DOCSLIB.ORG

The Drilling Rig Components

Total Page：16

File Type：pdf, Size：1020Kb

Download full-text PDF Read full-text
The Drilling Rig Components The drilling rig components. A mud tank is an open-top container, typically made of steel, to store drilling fluid on a drilling rig. They are also called mud pits, because they used to be nothing more than pits dug out of the earth. The tanks are generally open-top and have walkways on top to allow a worker to traverse and inspect the level of fluid in the tanks. The walkways also allow access to other equipment mounted on top. Recently, offshore drilling rigs have closed-in tanks for safety. The mud tank plays a critical role in mechanically removing destructive solids and sediment from costly land and offshore drilling systems.[1] A drilling rig normally has two tanks. A tank is sectioned off into compartments. A compartment may include a settling tank, sometimes called a sand trap, to allow sand and other solids in the drilling fluid to precipitate before it flows into the next compartment. Other compartments may have agitators, which are large fan blades stirring the fluid to prevent its contents from precipitating. The pipe work linking the mud tanks/pits with the mud pumps is called the suction line. This may be gravity fed or charged by centrifugal pumps to provide additional volumetric efficiency to the mud pumps. Shale shakers are devices that remove drill cuttings from the drilling fluid that is used for boring holes into the earth. Controlling the solids in drilling fluid is an important component of the cost of drilling, so research into improved shaker design is ongoing. Contents [hide] 1 Shale shaker design 2 Shaker Screen Panels 3 Causes of screen failure 4 Screen Panel Designation [edit] Shale shaker design Shale shakers typically consist of large, flat sheets of wire mesh screens or sieves of various mesh sizes that shake or vibrate the drill cuttings, commonly shale, across and off of the screens as the drilling fluid (mud) flows through them and back into the drilling fluid system. This separates the solid drill cuttings from the fluid so that it can be recirculated back down the wellbore. In oilfield industry, linear motion shale shakers are widely used. [edit] Shaker Screen Panels Shaker Screen Panel Screen panels play a major role by removing particles larger than the mesh size. Screen selection is critical since shaking is the primary stage in the removal of solids. Improper screen selection can lead to de-blinding[clarification needed], loss of drilling fluids, premature pump part failures, overloading of other solids removal equipment within the mud systems, decreased service life, reduced flow rate capacity, and serious problems in the wellbore. [edit] Causes of screen failure The causes of premature screen failure are:[citation needed] Personnel improperly trained on handling, storage, maintenance and installation of deck rubbers and screens Careless storage of screen panels prior to use Screens damaged before use from improper handling during installation Shaker screen not match very well to shale shaker Deck rubbers improperly installed Deck rubbers dirty, worn or missing Dried cuttings or drilling fluid left on screen during shutdown of shaker Personnel walking on screens or using the shaker as a work table Tools being dropped on screens Extremely high mud weights or heavy solids loading Defective or improperly manufactured screens Use of high pressure wash guns to clean plugged screens A mud tank is an open-top container, typically made of steel, to store drilling fluid on a drilling rig. They are also called mud pits, because they used to be nothing more than pits dug out of the earth. The tanks are generally open-top and have walkways on top to allow a worker to traverse and inspect the level of fluid in the tanks. The walkways also allow access to other equipment mounted on top. Recently, offshore drilling rigs have closed-in tanks for safety. The mud tank plays a critical role in mechanically removing destructive solids and sediment from costly land and offshore drilling systems.[1] A drilling rig normally has two tanks. A tank is sectioned off into compartments. A compartment may include a settling tank, sometimes called a sand trap, to allow sand and other solids in the drilling fluid to precipitate before it flows into the next compartment. Other compartments may have agitators, which are large fan blades stirring the fluid to prevent its contents from precipitating. The pipe work linking the mud tanks/pits with the mud pumps is called the suction line. This may be gravity fed or charged by centrifugal pumps to provide additional volumetric efficiency to the mud pumps. [edit] Mud tanks for solids control Mud tanks are the base of solids control equipment. Mud tanks for solids control systems are divided into Square tanks and Cone-shaped tanks according to the shape of the tank bottom. The body of the tank is made by welding the steel plate and section, using the smooth cone-shape structure or the corrugated structure. The mud tank surface and passages are made of slip resistant steel plate and expanded steel plate.The mud tanks are made of the side steel pipe, all of the structure can be folded without barrier and pegged reliably. The surface of the tank is equipped with a water pipeline for cleaning the surface and equipment on the tank, it uses soaked zinc processing for the expanded steel plate. The ladder is made of channel steel to take responsibility the body, the foot board is made of expanded steel plate. The two-sided guard rail are installed the safe suspension hook. The mud tank is designed the standard shanty to prevent the sand and the rain. The pipeline is installed in the tank to preserve the warm air heat. Mud tank quantity depends on mud process capacity requirements. Especially