Chevron’s Operational Excellence Management System

       Chevron is a transnational energy corporation with offices and projects all over the world.  The company takes great pride in conducting business according to its core values.  The company’s vision and mission statement, Business Conduct and Ethics code, and Operational Excellence Management System overview can be easily found on the company website and elsewhere on the Internet.

       The Chevron Way encompasses the company’s vision and mission statement.  Chevron’s vision is “to be the global energy company most admired for its people, partnerships, and performance” (Chevron, 2018; MBA Tutorials, 2020).  This vision reflects its core values “to conduct business in a socially responsible and ethical manner.  We respect the law, support universal human rights, protect the environment, and benefit the communities where we work” (Chevron, 2020; MBA Tutorials, 2020).

       In accordance with the Chevron Way, the company strives to safely and efficiently supply energy products to its customers all over the world; hire the best-qualified people; become the best-qualified and highest-performing organization for its partners; and earn the respect and admiration of all of its stakeholders (MBA Tutorials, 2020).

       Chevron’s Business Conduct and Ethics Code outlines for employees the values and high standards of the company.  As Chairman and Chief Executive Officer Mike Wirth writes, “The Chevron Way is our touchstone for getting results the right way and establishes high standards for how we operate around the world” (Chevron, 2020).  The code emphasizes the company’s commitment to comply with the laws, regulations, and customs of every country in which it operates.  Violations can range from human rights to health and safety matters to bribery and fraud.  Consequently, the company encourages all employees to speak up about alleged violations of the code.  Since the company has a non-retaliation policy, employees who speak up in good faith are protected from retaliation by supervisors and peers (Chevron, 2020).

       In the United States, Chevron and other energy companies are regulated by the U.S. Department of Transportation (DOT).  In 1994, DOT established the Pipeline and Hazardous Materials Safety Administration (PHMSA) to regulate the United States’ 2.6 million miles of oil and gas pipelines.  As of 2018, oil provided 40 percent of U.S. energy, and natural gas provided 25 percent (U.S. Department of Transportation, 2020).

       Pipelines are considered a transportation system because they transport oil and gas to residential, commercial, and industrial customers.  Transporting energy products through pipelines is considered the safest means of transport.  PHMSA regulates all types of pipelines: gathering lines, transmission pipelines, and distribution lines.  The agency is responsible for “regulating the safety of design, construction, testing, operation, maintenance, and emergency response of U.S. oil and natural gas pipeline facilities” (U.S. Department of Transportation, 2020).  Protecting human lives and the environment from pipeline safety hazards are the main focus of PHMSA (U.S. Department of Transportation, 2020).       

       Integrity Management is a program instituted by PHMSA that requires pipeline operators to analyze and understand the environment and population in the area where the pipeline exists. Operators must be able to foresee the consequences of a pipeline failure to the local environment and community.  This proactive approach to pipeline safety and emergency management helps operators to prioritize inspections and scheduled maintenance and keeps them well-prepared in the event of a pipeline failure (U.S. Department of Transportation, 2020).

       In addition to PHMSA, other federal agencies involved in pipeline safety and security are the Department of Homeland Security (DHS), Transportation Security Administration (TSA), Department of Energy (DOE), and the Federal Energy Regulatory Commission (FERC).  State and local governments as well as industry experts also contribute to regulatory controls and standards.  Individual states must meet minimum federal safety regulations but can create stricter rules (U.S. Department of Transportation, 2020). 

       PHMSA’s Office of Pipeline Safety performs “field inspections of pipeline facilities and construction projects; inspections of operator management systems, procedures, and processes; and incident investigation” (U.S. Department of transportation, 2020).  When violations or safety hazards are found, the agency can force an operator to take corrective action (U.S. Department of Transportation, 2020).

       Operators of gas distribution systems must participate in the Gas Distribution Integrity Management Program (DIMP) which requires them to develop and put into practice a comprehensive integrity management program tailored to their individual distribution systems.  The purpose is to enhance safety by identifying risks, ranking them by severity, and implementing safety precautions to manage and eliminate those risks (U.S. Department of transportation, 2018).

       Chevron has developed a comprehensive Operational Excellence Management System which reflects its core values as a company.  Mike Wirth, Chairman of the Board and CEO, takes personal responsibility for the company’s performance.  His primary concern, when it comes to safety, is “to eliminate high-consequence personal and process safety events.  This means no fatalities or serious injuries and no fires, spills or explosions that can affect people or communities” (Chevron, 2018).

       Wirth’s focus is on three important areas: 1) understanding the safety risks involved in managing oil and gas operations; 2) identifying the safety measures needed to mitigate the risks; 3) implementing, maintaining, and improving those necessary safety measures (Chevron, 2018).

       The goals of Chevron’s Operational Excellence Management System are to protect “people and the environment” (Chevron, 2018), fulfill its mission “to be the global energy company most admired for its people, partnerships, and performance” (Chevron, 2018), and successfully manage “workforce safety and health, process safety, reliability and integrity, environment, efficiency, security, and stakeholders” (Chevron, 2018).

       To implement and maintain such a system requires the cooperation of all members of management and the workforce.  Everyone in the company must be accountable for their actions and the actions of others.  Everyone must be responsible for fostering a culture of safety and performance excellence (Chevron, 2018).

       Company accountability begins with its compliance with all health, environmental, and safety laws and regulations. Next, the company must comply with its own internal policies and procedures.  At the same time, company personnel must continually assess the company’s risk management program and make improvements as needed.  Assurance measures must be taken to ensure that safety precautions are kept in place to mitigate all identified risks.  The competency of the workforce must be kept up-to-date to ensure that quality management requirements are met.  The company must provide educational opportunities to keep the workforce informed of new policies, practices, and procedures.  The company must incorporate advanced technology into its operations to reduce the risk of human error.  Communication systems must be effective and reliable in order to convey information about potential chemical and biological safety hazards.  Contractors hired by the company must be in compliance with Chevron’s Business Conduct and Ethics Code and Operational Excellence Management System to maintain consistency and high-performance standards across the company.  There must be a competent system in place to report and investigate accidents; evaluate causes; implement new safety procedures; and communicate findings with management and the workforce.  Finally, an emergency management team must be prepared to respond at any time to a serious crisis that could harm property and human lives (Chevron, 2018).

       The reliability and integrity of wells, pipelines, and other facilities must be managed effectively to prevent safety hazards and operational losses.  Equipment must be inspected and maintained on a routine basis (Chevron, 2018).

       Chevron maintains a goal “to do business in environmentally responsible ways” (Chevron, 2018).  The company seeks to prevent all spills and accidental releases of gas and oil; to reduce air, water, and ground pollution; to conserve national resources and reduce greenhouse gases; to manage waste, especially waste produced by contractors; to dismantle company assets that are no longer used and restore the natural environment to its original pristine state.  The company keeps the public informed of its environmental management policies on its website (Chevron, 2018).

       Efficient use of energy and resources in order to drive down costs is an important part of Chevron’s Operational Excellence Management System.  Maintaining a secure physical and cyber environment prevents unnecessary and unwanted intrusions and safety hazards.  Engaging all stakeholders, including outside contractors, in the safety and performance goals of the company ensures that everyone connected with the company is on board (Chevron, 2018).

       The Operational Excellence Management System at Chevron depends on strong leaders and committed workers who are willing to work together as a team to implement, maintain, and improve the safeguards which mitigate risk.  “Typical safeguards include facility designs, mechanical devices, engineered systems, protective equipment, and execution of procedures” (Chevron, 2018).  Once risks are identified, personnel work together to eliminate them; create new policies and procedures to manage them; and provide personal protective equipment to protect workers from them (Chevron, 2018).

       Personnel are also expected to follow a code of conduct that was designed to reinforce safety and mitigate risk.  The two key tenets of this code are: “Do it safely or not at all” and “There is always time to do it right” (Chevron, 2018).  If all employees operate on a daily basis within the fundamental safety provisions of the Operational Excellence Management System, safety hazards should be minimized or avoided altogether (Chevron, 2018).

       Chevron’s website provides an excellent overview for the general public of its history, operations, financial status, environmental and safety management, ongoing projects, and vision for the future.  What it does not address are the real situations that come up and threaten the financial standing of the company and the Operational Excellence Management System it has put in place.

       The jewel in Chevron’s crown is the Gorgon Project, located off the coast of Western Australia.  Gorgon is one of the largest liquefied natural gas (LNG) projects in the world, with the capacity to produce 15.6 million tonnes of LNG per year.  The processing facilities are located on a one percent section of Barrow Island, a Class A Nature Reserve.  Chevron has invested an enormous amount of time and resources into preserving the integrity of its pipelines, processing facilities, and the environmental standards of Barrow Island.  The company has set out to prove that an oil and gas company can successfully operate while respecting and preserving the local environment (Chevron Australia, 2020).  

       From its very beginning in 2009, the Gorgon Project has been plagued by failures, safety hazards, engineering challenges, and excessive costs.  Originally, the project was supposed to cost $US37 billion, and the first LNG was projected to be produced in 2014.  By the time the first load of LNG was produced and shipped off to Asia in 2016, the final cost came in at $US54 billion (Boiling Cold, 2020).

       In 2009, there was a strong worldwide demand for LNG.  In early 2016, the price of petroleum products had fallen, and there was an excessive supply of LNG on the market.  Chevron was under pressure to complete Gorgon and produce its first load of LNG.  In order to meet Chevron Chief Executive John Watson’s deadline, “untreated feed gas traveled from the Jansz-Io gas field wellheads, 1350 [meters] below sea level off the edge of the continental shelf, to Barrow island, 130 [kilometers] away” (Boiling Cold, 2020).  Once the gas was treated and ready for cooling, “the feed gas ran through [a propane cooler] on a separate circuit” (Boiling Cold, 2020).  The propane gas in the cooler circulated “back to the compressor through a knockout drum” (Boiling Cold, 2020).  Nearly three weeks later, the fourth knockout drum failed, damaging the compressor.  Production was halted for three months (Boiling Cold, 2020).

       Chevron released a statement more than a week later that the failure would only require routine repairs, and all equipment and materials were available at the facilities.  In reality, the propane compressor was flown to Perth for repairs.  Three months after the failure, Chevron had not reported it to the Department of Mines and Petroleum (DMP), the safety regulator for the Barrow Island LNG plant (Boiling Cold, 2020).

       In August 2016, Chevron finally met with DMP officials to discuss the incident.  Chevron provided an analysis of what led up to the incident.  The most serious violation was the failure of workers to follow the company’s safety code and stop the cooling process when the propane compressor began to vibrate excessively (Boiling Cold, 2020).

       Another significant issue was the failure by engineers and operating technicians to evaluate and identify possible safety hazards with the plant’s start-up operation and then take measures to make changes to the design or procedures to mitigate risks (Boiling Cold, 2020).

