Storage Vessel Applicability under NSPS Subpart OOOO 

As detailed below, API estimates that well over 10,000 storage vessels per year will trigger the 

Subpart OOOO tank standard or will otherwise need to be controlled to avoid triggering the standard. 

This conclusion is based on a very conservative analysis and the final rule will likely affect 

significantly more storage vessels each year. EPA concluded in the final rule that the compliance date 

for storage vessels should be deferred for one year to provide time for production of the needed 

control devices. Since the rule will cover at least 40 times the number of tanks that EPA predicted 

would be affected by the rule, it is clear that more time will be needed to ensure that controls will be 

available for all affected tanks. In addition, this illustrates that the trigger date for the tank standard 

should be revised to prevent a huge backlog of affected tanks that would exacerbate the control device 

availability problem.

Objective: Develop a yearly estimate of storage vessels that will exceed the 6 ton/year VOC 

control applicability threshold under the current NSPS Subpart OOOO. 

This paper explores the condensate and crude oil storage vessels that will require controls under NSPS 

Subpart OOOO as published on August 16, 2012. Although produced water tanks are regulated under 

Subpart OOOO, since condensate and crude production rates will be the driver for most control 

determinations, the production of produced water will be ignored for this evaluation. 

NSPS Subpart OOOO covers new, modified and reconstructed storage vessels. The vast majority of 

these new condensate and crude oil tanks are expected to directly support new production wells. 

Production data is reported to state oil and gas regulatory agencies on a well by well basis. HPDI 

collects this data from the state agencies and provides it to subscribers in a searchable data base that 

can be flexibly queried. API used the HPDI data base to assemble data on wells that first started 

production in 2011 and represent new wells/tanks in 2011. The results of this query are the primary

data feed for this analysis. The HPDI database includes production and location data, but does not 

provide sufficient detail to estimate emissions. Emissions estimates will be discussed in a later 

section. 

The next question to consider is how many crude oil or condensate storage vessels will be required to 

support the new production wells. For the present discussion, we will assume that one new storage 

vessel will be added for each new production well. In practice, the decision is made on a project by

project basis based on considerations such as field configuration, crude/condensate production rate, 

distance to pipeline, etc. Some production wells, particularly in oil fields, may bring several wells 

into an existing or new centralized tank battery. Pad wells that directionally drill multiple wells from 
a single location are becoming more common due to environmental, wildlife and landowner 

considerations and frequently do not have one tank per well-bore. Other wells will have enough 

crude/condensate production and/or are far enough from pipeline facility to require more than one 

storage vessel. Additionally, compressor stations in natural gas gathering systems and gas plants 

(a.k.a. midstream) will install some new storage tanks due to new or shifting production within a field. 

Although new condensate storage vessels in the midstream industry are proportional to new 

production wells, the number of midstream storage vessels is vastly outnumbered by the storage 

vessels associated with the production wells. Qualitative discussions within industry indicate that the 

number of new storage vessels installed to support each new production well will change from field to 

field, but on average is likely to be slightly more than one. Thus, our assumption is a ratio of one-toone. 

Conclusions from the HPDI Data Query: As stated previously, the HPDI data base is an exhaustive 

accumulation of data from State oil and gas regulatory agencies on hundreds of thousands of 

production wells. The data query was designed to eliminate all of the existing production wells and 

only include data on production wells starting production in 2011. 2011 was chosen to accommodate 

the delays in reporting the data to the agencies, the agencies entering the data into their systems, and 

HPDI incorporating the data into their data base. 

This analysis was done in three steps: (1) Data was extracted from the industry database for all wells 

with first production in 2011; (2) the data was scrubbed for invalid data, duplicate API numbers,

locations where condensate/crude oil tanks were not appropriate (e.g., offshore, Alaska North Slope, 

and CBM wells), and dry gas wells with no liquid production; (3) non-producing wells (e.g., injection 

wells, SWD wells, etc.) and (4) the remaining wells were divided into “oil” (GOR less than 10,000 

SCF/bbl) and “gas condensate” (GOR > 10,000 SCF/bbl) categories and factors were applied to 

estimate VOC from tank flashing.
This analysis provided the following results:

Record 

Count

Gas (BCF) Oil/condensate

(million bbl)

