Matthew Todd

Regulatory and Scientific Affairs

1220 L Street, NW Washington, DC 20005

- 4070 USA Telephone: 202

- 682

- 8 319 Fax: 202

- 682

- 8031 Email: ToddM@api.org www.api.org February 23 , 201 1

Mr. Bruce Moore U.S. E nvironmental P rotection A gency Mail Code : E143

- 03 Research Triangle Park, NC 2 7711

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 C FR 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 Na tural Gas Processing Plants,
40 CFR Part 60 Subpart LLL, Standards of Performance for Onshore Natural Gas Processing: SO 2 Emissions,
40 CFR Part 63 Subpart HH, National Emission Standards for Hazardous Air Pollutants From Oil and Natural Gas Production Fac ilities, 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

opera tions 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

- 8 319 or todd m@api.org

.

Sincerely,

/s/ Matthew Todd

Matthew Todd1



### Contents

1. WORKER SAFETY MUST BE CONSIDERED

................................ ................................ ... 2

2. THE FLOORS DO NOT NEED TO BE FIX ED

................................ ................................ .... 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 REQUIRE MENTS NEED TO BE CLARIFIED

................................ ....................... 8

7.1. Flare Continuous Pilots and Vmax Limits

................................ ................................ ....... 8

7.2. Enclosed Combustors Need To Be Distinguished From Fla res

................................ ....... 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

................................ ....................... 162



## 1. WORKER S AFETY MUST BE CONSID ERED

EPA needs to consider worker safety in this rulemaking. These requirements will mandate control technologies a nd 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
work ers 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 FI XED

EPA has indicated that it intend s 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 revie w 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

n ecessary (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 t hat EPA was obligated under § 112(d)(6) to

re

- determine MACT for certain source types because cost had been considered in3 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 a n Effective Standard

Lastly, the 1 ton/year (or 0.9 megagram per year) of benzene exemption threshold
should be considered a n ―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 enfo rceable) 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

- In

Always

- In policy. Thus, even at major sources, the use of emission limits to e xempt 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

- completin g 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 non

traditional reservo irs, 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) ca rrying 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 cr eated 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 enable4 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 f low 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 solid s 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 conde nsation 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 l osses, 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 syste m/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 fo rmation fluids or gas. As a well cleans

up, 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 a re 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 s ales. 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 implementa tion 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 si mple mechanical separation equipment. When air, CO2, or nitrogen is used in well operations, these gases would require extensive chemical and/or thermodynamic5 processes to extract natural gas from the gas stream. This equipment is inappropriate and unsaf e 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

s ystem 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 clea n

- 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 stage s 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 viab le 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
flo w

- 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 cl arity/ 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 appropria te 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 wi ll 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 i ndustry 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 productio n. 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 compe tition 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 equ ipment 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 afte r 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 contr ol 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 ru le 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 co mply 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 NSP S
MODIFI CATION

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 val id 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 correspond ingly increases when the production rises due to a workover. API believes that a modif ication 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 O NLY 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 ke y 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 i mpact 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 uncontrol led 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 e missions.



## 7. FLARE REQUIREMENT S 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.
Includ ed 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 eff

icient 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 rulemaki ng team established to modify flare requirements as a part of
the uni form 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 nee d 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 combust o r types of devices are increasingly being deployed for
emission control of streams that would histor ically 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 combusto rs 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. Provision s 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 expe rimental 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 ap provals. 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 implementatio n. 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 RE TAIN 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)

state s 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 eq uipment 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% V OC 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 U S 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

- oil

equivalent (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

- economi c 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 acquiri ng 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 s mall 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. T his 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 FO R WELL

- BORE DELIQUIFICATION CONT ROLS

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 te chnologies 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 particu lar technology or approach to the highly complex problem of well

- bore deliquification through regulation

. API does recognize that well

venting 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 c ould 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 im pact many small operators who tend to have portfolios of low rate ―marginal‖ wells. S pecifying 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

re gulatory 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 full y under stand the issue of well liquid

- loading and venting control prior to crafting regulations addressing i t. 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 fundament al 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 Challen ges, Trends in Gas Well Deliquification and the February 27, 2006 Oil & Gas Journal article Low

Pressure 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 liqu id 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 pro ducing 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 gas13 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 eit her 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 ene rgy depletes and the production

- rate declines, a well will reach the stag e 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 ene rgy 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 life

cycle curve with these different stages of a wells life illustrated.14 The produc tion 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

or der 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 flui d
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 su rface equipment/piping pressure

- loss and the back pressur e 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 well

bore (unload the well). Venting of wells has been a common practice in low rate gas well deliq uification 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 w ell 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 we ll 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 shut

in cycle to build enough pressure under the plunger to lift it and the liquid
colu mn. 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 d own 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 compression15 The choice of what te chnique to employ is based on well

- by

- well and reservoir

- by

reservoir 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. T he 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/b enefits 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 inno vation 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 encour age 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

- 7506.828 0

- 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 L ift

Plungers work by providing a mechanica l 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 pr essure/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 po int 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 l ook 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
del iquification, 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
minim ized 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 dev elop 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, defect s 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
horizont al 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

- h eads 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 Re search 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

- bloc ks. 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 ultimat ely do not
succeed.17 For example, the 9 th 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 artifi cial 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 pa st 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. Fo r more information

, please visit http://www.alrd c.com

.