De Minimis for Air Emissions

• Permit By Rule (formerly called a Standard Exemption)
• Standard Permit
• New Source Review Permit (Air Quality Permit)

If a small business owner or local government representative determines that an operation or activity meets the requirements of the De Minimis Rule and can show suitable proof that de minimis applies to their location, then no other state air authorization is required.

Ways to be De Minimis

List of De Minimis Facilities

Paragraph 1 of the rule is the easiest way to determine if an operation qualifies as de minimis by providing for an approved list. That list may be obtained at:

• List of De Minimis Facilities
• Steps to Amend the “List of De Minimis Facilities or Sources”

The list may also be obtained by calling the TCEQ’s Air Permits Division in Austin at 512/239-1240 and asking for the latest list of De Minimis Facilities.

De Minimis Rule

A.  Material Use – Paragraph 2 of the rule shows de minimis limits by the amount and type of materials that are allowed to be used in a year’s time. View the rule at 30 Texas Administrative Code, Chapter 116

B.   Effects Screening Levels (ESL) – Paragraph 3 of the rule shows how a facility meets the De Minimis Rule by evaluating the daily and annual emissions from the site. This chart shows the sitewide emission rate caps based on ESL: 30 TAC Chapter 116.119(a)(3) (PDF), (Help with PDF)

Record Keeping: It’s the Law

Although record keeping is important for any operation, it is especially important for a small business or local government claiming de minimis. The overall requirements for keeping appropriate records and the authorization for TCEQ investigators to examine those records are found in the Texas Health and Safety Code, Subtitle C, Air Quality, Chapter 382: Monitoring Requirements and Examination of Records (Section 382.016)

At a minimum, de minimis record keeping should consist of invoices for amounts of materials purchased. Facility owners and operators should maintain enough information to demonstrate they meet the De Minimis Rule requirements. Remember that these records must be produced upon request.

In Conclusion

The phrase “de minimis” literally means “of minimum impact.” It is intended that qualification for de minimis means there will be no significant contamination of the air. And it is also important to remember that the entire job site must meet de minimis standards in order to qualify under this rule.

Don’t forget that de minimis, if it qualifies, is just one of four options when it comes to satisfying state air authorization requirements in Texas. De minimis and Permit By Rule are attractive to small business owners and local government facility operators because there are no fees involved and the paperwork is minimal. But the two other options, a Standard Permit or a New Source Review Permit, may also be utilized, especially if it is felt that future growth would generate air emissions above the amounts allowed by de minimis or Permit By Rule.

EPA Method 21

METHOD 21 – DETERMINATION OF VOLATILE

ORGANIC COMPOUND LEAKS

1.0 Scope and Application.

1.1 Analytes.

Analyte CAS No.

Volatile Organic Compounds

(VOC)

No CASE number assigned

1.2 Scope. This method is applicable for the determination of VOC leaks from process equipment. These sources include, but are not limited to, valves, flanges and other connections, pumps and compressors, pressure relief devices, process drains, open-ended valves, pump and compressor seal system degassing vents, accumulator vessel vents, agitator seals, and access door seals.

1.3 Data Quality Objectives. Adherence to the requirements of this method will enhance the quality of the data obtained from air pollutant sampling methods.

2.0 Summary of Method.

2.1 A portable instrument is used to detect VOC leaks from individual sources. The instrument detector type is not specified, but it must meet the specifications and performance criteria contained in Section 6.0. A leak definition concentration based on a reference compound is specified in each applicable regulation. This method is intended to locate and classify leaks only, and is not to be used as a direct measure of mass emission rate from individual sources.

3.0 Definitions.

3.1 Calibration gas means the VOC compound used to adjust the instrument meter reading to a known value. The calibration gas is usually the reference compound at a known concentration approximately equal to the leak definition concentration.

3.2 Calibration precision means the degree of agreement between measurements of the same known value, expressed as the relative percentage of the average difference between the meter readings and the known concentration to the known concentration.

3.3 Leak definition concentration means the local VOC concentration at the surface of a leak source that indicates that a VOC emission (leak) is present. The leak definition is an instrument meter reading based on a reference compound.

3.4 No detectable emission means a local VOC concentration at the surface of a leak source, adjusted for local VOC ambient concentration, that is less than 2.5 percent of the specified leak definition concentration, that indicates that a VOC emission (leak) is not present.

3.5 Reference compound means the VOC species selected as the instrument calibration basis for specification of the leak definition concentration. (For example, if a leak definition concentration is 10,000 ppm as methane, then any source emission that results in a local concentration that yields a meter reading of 10,000 on an instrument meter calibrated with methane would be classified as a leak. In this example, the leak definition concentration is 10,000 ppm and the reference compound is methane.)

3.6 Response factor means the ratio of the known concentration of a VOC compound to the observed meter reading when measured using an instrument calibrated with the reference compound specified in the applicable regulation.

3.7 Response time means the time interval from a step change in VOC concentration at the input of the sampling system to the time at which 90 percent of the corresponding final value is reached as displayed on the instrument readout meter.

4.0 Interferences. [Reserved]

5.0 Safety.

5.1 Disclaimer. This method may involve hazardous materials, operations, and equipment. This test method may not address all of the safety problems associated with its use. It is the responsibility of the user of this test method to establish appropriate safety and health practices and determine the applicability of regulatory limitations prior to performing this test method.

5.2 Hazardous Pollutants. Several of the compounds, leaks of which may be determined by this method, may be irritating or corrosive to tissues (e.g., heptane) or may be toxic (e.g., benzene, methyl alcohol). Nearly all are fire hazards. Compounds in emissions should be determined through familiarity with the source. Appropriate precautions can be found in reference documents, such as reference No. 4 in Section 16.0.

6.0 Equipment and Supplies.

A VOC monitoring instrument meeting the following specifications is required:

6.1 The VOC instrument detector shall respond to the compounds being processed. Detector types that may meet this requirement include, but are not limited to, catalytic oxidation, flame ionization, infrared absorption, and photo-ionization.

6.2 The instrument shall be capable of measuring the leak definition concentration specified in the regulation.

6.3 The scale of the instrument meter shall be readable to ±2.5 percent of the specified leak definition

concentration.

6.4 The instrument shall be equipped with an electrically driven pump to ensure that a sample is provided to the detector at a constant flow rate. The nominal sample flow rate, as measured at the sample probe tip, shall be 0.10 to 3.0 l/min (0.004 to 0.1 ft3/min) when the probe is fitted with a glass wool plug or filter that may be used to prevent plugging of the instrument.

