclosed combustors and the typical materials (fuels) that 

are burned, API also believes they should be considered as burners rather than 

thermal oxidation devices. 

EPA should not create disincentives to use a broader deployment of these types of 

devices by requiring unnecessary or infeasible testing and/or monitoring. 

7.3. Provisions are Needed for Approval of New Control Technologies

During the last teleconference with the Agency several weeks ago, there was a 

favorable discussion about inserting provisions in the rulemaking that (with 

appropriate approvals) would allow for the experimental use and implementation of 

new control technologies. This would be a welcome provision in the rules. However, 

the ability to implement new technologies can sometimes be hampered by the 

approval process and the time it may take to get necessary approvals. Though 

extensively used worldwide in industry, as flaring rules stand right now, use of a 

sonic flare would have to get special approval as a new technology (if indeed a new 

technology provision is put into the new NSPS rule) before implementation. With 

backing from the Zink paper, it would seem more efficient to include use of sonic 

flares directly into the rule. This would eliminate the burden of getting special 

approvals for its use.
10

8. NSPS RULES SHOULD RETAIN THE VOC 10% EXEMPTION

API believes that the applicability criteria for the entire proposed Oil & Gas New Source 

Performance Standards (NSPS) should be the same cutoff (10 wt% VOC) used in the current 

NSPS Subpart KKK (which references Subpart VV,40 CFR 60.481). That subpart (§60.632) 

states that ―For a piece of equipment to be considered not in VOC service, it must be 

determined that the VOC content can be reasonably expected never to exceed 10.0 percent by 

weight‖. In its analysis EPA determined that it is not cost effective to include equipment that 

handles liquid or gas with less than 10 wt% VOC.

Since the primary objective of the proposed O&G NSPS regulation is to reduce VOC 

emissions, the sources to be regulated must be capable of emitting VOC. Therefore, API 

requests that the 10 wt% VOC criteria apply to all of the O&G source types that are to be 

regulated by this proposed rule, not just the fugitive sources (i.e., those suitable for a Leak 

Detection and Repair program).

9. INCREASED REGULATION MAY DECREASE OIL AND GAS

PRODUCTION

In prior discussions and presentations EPA has voiced the opinion that NSPS regulation of 

the E&P industry will not result in less production or reserves (natural gas supply). API 

believes this position is erroneous and offers the following discussion to underpin our belief. 

US onshore oil and gas production is a mature industry with a very large proportion of low 

rate ―marginal‖ producing wells and an increasing focus hydrocarbon deposits that are more 

difficult to find and extract in developing resource plays. As an indicator, the average 

production per new well has been declining for several years. 

The US Energy Information Administration’s (EIA) listing of oil and gas wells by production 

rate bracket illustrates the preponderance of low rate wells in the US E&P industry. Of 

363,459 producing US oil wells EIA data shows some 286,109 (78.7%) produce at a rate of 

10 barrel-of-oil-equivalent (BOE) or less per day. For gas wells, EIA’s data shows that of 

461,388 producing gas wells some 297,371 (64.5%) produce at a rate of 10 barrel-of-oilequivalent (BOE) or less per day. With these low production rates, these wells are 

economically marginal and very sensitive to additional costs. Costs imposed by regulation 

may make the ―tail‖ end of these wells non-economic and result in their shut-in and 

abandonment. Some proportion of this segment of the well portfolio may be abandoned 

which will reduce oil and natural gas production, royalty and tax income to mineral owners 

and government entities, and overall reserves. The extent of this reduction will be dependent 

on the scale of costs imposed by regulation. 
11

The shift towards non-traditional resource plays for domestic production is illustrated by the 

focus on and increasing importance of natural gas from shale, coal beds, and tight sands. Not 

many years ago, these reservoir types were regarded as uneconomic because the technology 

to produce them didn’t exist. At the gas prices of 2006-2007, the Shale Gas plays became 

economic and the industry began actively acquiring leasehold acreage and began drilling. 

With the price collapse in 2008, activity in the shale was significantly curtailed back to only 

those projects that were contractually mandatory. With the cost of drilling and completion 

under today’s regulations, the threshold price is a sustained market price well above today’s 

prices (the exact price level required to sustain production is a matter of much conjecture). 

