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7.0 STORAGE VESSELS

Storage vessels are sources of air emissions in the oil and natural gas sector. This chapter provides a 

description of the types of storage vessels present in the oil and gas sector, and provides estimates for a 

typical storage vessel as well as nationwide emission estimates. Control techniques employed to reduce 

emissions from storage vessels are presented, along with costs, emission reductions, and secondary 

impacts. Finally, this chapter provides a discussion of considerations used in developing regulatory 

alternatives for storage vessels.

7.1 Process Description

Storage vessels in the oil and natural gas sector are used to hold a variety of liquids, including crude oil, 

condensates, produced water, etc. Underground crude oil contains many lighter hydrocarbons in 

solution. When the oil is brought to the surface and processed, many of the dissolved lighter 

hydrocarbons (as well as water) are removed through as series of higher-pressure and low-pressure 

separators. Crude oil under high pressure conditions is passed through a either a two phase separator 

(where the associated gas is removed and any oil and water remain together) or a three phase separator 

(where the associated gas is removed and the oil and water are also separated). At the separator, low 

pressure gas is mechanically separated from the high pressure oil. The remaining low pressure oil is then 

charged to a storage vessel where it is stored for a period of time before being shipped off-site. The 

remaining hydrocarbons in the oil are emitted as vapors into the storage vessels.

Emissions of the remaining hydrocarbons from storage vessels are a function of working, breathing (or 

standing), and flash losses. Working losses occur when vapors are displaced due to the emptying and 

filling of storage tanks. Breathing losses are the release of gas associated with daily temperature 

fluctuations and other equilibrium effects. Flash losses occur when a liquid with entrained gases is 

transferred from a vessel with higher pressure to a vessel with lower pressure, thus allowing entrained 

gases or a portion of the liquid to vaporize or flash. In the oil and natural gas production segment, 

flashing losses occur when live crude oils or condensates flow into a storage tank from a processing 

vessel operated at a higher pressure. Typically, the larger the pressure drop, the more flashing emission 

will occur in the storage stage. Temperature of the liquid may also influence the amount of flash 

emissions.

The volume of gas vapor coming off a storage vessel depends on many factors. Lighter crude oils flash 

more hydrocarbons than heavier crude oils. In storage vessels where the oil is frequently cycled and the 
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overall throughput is high, working losses are higher. Additionally, the operating temperature and 

pressure of oil in the vessel dumping into the tank will affect the volume flashed gases coming out of the 

oil.

The composition of the vapors from storage vessels varies, and the largest component is methane but 

also includes ethane, butane, propane, and hazardous air pollutants (HAP) such as benzene, toluene, 

ethylbenzene, xylene (collectively referred to as BTEX), and n-hexane.

7.2 Emissions Data

7.2.1 Summary of Major Studies and Emissions

Given the potentially significant emissions from storage vessels, there have been numerous studies 

conducted to estimate these emissions. Many of these studies were consulted to evaluate the emissions 

and emission reduction options for emissions from storage vessels. Table 7-1 presents a summary of 

these studies, along with an indication of the type of information available in each study.

7.2.2 Representative Storage Vessel Emissions

Due to the variability in the sizes and throughputs, model tank batteries were developed to represent the 

ranges of sizes of storage vessels throughout the sector. Model tank batteries were not intended to 

represent any single facility, but rather a range of facilities with similar characteristics that may be 

impacted by standards. Model tank batteries were developed for condensate tanks and crude oil tanks. 

Average VOC emissions were then developed and applied to the model tank batteries.

7.2.2.1 Model Condensate Tank Batteries

During the development of the national emissions standards for HAP (NESHAP) for oil and natural gas 

production facilities (40 CFR part 63, subpart HH), model plants were developed to represent 

condensate tank batteries across the industry.1To estimate the current condensate battery population and 

distribution across the model plants, the number of tanks represented by the model plants was scaled 

from 1992 (the year for which that the model plants were developed under the NESHAP) to 2008 for 

this analysis. Based on this approach, it was estimated that there were a total of 59,286 existing 

condensate tanks in 2008. Condensate throughput data from the U.S. Greenhouse Gas Emissions 

Inventory2,3 was used to scale the condensate tank populations for each model condensate tank battery 

under the assumption that an increase in condensate production would be accompanied by a proportional 
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increase in number of condensate tanks. The inventory data indicate that condensate production 

increased from a level of 106 million barrels per year (MMbbl/yr) to 124 MMbbl/yr in 2008. This 

increase in condensate production was then distributed across the model condensate batteries in the same 

proportion as was done for the NESHAP. The model condensate tank batteries are presented in Table 7-

2. 

