Geological Expertise in Oil and Gas Exploration

(Graphic from Oil & Gas Portal)

Geologists use a variety of tools to discover underground pockets of crude oil and natural gas. Without their expertise, the oil and gas industry would not exist.

Exploration

The first thing geologists must determine is the location of geological formations that can trap oil and gas underground. They do this by determining what kind of sedimentary rocks form the reservoir and what kind of chemical elements are present in the rocks. If sandstones and carbonates are present, this is a good indication that ancient organic matter once existed in that area which decayed and formed hydrocarbons. The hydrocarbons became trapped underground in the form of crude oil and natural gas (Busby, 1999, p. 15).

Geological methods include drawing maps of the surface and subsurface region and gathering rock samples.

Topographical maps in 2-D and 3-D visualize layers of rock and the horizontal and vertical placement of those layers. Rock formations are given a two-part name, the geographical location, which is usually the name of the nearby town, and the predominant type of rock (Busby, 1999, p. 19).

Subsurface maps include three elements: structural, which shows the elevation of rock layers; isopach, which indicates thickness; and lithofacies, which reveal variations in a single layer of rock (Busby, 1999, p. 20).

When geologists take rock samples, they extract samples from the core and gather “cuttings” (rock chips) for “assessing the formation’s lithology, hydrocarbon content, and ability to hold and produce gas” (Busby, 1999, p. 20). If they can figure out how the rock layers were formed, they can determine if the conditions were right for “the generation, accumulation, and trapping of hydrocarbons” (Busby, 1999, p. 21).

Geochemical methods use chemical and bacterial analyses of soil and water samples from the surface and the area around underground gas and oil deposits to determine the presence of hydrocarbons. “Micro-seeps” of petroleum can be detected in this way (Busby, 1999, p. 21).

Vitrinite reflectance uses a reflectance microscope to measure the percentage of light which is reflected from vitrinite (plant organic matter found in shale). The percentage can indicate the presence of gas and oil (Busby, 1999, p. 21).

Geophysical methods use sound waves (seismic vibration) to “determine the depth, thickness, and structure of subsurface rock layers and whether they are capable of trapping natural gas and crude oil” (Busby, 1999, p. 22). Computers are used to gather and analyze the data. Geologists can now use 2D, 3D, and 4D seismic imaging in their analysis (Natural Gas, 2013).

On land, explosives and vibrations are used to generate sound waves. The energy that bounces off the rock layers is detected as echoes by sensors called geophones (jugs) (Busby, 1999, p. 23).

Bright spots and flat spots can reveal where deposits of gas-oil and gas-water deposits might exist underground. Amplitude variation with offset (AVO) and geology related imaging programs (GRIP) can enhance the resolution and analysis of bright spots (Busby, 1999, p. 24).

“Cross-well” seismic technology uses seismic energy in one well and sensors in nearby wells to retrieve high-resolution images that have been used successfully in determining the presence of crude oil. It is now being used in natural gas exploration (Busby, 1999, p. 24).

Gravity meters are used to detect salt domes and other rock formations capable of trapping gas and oil. Magnetometers detect the thickness of basement rock and find faults. Computer models create hypothetical pictures of subsurface structures from mathematical computations (Busby, 1999, p. 25).

Drilling

Once geologists determine the geological and economic feasibility of drilling a well, a group of geologists, geophysicists, and engineers pinpoint the site for the well and its potential reservoir. They decide how deep the well should be. The average well is about 5,800 feet deep in the United States. The drilling company must then get permission to drill from the owners of the land and determine who owns the mineral rights.  They sign a lease to use the land for a certain length of time.  The drilling company then breaks ground (spudding) and keeps well logs (measurements) to determine the possibility of gas and oil formation and the porosity and permeability of the rock. The contractors who own the drilling rigs sign an agreement to drill to a certain depth and detail what equipment they will need. A pit is dug at the site and lined with plastic that holds unnecessary materials (Busby, 1999, p. 29-30).

