Requirements

Pipelines should be decommissioned and abandoned (by removal or abandonment-in-place) in accordance with applicable national, regional and local regulations and requirements, concession terms and contractual agreements, and permit requirements. In the case of conflict the more stringent requirement should apply, unless an exception procedure is implemented to approve and document the deviation. Pipelines should be abandoned using generally accepted engineering and construction practices, proven industry processes, methods and procedures, as well as with due consideration for health, the environment and safety, sustainability and reuse, and Company reputation, both during abandonment activities and considering future land or sea use.

1. All onshore pipelines on the surface, and in depths shallower than 200 feet (below mean sea level) should be removed, unless buried to an acceptable depth below the surface or seabed suitable for abandonment-in-place. If abandoned in place, pipeline stability should be assured over the long term.
2. If a pipeline (or group of similar pipelines) is a candidate to be abandoned-in-place, a risk assessment should be performed in the early phase of abandonment planning to determine whether the pipeline should be removed or abandoned-in-place. The risk assessment should be consistent with the HSE risk management process and evaluate HSE, business, social, and reputational risk. The risk assessment should evaluate relevant criteria (such as potential public exposure, future land or sea uses, e.g. fishing or shipping, regulatory requirements, rights-of-way, landowner agreements, and technical feasibility) and the results documented and considered in making the removal versus abandonment-in-place decision. If abandonment-in-place is selected, appropriate mitigations should be implemented based on the risk assessment results.
3. A pipeline should not be removed or abandoned in place without first being cleaned to an acceptable standard, which is normally achieved by pigging and then flushing or purging the pipeline of hazardous liquids and gases, including hydrocarbons or other materials. Materials flushed or purged from liquid pipelines must be captured and sent for proper reuse or disposal. Gaseous materials may be permitted to be vented to atmosphere or to a control device if not purged to an active pipeline segment or otherwise captured for reuse. Regulatory approvals and permits may be required for the venting of gaseous materials or routing to a control device. The HSE department should be consulted for guidance on acceptable criteria and requirements for disposal or discharge of liquids and gases.
4. An unidentified pipeline should not be cut, sheared, drilled or welded upon. If unsure, check all related documentation (e.g. drawings, surveys, maps, regulatory records), interview operations staff (current and previous) and discuss with other operators that have pipelines in the vicinity to positively identify the pipeline in question. If questions persist, perform additional surveys and trace the line to its source (e.g. with sonar or divers) to positively identify the pipeline.
5. Hazardous wastes should be properly disposed of at an approved hazardous waste facility. Decommissioned materials containing hazardous wastes should either be sent to a decontamination facility (where the hazardous wastes should be removed and properly disposed of at an approved hazardous waste facility) or disposed of at an approved hazardous waste facility.
6. Environmental site assessment, remediation, and restoration should be coordinated with the pipeline abandonment work. Environmental Subject Matter Experts should be engaged during project planning and execution phases to determine if environmental assessment, remediation, and/or restoration activities are required. Onshore, coastal and offshore areas (land or seabed surfaces) should be left in a state suitable for subsequent use, without being a hazard to users of the areas.
7. Pipeline abandonment projects should define minimum technical capability and experience expectations within contract plans and bid/tender packages as needed to assure workforce competency for work execution.
8. Items to consider in early-phase project framing and alternative development include pipeline abandonment-in-place versus removal, timing of work activities, regulatory requirements, HSE issues and risks, financial issues and risks, disposal requirements, and stakeholder requirements or expectations. Each region where Company operates may have unique requirements, and the abandonment plan must be suited to the overall goals of both Company and external stakeholders.
9. Site visits and inspections should be undertaken during the planning and engineering phases to build an understanding of the site and establish detailed site-specific information, to identify issues that may need to be addressed in site-specific abandonment procedures or incorporated into analytical models, and to develop detailed abandonment execution plans and removal procedures.
10. The site visit and inspection should include assessment of the condition of the pipeline, associated facilities and infrastructure, and site conditions. The visit should include inspection, testing and documentation of the presence of hazardous materials. Typical materials that might be encountered at pipelines and associated facilities (which may or may not be hazardous) include the following:

• Naturally occurring radioactive material (NORM)
• Asbestos
• H2S
• Mercury
• Paint and lead-based paint
• Batteries
• Hydrocarbons
• Polychlorinated biphenyls (PCBs)
• Chemicals of unknown composition
• Containers of unknown material

11. A basis of estimate document should be developed for each pipeline abandonment project to guide the development of cost estimates. Where possible, individual pipeline abandonment projects may be grouped to form a campaign and thereby provide more leverage in dealing with contractors for securing equipment and reducing costs, and in gaining efficiencies through process repetition.
12. The following items should be considered and incorporated as appropriate during early phase project development and planning.