7.2.2.2 Model Crude Oil Tank Batteries

According to the Natural Gas STAR program,

4

there were 573,000 crude oil storage tanks in 2003. 

According to the U.S. Greenhouse Gas Emissions Inventory, crude oil production decreased from 1,464 

MMbbl/yr in 2003 to 1,326 MMbbl/yr (a decrease of approximately 9.4 percent). Therefore, it was 

assumed that the number of crude oil tanks in 2008 were approximately 90.6 percent of the number of 

tanks identified in 2008. Therefore, for this analysis it was assumed that there were 519,161 crude oil 

storage tanks in 2008. During the development of the NESHAP, model crude oil tank batteries were not 

developed and a crude tank population was not estimated. Therefore, it was assumed that the distribution 

of total number of crude oil tanks across the model crude oil tank batteries was the same as for 

condensate tank batteries. Table 7-3 presents the model crude oil tank batteries. 

7.2.2.3 VOC Emissions from Model Condensate and Crude Oil Tanks

Once the model condensate and crude oil tank distribution was developed, VOC emissions from a 

representative tank were estimated. Emissions from tanks vary considerably depending on many factors, 

including but not limited to throughput, API gravity, Reid vapor pressure, separator pressure, etc. The 

American Petroleum Institute (API) has published a program called E&P TANKS which contains a 

dataset of more than 100 storage tanks from across the country.5 A summary of the information 

contained in the dataset, as well as the output from the E&P TANKS program, is presented in Appendix 

??? of this document. According to industry representatives, this dataset in combination with the output 

of the E&P TANKS program is representative of the various VOC emissions from tanks across the 

country.6

The more than 100 tanks provided with the E&P TANKS program, which had varying characteristics, 

were modeled with a constant throughput of 500 bpd and the relationship of these different 

characteristics and emissions was studied. While many of the characteristics impacted emissions, a 

correlation was found to exist between API gravity and emissions. The average API gravity for all tanks 

in the data set was approximately 40 degrees. Therefore, we selected an API gravity of 40 degrees as 
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parameter to distinguish between lower emitting tanks and higher emitting tanks. While the liquid type 

was not specified for the tanks modeled in the study, it was assumed that, condensate tanks would be 

represented by tanks with higher emissions than crude oil tanks. Therefore, based on this study using the 

E&P Tanks program, it was assumed for this analysis that liquids with API gravity equal to or greater 

than 40 degrees should be classified as condensate and liquids with API gravity less than 40 degrees 

should be classified as crude oil.

The VOC emissions from all tanks in the analysis are presented in Appendix ???. Table 7-4 presents a 

summary of the average VOC emissions from all tanks as well as the average VOC emissions from the 

tanks identified as being condensate tanks and those identified as being crude oil tanks. As shown in 

Table 7-4, the tanks were modeled at a constant throughput 500 bbl. This was based on the assumption 

that tank emissions would increase in proportion with throughput. An average emission factor was 

developed for each type of liquid. The average of condensate tank VOC emissions was modeled to be 

1,046 tpy or 11.5 lb VOC/bbl and the average of crude oil tank VOC emissions was modeled to be 107 

tpy or 1.18 lb VOC/bbl. These emission factors were then applied to each of the two sets of model tanks 

in Tables 7-2 and 7-4 to develop the VOC emissions from the model tank batteries. These are presented 

in Table 7-5.

7.3 Nationwide Baseline Emissions from New or Modified Sources

7.3.1 Approach

The first step in this analysis is to estimate nationwide emissions in absence of the proposed rulemaking, 

referred to as the nationwide baseline emissions estimate. In order to develop the baseline emissions 

estimate, the number of new tanks expected in a typical year was calculated and then multiplied by the 

expected uncontrolled emissions per tank presented in Table 7-5. In addition, to ensure no emission 

reduction credit was attributed to sources already controlled under State regulations, it was necessary to 

account for the number of storage tanks already subject to State regulations as detailed below.