6.5 The instrument shall be equipped with a probe or probe extension for sampling not to exceed 6.4 mm (1/4 in) in outside diameter, with a single end opening for admission of sample.

6.6 The instrument shall be intrinsically safe for operation in explosive atmospheres as defined by the National Electrical Code by the National Fire Prevention Association or other applicable regulatory code for operation in any explosive atmospheres that may be encountered in its use. The instrument shall, at a minimum, be intrinsically safe for Class 1, Division 1 conditions,and/or Class 2, Division 1 conditions, as appropriate, as defined by the example code. The instrument shall not be operated with any safety device, such as an exhaust flame arrestor, removed.

7.0 Reagents and Standards.

7.1 Two gas mixtures are required for instrument calibration and performance evaluation:

7.1.1 Zero Gas. Air, less than 10 parts per million by volume (ppmv) VOC.

7.1.2 Calibration Gas. For each organic species that is to be measured during individual source surveys, obtain or prepare a known standard in air at a concentration approximately equal to the applicable leak definition specified in the regulation.

7.2 Cylinder Gases. If cylinder calibration gas mixtures are used, they must be analyzed and certified by the manufacturer to be within 2 percent accuracy, and a shelf life must be specified. Cylinder standards must be either reanalyzed or replaced at the end of the specified shelf life.

7.3 Prepared Gases. Calibration gases may be prepared by the user according to any accepted gaseous preparation procedure that will yield a mixture accurate to within 2 percent. Prepared standards must be replaced each day of use unless it is demonstrated that degradation does not occur during storage.

7.4 Mixtures with non-Reference Compound Gases. Calibrations may be performed using a compound other than the reference compound. In this case, a conversion factor must be determined for the alternative compound such that the resulting meter readings during source surveys can be converted to reference compound results.

8.0 Sample Collection, Preservation, Storage, and Transport.

8.1 Instrument Performance Evaluation. Assemble and start up the instrument according to the manufacturer’s instructions for recommended warmup period and preliminary adjustments.

8.1.1 Response Factor. A response factor must be determined for each compound that is to be measured, either by testing or from reference sources. The response factor tests are required before placing the analyzer into service, but do not have to be repeated at subsequent intervals.

8.1.1.1 Calibrate the instrument with the reference compound as specified in the applicable regulation. Introduce the calibration gas mixture to the analyzer and record the observed meter reading. Introduce zero gas until a stable reading is obtained. Make a total of three measurements by alternating between the calibration gas and zero gas. Calculate the response factor for each repetition and the average response factor.

8.1.1.2 The instrument response factors for each of the individual VOC to be measured shall be less than 10 unless otherwise specified in the applicable regulation.When no instrument is available that meets this specification when calibrated with the reference VOC specified in the applicable regulation, the available instrument may be calibrated with one of the VOC to be measured, or any other VOC, so long as the instrument then has a response factor of less than 10 for each of the individual VOC to be measured.

8.1.1.3 Alternatively, if response factors have been published for the compounds of interest for the instrument or detector type, the response factor determination is not required, and existing results may be referenced. Examples of published response factors for flame ionization and catalytic oxidation detectors are included in References 1-3 of Section 17.0.

8.1.2 Calibration Precision. The calibration precision test must be completed prior to placing the analyzer into service and at subsequent 3-month intervals or at the next use, whichever is later.

8.1.2.1 Make a total of three measurements by alternately using zero gas and the specified calibration gas. Record the meter readings. Calculate the average algebraic difference between the meter readings and the known value. Divide this average difference by the known calibration value and multiply by 100 to express the resulting calibration precision as a percentage.

8.1.2.2 The calibration precision shall be equal to or less than 10 percent of the calibration gas value.

8.1.3 Response Time. The response time test is required before placing the instrument into service. If a modification to the sample pumping system or flow configuration is made that would change the response time, a new test is required before further use.

8.1.3.1 Introduce zero gas into the instrument sample probe. When the meter reading has stabilized, switch quickly to the specified calibration gas. After switching, measure the time required to attain 90 percent of the final stable reading. Perform this test sequence three times and record the results. Calculate the average response time.

8.1.3.2 The instrument response time shall be equal to or less than 30 seconds. The instrument pump, dilution probe (if any), sample probe, and probe filter that will be used during testing shall all be in place during the response time determination.

8.2 Instrument Calibration. Calibrate the VOC monitoring instrument according to Section 10.0.

8.3 Individual Source Surveys.

8.3.1 Type I – Leak Definition Based on Concentration. Place the probe inlet at the surface of the component interface where leakage could occur. Move the probe along the interface periphery while observing the instrument readout. If an increased meter reading is observed, slowly sample the interface where leakage is indicated until the maximum meter reading is obtained. Leave the probe inlet at this maximum reading location for approximately two times the instrument response time. If the maximum observed meter reading is greater than the leak definition in the applicable regulation, record and report the results as specified in the regulation reporting requirements. Examples of the application of this general technique to specific equipment types are:

8.3.1.1 Valves. The most common source of leaks from valves is the seal between the stem and housing. Place the probe at the interface where the stem exits the packing gland and sample the stem circumference. Also, place the probe at the interface of the packing gland take-up flange seat and sample the periphery. In addition, survey valve housings of multipart assembly at the surface of allinterfaces where a leak could occur.

8.3.1.2 Flanges and Other Connections. For welded flanges, place the probe at the outer edge of the flange gasket interface and sample the circumference of the flange. Sample other types of nonpermanent joints (such as threaded connections) with a similar traverse.

8.3.1.3 Pumps and Compressors. Conduct a circumferential traverse at the outer surface of the pump or compressor shaft and seal interface. If the source is a rotating shaft, position the probe inlet within 1 cm of the shaft-seal interface for the survey. If the housing configuration prevents a complete traverse of the shaft periphery, sample all accessible portions. Sample all other joints on the pump or compressor housing where leakage could occur.

8.3.1.4 Pressure Relief Devices. The configuration of most pressure relief devices prevents sampling at the sealing seat interface. For those devices equipped with an enclosed extension, or horn, place the probe inlet at approximately the center of the exhaust area to the atmosphere.

8.3.1.5 Process Drains. For open drains, place the probe inlet at approximately the center of the area open to the atmosphere. For covered drains, place the probe at the surface of the cover interface and conduct a peripheral traverse.

8.3.1.6 Open-ended Lines or Valves. Place the probe inlet at approximately the center of the opening to the atmosphere.

8.3.1.7 Seal System Degassing Vents and Accumulator Vents. Place the probe inlet at approximately the center of the opening to the atmosphere.