Rotary drills, driven by a diesel engine, are the most common type of drill used because they can drill hundreds and even thousands of feet per day. The drill bit must be changed after 40 to 60 hours of drilling. Other drilling techniques include directional drilling, which allows drilling in multiple directions, horizontal drilling, which is used to enhance gas recovery and to inject fracturing fluids, and offshore drilling, which uses special equipment to drill in ocean water (Busby, 1999, p. 31-35).

Some of the drilling problems that come up include drilling a dry hold; a breakage inside the well; things falling into the well; and high pressures underground causing gas or water to flow into the well, changing the balance of the pressure in the well. Drilling must be halted then and the problem corrected (Busby, 1999, p.33).

Geologists use various tests to measure the probability that the well will produce enough oil and gas. Drilling-time measurements measure the rate of the bit’s penetration into the rock; mud logs measure the chemistry of mud and rock cuttings, looking for traces of gas; wireline logs sense electrical, radioactive, and sonic properties of rocks and fluids; electrical logs test rock for resistivity; gamma ray logs measure radioactivity; neutron logs measure rock density; caliper logs test the type of rock; dip logs look for the placement of rock layers; sonic/acoustic velocity logs measure the speed at which sound travels through rock. Traditionally, these tests were conducted on bare, uncased wells. But new technology allows testing to be done with the casing in place (Busby, 1999, p. 36-37).

If the well comes up dry, the well is plugged up and abandoned. If the well holds promise of a productive well, the bare well is “cased, or lined with metal pipe to seal it from the rock” (Busby, 1999, p.29). A foundation of cement is created. Then the casing is drilled with holes so gas can flow into the well. The flow rate of the gas is measured, and if productive, valves and fittings are installed in order to control the flow. Oil and gas products are separated at the wellhead. A gathering system is built after several wells are completed. Flow lines gather gas from several wells and transport it to a centralized processing facility (Busby, 1999, p. 37-38).

Transmission

“The pipeline industry carries natural gas from producers in the field to distribution companies and to some large industrial customers” (Busby, 1999, p. 43) through large pipes with high pressures, from 500 to 1,000 psi or 3,400 to 6,900 psi). Compressor stations along the lines maintain the pressures in the pipes. “As of the 1990s, more than 300,000 miles of gas pipelines criss-cross the United States, serving nearly 60 million gas customers” (Busby, 1999, p. 43).

Pipes are laid in trenches and coated inside with chemicals to prevent corrosion, improve light reflection, reduce water retention, reduce absorption of gas odorants, and to improve gas flow (Busby, 1999, p. 46-47).

Gas demand depends on weather, the season, and its use in power generation. Pipeline operators try to spread the costs over the whole year. Gas meters are used “to reduce costs and increase the accuracy of gas flow measurement” (Busby, 1999, p. 51).

Pipeline inspection and maintenance have to be done on a regular basis to detect gas leaks, address corrosion, repair damage, and to keep the gas flowing smoothly (Busby, 1999, p.  51-53).

Economic Concerns

During exploration, there is no guarantee that all the money spent on research, testing, and drilling will be recouped. If a well is productive, royalties must be paid to the owner of the mineral rights after all production costs are paid. State and federal governments regulate how many wells can exist per 640 acres and how much gas and oil can be produced over a certain time period. Offshore drilling, which has become more common, is very expensive because these oil rigs use special equipment and can drill as deep as 10,400 feet. When wells are losing pressure and running dry, companies must spend money on well stimulation. In fact, companies give priority to this because it costs less than exploring for new wells. It’s been estimated that the oil and gas companies spend roughly $5 billion on treating natural gas before it is ever transmitted through a pipeline. Pipelines and compressor stations must be built, inspected, repaired, and maintained. Environmental regulations cost companies money on research and new technologies (Busby, 1999, p. 15-54).

If oil and gas supplies diminish or are suddenly cut off, access to energy is decreased, and costs sky-rocket. When pipelines break or oil rigs are damaged or destroyed, this causes a disruption in the oil and gas supply. If the disruption lasts long enough, it can raise costs to the consumer. Political conflicts affect oil and gas supplies, energy costs, and the ability of companies to find new sources (Busby, 1999, p.15-54).