for mud storage, suitable for mud pump, drilling rig, etc. A mud pump is a reciprocating piston/plunger device designed to circulate drilling fluid under high pressure (up to 7,500 psi (52,000 kPa) ) down the drill string and back up the annulus. Mud pumps come in a variety of sizes and configurations but for the typical petroleum drilling rig, the triplex (three piston/plunger) mud pump is the pump of choice. Duplex mud pumps (two piston/plungers) have generally been replaced by the triplex pump, but are still common in developing countries. Two later developments are the hex pump with six vertical pistons/plungers, and various quintuplex's with five horizontal piston/plungers. The advantages that these new pumps have over convention triplex pumps is a lower mud noise which assists with better MWD and LWD retrieval. The "normal" mud pump consist of two main sub-assemblies, the fluid end and the power end. The fluid end produces the pumping process with valves, pistons, and liners. Because these components are high-wear items, modern pumps are designed to allow quick replacement of these parts. To reduce severe vibration caused by the pumping process, these pumps incorporate both a suction and discharge pulsation dampener. These are connected to the inlet and outlet of the fluid end. The power end converts the rotation of the drive shaft to the reciprocating motion of the pistons. In most cases a crosshead crank gear is used for this. Parts of mud pump: 1.housing itself. 2.liner with packing. 3.cover plus packing. 4.piston and piston rod. 5.suction valve and discharge valve with their seats. 6.stuffing box (only in double-acting pumps). 7.gland (only in double-acting pumps). An electric motor is an electromechanical device that converts electrical energy into mechanical energy. Most electric motors operate through the interaction of magnetic fields and current- carrying conductors to generate force. The reverse process, producing electrical energy from mechanical energy, is done by generators such as an alternator or a dynamo; some electric motors can also be used as generators, for example, a traction motor on a vehicle may perform both tasks. Electric motors and generators are commonly referred to as electric machines. Electric motors are found in applications as diverse as industrial fans, blowers and pumps, machine tools, household appliances, power tools, and disk drives. They may be powered by direct current, e.g., a battery powered portable device or motor vehicle, or by alternating current from a central electrical distribution grid or inverter. The smallest motors may be found in electric wristwatches. Medium-size motors of highly standardized dimensions and characteristics provide convenient mechanical power for industrial uses. The very largest electric motors are used for propulsion of ships, pipeline compressors, and water pumps with ratings in the millions of watts. Electric motors may be classified by the source of electric power, by their internal construction, by their application, or by the type of motion they give. The physical principle behind production of mechanical force by the interactions of an electric current and a magnetic field, Faraday's law of induction, was discovered by Michael Faraday in 1831. Electric motors of increasing efficiency were constructed from 1821 through the end of the 19th century, but commercial exploitation of electric motors on a large scale required efficient electrical generators and electrical distribution networks. The first commercially successful motors were made around 1873. Some devices convert electricity into motion but do not generate usable mechanical power as a primary objective, and so are not generally referred to as electric motors. For example, magnetic solenoids and loudspeakers are usually described as actuators and transducers,[1] respectively, instead of motors. Some electric motors are used to produce torque or force.[2] This article provides insufficient context for those unfamiliar with the subject. Please help improve the article with a good introductory style.
Load more

Recommended publications
  • Bop) Control System
    RISK ASSESSMENT OF THE DEEPWATER HORIZON BLOWOUT PREVENTER (BOP) CONTROL SYSTEM April 2000 - Final Report Prepared for: CAMERON CONTROLS CORP. EQE INTERNATIONAL Confidential Treatment Requested by Transocean Holdings LLC TRN-HCEC-00056391 Deepwater Horizon BOP Control System Risk Assessment April 2000 • 4. EVALUATION RESULTS As discussed in the introduction, the evaluation of the fault trees by boolean reduction results in the identification of the minimal cutsets, or the minimum combinations of failures that will result in the occurrence of the undesired event. Each of these cutsets is composed of one or more failures and each of the failures is assigned a probability of failure as discussed in Section 3. The product of the failure probabilities for all failure events in a cutset represents the probability of occurrence of the cutset. The sum of the cutsets for each fault tree model represents the probability of occurrence of the associated undesired event. In addition to these quantitative results, potential problem areas are often identified durmg the development of the model. These are discussed in Section 5. Table 4·1 summarizes the probability of occurrence of each of the undesired events. The number of cutsets shown in the table are those with a probability of occurrence greater than 1E-1 O. The overall potential for any of the events occurring which lead to the failure to perform the EDS function is 3.1 2E-4 (1183 cutsets). which is less than the sum of the individual events in Table 4-1. This is due to the fact that some of the cutset combinations result in failure of more than one of the functions but are correctly only counted once when looking at the overall likelihood.
