Glossary
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Fluid Migration Potential
Definition(s)
Fluid Migration Potential
The API inactive well program evaluates the potential for wellbore fluids to migrate through an inactive wellbore. Four fluid migration potential categories are defined in Table 3-1 as minimum, low, moderate, and significant. The appropriate fluid migration potential category for an inactive well is determined by the presence, or absence, of pressured formations and by the number of levels of protection. Concerns in evaluating the fluid migration potential are pressured formations existing as the completion interval or pressured formations existing behind uncemented casing in the same uncemented annulus as a fresh water aquifer that is not completely covered by surface casing. Pressured formations behind cemented casing are isolated and have minimum potential for fluid migration. TABLE 3-1 CATEGORIES OF FLUID MIGRATION POTENTIAL INTO FRESH WATER AQUIFERS Fluid Migration Potential Category Minimum There are no pressured formations, or the only pressured formations are isolated from the fresh water aquifers by cemented production casing, liner, or intermediate casing. Low The well has two or more levels of protection, there is no sustained pressure on the surface casing annulus, and The completion interval is a pressured formation, and all other pressured formations are isolated from the fresh water aquifers by cementing production casing, liner, or intermediate casing, or The completion interval may or may not be a pressured formation, but there are two or more levels of protection between the shallowest uncemented pressured formation and the lowermost fresh water aquifers. Moderate The well has one level of protection, there is no sustained pressure on the surface casing annulus, and The completion interval is a pressured formation, and all other pressured formations are isolated from the fresh water aquifers by cemented production casing, liner, or intermediate casing, or The completion interval may or may not be a pressured formation, but there is one level of protection between the shallowest uncemented pressured formation and the lowermost fresh water aquifer. Significant The well has zero levels of protection, and the completion interval is a pressured formation, or There is sustained pressure on the surface casing annulus, or The Christmas-tree or stuffing-box assembly design and mechanical integrity is not sufficient to provide long-term containment of the wellbore fluids, or A pressured formation and a fresh water aquifer exist in the same uncemented annulus. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsWell Construction
Definition(s)
Well Construction
The construction features of inactive wells which provide the mechanical barriers to fluid migration include: i) surface casing installed below all fresh water aquifers with cement circulated to the surface; 2) any intermediate casing installed and cemented, 3) production casing installed and cemented into the lowermost confining zone; and 4) any tubing and packer set in the well above the completion interval. The Christmas-tree or stuffingbox assembly isolates the wellbore fluids from the surface and provides readily accessible gauges on all tubing, casing, and annuli outlets for ease of monitoring pressures. The mechanical integrity of these well construction components is the key factor in their ability to provide a barrier to fluid migration. There are inactive wells which provide adequate protection against fluid migration into a fresh water aquifer or to the surface, but they may not have all of the construction details discussed above. By tailoring the monitoring program to a well's construction, operators can increase monitoring frequency for inactive wells that have fewer barriers to fluid migration. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsWell Construction
A set of operations to be directed by the lease operator employing the drilling contractor and third-party services equipment and personnel. Source: API Bulletin 97, Well Construction Interface Document Guidelines, First Edition, December 2013. Global StandardsInactive Well Program Goal
Definition(s)
Inactive Well Program Goal
The goal of the API inactive well program is to focus operator efforts on those inactive wells that pose a threat to fresh water aquifers or the surface. The API program involves a risk-based approach to developing effective monitoring programs for inactive wells so that fluid migration into fresh water aquifers, surface soils, or surface waters is prevented. TO meet this goal and to provide the greatest flexibility in monitoring program design, it is suggested that operators take appropriate action to add levels of protection whenever practical or appropriate. For example, temporarily abandoning a producing well completed with a packer in a pressured formation adds a level of protection, since the completion interval is isolated. In such a case, the risk of wellbore fluid migration from the completion interval is reduced, which may justify less frequent monitoring. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsInactive Well Program Concepts