• Regulatory requirements governing pipeline abandonment vary by country, and even within various regulatory jurisdictions within a country. Therefore national, regional and local regulations, concession terms and contractual agreements, and permit requirements should be reviewed, as well as government decrees in place at the time of project development and planning, including those that define hazardous wastes and hazardous waste management requirements. Permits are generally required where a regulatory framework exists, and some permitting processes may require a public comment period.
• A Transportation and Waste Management Plan should be developed that covers the handling, storage, transport and disposal of all wastes, including the recycling of scrap materials and the disposal of wastes, both hazardous and nonhazardous materials.
• Pipeline abandonment risks should be assessed using the HSE Risk Management process to evaluate HSE, business, social, and reputational risk. Risk registers that include HSE, project execution and Company reputational risk factors should be developed and appropriate risk mitigation plans developed and managed. Assets with similar HSE, reputational, and project execution risks may be grouped together to facilitate assessment.

Onshore Pipeline Abandonment

All onshore pipelines should be removed unless buried to a minimum of 3 feet below the surface, in which case abandonment-in-place may be an alternative. Where national, regional or local regulations and requirements, concession terms and contractual agreements, or permit requirements allow abandonment-in-place at depths shallower than 3 feet, a risk assessment should be performed to confirm that abandonment-in-place is sufficiently protective of the Company’s interests from all perspectives, including HSE, business, social, and reputation. If the risk assessment confirms that abandonment-in-place is sufficiently protective of the Company’s interests then an exception procedure is not required. For onshore facilities, minor equipment, piping and appurtenances (and subsurface infrastructure) associated solely with pipeline operation and safety may be decommissioned and removed with the pipeline.

1. Plan the pipeline abandonment, including isolation, draining, pigging, flushing, contents disposal, removal versus abandonment-in-place, and reclamation and restoration of impacted areas. Perform site visits, surveys, content-sampling, survey-map reviews, etc., as needed, as well as identifying in-line valves, repair locations, pipeline crossings, dead legs or other features that may require mitigation procedures.
2. Pipeline right-of-way agreements should be reviewed for special requirements, and to verify that the agreement will not be violated or that Company rights will not be unintentionally relinquished.
3. Sample the pipeline to determine the contents, then check contents for hazardous chemicals, materials or wastes (e.g., NORM, mercury or benzene) and check external coatings such as paint and insulation for potentially hazardous wastes (e.g., lead, asbestos, PCBs) that might require special handling procedures, disposal permits, or both.
4. De-energize and isolate the pipeline from energy sources. Where a pipeline to be abandoned is connected to other pipelines (or segments) that are to remain active (live), inactive or idle, the abandoned pipeline should be isolated by physical removal, e.g., “air-gapped.” All abandoned connections to active, inactive or idle pipelines should be permanently closed with flanges and blinds (or weld caps) per the pipeline material classification or specification. All welds and flanged joints installed to achieve isolation should be inspected and tested per the pipeline material classification or specification. Lock out and tag out all sources of energy (e.g., pumps, rectifiers, cathodic protection systems, and valves) that are not physically disconnected.
5. Drain pipeline and dispose of the contents per the Company’s waste management plan. For pipelines with unknown or uncertain integrity, perform a negative pressure test (normally 10–15 psi for 12 hours) to verify pipeline integrity for subsequent pigging and flushing operations.
6. Pipelines with suitable integrity (or with a successful negative pressure test) should be pigged and flushed to remove as much of the remaining contents as possible. For pipelines with uncertain integrity, consider using negative pressure to pull a pig thru the pipeline to remove fluids, which mitigates the risk of releasing contents to the environment. Recover all fluids and dispose of as per the waste management plan.
7. Flush or purge the pipeline to the cleanliness level specified by national, regional and local regulations and requirements, concession terms and contractual agreements, or permit requirements. If unspecified by regulations or contractual agreement, project team should set the minimum cleanliness level, which for example may be specified in parts per million or “flushing until clear returns”, e.g., until there is no sheen on receiving waters in a static sheen test. The minimum cleanliness requirement should be flushing until clear returns if no other requirements have been established. The minimum pipeline flushing volume to achieve clear returns should be 150% of the pipeline volume, but flushing efficiency is also dependent upon achieving adequate flow velocity, so higher volumes/flowrates may be required.
8. Drain the pipeline to remove, recover and dispose of flushing fluids per the waste management plan. Re-pigging the pipeline with an inert gas (typically nitrogen) is one method to remove flushing fluids.
9. Prior to severing or cutting a pipeline, verify the pipeline is depressurized and free of hazardous liquids and gases, including hydrocarbons.
10. Pipelines (or segments) that are abandoned in place should meet the following requirements:

