EBF 301
Global Finance for the Earth, Energy, and Materials Industries

Reading Assignment: Lesson 6

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Reading Assignment:

From Wellhead to Burnertip

While reading each of these short descriptions, try to visualize the movement of the natural gas through each stage and what exactly is occurring. We will go into more detail for each of these steps in the mini-lectures.

Read the following sections on the NaturalGas.org website.

Please go to this page "Understanding Henry Hub" from the CME Group. Read the content on the page and watch the video (2:59).

Optional Reading and Viewing

Readings

Natural Gas 101 Video (3:38 minutes)

Click for a transcript of the Natural Gas 101 Video.

Natural gas-- natural gas is primarily methane or CH4 with smaller quantities of other hydrocarbons. It was formed millions of years ago when dead organisms sunk to the bottom of the ocean and were buried under deposits of sedimentary rock. Subject to intense heat and pressure, these organisms underwent a transformation in which they were converted to gas over millions of years.

Natural gas is found in underground rocks called reservoirs. The rocks have tiny spaces called pores that allow them to hold water, natural gas, and sometimes oil. The natural gas is trapped underground by impermeable rock called a cap rock and stays there until it is extracted.

Natural gas can be categorized as dry or wet. Dry gas is essentially gas that contains mostly methane. Wet gas, on the other hand, contains compounds such as ethane and butane in addition to methane. These natural gas liquids or NGLs for short can be separated and sold individually for various uses such as in refrigerants and to produce products like plastics.

Conventional natural gas can be extracted through drilling wells. Unconventional forms of natural gas like shale gas, tight gas, sour gas, and coalbed methane have specific extraction techniques. Natural gas can also be found in reservoirs with oil and is sometimes extracted alongside oil. This type of natural gas is called associated gas. In the past, associated gas was commonly flared or burned as a waste product, but in most places today it is captured and used.

Once extracted, natural gas is sent through small pipelines called gathering lines to processing plants, which separate the various hydrocarbons and fluids from the pure natural gas to produce what is known as pipeline quality dry natural gas before it can be transported. Processing involves four main steps to remove the various impurities-- oil and condensate removal, water removal, separation of natural gas liquids, sulfur and carbon dioxide removal. Gas is then transported through pipelines called feeders to distribution centers or is stored in underground reservoirs for later use.

In some cases, gas is liquefied for shipping in large tankers across oceans. This type of gas is called liquefied natural gas or LNG. Natural gas is mostly used for domestic or industrial heating and to generate electricity. It could also be compressed and used to fuel vehicles and is a feedstock for fertilizers, hydrogen fuel cells, and other chemical processes.

Natural gas development, especially in the United States, has increased as a result of technological advances in horizontal drilling and hydraulic fracturing.

When natural gas is burned, there are fewer greenhouse gas emissions and air pollutants when compared to other fossil fuels. In fact, when used to produce electricity, natural gas emits approximately half the carbon emissions of coal. Despite fewer emissions, natural gas is still a source of CO2.

In addition, methane is a potent greenhouse gas itself, having nearly 24 times the impact of CO2. During the extraction and transportation process, natural gas can escape into the atmosphere and contribute to climate change. Natural gas leaks are also dangerous to nearby communities because it is a colorless, odorless, highly toxic, and highly explosive gas. That's natural gas.

Credit: Student Energy

A History of Natural Gas Video (11:57 minutes)

Click for a transcript of A History of Natural Gas Video.

Natural gas has enormous potential as a versatile energy source. While it's had a history of powering electric generators and heating stove-tops, it's growing in use as an efficient fuel that also powers cars and trucks. But what exactly is natural gas? Natural gas is a naturally occurring chemical, primarily made up of methane-- CH4. Its purity makes it an environmentally friendly fuel. Methane does not leave a residue when burned, so its emissions do not react with sunlight to create smog.

How Natural Gas is Formed

The natural gas we use today began as microscopic plants and animals living in the ocean tens of millions of years ago. As they thrived, they absorbed energy from the sun, which was stored as carbon molecules in their bodies. When they died, they sank to the bottom of the sea and were covered by layer after layer of sediment. As these plants and animals became buried deeper in the earth over millions of years, heat and pressure began to rise. The amount of pressure and degree of heat transformed the bio-matter into natural gas.

Where Natural Gas is Formed

After natural gas was formed it tended to migrate upward through tiny pores and cracks in the surrounding rock. Some natural gas seeped to the surface, while other deposits traveled upward until they were trapped under impermeable layers of rock such as shale or clay. These trapped deposits are where we find natural gas today. In 1859, Edwin Drake drilled the first commercial well in Titusville, Pennsylvania, striking natural gas and oil. This is considered by many to be the beginning of the natural gas industry.

First Uses of Natural Gas

For most of the 1800s, natural gas was used almost exclusively as a fuel for lamps. Because no pipeline network existed to transport large amounts of gas over long distances, most of the gas was used to light local city streets. It was moved through small bore lead pipe. Then in 1885, Robert Bunsen invented a burner that mixed air with natural gas. The Bunsen burner showed how gas could provide heat for cooking and warming buildings. After the 1890s, many cities began converting their street lamps to electricity forcing gas producers to look for new markets. But the lack of mobility to transport gas to consumers was still an issue.