Definition(s)
Inactive Well Program Concepts
The API inactive well program is a risk-based approach for determining if an inactive well poses a threat to fresh water aquifers, surface soils, or surface waters. The methodology described in the following sections identifies wellbore conditions that prevent fluid migration from pressured formations. Fluid migration potentials for inactive wells are defined based upon the presence of pressured formations and upon the well construction and its mechanical integrity. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsLevel of Protection
Definition(s)
Level of Protection
A level of protection is a barrier to fluid migration into fresh water aquifers that has mechanical integrity, and its integrity can be monitored with some degree of confidence. Well construction components, such as surface casing, production casing, tubing and packer, and wellbore plugs, are such barriers. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsLevel of Protection
A level of protection is a barrier to fluid migration into fresh water aquifers that has mechanical integrity, and its integrity can be monitored with some degree of confidence. The well construction components, such as surface casing, production casing, tubing and packer, and wellbore plugs, are such barriers. Levels of protection are sometimes referred to as layers of protection. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsPressured Formation
Definition(s)
Pressured Formation
A pressured formation is any producing, injection, disposal, permeable hydrocarbon bearing, or permeable salt water bearing formation penetrated by the well which has sufficient pressure to initiate and sustain significant fluid migration into a fresh water aquifer or to the surface. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsTemporarily Abandoned Well
Definition(s)
Temporarily Abandoned Well
An inactive well should be classified as TA when the completion interval is isolated. The completion interval may be isolated using the bridge plug method, the cement squeeze method, or the balanced cement plug method. As an alternative to the bridge plug method, isolation of the completion interval may also be achieved by installing a plug in an existing packer which does not have tubing. Temporary abandonment should be used when an operator is holding a wellbore in anticipation of future utilization, such as in an enhanced oil recovery project. TA status should begin the day afìer the completion interval has been isolated from the wellbore. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsTemporarily Abandoned (TA)
Inactive wells in which the completion interval has been isolated from the interior of the casing. The completion interval may be isolated using the bridge plug method, the cement squeeze method or the balanced cernent plug method. If a packer is installed in the well, isolation of the completion interval may also be achieved by installing a plug in the packer which has no tubing. Temporary abandonment is generally used when a well is a candidate for future utilization, such as in a possible enhanced oil recovery project. TA status should begin the day after the completion interval has been isolated from the wellbore. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsTemporarily Abandoned Well
TEMPORARILY ABANDONED WELL shall mean a well which is incapable of production or injection without the addition of one or more pieces of wellhead or other equipment, including valves, tubing, rods, pumps, heater-treaters, separators, dehydrators, compressors, piping or tanks. Source: Oil and Gas Conservation Commission, Practice and Procedure, Code of Colorado Regulations, 2 CCR 404-1, February 2013. RegulationsShut-in Well
Definition(s)
Shut-In Well
Well with one or more valve(s) closed on the flow path. Source: ISO 16530-1:2017, Petroleum and natural gas industries — Well integrity – Part 1: Life cycle governance, First Edition, March 2017. Global StandardsShut-In Well
An inactive well should be classified as shut-in when the completion interval is open to the tubing or to the casing. A shut-in well may have tubing and packer, which isolates the interior of the casing above the packer from the completion interval. A well may also be shut-in without a packer which exposes the interior of the casing to any fluids from the completion interval. Shut-in wells may have been removed from active service in anticipation of workover, temporary abandonment, or plugging and abandonment operations. Generally, the wellbore condition is such that its utility may be restored by opening valves or by energizing equipment involved in operating the well. Shut-in status should begin three months after production, injection, disposal, or workover operations cease. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsShut-In