Raw Extract 40,766 7,505 100% 491 100%

Invalid data 1,576 99 1.3% 11 2.2%

Duplicate API 3,182 No volume data lost in this step

Alaska and Offshore 543 419 5.6% 69 14.1%

CBM & CO2 985 146 1.9% 0.001 0.0%

Non-Producing 78 4 0.1% 0.6 0.1%

Remaining Wells

Dry Gas Wells 7,257 4,086 54.4% 0 0.0%

Gas Condensate 6,199 2,070 27.6% 37 7.5%

Oil Wells 21,024 681 9.1% 373 76.1%

Total 40,766 7,505 100% 491 100%

Based on 2011 production, as the analysis of HPDI data above shows, approximately 27,000 wells 

(i.e., 6,199 gas condensate plus 21,024 oil wells) had hydrocarbon liquid production and, therefore, 

constitute the population of tanks evaluated for requiring controls under NSPS Subpart OOOO.

Determination of Emission Factor (lbsvoc/Bblproduction): 

Determining condensate/crude oil tank emissions (particularly flashing emissions) is typically done 

using one of the modeling systems developed over the last two decades. Typical systems used range 

from the correlation based Vasquez and Beggs calculations through the E&P Tanks modeling system 

to full simulation modeling using a process modeling system such as HySys or ProSim. All of these 

systems require information/data regarding pressures, temperatures and hydrocarbon liquid 

characteristics such as API gravity or composition. Several historical studies of condensate/crude oil 

tank emissions were reviewed in an attempt to determine appropriate physical and condensate/crude 

oil characteristic/composition emissions to apply to the HPDI derived data. 

The Vasquez/Beggs correlation equation approach (from the State of New Mexico Air Quality 

Department) was evaluated. It was determined that many field conditions are well outside of the 

applicable range of the Vasquez/Beggs correlation approach and hence it was not useful for the 

purposes of this study. 
The Hy-Bon Engineering study conducted for the Texas Department of Environmental Quality in 

2009 was evaluated. This study evaluated 36 wells in West Texas and North Texas (6 of the wells 

were later discarded for data quality issues). The Hy-Bon study was only issued as a draft document

and there were significant questions around whether an actual condensate throughput during each 24-

hour test was taken. Calculating a VOC flash emissions factor based on condensate throughput 

requires an accurate measurement of throughput; therefore, the Hy-Bon study is not useful. 

A report by the Eastern Research Group, Inc. (ERG) prepared for the TCEQ in 2012 that presents a 

detailed data analysis and grouping project was also evaluated. In this study, ERG integrated data 

from 4 studies and 2 surveys (conducted by ERG) and found that the arithmetic average emissions 

factor for condensate tanks was 9.75 lb/bbl with a range of 5.87 lb/bbl to 16.0 lb/bbl. The conclusion 

from these exhaustive studies is that predicting VOC emissions from stock tank volumes requires 

significant amounts of well/tank-specific information and broad assumptions of this information 

are not valid or useful for estimating tank VOC emissions based on production volumes. VOC 

emissions are a function of: (1) gas/liquid compositions; (2) separator pressure; (3) separator 

temperature; (4) ambient pressure and temperature; and (5) stock tank temperature. Because of the 

very wide range of reasonable values for each of these parameters, API does not believe that 

assumptions regarding these parameters can be used to model or assign VOC emissions based 

simply on stock tank barrels.

However, API does understand the need to make the best predictions possible on condensate/crude 

storage vessel emissions and Subpart OOOO applicability with the data available. Due to the 

integration of 4 studies and 2 surveys, the amount of data analysed, and in order to move forward with 

this analysis, emission factors of 9.75 lb/bbl (the arithmetic average from the ERG study, Table 2-15)

and 16 lb/bbl (representing a high regional average) were used for condensate and 2 lb/bbl was used 

for oil without any further attempt at “refinements” that would have the net result of introducing a 

bias on the analysis without any basis. Due to the wide range of potential factors available for 

condensate, two emission factors were analysed to indicate the sensitivity of the number of 

condensate vessels subject to Subpart OOOO to condensate emission factor. The use of a GOR less 

than 10,000 to designate crude oil, thus a 2 lb/bbl emission factor, almost certainly causes an under 

estimate of emissions on many crude oil storage vessels, since it is likely that many of these vessels 

should have been analysed using the higher condensate factors. 
This simple emission factor approach results in the following table when applied to the production 

data extracted from the HPDI database: 