Dawn Pisturino

Thomas Edison State University

October 22, 2020; March 18, 2022

Copyright 2020-2022 Dawn Pisturino. All Rights Reserved!

Busby, R.L. (Ed.). (1999). Natural Gas in Nontechnical Language. Tulsa, OK: PennWell.

Natural Gas. (2013). Natural gas and the environment. Retrieved from

       http://www.naturalgas.org

The Basics of Gas Exploration, Production, and Distribution

Offshore natural gas drilling

The Basics of Gas Exploration, Production, and Distribution

Gas and oil traps are formed by geological events such as tectonic plate shifting, glacier movement, and extreme temperature changes. As long as the gas cannot escape from the area, it will be trapped in place (Blewett, 2010).

When reservoir rock is subjected to high pressure and other conditions, it can become fractured or deformed, creating a space that can fill up with oil or natural gas. Anticlines are structural traps which occur when layers of rock are pushed upward, causing an arch. Synclines occur when the rock is pushed downward. Domes are similar to anticlines but have a more rounded appearance (Busby, 1999).

Faults occur when rocks crack due to outside forces and sections, or plates, slide out of alignment. Sections of rock can slide upward (dip-slip) or sideways (strike-slip). Thrust faults appear on the earth’s surface as mountain ranges. Fractures can divide traps into smaller compartments and increase the permeability of sedimentary rocks. Shales and chalks are normally porous and impermeable. When fracturing occurs, it can make these rocks more permeable, making it possible for gas to get trapped inside the rocks (Busby, 1999).

Stratigraphic traps are harder to access than structural traps because the gas and oil have been trapped within the layers of rock. These traps form as the result of changes in the porosity and permeability of the rock due to the way in which sediment has been deposited. Gas cannot escape the rock. Large fields of gas and oil can be trapped in this way (Busby, 1999).

Combination traps have the characteristics of both structural and stratigraphic traps. A salt dome occurs when a large quantity of salt gets trapped in sedimentary layers and breaks through the earth’s surface, forming “a plug-like structure” (Busby, 1999).

Carbonate rock reservoirs formed when ancient caves collapsed, causing fractures in the rocks. A new cave system was created, forming a reservoir for gas and oil to be trapped inside (Busby, 1999).

In order for any oil or gas field to be productive, there must exist the right combination of “reservoir rock, trap, and cap rock or other seal” (Busby, 1999). There must be “source rock that has generated gas or oil, reservoir rock to hold the gas, a trap to seal it off, and the right timing” (Busby, 1999). Without a trap in place, the gas will disperse out of the area (Busby, 1999).

The largest producing gas fields in the United States are as follows:

Marcellus Shale is an unconventional shale formation which stretches beneath two-thirds of Pennsylvania and parts of New York, Ohio, West Virginia, Maryland, Kentucky, and Virginia. This area is estimated to hold 6 trillion cubic feet of natural gas.  The most productive wells lie 5,000 to 8,500 feet below the earth’s surface (Pennsylvania Department of Environmental Protection, 2020).

This natural gas can only be accessed through vertical and horizontal drilling and the use of hydraulic fracturing (fracking). The Pennsylvania Department of Environmental Protection inspects and monitors these wells “from construction to reclamation to ensure that the site has proper erosion controls in place, and that any waste generated in drilling and completing the well was properly handled and disposed. Also, unconventional well operators are required to submit a variety of reports regarding well drilling, completion, production, waste disposal, and well plugging” (Pennsylvania Department of Environmental Protection, 2020).

The Newark East gas field in Texas is composed of Barnett Shale. Currently, 5,600 wells and 150 rigs are in operation. The field is estimated to hold 1,951 billion cubic feet of natural gas (Geo ExPro, 2007; Oil Price, 2015).