Inactive wells in which the completion interval is open to the tubing and to the casing, or is open to the tubing only. The well may be shut-in without packer and with or without tubing, in which case the interior of the casing is not isolated from the completion interval. Or, the shut-in well may have tubing and packer, which isolates the interior of the casing above the packer from the completion interval. Shut-in wells have been removed from active service in anticipation of a workover, temporary abandonment, or plugging and abandonment operations. Generally, the wellbore condition is such that its utility may be restored by opening valves or by energizing equipment involved in operating the well. Shut-in status should begin 90 days after production, injection, disposal or workover operations cease. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsShut-In Well
SHUT-IN WELL shall mean a well which is capable of production or injection by opening valves, activating existing equipment or supplying a power source. Source: Oil and Gas Conservation Commission, Practice and Procedure, Code of Colorado Regulations, 2 CCR 404-1, February 2013. RegulationsInactive
Definition(s)
Inactive
The term inactive, when used with regard to well status, is broadly defined by regulatory agencies and covers a wide spectrum of wellbore conditions. Furthermore, Federal and state regulatory programs rarely make a distinction between inactive wells which have the completion interval isolated from the wellbore and those which have open completion intervals. Well status terms such as shut-in, standing, temporarily abandoned (TA), inactive, suspended, etc. have generally been used interchangeably by regulatory agencies. Industry and regulatory agencies should standardize the terminology used to describe inactive wells. API recommends that inactive wells be classified as either shut-in or TA as defined below. Source: API BULLETIN E3, Environmental Guidance Document: Well Abandonment and Inactive Well Practices for U.S. Exploration and Production Operations, First Edition, January 1993 (Reaffirmed June 2000). Global StandardsInactive
“Inactive well” means a well that is not being used for beneficial purposes such as production, injection or monitoring and that is not being drilled, completed, repaired or worked over. Source: Oil and Gas, New Mexico Administrative Code Title 19, Chapter 15, January 2013. RegulationsVIV
Definition(s)
VIV
In-line and transverse oscillation of the riser string as the result of the periodic shedding of vortices from sea currents. Source: API Specification 16Q, Design, Selection, Operation, and Maintenance of Marine Drilling Riser Systems, Second Edition, April 2017. Global StandardsVIV
vibration. Source: API Specification 16Q, Design, Selection, Operation, and Maintenance of Marine Drilling Riser Systems, Second Edition, April 2017. Global StandardsVIV
Vortex-induced vibration. Source: API Standard 2RD, Dynamic Risers for Floating Production Systems, Second Edition, September 2013. Global Standards Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards Source: API RP 17B, Recommended Practice for Flexible Pipe, Fourth Edition, July 2008. Global Standards Source: API SPEC 17E, Specification for Subsea Umbilicals, Upstream Segment, Fourth Edition, October 2010. Global Standards Source: ISO 19901-7:2013, Petroleum and natural gas industries – Specific requirements for offshore structures – Part 7: Stationkeeping systems for floating offshore structures and mobile offshore units. Global StandardsVIV
In-line and transverse oscillation of a riser in a current induced by the periodic shedding of vortices. Source: API Standard 2RD, Dynamic Risers for Floating Production Systems, Second Edition, September 2013. Global StandardsUV
Definition(s)
UV
Ultraviolet. Source: API RP 14G, Recommended Practice for Fire Prevention and Control on Fixed Open-type Offshore Production Platforms: Upstream Segment, Fourth Edition, April 2007. Global Standards Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards Source: API RP 17B, Recommended Practice for Flexible Pipe, Fourth Edition, July 2008. Global Standards Source: API SPEC 17J, Specification for Unbonded Flexible Pipe, Third Edition, July 2008. Global Standards Source: API RP 98, Personal Protective Equipment Selection for Oil Spill Responders, First Edition, August 2013. Global StandardsUV