• Each end of the pipeline should remain buried to a minimum depth of 3 feet or greater. Measures should be taken to ensure the pipeline ends remain stable and do not experience excessive settlement or buoyant movements during seasonal changes in soil conditions.
• Each end of the pipeline should be sealed with a welded cap, a steel plate, a skillet plate, a blind flange, a locking plug, or a grout plug.
• Each end of the pipeline should be permanently identified and then covered with appropriate materials.
• Grouting of pipelines should be required where loss of integrity (e.g. collapse of the pipe, holes, buoyancy) could potentially result in an unacceptable risk or liability to the Company (e.g. pipe greater than 10 inches in diameter under roads or railroads, under canals, dikes, sea defense or dune crossings where the water level is higher than the surrounding land surface, or where local regulations require continuous plugging). Grouting should form a continuous plug throughout the pipeline (or section of pipeline) to mitigate the risk to an acceptable level.
• Pipelines should be marked with above-ground pipeline warning markers if required by applicable national, regional or local regulations and requirements, concession terms and contractual agreements, or rights-of-way or permit requirements.

11. Pipelines (or segments) that are removed should meet the following requirements:

• Pipelines on the surface should be removed by severing in place and removal.
• Pipelines buried shallower than 3 feet in depth should require excavation, severing and removal. Excavation should follow established safety procedures and may require special permits.
• Cold-cutting methods are preferred (e.g., shearing, reciprocating or circular metal saws) over hot work methods from a safety perspective. All work should follow applicable safety procedures.

12. Remove all associated pipeline surface and subsurface infrastructure (including at coastal sites) unless they have future economic utility.
13. Remove all pipeline minor equipment, piping and appurtenances associated solely with pipeline operation and safety, unless they have future economic utility.
14. Associated pipeline infrastructure such as buildings, roads, power lines, gravel pads, and concrete pads should be removed unless regulations, government requirements, concession or landowner/lease agreements stipulate that they remain in place.
15. Document final site condition and retain all records (including, for example, “as abandoned” drawings, before-and-after photos or videos, regulatory submittals, permits and approvals, contractual records, route maps and end points of abandoned-in-place pipelines, sampling reports, and inventory data).

Offshore Pipeline Abandonment

All offshore pipelines in water depths shallower than 200 feet below mean sea level should be removed, unless buried to a minimum of 3 feet below the seabed surface, e.g. below the natural seafloor, in which case abandonment-in-place may be an alternative.

Reburial to the 3 feet minimum below the seabed surface may also be an acceptable alternative to removal. Buried pipelines in water depths from 200 feet to 300 feet are candidates for abandonment-in-place regardless of burial depth, provided that they do not present a hazard (obstruction) to navigation, commercial fishing (trawling) activities or future use. Where national, regional or local regulations and requirements, concession terms and contractual agreements, or permit requirements allow abandonment-in-place at depths shallower than 3 feet a risk assessment should be performed to confirm that abandonment-in-place is sufficiently protective of the Company’s interests from all perspectives, including HSE, business, social, and reputation. If the risk assessment confirms that abandonment-in-place is sufficiently protective of the Company’s then an exception procedure is not required.