Transporting Natural Gas

In the energy industry, natural gas was originally obtained as a byproduct from oil production. Since it was viewed as too costly to produce, much of it was burned off by flaring at the wellhead. Improvements in metals, welding techniques, and pipe-making during World War II, opened natural gas to new markets thanks to pipeline networks. Throughout the 1950s and 1960s, thousands of miles of pipeline were constructed throughout the United States.

Although natural gas was becoming economically attractive with a growing pipeline network, crude oil was still far more popular and more widely used as a source of energy. For years, the industry perception remained that supplies of natural gas were limited. Although natural gas had been discovered in tight rock formations called shale, it was deemed too expensive and difficult to harness.

Technology Advances

With advances in drilling technology, new solutions emerged that solved these issues. Horizontal drilling and hydraulic fracturing, commonly referred to as fracking, were introduced as innovative techniques to reach shale deposits and harvest natural gas. Originally pioneered in the 1940s and refined in the 1970s, these processes have revolutionized the industry.

After the well site has been carefully prepared to meet environmental health and safety standards, drilling can begin. This is an intricate operation requiring a well-planned infrastructure, a variety of processes, and expert well-trained specialists are used to bring natural gas to the surface. Chesapeake works with these experts during every aspect of the project, while strictly adhering to all individual state regulations.

During the drilling process, the rig is in constant operation 24 hours a day, seven days a week, for approximately 21 to 28 days. As an added precaution in some areas, a protective mat covers 2/3 of the pad site. Utilizing heavy duty industrial strength drill bits, a typical well is drilled in several stages, starting with a large diameter drill bit and then successively smaller drill bits as the drilling has advanced.

After drilling each portion of the well, nested steel protective casing is cemented into place. This will protect groundwater and maintain the integrity of the well. Initially, and prior to moving in the drilling rig, a large diameter hole is drilled for the first 50 to 80 feet. Conductor casing is then cemented into place, stabilizing the ground around the drilling rig and wellhead and isolating the well from most private water wells.

In the Marcellus area, the fresh water zone extends to approximately 800 feet below ground. The fresh water zone consists of porous sandstone and rock strata containing water within the pore space of the rock. Chesapeake utilizes air drilling until the hole is advanced to an average of 100 to 200 feet below the base of the fresh water zone. This provides added protection to the fresh water zone.

A series of compressors and boosters generate the air that is used to lift the rock cuttings in fresh water into steel bins. The rock cuttings are then disposed of within state guidelines and permits. The drilling equipment is retracted to the surface and stored for the second stage of drilling. To protect the integrity of the hole and to protect the surrounding deep fresh water zone, a second layer of steel casing called surface casing is installed and cemented inside the newly drilled hole and conductor casing.

Cement is pumped down through the surface casing and up along the sides of the well to provide a proper seal. This completely isolates the well from the deepest of private or municipal water wells. A blowout preventer is installed after the surface casing has been cemented. The blowout preventer is a series of high-pressure safety valves and seals attached to the top of the casing to control well pressure and prevent surface releases.

Next, a small drilling assembly is passed down through the surface casing. At the bottom of the casing, the bit drills through the float equipment and cement continuing its journey to the natural gas target area as deep as 8,000 feet below the surface. The drilling method employed below the surface casing uses drilling mud, which is a nonhazardous mixture based on bentonite clay or synthetic thickeners. In addition to lifting the rock cuttings out of the hole, drilling mud also helps to stabilize the hole, cool the drill bit, and control downhole pressure. A few hundred feet above the target shale, the drilling assembly comes to a stop.

The entire string is retracted to the surface to adjust the drilling assembly and install a special drilling tool. This tool allows Chesapeake to gradually turn the drill bit until a horizontal plane is reached. The remainder of the well is drilled in this horizontal plane while in contact with the gas producing shale. Drilling continues horizontally through the shale at lengths greater than 4,000 feet from the point where it entered the formation.

Once drilling is completed, the equipment is retracted to the surface. Then a smaller diameter casing called production casing is installed throughout the total length of the well. The production casing is cemented and secured in place by pumping cement down through the end of the casing. Depending on regional geologic conditions, the cement is pumped around the outside casing wall to approximately 2,500 feet above the producing shale formation or to the surface.

The cement creates a seal to ensure that formation fluids can only be produced via the production casing. After each layer of casing is installed, the well is pressure-tested to ensure its integrity for continued drilling. A cross-section of the well below the surface reveals several protective layers-- cement, conductor casing, cement, surface casing, drilling mud, production casing, and then production tubing through which the produced gas and water will flow. Seven layers of protection.

Horizontal drilling offers many advantages when compared to vertical drilling. Since horizontal wells contact more of the gas producing shale, fewer wells are needed to optimally develop a gas field. Multiple wells can be drilled from the same pad sites. For example, development of a 1,280 acre tract of land using conventional vertical drilling techniques could require as many as 32 vertical wells with each having its own pad site. However, one multi-well pad site with horizontal wells can effectively recover the same natural gas reserves from the 1,280 acre tract of land while reducing the overall surface disturbance by 90%.