       Other violations included workers with inadequate knowledge to start up the plant, fuzzy management responsibilities, and insufficient technical resources to deal with a problem (Boiling Cold, 2020).

       Chevron took corrective measures to fix the problems and satisfy the requirements set forth by the DMP, then issued a public statement to assure the public that they had taken action to ensure the safety of all people working at the plant (Boiling Cold, 2020).

       Part of Chevron’s environmental agreement with Western Australia was “to capture and store underground 40 percent of the [Gorgon] plant’s emissions through a sophisticated process known as geosequestration or carbon capture and storage” (Australian Broadcasting Corporation, 2018).  Chevron proudly brags about its CO2 injection project on its website.  But the reality shows something different.

       Chevron promised that between 5.5 and 8 million tonnes of CO2 would be injected into its underwater carbon storage project in the first two years of production on Barrow Island.  But seal failures and problems with corrosion delayed the CO2 injection project, leaving the Federal Government of Australia $AU60 million dollars poorer. As a result, all the gains in lower CO2 emissions made by the widespread use of solar power were wiped out.  A spokesperson for Chevron stated, “Our focus is on the safe commissioning and start-up of the carbon dioxide injection project and achieving a high percentage of injection over the 40-year life of the Gorgon project” (Australian Broadcasting Corporation, 2018).

       Chevron’s CO2 injection project was approved by Premier Colin Barnett on September 14, 2009. “The Barrow Island Act was the first legislation regulating carbon dioxide storage (geosequestration) in the world” (Department of Mines, Industry Regulation and Safety, 2019).  The project started injecting CO2 into the Dupuy Formation, a geological layer located more than two kilometers beneath Barrow Island, in August 2019.  Since then, the Department of Mines, Industry Regulation and Safety has been monitoring the project, making sure that Chevron stays in compliance with the Barrow Island Act and its Pipeline License (Department of Mines, Industry Regulation and Safety, 2019).

       When Chevron’s carbon dioxide system successfully started up in August 2019, Chevron Australia issued a press release reassuring the Australian public that it would continue to monitor all safety issues and fulfill its promise to reduce the Gorgon plant’s greenhouse gas emissions by 40 percent over the 40-year life of the project (Chevron Australia, 2019).

       When the coronavirus spread around the world early in 2020, the slumping oil and gas industry was hit with more problems.  The economic lockdowns put in place to stop the spread of the virus kept people at home, causing a backlog in equipment and parts orders, and a slowdown in preventative maintenance and repairs on wells, transmission pipelines, refineries, and gas distribution systems (Reuters, 2020).

       In order to cut costs, companies like Chevron and ExxonMobil began laying off workers, putting off maintenance and repair projects, and delaying start-up projects.  This put established wells, pipelines, refineries, and gas distribution systems at risk for future failure and safety hazards (Reuters, 2020).

       In July 2020, it was reported by the Australian media that routine maintenance at Barrow Island had uncovered thousands of cracks in eight propane kettles that had been sitting in storage for several years.  These kettles had been scheduled to be installed on LNG Train 2.  It has been speculated that the cracks were caused by water penetrating the thermal insulation surrounding the vessels.  The insulation was installed by overseas construction firms and then shipped to Australia (Boiling Cold, 2020).

       While repairing the cracks in the eight propane kettles, workers at Chevron discovered defective welds in those same kettles.  Executive Vice-President Jay Johnson told investment analysts that the defects occurred during the manufacturing process and not because they were poorly designed.  He claimed that repairs would be sufficient to make the vessels safe (Boiling Cold, 2020).

       Safety measures were put in place to mitigate risks in LNG Trains 1 and 3, but Chevron refused to reveal what those safety measures were or how workers would be safe while repairing LNG Train 2 (Boiling Cold, 2020).

       The company suffered a $US8.3 billion loss in the second quarter of 2020 due to problems at the Gorgon Project.  And it refused to explain how the 16 propane-filled kettles still operating were safe without being inspected for cracks and weld defects (Boiling Cold, 2020).

       In September, Chevron reported that it had given incorrect instructions to welders repairing the eight propane kettles on LNG Train 2.  Authorized personnel had neglected to inform welders that a post-weld heat treatment needed to be done, subjecting the weld to more cracking and failure (Boiling Cold, 2020).

       More delays in repairs have cost Chevron and its partners more than $AU500 million.  The continued problems at Gorgon have worried union leaders and workers alike.  The Department of Mines, Industry Regulation and Safety “gave Chevron permission to continue operating [LNG] Trains 1 and 3 under a plan where Train 1 would close for inspection of its kettles in early October and Train 3 would shut down in early January [2021]” (Boiling Cold, 2020).

       The company error occurred simultaneously with the final phase of its plan to lay off 20 to 30 percent of its Australian workforce due to losses incurred from COVID-19 lockdowns, a slumping oil and gas industry, and the expensive problems at Gorgon Project.  If repairs need to be done on Trains 1 and 3, the company will incur even more losses.  In order to recover some of its losses, Chevron plans to sell between $US5 billion and $US10 billion worth of assets (Boiling Cold, 2020).

       Publicly, Chevron does what it needs to do to keep a shining reputation, but the reality is a much different story.  Chevron’s lofty goals for itself magnify every mistake that it makes, from environmental violations to engineering and operational errors to investment losses.  Although  basically a sound company and a worthy employer, Chevron is in a tough position due to stricter environmental standards, COVID-19 restrictions, a slumping industry, and forces lined up against the use of fossil fuels.

References

Chevron. (2020). Chevron business conduct and ethics code. Retrieved from

https://www.chevron.com/-/media/shared-media/documents/chevronbusinessconductethics

       code.pdf

Chevron. (2018). Chevron operational excellence management system. Retrieved from

Click to access OEMS_Overview.pdf

Chevron Australia. (2019). Safe start up and operation of the carbon dioxide injection system at

       the gorgon natural gas facility. Retrieved from https://australia.chevron.com/

       news/2019/carbon-dioxide-injection/

Department of Mines, Industry Regulation and Safety. (2019). Gorgon carbon dioxide injection

       project. Retrieved from https://www.dmp.wa.gov.au/Petroleum/Gorgon-CO2-injection-

       project-1600.aspx

Diss, K. (2018, June). How the gorgon gas plant could wipe out a year’s worth of australia’s

       solar emissions savings. Australian Broadcasting Corporation. Retrieved from

https://www.abc.net.au/news/2018-06-21/gorgon-gas-plant-wiping-out-a-year-of-solar-

       emission-savings/9890386.     

MBA Tutorials. (2020). Chevron mission and vision statement. Retrieved from

Chevron Mission & Vision Statement

Milne, P. (2020, July). Gorgon’s catastrophic start-up. Boiling Cold. Retrieved from

https://www.boilingcold.com.au/gorgons-catastrophic-startup/

Milne, P. (2020, July). Cracks at chevron’s gorgon threaten safety and lng production.

       Boiling Cold. Retrieved from https://www.boilingcold.com.au/cracks-at-chevrons-gorgon-

       threaten-lng-production/

Milne, P. (2020, August). Gorgon weld problems raise safety questions chevron will not answer.

       Boiling Cold. Retrieved from https://www.boilingcold.com.au/gorgon-weld-problems-raise-

       safety-questions-chevron-will-not-answer/

Milne, P. (2020, September). Chevron to redo its botched gorgon weld repairs. Boiling Cold.

       Retrieved from https://www.boilingcold.com.au/chevron-to-redo-its-botched-gorgon-weld-

       repairs/

Milne, P. (2020, November). Chevron to restart gorgon lng train after $500m production loss.

       Retrieved from https://www.boilingcold.com.au/chevron-to-restart-gorgon-lng-train-after-

       500m-production-loss/  

U.S. Department of Transportation. (2020). About phmsa. Retrieved from

https://www.phmsa.dot.gov/about-phmsa/phmsa-mission/

U.S. Department of Transportation. (2018). Gas distribution integrity management. Retrieved

       from https://www.phmsa.dot.gov/technical-resources/pipeline/gas-distribution-integrity-   

       management-program/

Yagova, O., George, L., Bozorgmehr, S. (2020, May). Coronavirus creates repair headache for

       Oil and gas industry. Reuters. Retrieved from

https://www.reuters.com/article/us-health-coronavirus-oil-maintenance-an/coronavirus-

       creates-repair-headache-for-oil-and-gas-industry-idUSKBN22V0LT.

Dawn Pisturino

Thomas Edison State University

December 16, 2020; April 20, 2022

Copyright 2020-2022 Dawn Pisturino. All Rights Reserved.

Gas Pipeline Maintenance and Safety

       The main goal of a natural gas distribution company is to deliver affordable energy to customers in a safe manner at the lowest possible cost.  Utility companies in the United States are private businesses, even though they are regulated by local, state, and federal agencies, and must make a reasonable profit in order to pay employees, finance support services, expand services, and keep the natural gas distribution system well-maintained and safe (Busby, 1997, p. 45).

       Before a pipeline is even built, it must be approved by the Federal Energy Regulatory Commission (FERC).  Companies must submit their “construction plans and economic studies that demonstrate a demand for gas in the area to be served and an available, adequate supply of gas” (Busby, 1997, p. 45).  Companies must also detail the pipeline’s environmental impact on the local surroundings.  Once the FERC approves the pipeline, it issues a certificate to the company (Busby, 1997, p. 44-45).

       The next steps are to purchase the right-of-way and lease property along the path of the pipeline.  Peculiarities in the local environment, the length of the pipeline, the local population, expected customer needs, and the projected load dictate what choices the design engineers make – gas pressure, pipe diameter, pipe wall thickness, type and spacing of compressors, and more. Computer software now exists to assist engineers to choose the right location and calculate the right specifications.  Once all this is done, the appropriate pipes, valves, and other parts and equipment are ordered (Busby, 1997, p. 45).

       Ditching machines dig deep trenches in the ground, and sections of pipe are laid out along the trench.  The sections of pipe are held in place while welders weld the lengths of steel pipe into one long pipeline.  After the pieces of pipe are welded, “the outside surface of the pipe is cleaned, coated, and wrapped to inhibit external corrosion” (Busby, 1997, p. 46).  Frequently, these pipes have been coated inside at the steel mill to prevent corrosion; to aid internal inspection of the pipe; to reduce water retention after hydrostatic testing; to reduce absorption of gas odorants; to create a friction-free surface.  After the pipe is welded, coated, and inspected, it is lowered into the trench, where it is re-covered with appropriate backfill (Busby, 1997, p. 46-47). 

       At any point along this timeline, safety issues can come up which might not become apparent until months or years later.  A faulty pipe, an inappropriate valve, a design flaw, a pipeline that is allowed to carry too much pressure, an improper weld or inappropriate backfill, may lead to a dangerous break or leak later on down the line.