Gas Condensate Wells Oil Wells

Emission Factor 16 lb/bbl 9.75 lb/bbl 2.0 lb/bbl

<6 tpy 2356 wells 2891 wells 11552 wells

>6 and <10 tpy 561 wells 598 wells 2326 wells

>10 and <100 tpy 2597 wells 2259 wells 6562 wells

>100 tpy 685 wells 451 wells 584 wells

Total wells controlled by OOOO 3843 wells 3308 wells 9472 wells

Total well count 6199 wells 6199 wells 21024 wells

As this conservative estimate shows, approximately 13,000 tanks associated with new wells starting 

production in 2011 would be subject to NSPS Subpart OOOO and require emission controls based on 

the current 6 tpy threshold without any consideration of other storage vessels (e.g., replacement tanks 

discussed below). The analysis also shows that, regardless of any variation in the emission factor on a 

vessel-by-vessel basis, the estimate of vessels subject to Subpart OOOO is not sensitive to these 

variations. Given the conservatively low emission factors used, API believes the 13,000 estimate 

represents a lower bound of tanks subject to control by NSPS Subpart OOOO each year. 

Clearly, API believes this analysis shows the estimate of tanks subject to control in the Subpart 

OOOO docket is woefully low by a factor greater than 40. 

It’s important to note that additional storage tanks that would potentially be subject to NSPS OOOO, 

but were not included for this evaluation; these include:

• Produced water tanks;

• Tanks within midstream operations; and

• Tanks replacements

Storage tanks have a useful life that is much shorter than the useful life of producing wells. As the 

tanks in a field begin to age, the frequency of corrosion and wear failures begins to increase and tanks 

are replaced. Typically, tanks last less than 15 years without much failure risk. Beyond that, the risks 

increase. Since a large portion of the oil and condensate storage tanks currently in service have 

passed the 15 year mark, many operators in older fields are actively engaging in “tank replacement 

projects”. With upwards of a million atmospheric hydrocarbon storage tanks currently in service, the 

number of replacement storage vessels in any given year could easily equal the number of new wells. 

Since tank replacements generally occur in mature fields, many of the tanks to be replaced will be 

uncontrolled, but a new control will be needed for the replacement because of Subpart OOOO. For 

tanks to be replaced that are already controlled, the existing control devices may not meet the criteria 

of Subpart OOOO, and will also have to be replaced at the same time as the tank replacement occurs.
Therefore, the estimate determined in this evaluation would be at the lower end of the total 

population of tanks potentially subject to NSPS OOOO. 

State Regulations Requiring Emission Controls

The final factor in determining the number of wells regulated by NSPS Subpart OOOO is estimating 

how many wells would be excluded because of state and local enforceable emission limits. Although 

several states have permit requirements that result in emission controls on storage vessels, very few 

have storage vessel specific limits below the 6 tpy of VOC threshold present in Subpart OOOO. 

While the presence of an emission control on the storage vessel is enforceable, the 6 tpy VOC 

emission limit typically is not. Thus, for any storage vessel to be excluded from NSPS Subpart

OOOO control requirements as currently written, additional permit actions are required on a site-bysite basis. API is in the process of estimating the number of storage vessels that may have controls 

installed with enforceable emission limits from state and local regulations using the emissions 

estimates above. 

Conclusion:

This analysis continues to support API’s positions regarding the storage tank requirements in the final 

NSPS Subpart OOOO rule. They are:

 The storage tanks standards, as demonstrated in this paper, will apply to far more tanks than 

EPA anticipates, leaving far too little time for all operators to achieve compliance with the 

standards. Therefore, EPA needs to extend the tank compliance deadline to October, 2015.

 Controls are not currently justified as Best System of Emission Reduction (BSER) because of 

the shortage of available controls to meet the demand combined with a lack of demonstration 

from existing manufacturers to meet the full requirements of the final rule. As such, they 

should not be required for tanks for which construction commenced between the proposal 

date and the compliance date.

 The control requirements and associated compliance assurance requirements are confusing, 

complex and overly stringent. They must be clarified and simplified in several respects to 

facilitate compliance for thousands of additional sources each year that are often located at 

remote, unmanned facilities.