1.answer the following with respect to bp case and rights based ethics. complete answer in full and complete sentences.
provide a definition of rights based ethics
provide a paragraphe explaining how bp failed in its expectation of considering the rights of its employees. this explanation must agree with the definition provided.
CASE STUDY: BP
Christina Ingersoll, Richard M. Locke, Cate Reavis
The assignment is at the end of the case study
I recommend you review the Near Misses and Hidden Traps BEFORE you read the case. Also review Duties and Rights Ethics.
The purpose of this exercise is to help you see, that in reality, how easy it is for people and organizations to fail in many of decision-making concepts and ethical theories we have studied. The goal is to show you that the concepts we have studied academically really are relevant. It is also to show you that when we fail in our ethical obligations and in our expectations to others, how catastrophic the affect is on our moral code.
When Mike Williams woke up on Tuesday, April 20, 2010, he knew the procedures for jumping from a 33,000 ton oil rig. This would prove to be important knowledge later that night when an emergency announcement was issued over the rig's PA system.
Williams was the chief electronics technician for Transocean, a support company that specialized in deep water drilling equipment. The company's $560 million Deepwater rig was in the Gulf of Mexico working on the Macondo well. British Petroleum (BP) held the rights to explore the well and had leased the rig, along with its crew, from Transocean. Of the 126 people aboard the Deepwater, 79 were from Transocean, seven were from BP, and the rest were from other firms.
Williams was accustomed to emergency alarms. Gas levels had been running high enough to prohibit any such work as welding or wiring that could cause sparks. Normally, the alarm system would have gone off with gas levels as high as they were. However, the alarms had been disabled in order to prevent false alarms from waking people in the middle of the night. But the emergency announcement that came over the PA system on the night of April 20 was clearly no false alarm.
Moments after the announcement, Williams was jolted by a shake and the revving of one of the rig's engines. Before he knew it, there were two explosions forcing him and other crew members to abandon ship by jumping into the partially flaming ocean. Of the 126 workers, 17 were injured, including Williams, and 11 were killed. The rig burned for 36 hours, exploding the 700,000 gallons of oil that were on board. The Deepwater sank on April 22, taking with it the top pipe of the well and parts of the system that were supposed to prevent blowouts from occurring.
As of 2010, the Deepwater disaster was the largest marine oil spill ever to occur in U.S. waters. By the time the well was capped on July 15, 2010, nearly five million barrels of oil had spilled into the Gulf of Mexico.
It was surprising to analysts how such a disaster could happen, particularly involving a company like BP, which publicly prided itself on its commitment to safety. It did seem clear that, in an effort to close up the Macondo well, several key decisions were made, each involving multiple stakeholders and trade-offs of time, money, safety, and risk mitigation. The public debate began immediately on whether the result of these decisions indicated operational or management problems on the rig, and whether these problems were endemic to the oil industry, or resided within BP itself. To help answer these questions, several task forces were formed to investigate the root causes of the disaster and who among the various players involved with the Macondo well bore responsibility for the disaster and for its resolution.
In the late 1970s, the British government began selling off its ownership of BP in an attempt to increase productivity. When the government sold its final 31% share in 1987, BP's performance was in trouble. The company's performance continued to decline as a private company. In 1992, BP posted a loss of $811 million. Nearing bankruptcy, the company was forced to make dramatic cost cutting measures. Things started to improve in the mid-1990s. With a smaller workforce BP's new CEO put into effect an aggressive growth strategy.
In 2001, BP began recreating itself. The company wanted to be known as an environmentally friendly oil company. Over the next decade, the company launched the new Alternative Energy division, that was the world's largest manufacturer of solar cells and Britain's largest producer of wind energy. Between 2005 and 2009, BP invested $4 billion in alternative energy. BP's total company investment over the same time period was $982 billion.
In May 2007, Tony Hayward replaced John Browne as CEO. Hayward promised to "focus on safety issues, slow down growth and reduce production targets." Hayward improved corporate performance by shrinking the Alternative Energy division and reduce staff and four levels of management. BP's workforce fell from 97,000 to 80,300 people.