8.3.1.8 Access door seals. Place the probe inlet at the surface of the door seal interface and conduct a peripheral traverse.

8.3.2 Type II – “No Detectable Emission”. Determine the local ambient VOC concentration around the source by moving the probe randomly upwind and downwind at a distanceof one to two meters from the source. If an interference exists with this determination due to a nearby emission or leak, the local ambient concentration may be determined at distances closer to the source, but in no case shall the distance be less than 25 centimeters. Then move the probe inlet to the surface of the source and determine the concentration as outlined in Section 8.3.1. The difference between these concentrations determines whether there are no detectable emissions. Record and report the results as specified by the regulation. For those cases where the regulation requires a specific device installation, or that specified vents be ducted or piped to a control device, the existence of these conditions shall be visually confirmed. When the regulation also requires that no detectable emissions exist, visual observations and sampling surveys are required.

Examples of this technique are:

8.3.2.1 Pump or Compressor Seals. If applicable, determine the type of shaft seal. Perform a survey of the local area ambient VOC concentration and determine if detectable emissions exist as described in Section 8.3.2.

8.3.2.2 Seal System Degassing Vents, Accumulator Vessel Vents, Pressure Relief Devices. If applicable, observe whether or not the applicable ducting or piping exists. Also, determine if any sources exist in the ducting or piping where emissions could occur upstream of the control device. If the required ducting or piping exists and there are no sources where the emissions could be vented to the atmosphere upstream of the control device, then it is presumed that no detectable emissions are present. If there are sources in the ducting or piping where emissions could be vented or sources where leaks could occur, the sampling surveys described in Section 8.3.2 shall be used to determine if detectable emissions exist.

8.3.3 Alternative Screening Procedure.

8.3.3.1 A screening procedure based on the formation of bubbles in a soap solution that is sprayed on a potential leak source may be used for those sources that do not have continuously moving parts, that do not have surface temperatures greater than the boiling point or less than the freezing point of the soap solution, that do not have open areas to the atmosphere that the soap solution cannot bridge, or that do not exhibit evidence of liquid leakage. Sources that have these conditions present must be surveyed using the instrument technique of Section 8.3.1 or 8.3.2.

8.3.3.2 Spray a soap solution over all potential leak sources. The soap solution may be a commercially available leak detection solution or may be prepared using concentrated detergent and water. A pressure sprayer or squeeze bottle may be used to dispense the solution. Observe the potential leak sites to determine if any bubbles are formed. If no bubbles are observed, the source is presumed to have no detectable emissions or leaks as applicable. If any bubbles are observed, the instrument techniques of

Section 8.3.1 or 8.3.2 shall be used to determine if a leak exists, or if the source has detectable emissions, as applicable.

9.0 Quality Control.

Section | Quality Control |  Measure Effect

8.1.2 Instrument calibration precision check Ensure precision and accuracy, respectively, of instrument response to 10.0 Instrument calibration standard

10.0 Calibration and Standardization.

10.1 Calibrate the VOC monitoring instrument as follows. After the appropriate warmup period and zero internal calibration procedure, introduce the calibration gas into the instrument sample probe. Adjust the instrument meter readout to correspond to the calibration gas value.

NOTE: If the meter readout cannot be adjusted to the proper value, a malfunction of the analyzer is indicated and corrective actions are necessary before use.

11.0 Analytical Procedures. [Reserved]

12.0 Data Analyses and Calculations. [Reserved]

13.0 Method Performance. [Reserved]

14.0 Pollution Prevention. [Reserved]

15.0 Waste Management. [Reserved]

16.0 References.

1. Dubose, D.A., and G.E. Harris. Response Factors of VOC Analyzers at a Meter Reading of 10,000 ppmv for Selected Organic Compounds. U.S. Environmental Protection

Agency, Research Triangle Park, NC. Publication No. EPA

600/2-81051. September 1981.

2. Brown, G.E., et al. Response Factors of VOC

Analyzers Calibrated with Methane for Selected Organic Compounds. U.S. Environmental Protection Agency, Research Triangle Park, NC. Publication No. EPA 600/2-81-022. May 1981.

3. DuBose, D.A. et al. Response of Portable VOC

Analyzers to Chemical Mixtures. U.S. Environmental Protection Agency, Research Triangle Park, NC. Publication No. EPA 600/2-81-110. September 1981.

4. Handbook of Hazardous Materials: Fire, Safety, Health. Alliance of American Insurers. Schaumberg, IL.1983.

17.0 Tables, Diagrams, Flowcharts, and Validation Data.

Fluid Catalytic Cracking Unit (FCCU)

A Fluid Catalytic Cracking Unit (FCCU) has been an integral part of oil refineries since 1942, when it was introduced in the United States by Exxon Corporation in response to a growing wartime need for hydrocarbon based fuels. An FCCU accepts chains of hydrocarbons and breaks them into smaller ones in a chemical process called cracking. This allows refineries to utilize their crude oil resources more efficiently, making more products such as gasoline for which there is a high demand.

Crude oil contains a wide variety of hydrocarbons of various lengths. Depending on the length of the hydrocarbon, it can be used in a variety of ways. For example, cooking gas usually has four carbons, while gasoline for cars is a longer chain, containing eight carbons. Lubricating oils are even longer, with 36 carbons in the hydrocarbon chain. When oil is refined, these hydrocarbons are separated out for use.

However, a barrel of crude oil will not always yield the desired ratio of hydrocarbons. For example, the market may be heavy for gasoline, but light for lubricating oil. Instead of discarding the lubricating oil, it is chemically cracked in an FCCU so that it can be turned into gasoline and other hydrocarbons with shorter changers. Hydrocarbons can be cracked in other ways, but chemical cracking in an FCCU is the most common and efficient.

The FCCU uses an extremely hot catalyst to crack the hydrocarbons into shorter chains. Zeolite, bauxite, silica-alumina, and aluminum hydrosilicate are all catalysts commonly used in an FCCU unit. Both the oil and catalyst in the FCCU are usually extremely hot, and the oil is often in a vapor form. The catalyst splits the long hydrocarbon chains into shorter units, and the mixture travels from the FCCU to another distillation column so that the cracked hydrocarbons can be extracted.