Adding significant costs to reach new environmental goals will further delay the 

development of this resource, and may increase imports of natural gas. The extent of 

reduction in oil and gas production, reserves, royalties, and tax payments will depend on the 

scale of the costs imposed by regulation. 

These impacts can disproportionally impact small oil and gas companies/operators who tend 

to have a portfolio of low rate marginal wells that are not economic for larger companies. 

There are 10,439 operators in the Oil & Gas industry that produced a combined 22 MMCF/d 

from 233,607 wells in 2008. This average of 0.1 MCF/day/well is very sensitive to costs and 

many of these operators cannot tolerate any additional costs and remain solvent. With an 

average of 22 wells (233,607 wells/10,439 operators) per operator it is obvious that most of 

these low rate wells are operated by small operators and regulatory imposed costs would 

disproportionally impact these small businesses.

10. ALLOW FLEXIBILITY FOR WELL-BORE 

DELIQUIFICATION CONTROLS

API has significant concerns with EPA’s apparent focus in the December, 2009, CAAAC 

Multi-pollutant Sector Approach presentation on plunger-lift as a single technology-choice 

for addressing the challenge of reduced well venting. Deliquification of gas wells is a highly 

complex and technical subject with many approaches and technologies in use and venting of 

wells is one technique used. A very large amount of industry focus and attention is applied

to gas-well deliquification with innovation and research continually underway. It is not 

appropriate for EPA to specify a particular technology or approach to the highly complex 

problem of well-bore deliquification through regulation. API does recognize that wellventing can be a significant source of hydrocarbon pollutant emissions and that there are 

technologies and techniques in use and available to sharply reduce, but not eliminate, venting 

of wells to assist in deliquification. In fact, many of API’s member companies have been on 

the forefront of developing and applying innovative solutions for well-bore liquids unloading 

with no venting or reduced venting. 
12

Specifying a single technology or approach could negatively impact the continued ability to 

produce low rate gas wells, stifle innovation, shorten the economic life of the majority of US 

gas wells, and disproportionally impact many small operators who tend to have portfolios of 

low rate ―marginal‖ wells. Specifying one approach to deliquification will limit the 

economic life of gas wells and could cause companies to rethink their investment in US gas 

development. This may negatively impact the clean-fuel natural gas supply and the country’s 

energy security. Operators must have the flexibility to choose the most appropriate and cost 

effective approach for each individual well/reservoir/age/production combination and the 

regulatory certainty to underpin continued investment. 

API suggests that EPA take a different approach to reducing venting by providing regulatory 

dis-incentives for continued venting rather than trying to enter the discipline of production 

engineering and well deliquification. Additionally, API suggests that EPA fully understand 

the issue of well liquid-loading and venting control prior to crafting regulations addressing it. 

API would like to offer assistance, through organizing meetings, workshops, and/or training 

sessions with well deliquification experts to help EPA gain the necessary understanding to 

craft a workable and effective regulation. 

10.1. Background on Well-bore Deliquification (liquids unloading)

It is important to fully understand the fundamental nature of well bore liquid loading 

or the range of technologies in use to address it – in particular plunger lift and its 

appropriate use, limitations, and efficacy. API offers the following discussion of 

well venting and well-bore deliquification to assist EPA in crafting workable, 

appropriate, and effective requirements for reducing well venting for well-bore 

deliquification. Additionally, we highly recommend the June, 2009 American Oil 

and Gas Report article Artificial Lift Advances Address Challenges, Trends in Gas 

Well Deliquification and the February 27, 2006 Oil & Gas Journal article LowPressure Gas Well Deliquification Requires Different Approaches. Both articles 

provide a robust discussion of this topic.

Well deliquification is a fundamental challenge for continued production from the 

majority of US gas wells and the proportion is expected to grow with new growth 

concentrated in non-traditional gas reservoirs such as shales, coal-beds, and tight-gas

sands which are all very susceptible to liquid loading. Liquid loading of well-bores

occurs when the gas production-rate up the well-bore is not sufficient to carry liquids 

out of the well-bore. When a liquid column builds up in the well-bore, the weight of 

the column puts back-pressure on the producing formation and the production rate 

declines to the point where the well can quit flowing. According to the Energy 

Information Administration’s 2009 ―Distribution of Wells by Production Rate 

Bracket‖ some 338,056 (73%) wells out of a total gas well inventory of 461,388 gas 
13

wells produce 90 mcf of gas (15 BOE or less) or less per day

(http://www.eia.doe.gov/pub/oil_gas/petrosystem/us_table.html) . These low rate wells 

are either impaired by liquids accumulation or are using a deliquification method to 

produce. 