In addition to cutting management, Hayward also transformed BP's culture to one that was not afraid to take risk. He believed that too many people were making decisions leading to extreme cautiousness. He said, “being too safe is killing us".
In a short period of time, BP transitioned from a small, state-sponsored company to one of the largest non-state-owned oil companies in the world. In the month before the Deepwater disaster, BP was the largest company listed on the London Stock Exchange. The change required merging with and purchasing other companies. BP also took further strict cost cutting measures.
In the late 1980s, BP comprised of several layers of management that made it difficult for anyone to make decisions quickly. In some cases, a proposal for change required 15 signatures. At the same time, the company had too much debt and its performance was bad. Robert Horton, appointed CEO in 1989, cut $750 million from BP's annual expenses. He removed several layers of management – 80 people. Horton increased the speed of managerial decision making. Horton transformed hierarchically structured departments into smaller, more flexible teams charged with maintaining open lines of communication.
Horton transferred decision making power away from the corporate centre to the upstream and downstream business divisions. Employees at all levels were encouraged to take responsibility and exercise decision making initiative. In 1992, David Simon was appointed CEO replacing Robert Horton. Simon continued Horton's policy of cost cutting, especially in staffing.
The biggest changes occurred in BPX, which was led by John Browne. Browne created a feeling of entrepreneurship among his staff. He extended decision making responsibilities to employees at more levels in the organization. Under this strategy, decision making authority and responsibility for meeting performance targets was no longer held by BP's regional operating companies, but by onsite asset managers. Employee compensation was tied to asset performance and the overall performance of the site. After Browne took over this model was applied across the company.
One trade-off with this model was that because each site manager managed their own "asset" and was compensated for its performance, there was little incentive to share best practices on risk management among other BP exploration locations. There was little oversight over setting performance targets, particularly where risk management and safety were essential to the long-term success of an oil company. BP had a lot of safety violations.
Safety Issues at BP
In the mid-2000s, disaster struck BP twice within a 12-month period. On March 23, 2005, an explosion at BP's Texas City Refinery killed 15 people and injured another 180, and resulted in financial losses exceeding $1.5 billion. BP hired outside experts to write an report on the Texas City tragedy. One of the findings highlighted in the Report was that the company had cut back on maintenance and safety measures at the plant in order to reduce costs, and that responsibility for the explosion ultimately rested with company senior executives. Another concern outlined in the Report was that while BP had emphasized personal safety and achieved significant improvements, the company "has mistakenly interpreted improving personal injury rates as an indication of acceptable process safety, creating a false sense of confidence." The Report went on to state the following:
BP documents suggested that many employees did not believe that safety was a core value at BP. One of the reasons for this belief is that BP's executive and corporate refining management had not communicated a consistent and meaningful message about the importance of process safety and a firm conviction that process accidents were not acceptable. The BP stated policy on health and safety, "no accidents, no harm to people and no damage to the environment" was not widely known to the employees.
Until BP's many layers of management consistently articulated a clear message on process safety, it would be difficult to persuade the refining workforce that BP was truly committed on a long-term basis to process safety excellence.
In March 2006, a second disaster struck BP. In Alaska more than 200,000 gallons of oil poured into the bay from a hole in the pipeline, making it the largest oil spill in Alaska. Alaskan state regulators had been warning BP since 2001 that its management procedures were out of alignment with state regulations, and that critical equipment needed to be better maintained.
BP took several actions in response to the Report. BP executives clearly realized that when it came to safety, there was room for improvement.
John Browne met with the company's top 200 leaders to stress BP's commitment to safety and communicate his expectations regarding safety. Additionally, BP senior managers attended town hall meetings with employees to discuss safety issues. The chief executive conducted meetings and sent written communications to BP America employees regarding safety issues.
BP announced that it had committed $7 billion over the next four years to upgrade all aspects of safety at its U.S. refineries and to repair and replace pipelines in Alaska. The company had also announced $300 million and significant external input for process safety management renewal in refining.