    [Show full text]
  • Final Report on the Investigation of the Macondo Well Blowout
    Final Report on the Investigation of the Macondo Well Blowout Deepwater Horizon Study Group March 1, 2011 The Deepwater Horizon Study Group (DHSG) was formed by members of the Center for Catastrophic Risk Management (CCRM) in May 2010 in response to the blowout of the Macondo well on April 20, 2010. A fundamental premise in the DHSG work is: we look back to understand the why‘s and how‘s of this disaster so we can better understand how best to go forward. The goal of the DHSG work is defining how to best move forward – assessing what major steps are needed to develop our national oil and gas resources in a reliable, responsible, and accountable manner. Deepwater Horizon Study Group Investigation of the Macondo Well Blowout Disaster This Page Intentionally Left Blank Deepwater Horizon Study Group Investigation of the Macondo Well Blowout Disaster In Memoriam Karl Kleppinger Jason Anderson Roughneck Senior tool pusher Adam Weise Dewey Revette Roughneck Driller Shane Roshto Stephen Curtis Roughneck Assistant driller Wyatt Kemp Donald Clark Derrick man Assistant driller Gordon Jones Dale Burkeen Mud engineer Crane operator Blair Manuel Mud engineer 1 Deepwater Horizon Study Group Investigation of the Macondo Well Blowout Disaster In Memoriam The Environment 2 Deepwater Horizon Study Group Investigation of the Macondo Well Blowout Disaster Table of Contents In Memoriam...............................................................................................................................................1 Table of Contents .......................................................................................................................................3
    [Show full text]
  • Introduction Blowout Preventer Stack Equipment
    WELL CONTROL EQUIPMENT & PROCEDURES WC-1 Introduction Preventing and, when prevention is not sufficient, respond- ing to potential uncontrolled releases of oil or gas ("blow- out") is critical to safe drilling operations. A kick is an influx of formation fluids into the wellbore. A blowout is an uncon- trolled kick exiting the well at surface. Well control is a process that begins with spudding the well and is not complete until the well is put on production and all drilling operations cease. This chapter will examine equipment commonly used in well control and processes used to control kicks of oil or gas. Blowout preventer stack equipment Annular blowout preventer The annular blowout preventer is installed at the top of the BOP stack (Figure WC-1) and has the capability of closing (sealing off) on anything in the bore or completely shutting off (CSO) the open hole by applying closing pressure. The sealing device of an annular blowout preventer is re- ferred to as the “packing element”. It is basically a do- nut-shaped element made out of elastomeric material. To reinforce the elastomeric material, different shapes of me- tallic material are molded into the element. This keeps the elastomeric material from extruding when operating system pressure or wellbore pressure is applied to the bottom of the packing element. Since the packing element is exposed to different drilling environments (i.e., drilling fluid/mud, cor- rosive H S gas and/or temperature of the drilling fluid), it is 2 Figure WC-1: Schematic (top) and photo of annular blowout important to make sure that the proper packing element is preventers.
    [Show full text]
  • Prepared by Supervised By
    Prepared By 4th Student of Special Geology Supervised By Prof. Dr. of Economic Geology Tanta University Faculty of Science Geology Department 2016 1 Abstract An oil spill is a release of a liquid petroleum hydrocarbon into the environment due to human activity, and is a form of pollution. The term often refers to marine oil spills, where oil is released into the ocean or coastal waters. Oil spills include releases of crude oil from tankers, offshore platforms, drilling rigs and wells, as well as spills of refined petroleum products (such as gasoline, diesel) and their by-products, and heavier fuels used by large ships such as bunker fuel, or the spill of any oily refuse or waste oil. Spills may take months or even years to clean up. During that era, the simple drilling techniques such as cable-tool drilling and the lack of blowout preventers meant that drillers could not control high-pressure reservoirs. When these high pressure zones were breached the hydrocarbon fluids would travel up the well at a high rate, forcing out the drill string and creating a gusher. A well which began as a gusher was said to have "blown in": for instance, the Lakeview Gusher blew in in 1910. These uncapped wells could produce large amounts of oil, often shooting 200 feet (60 m) or higher into the air. A blowout primarily composed of natural gas was known as a gas gusher. Releases of crude oil from offshore platforms and/or drilling rigs and wells can be observed: i) Surface blowouts and ii)Subsea blowouts.