1. Plan the pipeline abandonment, including isolation, contents disposal, removal versus abandonment-in-place, and impacted areas. Perform site visits, surveys, contents sampling, survey map reviews, etc., as needed, as well as identifying in-line valves, repair locations, anchors, anchor mats, pipeline crossings, power or communications cable crossings, dead legs or other features that may require mitigation procedures. During the site visit, meet with field engineers and operators to discuss the history and condition of the pipeline (e.g., last time pigged, paraffin plugs, corrosion issues, repair details, and number of repairs) and identify potential concerns such as areas of high scour, sea bottom mudslides, and environmentally sensitive areas.
2. Pipeline agreements (e.g. right-of-way, crossing, access to third party facilities, fluid handling) should be reviewed for special requirements, and to verify that the agreement will not be violated or that Company rights will not be unintentionally relinquished. Particular attention should be given to retaining rights-of-way at shore crossings where future use is of concern.
3. Where seabed or environmental conditions (e.g., mud flows, erosion, currents, storms, mudslides, sediment movement, seismic events) may have caused a pipeline to move or shift, consider surveying affected pipelines with sonar equipment or by diver with a GPS pinger. The intent is to verify the line location, identify damage and locate impediments to abandonment (e.g., pipeline crossings, electrical power or communications cable crossings, valves, repair clamps, auger anchors, and concrete mats), and to determine the type and location of debris (shipwrecks, containers, etc.) on or near the pipeline. This information will be critical for planning pipeline abandonment.
4. Sample the pipeline to determine the contents, then check contents for hazardous chemicals, materials or wastes (e.g., NORM, mercury or benzene) and check external coatings such as paint and insulation for potentially hazardous wastes (e.g., lead, asbestos, PCBs) that might require special handling procedures, disposal permits, or both.
5. De-energize and isolate the pipeline from energy sources. Where a pipeline to be abandoned is connected to other pipelines (or segments) that are to remain active (live), inactive or idle, the abandoned pipeline should be isolated by physical removal, e.g. “water gapped” or “air gapped”. All abandoned connections to active, inactive or idle pipelines should be permanently closed with flanges and blinds (or weld caps) per the pipeline material classification or specification. All welds and flanged joints installed to achieve isolation should be inspected and tested per the pipeline material classification or specification. Lock out and tag-out all sources of energy (such as pumps, rectifiers, cathodic protection systems, and valves) that are not physically disconnected.
6. If possible, pig the pipeline to be abandoned. Recover all fluids and dispose of them in accordance with the waste management plan, taking into account waste characteristics.
7. Flush or purge the pipeline to the cleanliness level specified by national, regional and local regulations and requirements, concession terms and contractual agreements, and permit requirements. If unspecified by regulations or contractual agreement, the project team and management should set the minimum cleanliness level, which for example may be specified in parts per million or “flushing until clear returns”, e.g., until there is no sheen on receiving waters in a static sheen test. The minimum cleanliness requirement should be flushing until clear returns if no other requirements have been established. The minimum pipeline flushing volume to achieve clear returns should be 150% of the pipeline volume, but flushing efficiency is also dependent upon achieving adequate flow velocity, so higher volumes/flowrates may be required.
8. Pipelines should not be cut, severed, sheared, drilled or welded upon unless it can be positively identified along its entire length (with no risk of misidentification) and there is a reasonable assurance that it has been flushed, depressurized to an equilibrium state, and is free of hazardous liquids and gases, including hydrocarbons. Suitable safeguards should be employed to mitigate risk (i.e., drilling a pilot hole and checking contents, setting a pollution dome, etc.) and to protect against releasing hazardous materials to the environment.
9. Where there is any doubt or question relative to the identity, depressurization or cleanliness of a pipeline, and the decision has been made to proceed with cutting, severing, shearing, drilling or welding, suitable precautions should be taken to mitigate the higher risk. One proven industry practice is to use “hot tap” methods to verify that the pipeline is depressurized, and to confirm that the pipeline has been flushed and cleaned, and the contents are suitable for release to the environment. The “hot tap” provides a means of controlling flow and sampling/testing the contents, and if the contents are not clean it provides a means of localized flushing to further clean the line. The “hot tap” provides pressure and flow control mitigation against cutting into the wrong pipeline, which could be pressurized with hazardous contents.
10. Whether severed in place for removal or abandonment-in-place, precautions should be instituted to protect divers, surface personnel, equipment and marine vessels, and the environment during subsea work. Containment domes (hoods) are one mitigation method against inadvertent fluid releases during subsea severing of pipelines.
11. On conventional fixed structures the pipeline and tube turn are often severed and removed together, and the riser left in place for removal with the jacket as part of facility decommissioning. In this case the pipeline riser should be severed inside the jacket footprint, and sufficiently supported by the jacket to allow safe lifting with the jacket. A plug should not be placed in the bottom of a riser as it can present a projectile hazard during jacket lifting and removal.
12. Abandoned pipeline segments, and related appurtenances such as risers, equipment, and piping that are cleaned and abandoned, but not removed should be identified as such with nameplate tags. The tags should include the pipeline number (or segment number), with date abandoned, and facility “to/from” information. Nameplate tags are typically fabricated from brass (other materials may be acceptable) and should be attached with nylon tie-wraps if subsea, and with stainless steel wire if on surface facilities.
13. Pipelines (or segments) that are abandoned in place in water depths of 300 feet or less should meet the following requirements unless noted otherwise:

• Each end of the pipeline should be buried to a depth of 3 feet or greater. In areas with evidence of seabed scour, additional precautions should be taken to mitigate erosion resulting from abandonment activities.
• Each end of the pipeline should be sealed with a blind flange or a locking plug regardless of water depth, i.e., even in water depths greater than 300 feet. Examples of suitable locking plugs include a “dogging type internal plug” on pipelines 6 inches and larger and a “dogging external sealing cap” on pipelines 4 inches and smaller. A rubber plumber’s plug is not an acceptable long-term locking plug.
• Each end of the pipeline should be stabilized at the burial movement. Stabilization should be accomplished with an engineered solution based on seabed conditions and likely loads, or by utilizing proven industry practices. In shallow water, hurricane (typhoon) prone areas (such as the United States – Gulf of Mexico) a proven practice utilizes an auger-type anchor and steel cable to temporarily secure the pipeline end, followed by permanent stabilization with cement bag coverage.
• Where an auger-type anchor is used to temporarily stabilize the end of a pipeline, it should be fully embedded and externally attached or looped to the pipeline end with a 1/2-inch cable. Cement bags (not simple sand bags) should be placed over the end of each pipeline to extend 6 feet in front of, 3 feet behind and 3 feet to each side past the end of pipe as a minimum. If allowed by regulations, requirements and agreements, concrete mats may be used in lieu of cement bags to cover the ends of the pipeline.
• The resulting surface should be even with natural seabed surface and should not present an obstruction to navigation or commercial fishing (trawling) activities, e.g., the top of cement bags, concrete mats, etc. should not protrude above the natural seabed surface.

14. Pipelines (or segments) that are removed should meet the following requirements:

• Pipelines on the seabed surface may be severed in place, and then lifted or pulled to the surface, and transported to shore facilities for clean-up and disposal or salvage (material recycling).
• Pipelines buried below the seabed surface should require excavation, severing and removal. Some seabed soil conditions may allow pulling of the pipeline out of the seabed to the surface without excavation, but caution must be used as obstructions (such as other pipelines or cables) may be hidden and could pose significant risks.
• Pipelines are typically severed on both sides of crossings (other pipelines or cables) to eliminate the risk of damage at crossings during pipeline lifting or pulling to the surface, and then the pipeline segment under the crossing carefully removed.
• If reverse-lay operations are employed, the subsea end of the pipeline segment should be sealed with a locking plug or cap to contain the contents during pulling to the surface. Plugs or caps should be mechanically attached and able to withstand the forces encountered without releasing. Examples of suitable locking devices include a “dogging type plug” on pipelines 6 inches and larger and a “dogging cap” on pipelines 4 inches and smaller. A rubber plumber’s plug is not an acceptable locking plug.

15. Associated pipeline subsea infrastructure and appurtenances (such as pipeline manifolds, jumpers, pipeline end manifolds [PLEMs] and terminations [PLETs], anchors, pilings, concrete mats, riprap, cement bags, etc.) should be removed as required by national, regional and local regulations and requirements, concession terms and contractual agreements, and permit requirements, and as follows:

• Subsea infrastructure and associated appurtenances in water depths of 200 feet and less should be removed, unless flush with or buried below the seabed surface.
• Subsea infrastructure and associated appurtenances in water depths from 200 feet to 300 feet should be removed, unless flush with or buried below the seabed surface, unless they can be demonstrated through a risk assessment to not present a hazard (obstruction) to navigation, commercial fishing (trawling) activities or future use.
• Subsea infrastructure and associated appurtenances in water depths greater than 300 feet do not have to be removed solely due to surface hazard (obstruction) considerations.

16. Remove all concrete foundations, footings, and other subsurface infrastructure (such as drains and sumps) in coastal sites (onshore) that are included in offshore pipeline abandonment.
17. Remove all pipeline surface minor equipment, piping and appurtenances associated solely with pipeline operation and safety, unless they will be removed during facility decommissioning or have future economic utility.
18. Document final site condition and retain all records (including, for example, “as abandoned” drawings, before-and-after photos, videos or sonar scans, regulatory submittals, permits and approvals, contractual records, route maps and end points of abandoned-in-place pipelines, sampling reports, and inventory data).

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Compatibility with Fluid

The gasket should obviously not be affected by fluid being sealed over the whole range of operating conditions. If any doubt exists, then the gasket manufac­turer should be consulted.

Temperature

The gasket selected should have reasonable life expectancy at the maximum temperature encountered (or the minimum temperature if for a low temperature application). A broad indication of the tem­perature pressure ratings of the common gasket materials is shown in the figure below.

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Purpose

To create a seal, gasket has to fill up the voids in the flange surface present because of surface finish and any flange rotation (or relative distortion) between the two surfaces.
The flange surface will thus give a broad indication of which gasket materials are likely to be suitable. Finishes of standard raised face flanges usually fall within the range 3.2 to 12.5mm, but this may be expressed in micro inch or roughness number.