       Safety is the paramount concern in pipeline operations.  “Pipelines require regular patrol, inspection, and maintenance, including internal cleaning and checking for signs of gas leaks” (Busby, 1997, p. 51-52).  A major pipeline disaster could lead to political and economic repercussions, as well as environmental pollution and threats to property and human lives (Busby, 1997, p. 51-52).

       The most common cause of pipeline damage is third-party damage, caused by contractors and other people digging too close to natural gas lines.  Any damage to the pipe, the coating, or the welded joints can cause leakage and breakage.  Most states now have requirements for contractors to determine the location of utility lines before they dig new trenches (Busby, 1997, p. 52).

       Corrosion is the second most common cause of pipeline damage. “To minimize corrosion, pipeline companies install electrical devices called cathodic protection systems, which inhibit electrochemical reactions between the pipe and surrounding materials” (Busby, 1997, p. 52).  Any kind of rust, cracking, or pitting can cause pipe breakage or leakage.  If the original coating on the pipe was defective before use, the problem may go undetected for a long time (Busby, 1997, p. 52).

       A hydrostatic test can prove whether or not a pipeline is defective or needs repairs.  The gas is removed from the pipeline and the pipe is filled with high-pressure water.  But this is an expensive procedure so pipeline operators use a device called a pig that travels through the pipeline to remove dirt and corrosion.  These materials can cause damage to the pipes, regulators, and meters.  More advanced pigs (smart pigs) use technology that can measure pipe wall thickness and other abnormalities which can indicate corrosion and other damage (Busby, 1997, p. 52-53).

       Aerial patrols of transmission lines make routine surveys that can detect signs of leakage, such as patches of yellow vegetation in areas that are normally green; construction projects that may have damaged the line; or bare pipes that need to be re-covered (Busby, 1997, p. 53).

       Leak detectors can detect gas leaks above and below the ground.  Workers can detect leaks by the presence of brown or yellow vegetation.  By digging small holes at these locations, gas leaks can be detected by visual inspection or the odor of gas.  Inline cameras are used to detect leaks inside pipelines (Busby, 1997, p. 67).

       Workers routinely survey pipelines for leaks on a set schedule.  Public buildings, such as schools, hospitals, government offices, and theaters, are given priority attention.  Serious leaks are repaired immediately.  Companies are obligated to investigate customer reports of gas odor, leaks, explosion, or fire in a reasonable amount of time, according to the severity of the leak (Busby, 1997, p. 67).  Natural gas utilities post information on their websites educating consumers on detecting and reporting natural gas leaks.

       Mains and other distribution pipes made of plastic are repaired by shutting off the gas and squeezing closed the pipe on each side of the leak.  The leaking section is replaced with new pre-tested plastic piping and appropriate connections made on each end. “Mechanical couplings are commonly used for this purpose” (U.S. Department of Transportation, 2017, p. VI-20).  Repairs must be done by qualified technicians (Busby, 1997, p. 69). 

       Leaks in steel pipes can be repaired with “leak clamp[s] applied directly over the leak” (U.S. Department of Transportation, 2017, p. VI-20).  If multiple leaks are found, the easiest way to repair the pipe is to replace it altogether with pre-tested pipe that has been coated, wrapped, and strengthened by cathodic protection.  Steel pipe can also “be replaced by inserting PE pipe manufactured according to ASTM D2513 in the existing line and making the appropriate connections at both ends” (U.S. Department of Transportation, 2017, p. VI-20).  Qualified technicians must be used to make the repairs who will use the proper connections, provide adequate support, and consider thermal expansion and contraction of the PE pipe (U.S. Department of Transportation, 2017, p. VI-20).

       Instead of repairing cast iron natural gas pipes, the U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) instituted programs to identify, manage, and replace cast and wrought iron pipelines as early as 2009.  The Distribution Integrity Management Programs (DIMP) became mandatory for all U.S. pipeline operators in 2011 (U.S. Department of Transportation, 2020).

       In 2012, PHMSA urged state pipeline safety agencies to “monitor cast iron replacement programs, establish accelerated leak surveys, focus safety efforts on high-risk pipe, incentivize pipeline rehabilitation, repair and replacement programs, strengthen inspection, accident investigation, and enforcement actions, and install home methane gas alarms” (U.S. Department of Transportation, 2020).  While cast iron gas pipes can be repaired using PE or steel pipe and the appropriate connections by qualified technicians, the official recommendation is to replace these pipes altogether.

       The United States Department of Labor’s Occupational Safety and Health Administration (OSHA) is restricted by Section 4(b)(1) of the Occupational Safety and Health Act when it comes to oversight of oil and gas pipelines.  OSHA’s authority is largely limited to contractors hired by pipeline owners and operators and their workers when it comes to occupational health and safety hazards (United States Department of Labor, 2004).

       The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration (PHMSA) is the primary regulator of oil and gas pipelines in the United States.  The administration sponsors a Gas Distribution Integrity Management Program which requires all operators to create a Distribution Integrity Management Program (DIMP) that includes the following elements: “knowledge; identify threats; evaluate and rank risks; identify and implement measures to address risks; measure performance, monitor results, and evaluate effectiveness; periodically evaluate and improve program; report results” (U.S. Department of Transportation, 2020).

       Gas distribution systems are a necessary part of modern life.  With all stakeholders working together to achieve optimal safety, natural gas will continue to be a safe, low-cost, efficient form of energy.

References

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

U.S. Department of Transportation. (2017). Guidance Manual for Operators of Small Natural

       Gas Systems. Oklahoma City, OK: U.S. Department of Transportation.

U.S. Department of Transportation. (2020). Pipeline replacement. Retrieved from

https://www.phmsa.dot.gov/data-and-statistics/pipeline-replacement/

U.S. Department of Transportation. (2020). Gas distribution integrity management. Retrieved

       From https://www.phmsa.dot.gov/technical-resources/pipeline/gas-distribution-integrity-

       management-program/

U.S. Department of Labor. (2004). Laws and regulations. Retrieved from

https://www.osha.gov/laws-regs/standardinterpretations/2004-05-28-0

Dawn Pisturino

Thomas Edison State University

December 8, 2020; April 19, 2022

Copyright 2020-2022 Dawn Pisturino. All Rights Reserved.

Local Natural Gas Distribution Systems

(Photo: Unisource Energy Services)

If you’ve ever wondered where your natural gas comes from and how it gets to your house or business, here’s an example of how a local natural gas distribution system works. Regulations and construction requirements may differ from state to state.

Case Study: Local Natural Gas Distribution in Kingman, Arizona

Unisource Energy Services (UES) in Kingman, Arizona receives natural gas from the Transwestern Pipeline, which originates in Texas.  The steel transmission pipeline is 30 inches in diameter and operates at pressures from 200 to 1500 psi.  The pressure is reduced to 60 psi at UNS regulator stations and then reduced again to 0.25 psi before it enters the service lines that connect to home appliances (Unisource Energy Services, 2019; Energy Transfer, 2020).

In Arizona, there are four compressor stations along the Transwestern Pipeline at Klagetoh, Leupp, Flagstaff, and Seligman.  The compressors were built by USA Compression (Energy Transfer, 2020; USA Compression, 2020).

“Natural gas is compressed for transmission to minimize the size and cost of the pipe required to transport it” (Busby, 2017, p. 49).  Friction inside the pipe reduces the pressure and flow rate.  The gas is re-compressed at compressor stations in order to boost the pressure in the line.  Compressor stations are generally found every 50 to 100 miles along a pipeline.  They are a crucial part of the transport system that keeps the natural gas flowing through the pipe at the right pressure and flow rate.  Air is mixed in with the gas to lower emissions from the compressor stations (Busby, 2017, p. 49, 51).

Reciprocating compressors use high compression ratios but have limited capacities.  They are driven by internal combustion natural gas engines (Busby, 2017, p. 49).

Centrifugal compressors use lower compression ratios but have high capacities.  They rotate at 4,000 to 7,000 rpm and are driven by natural gas turbines.  They are energy efficient and cost less to install and use (Busby, 2017, p. 49-50).

The Transwestern Pipeline has an interconnect point at Kingman, Arizona, at legal description 21 N, 16 W, in Section 19.  There is a measuring station there that measures the amount of gas delivered to the Kingman interconnect (Energy Transfer, 2020).

Transwestern utilizes all types of meters in its measuring stations: orifice meters to measure gas received or delivered at an interconnect; turbine meters or ultrasonic meters to measure displaced gas; and coriolus meters, all according to the AGA Gas Measurement Manual (Energy Transfer, 2020).

“Metering of gas flow is an important function of pipeline gas operations” (Busby, 2017, p. 51) because customers along the line pay for the amount of natural gas they receive.  Meters must be accurate in order to ensure accurate and reliable billing (Busby, 2017, p. 49).

Many natural gas companies handle seasonal demand by storing natural gas in underground facilities or storing it as liquefied natural gas (LNG).  “Peak shaving is one of the most common domestic uses for LNG today” (ADI Analytics, 2015).  When seasonal demand (usually in the winter) requires a bigger load of natural gas, the “LNG is regasified and sent to the distribution pipelines” (Maverick Engineering, 2016).

Natural gas supplies can also be augmented with synthetic natural gas (SNG) during seasonal demand.  SNG is actually propane-air or liquefied petroleum gas air (LP-air) which “is created by combining vaporized LPG with compressed air” (Transtech Energy, 2020).  During seasonal demand, peak shaving facilities inject SNG into the natural gas distribution system to augment the real natural gas in order to meet increased demand (Transtech Energy, 2020).

Another way to increase the natural gas supply during peak demand is line packing.  This requires installing oversized pipes in transmission lines, which is incredibly expensive, and not always worth the cost (INGAA Foundation, 1996).

Unisource Energy Services has no storage facilities so it must plan ahead and estimate how much natural gas it will need to meet the winter peak demand.  Then it must contract with a reliable natural gas supplier, schedule the deliveries, and submit its Gas Supply Plan to the Arizona Corporation Commission.  This arrangement is called an asset management agreement (AMA) (American Gas Association, 2019; Arizona Corporation Commission, 2017).

As local natural gas distribution companies grow, they must install new lines to accommodate new customers.  The state of Arizona requires that all excavations be reported to the state at least 2 days before the actual trenching.  All utility lines must be discovered and clearly marked.  Only manual digging can be used within 24 inches of marked lines (Arizona 811, 2020).  These requirements were put in place for safety reasons, to prevent damage to buildings and injuries to humans.

Joint trench requirements can differ from city to city, county to county, and state to state. But a typical safe guideline is as follows: a trench at least 36 inches deep and 18 inches wide; 24 inches between gas and electric lines and between natural gas and water lines; 12 inches between natural gas and communication lines; 24 inches between natural gas and sewer lines (Arizona Public Service Electric, 1995; Lane Electric Cooperative, 2020).