The Macondo Prospect
The Macondo Prospect was located in the Gulf of Mexico. At 5,000 feet below sea level, the well demonstrated great potential for extracting oil, but was also hazardous. Natural gas levels were high in the reservoirs, which made drilling challenging.
Drilling in deep and ultra-deep water started to become economically profitable and technically feasible in the mid-2000s. Because of the complexities of deep water operations, creating a productive deep water oil field was extremely expensive compared to shallow water oil drilling. But the potential payoff was enticing. A well producing in shallow water might yield a few thousand barrels of oil a day. Deep water wells could yield more than 10,000 barrels per day.
BP acquired the rights to the Macondo Prospect. BP was the principal developer and operator, holding a 65% financial share in the project. BP leased a rig, equipment and staff from Transocean. While BP maintained operational decision making authority, Transocean employees, who performed the majority of the work on the rig, had some decision making authority over operations and maintenance. BP started drilling the Macondo well in October of 2009. Drilling, however, was interrupted by Hurricane Ida. BP commenced drilling on February 3, 2010 leasing Transocean's Deepwater rig.
Transocean charged BP approximately $500,000 per day to lease the rig, plus the same amount in contractor fees. BP originally estimated that drilling the Macondo well would take 51 days and cost approximately $96 million. By April 20, 2010 the rig was already on its 80th day on location and had exceeded its original budget.
The Deepwater Rig
The Deepwater rig came with a long list of maintenance issues. In September 2009, BP conducted safety tests on the rig, which was in use at another BP drilling site at the time. The test identified 390 repairs that needed immediate attention. It was later learned that the Deepwater rig was never taken in for repairs previous to the disaster and never stopped working at any point between the September 2009 tests and April 20, 2010.
As Transocean's Chief Technician Williams experienced, the crew learned how to develop
short-cuts in order to maintain the function of the rig. Williams was responsible for maintaining the three oversight computers that controlled the drilling technology. These computers, operating on an old Windows operating system, would frequently freeze. If computer A went down the driller would have to go to computer B in order to maintain control of the well. If somehow all three computers went down at once, the drill would be completely out of control. Williams frequently reported the software problems and the need to have them fixed.
Despite the hazards of the Macondo well site, the known maintenance issues on the rig, and the setbacks, BP felt confident that it had found oil. However, since Deepwater was an exploratory vessel, the crew was under orders to close the well temporarily and return later with another rig to extract the oil.
Anatomy of a Disaster
Closing the Macondo well was very complex due to competing interests of cost, time and safety, as well as the number of people and organizations involved in the decision making process. Adding to the complexities of decision making on the Deepwater was the fact that many of BP's decision makers for the Macondo well had only been in their positions for a short time before disaster struck.
As the Deepwater Disaster was analyzed, questions arose as to whether, in combination with the chaotic mix of decision makers, three key decisions on closing the Macondo well played a role in the downing of the oil rig – Well Casing, Centralizers, and Circulating Mud and the Cement Bond Log
The process of deep water drilling involves drilling through rock, installing and cementing casing to secure the well hole, then drilling deeper and repeating the process. On April 9, 2010, the crew of the Deepwater finished drilling the last section of the well, which extended 18,360 feet below sea level and 1,192 feet below the casing.
During the week of April 12, BP project managers had to decide how best to secure the well's final 1,192-foot section. One option involved hanging a steel tube called a liner on the bottom of the casing already in the well and then inserting another steel liner tube called a "tieback" on top of the liner hanger. The liner/tieback casing option provided four barriers of protection against gas and oil leaks getting into the well accidentally. These barriers included the cement at the bottom of the well, the hanger seal that attaches the liner to the existing casing in the well, the cement that secures the tieback on top of the liner, and the seal at the wellhead.
The other casing option, known as "long string casing," involved running a single string of steel casing from the seafloor all the way to the bottom of the well. Long string casing provided two barriers to the flow of gas up the annular space that surrounded the casing: the cement at the bottom of the well and the seal at the wellhead. Compared to the liner tie-back option, the long string
casing option took fewer days to install.