Surface Joining

The recommended surface finish for the compressed fibre jointing (above a thickness of 1 mm) is 3.2mm to 12.5mm Ra (125m in 500min. CLA). These values are also used for graphite laminate (above a thickness of 0.8mm).
A surface finish of 1.6mm to 6.3mm Ra (63 to 200 in. CLA) is possible for tongue and groove flange facings or for very thin gaskets (0.4mm or below).
Surface finishes below 1.6mm are not recommended due to their negative effect on creep resistance of the gasket.

Surface for Spiral Wound Gasket

This type of gasket requires a range of surface finishes dependent upon the application:

• General - 3.2mm to 5.1mm Ra (125min. to 200min. CLA)
• Critical - 3.2mm Ra (125min. CLA).
• Vacuum applications - 2.0mm Ra (80min. CLA)

Solid Flat Metal Surface

A surface finish in the order of 1.6mm Ra is acceptable but for more critical conditions, a finish no more coarse than 0.8mm Ra is preferred. Again for optimum performance, the smoother the flange surface finish, the better the performance.

Surface for Metallic Ring Joint Gaskets

The angled surfaces (typically 23°) of both grooves and octagonal gaskets and the contact faces of oval gaskets should have a surface finish no rougher than 1.6mm Ra.

Machining of Flange Faces

Under no circumstances should flange seating surfaces be machined in a manner that tool marks extend radially across the seating surface. Such tool marks are practically impossible to seal regardless of the type of gasket being used.

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What is Liquefied Natural Gas?

• Liquid methane that contains trace contaminants
• Stored at atmospheric pressure & -161°C (-256°F)
• Colorless, odorless, non-corrosive and non-toxic
• Chemical composition (typical)

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1. Abstract

The Safety Shutdown concept is focused on the prevention of hydrocarbon release, stopping the flow of hydrocarbon to a leak, and minimizing the effects of hydrocarbon that are released. Additionally, fire and toxic gas protection is also provided.
The primary goal is to maximize available production and at the same time to shore in a safety manner to equipment and personnel. This goal will be accomplished by employing a Keep It Simple and Safe philosophy and a Four-Level Shutdown concept.

2. Implementation

The basis for implementing the Safety Shutdown concept is the American Petroleum Institute Recommended Practice RP 14C. This Recommended Practice was used as a guide in developing the shutdown logic. API RP 14C provides two levels of protection to prevent or minimize the effects of an equipment failure. The two levels of protections are

• The highest order (primary)
• The next highest order (secondary)

Listed below are examples of undesirable events that cause alarm and/or shutdown action. This is not an all inclusive list, it is however illustrative of the protection philosophy.

• Overpressure
• Underpressure
• Leak
• Liquid Overflow
• Gas Blow-by
• Fired Equipment Protection
• High Hydrogen Sulfide Concentration
• Fire

Risk severity is divided into Four (4) Levels of Shutdown. These different risk levels will be utilized to protect equipment and personnel, while maintaining production as high as practical.
The shutdown levels are defined as follows:
Level 1: Local System Shutdown. It involves only services not imperative to the main process.
Level 2: Main Process Train Shutdown. It will allows continued operation of the remainder of the facilities and will permit the process train to be corrected and put back on stream.
Level 3: Critical Process Shutdown. The facility is shutdown by an essential single train process or by fire, high toxic gas, or combustible gas alarm. All ESD valves should be closed. All high pressure gas inventories should be relieved to flare only in the event of fire or high toxic gas alarm. Power generation should remain in operation until low fuel gas pressure causes shutdown. Utilities and equipment auxiliaries should remain in service as long as possible.
Level 4: Abandonment. It should be actuated only by senior personnel from the central control room. All ESD valves should be closed and all gas inventories should be vented to flare. The facility should be de-energized except for emergency and other essential power source.

3. Examples

Followings are specific examples that illustrate the Four Level Shutdown philosophy.
Level 1 (Local System Shutdown)

• High or Low Pressure in an incoming flow line to a production header, would shut-in only the affected well.
• The Water Injection System can be automatically shut down, but would not affect oil production.
• The Hot Oil System can be automatically shut down, but would not affect oil production.

Level 2 (Main Process Train Shutdown)

• A gas compression train can be automatically shut down, but would not affect the oil production.
• An oil production train can be automatically shut down, and oil production affected only by volume loss from the affected train.
• A gas turbine generator set can be automatically shut down. If the oil train pump can still maintain full production, no reduction in oil production is required. Otherwise curtailment of oil production or standby power augmentation should be required to prevent a level 3 shutdown.
• The Glycol Regeneration Unit can be automatically shut down, but not affect Fuel Gas, Gas Lift Gas Flow or Oil Production. A facility shut down would occur only if the problem is not corrected before the residue gas moisture analyzer reaches the shutdown value.