Unisource Energy Services is required by law to follow state and local construction requirements and trenching laws.  The company uses plastic pipes 0.5 to 8 inches in diameter and coated steel pipes 0.75 to 16 inches in diameter (Unisource Energy Services, 2019).  Like all natural gas companies, company engineers must consider line pressures, the length of the line, and estimated load when deciding which pipes to use.

References

ADI Analytics. (2015). A new role for small-scale and peak shaving lng infrastructure.

       Retrieved from https://www.adi-analytics.com/2015/06/03/a-new-role-for-small-scale-and-

       peak-shaving-lng-infrastructure/

American Gas Association. (2019). LDC supply portfolio management during the 2018-2019

       winter heating season. Retrieved from

Click to access whs-2018-2019-report-final-12-20_2019-.pdf

Arizona 811. (2020). Proper planning. Retrieved from https://www.arizona811.com.

Arizona Corporation Commission. (2017). Winter preparedness. Retrieved from

https://www.azcc.gov/docs/default-source/utilities-files/gas/winter-preparedness-2017/uns-

       gas-2017-winter-prepardness.pdf?sfvrsn=daa79b6f_2_.

Arizona Public Service Electric. (1995). Trenching requirements. Retrieved from

https://www.aps.com/en/About/Construction-and-Power-Line-Siting/Construction-Services.

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

Energy Transfer. (2020). Natural gas. Retrieved from

https://www.energytransfer.com/natural-gas.

INGAA Foundation. (1996). The use of liquefied natural gas for peaking service. Retrieved from

https://www.ingaa.org/File.aspx?id=21698.

Lane Electric Cooperative. (2020). Typical trench detail. Retrieved from

Programs & Services

Maverick Engineering. (2016). Oil & gas: LNG: Peak shaving facilities. Retrieved from

https://www.maveng.com/index.php/business-streams/oil-gas/lng/peak-shaving-facilities.

Transtech Energy. (2020). SNG peak shaving system design & implementation. Retrieved from

https://www.transtechenergy.com/peak-shaving-systems.

Unisource Energy Services. (2019). Construction services. Retrieved from

Construction Services

USA Compression. (2020). Gas compression. Retrieved from

Gas Compression

Dawn Pisturino

Thomas Edison State University

November 19, 2020; April 18, 2022

Copyright 2020-2022 Dawn Pisturino. All Rights Reserved.

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

History of Chevron Corporation

(Standard Oil Company of California gas station)

       In September 1876, oil driller Alex Mentry struck oil at Pico No. 4 in Pico Canyon, California.  This set off a new “gold rush” in search of oil, the “black gold.”  At the time, Mentry worked for California Star Oil.  A few years later, on September 10, 1879, Pacific Coast Oil Company, which had incorporated in San Francisco, California on February 19, 1879, acquired California Star Oil – and this is where the history of Chevron begins (Chevron, 2020).

       Pacific Coast built the largest refinery in California at Point Alameda on San Francisco Bay, with the capacity to produce 600 barrels a day.  The company built a pipeline from Pico Canyon to the Southern Pacific Railroad train station at Elayon in southern California. By 1895, they had acquired the first steel tanker in California, the George Loomis, which could hold 6,500 barrels of crude oil (Chevron, 2020).

       In 1878, competition appeared in the form of Standard Oil Company (Iowa).  Known for its marketing skills, quality products, effective advertising campaigns, and rich financial backing, it set up shop in San Francisco, California with the goal of dominating the West Coast’s oil market.  By 1885, Standard Oil had distribution centers throughout the West Coast.  By contrast, Pacific Coast Oil Company was struggling to survive. Finally, in 1900, Standard Oil purchased the struggling company in order to increase its own production, transportation, and refining operations. In 1906, consolidation between Pacific Coast Oil and Standard Oil (Iowa) produced a new company – Standard Oil of California (Chevron, 2020).

       In 1911, Standard Oil of California established the California Natural Gas Company at its El Segundo plant in southern California in order to explore for natural gas in the San Joaquin Valley.  A second pipeline was built, linking the Richmond refinery, which was built in 1902, and the Kern River Field (Chevron, 2020).

       In an effort to conserve energy resources, the Starke gas trap – invented by engineer C.C. Scharpenberg and geologist Eric Starke — was invented and implemented for capturing natural gas from a well (Chevron, 2020).

       Between 1912 and 1919, Standard Oil of California expanded its operations until it saturated the market in a five-state area.  “Petroleum and natural gas are by far the major fuels used on the Pacific Coast” (Miller, 1936, p. 86).  But its market share had dropped by 1926 due to increased competition.  With the re-opening of the Panama Canal in 1914, Standard Oil of California ventured into the international market and expanded its market share in the Eastern United States and Europe (Chevron, 2020).  Natural gas use, however, continued to grow, from 72,000 cubic feet consumed on the West Coast in 1921 to 258,000 cubic feet consumed in 1933 (Miller, 1936, p. 86).

       Standard Oil of California continued to expand its operations through subsidiaries, mergers, and partnerships.  It opened operations in the Middle East, Canada, Mexico, and Central America.  In September 1950, the company completed the Trans-Arabian Pipeline.  Company revenues reached 1 billion dollars in 1951.  A merger with Standard Oil of Kentucky in 1961 expanded its markets in five southeastern states.  In 1977, Chevron USA was formed with the merger of six domestic oil and gas operations.  In 1979, Chevron celebrated 100 years of operations (Chevron, 2020).

       In March 1984, Chevron merged with Gulf Oil Corporation.  This merger increased their reserves of oil, gas, and natural gas liquids.  In the 1990s, Chevron developed the Escruvos

Natural Gas project in Nigeria, converting natural gas to liquids.  In 1996, “Chevron transferred its natural gas gathering, operating, and marketing operation to NGC Corporation (later Dynergy) in exchange for a roughly 25% equity stake in NGC” (Chevron, 2020). Through its merger with Texaco, Chevron acquired 11 million oil-equivalents of natural gas reserves.  Using 3-D imaging signals, Chevron discovered one of the largest crude oil and natural gas fields in the U.S. Gulf of Mexico in May 2009.  In 2005, Chevron changed its name to Chevron Corporation, acquired Unocal, and increased its natural gas reserves by 15 per cent.  The Gorgon Project and Wheatstone Project in Western Australia are boosting Chevron’s liquefied natural gas reserves. Gorgon, which will supply the Asia-Pacific market, had a daily production of 2.3 billion cubic feet of natural gas and 6,000 barrels of condensate in 2019.  Production is projected to last 40 or more years, with 15.6 million metric tons of liquefied natural gas produced per year (Chevron, 2020).

       “Chevron’s development of oil and natural gas from shale and tight rock formations has intensified since the company entered the Marcellus Shale through its acquisition of Atlas Energy in 2011” (Chevron, 2020).  The company’s policy of partnerships, mergers, and acquisitions has paid off handsomely for its bottom line and future success.

       Likewise, experts say that energy demand could increase by 33% by the year 2040, making all sources of energy important: natural gas, crude oil, coal, renewables, and nuclear (Chevron, 2020).  California alone “produced more than 200 million cubic feet of natural gas in 2017 used for heating and cooking in homes and businesses and to generate electricity” (Powering California, 2019).  Chevron has expanded into geothermal, solar, wind, biofuel, fuel cells, and hydrogen energy.  It recently invested in Carbon Clean Solutions, a company which is developing technology that “removes carbon dioxide at a price of $30.00 per ton” (Houston Chronicle, 2020.)  The prototype is expected to come out in 2021.

       The demand for natural gas and liquefied natural gas has intensified as companies and consumers look for cleaner, cheaper sources of energy.  Liquefied natural gas (LNG) can be easily shipped and stored because cooling the gas at temperatures of -260 degrees Fahrenheit shrinks the gas into 600 times smaller its normal volume.  LNG can be re-gasified and transmitted through natural gas pipelines to power plants fueled by natural gas, as well as industrial, residential and commercial consumers.  Markets for both natural gas and LNG have increased in the U.S. since 2007, and Asian countries are demanding more imported product (U.S. Energy Information Administration, 2020).  Chevron Shipping Company has a large fleet of crude oil tankers and LNG carriers to meet this demand (Chevron, 2020).

       Chevron has crude oil and natural gas fields in Colorado, New Mexico, and Texas. In 2018, they produced 651 million cubic feet of natural gas and 77,000 barrels of natural gas liquids (NGL).  In 2018, Chevron’s holdings in the Gulf of Mexico produced 105 million cubic feet of natural gas and 13,000 barrels of NGLs. Its Jack and St. Malo fields produced 139,000 barrels of liquids and 21 million cubic feet of natural gas. Its Big Foot Project produced 25 million cubic feet of natural gas per day. Its Tahiti field in the Gulf produced 22 million cubic feet of natural gas and 3,000 barrels of NGLs.  Its Mad Dog Field yielded 8,000 barrels of liquids and 1 million cubic feet of natural gas.  The Stampede Field produced 4 million cubic feet of natural gas. In California, 25 million cubic feet of natural gas and 400 barrels of NGLs were produced.  In the Appalachian Basin, 240 million cubic feet of natural gas, 4,000 barrels of NGLs, and 1,000 barrels of condensate were produced (Chevron, 2020).

       “The Chevron Pipe Line Company transports crude oil, refined petroleum products, liquefied petroleum (LPG), natural gas, NGLs, and chemicals within the U.S.” (Chevron, 2020).  It manages pipelines for Chevron Phillips Chemical and has financial interests in other U.S. and international pipelines.  Chevron Power and Energy Management Company handles gas-fired and renewable energy power generation.  Cogeneration facilities fueled by natural gas produce electricity and steam and re-use recovered waste heat to optimize oil operations.  Chevron’s Supply and Trading branches in Houston, Texas, London, Singapore, and San Ramon, California provide support for crude oil and natural gas production operations, refining, and marketing. Approximately 5 million barrels of liquids and 5 billion cubic feet of natural gas are traded on the commodities exchange every day.  Chevron’s Gas Supply and Trading group “markets and manages transportation for Chevron’s equity natural gas production.  It also manages all LPG and NGL trading, including supplying refineries and marketing NGLs produced by Chevron’s refineries and Upstream assets” (Chevron, 2020).

       In order to ensure a qualified work force for the future, Chevron invests in education to teach high school students science, technology, engineering, and mathematics (STEM).  Geologists, chemists, IT specialists, healthcare workers, engineers, and other specialists working for Chevron must be experienced professionals in their fields.  They actively encourage girls to become proficient in STEM.  And they support programs to help low-income men and women get the skills they need to get high-paying jobs in the global energy industry (Chevron, 2020).

       More than 100 years later, Chevron is exploring, researching, developing, and utilizing new technologies in order to meet increasing demands for energy.  It continues to be a leader in the global energy industry.