The B-43 Area in Arkansas is estimated to hold 1,025 billion cubic feet of natural gas, but not much other information was available (Oil Price, 2015).

The San Juan Basin is found in Colorado and New Mexico. It is estimated that the field holds 1,024 billion cubic feet of natural gas. Not much other information was available (Oil Price, 2015).

The Haynesville/Bossier Shale formation is located in eastern Texas and western Louisiana. The natural gas is found at depths greater than 10,000 feet below the earth’s surface. The area is producing 2,680 million cubic feet per day of natural gas and 420 barrels per day of condensate (Railroad Commission, 2020).

The Pinedale gas field in Wyoming is the sixth largest gas field in the United States. It covers 70 square miles. Its layers of sandstone are 6,000 feet thick and form a 30-mile anticline. Operators use horizontal drilling to access the natural gas. In 2015, it produced 4 million barrels of gas condensate and 436 billion cubic feet of natural gas. Its gas reserves hold 40 trillion cubic feet of natural gas—enough to provide energy to the entire country for 22 months (American GeoSciences, 2018).

The Carthage natural gas field near Carthage, Texas produced 13,912,377 million cubic feet of natural gas in June 2020. Not much other information was available (Texas Drilling, 2020).

The Jonah field is located south of Pinedale, Wyoming. It covers 21,000 acres and is estimated to hold 10.5 trillion cubic feet of natural gas. Chevron is one of the energy companies involved in both Jonah and Pinedale (Wyoming History, 2014).

The Wattenberg field covers 180,000 acres in Colorado. Horizontal wells are drilled to access the natural gas. It has a complicated geological structure due to “crustal basement rock weakness [ caused by super-heated] organic Niobrara source rocks” (PDC Energy, 2020).

Prudhoe Bay in Alaska has been producing oil and gas for 40 years. It covers 213,543 acres and holds 46 trillion cubic feet of natural gas (NS Energy, 2020). Pump station 1, at the beginning of the Trans-Alaska Pipeline, is situated within the Prudhoe Bay field. The natural gas is held in place by “an overlying gas cap and in solution with the oil” (Department of Environmental Conservation, 2020). The Alaska LNG project will be using natural gas from the Prudhoe Bay field to produce liquefied natural gas (NS Energy, 2020).

The most common technique for drilling wells is rotary drilling because “it can drill several hundreds or thousands of feet in a day” (Busby, 1999). A long piece of steel pipe with a drill bit on the end is suspended from a rig and driven into the ground by a diesel engine. The rotating bit drilling into the earth “creates the wellbore or borehole” (Busby, 1999). The bit must be changed after 40 to 60 hours of drilling.

Directional drilling is being used more commonly now to access oil and natural gas in unconventional traps (tight formations). Rotary rigs can now drill in many different directions to reach gas in multiple areas, drill offshore, or drill under populated areas (Busby, 1999).

Horizontal drilling can increase the recovery of natural gas “from a thin formation . . . a low-permeability reservoir . . . isolated productive zones . . . by connecting vertical fractures . . . prevent production of excessive gas or water from above or below the reservoir . . . to inject fracturing fluids” (Busby, 1999).

Offshore drilling is more expensive because the average rig drills down to around 10,400 feet. “An offshore exploratory rig must be able to move across the water to different drilling sites” (Busby, 1999).

Drilling barges are used in shallow waters. Jack-up rigs can be raised or lowered and drill down to a depth of 350 feet. A semisubmersible platform floats on pontoons and anchors at the drilling site. These platforms can drill down to 2,000 feet. Drill ships float over the drill site and can drill down to almost any depth (Busby, 1999).

Once a productive field has been discovered, a fixed or a tension-leg platform is permanently anchored at the site. The legs on fixed platforms can be anchored with piles driven into the ocean floor; whereas, tension-leg platforms float above the field and are anchored by “steel tubes connected to heavy weights on the sea floor” (Busby, 1999).

Drilling a dry hole can be one of the biggest expenses associated with drilling wells. More common issues include something breaking inside the well or objects falling into the hole. Drilling must then be stopped and the problem corrected (Busby, 1999).