Level 3 (Critical Process Shutdown)

• Instrument air failure (automatic)
• Leak detection in any main oil production header
• Combustible gas sensors (automatic)
• Fire sensors (automatic)
• Hydrogen Sulfide sensors (automatic)
• Critical Process Shutdown, i.e. Fuel gas (automatic)
• Manual

Level 4 (Abandonment)

• Manual initiation required by senior personnel only and would be confirmed over the public address system.

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What is Knowledge?
There are two types of knowledge that can be transferred between people and/or entities. A significant difference is between tacit and explicit knowledge:

Tacit knowledge is the stock of expertise and knowledge within an organization—primarily located within the brains of employees that cannot be easily expressed or identified, but may nevertheless be essential to its effective operation.

Explicit knowledge is the most visible knowledge found in practices, manuals, presentations, guidelines, documentation, files and other accessible sources.

The importance of knowledge management (KM) within the corporate environment as mentioned by Chevron’s former CEO, Ken Derr: “We learned that we could use knowledge to drive learning and improvement in our company. We emphasize shopping for knowledge outside our organization rather than trying to invent everything ourselves. Every day that a better idea goes unused is a lost opportunity. We have to share more, and we have to share faster.” BP’s former chairman and CEO, John Browne, similarly identified the central role of KM: “All companies face a common challenge: using knowledge more effectively than their competitors do.” The oilfield services leader Schlumberger’s D.E. Baird was saying that: “We must become experts in capturing knowledge, integrating and preserving it, and then making what has been learned quickly and easily available to anyone who will be involved in the next business decision.” The online knowledge-based OGnition also mentioned: “With worldwide knowledge in the energy industry, we offer to close the competency gaps in the workforce by leveraging the experience and technical knowledge of industry experts to address the challenges the industry faces today.”

Urged by a common goal of maintaining valuable knowledge, energy and services companies set out to adopt a strategy to establish their own sets of knowledge management. The table below shows how each company started its own Knowledge Management.

Company	Motive for Adopting Knowledge Management
BP	Following radical organizational decentralization, Knowledge Management viewed as mechanism for achieving lateral coordination
Shell	In Shell’s highly decentralized multinational structure, Knowledge Management was a natural complement to strategic planning and career management as an integrating mechanism. With poor profitability during early 1990s, Shell came under strong pressure to make more effective use of its dispersed talent
Chevron	Chevron’s adoption of Knowledge Management driven by pressure for cost reduction during early 1990s and as recent as 2015 resulted in strong interest in the transfer of best practices
ExxonMobil	XOM adopted Knowledge Management during the mid 1990s primarily by its desire to improve efficiency in E&P and in refining through improved identification and transfer of best practices
ConocoPhillips	Expansion of exploration, especially in deepwater Gulf of Mexico, created the need for data management systems to support large amount of data being generated and processed and link them to decision processes
Marathon Oil	Desire to improve upstream performance through more effective linking of people to people and people to information
Schlumberger	Knowledge Management came from the need to link rapidly advancing data management with systems that link human expertise in globally distributed operations
Halliburton
Fluor Corporation	Fluor started the Knowledge Management system, Knowledge OnLine, to enable employees throughout Fluor's worldwide offices to access corporate information and contribute solutions, lessons learned and expertise

When did Knowledge Management become recognized by companies?

Since the early 1990s, the major oil and gas companies as well as large services and consulting firms have realized that they are operating in a knowledge-based business environment where technical and safety performance must be achieved through the early identification of opportunities and potential issues that can arise, both from an organizational knowledge-capture perspective and as training to a transitioning workforce.

The following table illustrates the timing when companies started adopting Knowledge Management.

Company	Adoption of Knowledge Management	Originated for Knowledge Management
BP	1996	Organizational learning/best practices transfer in upstream
Shell	1995	Organizational learning initiatives by corporate planning
Chevron	1996	Best practices transfer and cost reduction
ExxonMobil	2003	Exxon: application of IT to E&P Mobil: best practices transfer
ConocoPhillips	1998	IP support for E&P
Marathon Oil	1999	IP applications to exploration
Schlumberger	1997	IP applications to drilling
Halliburton	1998	IP applications to drilling
Fluor Corporation	1998	Collaboration and knowledge transfer

Why should we capture Knowledge?