Catalysts can be reused for additional cracking after the carbon which coats them after the process has been removed. In the 1930s, when the concept of an FCCU first began to be developed, a team of scientists designed an FCCU which would work in a continuous cycling mode, capable of processing 13,000 barrels of oil a day. A continuous FCCU has a primary reactor, a distillation column for separating out the cracked hydrocarbons, and a regeneration unit for cleaning the catalysts and preparing them for reuse.

The use of an FCCU increases the yield and efficiency of a refinery, and for this reason has become integral to the petroleum processing industry.

Fluid Coker Unit (FCU)

There are three types of cokers used in oil refineries: Delayed coker, Fluid coker and Flexicoker.^[2][3] The one that is by far the most commonly used is the delayed coker.

A coker or coker unit is an oil refinery processing unit that converts the residual oil from the vacuum distillation column or the atmospheric distillation column into low molecular weight hydrocarbon gases, naphtha, light and heavy gas oils, and petroleum coke. The process thermally cracks the long chain hydrocarbon molecules in the residual oil feed into shorter chain molecules.

This coke can either be fuel grade (high in sulphur and metals) or anode grade (low in sulphur and metals). The raw coke directly out of the coker is often referred to as green coke.^[1] In this context, “green” means unprocessed. The further processing of green coke by calcining in a rotary kiln removes residual volatile hydrocarbons from the coke. The calcined petroleum coke can be further processed in an anode baking oven in order to produce anode coke of the desired shape and physical properties. The anodes are mainly used in the aluminium and steel industry.

Gaseous, Liquid and Solid Fuels

Gaseous Fuels

Gaseous fuels may be divided into four classes: natural gas, producer gas, water gas and coal gas.
Natural gas exists already formed in the earth, and is obtained by boring tube wells, similar to petroleum wells. Its essential heat producing constituents are methane (CH4) and hydrogen. It is the cheapest and most efficient of all fuels, when properly burned; but it requires a large amount of air for its combustion, and special burners must be used.
Producer gas is made by forcing air through a bed of incandescent coal or coke, in specially constructed furnaces. Its essential heat constituent is carbon monoxide (CO), of which it contains about 28 to 30 per cent. But it also contains about 63 per cent of nitrogen from the air, and some carbon dioxide, which dilute the gas very much, and reduce its calorific intensity greatly. It is extensively used for fuel, because of its cheapness, cleanliness, and the regularity of the temperature obtained.
In converting carbon to carbon monoxide, about one-third of the heat value of the carbon is set free, thus heating the gas very hot. If it is at once led, through short flues, into the combustion chamber and burned with air, a much higher temperature is obtained, than if it is permitted to cool before burning. In modern gas producers, this waste of heat is largely avoided by introducing steam into the incandescent coal, together with the air; the steam dissociates into hydrogen and oxygen, and the latter gas combines with the carbon, forming more carbon monoxide. These gases, mixing with the producer gas, increase its calorific intensity.

In the Siemens gas producer * (Fig. 17), the coal is introduced at (E), falls upon the step grate (B, B), and is brought to incandescence by air entering through the openings while steam is injected from the pipe (C), and the gas formed escapes through (A, A). The ashes fall through the grate (G) into the pit, which is kept closed
except when cleaning. A more modern producer (Taylor’s) is shown in Fig. 18. The coal rests on a bed of ashes (A, A), and air is forced through the blast pipe (F), raising the fuel to incandescence. The gas formed passes out by the pipe (E). The grate (G) is made to revolve by the crank at (B), and the ashes fall over the edge of the grate at (H). The bed of ashes is kept about 3 feet deep on the revolving bottom at all times. Steam from the pipe (D) is introduced with the air through the blast pipe, which is provided with a hood to disseminate them through the fuel. In all producer gas plants, the regenerative heating system is used.
The Siemens regenerative furnace is a type of this style of heating. This furnace is represented in its simplest form in :Fig. 19. The material to be heated is placed on the hearth of the furnace (A). There are four passages, B, C, D, and E, filled with loosely
piled fire-brick called the “checker work.” On their way to the chimney, the hot gases from the furnace pass through and heat two checker works, e.g. (B) and (C). ‘When they are sufficiently heated, the flow of furnace gases is turned into (D) and (E), through which they pass to the chimney. Then fuel gas is conducted through the hot passage (B), to the furnace (A), where it mixes

with air which has been heated by passing through (C). The temperature of (A) is thus much higher than if the air and gas arrived at (A) cold. While (B) and (C) are being thus cooled, (D) and (E), are being heated by the furnace gases, and after a time, the dampers are turned, and the gas made to pass through (E), and the air through (D), while the combustion products pass through (B) and (C) to the chimney. Hence the process is an alternating one, the checker works on one side being heated, while those on the other are giving up their heat to the gas and air respectively. Since the interstices between the bricks of the checker work frequently become clogged with ashes and soot, the combustion gases are sometimes passed through flues containing narrow tubes, through which the gas and air are passing to the furnace, in a direction opposite to that taken by the fire gases. The waste gases from blast furnaces contain over 30 per cent of carbon monoxide and about 63 per cent of nitrogen. These gases are largely employed near the furnaces for heating purposes. Water gas is sometimes usee1 as a fuel, but oftener as a constituent of illuminating gas. It is made by blowing steam over incandescent anthracite coal or coke, and is a mixture of about
45 per cent each of carbon monoxide and hydrogen, with small amounts of nitrogen, oxygen, and carbon dioxide. :For the best results, the temperature must not fall below 1000° C.; above this point, the reaction is:

But at lower temperatures, the following takes place:

smoke or soot. Its calorific value is about 3000 C. per cubic meter. One kilo of coke produces about 1.13 cubic meters of water gas, but anthracite gives a better yield ..
The fuel is brought to incandescence by a blast of air, and during this part of the process the heat generally goes to waste. When it is white hot, the air is cut off, and the steam is turned on; decomposition occurs, according to the first reaction above. As soon as the temperature falls below 1000° C., the steam is cut off and the air blast turned on till the coal is again white hot. Thus alternate blowings of air and steam are carried on. The generator gas produced by the air blast is sometimes saved and used, but in making illuminating gas it goes to waste. For illuminating gas, this water gas is “enriched” with naphtha.
Coal gas is made by distilling bituminous coal in retorts. It contains hydrogen and marsh gas in large quantities, – about 40 per cent of each, – besides small amounts of carbon monoxide, carbon dioxide, nitrogen, oxygen, and hydrocarbons of the CnH2n and CnH2n-2 series, which impart illuminating properties. It has a limited use in domestic stoves and as a source of power in gas engines.
The average composition of the various fuel gases is shown in
the following table * :-

When burned. with 20 per cent excess of air, and assuming that the escaping gases have a temperature of 500°F., 1000 cubic feet of gas will evaporate the following number of pounds of water, at from 6O° F. to 212° F. :-

Liquid Fuels

Fossil fuels are also generally liquid fuels. The most notable of these is gasoline. Although unproven, it is generally accepted that they formed from the fossilized remains of dead plants and animals by exposure to heat and pressure in the Earth’s crust.

