## Storage Vessel Applicability u nder 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 ver y conservative analysis and the final rule will likely affect significantly more storage vessels each year. EP A 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 b e 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 af fected 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 explo re s 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, s ince 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 m ajority 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 p rovides 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 crud e 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 froma 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 p roduction 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 wel ls. 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 ra tio of one

- to

one.

C onclusions 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, a nd 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 ( lbs voc /Bbl production ):
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 Vasqu ez 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
cha racteristics 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 correlat ion 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

- B on 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 emiss ions 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 a nd 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 estimati ng tan k 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 bes t predictions possible on condensate/crude storage vessel emission s 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, em ission factors of 9.75 lb/bbl (the ar i thmetic 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 t he 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
conde n sate vessels subject to Subpa rt OOOO to conde n sate 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 thes e 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

Emissi on 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 re quire 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

- vess el 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 a dditional storage tank s 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 r eplacement 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 Su bpart 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 t he 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

- by

site 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 demonstrate d 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 shor tage 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 pro posal 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 locate d at remote, unmanned facilities.