Fracking is a technique that involves pumping water and sand at high pressure into shale formations. After drilling has been completed in a prospective location, the shale formation is perforated or punctured to prime it for the fracturing process. The area is then subjected to water and sand at high pressure to fracture the shale. Once fractured, sand is used to hold the small cracks and fissures open, releasing natural gas and allowing it to move up the wellbore to the surface. With this new technology, a land rush soon followed by gas producers to obtain the best locations in potential gas shale plays across the nation. More discoveries are made every year and new industry estimates now state that the US has a 100 year supply of natural gas.

Common Uses of Natural Gas Today

Today, natural gas is used all over the world as a versatile form of clean-burning energy. Common uses include heating homes and powering hot water heaters, dryers, and stovetops. But its ability to adapt to so many other needed areas have made it an ideal energy for making plastics, powering electric turbines, and commercial chillers that cool office buildings. When used as an automotive fuel, Compressed Natural Gas, or CNG, is a clean fuel that can power buses, trucks, and compact cars.

Natural gas has proven to be a clean, affordable, abundant alternative to gasoline and coal. 99% of the natural gas used in the US is produced at home in our own nation. With a variety of uses and new technology, natural gas is proving it's the energy of the future.

Credit: Chesapeake Energy

Natural Gas from Shale Video (9:22 minutes)

Click for a transcript of the Natural Gas from Shale video.

Chevron is involved in all aspects of energy production. And we are at the forefront of advances in safe and successful exploration and production, including natural gas from shale. As in all our operations, we are committed to safety, protecting people, the environment, and contributing to local communities. Chevron applies high standards and processes which always meet or exceed government regulations. We aim to be a good neighbor, partner, and steward of the environment.

Natural gas from shale was formed in the same manner as all hydrocarbons. Over time the remains of minute organisms were deposited in sediments at the bottom of ancient oceans. Through geological time, these sediments were buried and subjected to heat and pressure, turning the organic matter into oil and natural gas. In most oil and gas reservoirs, the hydrocarbons migrate from the source rock and are trapped in overlying, porous rock. These reservoirs have been produced worldwide for over a century.

Natural gas from shale is produced directly from the source rock. Since the shale is fine grained and impermeable, the gas does not flow naturally. In today's changing world energy landscape, natural gas from shale offers economic benefits and security of supply. Advances in knowledge and technology in the oil and gas industry are now allowing companies to develop natural gas from shale. Once we have acquired a license from government, we develop an accurate picture of the subsurface through the acquisition of seismic data.

Seismic surveying uses reflected sound waves to map geological layers deep underground. Seismic surveys are performed by a range of techniques. One of these is vibroseis a method requiring a group of large trucks equipped with vibrating plates. Approximately every 25 meters, the plates are lowered onto the ground and vibrated to send seismic waves down into the earth. The trucks spend a few seconds vibrating at each location, and the energy released is similar to that from a pneumatic drill. Seismic operations are only conducted during the hours of daylight and at a minimum distance from nearby buildings or water wells.

Well sites are selected based on geological understanding and distance to buildings, access by road, agreements with landowners, and availability of water. The selected sites are leased and permitted following consultation with local residents and authorities. After which an area of land is cleared, leveled, and made ready for the arrival of the drilling rig. A site access road is built as far from residential areas as possible to safeguard pedestrians and traffic. Chevron's exploration drill sites cover an area approximately the size of a football pitch.

The rig will stand to a height of almost 40 meters. The minimum distance between homes and the rig will be 300 meters. At this distance, noise levels will be lower than traffic noise. Initial drilling operations are expected to take around two months. Water is required for drilling operations, and it will be sourced either from onsite wells or transported by tanker. Water access and disposal is subject to local and national regulations and subject to our own strict water management standards.

Sampling is carried out in neighboring wells before and during all operations to ensure there is no impact on the water table. Fluid called "drilling mud" is used during drilling operations to maintain pressure, cool the drill bit, and bring the rock cuttings to the surface. The drill cuttings will be transported to a licensed waste disposal site and traffic movements will be monitored and kept to a minimum. Vertical wells are drilled more than two kilometers deep to test for the presence of organic rich shale. Chevron has global standards and procedures and applies best practices to ensure we drill wells safely and without environmental harm.

Well design will be reviewed by our own internal specialists and permitted by the relevant authorities. Protection of shallow aquifers, commonly 200 meters below surface, is critically important. Our wells are lined with multiple layers of steel casing and cement which form a continuous barrier of protection between the wellbore and the aquifer. Pressure tested for strength, the casing lasts the life of the well. Samples of shale, called cores, are brought to the surface for analysis to determine whether natural gas is present and how the shale will respond to fracturing.

If the results are promising, the next step would be to perform a small fracturing job to test the shale's potential to fracture and release its gas. If the results are negative, the well will be plugged with cement and the land will be restored to original use. If results from exploration wells are encouraging, hydraulic fracturing will take place. Hydraulic fracturing is the process of injecting water, sand, and additives, under pressure, to crack the shale rock and allow the natural gas to flow.

This technology has been used safely for 60 years in more than a million wells worldwide. It is not unique to shale. The fracturing additives are less than 0.5%, and these help to make the process more efficient, minimize friction, and carry the sand deep into the fracture network. All substances used are governed by local, national, and European regulations. If the results from fracturing and testing of vertical well are positive, we'll progress to drilling horizontal wells.