    [Show full text]
  • Snubbing Operations
    IRP 15: Snubbing Operations An Industry Recommended Practice (IRP) for the Canadian Oil and Gas Industry Volume 15 - 2020 EDITION: 4 SANCTION DATE: February 2020 Operational Practices and Procedures IRP 15 Snubbing Operations Copyright/Right to Reproduce Copyright for this Industry Recommended Practice is held by Energy Safety Canada, 2020. All rights reserved. No part of this IRP may be reproduced, republished, redistributed, stored in a retrieval system, or transmitted unless the user references the copyright ownership of Energy Safety Canada. Disclaimer This IRP is a set of best practices and guidelines compiled by knowledgeable and experienced industry and government personnel. It is intended to provide the operator with general advice regarding the specific topic. It was developed under the auspices of the Drilling and Completions Committee (DACC). IRPs are provided for informational purposes. Users shall be fully responsible for consequences arising from their use of any IRP. The recommendations set out in this IRP are meant to allow flexibility and must be used in conjunction with competent technical judgment. It is recognized that any one practice or procedure may not be appropriate for all users and situations. It remains the responsibility of the user of this IRP to judge its suitability for a particular application and to employ sound business, scientific, engineering and safety judgment in using the information contained in this IRP. If there is any inconsistency or conflict between any of the recommended practices contained in this IRP and an applicable legislative or regulatory requirement, the legislative or regulatory requirement shall prevail. IRPs are by their nature intended to be applicable across industry, but each jurisdiction may have different or unique legal requirements.
    [Show full text]
  • Deepwater Horizon Blowout Preventer Failure Analysis Report to the U
    Deepwater Horizon Blowout Preventer Failure Analysis Report To the U. S. Chemical Safety and Hazard Investigation Board CSB-FINAL REPORT-BOP(06-02-2014) The Deepwater Horizon BOP stack at NASA-Michoud (with the upper LMRP portion on left) This analysis considered the BOP examinations that were conducted by Det Norske Veritas (DNV) at the NASA Michoud facility near New Orleans, Louisiana. The examinations were in two phases, the first conducted for the Joint Investigation Team and a Phase 2 funded by BP. CSB and Engineering Services were excluded from Phase 2, but subsequently obtained examination information from that period. Contents 1. Introduction...............................................................................................................................3 2. Summary of incident failures and new opinions.......................................................................4 3. Incident summary timeline.......................................................................................................8 4. Incident progression: initial fluid displacement for the negative pressure test.....................13 5. Incident progression: negative pressure test..........................................................................14 6. Incident progression: final displacement and initial oil flow starts.......................................18 7. Incident progression: oil flow increases..................................................................................20 8. Failure of the upper annular and sealing by a
    [Show full text]
  • Blowout Preventer Control System Reliability Primarily Focused on Subplate Mounted (SPM) Valves
    Engineering Technology Assessment Center (ETAC) REDACTED FOR PUBLIC USE August 2016 Blowout Preventer Control System Reliability Primarily Focused on Subplate Mounted (SPM) Valves Prepared by Roy Lindley Edited by David McCalvin BSEE Engineering Technology Assessment Center (ETAC) About the Author Roy Lindley is a mechanical engineer and a national security program manager at Argonne National Laboratory. Lindley has over 32 years of experience in conducting and managing engineering programs including multi-discipline evaluations for major U.S. DOE projects on electric utility applications, and various energy conversion technologies. He has a varied technical scope that includes pressure vessels, structural and seismic support design, data acquisition, and code compliance analysis. Lindley is also a security expert that does laboratory testing of security systems and design recommendations. Disclaimer This report was prepared by Argonne National Laboratory (ANL) under contract to the Department of Energy (DOE) through an inter-agency agreement between the Department of the Interior, Bureau of Safety and Environmental Enforcement (BSEE) and the DOE. The opinions, findings, conclusions, and recommendations expressed in the report are those of the authors and they do not necessarily reflect the views or policies of BSEE. This report was prepared as an account of work sponsored by an agency of the United States Government. Neither the United States Government nor any agency thereof, nor UChicago Argonne, LLC, nor any of their employees or officers, makes any warranty, express or implied, or assumes any legal liability or responsibility for the accuracy, completeness, or usefulness of any information, apparatus, product, or process disclosed, or represents that its use would not infringe privately owned rights.