Ultra-violet. Source: API SPEC 17E, Specification for Subsea Umbilicals, Upstream Segment, Fourth Edition, October 2010. Global Standards Source: Rules for Classification and Construction, IV Industrial Services, 6 Offshore Technology, 9 Guideline for Personnel Transfers by Means of Lifting Appliances, Edition 2011, Germanischer Lloyd SE, Global StandardsUKOOA
Definition(s)
UKOOA
United Kingdom Offshore Operators Association. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards Source: Prevention of Fire and Explosion, and Emergency Response on Offshore Installations, Offshore Installations (Prevention of Fire and Explosion, and Emergency Response) Regulations 1995, Approved Code of Practice and guidance (UK HSE L65), Second Edition, 1997. Regulatory Guidance Source: A Guide to the Offshore Installations and Pipelines Works (Management and Administration) Regulations 1995, Guidance on Regulations (UK HSE L70), Second Edition, 2002. Regulatory Guidance Source: Rules for Classification and Construction, IV Industrial Services, 6 Offshore Technology, 9 Guideline for Personnel Transfers by Means of Lifting Appliances, Edition 2011, Germanischer Lloyd SE, Global StandardsSWL
Definition(s)
SWL
A load-carrying member with thrust bearings that allows the load to rotate. Source: API RP 2D, Operation and Maintenance of Offshore Cranes, Seventh Edition, December 2014. Global StandardsSWL
Safe working load. Source: API RP 2D, Operation and Maintenance of Offshore Cranes, Seventh Edition, December 2014. Global Standards Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards Source: API SPEC 17D, Design and Operation of Subsea Production Systems—Subsea Wellhead and Tree Equipment, Upstream Segment, Second Edition May 2011 (Errata September 2011). Global Standards Source: Rules for Classification and Construction, IV Industrial Services, 6 Offshore Technology, 9 Guideline for Personnel Transfers by Means of Lifting Appliances, Edition 2011, Germanischer Lloyd SE, Global Standards Source: Rules for Classification – Offshore units, DNVGL-OU-0101, Offshore drilling and support units, DNV GL, July 2015. Global StandardsSWL
Still water level. Source: ISO 19905-1:202, Petroleum and natural gas industries – Site-specific assessment of mobile offshore units – Part 1: Jack-ups. Global StandardsSBR
Definition(s)
SBR
Styrene butadiene rubber. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global StandardsSBR
Shear Blind Ram. Source: Deepwater Well Control Guidelines. IADC GuidelinesSBR
Storage bend radius. Source: API RP 17B, Recommended Practice for Flexible Pipe, Fourth Edition, July 2008. Global StandardsPD
Definition(s)
PD
Product definition. Source: API STANDARD 18LCM, Product Life Cycle Management System Requirements for the Petroleum and Natural Gas Industries, First Edition, April 2017. Global StandardsPD
Published Document. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global StandardsPD
Pulse density. Source: API RP 5A5, Field Inspection of New Casing, Tubing, and Plain-end Drill Pipe, Reaffirmed August 2010. Global Standards Source: API RP 7G-2, Recommended Practice for Inspection and Classification of Used Drill Stem Elements, First Edition, August 2009. Global StandardsPCD
Definition(s)
PCD
Pitch circle diameter. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global StandardsN/A
Definition(s)
NA
Not applicable. Source: API Standard 2RD, Dynamic Risers for Floating Production Systems, Second Edition, September 2013. Global Standards Source: API RP 17G, Recommended Practice for Completion/Workover Risers, Second Edition, July 2006 (Reaffirmed April 2011). Global Standards Source: API SPEC 5CRA, Specification for Corrosion Resistant Alloy Seamless Tubes for Use as Casing, Tubing and Coupling Stock, Upstream Segment, First Edition, February 2010 (Errata August 2011). Global Standards Source: API SPEC 16C, Specification for Choke and Kill Systems, First Edition, January 1993 (Reaffirmed 2001). Global StandardsN/A
Not applicable. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global StandardsMWL
Definition(s)
MWL
Mean Water Level. Source: API Standard 2RD, Dynamic Risers for Floating Production Systems, Second Edition, September 2013. Global Standards Source: API RP 17B, Recommended Practice for Flexible Pipe, Fourth Edition, July 2008. Global StandardsMWL
Mean Water Line. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global StandardsMBS
Definition(s)
MBS
Minimum breaking strength. Source: API RP 2SM, Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition, July 2014. Global Standards Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards Source: ISO 19901-7:2013, Petroleum and natural gas industries – Specific requirements for offshore structures – Part 7: Stationkeeping systems for floating offshore structures and mobile offshore units. Global StandardsMBS
The minimum break strength (MBS) is defined as the minimum single value from a series of five prototype rope assembly, including terminations, break tests.