The decision about which casing design to use changed several times. A BP Plan Review recommended against using long string casing because of the inherent risks of having fewer gas barriers. But internal communications within BP indicated the company was actually leaning towards using the long string casing option. On March 25, 2010, a BP drilling engineer, emailed Allison Crane, a materials management coordinator for BP, and said choosing long string casing "saves a lot of time … at least 3 days…" On March 30, the BP drilling engineer emailed the BP completions engineer, another BP drilling engineer, and said "not running the tieback … saves a good deal of time/money." On April 15, BP estimated that using a liner instead of the long string casing "will add an additional $7 – $10 million to the completion cost."
A few days after BP completed the first version of its Forward Plan Review, the company released a revised version which referred to the long string casing option as "the primary option" and the liner as "the contingency option." The Forward Plan Review acknowledged the risks of long string casing, but considered it the "best economic case and well integrity case for future completion operations."
In closing up the well, BP was responsible for cementing in place the steel pipe that ran into the oil reservoir. The cement would fill the space between the outside of the pipe and surrounding rock, allowing a more uniform cement sheath to form around the pipe, while preventing any gas from flowing up the sides. Centralizers are special brackets that are used to help keep the pipe centreed.
To help inform decision making on the well pipe centralization, BP hired Halliburton, the cementing contractor, to run simulations and lab tests. Jesse Marc Gagliano was the Halliburton account representative for BP. He worked in BP's Houston office and was on the same floor as the BP Macondo well management team of John Guide, who was part of the operations unit, and Brett Cocales, Brian Morel, and Mark Hafle who were part of the engineering unit. Gagliano also worked with the Halliburton crew members on the rig to advise them on logistics.
One of Gagliano's main responsibilities was running an OptiCem model designed to help predict potential gas flow that might interfere with getting a good cement job on a well site. The OptiCem model, considered highly reliable, took data inputs from BP engineers and evaluated the likely effectiveness of various well designs. Gagliano said after the disaster, "It is a model. It is as good as the information you put into it. So the more accurate information you have, the more accurate the output will be." After running the model, Gagliano discovered that if BP used only six centralizers, as was planned, the risk for problems was quite significant. He found that at least 21 centralizers would be needed to significantly lower the risk.
Though nothing was written down, court testimony revealed that Gagliano expressed concern that the OptiCem results indicated a very high risk that the cement job would encounter
"channeling." BP questioned the reliability of the OptiCem results because some of the earlier outputs related to compression factors in the well were different than what the crew engineers measured onsite.49 According to Gagliano, the group spent much of the morning trying to figure out the best way to use the centralizers they did have.
After their meeting, a series of emails were exchanged, leading off with one from Morel explain how to utilize the six centralizers they had on hand. A few hours after Morel sent his email, Walz wrote a lengthy email to Guide, the Macondo well operations manager, expressing his concern about using just six centralizers. Guide responded to Walz's email early in the afternoon on Friday, April 16, expressing concern about the decision made by his supervisor, David Sims, to order additional centralizers.
When asked in court why he would ever question the OptiCem model's results, Guide responded, "There were several reasons, first of all, it's a model, it's a simulation, it's not…the real thing. From past experiences sometimes it's right and sometimes it's wrong. And I also know in this particular case…they made reference to having to tinker with it to try to get some of the results that were reasonable."
Meanwhile, Morel had gotten 3D profile information on the well hole, which indicated that it was actually very straight: 6/10ths of a degree off of vertical. In an email to Cocales, Morel questioned Gagliano's recommendation to use more centralizers. He believed doing so could slow down the process of sealing and cementing the well.
Based on the information about the straightness of the well hole, Cocales believed that despite the OptiCem model's results, additional centralizers would only add a small additional measure of safety. In his reply to Morel, Cocales indicated he was in agreement with Guide.