Pressures become higher as the rig drills deeper. When this occurs, gas and water “can flow into the well, dilute the drilling mud, and reduce its pressure” (Busby, 1999). When the flow of fluids is uncontrolled, this is called a blowout.

“Natural gas is produced from most reservoirs by expansion, where the pressure of the expanding gas underground forces it into the well” (Busby, 1999). When the pressure drops in the well, gas production decreases. It can be stimulated with the use of a compressor (Busby, 1999).

Once the gas has been purified and processed, it is transported through pipelines from the gas field to distribution companies and industrial customers. Compressor stations along the line maintain the pressure needed to keep the gas flowing smoothly through the pipe. The gas flow is measured at the beginning and end of each pipe section, at each compressor station, and each intersection where the pipe branches off into two pipelines. Large industrial customers receive natural gas directly to their facilities, which “requires high-volume meters” (Busby, 1999).

Economically, it is essential to measure natural gas flow accurately at all points of the supply chain because “an error of 1% in measuring 300 million ft3 of gas per day can lead to a difference of about $2 million per year” (Emerson, 2016). After all, customers pay for the amount of energy delivered.

Differential pressure (DP) meters “measure volumetric flow through a calibrated orifice (generally a plate), are inexpensive, and simple in concept” (Emerson, 2016). Measurements must be corrected for density (mass), temperature, pressure, and gas composition. DP meters are not as acceptable as more advanced technologies (Emerson, 2016).

Ultrasonic meters measure volumetric flow rates by measuring “speed and sound in the gas” (Emerson, 2016). They have an accuracy of 0.35% to 0.5%. Some are available with an accuracy of 0.25% (Emerson, 2016).

Coriolis meters “measure mass flow and density” (Emerson, 2016) but temperature, pressure, and gas composition still need to be measured. These meters tend to be rather expensive (Emerson, 2016).

Flow computers “measure, monitor, and may provide control of gas flow for all types of meters” (Emerson, 2016). They record data from volumetric flow measurement, temperature, gas composition, and density in order to calculate flow rate. Every calculation is dated and timed (Emerson, 2016).

Shale gas is usually composed of less than 50% methane and roughly 50% of ethane, propane, butane, pentane and other gases. CO2, H2S, and sand can also be present. DP meters are excellent meters to use at the gas field site and when impurities are removed from the gas (Emerson, 2016).

Once the natural gas has been purified of water and CO2, the natural gas is processed through liquid separators and H2S separators. At this point, a Coriolis meter or ultrasonic meter is used (Emerson, 2016).

Ultrasonic meters are generally used on transmission pipelines, while Coriolis meters are used on distribution lines. To accurately calculate the Btus (British thermal units) per pound, a gas chromatography device is used (Emerson, 2016). One Btu equals “the energy released by burning a match” (U.S. Energy Administration, 2020).

Dawn Pisturino

Thomas Edison State University

October 30, 2020

References

American GeoSciences. (2018). The pinedale gas field, wyoming. Retrieved from

https://www.americangeosciences.org/geoscience-currents/pinedale-gas-field-wyoming.

Blewett, R.L. (Ed.) (1999). Shaping a Nation: A Geology of Australia. Canberra: Australia

       National University.

Busby, R.L. (Ed.). (1999). Natural Gas in Nontechnical Language. Tulsa, OK: PennWell.

Department of Environmental Conservation. (2020). Prudhoe bay fact sheet. Retrieved from

https://www.dec.alaska.gov/

Emerson. (2016). Selecting flow meters for natural gas fiscal measurement. Retrieved from

https://www.emerson.com/documents/automation/article-selecting-flow-meters-for-natural-

       gas-fiscal-measurement-daniel-en-us-177810.pdf.

Geo ExPro. (2007). Producing gas from shales. Retrieved from

https://www.geoexpro.com/articles/2007/03/producing-gas-from-shales.