Gasoline is the most widely used liquid fuel. Gasoline, as it is known in United States and Canada, or petrol in India, Britain, Australia, New Zealand, South Africa and many English-speaking countries, is made of hydrocarbon molecules forming aliphatic compounds, or chains of carbons with hydrogen atoms attached. However, many aromatic compounds (carbon chains forming rings) such as benzene are found naturally in gasoline and cause the health risks associated with prolonged exposure to the fuel.

Production of gasoline is achieved by distillation of crude oil. The desirable liquid is separated from the crude oil in refineries. Crude oil is extracted from the ground in several processes, the most commonly seen may be beam pumps. To create gasoline, petroleum must first be removed from crude oil.

Gasoline itself is actually not burned, but the fumes it creates ignite, causing the remaining liquid to evaporate. Gasoline is extremely volatile and easily combusts, making any leakage extremely dangerous. Gasoline for sale in most countries carries an octane rating. Octane is a measure of the resistance of gasoline to combusting prematurely, known as knocking. The higher the octane rating, the harder it is to burn the fuel, which allows for a higher compression ratio. Engines with a higher compression ratio produce more power (such as in race car engines). However, such engines actually require a higher octane fuel .

Conventional diesel is similar to gasoline in that it is a mixture of aliphatic hydrocarbons extracted from petroleum. Diesel may cost more or less than gasoline, but generally costs less to produce because the extraction processes used are simpler. Many countries (particularly in Europe, as well as Canada) also have lower tax rates on diesel fuels.

After distillation, the diesel fraction is normally processed to reduce the amount of sulfur in the fuel. Sulphur causes corrosion in vehicles, acid rain and higher emissions of soot from the tail pipe (exhaust pipe). In Europe, lower sulfur levels than in the United States are legally required. However, recent US legislation will reduce the maximum sulphur content of diesel from 3,000 ppm to 500 ppm by 2007, and 15 ppm by 2010. Similar changes are also underway in Canada, Australia, New Zealand and several Asian countries.

A diesel engine is a type of internal combustion engine which ignites fuel by compressing it (which in turn raises the temperature) as opposed to using an outside source, such as a spark plug.

Kerosene once used in kerosene lamps as an alternative to whale oil, is today mainly used in fuel for jet engines (more technically Avtur, Jet A, Jet A-1, Jet B, JP-4, JP-5, JP-7 or JP-8). One form of the fuel known as RP-1 is burned with liquid oxygen as rocket fuel. These fuel grade kerosenes meet specifications for smoke points and freeze points.

In the mid-20th century, kerosene or “TVO” (Tractor Vaporising Oil) was used as a cheap fuel for tractors. The engine would start on gasoline, then switch over to kerosene once the engine warmed up. A “heat valve” on the manifold would route the exhaust gases around the intake pipe, heating the kerosene to the point where it can be ignited by an electrical spark.

Kerosene is sometimes used as an additive in diesel fuel to prevent gelling or waxing in cold temperatures.

Biodiesel is similar to diesel, but has differences akin to those between petrol and ethanol. For instance, biodiesel has a higher cetane rating (45-60 compared to 45-50 for crude-oil-derived diesel) and it acts as a cleaning agent to get rid of dirt and deposits. It has been argued that it only becomes economically-feasible above oil prices of $80 (£40 or €60 as of late February, 2007) per barrel. This does however depend on locality, economic situation, government stance on biodiesel and a host of other factors- and it has been proven to be viable at much lower costs in some countries. Also, it gives about 10% less energy than ordinary diesel. NOTE: As with alcohols and petrol engines, taking advantage of biodiesel’s high cetane rating potentially overcomes the energy deficit compared to ordinary number 2 diesel.

Generally, the term alcohol refers to ethanol, the first organic chemical produced by humans,^[1] but any alcohol can be burned as a fuel. Ethanol and methanol are the most common, being sufficiently inexpensive to be useful.

Methanol is the lightest and simplest alcohol, produced from the natural gas component methane. Its application is limited due to its toxicity (similar to gasoline). Small amounts are used in some gasolines to increase the octane rating. Methanol-based fuels are used in some race cars and model airplanes.

Methanol is also called methyl alcohol or wood alcohol, the latter because it was formerly produced from the distillation of wood. It is also known by the name methyl hydrate.

Ethanol, also known as grain alcohol or ethyl alcohol, is most commonly used in alcoholic beverages. However, it may also be used as a fuel, most often in combination with gasoline. For the most part, it is used in a 9:1 ratio of gasoline to ethanol to reduce the negative environmental effects of gasoline.

There is increasing interest in the use of a blend of 85% fuel ethanol blended with 15% gasoline. This fuel blend called E85, has a higher fuel octane than most premium gasolines. When used in a modern Flexible fuel vehicle, it delivers more performance to the gasoline it replaces.^[2]

Ethanol for use in gasoline and industrial purposes may be called a fossil fuel because it is synthesized from the petroleum product ethylene, which is cheaper than production from fermentation of grains or sugarcane.

Butanol is an alcohol which can be used as a fuel in most gasoline internal combustion engines without engine modification. It is typically a product of the fermentation of biomass by the bacterium Clostridium acetobutylicum (also known as the Weizmann organism). This process was first delineated by Chaim Weizmann in 1916 for the production of acetone from starch for making cordite, a smokeless gunpowder.

The advantages of butanol are its high octane rating (over 100) and high energy content, only about 10% lower than gasoline, and subsequently about 50% more energy-dense than ethanol, 100% more so than methanol. Butanol’s only major disadvantages are its high flashpoint (95 °F or 35 °C), toxicity (note that toxicity levels exist but are not precisely confirmed), and the fact that the fermentation process for renewable butanol emits a foul odour. The Weizmann organism can only tolerate butanol levels up to 2% or so, compared to 14% for ethanol and yeast. Making butanol from oil produces no such odour, but the limited supply and environmental impact of oil usage defeats the purpose of alternative fuels. The cost of butanol is about $0.57-$0.58 per pound ($1250-$1320 per metric ton or $4 approx. per US gallon). Butanol is much more expensive than ethanol (approx. $1.50 per gallon) and methanol.