Wells and reservoirs follow a continuum of flow regimes, in their economic life, as 

the reservoir depletes, production goes down, well-bore (tubing) velocity goes down,

and liquid loading begins to occur in the well-bore. In the early stage of a well’s life 

many (but by no means all) wells can flow freely and with sufficient velocity to avoid 

liquid loading problems. As the reservoir energy depletes and the production-rate 

declines, a well will reach the stage where liquid-loading begins to be a problem and 

one of a portfolio of technologies or techniques will be used to help lift liquids using 

the reservoirs energy. As a well continues to produce and the reservoir energy 

declines further, a well will reach the stage where the reservoirs energy is not 

sufficient to lift liquids and energy, in the form of pumps, gas lift, etc., will have to be 

added to continue producing. When the expected production from a well cannot 

support the investment required to enable deliquification, it will reach the end of its 

economic life and be abandoned. The following figure shows a generalized well lifecycle curve with these different stages of a wells life illustrated. 
14

The production rate of a well, consequent velocity up the well-bore, and hence ability 

to lift liquids is mostly a function of the differential pressure between the reservoir 

and the flow-line/collection system and the reservoir’s sensitivity to backpressure. In 

order to flow, the total reservoir pressure must be greater than the total resistance to 

flow. This resistance is comprised of fluid friction and fluid interference across the 

reservoir; the flowing friction up the well-bore; the weight of the vertical fluid 

column in the well-bore; surface equipment and piping pressure losses; and the 

collection system/flow-line back-pressure. Opening a well-bore to atmospheric 

pressure (venting a well) removes the surface equipment/piping pressure-loss and the 

back pressure from the collection line and increases differential pressure to increase 

flow rates and velocities, which may enable the well to lift the liquid from the wellbore (unload the well). Venting of wells has been a common practice in low rate gas 

well deliquification for decades and is not restricted to wells without deliquification 

assist technologies, such as plunger lifts, in place. 

To combat this normal well/reservoir depletion and assist liquid lift a number of 

techniques are used – dependent on the well configuration, reservoir properties, well 

depth, and surface equipment and collection system. Some of these techniques are: 

The tubing in a well may be changed to smaller diameter ―velocity strings‖ 

which provide for higher velocity at any given flow rate and provide higher 

liquid lift capabilities. 

Soap injection may be used to ―foam‖ the liquids to reduce the unit density 

and enable liquids lifting. 

Wells may be put on a shut-in cycle to allow pressure/energy build-up of the 

reservoir near the well bore which equals higher production rates/velocity 

(temporary) and better liquids lifting.

Plunger lift may be installed in a well. This is generally coupled with a shutin cycle to build enough pressure under the plunger to lift it and the liquid 

column.

Mechanical pumps are selected when liquid rate is too high for plungers to 

operate or reservoir pressure is too low for plungers to operate without 

excessive shut-ns for build up.

Gas lift which raises tubing velocity to lift liquids by injecting gas down the 

tubing-casing annulus.

Compression which lowers the surface pressure creating more differential for 

flow and increasing velocity by lowering pressure.

Combinations of above approaches such as foaming, gas lift, and compression
15

The choice of what technique to employ is based on well-by-well and reservoir-byreservoir analysis and is one of the primary jobs of the production engineering teams. 

For a typical well, as it moves through the depletion continuum, a series of techniques 

will be employed. The decision on technology-selection requires a thorough 

understanding of the conditions that a reservoir is flowing into, the reservoir’s 

sensitivity to backpressure and the volumes and pressures that the deliquification 

technology must handle, and costs/benefits of applying the technology. This is a 

matter for engineering analysis and should not be a matter for regulation. For the 

EPA to mandate or even provide incentives to use a specific technology such as 

plungers will have the effect of stifling innovation and often deploying inappropriate 

technology. Saying that venting should be curtailed is a long way from the EPA 

requiring a broad implementation of a niche technology like plungers. In crafting 

regulations addressing well venting, EPA must encourage the flexibility to apply 

engineering analysis while introducing minimum venting as a criterion. 