The anticipating water usage for drilling one well and performing single stage fracturing is 2,400 cubic meters. Multistage fracturing of a horizontal well is expected to use 16,000 cubic meters of water. This can be reduced by recycling from one fracturing job to the next.

The next step is pilot testing, where several horizontal wells drilled from a single drill site to test commercial viability. This operation would be more intensive than exploration activity. The well pad will be bigger to accommodate more equipment, including a pond to store the water required for fracturing.

Horizontal wells provide far more exposure to the gas bearing formation and are approximately two kilometers in length. Where a horizontal well has been drilled, production casing is inserted into the end section of the wellbore. Cement is then pumped down the entire length of the casing and back up around the outside to create a permanent seal. Around 16 horizontal wells could be drilled from one pad to minimize the operational footprint on the land. If we find natural gas in sufficient quantities for full scale development drilling operations would continue for several months at each location.

Once natural gas is flowing from the wells, all drilling and fracturing equipment will be removed from the well pad. The site will be restored and replanted with access for crews to perform periodic monitoring and maintenance. All that would remain visible above ground would be valves, flow lines, and storage tanks.

At Chevron, we are focused on identifying and developing our assets safely, efficiently, and reliably. We are committed to utilizing technology to develop new energy resources while reducing our environmental footprint.

Credit: Chevron

Using Hydraulic Fracturing and Horizontal Drilling for Natural Gas Production Video (3:09 minutes)

Click for a transcript of the Using Hydraulic Fracturing and Horizontal Drilling for Natural Gas Production video.

Natural gas is a clean burning fossil fuel found deep below ground. Some natural gas is trapped within shale, a dense rock once thought beyond our reach for energy production. By combining two well-established technologies-- horizontal drilling and hydraulic fracturing-- we can now unlock this valuable resource. Before any drilling begins, our geologists examine rock characteristics to see if gas is likely to be present. If gas is confirmed, we determine the best location for drilling.

The natural gas will be located in shale layers. These may be as deep as 2 miles or 3.5 kilometers below the surface. That's 10 times the height of the Eiffel Tower. To ensure that the subterranean area is sealed off and groundwater is protected for the life of the well, we line our wells with several layers of protective steel casing and cement. Once at the target depth, we drill horizontally about 5,000 feet or 1,500 meters. This provides more access to the gas along the shale layer.

When drilling is complete, steel production casing is inserted into the horizontal section of the well. Cement is then pumped down the length of the casing and back up around it. This permanently secures the well and prevents gas and liquids from seeping out as they are brought to the surface. Next, we use an electrical perforating gun to make small holes in the steel casing and cement. Finally, to release the gas from the rock, we use hydraulic fracturing. This is a safe and proven technology that's been in use since the 1940s.

A mixture of more than 99% water and sand and less than 1% additives is pumped into the well under high pressure. The mixture is pumped down the well and out through the perforations into the surrounding shale formation creating fractures that allow gas to flow to the well. The fractures are contained within a few hundred yards or meters of the wellbore and separated from the aquifer by about one to three miles or two to four kilometers of impermeable rock. At the surface, Chevron manages the well site to strict environmental standards.

When pumping is complete, flowback water is retrieved from the well and captured in tanks or lined pits. Flowback water is typically either treated and reused in future hydraulic fracturing jobs or injected into permitted water disposal wells. In some locations, flowback water may be disposed of at a certified waste facility. Solids are cleaned and responsibly disposed of at a waste facility. When each well is complete, the drilling and fracturing equipment is removed, and the pits are filled in.

The reduced site now contains only the necessary equipment to ensure the natural gas continues to be produced safely-- primarily, a wellhead and related equipment. It's estimated that a typical well has a life of 30 years or more. This new generation of natural gas production can help secure a domestic energy supply and energy security for decades to come.

Credit: Chevron

Natural Gas Pipelines Operations Video (8:45 minutes)

Click for a transcript of the Natural Gas Pipelines Operations video.

Because of its domestic abundance, low environmental emissions, and high energy content, natural gas has become a very popular and important fuel in North America. In these early years of the 21st century, about one quarter of America's daily energy need is met by natural gas, including heating, electric generation, and industrial feedstock used for making products such as plastics and fertilizer. As the population swells and with it the need for this cleaner burning fuel, so too must long-haul pipeline systems evolve and expand to keep pace with America's natural gas demand.

Recently, Americans used more than 22 trillion cubic feet of natural gas in a single year. That's a tremendous amount of energy when one considers that 1 trillion cubic feet of natural gas is enough to heat one million homes for 15 straight years. Long-haul pipelines are the critical link between the often lengthy distances separating natural gas supply and major market areas. These major transportation systems generally differ from local distribution pipelines in several ways, such as the material composition and diameter of the pipeline, larger diameter steel versus smaller diameter plastic, and higher operating pressures versus lower operating pressures.

When it comes to the operation of long-haul natural gas pipeline systems and the coexistence between the transportation systems and the public, operating companies place their focus in two primary areas-- providing reliable service to customers and further minimizing the relatively low risks associated with transporting a volatile fuel source under high pressure. Bureau of Transportation statistics records have historically and consistently shown that long-haul pipelines have the best transportation safety record in the United States.