On June 20 2006, DuPont and BP announced that they were converting an existing ethanol plant to produce 9 million gallons of butanol per year from sugar beets. DuPont stated a goal of being competitive with oil at $30-$40 per barrel without subsidies, so the price gap with ethanol is narrowing.

Solid Fuels

Solid fuel refers to various types of solid material that are used as fuel to produce energy and provide heating, usually released through combustion.

Solid fuels include wood (see wood fuel), charcoal, peat, coal, Hexamine fuel tablets, and pellets made from wood (see wood pellets), corn, wheat, rye and other grains. Solid-fuel rocket technology also uses solid fuel (see solid propellants).

Solid fuels have long been used by humanity to create fire. Coal was the fuel source which enabled the industrial revolution, from firing furnaces, to running steam engines. Wood was also extensively used to run steam locomotives. Both peat and coal are still used in electricity generation today.

The use of some solid fuels (eg. coal) is restricted or prohibited in some urban areas, due to unsafe levels of toxic emissions. The use of other solid fuels such as wood is increasing as heating technology and the availability of good quality fuel improves. In some areas, smokeless coal is often the only solid fuel used. In Ireland, peat briquettes are used as smokeless fuel. They are also used to start a coal fire.

Greenhouse Gas Reporting Rule

In response to the FY2008 Consolidated Appropriations Act (H.R. 2764; Public Law 110–161), EPA has proposed a rule that requires mandatory reporting of greenhouse gas (GHG) emissions from large sources in the United States.

The proposed rule would collect accurate and comprehensive emissions data to inform future policy decisions.

In general, EPA proposes that suppliers of fossil fuels or industrial greenhouse gases, manufacturers of vehicles and engines, and facilities that emit 25,000 metric tons or more per year of GHG emissions submit annual reports to EPA.  The gases covered by the proposed rule are carbon dioxide (CO₂), methane (CH₄), nitrous oxide (N₂O), hydrofluorocarbons (HFC), perfluorocarbons (PFC), sulfur hexafluoride (SF₆), and other fluorinated gases including nitrogen trifluoride (NF₃) and hydrofluorinated ethers (HFE).

• It is mandatory
• “above appropriate thresholds”
• Covers all sectors of society – both upstream and downstream
• Uses the Clean Air Act as authority

MACT UUU

EPA issued new maximum achievable control technology (MACT) standards applicable to emission sources excluded from coverage under the petroleum refineries MACT on April 11, 2002 (67 FR 17762-17822). The new MACT standards, codified in Subpart UUU to 40 CFR Part 63, (The Code of Federal Regulations (CFR) is the codification of the general and permanent rules published in the Federal Register by the executive departments and agencies of the Federal Government)  regulate emissions from fluidized catalytic cracking units (FCCUs), catalytic reforming units (CRUs), and sulfur recovery units (SRUs) at petroleum refineries. In addition, the new standards require owners/ operators to implement work practice standards intended to limit hazardous air pollutant (HAP) emissions from bypass lines that can divert a vent stream away from a control device.

The new standards are expected to apply to sources at 132 of 164 existing petroleum refineries in the United States and U.S. territories. When fully implemented, the MACT standards are expected to reduce HAP emissions from affected petroleum refineries by about 11,000 tons year (tpy), or by about 87% from baseline emissions. [The expected emission reductions do not take into account reductions attributable to controls that will be installed pursuant to legal settlements reached over the past year with various petroleum refining companies.]

The Subpart UUU MACT standards allow owners/operators to choose from a variety of compliance options. For example, owners/operators of FCCUs that are not already subject to new source performance standards (NSPS) may choose to comply with any one of four compliance options. Alternatively, if an FCCU is already subject to NSPS requirements, continued compliance with the NSPS constitutes compliance with the FCCU emission limits in Subpart UUU.

Natural Gas Processing

Natural gas processing plants, or fractionators, are used to purify the raw natural gas extracted from underground gas fields and brought up to the surface by gas wells. The processed natural gas, used as fuel by residential, commercial and industrial consumers, is almost pure methane and is very much different from the raw natural gas.

Raw natural gas typically consists primarily of methane (CH₄), the shortest and lightest hydrocarbon molecule. It also contains varying amounts of:

• Heavier gaseous hydrocarbons: ethane (C₂H₆), propane (C₃H₈), normal butane (n-C₄H₁₀), isobutane (i-C₄H₁₀), pentanes and even higher molecular weight hydrocarbons. When processed and purified into finished by-products, all of these are collectively referred to as NGL (Natural Gas Liquids).
• Acid gases: carbon dioxide (CO₂), hydrogen sulfide (H₂S) and mercaptans such as methanethiol (CH₃SH) and ethanethiol (C₂H₅SH).
• Other gases: nitrogen (N₂) and helium (He).
• Water: water vapor and liquid water.
• Liquid hydrocarbons: perhaps some natural gas condensate (also referred to as casinghead gasoline or natural gasoline) and/or crude oil.
• Mercury: very small amounts of mercury primarily in elemental form, but chlorides and other species are possibly present.^[1]

The raw natural gas must be purified to meet the quality standards specified by the major pipeline transmission and distribution companies. Those quality standards vary from pipeline to pipeline and are usually a function of a pipeline system’s design and the markets that it serves. In general, the standards specify that the natural gas:

• Be within a specific range of heating value (caloric value). For example, in the United States, it should be about 1,035 ± 5% Btu per cubic foot of gas at 1 atmosphere and 60 °F (41 MJ ± 5% per cubic metre of gas at 1 atmosphere and 0 °C).
• Be delivered at or above a specified hydrocarbon dew point temperature (below which some of the hydrocarbons in the gas might condense at pipeline pressure forming liquid slugs which could damage the pipeline).
• Be free of particulate solids and liquid water to prevent erosion, corrosion or other damage to the pipeline.
• Be dehydrated of water vapor sufficiently to prevent the formation of methane hydrates within the gas processing plant or subsequently within the sales gas transmission pipeline.^[2][3]
• Contain no more than trace amounts of components such as hydrogen sulfide, carbon dioxide, mercaptans, nitrogen, and water vapor.

referred to as coalbed gas and it is also called sweet gas because it is relatively free of hydrogen sulfide. Maintain mercury at less than detectable limits (approximately 0.001 ppb by volume) primarily to avoid damaging equipment in the gas processing plant or the pipeline transmission system from mercury amalgamation and embrittlement of aluminum and other metals.^[1][4][5]

Types of raw natural gas wells

Raw natural gas comes primarily from any one of three types of wells: crude oil wells, gas wells, and condensate wells.