7.3.2 Number of New Storage Tanks Expected to be Constructed or Reconstructed

The number of new storage tanks expected to be constructed was determined for the year 2015 (the year 

of analysis for the regulatory impacts). To do this, it was assumed that the number of new or modified 

tanks would increase in proportion with increases in production. The Energy Information Administration 

(EIA), published crude oil production rates up to the year 2011.7 Values were not available at the time of 
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this document for the year 2015. Therefore, using the forecast function in Microsoft Excel® , crude oil 

production was predicted for the year 2015.aFrom 2009 to 2015,bthe expected growth of crude oil 

production was projected to be 8.25 percent (from 5.36 bpd to 5.80 bpd). Applying this expected growth 

to the number of existing tanks results in an estimate of 4,890 new or modified condensate tanks and 

42,811 new or modified crude oil tanks. The number of new or modified storage tanks expected to be 

constructed or reconstructed is presented in Table 7-6.

7.3.3 Level of Controlled Sources in Absence of Federal Regulation 

As stated previously, to determine the impact of a regulation, was first necessary to determine the 

current level of emissions from the sources being evaluated, or baseline emissions. To more accurately 

estimate baseline emissions for this analysis, and to ensure no emission reduction credit was attributed 

for sources already being controlled, it was necessary to determine which storage vessels were already 

being controlled. To do this, the National Emissions Inventory (NEI) was used. Storage vessels in the 

oil and natural gas sector were identified for the review of the maximum achievable control technology 

(MACT) standards.8There were 5,412 storage tanks identified in the NEI, and of these, 1,973 (or 36 

percent) were identified as being uncontrolled. Therefore, this percent of uncontrolled tanks was applied 

to the number of new or modified tanks results in an estimate of 1,782 new or modified condensate 

storage tanks and 15,607 new or modified crude oil storage tanks. These are also presented in Table 7-6.

7.3.4 Nationwide Emission Estimates for New or Modified Storage Tanks

Nationwide emissions estimates are presented in Table 7-6 for condensate storage tanks and crude oil 

storage tanks. Model tank emissions were multiplied by the number of expected new or modified storage 

tanks that would be uncontrolled in the absence of a federal regulation. As shown in Table 7-6, the 

baseline nationwide emissions are estimated to be 21,373 tpy for condensate storage tanks and 

23,421 tpy for crude oil storage tanks.

7.4 Control Techniques

7.4.1 Potential Control Techniques

 

a The crude oil production values published by the EIA include leased condensate. Therefore, the increase in crude oil 

production was assumed to be valid for both crude oil and condensate tanks for the purpose of this analysis.

b The year 2008 was considered an outlier for production and therefore was not used in this analysis.
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In analyzing controls for storage vessels, we reviewed control techniques identified in the Natural Gas 

STAR program and state regulations. We identified two ways of controlling storage vessel emissions, 

both of which can reduce VOC emissions by 95 percent. One option would be to install a vapor recovery 

unit (VRU) and recover all the vapors from the tanks. The other option would be to route the emissions 

from the tanks to a flare. These control technologies are described below along with their effectiveness 

as they apply to storage tanks in the oil and gas sector, cost impacts associated with the installation and 

operation of these control technologies, and any secondary impacts associated with their use.

7.4.2 Vapor Recovery Units

7.4.2.1 Description of Vapor Recovery Units

Typically, with a VRU, hydrocarbon vapors are drawn out of the storage tank under low pressure and 

are piped to a separator, or suction scrubber, to collect any condensed liquids, which are typically 

recycled back to the storage tank. Vapors from the separator flow through a compressor that provides 

the low-pressure suction for the VRU system. Vapors are then either sent to the pipeline for sale or used 

as on-site fuel.9

7.4.2.2 Effectiveness of Vapor Recovery Units

Vapor recovery units have been shown to reduce VOC emissions from storage tanks by approximately 