NS Energy. (2020). Prudhoe bay oil field. Retrieved from

Prudhoe Bay Oil Field

Oil Price. (2015). The top 10 largest oil and gas fields in the united states. Retrieved from

https://www.oilprice.com/Energy/

PDC Energy. (2020). Wattenberg field. Retrieved from

https://www.pdce.com/operations-overview/wattenberg-field/

Pennsylvania Department of Environmental Protection. (2020). Marcellus shale. Retrieved from

https://www.dep.pa.gov/Business/Energy/Pages/default.aspx.

Railroad Commission. (2020). Haynesville bossier shale information. Retrieved from

https://www.rrc.state.tx.us/oil-gas/major-oil-and-gas-formations/haynesvillebossier-shale-

       information/

Texas Drilling. (2020). Carthage. Retrieved from

       http://www.texas-drilling.com/panola-county/carthage.

Wyoming History. (2014). Jonah field and pinedale anticline natural gas success story.

       Retrieved from https://www.wyohistory.org/encyclopedia/jonah-field-and-pinedale-

       anticline-natural-gas-success-story.

U.S. Energy Administration. (2020). British thermal units. Retrieved from

https://www.eia.gov/energyexplained/units-and-calculators/british-thermal-units.php.

Why does Australia have so much Natural Gas?

Gorgon Project, Chevron.com

Chevron is a multinational corporation with offices, plants, pipelines, partnerships, and subsidiaries located all over the world. One of the company’s largest and most important overseas projects is the Gorgon Project – and associated smaller projects – situated off the coast of Western Australia.

Australia does not produce a lot of oil, but it produces an abundance of natural gas. This phenomenon is due to the geology of the Australian continent (Blewett, 2012, p. 221).

The Northern Carnarvon Basin, created during the Paleozoic period, is located off the northwestern coast of Australia, on the northwest shelf. “The basin is Australia’s premier hydrocarbon province where the majority of deep water wells have been drilled (greater than 500 meters water depth) . . . Almost all the hydrocarbon resources are reservoired within the Upper Triassic, Jurassic, and Lower Cretaceous sandstones beneath the regional early Cretaceous seal” (Geoscience Australia, 2020). The faults on this area run north or northeast, among “structural highs and sub-basins” (Geoscience Australia, 2020) which occurred over four geological phases involving glacial and tectonic activity (Geoscience Australia, 2020).

The basin covers 535,000 square kilometers, with water depths up to 4,500 meters. Paleozoic, Mesozoic, and Cenozoic sediment covers the area, up to 15,000 meters thick. The area comprises two Mesozoic petroleum supersystems (Geoscience Australia, 2020).

Total petroleum systems of the northwest shelf include the Dingo-Mungaroo/Barrow system and the Locker/Mungaroo/Barrow system. In the Dingo-Mungaroo/Barrow system, the hydrocarbon source rock is composed of Jurassic Dingo Claystone. The reservoir rocks comprise the Triassic Mungaroo Formation, Jurassic rocks, and the Cretaceous Barrow Group. In the Locker/Mungaroo/Barrow system, the source rock is composed of Triassic Locker Shale. The reservoir rocks comprise the Triassic Mungaroo Formation and the Cretaceous Barrow Group. Muderong Shale makes up the vast seal over much of the area (Bishop, 1999, p.6-7).

A total petroleum system is composed of several elements: the depocenter, which is the basin; the source, which is made of rocks containing organic materials; the reservoir, which is made of porous, permeable rock, such as sandstone; the seal, which is made of impermeable rock, such as shale; the trap, which holds the accumulation of source rocks; the overburden, which is composed of sediments subjected to heat; and the migration pathways, which allow the source rocks to form a link with the trap (Blewett, 2012, p. 176).

Additionally, there must be geochemical processes which cause “trap formation, hydrocarbon generation, expulsion, migration, accumulation, and preservation” in a precise order with exact timing (Blewett, 2012, p. 176). Millions of years of geological events, such as the shifting of tectonic plates and glacier movement, as well as extreme changes in weather, such as the change from the Ice Age to a more temperate climate, formed the particular geology which makes up the Australian continent and its surrounding oceans (Blewett, 2012, p. 217).