Dawn Pisturino

Thomas Edison State University

December 16, 2020

Copyright 2020-2022 Dawn Pisturino. All Rights Reserved.

References

Chevron. (2020). History: see where we’ve been and where we’re going. Retrieved from

https://www.chevron.com.

Chevron. (2020). Operations: driving human progress. Retrieved from

https://www.chevron.com.

Chevron. (2020). Project portfolio: delivering energy worldwide. Retrieved from

https://www.chevron.com.

Houston Chronicle. (2020). Chevron invests in carbon capture technology company. Retrieved

       from https://www.houstonchronicle.com/business/energy/article/Chevron-invests-in-carbon-

       capture-technology-15063229.php.

Miller, W. (1936). Pacific Coast Oil and Natural Gas. Economic Geography, 12 (1), 86-90.

       doi: 10.2307/140266.

Powering California. (2019). The history of oil and natural gas in california. Retrieved from

https://www.poweringcalifornia.com/the-history-of-oil-and-natural-gas-in-california-2/

U.S. Energy Information Administration. (2020). Natural gas explained. Retrieved from

https://www.eia.gov/energyexplained/natural-gas.

Evolution of Natural Gas in America

The natural gas industry is so vital to the functioning and prosperity of the United States that a depletion of natural gas resources would cripple the whole country.  Roughly 25% of the energy used in the United States comes from natural gas.  From manufacturing uses to home energy consumption, natural gas plays an important role in everyday life, even if American consumers are unaware of it (Busby, 1999, p. xviii).

       Natural gas is a natural resource that has developed over millions of years of plant and animal decomposition.  It is often found at the bottom of bodies of water that have existed for eons, such as oceans and lakes.  Plant and animal matter that became buried before decomposition or became lodged in anaerobic water, such as a stagnant pond, avoided oxidation.  As sand, mud, and other materials collected on top of the organic matter over long periods of time, these materials solidified into rock.  The organic matter was preserved by the rock. Years and years of pressure and heat turned the organic matter into gas and oil.  “Coal, shale, and some limestones have a dark color that comes from their rich organic content.  Many sedimentary basins are gas-prone and produce primarily natural gas” (Busby, 1999, p. 2-3).

       The average composition of natural gas, after processing, is 88% methane, 5% ethane, 2% propane, and 1% butane (Busby, 1999, p. 2).  The natural gas widely used today is, therefore, largely methane, “a colorless, odorless gas that burns readily with a pale, slightly luminous flame (Busby, 1999, p. 1).  The by-products of burning natural gas are mostly water vapor and carbon dioxide, making it “the cleanest burning fossil fuel” (Busby, 1999, p. 1).

       Methane is used in making solvents and other chemical compositions.  Propane and butane are separated from natural gas and sold as separate fuels. Liquified petroleum gas (LPG) is mostly propane and used as a fuel in rural areas where pipelines do not exist.  When carbon dioxide and helium are recovered from natural gas, they are often used to boost production in old oil fields.  Helium that is recovered from natural gas is used to fill balloons and blimps.  It is also widely used in the electronics industry.  Hydrogen sulfide, which is very corrosive, must be removed from natural gas before it is transmitted through pipelines or it will damage vital parts of gas wells and pipes (Busby, 1999, p. 1-2).

       Wood that has been subjected to high temperatures over time, turns into coal.  Coal seam gas is primarily methane. At depths with cooler temperatures, bacteria produce microbial gas, which is largely methane. Thermogenic gas develops at lower depths and with temperatures greater than 300 degrees Fahrenheit.  Trapped in underground reservoirs, high temperatures sometimes “gasify” the heavier hydrocarbons.  When the temperature cools, the gas re-liquifies and forms a condensate, which is largely pure gasoline. This is known as “wet” gas.  “Dry” gas is composed of pure methane.  Natural gas liquids (NGL) are composed of butane, propane, ethane, and gasoline condensate.  At depths greater than 18,000 feet, high temperatures turn oil into natural gas and graphite (Busby, 1999, p. 3-4).

       “Most deep wells are drilled in search of natural gas . . . [because] most gas that has been generated over the ages has been lost rather than trapped, which is why many exploratory wells are unproductive” (Busby, 1999, p. 3-4).  The reservoir rock holding the gas must be porous as well as permeable to allow for containment and access.

       Although people in the past were aware of natural gas, it was not until the 1800s that gas began to be developed and used for various purposes.  Coal gas began to be utilized in gas lighting in America and Europe, which allowed factories and businesses to operate for longer hours and families to engage in more social activities in the evenings (Busby, 1999, p. 5-6).

       One of the first inventors to experiment with coal gas was William Murdoch.  His experiments were so successful that his employer, Boulton & Watt, expanded its business to include “installing gas lighting in English factories” (Busby, 1999, p. 6).  The city of Birmingham adopted gas lighting, which inspired great demand for this new technology (Busby, 1999, p. 6).

       One of the first gas lights, the Thermolamp, was invented by Philippe Leon in France in 1799.  He patented a process to generate gas from wood and put it on display in Paris in 1802.  But the French government rejected the idea of a massive lighting system fueled by gas (Busby, 1999, p. 6).

       In 1807, Frederick Winsor “staged the first gas street-lighting display in London” (Busby, 1999, p. 6).  He had found a way to pipe large quantities of gas via a centralized system and founded his own public gas distribution company in 1812 (Busby, 1999, p. 6).

       By 1819, London had installed approximately 300 miles of gas pipes that supplied more than 50,000 gas burners.  The pipes were made of wood, but these were eventually replaced by metal pipes (Busby, 1999, p. 6).                                                                                                                                        

       In America, Charles Peale began testing gas lighting in Philadelphia in 1802.  The city of Baltimore hired his son, Rembrandt Peale, to install a gas lighting system in 1816.  The first gas utility company in America was born in that year, and more sprouted up along the East coast.  The first gas company in the southern states was established in New Orleans (Busby, 1999, p. 6).

       America could boast around a thousand companies selling coal gas for lighting by the end of the 19^th century.  And most major cities around the world had adopted gas lighting (Busby, 1999, p. 6).

       Most consumer gas distribution was not metered but delivered at a flat rate, which was based on the number of hours of use and the number of lights in a household or business.  A gas meter was invented in 1815.  By 1862, gas meters – which monitor the volume of gas used – were being used in London.  Coin-operated meters became available in the 1890s which allowed poorer consumers to utilize gas energy as they could afford it (Busby, 1999, p. 7).

       “Coke is a solid, porous by-product of gas manufacturing that can also be used for domestic heating” (Busby, 1999, p. 8).  The evolution of the iron and steel industries created a demand for blast-furnace coke that led to the development of the push-through-coke oven.  The demand for coke oven gas increased until it “constituted 18.7% of all manufactured gas” (Busby, 1999, p. 8) in 1920.

       As new uses for gas were discovered, developed, and implemented, “the first gas range in the U.S. was built around 1840” (Busby, 1999, p. 8).  The Goodwin Company introduced the Sun Dial Stove in 1879.  Two more gas stove manufacturers opened within four years.  And in 1887, the first gas appliance store opened in Providence, Rhode Island.  By 1900, cooking with gas had outstripped gas lighting and gas heating (Busby, 1999, p. 8).                                                                                                            

       Using gas to heat water storage tanks became popular in the 1860s.  The year 1883 saw the first circulating water heater come onto the market.  A water heater with a thermostat was introduced a few years later. Gas distribution was fast becoming a household necessity (Busby, 1999, p. 9).

       Natural gas was frequently discovered in the 1800s when people drilled for water, but the gas was ignored.  It was not until 1821 that William Hart drilled the first natural gas well and piped it through wooden pipes to neighbors’ homes.  This same gas was used to light up the City of Fredonia, New York a few years later (Busby, 1999, p. 9).

       Gas wells were drilled in Pennsylvania, New York, and West Virginia throughout the 1830s and 1840s.  But gas pipes were still primitive and only able to transport gas to customers near the gas wells (Busby, 1999, p. 10).

       The first natural gas company opened in Fredonia, New York in 1865.  When oil was discovered in Titusville, Pennsylvania, an oil rush ensued that diminished the importance of natural gas.  “Gas produced along with oil was usually just burned off, or flared” (Busby, 1999, p. 10).

       Andrew Carnegie, the famous steel magnate, documented in 1885 that 10,000 tons of coal had been replaced by natural gas.  But as the supply of natural gas became depleted, steel makers were forced to revert to using coal again by 1900.  This pattern repeated itself for the next 25 years.  Wastefulness and leakage were the main culprits (Busby, 1999, p. 10).

       The first long-distance wooden pipeline was built between West Bloomfield and Rochester, New York in the 1870s when a large reservoir of natural gas was discovered in West Bloomfield.  The gas was transported through this 25-mile pipeline (Busby, 1999, p. 10).

       Indiana Gas and Oil Company laid a 120-mile parallel pipeline made of wrought iron in 1891 that used high pressure (525 psi) to transmit natural gas to Chicago from the gas field in Indiana.  The company started using manufactured gas when the natural gas supply ran out in 1907 (Busby, 1999, p. 10-11).

       Oxyacetylene welding was invented in 1911 which sped up development of seamless steel pipe in the 1920s.  Natural gas could now be transmitted at higher pressures and in larger quantities and to longer distances, which boosted profitability for natural gas companies and helped them compete with other fuels.  The natural gas industry continued to expand until the Great Depression, which slowed down economic activity across the country.  As soon as World War II was over and the economic climate improved, the industry began to boom again (Busby, 1999, p. 11-12).

       Natural gas is one of the main fuels used in the food processing industry in the United States.  Large boilers are used to create process steam, which is used in “pasteurization, sterilization, canning, cooking, drying, packaging, equipment clean-up, and other processes” (Busby, 1999, p. 87). Natural gas energy saves companies money when they install “high-efficiency, low-emission natural gas-fired boilers” (Busby, 1999, p. 87). 

       Large amounts of hot water are also needed for “cleaning, blanching, bleaching, soaking, and sterilization” (Busby, 1999, p. 87).  High-efficiency industrial water heaters are used routinely in food processing.  Gas appliances are also used for “drying, cooking, and baking, as well as for refrigeration, freezing, and dehumidification” (Busby, 1999, p. 87).

       Tyson Foods has made a commitment to reduce energy use and produce fewer emissions that puts them at the top of the food processing industry.  As of 2019, they were using 42.15%

non-renewable fuels (including natural gas), 15.72% electricity, and 0.45% renewable energy (wind and solar power).  They are using renewable fuels like biogas from their waste treatment plants in their plant boilers in order to reduce their natural gas use.  They used about 666 million cubic feet of biogas in their boilers in 2019.  Although their energy use went up in 2019, their emissions went down.  The company is reusing process water in their plants to reduce water use.  And it is considering natural gas, electrification, and hydrogen fuel for their transportation fleet (Tyson Sustainability, 2019).