95 percent.9 A VRU recovers hydrocarbon vapors that potentially can be used as supplemental burner

fuel, or the vapors can be condensed and collected as condensate that can be sold. If natural gas is 

recovered, it can be sold as well, as long as a gathering line is available to convey the recovered salable 

gas product to market or to further processing. A VRU also does not have secondary air impacts, as 

described below. However, a VRU cannot be used in all instances. Some conditions that affect the 

feasibility of VRU are: fluctuations in vapor loading caused by surges in throughput and flash emissions 

from the tank; potential for drawing air into condensate tanks causing an explosion hazard; and lack of 

appropriate destination or use for the vapor recovered.

7.4.2.3 Cost Impacts for Vapor Recovery Units

Cost data for a VRU was obtained from an Initial Economic Impact Analysis (EIA) prepared for 

proposed state-only revisions to a Colorado regulation.10 Cost information contained in the EIA was 

assumed to be giving in 2007 dollars. Therefore costs were escalated to 2008 dollars using the CE 
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Indices for 2007 (525.4) and 2008 (575.4).11 According to the EIA, the purchased equipment cost of a 

VRU was estimated to be $85,423 (escalated to 2008 dollars from $75,000 in 2007 dollars). Total 

capital investment, including freight and design and installation was estimated to be $98,186. These cost 

data are presented in Table 7-7. Total annual costs were estimated to be $18,983/year.

7.4.2.4 Secondary Impacts

A VRU is a pollution prevention technique that is used to recover natural gas that would otherwise be 

emitted. No secondary emissions (e.g., nitrogen oxides, particulate matter, etc.) would be generated, no 

wastes should be created, no wastewater generated, and no electricity needed. Therefore, there are no 

secondary impacts expected due to the use of a VRU.

7.4.3 Flare

7.4.3.1 Description and Effectiveness

Flares are also used to control emissions from condensate and crude oil storage tanks. A flare is a hightemperature oxidation process used to burn combustible components, mostly hydrocarbons, found in 

waste streams.12 Flares are used to control VOC in many industrial settings, since the flare can normally 

handle fluctuations in concentration, flow rate, heating value, and inert species content.13 While 

industrial-type flares could achieve around 98 percent efficiency, the types of flares installed for the oil 

and gas sector are usually more crude and are assumed achieve 95 percent efficiency.10 Because tank 

batteries are typically remotely located and un-manned, flares should be equipped with an auto igniter 

and a surveillance system which identifies when pilot is not lit and attempts to relight it, documents the 

duration of time when the pilot is not lit, and notifies and operator that repairs are necessary. Flares do 

not have the same operational issues as VRUs, however secondary impacts are associated with flares as 

discussed below.

7.4.3.2 Cost Impacts

Cost data for a flare was also obtained from the Initial EIA prepared for proposed state-only revisions to 

the Colorado regulation.10 As performed for the VRU, costs were escalated to 2008 dollars using the CE 

Indices for 2007 (525.4) and 2008 (575.4).14 According to the EIA, the purchased equipment cost of a 

flare, including an auto igniter and surveillance system was estimated to be $23,699 (escalated to 2008 

dollars from $21,640 in 2007 dollars). Total capital investment, including freight and design and 
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installation was estimated to be $32,301. These cost data are presented in Table 7-8. Total annual costs 

were estimated to be $8,909/year.

7.4.3.3 Secondary Impacts

Combustion and partial combustion in the flare of many pollutants also create secondary pollutants 

including nitrogen oxides, carbon monoxide, sulfur oxides, carbon dioxide, and smoke/particulates.

Reliable data for emission factors from flares on condensate and crude oil storage tanks are limited. 

Guidelines published in AP-42 for flare operations are based on tests from a mixture containing 

80 percent propylene and 20 percent propane.12 These emissions factors, however, are the best 

indication for secondary pollutants from flares currently available. The secondary emissions per tank are 

provided are provided in Table 7-9. 