Source: API RP 2SM Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, Second Edition, July 2014. Global StandardsMBS
The minimum single value from a series of five prototype rope assembly break tests, including terminations. Source: API RP 2SM Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, Second Edition, July 2014. Global Standards Source: API RP 2SM, Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition, July 2014. Global StandardsMBS
RCS certified strength of a chain, wire rope, fibre rope or accessories. Source: ISO 19901-7:2013, Petroleum and natural gas industries – Specific requirements for offshore structures – Part 7: Stationkeeping systems for floating offshore structures and mobile offshore units. Global StandardsMBR
Definition(s)
MBR
Minimum bend radius. Source: API Specification 16Q, Design, Selection, Operation, and Maintenance of Marine Drilling Riser Systems, Second Edition, April 2017. Global Standards Source: API RP 2SM Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, Second Edition, July 2014. Global Standards Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards Source: API RP 17B, Recommended Practice for Flexible Pipe, Fourth Edition, July 2008. Global Standards Source: API SPEC 17J, Specification for Unbonded Flexible Pipe, Third Edition, July 2008. Global Standards Source:API SPECIFICATION 7K, Drilling and Well Servicing Equipment, Sixth Edition, December 2015. Global Standards Source: API STD 53, Blowout Prevention Equipment Systems for Drilling Wells, Upstream Segment, Fourth Edition, November 2012. Global StandardsMBR
Minimum bending radius. Source: API RP 2SM, Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition, July 2014. Global StandardsMBR
Minimum radius to which the synthetic fiber rope construction can be bent to without damage to any part of the rope construction (including the jacket and filter). Source: API RP 2SM, Design, Manufacture, Installation, and Maintenance of Synthetic Fiber Ropes for Offshore Mooring, First Edition, July 2014. Global StandardsMBR
The minimum hose bending radius dimension measured from the centerline of the hose specified in Table 10. NOTE: See Figure 11. Source:API SPECIFICATION 7K, Drilling and Well Servicing Equipment, Sixth Edition, December 2015. Global StandardsMBR
Minimum bending radius at zero tensile load. Source: API SPEC 17E, Specification for Subsea Umbilicals, Upstream Segment, Fourth Edition, October 2010. Global StandardsMBL
Definition(s)
MBL
Minimum breaking load. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global StandardsMAOP
Definition(s)
MAOP
Maximum allowable operating pressure. Source: API Standard 2RD, Dynamic Risers for Floating Production Systems, Second Edition, September 2013. Global Standards Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards Source: IADC UBO / MPD Glossary, December 2011. Global StandardsIVA
Definition(s)
IVA
Independent verification agent. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global StandardsHMPE
Definition(s)
HMPE
High modular polyethylene. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global Standards Source: ISO 19901-7:2013, Petroleum and natural gas industries – Specific requirements for offshore structures – Part 7: Stationkeeping systems for floating offshore structures and mobile offshore units. Global StandardsGVI
Definition(s)
GVI
General visual inspection. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global StandardsGRP
Definition(s)
GRP
Glass-reinforced plastic. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global StandardsGRP
Glass-fibre-Reinforced Plastic. Source: ISO 21457:2010, Petroleum and natural gas industries — Materials selection and corrosion control for oil and gas production systems, First Edition,September 2010. Global StandardsGRE
Definition(s)
GRE
Glass-fibre-reinforced epoxy. Source: ISO 14692-1:2017, Petroleum and natural gas industries — Glass-reinforced plastics (GRP) piping — Part 1: Vocabulary, symbols, applications and materials, Second Edition, August 2017. Global StandardsGRE
Epoxy resin-based composite that is reinforced with glass fibre. Source: ISO 14692-1:2017, Petroleum and natural gas industries — Glass-reinforced plastics (GRP) piping — Part 1: Vocabulary, symbols, applications and materials, Second Edition, August 2017. Global StandardsGRE
Glass-reinforced epoxy. Source: API RP 17L2, Recommended Practice for Flexible Pipe Ancillary Equipment, First Edition, March 2013. Global StandardsFEA
Definition(s)
FEA
Numerical method for analyzing dynamic and static response by dividing the structure into small continuous elements with the given material properties.- NOTE: The analysis can be local or global.