    [Show full text]
  • Towards Automated Condition Monitoring of Blowout Preventer Wellbore Packers
    Towards Automated Condition Monitoring of Blowout Preventer Wellbore Packers Se Un Park1, Rajesh Kumar Bade2, Daniel Barker3, and Daniel Edgardo Viassolo4 1,4Schlumberger, 1430 Enclave Pkwy., Houston, TX, 77077, USA [email protected], [email protected] 2,3Schlumberger, 4601 Westway Park Blvd., Houston, TX 77041, USA [email protected], [email protected] ABSTRACT of mud serves as primary means of controlling wellbore pressure during drilling, a BOP forms the final layer of According to Bureau of Safety and Environmental protection that prevents a loss of well-control (LOWC) event Enforcement (BSEE), in 2017 a total of 45 out of 59 rigs from becoming a hazardous blowout. A study by Per Holland operating in the Gulf of Mexico reported component failures and the Bureau of Safety and Environmental Enforcement of well control related equipment. The aftermath of the oil (2016) reports that approximately 60% of LOWC events spill from the Deepwater Horizon rig provides stark occur during drilling operations. illustration that acceptance of the equipment failure status quo is untenable. In this work, the authors propose novel A BOP is placed on top of wellhead with drilling equipment automated strategies to monitor the health of blowout going through it into a well. Depending on operating context preventers (BOPs) on offshore drilling rigs. Using physics- of LOWC event, a BOP must either isolate wellbore pressure based models, we demonstrate computational detection of by sealing around a tubular or drill pipe (Figure 1) or shear a pressure tests by identifying characteristic features in time- tubular before isolating wellbore pressure. The task of series pressure data.
    [Show full text]
  • Appendix K BOP Leaks
    Appendix K BOP Leaks Appendix K BOP Leaks Appendix K BOP Leaks There were five minor leaks in the Deepwater Horizon BOP control system: three were identified after the BOP stack was latched to the wellhead in February 2010, and two were identified during the post-incident intervention by the remotely operated vehicle (ROV). None of these leaks caused or contributed to the April 20 incident, and they did not adversely impact the functionality or redundancy of the BOP control system to perform as designed in a well control event. The five leaks were as follows: Identified Pre-Incident • Leak on the open-side function of the test ram BOP • Leak on accumulator surge bottle on the upper annular BOP • Leak on the lower annular BOP close function Identified Post-Incident • Leak on a hose fitting to the lock function on the ST Lock circuit • Leak on blind shear ram ST Lock sequence valve to ST Lock chamber The leaks were small in volume and, in some cases, regardless of volume, they would not have adversely impacted the closure of the well-control components.A Functioning of the well-control components relied on the hydraulic supply from the rig via a hydraulic conduit line, and from surface and subsea accumulator storage bottles. Low-volume leaks did not impede functionality because any fluid lost was recharged by the rigid conduit line being supplied by the Cameron Surface Control System, which included 45 40-gallon accumulators that were continuously replenished to a stored pressure of 5,000 psi.1 In the event the hydraulic conduit line was severed or destroyed, eight 80-gallon accumulator bottles on the BOP stack would have fed hydraulic fluid to function the BOP.2 Importantly, the ST Lock circuit leak on the blind shear ram sequence valve to ST Lock lock chamber confirms that the blind shear ram functioned.