Transportation Fatalities per 100,000 U.S. Residents
Transportation Type Fatalities per 100,000 U.S. Residents
Air .24
Rail .30
Transit .08
Pipeline .004

Pipeline system accidents, which are reported to PHMSA, are rare, particularly when one considers that trillions of cubic feet of natural gas transported each year. But the industry fully understands the potential impact of a damaged pipeline and takes many measures to both maintain pipeline systems and prevent these accidents from occurring. Clearly, even though long-haul pipes have the fewest accidents among all companies involved in transportation, there is no rest on the best in class laurels.

But one incident is one too many, and operators continually look for ways to improve the transportation of natural gas. The industry has built its solid safety record on a foundation of continuous improvement. And as a result, it has seen a percentage decrease in the number of significant incidents in the past 20 years while the amount of natural gas moved in that time frame increased dramatically.

Every step of the way, these long-haul pipeline systems are monitored around the clock by high-tech equipment and highly skilled employees. The basic process to transport natural gas long distances involves not only the specialized steel pipeline but related measurement and pressure regulating equipment, compressor stations that compress the natural gas molecules to facilitate the journey, and control centers that monitor major operating conditions around the clock. Companies also repeatedly communicate with those living near pipelines, emergency responders, and other important stakeholders through various methods while providing strategically located above-ground markers and other means to remind them of their mostly underground assets.

As natural gas travels through the pipeline system, it is pressurized to varying levels inside the long-haul pipes to facilitate its journey. This is accomplished by squeezing the natural gas molecules by pressure known as compression. Compression of the natural gas molecules serves a twofold purpose. One, it reduces the size of the natural gas molecule by many times, thus increasing the amount of natural gas that can be transported in a given sized pipe. And two, it provides a propellant force or boost to help move the natural gas through the pipeline system.

Typically, compression of the natural gas molecules is required periodically along the route. This is accomplished by compressor stations usually placed at 40 to 100 mile intervals along the route. The natural gas enters the compressor station, or booster station as it's also called, where it is recompressed mechanically and propelled toward the next active compressor station where the process repeats. As a result, the highly pressurized natural gas moves through the pipelines at an average of about 10 to 20 miles per hour.

Along its journey, measurement and/or regulating stations are placed periodically to help manage the flow of natural gas entering or leaving the pipeline. At these stations, mechanical pressure regulators are used as necessary to reduce the pressure inside the pipeline to match customer needs. This facilitates the transfer of natural gas to industrial customers and the distribution companies that deliver the product to millions of homes and businesses each day.

The transportation of natural gas is often closely linked with the temporary storage of the commodity in porous rock formations or salt caverns deep underground. The underground geologic formations and associated above-ground operations equipment are connected by pipeline to various mainline systems. Natural gas storage facilities are important because they can temporarily hold large volumes of natural gas for later withdrawal during periods of high customer demand.

In order to manage the natural gas that enters the pipeline and to ensure shippers receive the transportation and/or storage services that they've contracted for, sophisticated control systems are required. Centralized natural gas control operations manned by trained operators continuously collect, assimilate, and manage data received from measurement, monitoring, and compression facilities all along the pipe. Most of the data received by a natural gas control center is provided by supervisory control and data acquisition systems, better known as SCADA.

SCADA is a sophisticated communication system that operates in real time with very little lag between measurements taken and the relay of the data to the natural gas control center. Measurements monitored and relayed include natural gas flow rates, operational pressures, and temperature readings, all of which are important to the assessment of the status of the pipeline at any given time. Alarms at these remote locations are also relayed to the control system operators. It's important for operators in the center to know what is happening along the pipeline system at all times. This allows for quick reaction to address and adjust to changing operating conditions.

Operators with these computer monitoring SCADA systems often have the ability to remotely operate certain equipment along the route, such as compressor station engines or valves. But these operator actions are limited by safeguards and redundant devices. Adjusting compressor engines allows for the quick and easy adjustment of flow rates in the pipeline, while remote operation of valves allow for the isolation of certain sections of pipeline for maintenance or emergency response purposes in coordination with local operating personnel.

Remote operating capability plus the strategic local area or regional placement of trained employees makes for the effective management and control of these long-haul natural gas transportation systems. For more information about long-haul natural gas pipelines, please visit the Interstate Natural Gas Association of America website at www.ingaa.org.

Credit: Spectra Energy

Natural Gas Liquids Video (11:14 minutes)

Click for a transcript of the Natural Gas Liquids video.

Hello, I’m Dan Brockett. I'm a member of the Shale Energy Education Team. And I work for Penn State Cooperative Extension. Today, I'm going to be talking a little bit about natural gas liquids.

[Slide]: Natural gas Liquids (NGL’s) are found in “wet gas” areas of shale gas producing regions.

[Dan]: I'm going to try to answer a few questions about natural gas liquids, like what is it, where is it, and why does it have added value. Then we're going to take a look at how NGLs are produced and processed, from wellhead to fractionation. Finally, we'll talk a little bit about how NGLs are used, and a bit of news regarding the future of NGLs in the Appalachian basin.