“The main trap styles in the [Carnarvon] basin are anticlines, horsts, fault roll-over structures, and stratigraphic pinch-outs beneath the regional seal” (Blewett, 2012, p. 220). Australia has an abundance of natural gas due to the type of vegetation which decayed and became trapped in “non-marine coaly source rocks” (Blewett, 2012, p. 221) and the fact that some basins did not evolve long enough to create the conditions to produce oil.

Chevron entered the Western Australia oil and gas market when it purchased Caltex in 1952. In 1980, the Gorgon natural gas field was discovered west of Barrow Island; and in 2003, Chevron received permission from the Western Australia government to build a natural gas plant on Barrow Island (Chevron Australia, 2020).

Barrow Island is located 60 kilometers off the northwest coast of Western Australia. Chevron’s Gorgon Project includes three liquefied natural gas (LNG) processing plants capable of producing 15.6 million tonnes per annum (MTPA), and a domestic natural gas plant capable of producing 300 terajoules of natural gas per day (Chevron Australia, 2020). According to the operators of the Dampier-Bunbury Pipeline, which transmits this natural gas to distributors, one terajoule of natural gas can provide energy to the average household in Western Australia for 50 years, so Chevron’s Gorgon Project is a significant contribution to Western Australia’s regional economy (Dampier Bunbury Pipeline, 2020). The project is expected to be productive for 40 or more years (Chevron Australia, 2020).

The onshore Gorgon Project also includes three acid gas removal units, two LNG tanks, four condensate tanks, three CO2 compression plants, two monoethylene glycol (MEG) processing plants, 2 inlet processing units, and ground flare capabilities. Marine facilities, an airport, employee housing, a fire station, laboratory, warehouse, workshop, and a permanent operations facility complete the physical structure of the Barrows Island onshore project (Chevron Australia, 2020).

“A subsea gas gathering system is located on the ocean floor at the Gorgon and Jansz-Io fields, located about 65 and 130 kilometers respectively off the west coast of Barrow Island” (Chevron Australia, 2020). From there, natural gas from both fields is transmitted to the Barrow Island facility by undersea pipelines. After processing, gas for domestic use is transmitted through a 90 kilometer domestic gas pipeline that ties in to the Dampier-Bunbury Natural Gas Pipeline. Once the LNG is processed, it is stored and shipped by large LNG tankers to Japan and other Asian countries (Chevron Australia, 2020).

The Dampier-Bunbury Pipeline (DBP), at 1600 kilometers long, is the longest pipeline in Australia. Built in 1984, it is expected to last for another 50 years. Every year, it receives 112,000 hours of planned maintenance to ensure its safety and optimal condition. Twenty-seven turbine compressor units, located at ten sites along the pipeline, exert enough pressure to push the natural gas along the pipeline. It has functioned at 99% efficiency for the last ten years. Owned by the Australian Gas Infrastructure Group, more than 2 million homes and businesses benefit from the pipeline. The company also supplies natural gas to power generators, mines, and manufacturers — and other companies can tie in to the pipeline (Dampier Bunbury Pipeline, 2020).

DBP owns 34,000 kilometers of distribution networks, 5,500 kilometers of transmission pipelines, 52 petrajoules of storage capacity, employs 315 workers, and contracts with 1,600 contractors. The company’s goal is to provide natural gas at the lowest possible cost. The company provides 21% natural gas for power generation; 39% for mineral processing; 9% for other industrial purposes; 9% for retail outlets; 22% for mining.  Alcoa and BHP Billiton are two of its large industrial customers. The company provides natural gas to Synergy and Alinta for power generation (Dampier Bunbury Pipeline, 2020).

DBP operates the Dampier-Bunbury Pipeline for the Australian Gas Infrastructure Group (AGIG). It also plans and constructs metering stations, executes the tie-ins for other companies, and provides an odorization service. In 2013, “DBP completed the metering station for the connection of the Chevron-operated Gorgon Project” (Dampier Bunbury Pipeline, 2020).