    [Show full text]
  • Macondo Investigation Report Volume 3 4/17/2016
    U.S. CHEMICAL SAFETY AND HAZARD INVESTIGATION BOARD INVESTIGATION REPORT VOLUME 3 DRILLING RIG EXPLOSION AND FIRE AT THE MACONDO WELL (11 Fatalities, 17 Injured, and Serious Environmental Damage) DEEPWATER HORIZON RIG MISSISSIPPI CANYON 252, GULF OF MEXICO KEY ISSUES: APRIL 20, 2010 • HUMAN FACTORS • ORGANIZATIONAL LEARNING • SAFETY PERFORMANCE INDICATORS • RISK MANAGEMENT PRACTICES • CORPORATE GOVERNANCE • SAFETY CULTURE REPORT NO. 2010-10-I-OS 4/17/2016 Macondo Investigation Report Volume 3 4/17/2016 [This page left intentionally blank.] 2 Macondo Investigation Report Volume 3 4/17/2016 Contents VOLUME 3 – INTRODUCTION .............................................................................................................. 15 Moving Beyond the Blowout Preventer ...................................................................................................... 19 Volume Overview ....................................................................................................................................... 20 1.0 HUMAN FACTORS ..................................................................................................................... 21 1.1 Macondo Temporary Abandonment Personnel ............................................................................. 25 1.2 Macondo Temporary Abandonment Activities: Four Phases ........................................................ 26 1.2.1 Phase 1: Presetting of the Diverter System Route ............................................................ 27 1.2.2 Phase 2: Displacement
    [Show full text]
  • Deepwater Horizon – Failure of Blowout Preventer (BOP)
    Deepwater Horizon – Failure of Blowout Preventer (BOP) Jim Thomson September 2016 Jim Thomson September 2016 1 20 April 2010, Gulf of Mexico • 11 dead • $350m (2001 cost) platform destroyed • Largest ever oil spill • BP CEO sacked • New regulator (BSEE) created Total BP liability (2016) $61 bn, plus other lesser liabilities: • Anadarko (junior non-operating partner) • MOEX (junior non-operating partner) • Transocean (operator/owner) • Cameron (BOP designer) • Halliburton (drilling contractor) 129 people on board: Final total cost ~$80 bn ?? 6 BP personnel 30 Halliburton Others mostly Transocean Most expensive ever accident (except Chernobyl and Fukushima) Jim Thomson September 2016 2 1. Why didn’t the Blowout Preventer work? 2. Were there any common causes between Deepwater Horizon and the 2005 Texas City Refinery accident? A cautionary tale of bad standards, weak regulation, and minimal compliance Jim Thomson September 2016 3 Deepwater Horizon Sea level 18360 feet (5564 m) 40 feet Blowout 4992 feet from sea level (13 m) Preventer to reservoir (1513 m) to seabed Seabed The BOP was designed and manufactured to API standards by Production Cameron International (Texas), and owned and operated by Casing Transocean (Switzerland) under contract to BP. Cameron: 20000 employees NOT TO SCALE! $8.5 bn turnover (2012) Cameron International was bought by Schlumberger in 2016 SIMPLIFIED! for $14.8 bn. Transocean: 18000 employees $10 bn turnover (2012) Hydrocarbon Jim Thomson September 2016 Reservoirs 4 The role of the BOP was to shear the drill pipe
    [Show full text]
  • Deepwater Horizon Oil Spill Final Programmatic Damage Assessment
    2. Incident Overview Final Programmatic Damage Assessment and Restoration Plan and page 2–1 Final Programmatic Environmental Impact Statement What Is in This Chapter? • Executive Summary • Introduction (Section 2.1): In brief, what happened after the Deepwater Horizon explosion and how did agencies respond? • Explosion, Well Blowout, and Containment (Section 2.2): What happened in the immediate aftermath of the explosion on the Deepwater Horizon mobile drilling unit? • Consequences of the Blowout (Section 2.3): How much oil and what other spill materials were released into the Gulf of Mexico? What response actions were taken to reduce harm to people and the environment from the Deepwater Horizon incident? 2 Executive Summary Executive • References (Section 2.4) Executive Summary On April 20, 2010, the Deepwater Horizon mobile drilling unit exploded, caught fire, and eventually sank, resulting in a massive release of oil and other substances from BP’s Macondo well. Initial efforts to cap the well following the explosion were unsuccessful, and for 87 days after the explosion, the well blasted oil and natural gas continuously and uncontrollably into the northern Gulf of Mexico. According to the U.S. District Court’s findings of fact, approximately 3.19 million barrels (134 million gallons) of oil were released into the ocean (U.S. v. BP et al. 2015), by far the largest offshore marine oil spill in U.S. history. The total volume of oil released is about 12 times more than the 1989 Exxon Valdez spill; given the continuous release for nearly 3 months, the Deepwater Horizon spill was equivalent to the Exxon Valdez spill re-occurring in the same location every week for 12 weeks.
    [Show full text]