This map shows a portion of the Appalachian basin that contains Marcellus Utica and upper Devonian shale gas. You'll see the red line further east shows approximate Marcellus and upper Devonian wet-dry dividing line. The middle line shows approximate Utica Point Pleasant wet-dry line. And the line furthest west shows oil. For today's purposes, we're only talking about wet gas. And remember that these are only estimates of where these products are located.

[Slide]: Natural Gas Liquids: Each successive NGL has an additional carbon molecule and different chemical properties.

C1H4 – Methane (dry gas)

C2H6- Ethane

C3H8 – Propane

C4H10 – Butane (and Isobutane)

C5H12 – Pentane (natural gasoline)

[Dan]: Each successive natural gas liquid has additional carbon molecule and different chemical properties. Starting from the top, C1H4 is methane. That's referred to as dry gas, and generically referred to as natural gas. This is what we might expect to be piped into our homes and used to generate electricity.

All of those remaining hydrocarbons-- ethane, propane, butane, and iso-butane, and pentane-- are referred to as natural gas liquids. Natural gas liquids have added value based on BTU.

[Slide]:

NGL’s Have Added Value (based on BTU)
Gas Net BTU Value Typical Volume (more to less)
Methane 1,011 more
Ethane 1,783
Propane 2,572
Butane 3,225
Pentane 3,981
Hexane 4,667 less

BTU stands for British thermal unit. To give you some scale, 1 BTU equals approximately lighting one match and letting it burn to the bottom. So you can see that methane, our dry gas, has about 1,000 BTUs, where ethane is about 1,800 BTUs.

As those hydrocarbons get heavier, they contain more BTUs. You will also note the typical volume that comes out of a well in the Appalachian basin in the wet gas region contains more methane than ethane, more ethane than propane, et cetera. So lighter gases tend to be produced more often than heavier gases.

Pipeline specification regarding those BTUs. Interstate pipelines require less than approximately 1,100 BTUs per SCF. SCF may not be a common term for you. It stands for standard cubic feet. Standard conditions are normally set around 60 degrees Fahrenheit and about 14.7 pressure at sea level.

Now, unprocessed wet gas is often well over 1,200 BTUs. And even when those heavier hydrocarbons, like propane, butane, and pentane, are removed, the BTU content still often exceeds 1,100. Some ethane then needs to be removed to meet pipeline specifications while the rest of the ethane may be rejected if there's not a market. Rejected ethane does not mean that it's thrown away. It's simply added to the gas stream, and contributes higher BTUs.

To give you an example of price, if there are processing facilities in a pipeline to market, then the price received tends to be significantly higher because those products can be separated and sold at their best and highest use. The other way natural gas liquids are often sold are in batches. They're sold as batches and separated from dry methane gas, but not separated into their each individual components.

[Slide]

Liquids Price Impact Example, assuming 1250 btu gas)

Category 1: Natural Gas = $2.00. Rich Gas increment = additional $.50 for a total of $2.50/MCF

Category 2: Natural Gas assumes 30-% shrinkage to $1.40. The Rich gas increments are divided into ethane, propane, iso-butane, butane and natural gasoline for a total of $3.21 /MCF

[Dan]: So now, let's talk about the process of how these natural gas liquids fall out of the gas stream. Pressure and temperature causes the heaviest hydrocarbons to fall out of the gas stream as liquids at the wellhead.

What is condensate? In this case, we'll refer to it as field condensate because it comes from the field where the gas is being produced. These condensates are a group of hydrocarbons that don't fit easily in the mainstream product categories. Usually, we're talking about pentane (C5)plus. The lower the number is, the heavier the condensate is. And generally, the heavier, the better the price.

Now, everything in this scale is compared to water, which is a 10. A number higher than 10 floats on top of water. Lower than 10, sinks. This graphic demonstrates that. As you can see on the left, lighter to heavier. And on the right, those products-- propane is lighter than butane, which is lighter than pentane, et cetera.

[Slide]:Density of Liquids

The API gravity goes from lighter to heavier in the following list:

Propane, Butane and Isobutane, Pentane, Hexane, Heptane

[Dan]: The next step in the process is a compressor station. The purpose of a compressor station is to add pressure to get gas to an interstate pipeline or to go to further processing. As you might guess, a compressor station adds pressure, which causes more liquids to fall out. We'll refer to these liquids as natural gasoline or drip gas. In this picture, you can see that center tower is water that's fallen out of the system, whereas the four towers outside of the center contain that natural gasoline.

The next step in the process is the cryogenic expansion process. If it's economic to extract ethane, cryogenic processes are required for high recovery rate. Essentially, cryogenic processes consist of dropping the temperature of the gas stream to about minus 120 degrees Fahrenheit.

Now, this is going to condense most of the natural gas liquids while methane will stay a gas. This separates most of the wet gas from the dry gas, but does not separate all the components of natural gas liquids. In order to do that, it requires fractionation.

Now, you can see in this graphic, our mixed natural gas liquids come in on a pipeline. And then they go through a series of towers that have different pressure and temperatures. The boiling point will only be reached by one product per tower. So you have a de-ethanizer, a de-propanizer, a de-butanizer, a de-isobutanizer.