As it turned out, the additional centralizers that Sims gave the green light to order were a "slip-on" variety that took more time to install on a pipe, and were considered risky because of fears they might come off during installation and get stuck in the casing above the well-head. As a result, Guide and Walz decided not to use any additional centralizers. Gagliano later learned of their decision from another Halliburton employee who was on board the Deepwater. In his testimony in court Guide revealed that no one had considered postponing or putting a stop work order on the cement job until centralizers of the right kind were located.
On April 18, two days after Guide and Walz decided not to use the additional centralizers, Gagliano sent the formal report of the OptiCem results as an email attachment to the Macondo well management team. The report included the following observation: "Based on the well analysis of the above outlined well conditions, this well is considered to have a SEVERE gas flow problem. Wells in this category fall into Flow Category 3." However, the text of the email that Gagliano sent to the BP managers on April 18 did not say anything about the hazards of the Macondo well. Cocales and Guide later testified that neither had read that part of the report – .
Circulating Mud and the Cement Bond Log
The whole process of cementing an oil well is notoriously tricky. A 2007 study by the MMS found that cementing was the single most significant factor in 18 of 39 well blowouts in the Gulf of Mexico over a 14-year period.
Before cementing a well, it is common practice to circulate the drilling mud through the well, bringing the mud at the bottom all the way up to the drilling rig. This procedure, known as "bottoms up," allows workers to check the mud to see if it is absorbing gas leaking in. If so, the gas has to be separated out before the mud can be re-submerged into the well. According to the American Petroleum Institute, it is cementing best practice to circulate the mud at least once. In the case of the Macondo well, BP estimated that circulating all the mud at 18,360 feet would take anywhere from six to 12 hours. According to the drilling logs from Monday, April 19, mud circulation was completed in just 30 minutes.
In concert with the decision to do a partial circulation, BP managers chose not to run a test called a "cement bond log" to check the integrity of the cement job after it was pumped into the well, despite Gagliano's warnings of potential channeling. Workers from Schlumberger had been hired to perform a cement bond log if needed, but on the morning of Tuesday, April 20, about 12 hours before the blowout, BP told the Schlumberger workers their services would not be needed. According to Schlumberger's contract, BP would pay a cancellation fee equal to 7% of the cost of having the cement bond log and mechanical plug services completed.
BP and the engineers on site had used a decision tree, a system of diagnostic questions to define future actions, to determine whether they would need to perform a cement bond log. BP ultimately followed their own decision tree accurately, but when reviewed in court, it was pointed out that there could have been channeling in the well pipe during the cement job. Channeling was considered highly likely given that far fewer centralizers were used than what the OptiCem model had recommended. Such mud-cement channeling would not have been picked up in the diagnostic tests listed in BP's decision tree. The only way to accurately diagnose a bond failure due to channeling was with a cement bond log. However, when asked in court about the decision not to run a cement bond log despite seeing a loss return of 3,000 barrels of drilling mud, Mark Hafle, one of BP's drilling engineers, responded that the model he had from Halliburton indicated that the cement job should be fine. He also went on to explain that a cement bond log would be done at some point on this well, but that it was usually done pre-production:
So, that cement bond log is an evaluation tool that is not always 100% right. There's many factors that can affect its quality. It's not a quantitative tool. It does not tell you the exact percentage of cement at any given point. … It's a tool in the engineering tool box that has to be used with a bit of caution. But if it shows there's no cement two or three years from now when we come to do the completion we will do a remedial cement job on that casing.
Fallout from Disaster
The impact of the Deepwater explosion and the subsequent Macondo well oil leak was devastating on a number of fronts, the most obvious being the death of 11 crew members and the injuries sustained by another 17. The environmental damage from the oil spill was extensive, with 25 national wildlife refuges in its path. Oil was found on the shores of all five Gulf States, and was responsible for the death of many birds, fish, and reptiles. The total amount of impacted shoreline in Louisiana alone grew from 287 miles in July to 320 miles in late November 2010. Unlike conditions with the Alaskan Exxon-Valdez oil spill, the contaminated Gulf shoreline was not rock but wetland. Grasses and loose soil, a perfect sponge for holding oil, dominated wetland ecosystems.