Natural gas that comes from crude oil wells is typically termed associated gas. This gas can exist separate from the crude oil in the underground formation, or dissolved in the crude oil.

Natural gas from gas wells and from condensate wells, in which there is little or no crude oil, is termed non-associated gas. Gas wells typically produce only raw natural gas, while condensate wells produce raw natural gas along with a very low density liquid hydrocarbon called natural gas condensate (sometimes also called natural gasoline or simply condensate).

Raw natural gas can also come from methane deposits in the pores of coal seams. Such gas is referred to as coalbed gas and it is also called sweet gas because it is relatively free of hydrogen sulfide.

Description of a natural gas processing plant

There are a great many ways in which to configure the various unit processes used in the processing of raw natural gas. The block flow diagram below is a generalized, typical configuration for the processing of raw natural gas from non-associated gas wells. It shows how raw natural gas is processed into sales gas pipelined to the end user markets.^{[6][7][8][9][10]} It also shows how processing of the raw natural gas yields these byproducts:

• Natural gas condensate
• Sulfur
• Ethane
• Natural gas liquids (NGL): propane, butanes and C₅+ (which is the commonly used term for pentanes plus higher molecular weight hydrocarbons)

Raw natural gas is commonly collected from a group of adjacent wells and is first processed at that collection point for removal of free liquid water and natural gas condensate. The condensate is usually then transported to an oil refinery and the water is disposed of as wastewater.

The raw gas is then pipelined to a gas processing plant where the initial purification is usually the removal of acid gases (hydrogen sulfide and carbon dioxide). There are many processes that are available for that purpose as shown in the flow diagram, but amine treating is the process that was historically used. However, due to a range of performance and environmental constraints of the amine process, a newer technology based on the use of polymeric membranes to separate the carbon dioxide and hydrogen sulfide from the natural gas stream has gained increasing acceptance.

The acid gases removed by membrane or amine treating can then be routed into a sulfur recovery unit which converts the hydrogen sulfide in the acid gas into elemental sulfur. There are a number of processes available for that conversion, but the Claus process is by far the one usually selected. The residual gas from the Claus process is commonly called tail gas and that gas is then processed in a tail gas treating unit (TGTU) to recover and recycle residual sulfur-containing compounds back into the Claus unit. Again, as shown in the flow diagram, there are a number of processes available for treating the Claus unit tail gas. The final residual gas from the TGTU is incinerated. Thus, the carbon dioxide in the raw natural gas ends up in the incinerator flue gas stack. is usually then transported to an oil refinery and the water is disposed of as wastewater.

The raw gas is then pipelined to a gas processing plant where the initial purification is usually the removal of acid gases (hydrogen sulfide and carbon dioxide). There are many processes that are available for that purpose as shown in the flow diagram, but amine treating is the process that was historically used. However, due to a range of performance and environmental constraints of the amine process, a newer technology based on the use of polymeric membranes to separate the carbon dioxide and hydrogen sulfide from the natural gas stream has gained increasing acceptance.

The acid gases removed by membrane or amine treating can then be routed into a sulfur recovery unit which converts the hydrogen sulfide in the acid gas into elemental sulfur. There are a number of processes available for that conversion, but the Claus process is by far the one usually selected. The residual gas from the Claus process is commonly called tail gas and that gas is then processed in a tail gas treating unit (TGTU) to recover and recycle residual sulfur-containing compounds back into the Claus unit. Again, as shown in the flow diagram, there are a number of processes available for treating the Claus unit tail gas. The final residual gas from the TGTU is incinerated. Thus, the carbon dioxide in the raw natural gas ends up in the incinerator flue gas stack.

The next step in the gas processing plant is to remove water vapor from the gas using either the regenerable absorption in liquid triethylene glycol (TEG)^[3], commonly referred to as glycol dehydration, or a Pressure Swing Adsorption (PSA) unit which is regenerable adsorption using a solid adsorbent.^[11] Other newer processes requiring a higher pressure drop like membranes or dehydration at supersonic velocity using, for example, the Twister Supersonic Separator may also be considered.

Mercury is then removed by using adsorption processes (as shown in the flow diagram) such as activated carbon or regenerable molecular sieves.^[1]

Nitrogen is next removed and rejected using one of the three processes indicated on the flow diagram:

• Cryogenic process^[12] using low temperature distillation. This process can be modified to also recover helium, if desired.
• Absorption process^[13] using lean oil or a special solvent^[14] as the absorbent.
• Adsorption process using activated carbon or molecular sieves as the adsorbent. This process may have limited applicability because it is said to incur the loss of butanes and heaver hydrocarbons.

The next step is to recover the natural gas liquids (NGL) for which most large, modern gas processing plants use another cryogenic low temperature distillation process involving expansion of the gas through a turbo-expander followed by distillation in a demethanizing fractionating column.^[15][16] Some gas processing plants use lean oil absorption process^[13] rather than the cryogenic turbo-expander process.

The residue gas from the NGL recovery section is the final, purified sales gas which is pipelined to the end-user markets.

The recovered NGL stream is processes through a fractionation train consisting of three distillation towers in series: a dethanizer, a depropanizer and a debutanizer. The overhead product from the deethanizer is ethane and the bottoms are fed to the depropanizer. The overhead product from the depropanizer is propane and the bottoms are fed to the debutanizer. The overhead product from the debutanizer is a mixture of normal and iso-butane, and the bottoms product is a C₅+ mixture. The recovered streams of propane, butanes and C₅+ are each “sweetened” in a Merox process unit to convert undesirable mercaptans into disulfides and, along with the recovered ethane, are the final NGL by-products from the gas processing plant.

TITLE V (from South Coast Air Quality Management District)

Title V is a federal program designed to standardize air quality permits and the permitting process for major sources of emissions across the country. The name “Title V” comes from Title V of the 1990 federal Clean Air Act Amendments which requires the Environmental Protection Agency (EPA) to establish a national, operating permit program. Accordingly, EPA adopted regulations [Title 40 of the Code of Federal Regulations, Chapter 1, Part 70 (Part 70)], which require states and local permitting authorities to develop and submit a federally enforceable operating permit programs for EPA approval. The South Coast Air Quality Management District (AQMD) adopted Regulation XXX – Title V Permits in 1993 to interface the federal permitting requirements with the submitted Title V permit program. On March 31, 1997, EPA granted interim approval to AQMD’s Title V program. The program submittal was finally approved on November 30, 2001.