       “Natural gas . . . is the cleanest burning fossil fuel, and emits very few pollutants into the atmosphere” (Natural Gas, 2013).  Although Tyson is already using natural gas in its plants, it might want to consider using natural gas to generate its own electricity in order to free itself from dependency on local electric companies.  This could save them money in the long run, especially as electricity rates go up and electricity delivery reliability goes down.  This, however, would require a large capital investment that Tyson might not want to make (Natural Gas, 2013).

       But Tyson is already using boilers that produce steam, and this steam could be used to generate electricity.  If the boiler keeps running, “the steam can be diverted to a turbine for generating power” (Busby, 1999, p. 87-88).  This is called cogeneration because “waste heat is recovered and used” (Busby, 1999, p. 87).

       Although most power plants have been fueled by coal, there has been a push towards using natural gas because this reduces emissions of sulfur dioxide, nitrogen oxides, soot, and smoke (Busby, 1999, p. 88).  “Natural gas can be used to produce electricity either directly, in a gas-powered turbine, or indirectly, in a steam-powered turbine (using steam from a gas-fired boiler)” (Busby, 1999, p. 89).  The natural gas also serves to increase boiler efficiency.

       Natural gas demand is expected to increase in the future as consumers expect energy efficiency regulations to reduce emissions in the atmosphere and industries are pressured to use low-carbon fuels.  Natural gas is a clean, reliable, and efficient energy source that can be used with confidence in the residential, commercial, and industrial settings.

Dawn Pisturino

Thomas Edison State University

October 14, 2020

Copyright 2020-2022 Dawn Pisturino. All Rights Reserved.

References

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

Tyson Sustainability. (2019). 2019 sustainability report. Retrieved from 

https://www.tysonsustainability.com/environment/energy-emissions.

.

A Case Study in Drought: Bullhead City, Arizona

New York Post – Lake Mead at Hoover Dam

Bullhead City, Arizona Primary Hazard: Drought

According to the National Drought Mitigation Center, drought is considered a creeping natural hazard because it has no “clear beginning and end like tornadoes or hurricanes or floods” (National Drought Mitigation Center, 2019, para. 19).  It can develop over many months or years as the climate in a region changes.  This is called “natural climate variability . . . we consider drought to be a normal part of climate just like floods, hurricanes, blizzards, and tornadoes” (National Drought Mitigation Center, 201, para. 7).

Why Bullhead City has the Highest Probability of Drought

Bullhead City, Arizona is a desert community on the Colorado River which sits at an elevation of 566 feet above sea level.  Roughly 40,000 people call it home (City Data, 2017).  Due to an abundance of rain and snow during the 2018-2019 winter season, the U.S. Drought Monitor determined in June, 2019 that Bullhead City had graduated from drought to an abnormally dry area (Associated Press, 2019).  As of this writing, however, the monsoon season—which normally dumps a lot of rain in the area—has been sparse, and Bullhead City is in danger of falling back into drought if the 2019-2020 winter season does not produce adequate precipitation.

Lack of precipitation affects water levels in lakes, rivers, and reservoirs.  Lake Mead, which is held in place by the Hoover Dam, supplies the bulk of water used by residents in Bullhead City and other populated areas along the Colorado River (Associated Press, 2019).

In April, 2019, Congress passed an updated Colorado River Drought Contingency Plan which affects Arizona, California, Nevada, and other states dependent on the Colorado River for water and hydroelectric power.  If Arizona loses its Colorado River allotment, communities will have to pump groundwater, which can be contaminated with natural nitrate and arsenic, or find other alternatives, such as the unpopular use of recycled water (Whitman, 2019).                                                                                                                                         

Removing contaminants raises the cost of water to consumers.  The ideal situation is “to pump only as much groundwater as flows back underground, a balance known as safe yield, by 2025” (Whitman, 2019, para. 13).  But that is a tough goal to implement.  Water conservation measures can stifle growth, an unpopular idea in high-growth areas.

Currently, the Colorado River supplies water to more than 30 million people in seven states, with 70% of that water used for agriculture (Zielinski, 2010).  When government officials designated water allotments to these states in 1922, there were far fewer people living in the region.  And the strain is showing: “the Colorado River no longer regularly reaches the sea” (Zielinski, 2010, para.10).  In fact, it turns into a pathetic mud puddle 50 miles north of the Pacific Ocean.

The Los Angeles Department of Water and Power (DWP) plans to build a solar-powered pump station south of Hoover Dam on the Colorado River that would continually refill Lake Mead and produce a continuous supply of hydroelectric power to millions of people in California.  The fear is that this project would shrink water supplies to communities farther down the Colorado River—such as Bullhead City (Grossman, 2018).

Shrinking water supplies, smaller water allotments, and increased demand have fueled tensions between the states dependent on the Colorado River—especially, between Arizona and California.  And those tensions are not going away anytime soon (Runyon & Jaspers, 2019).

Preparedness, Mitigation, Response, and Recovery

Bullhead City has its own Drought/Water Shortage Contingency Plan.  The Arizona State Legislature passed House bill 2277 in 2005 which requires communities to develop and maintain a system water plan that includes three parts: a water supply plan, a water conservation plan, and a drought preparedness plan.  This requirement has become part of the State’s water resource management plan to develop preparedness and mitigation strategies at both the local and state level (City of Bullhead City, 2016).

The United States Bureau of Reclamation (USBR) also requires local communities to develop drought/water shortage contingency plans to conserve water.  These plans outline community response to reductions in the water supply due to drought, infrastructure failure, or other causes (City of Bullhead City, 2016).

Bullhead City depends solely on the Colorado River for its water supply.  Arizona’s water allotment was designated in the 1922 Colorado River Compact.  “The city of Bullhead City diverts its Colorado River surface water allocation through groundwater wells” (City of Bullhead City, 2016, p. 5).  This is possible because of the Colorado River aquifer that exists.

The Secretary of the Interior can declare a shortage of Colorado River water.  All states dependent on the Colorado River would be forced to share in the water shortage as determined  by the 2007 Record of Decision – Colorado River Interim Guidelines for Lower Basin Shortages and the Coordinated Operations for Lake Powell and Lake Mead.  Bullhead City’s right to Colorado River water is fourth priority, which means that communities with higher priority will get their Colorado River water first.  The Mohave County Water Authority (MCWA) has set aside 107, 239 acre-feet of long-term water credits for Bullhead City.  Bullhead City, along with other Colorado River communities, has been given until 2026 to put preparedness plans in place to respond to drought and water shortages (City of Bullhead City, 2016).

If the water credits are eventually used, Bullhead City has a contract with the Central Arizona Project water canal to use groundwater pumping to recover their allotted water.  The use of such credits would incur extra costs that would be passed on to consumers (City of Bullhead City, 2016).

Bullhead City has developed plans to respond to a 20% and a 40% reduction in water supplies.  Both plans call for the unpopular use of reclaimed (recycled) water.  The extensive use of reclaimed water would require the building of extra infrastructure (City of Bullhead City, 2016). 

The response plan for Bullhead City has been developed as a staged response with the following components: water use reduction; priority users and water reduction; water rates/financial incentives; the role of private water companies; preparedness and mitigation plans for private water companies sub-contracted by Bullhead City; voluntary versus mandatory water reduction; agricultural irrigation versus drinking water; water conservation; public education; stored water recovery and delivery; scenarios of probable water shortage conditions; the use of reclaimed water; demand versus supply evaluation.  These plans would be implemented according to the water level in Lake Mead.  The strictest water management plans would be enforced when the level in Lake Mead is at or below 1,025 feet (City of Bullhead City, 2016).

In the meantime, Bullhead City has waged a public education campaign about the use of xeriscaping using low-water plants and trees; drip irrigation; and harvesting rainwater for landscape use (Water Resources Research Center, 2019).  Tips on conserving water are freely available on the city’s website.  Water rebates are available to consumers.  Water usage reports are available for public perusal.  And water development fees have been imposed to improve water services in the city (City of Bullhead City, 2019).

Bullhead City receives an average of 3 to12 inches of rain a year (Arizona Water Facts, 2019).  Epcor, a private water company, has raised consumer water rates 25% to 35% during the drought.  This situation has prompted Bullhead City to introduce Proposition 415, which would approve a bond up to $130 million to buy out the company (City of Bullhead City, 2019).  If approved, the city will own another source of water and provide water services at a lower cost to consumers.

Identify Gaps and Suggest Expansion of Preparedness, Mitigation, Response, and Recovery Plans

Bullhead City has not done enough to control population growth.  The city advertises itself as the lowest cost of living city in the state based on a 2015 study done by the Council for Community and Economic Research (Merrill, 2015).  This draws more people on fixed incomes from within and outside of the state.  These people can ill afford to pay higher water rates and development fees.  And if water supplies are, indeed, shrinking, Bullhead City can ill afford to add more people to its population.

Furthermore, if Bullhead City plans to use reclaimed water in the future, it needs to build the infrastructure now, and not wait for an emergency situation to arise.

Initial Evaluation and Emergency Management Procedures

Drought is the main hazard facing Bullhead City, Arizona.  It is dependent on water supplied by the Colorado River and the allotment it receives based on the Colorado River Compact of 1922.  Although it has plans in place for a 20% and 40% reduction in water supplies, it has not planned for anything more severe.  At the very worst, the governor of the State of Arizona would declare a disaster and water would have to be trucked in for residential and business use.  A lack of water would lead to social chaos and fighting among citizens.  There would be a mass exodus of people out of town.  Law enforcement would be heavily involved to control the situation. EMS personnel and local hospitals would have to deal with people who were severely dehydrated.  Animals would be abandoned and left to die from thirst.  City officials would be overwhelmed by demands for water.

Interrelationships among the Core Components of the Emergency Management Phases

Drought and water shortages can vary from season to season.  Preparedness plans to deal with these problems and to mitigate the costs and impacts are essential to protect the vital resource of water.  Well-conceived plans must be in place to respond to serious shortages of water for the sake of the community.  If the problem becomes serious enough, there might not be a recovery phase.

Conclusion

The desert was never meant to support millions of people.  Water is a precious resource that has not been taken seriously enough by government officials, city planners, and members of the real estate and development professions.  Bullhead City is dependent on a river it cannot control, weather and climate it cannot control, and State politicians it cannot control.  The city must do whatever it takes to protect its water supply.

Dawn Pisturino

Thomas Edison State University

September 24, 2019

References

Arizona Water Facts. (2019). Bullhead City, Arizona. Retrieved from

       http://www.arizonawaterfacts.com/mtw/bullhead-city.

Associated Press. (2019. June). Arizona out of short-term drought. Mohave Daily News.