In terms of direct economic damages, the sinking of the Deepwater rig represented a $560 million loss for Transocean and Lloyds of London, the insurance company which had unwritten the rig. The unprecedented loss of an entire semi-submersible rig was predicted to change underwriting policies for all oil rigs. As one underwriter noted, "It's never happened that a semi could burn into the sea and completely sink. Now underwriters have to include that as a risk. That's probably $10,000 to $15,000 more per day in rig insurance. They'll make it up by charging more on a per-rig basis."
BP's price tag for the lost oil – five million barrels – was $374 million. If a federal court ruled that the company was grossly negligent, BP could face up to $3.5 billion in fines. On April 15, five days before the disaster, BP's stock was trading on the NYSE at $60.57 and on June 25, it hit a 14-year low of $27.02. In addition to the frustration felt by shareholders and the public at large that the company had failed at several attempts to stop the leak, they were also unimpressed with BP's PR strategy, citing skepticism over the company's offer to pay fishermen if they signed a waiver promising not to sue the company.
Alongside those companies directly involved with the Macondo well project, the Deepwater disaster affected the oil industry as a whole. On May 28, 2010, Secretary of the Interior issued a moratorium on all deep water oil drilling in U.S. waters. The purpose of the moratorium was to allow time to assess the safety standards that should be required for drilling, and to create strategies for dealing with wild wells in deep water. Government analysts estimated that about 2,000 rig worker jobs were lost during the moratorium and that total spending by drilling operators fell by $1.8 billion. The reduction in spending led to a decline in employment-estimates indicated a temporary loss of 8,000 to 12,000 jobs in the Gulf Coast -and income for the companies and individuals that supplied the drilling industry. The moratorium also reduced U.S. oil production by about 31,000 barrels per day in the fourth quarter of 2010 and by roughly 82,000 barrels per day in 2011. This loss, however, was not large relative to total world production, and was not expected to have a discernable effect on the price of oil. The moratorium, originally intended to last until the end of November, was lifted in mid-October 2010.
The economic losses also extended to the thousands of coastal small business owners
including fishermen, shrimpers, oystermen, and those whose livelihood depended in whole or in part on fishing or tourism. The tourism industries in Alabama, Louisiana, and Florida were particularly hard hit. Ironically, analysts had previously predicted that tourism in the Gulf region, which was devastated by Hurricane Katrina in 2005, would return to pre-Katrina levels in 2010. Between the energy, fishing, shrimping, and tourism industries, the Gulf region lost an estimated 250,000 jobs in 2010.
BP pledged to compensate those individuals whose livelihoods would be affected. On June 16, 2010, in agreement with the U.S. government, the company established the Gulf Coast Claims Facility (GCCF), an escrow fund of $20 billion to pay for the various costs arising from the oil spill. GCCF staff evaluated the claims of companies and individuals who suffered demonstrable damages from the oil spill. The fund was also intended to pay municipalities, counties, and state organizations for lost tax revenue or additional clean-up costs.
By February 28, 2011, the GCFF had received over 500,000 claims, and 170,000 people and businesses had been paid …
We are a professional custom writing website. If you have searched a question and bumped into our website just know you are in the right place to get help in your coursework.
Yes. We have posted over our previous orders to display our experience. Since we have done this question before, we can also do it for you. To make sure we do it perfectly, please fill our Order Form. Filling the order form correctly will assist our team in referencing, specifications and future communication.
2. Fill in your paper’s requirements in the "PAPER INFORMATION" section and click “PRICE CALCULATION” at the bottom to calculate your order price.
3. Fill in your paper’s academic level, deadline and the required number of pages from the drop-down menus.
4. Click “FINAL STEP” to enter your registration details and get an account with us for record keeping and then, click on “PROCEED TO CHECKOUT” at the bottom of the page.
5. From there, the payment sections will show, follow the guided payment process and your order will be available for our writing team to work on it.