Transmission pipelines are usually 6-48 inches in diameter and can handle pressures of 200-1500 psi. The high pressures move the natural gas through the line. Distribution pipelines are separated into main lines and service lines and carry natural gas to homes and businesses. They operate at lower pressures for safety reasons (Pipeline Safety Trust, 2019).

Compressors fueled by electric or natural gas use high pressure to push the gas through the pipeline. Compressor stations are located about every 50 to 100 miles along the line, and pressures can be adjusted as needed (Pipeline Safety Trust, 2019).

Gas pipeline operators, such as DBP in Western Australia, monitor the pipeline for problems using “a Supervisory Control and Data Acquisition system (SCADA). A SCADA is a pipeline computer system designed to gather information such as flow rate through the pipeline, operational status, pressure, and temperature readings” (Pipeline Safety Trust, 2019). These readings help operators to address problems quickly and easily. Operators, for example, can isolate a section of pipe that is malfunctioning or adjust flow rates via the compressors and valves (Pipeline Safety Trust, 2019).

When a transmission line reaches the utility company’s “city gate,” it begins to transmit gas into the lower pressure distribution system that ultimately delivers the gas to homes and businesses. This is where the odorant is added to the gas. Gas mains, which are usually 2-24 inches in diameter, utilize pressures up to 200 psi. The service lines, on the other hand, only use pressures up to 10 psi (Pipeline Safety Trust, 2019).

The gas utility company is responsible for monitoring flow rates and pressures along the distribution line. When regulators sense a change in pressure, they will open or close in order to adjust the amount of pressure in the line. Relief valves release excess gas if the pressures build too high (Pipeline Safety Trust, 2019).

Pipeline operators, such as DBP in Western Australia, must monitor pipes for corrosion, leaks, breakages, and construction workers digging too close to the lines. They must follow pressure specifications determined by government regulatory bodies, otherwise, pipelines can become a safety and environmental hazard to the local community (Pipeline Safety Trust, 2019).

Barrow Island is a Class-A nature reserve, and Chevron has worked hard with the Western Australia government to maintain the local habitat for the native flora and fauna. Their goal to reduce CO2 emissions has led them to construct a CO2 injection system which allows them to inject excess CO2 from natural gas into a deep underwater trap called the Dupuy Formation, located two kilometers underneath Barrow Island. This system is projected to reduce greenhouse gas emissions by 40% and is fully supported by the Australian government (Chevron Australia, 2020).

Chevron is a well-respected energy corporation in Western Australia. The Gorgon Project alone is projected to contribute $400 billion to Australia’s Gross Domestic Product and $69 billion in taxes to the federal government between 2009 and 2040. With its booming natural gas industry in place, Australia is now a leading producer of natural gas in the world market (Chevron Australia, 2020).

Dawn Pisturino

Thomas Edison State University

October 27, 2020

Copyright 2020-2021 Dawn Pisturino. All Rights Reserved.

 References

Bishop, M.G. (1999). Total Petroleum Systems of the Northwest Shelf, Australia: The Dingo-

       Mungaroo/Barrow and the Locker/Mungaroo/Barrow. Reston: U.S. Geological Survey.

Blewett, R. (Ed.). (2012). Shaping a Nation: A Geology of Australia. Canberra: Australia

       National University.

Chevron Australia. (2020). Gorgon project overview. Retrieved from

https://www.australia.chevron.com.

Dampier Bunbury Pipeline. (2020). About dbp. Retrieved from https://www.dbp.net.au.

Geoscience Australia. (2020). Energy. Retrieved from

https://www.ga.gov.au/scientific-topics/energy.

Pipeline Safety Trust. (2019). Pipeline basics & specifics about natural gas pipelines. Retrieved

       From http://www.pstrust.org/wp-content/uploads/2019/03/2019-PST-Briefing-Paper-02-Nat

       GasBasics.pdf.