Once wells reach the point where energy must be added, there are many options such 

as pumps, gas lift, and compressors available to work in gas wells both before and 

after the brief time that plungers might be applied. 

An excellent overview of this subject is Gas Well Deliquification, Second Edition, by 

Dr. James F. Lea, Dr. Henry V. Nickens, and Mr. Mike R. Wells (Gulf Publishing, 

2008, ISBN 978-0-7506.8280-0). This 588 page book does a good job of explaining 

the basis for choosing among the various technologies, but it does not presume to 

force a one-size-fits-all solution on the industry. 

10.2. Background on Plunger Lift

Plungers work by providing a mechanical barrier between a small volume of water 

and the gas that is used to transport it. If the gas could flow faster, then that 

mechanical barrier would not be necessary or helpful. Plunger capacity is limited by 

well depth, differential between reservoir pressure/surface pressure, and the gas/liquid 

ratio that the well produces. Even plunger lifted wells reach a point where they lack 

the reservoir pressure to run a plunger against backpressure often enough to lift the 

liquid that must be lifted. At that point the operator has the choice of replacing the 

plunger with a lift method that adds energy to the system or plugging the well. In the 

case of CBM wells for example, this point is generally reached around 50% of 

original gas in place (OGIP). Operators look at these wells and have to make the 

decision to spend capital on a pump or spend capital on drilling a new well—the 

economics of that decision generally favor installing a pump.
16

Although plungers are among the most common tools used in middle stage 

deliquification, plungers do not eliminate the need to vent to atmosphere. In many 

cases, wells are vented to atmosphere to generate the differential pressure necessary 

to lift the plunger and liquid column up the well-bore. This can be controlled and 

minimized but not eliminated.

One of the primary studies/projects EPA likes to highlight from its Natural 

Gas Star program is the BP ―smart automation‖ well bore venting control 

system in the San Juan basin. What is generally misunderstand or not 

acknowledged is that the majority of the wells which were venting (around 4.2 

BCF of gas per year) were plunger equipped and were vented in order to 

generate the energy necessary to lift the plunger and liquid column. 

The fact that it took nearly 6 years to fully develop the system and achieve 

90% + venting reduction is also often ignored. It is technically and 

operationally very difficult.

Plungers are not universally applicable to well-bores. For example, a plunger 

cannot be run in a well-bore with changing tubing sizes, defects or buildups of 

scale or in coil tubing which has an ―internal upset‖ weld seam. Plungers can 

only be run where the inside of the well-bore is smooth and in reasonably 

good condition. They also do not work well in highly deviated directional or 

horizontal well-bores.

Although casing plungers are available for wells without tubing, they have 

had significant reliability problems and it is also difficult to control the 

velocity up the well-bore to avoid high velocities which have blown the top 

off of well-heads resulting in uncontrolled release of significant quantities of 

gas.

Once a well/reservoir declines sufficiently, plungers will no longer work and 

energy must be added to the well-bore or the well abandoned. This is an 

economics decision. 

10.3. Industry Research on Well-Bore Deliquification 

There is a tremendous amount of research and work focused on well-bore 

deliquification, from a production and economics perspective alongside emissions 

reduction, and EPA needs to not discourage this or insert road-blocks. This work is 

both optimizing and improving existing techniques along with developing entirely 

new types of systems. Industry needs the flexibility to pilot some of these 

ideas/developments without regulatory impediments – even if they ultimately do not 

succeed. 
17

For example, the 9th Annual Gas Well Deliquification Workshop is scheduled for 

February 28 – March 2, 2011 in Denver, Colorado. This workshop series, along with 

a portfolio of other venues dedicated to well deliquification and artificial lift, is 

organized by the Artificial Lift Research and Development Council (ALRDC), and 

the Southwestern Petroleum Short Course (SWPSC). The 34th Annual 

ASME/ALRDC International Gas-Lift Workshop was held in Singapore on February 

7 - 11, 2011 with past annual workshops at various venues around the world. The 

ALRDC / SWPSC 2011 Appalachian Basin Gas Well Deliquification Seminar and 

workshop is scheduled for June 2011. For more information, please visit 

http://www.alrdc.com.