7.5 Regulatory Options and Nationwide Impacts of Regulatory Options

7.5.1 Consideration of Regulatory Options for Condensate and Crude Oil Storage Tanks

The VOC emissions from storage vessels vary significantly, depending on the rate of liquid entering and 

passing through the vessel (i.e., its throughput), the pressure of the liquid as it enters the atmospheric 

pressure storage vessel, the liquid’s volatility and temperature of the liquid. Some storage vessels have 

negligible emissions, such as those with very little throughput and/or handling heavy liquids entering at 

atmospheric pressure. Therefore, in order to control the tanks with significant VOC emissions, a cutoff 

was evaluated to limit the applicability of the standards to these tanks. Rather than require a cutoff in 

terms of emissions that would require a facility to conduct an emissions test on their storage tank, a 

throughput cutoff was evaluated. It was assumed that facilities would have tank throughput data readily 

available. Therefore, we evaluated the costs of controlling storage tanks with varying throughputs to 

determine which throughput level would provide the most cost effective control option.

The standard would require an emission reduction of 95 percent, which, as discussed above, could be 

achieved with a VRU or a flare. A flare is an option for tank batteries because of the operational issues 

associated with a VRU as discussed above. However the use of a VRU is preferable to a flare because a 

flare destroys, rather than recycle, valuable resources and there are secondary impacts associated with 

the use of a flare. Therefore, the cost impacts associated a VRU installed for the control of storage tanks 

were evaluated.
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To conduct this evaluation, emission factor data from a study prepared for the Texas Environmental 

Research Consortium15 was used to represent emissions from the different throughputs being evaluated. 

For condensate storage tanks, an emission factor of 33.3 lb VOC/bbl was used and for crude oil storage 

tanks, an emission factor of 1.6 lb VOC/bbl was used. Using the throughput for each control option, an 

equivalent emissions limit was determined. Table 7-10 presents the following regulatory options 

considered for condensate tanks:

Regulatory Option 1: Control condensate storage tanks with a throughput greater than 0.5 

bbl/day (equivalent emissions of 3.0 tpy);

Regulatory Option 2: Control condensate storage tanks with a throughput greater than 1 bbl/day 

(equivalent emissions of 6 tpy);

Regulatory Option 3: Control condensate storage tanks with a throughput greater than 2 bbl/day 

(equivalent emissions of 12 tpy);

Regulatory Option 1: Control condensate storage tanks with a throughput greater than 0.5 

bbl/day (equivalent emissions of 30 tpy);

As shown in Table 7-10, Regulatory Option 1 is not cost effective condensate storage tanks with a 

throughput of 0.5 bbl/day. Therefore Regulatory Option 1 is rejected. Since the cost effectiveness 

associated with Regulatory Option 2 is acceptable ($3,288/ton), this option was selected. As shown in 

Table 7-5, Model Condensate Tank Categories F, G, and H have throughputs greater than 1 bbl/day and 

emissions greater than 6 tpy. Therefore, for the purposes of determining impacts, the populations of new 

and modified condensate storage tanks associated with categories F, G, and H are assumed to be 

required to reduce their emissions by 95 percent, a total of 94 new or modified condensate tanks.

A similar evaluation was performed for crude oil tanks and is presented in Table 7-11 for the following 

regulatory options:

Regulatory Option 1: Control crude oil storage tanks with a throughput greater than 1 bbl/day 

(equivalent emissions of 0.3 tpy);

Regulatory Option 2: Control condensate storage tanks with a throughput greater than 5 bbl/day 

(equivalent emissions of 1.5 tpy);

Regulatory Option 3: Control condensate storage tanks with a throughput greater than 20 bbl/day 

(equivalent emissions of 6 tpy);

Regulatory Option 1: Control condensate storage tanks with a throughput greater than 50 bbl/day 

(equivalent emissions of 15 tpy);
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As shown in Table 7-11, Regulatory Options 1 and 2 are not cost effective crude oil storage tanks with a 

throughput of 1 and 5 bbl/day, respectively. Therefore Regulatory Options 1 and 2 are rejected. Since 

the cost effectiveness associated with Regulatory Option 3 is acceptable ($3,422/ton), this option was 

selected. As shown in Table 7-5, Model Crude Oil Tank Categories G and H have throughputs greater 

than 20 bbl/day and emissions greater than 6 tpy. Therefore, for the purposes of determining impacts, 

the populations of new and modified crude oil storage tanks associated with categories G and H are 

assumed to be required to reduce their emissions by 95 percent, a total of 209 new or modified 

condensate tanks.