And what comes out at the end is condensate. We'll refer to this as plant condensate. Generally, pentane plus. This is a picture of a fractionation plant in Houston, Pennsylvania. That's in Washington County.

Now, let's talk about how natural gas liquids are used. The most plentiful of the natural gas liquids is ethane. And it's predominantly used as a petrochemical feedstock. We're going to talk more about that later. There is a portion of ethane that's used as a heating fuel source. That's only when it's mixed with methane or propane.

Next, we'll talk about propane. About 35% of propane is used as a petrochemical feedstock. The majority of propane is used as a heating fuel source. You might be familiar with that as a heating source in your home, or barbecue, or for drying corn or lumber-- things like that. Also, about 10% of propane is exported. Butane-- about 22% of that is used as a petrochemical feedstock.

About 10% is exported, but the bulk of butane is used as a blend stock for motor gasoline. Iso-butane is entirely used as a blend stock for motor gasoline. Or natural gasoline-- that's pentane plus-- about 10% is used as a petrochemical feedstock. About 10% is exported. The majority of it goes as a blend stock for motor gasoline, and 8% to 10% is used for ethanol denaturing.

The infrastructure for ethane markets is very important, because it's the most plentiful of the natural gas liquids. Just a few years ago, there wasn't an outlet for ethane in the Appalachian basin. But quickly, pipelines were built to the Gulf Coast, where there are many cracker plants, also to Sarnia, Ontario, where there are a few cracker plants, and most recently to the Marcus Hook facility.

There's a pipeline that goes across southern Pennsylvania, taking that to an export facility, where it's placed on a ship and exported overseas. There's also a local option that may develop in the next four to five years in terms of developing cracker plants in the Appalachian basin.

So the ethylene chain goes from natural gas. Those products are then separated, fractionated. And you might have purity ethane that comes out. That purity ethane goes to a cracker plant. At that cracker plant, that purity ethane is turned into ethylene. Ethylene is further refined into intermediate products like PVC, vinyl chloride, styrene, and polystyrene. And those products are used to make adhesive, tires, footwear, bottles, caps-- a lot of things that are used as everyday products.

The future of natural gas liquids in the Appalachian basin. Well, there are some outlets for ethane and other natural gas liquids now, but those opportunities are growing. And more outlets for ethane, including additional pipelines to Sarnia, additional exports, and additional pipelines to the Gulf Coast. But this also includes an announcement from Shell to build an ethane-only cracker plant in Beaver County, Pennsylvania.

I'd like to give some credit to those folks who contributed to this presentation, including the Penn State Marcellus Center for outreach and research, Jim Ladlee at Penn State, Wikipedia, engineeringtoolbox.com, photos from MPLX and from the American Chemistry Counsel, and a map from EIA. If you would like more information on natural gas liquids or anything else regarding natural gas, please go to our website-- naturalgas.psu.edu. And thank you, very much.

Credit: Penn State Extension

How a Gas Turbine Works Video (2:39 minutes)

Click for a transcript of the How a Gas Turbine Works video.

PRESENTER: Air-- a lot of gaseous molecules floating all around us. It's great for breathing, and it turns out it's great for getting lights turned on. That's because air along with abundant natural gas or other fuels are the ingredients that combine in a gas turbine to spin the generator that produces electric current. If you follow the electricity you use at home or at work, back through the power lines to your local power plant, you'll see that the process most likely starts with the work of the gas turbine, the very heart of the power plant.

First, air is drawn in through one end of the turbine. In the compressor section of the turbine, all those air molecules are squeezed together, similar to a bicycle pump squeezing air into a tire. As the air is squeezed, it gets hotter, and the pressure increases.

Next, fuel is injected into the combustor, where it mixes with a hot compressed air and is burned. This is chemical energy at work. Essentially, this is what happens in your family car's engine, but at about 2,900 times more horsepower.

Actually, it's exactly like the turbine engines on jet airplanes. The hot gas created from the ignited mixture, moves through the turbine blades, forcing them to spin at more than 3,000 RPMs. Chemical energy has now been converted into mechanical energy. The turbine then captures energy from the expanding gas, which causes the drive shaft, which is connected to the generator, to rotate.

That generator has a large magnet surrounded by coils of copper wire. When that magnet gets rotating fast, it creates a powerful magnetic field that lines up electrons around the coils and causes them to move. The rotating mechanical energy has now been converted into electrical energy because the movement of electrons through a wire is electricity. In what's called a combined cycle power plant, the gas turbine can be used in combination with a steam turbine to generate 50% more power. The hot exhaust generated from the gas turbine is used to create steam at a boiler, which then spins the steam turbine blades with their own drive shaft that turns the generator. What you end up with is the most efficient system for converting fuel into energy. And that's your GE Gas Turbine 101.

Credit: GE Power

How does a Steam Turbine Work? Video (5:42 minutes)

Click for a transcript of the How does a Steam Turbine Work? video.

Nuclear and coal-based thermal power plants together produce almost half of the world's power. Steam turbines lie at the heart of these power plants. They convert thermal energy in the steam to mechanical energy. This video will explain the inner workings of the steam turbines and why they are constructed in the manner they are in a step-by-step, logical manner.