• Some select industries are faced with an aging workforce. The majority of the workforce, in fact, will be nearing retirement age over the next decade.
• Between 2000 and 2010, the Society for Petroleum Engineers (SPE) estimated that 231,000 years of cumulative experience and knowledge will be lost to the industry in the next 10 years due to the retirement of petroleum engineers and other technical staff. Knowledge management offers a means of limited and potentially devastating effects of the continuous knowledge loss due to retirement & downsizing (Drain, 2001).
• In order to make sure that this current gap does not turn into a future shortage, the industry needs to work in tandem with educational institutions and government to recruit and train people and transfer knowledge.
• It is served as a hub for innovative technologies and thinking and as an industry striving to always improve in both good times and challenging times.
• Since the energy industry is often challenged by fluctuations due to the world market, supply and demand, geopolitical conditions, etc. that makes sustaining the industry and workforce a huge challenge, a knowledge database can provide current and future industry professionals a means to exchange knowledge, collaborate and to address technical and commercial challenges facing the industry.

How can Knowledge Management help current and future professionals in the energy industry?

After the oil bust during 2008-2009 and as recent as Fall of 2014, more energy knowledge loss contributed by people taking early retirement, forced to move to a related industry and some taking a different approach of pursuing an entirely new career path. Knowledge Management is even more critical when baby boomers, born between 1946 and 1964, are heading into retirement in large numbers. If not managed properly, this could contribute to lost and irreplaceable knowledge in the industry.

Major companies have been going beyond occasional bilateral knowledge exchanges to form interactive groups that share knowledge in a rich, continuous and dynamic manner. Since 1998, all of the oil and gas majors have established informal or semi-formal groupings of employees that share common technical or professional interests for the explicit purpose of sharing knowledge. These knowledge-sharing groups go under a range of different names. For example, community types within ExxonMobil include: communities of Practice, Best Practice Communities, and Communities of Interest (ExxonMobil, 2003). Unfortunately, information gathered from these interactive groups’ knowledge sharing sessions often does not equate to real life experience that professionals can search for easily.

In order to mitigate the shortcoming to replace valuable knowledge, we need tools that capture the intangible assets of tacit knowledge for speedy exploitation to superior technology, management systems, innovation and know-how in order to achieve the competitive advantage in the industry, especially not to reinvent the wheels.

There are online forums and platforms that can help such as Google and Linkedin Groups that gear toward technical subjects. However, those groups are typically organized in an isolated subject or discipline. If one needs to learn across disciplines and various subjects, chances are that person needs to join multiple groups in order to get the information (s)he seeks to learn.

Fortunately, there is one online knowledge network, OGnition, that can connect those missing dots together. OGnition is an online community for the energy industry that offers knowledge and solutions in disciplines that range from upstream, midstream and downstream to occupational safety and operations. Anyone can ask a question to be answered by a Subject Matter Expert (SME) in their field of expertise. People can also share their accrued industry experience as lessons learned through posting as a blog or simply describing the factual events. Sharing lessons learned is the most valuable way to capture knowledge management that can be tagged and searched for and reused repeatedly.

The goal of knowledge management is to make sure that good experience gets repeated and bad incidents never ever happen again, to anyone, anywhere. Without knowledge sharing and lessons not-learned, we will keep making mistakes and reinventing the wheel.

Knowledge is meant to flow!




REFERENCES
Boyd, A. (2003): “Shell’s Communities of Practice: Ten Years On”. Presentation. January.
ExxonMobil Corporation (2003): Knowledge Management in ExxonMobil Upstream. Presentation, February.
Chevron Texaco Corporation (2002): The Chevron Texaco Way. San Francisco.
Derr, T.K. (1999): “Managing knowledge the Chevron way”. Speech given at Knowledge Management World Summit. San Francisco, California. Available at http://www.chevrontexaco. com/news/archive/chevron_speech/1999/99-01-11.asp
Drain, B. (2001): Retaining Intellectual Capital in the Energy Industry. Sapient Corporation.
Gartner Group (1999): The Knowledge Management Scenario: Trends and Directions for 1998-2003. Gartner, 18 March.
Hansen, M.T., Nohria, N. Tierney, T. (1999): “What’s Your Strategy for Managing Knowledge?”, Harvard Business Review, Vol. 77, num. 2, pp. 106–116.
KPMG Consulting (2002): Knowledge Management Research Report 2000. KPMG, October.
Grant, R. (2013): The Development of Knowledge Management in the Oil and Gas Industry, Universia Business Review.
OGnition (2016): Retrieved from http://www.ognition.com/about


NOTES
Contact author: Tadd Pham; https://plus.google.com/+TaddPham

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