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- 1 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. Fina lly, 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, cond ensates, 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 befor e 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 losse s 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 c ondensates 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 flas h 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 theTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 2 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 compon ent 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 E missions Data

7.2.1 Summary of Major Studies and Emissions
Given the po tentially 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 bat teries 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) f or oil and natural gas production facilities (40 CFR part 63, subpart HH), model plants were developed to represent condensate tank batteries across the industry. 1 To estimate the current condensate battery population and distribution across the model plan ts, 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 ex isting condensate tanks in 2008. Condensate throughput data from the U.S. Greenhouse Gas Emissions Inventory 2 , 3 was used to scale the condensate tank populations for each model condensate tank battery under the assumption that an increase in condensate pro duction would be accompanied by a proportionalTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 3 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 conde nsate production was then distributed across the model condensate batteries in the same proportion as was done for the NESHAP. T he 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 w as 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

co ndensate 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 ind ustry 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 charac teristics,

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 asTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 4 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 Appe ndix ??? . 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 we re modeled at a constant throughput 500 bbl. This was based on the assumption that tank emissions would increase in proportion with throughput. A n average emission factor was developed for each type of liquid. The average of condens ate tank VOC emissions w as 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,

r eferred 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 i n 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 Numbe r 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 wit h 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 ofTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 5 this document for the year 2015. Therefore, using the f orecast function in Microsoft Excel ® , crude oil production was predicted for the year 2015. a From 2009 to 2015, b the expected growth of crude oil production was projected to be 8.25 pe rcent (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 expect ed 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 previous ly, to determine the impact of a regulation, was first necessary to determine the current level of emissions fr om the sources being evaluated, or baseline emissions. T o 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 sto rage 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. 8 There 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 c ondensate 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 nation wide 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 w as considered an outlier for production and therefore was not used in this analysis.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 6 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 wit h 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 separ ator 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 VO C 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 processin g. 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 CETSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 7 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 imp acts expected due to the use of a VRU

.
7.4.3 Flare

7.4.3.1 Des cription and Effectiveness
Flares are also used to control emissions from condensate and crude oil storage tanks. A flare is a high

temperature 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 o f flares installed for the oil and gas sector are usually more crude and are assumed achieve 95 percent efficiency. 10 Because tank batteries are ty

pically 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 attempt s to relight it, documents the duration of time when the pilot is not lit, and notifies and o perator 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 prop osed 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, includi ng 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 andTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 8 installation was estimated to be $ 32,301 . These cost data are presen ted 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 di oxide, and smoke/particulates. R eliable 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 seconda ry emission s 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 signif icantly, 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 ve ssels 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 applicab ility 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 th roughput 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 reduct ion 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 be cause 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.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 9 To conduct this evaluation, emission factor data from a study prepared for the Texas Environmental Research Consortium 15 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 condensat e 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 emission s 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 emiss ions 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 a cceptable ($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 populati ons 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 tan ks 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 w ith 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 tank s with a throughput greater than 50 bbl/day (equivalent emissions of 15 tpy);TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 10 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 emiss ions 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 n ew 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 determi ned 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 signif icant 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 Impac ts 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%.TSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 11 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 Triang le 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

. Inv entory 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 G as 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 F uels 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 Contro l Commission’s Regulation Number 7, “Emissions of Volatile Organic Compounds.” September 18, 2008.
11

. Insert reference for CE indicesTSD CHAPTER UPDATE INTERNAL DRAFT: DO NOT CITE, QUOTE OR DISTRIBUTE

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- 12 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).