Title V applies only to facilities that meet specific criteria.  This section provides general information on the following:

• Who is Subject to Title V?
• Title V Exemption

Who is Subject to Title V?

Title V Emission Thresholds

Title V only applies to “major sources.”  EPA defines a major source as a facility that emits, or has the potential to emit (PTE) any criteria pollutant or hazardous air pollutant (HAP) at levels equal to or greater than the Major Source Thresholds (MST). The MST for criteria pollutants may vary depending on the attainment status (e.g. marginal, serious, extreme) of the geographic area and the Criteria Pollutant or HAP in which the facility is located. There are three air basins within the jurisdiction of the AQMD. The following table shows how a facility may determine if it is a Title V major source based on MST for the three air basins (click here for map of the air basins).

Phase One and Phase Two Title V Permits

The Title V permitting program in the AQMD is implemented in two phases. In Phase One (March 1997 to March 2000), facilities were subject to the Title V permitting program if their total actual emissions (both for permitted and non-permitted equipment stated in their 1992 or later Annual Emissions Report) exceeded 80 percent of the MST. Facilities identified in Phase One were eligible for a three-year deferral from complying with the Title V permitting requirements if they demonstrated that the most recent, validated, reported emissions were less than the MST and a permanent change has occurred to explain the reduction in reported emissions. After three years, AQMD re-evaluates Title V applicability for these facilities for inclusion in Phase Two.

In Phase Two, all facilities whose PTE is at least equal to the MST must comply with the Title V permitting requirements. Facilities that have not demonstrated their PTE are evaluated for Title V applicability based on their total reported actual emissions exceeding 50 percent of the MST. Additional information pertaining to Title V applicability and PTE limitations is found in AQMD Rules 3001 and 3008.

AQMD Title V permits were earlier issued in a format developed for the NOx and SOx Regional Clean Air Incentives Market (RECLAIM) program. In March 1999, the AQMD Governing Board approved an alternative approach recommended by the Permit Streamlining Task Force to issue future Title V permits by compiling the existing equipment-based permit with Title V requirements. Reception to the alternative format was positive since it did not significantly deviate from the layout of the command and control permit, which is familiar to all permitted facilities.

Title V Exemption

Rule 301(p)(13) and Rule 306 provide a mechanism for a facility to request for an exemption from the Title V permitting program. The following options are available to the facility:

1. Demonstrate the Facility-wide PTE is below MST

A facility that demonstrates they are not a major source is not subject to the Title V permitting requirements except as provided in Rule 3001(c). This option requires submittal of Form 500-E, Form 400-A and applicable fees along with documentation to support that the facility-wide PTE is below the MST. Required documentation may include but not limited to emissions calculations, historical throughput records, basis for emission factors and source test results.

2. Limiting the Facility PTE below the MST

A facility may also be exempted from the Title V program by limiting their facility’s PTE below the MST. This scheme however requires that the new PTE be permanent and verifiably enforceable, typically done through enforceable permit change. The matrix below illustrates various scenarios under this option:

This option generally requires applying for a change of condition to existing permit by the addition of a facility emission cap below the MST. Submittal of Form 500-E, Form 400-A and Supplemental Form 400-E-XX for each affected permit unit, and applicable fees must accompany this exemption request.

3. Correcting the AER to reflect below 50 percent of MST

In submitting the AER, a facility may have incorrectly reported their actual emissions, which made them subject to Title V permitting program. A facility that has not demonstrated their PTE and whose actual emissions are below 50 percent of the MST may be exempted from the Title V program. Rule 3008 allows this option and is illustrated in the following scenarios:

This option requires a plan application if the previous AER is to be corrected to reflect less than 50 percent of the MST. Form 500-E, Form 400-A and applicable fees must be submitted if the request uses this option. Please note that it takes about six to eight months for the AQMD to validate the original AERs.  A separate request to amend the AER must be submitted to the Emissions Reporting Group in accordance with Rule 301(e)(8)(E).

In some instances, a facility may be requesting for exemption based on the most recent submitted AER that has not yet been validated. In this case, Form 500-E is sufficient for exemption request that accompanies a copy of the most recent AER provided that the AER requires no correction.

All annual reported emissions occurring in 2001 and thereafter must be less than 50 percent of the MST in order for the facility to demonstrate that they are not a major source.

This option is not available for facilities that were brought into Phase 1 of the Title V permitting program .

Turnarounds

Turnarounds are scheduled events wherein an entire process unit of an industrial plant (refinery, petrochemical plant, power plant, pulp and paper mill, etc.) is taken offstream for an extended period for revamp and/or renewal. Turnaround is a blanket term that encompasses more specific terms such as I&Ts (Inspection & Testing), debottlenecking projects, revamps and catalyst regeneration projects. Turnaround can also be used as a synonym of shutdowns and outages.

Turnarounds are expensive – both in terms of lost production while the process unit is offline and in terms of direct costs for the labor, tools, heavy equipment and materials used to execute the project. They are the most significant portion of a plant’s yearly maintenance budget and can affect the company’s bottom line if mismanaged.^[1] Turnarounds have unique project management characteristics^[2] which make them volatile and challenging.

Upstream, Midstream and Downstream

Upstream

The petroleum industry is usually divided into three major components: Upstream, midstream and downstream, though midstream operations are usually included in the downstream category.

The upstream oil sector is a term commonly used to refer to the searching for and the recovery and production of crude oil and natural gas. The upstream oil sector is also known as the exploration and production (E&P) sector.

The upstream sector includes the searching for potential underground or underwater oil and gas fields, drilling of exploratory wells, and subsequently operating the wells that recover and bring the crude oil and/or raw natural gas to the surface.

Midstream

The midstream industry processes, stores, markets and transports commodities such as crude oil, natural gas, natural gas liquids (LNGs, mainly ethane, propane and butane) and sulphur.

Downstream

The downstream oil sector is a term commonly used to refer to the refining of crude oil, and the selling and distribution of natural gas and products derived from crude oil. Such products include liquified petroleum gas (LPG), gasoline or petrol, jet fuel, diesel oil, other fuel oils, asphalt and petroleum coke.

The downstream sector includes oil refineries^[1], petrochemical plants, petroleum product distribution, retail outlets and natural gas distribution companies. The downstream industry touches consumers through thousands of products such as petrol, diesel, jet fuel, heating oil, asphalt, lubricants, synthetic rubber, plastics, fertilizers, antifreeze, pesticides, pharmaceuticals, natural gas and propane.