       Retrieved from http://www.mohavedailynews.com/news/arizona-out-of-short-term-

       drought/article_8c36c50a-9259-11e9-ab41-9b4eacdd7bd1.html

City Data. (2017). Bullhead City, Arizona. Retrieved from

       http://www.city-data.com/city/Bullhead-City-Arizona.html

City of Bullhead City. (2019). City of Bullhead City. Retrieved from

       http://www.bullheadcity.com

City of Bullhead City. (2016). City of bullhead city drought/water shortage contingency

       plan. Retrieved fromhttp://www.bullheadcity.com/home/showdocument?id=7546

Grossman, D. (2018, July). The hoover dam changed america – And it might do it again.

       Popular Mechanics. Retrieved from

https://www.popularmechanics.com/technology/infrastructure/922539919/the-hoover-dam-

       changed-americaand-it-might-do-it-again.

Merrill, Laurie. (2015, June). Which arizona cities will cost you the least. AZ Central.

       Retrieved from https://www.azcentral.com/story/money/business/2015/06/17/bullhead-

       city-cheapest-arizona-city/28899239.

National Drought Mitigation Center. (2019). What is drought. Retrieved from

       http://www.drought.unl.edu/Education/Drought forKids/What is Drought.aspx.

Runyon, L. & Jaspers, B. (2019, February). What is happening with the colorado river drought

       plans. KPBS. Retrieved from

https://www.kpbs.org/news/2019/feb/07/what-is-happening-colorado-river-drought-plans.

Water Resources Research Center. (2019). Low-Water tree and plant guide. Retrieved from

       http://www.wrrc.arizona.edu

Whitman, E. (2019, April). After colorado river drought plan, what’s next for water in arizona.

       Retrieved from https://www.phoenixnewtimes.com/content/print/view/11268880.

Zielinski, S. (2010, October). The colorado river runs dry. Smithsonian Magazine.

       Retrieved from https://www.smithsonianmag.com/science-nature/the-colorado-river-runs-

       dry-61427169.

The Evolution of Emergency Management in the United States

Associated Press

What is “emergency management?”  According to Haddow, Bullock, and Coppola (2017), “the definition of emergency management can be extremely broad and all-encompassing.”  It is an evolving discipline whose priorities have changed in response to diverse events, political leadership, and scientific advances.

The nature of the events and the responses of political leaders have been the most influential in shaping emergency management priorities and organizational structure.  Since emergency management “deals with risk and risk avoidance” (Haddow, Bullock, & Coppola, 2017), no single event will be handled in precisely the same way.  A terrorist attack like 9/11, which was a major criminal event that involved foreigners and foreign countries, will have a much greater impact on the psyche of the American people and affect a broader range of government departments, than a natural event like a hurricane or earthquake.

The U.S. Constitution “gives the states the responsibility for public health and safety – hence the responsibility for public risks – with the federal government in a secondary role.  The federal role is to help when the state, local or individual entity is overwhelmed” (Haddow, Bullock, & Coppola, 2017).

What kind of events can hit American communities?  Natural events include floods, earthquakes, hurricanes, storm surges, tornadoes, wildfires, land movements such as avalanches and mudslides, tsunamis, volcanic eruptions, severe winter storms, drought, extremes of heat and cold, coastal erosion, thunderstorms, lightning, and hail.  Technological events can include building fires, dam failures, hazardous material incidents, nuclear and radiation accidents. 

Criminal events include terrorism and the potential use of biological, radiological, and nuclear weapons (Haddow, Bullock, & Coppola, 2017).      

On May 31, 1889, the South Fork dam in Johnstown, PA failed, and “unleashed 20,000,000 tons of water that devastated” the town and killed 2,209 residents (National Park Service,2017).  The failure was caused by inadequate construction, maintenance, and repair.  This event caught the attention of the entire world, and people banded together to help “the Johnstown sufferers” (National Park Service, 2017).

In 1803, Congress passed legislation authorizing federal funds to help a town in New Hampshire destroyed by fire.  This set the precedence for federal involvement in local events.  But it was under Franklin D. Roosevelt “that the federal government began to make significant investments in emergency management functions” (Haddow, Bullock, & Coppola, 2017).

The Reconstruction Finance Corporation and the Bureau of Public Roads were authorized “to make disaster loans available for repair and reconstruction of certain public facilities” (Haddow, Bullock, & Coppola, 2017) in the 1930s. The Tennessee Valley Authority – established to produce hydroelectric power – also sought to reduce flooding in the valley (Haddow, Bullock, & Coppola, 2017).

The Flood Control Act of 1936 authorized the U.S. Army Corps of Engineers “to design and build flood-control projects” (Haddow, Bullock, & Coppola, 2017).  Now, “humans could control nature” and promote growth and development in areas previously unavailable (Haddow, Bullock, & Coppola, 2017).

The 1950s and the Cold War brought a whole new dynamic to the discipline of emergency management.  Scientists had succeeded in creating a whole new arsenal of weapons with the capability of destroying the world.  The potential for nuclear holocaust was so great, “civil defense programs proliferated across communities” (Haddow, Bullock, & Coppola, 2017).  People built bomb shelters to protect themselves, their families, and their communities.  A feeling of paranoia gripped the entire nation as U.S. politicians engaged diplomatically with representatives from the Soviet Union.                                                                            

The Federal Civil Defense Administration (FCDA) was a poorly-funded department “whose main role was to provide technical assistance” (Haddow, Bullock, & Coppola, 2017) in the event of nuclear attack.  In reality, however, it was the civil defense directors at the local and state levels who shaped the policies and response to potential disaster.

The 1960s focused attention on natural disasters, and the National Flood Insurance Act of 1968 was passed by Congress.  The National Flood Insurance Program was subsequently created, which helped to ease the burden on homeowners located in flood areas and to act proactively before the floods began.  This legislation emphasized “the concept of community-based mitigation” (Haddow, Bullock, & Coppola, 2017).  When communities joined the NFIP, they committed themselves to passing local ordinances which controlled development in floodplain areas.  The federal government produced floodplain maps to support these ordinances.

George Bernstein, who became head of the Federal Insurance Administration under President Richard Nixon, strengthened the program by “linking the mandatory purchase of flood insurance to all homeowner loans that were backed by federal mortgages” (Haddow, Bullock, & Coppola, 2017).  This led to the Flood Insurance Act of 1972.

During the 1970s, “more than 100 federal agencies were involved in some aspect of risks and disasters” (Haddow, Bullock, & Coppola, 2017).  The fragmentation, conflicts, and confusion that resulted were no different on the state and local levels.  When Three Mile Island occurred, these problems became all-too-apparent to the general public.  As a result, the Federal Emergency Management Agency (FEMA) was created by Congress under President Jimmy Carter, with the director reporting directly to the president.

Reorganization Plan Number 3, which created FEMA, sought to establish the following guidelines: FEMA workers “were to anticipate, prepare for, and respond to major civil emergencies” (Haddow, Bullock, & Coppola, 2017); the agency would demand “the most efficient use of all available resources” (Haddow, Bullock, & Coppola, 2017); “emergency responsibilities should be extensions of federal agencies” (Haddow, Bullock, & Coppola, 2017); and “federal hazard mitigation activities should be closely linked with emergency preparedness and response functions” (Haddow, Bullock, & Coppola, 2017).

In the 1980s, civil defense became the priority under President Ronald Reagan.  Director Louis Giuffrida reorganized FEMA, moved multiple departments into one building, and placed the agency’s priority “on government preparedness for a nuclear attack” (Haddow, Bullock, & Coppola, 2017).  Giuffrida resigned after a financial scandal, which undermined the credibility of the agency.  The new director, Julius Becton, worked to restore “integrity to the operations and appropriations of the agency” (Haddow, Bullock, & Coppola, 2017).  Under Becton’s leadership, natural hazards like earthquakes, hurricanes, and floods were given a low priority, confirming that the agency “continued the pattern of isolating resources for national security priorities without recognizing the potential of a major natural disaster” (Haddow, Bullock, & Coppola, 2017).

Senator Al Gore, during Senate hearings, questioned FEMA’s priorities and its preparedness in the event of a major earthquake.  FEMA was pressured to create an earthquake preparedness plan which “would later become the standard for all of the federal agencies’ response operations” (Haddow, Bullock, & Coppola, 2017).

Under George H.W. Bush, multiple natural disasters occurred – including Hurricane Andrew – which affected people’s perception of FEMA.  “People wanted, and expected, their government to be there to help in their time of need” (Haddow, Bullock, & Coppola, 2017).  FEMA was perceived as weak and ineffective.

James Witt was appointed Director by President Bill Clinton.  Witt had extensive experience in emergency management and reorganized FEMA to support community relations, the efficient use of new technology, and an emphasis on “mitigation and risk avoidance” (Haddow, Bullock, & Coppola, 2017).

The 1990s heralded a new wave of natural disasters.  FEMA successfully handled the Midwest floods of 1993 and initiated “the largest voluntary buyout and relocation program to date in an effort to move people out of the floodplain . . .” (Haddow, Bullock, & Coppola, 2017).

Director Witt became a member of Clinton’s cabinet and persuaded state governors “to include their state emergency management directors in their cabinets” (Haddow, Bullock, & Coppola, 2017).  This is how important emergency management had become.

The bombing of the World Trade Center in 1993 and the Oklahoma Bombing in 1995 reaffirmed the notion that terrorist events fall into the category of “risks and the consequences of those risks” (Haddow, Bullock, & Coppola, 2017).  Emergency management has been an important part of handling similar events.

FEMA’s Project impact: Building Disaster-Resistant Communities heralded “a new community-based approach” (Haddow, Bullock, & Coppola, 2017) that required communities “to identify risks and establish a plan to reduce those risks” (Haddow, Bullock, & Coppola, 2017).  The ultimate goal was for the community to “promote sustainable economic development, protect and enhance its natural resources, and ensure a better quality of life for its citizens” (Haddow, Bullock, & Coppola, 2017).

Project Impact was defunded under President George W. Bush.  After the unexpected earthquake in Seattle, however, FEMA received a lot of praise from Seattle’s mayor, and the program was restored.  Seattle, it turned out, had been “one of the most successful Project impact communities” (Haddow, Bullock, & Coppola, 2017).

The events of 9/11 proved the effectiveness of FEMA when “hundreds of response personnel initiated their operations within just minutes of the onset of events” (Haddow, Bullock, & Coppola, 2017).  FEMA was then incorporated into the newly-formed Department of Homeland Security and lost much of its effectiveness and power.  The new National Incident Management System (NIMS) fell under the auspices of the Director of Operations Coordination (Haddow, Bullock, & Coppola, 2017).

The threat of Hurricane Katrina off the Gulf Coast in 2005 prompted President Bush to declare “a disaster in advance of an emergency event for the states in the projected impact zone” (Haddow, Bullock, & Coppola, 2017) and caused DHS/FEMA to shoulder the responsibility.  Their response was a failure.