. The regulatory options and Table 7-11 presents the options for crude oil tanks. OPtion

As shown in Table 7-10 it is not cost effective to regulate condensate storage tanks with a throughput of 

0.5 

We have determined that the cost effectiveness of control of storage vessels with VOC emissions of 6 

tpy would be approximately $3,150/ton, which we consider to be reasonable. In light of the above, we 

believe that it is important to control these tanks with significant VOC emissions and are therefore 

proposing to require that storage vessels with at least 6 tons per year of VOC emissions comply with the 

proposed NSPS standard of 95 percent VOC reduction.

7.5.2 

7.5.3 Identifications of Regulatory Options for ?

7.5.4 Nationwide Impacts of Regulatory Options

Comment [AHB1]: If 6 tpy is a significant 

amount, it should not matter whether the storage 

vessel is currently controlled or not.

Comment [BMoore2]: I agree, but I don’t 

understand what you’re getting at. We’re saying that 

if a tank emits at least 6 tpy, it will be cost-effective 

to control it by 95%.
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7.6 References

1. National Emissions Standards for Hazardous Air Pollutants for Source Categories: Oil and 

Natural Gas Production and Natural Gas Transmission and Storage – Background Information 

for Proposed Standards. U. S. Environmental Protection Agency, Research Triangle Park, NC. 

Publication No. EPA-453/R-94-079a. April 1997.

2. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2008. U.S. Environmental 

Protection Agency, Research Triangle Park, NC. Publication No. EPA 430-R-10-006. April 15, 

2010.

3. Inventory of U.S. Greenhouse Gas Emissions and Sinks: 1990 – 2007. U.S. Environmental 

Protection Agency, Research Triangle Park, NC. Publication No. EPA 430-R-09-004. April 15, 

2009.

4. U.S. Environmental Protection Agency. Lessons Learned from Natural Gas STAR Partners: 

Installing Vapor Recovery Units on Crude Oil Storage Tanks. Publication No. EPA 430-B-03-

015. October 2003.

5. Need to insert a reference for E&P TANKS here

6. Grubert, D., EC/R Incorporated, to B. Moore, Fuels and Incineration Group, U.S. Environmental 

Protection Agency, Research Triangle Park, NC. Summary of the October 12, 2010 Meeting 

Between the EPA and American Petroleum Institute. July 28, 2011.

7. U.S. Energy Information Administration. Table 4a. U.S. Crude Oil and Liquid Fuels Supply, 

Consumption, and Inventories. Available on the Internet at 

http://www.eia.gov/emeu/steo/pub/cf_tables/steotables.cfm?tableNumber=9

8. Memorandum from Wilson, D., et al, ERG, to A. Pope, U.S. Environmental Protection Agency. 

Documentation for NEI Updates for Oil and Natural Gas Production and Natural Gas 

Transmission and Storage. March 15, 2011.

9. U. S. Environmental Protection Agnecy, Washington, DC. Lessons Learned from Natural Gas 

STAR Partners: Installing Vapor Recovery Units on Crude Oil Storage Tanks. October 2003. 

Publication No. EPA-430-B-03-015.

10. Initial Economic Impact Analysis for Proposed State-Only Revisions to the Air Quality Control 

Commission’s Regulation Number 7, “Emissions of Volatile Organic Compounds.” September 

18, 2008. 

11. Insert reference for CE indices
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12

. U.S. Environmental Protection Agency. AP 42, Fifth Edition, Volume I, Chapter 13.5 Industrial 

Flares. Office of Air Quality Planning & Standards. 1991

13

. U.S. Environmental Protection Agency. Air Pollution Control Technology Fact Sheet: FLARES. 

Clean Air Technology Center.

14. Insert reference for CE indices

15. Hendler, A., URS Corporation, Austin, TX, et al. VOC Emissions From Oil and Condensate 

Storage Tanks. Prepared for Texas Environmental Research Consortium, The Woodlands, TX. 

October 31, 2006 (revised April 2, 2009).