To understand its basic workings, let's first observe one of their blades. You can see that the blade of a steam turbine has an airfoil shape. When the high-energy fluid passes over it, this airfoil shape will create a pressure difference.

This will subsequently create lift force. The lift force will rotate the turbine. In short, the energy in the fluid transfers to the mechanical energy of the rotor. (Flow energy > Mechanical energy)

To further understand steam turbine operation, let's understand fluid energy in greater depth. A fluid has three forms of energy due to its speed (kinetic energy), pressure, and temperature. As the blades absorb energy from the fluid, all three forms of energy come down.

The low-velocity jet is of no use to produce effective lift force. To increase velocity, the fluid is passed through a stator section. The stator set is stationary and attached to the turbine casing. You can see that flow area decreases along the stator, and the speed thus increases.

In short, the stator acts like a nozzle. As the speed of the jet increases in the stator, kinetic energy increases. As there is no net energy transfer in the fluid and stator section, the pressure and temperature of the jet should decrease to keep the total energy constant.

Now the next row of rotors is added. The stator also makes sure that the flow coming out of it will be at an optimum angle of attack to the next rotor set. After that, another nozzle set is added. Many such sets are used in a steam turbine.

There is an important term while designing steam turbines-- namely, degree of reaction. This term is calculated by dividing pressure and temperature energy by the total energy change in the rotor. Pressure and temperature energy together is called enthalpy. The degree of reaction decides what type of steam turbine it is.

As the pressure of the steam undergoes a drastic reduction during steam turbine operation, its volume increases proportionally. To accommodate such an expanded steam we have to increase the flow area. Otherwise, the flow speed will become too high. This is the reason why the steam turbine blades are too long towards the outlet.

You can see how long the last stage turbine blades are compared to the first stage blades. The tips of such long blades will have very high velocity compared to the root. A twist has given to it so that all blade cross-sections will remain at an optimum angle of attack.

This kind of large turbine uses two such symmetrical units. You can see how the steam is equally divided between these units. High-capacity power plants use different stages of steam turbines, such as high-pressure turbines, intermediate-pressure turbines, and low-pressure turbines.

All these units are attached to a single rotating shaft. The shaft in turn, is connected to a generator. The reason for such different stages is quite interesting. With greater steam temperature comes greater power plant efficiency. This is according to the second law of thermodynamics.

But we cannot have temperature greater than 600 degrees Celsius since the turbine blade material will not withstand temperature more than that. The temperature of the steam decreases as it flows along the rows of the blade. Consequently, a great way to increase power plant efficiency is to add more heat after the first stage.

So after the first stage, the steam is bypassed to the boiler, and more heat is added. This is known as reheating. This will increase the steam temperature again, leading to higher plant efficiency and output.

One challenging problem in power plant operation is to keep the speed of the steam turbine constant. This is important since frequency of the electricity produced is directly proportional to the generator speed. However, depending on the load or power demand, the steam turbine speed will vary. To keep the steam turbine speed constant, a steam flow governing mechanism is used.

If a steam turbine rotates at a higher speed, the control valve will automatically reduce the steam flow rate to the turbine until the speed becomes normal. If a turbine rotates at a low speed, the inverse will be done. In this way, the balance of power demand and power supply will be perfectly synchronized.

To learn more about degree of reaction and its implications, please check the next video. Please help us at Patreon.com so that we can add one more member to the team, and we will be able to release two educational videos per month. Thank you.

Credit: Learn Engineering

Liquefied Natural Gas (LNG) 101 Video (2:23 minutes)

Click for a transcript of the Liquified Natural Gas 101 video.

LNG, Liquefied Natural Gas. LNG is natural gas that has been cooled to at least minus 162 degrees Celsius to transform the gas into a liquid for transportation purposes.

To understand why liquefying natural gas is important, we first need to understand natural gas's physical properties. Methane has a very low density and is therefore costly to transport and store. When natural gas is liquefied, it occupies 600 times less space than as a gas.

Normal gas pipelines can be used to transport gas on land or for short ocean crossings. However, long distances and overseas transport of natural gas via pipeline is not economically feasible. Liquefying natural gas makes it possible to transport gas where pipelines cannot be built, for example, across the ocean.

The four main elements of the LNG value chain are, one, exploration and production, two, liquefaction, three, shipping, four, storage and regasification. At the receiving terminal, LNG is unloaded and stored before being regasified and transported by pipe to the end users.

The demand for LNG is rising in markets with limited domestic gas production or pipeline imports. This increase is primarily from growing Asian economies, particularly driven by their desire for cleaner fuels and by the shutdown of nuclear power plants.

The largest producer of LNG in the world is Qatar with a liquefaction capacity in 2013 of roughly one-quarter of the global LNG production. Japan has always been the largest importer of LNG and in 2013 consumed over 37% of global LNG trade.

The extraction process also has environmental and social issues to consider. LNG projects require large energy imports for liquefaction and regasification and therefore have associated greenhouse gas emissions.

Spills pose concerns to local communities. There have been two accidents connected to LNG. But in general, liquefaction, LNG shipping, storage, and regasification have proven to be safe. LNG projects require large upfront capital investments, which can be a challenge in moving projects ahead.

That's LNG.

Credit: Student Energy