Obama’s appointee, W. Craig Fugate, designated victims of disasters as “survivors” and developed the Whole Community concept which emphasized “preparedness partnerships that had been developed among federal, state, local, private sector, voluntary, and non-profit entities” (Haddow, Bullock, & Coppola, 2017).  Involving people from all sectors of the community has increased the effectiveness of emergency management response to disasters.

The history and development of emergency management prove how events influence and shape government policies, departmental organization, leadership priorities, and government response to national emergencies.  When all citizens get involved, emergency preparedness and response protect communities and mitigate the costs of recovery.

Dawn Pisturino

Thomas Edison State University

August 8, 2019

Copyright 2019-2021 Dawn Pisturino. All Rights Reserved.

References

Haddow, G.D., Bullock, J.A., & Coppola, D.P. (2017). Introduction to emergency

       management. Cambridge, MA: Elsevier Inc.

National Park Service. (2017). Johnstown flood national memorial pennsylvania.

       Retrieved from http://www.nps.gov/jofl/index.htm.

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.

9/11, the Incident Command System, and the National Incident Management System

Incident Command System and the National Incident Management System

[Twenty] years ago, America changed forever.  Protecting our nation from terrorist attacks became the primary objective.  The systems and operations developed to prepare, plan, mitigate, respond, and recover from terrorist attacks expanded to include ALL disasters.  We now have a national disaster plan which is utilized at the local, tribal, state, and federal levels.

Brief Overview of the Events of 9/11

At 8:46 a.m. on September 11, 2001, American Airlines Flight 11 crashed into the North Tower of the World Trade Center in New York City.  Seventeen minutes later, United Airlines Flight 175 smashed into the South Tower.  At 9:37 a.m., American Airlines Flight 77 nose-dived into the Pentagon building in Arlington, Virginia.  All three airplanes had been hijacked by members of the radical Islamic terrorist organization, Al Qaeda (Haddow, 2017; 911 Memorial, 2018).

“The use of fuel-filled planes caused catastrophic fires in all three buildings impacted, and this led to collapse of both World Trade Center towers and the wing of the Pentagon directly affected” (Haddow, 2017, p. 393).  The federal government has spent more than $20 billion on the response and recovery of the World Trade Center attacks alone.  On the positive side, the events of 9/11 led to the creation of the Department of Homeland Security and the development and implementation of a more comprehensive and advanced national response to disasters, regardless of size and cause (Haddow, 2017).

The Core Components of the National Incident Management System (NIMS)

“NIMS was created to integrate effective practices in emergency preparedness and response into a comprehensive national framework for incident management” (Haddow, 2017, p.247).  Its flexibility allows it to adapt to any kind of disaster, from routine incidents involving local communities to large-scale events, such as hurricanes or earthquakes (DHS, 2008).  NIMS provides a template for “coordination and standardization among emergency management/response personnel and their affiliated organizations” (DHS, 2008, p.7).

The National Incident Management System is guided by five core components: preparedness; communications and information management; resource management; command and management; and ongoing management and maintenance.  The National Integration Center is responsible for directing NIMS, using the latest technology and operational systems (DHS, 2008).

Preparedness is a multi-task discipline which uses assessment skills; advanced planning; appropriate procedures and protocols; up-to-date training and practice exercises; skilled personnel with the proper licensure and certification; the latest technology and equipment; and the ability to evaluate responses to events and revise protocols and procedures for improved responses to future events (DHS, 2008).

Communications and information management are crucial to emergency responders because all command and coordination stations must share a common goal and operating system in order to work effectively as a team (DHS, 2008).

Resource management demands that “the flow of resources [personnel, equipment, etc.] be fluid and adaptable to the requirements of the incident” (DHS, 2008, p. 8)  Without a well-coordinated movement of resources to the disaster site, responders cannot do their job in a timely and efficient manner.

Command and management “enable effective and efficient incident management and coordination by providing a flexible, standardized incident management structure” (DHS, 2008, p. 8) which involves the Incident Command System, Multi-agency Coordination Systems, and public information.  Jurisdiction, authority, and multi-agency involvement must be decided and coordinated before and during the disaster event for the response to be successful.

Ongoing management and maintenance by the National Integration Center ensures that the National Incident Management System will always perform at a top-notch level.  Failures and successes must be evaluated and addressed and systems refined accordingly (DHS, 2008).

How the Components of NIMS Support and Complete the Incident Command System (ICS)

“NIMS was developed as an outgrowth of ICS that allows for increased interorganizational coordination that is not necessarily addressed under standard ICS structures.  The system is designed to be a more comprehensive incident management system than ICS because it goes beyond the field-level incident command and control and addresses all phases of emergency management, as well as all stakeholders (including the NGO and private sectors).  It does not, however, replace ICS” (Haddow, 2017, p. 248).

The National Incident Management System provides a template by which the ICS can operate more efficiently.  It is an upper management organizational system that oversees the entire operation of a disaster event (Haddow, 2008).

The Incident Command System falls under the command and management component of the National Incident Management System.  ICS addresses all hazards, regardless of cause, at the federal, state, tribal, and local levels.  NGOs and the private sector are also included (DHS, 2008).

The ICS standardizes the use of common terminology for all agencies involved; inventories and describes resources used; and records incident fatalities (DHS, 2008).

A flexible organizational system adapts the ICS to the needs of a particular event.  A small, community-based incident will require less manpower and fewer resources than an event on the scale of Hurricane Katrina (DHS, 2008).

ICS develops a set of objectives by which an event can be measured, studied, and evaluated.  This is important for quality improvement.  The Incident Commander or Unified Commander creates an Incident Action Plan which “should guide all response activities” (DHS, 2008, p. 47).  There should be enough staff and supervisors involved to make the work flow go as planned (DHS, 2008).

The Incident Commander determines and oversees the locations of command facilities.  Resources must be carefully managed to control costs and availability.  Communication systems must be set up and maintained to provide optimal information sharing and communication (DHS, 2008).

How NIMS and ICS were Utilized in the Events of 9/11

The events of 9/11 resulted in a large number of fatalities among first responders.  It became necessary to re-evaluate and re-write appropriate procedures and protocols.  At that time, there were no procedures in place to deal with terrorist attacks.  The Department of Homeland Security was created, which absorbed FEMA into its structure.  The National Incident Management System gradually developed and was finally published in 2008 (Hadddow, 2017).

As soon as the North Tower of the World Trade Center in New York City was attacked on 9/11, New York City emergency dispatchers sent police, paramedics, and firefighters to the site.  Battalion  Chief Joseph Pfeifer of the New York City Fire Department dispatched additional fire personnel and equipment.  The Port Authority Police Department, which was responsible for the security of the World Trade Center, went into action to help with evacuation and rescue (911 Memorial, 2018).

President Bush was notified at 8:50 a.m.  At 8:55 a.m., the South Tower was declared secure, and no evacuation attempts were made. Four minutes later, it was decided to evacuate both towers.  And, at 9:00 a.m., all civilians were ordered to evacuate the World Trade Center complex.  At 9:02 a.m., evacuation efforts were underway, when the South Tower was attacked at 9:03 a.m.  President Bush was further informed at 9:05 a.m., and Mayor Rudy Giuliani arrived at the New York City Police Department Command Post (911 Memorial, 2018).

At 9:30 a.m., the Mayor’s Office of Emergency Management evacuated its office at the World Trade Center.  Vice-President Dick Cheney was evacuated from the White House (911 Memorial, 2018).

The Pentagon attack occurred at 9:37 a.m.  Emergency personnel immediately responded.  At 9:45 a.m., the White House and the U.S. Capitol Building were evacuated (911 Memorial, 2018).

The South Tower of the World Trade Center collapsed at 9:59 a.m.  At 10:15 a.m., the Pentagon E-ring collapsed.  The North Tower of the World Trade Center collapsed at 10:28 a.m., and the evacuation of lower Manhattan began at 11:02 a.m.  At 5:20 p.m., the entire World Trade Center collapsed.  All efforts after that were dedicated to putting out the fires, securing the crime site, finding and rescuing survivors, recovering the dead, identifying victims, and removing and cleaning up debris and body parts (Haddow, 2017; 911 Memorial, 2018).

In 2002, two after-action reports were released: Improving NYPD Emergency Preparedness and Response and Arlington County After-Action Report on the Response to the 9/11 Terrorist Attack on the Pentagon.  These reports helped to shape improvements in the emergency management discipline (Haddow, 2017).

The NYPD report identified twenty areas of improvement, with six warranting immediate action: “clearer delineation of roles and responsibilities of organizational leaders; better clarity in the chain of command; radio communications protocols and procedures that optimize information flow; more effective mobilization of response staff; more efficient provisioning and distribution of emergency and donated equipment; a comprehensive disaster response plan with a significant counterterrorism component” (Haddow, 2017).

It is easy to see here how the implementation of the National Incident Management System would have improved the response to the 9/11 World Trade Center attacks.  The Command and Management Component would have helped to define the authority of the Incident Commander and to clarify the chain of command.  The Communications and Information Management Component would have centralized communications and information sharing to present a clear picture of what was happening and what was needed.  The Resource Management Component would have coordinated the flow of personnel and equipment to the site to more efficiently deal with the disaster.  The Ongoing Management and Maintenance Component would have ensured that a comprehensive plan was in place to manage a major terrorist attack.  The Preparedness Component would have ensured that New York City was ready to bring all agencies together to work as an expert team in responding to a major disaster (DHS, 2008).

The response to the Pentagon attack was deemed a success due to its quick, coordinated, well-prepared response based on the Incident Command System.  Arlington County already had a Comprehensive Emergency Management Plan in place.  The Arlington County Fire Department had already considered the possibility of a weapons of mass destruction scenario and was well-prepared to respond (Haddow, 2017).

Conclusion

It is unfortunate that disasters have to occur in order to improve emergency management as a discipline and emergency response as a necessity of life.  But complacency is not an option.  Preparation is the key to effective response and recovery when disasters do occur.  The Incident Command System, guided by the core components of the National Incident Management System, is an effective tool for coordinating and managing preparation, planning, mitigation, response, and recovery of major disasters on the local, tribal, state, and federal levels.

Dawn Pisturino

Thomas Edison State University

September 18, 2019

Copyright 2019-2021 Dawn Pisturino. All Rights Reserved.

References

911 Memorial. (2018 ). 9/11 Memorial Timeline. Retrieved from

       http://www.timeline.911memorial.org/#FrontPage

Department of Homeland Security. (2008). National incident management system.

       Retrieved from http://www.fema.gov/nims.

Haddow, G.D., Bullock, J.A., & Coppola, D.P. (2017). Introduction to emergency

       management. (6^th ed.). Cambridge, MA: Elsevier.