Glossary
Browse the IADC Lexicon alphabetically or by category. Get comprehensive definitions of drilling industry terms.
Sand Control
Definition(s)
Sand control
Sand control involves the use of specialized methods/equipment downhole to prevent sand from being produced in the wellbore. Such methods/equipment include: chemical consolidation; screens, slotted liners and filters; inside casing and open-hole gravel packs; propped fracturing, including use of resin coated sand. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsSand Management
Definition(s)
Sand management
An alternative to the use of sand control is sand management, which involves the use of measures to minimize, monitor and manage sand production within allowable limits throughout the field life, without relying on downhole sand-control equipment/methods. While this approach has the advantages of low capital cost and allowing maximization of production rates, it does rely heavily on the predictions of how much sand is likely to be produced over the life of the well. It also requires ongoing monitoring of the sand production from each well and management of the attendant risks. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsSlugging
Definition(s)
Slugging
Of all the different flow regimes, the one typically of most interest in multiphase subsea production systems is slug flow. Slug flow involves the intermittant production of liquid slugs and gas bubbles, some of which can be hundreds of metres long, and can lead to severe fluctuations in pressures and flowrates throughout the production system if not properly predicted and managed. Such dramatic fluctuations can cause: equipment damage, due to vibration, impact loads and/or enhanced corrosion; large disturbances in the separation facilities, resulting in poor separation of phases; large and rapidly varying compressor loads, resulting in inefficient compressor operations and unwanted flaring; frequent shutdowns and/or adoption of restrictive operating practices, both of which can result in a significant loss of revenue. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsNormal Slugging
Definition(s)
Hydrodynamic slugging
Hydrodynamic slugging (also known as normal slugging) usually occurs at moderate gas and liquid velocities. As the relative velocity of the gas moving over the liquid increases, the liquid tends to form waves until at some point the height of the waves bridges to the top of the pipe and a slug is formed. Such slugs are often generated at or near the inlet point of the system, and can grow or shrink in length downstream of their formation point, due to changes in the inclination angle and/or compressibility effects. The length of hydrodynamic slugs is principally a function of the flowline diameter (but typically they are relatively short, being in the order of 20 to 40 pipe diameters in length) and hence the use of two smaller-diameter flowlines in place of one bigger line can assist in controlling this type of slugging. It should be noted, however, that these short high-frequency slugs can also merge into longer low-frequency slugs due to terrain/other effects. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsHydrodynamic Slugging
Definition(s)
Hydrodynamic slugging
Hydrodynamic slugging (also known as normal slugging) usually occurs at moderate gas and liquid velocities. As the relative velocity of the gas moving over the liquid increases, the liquid tends to form waves until at some point the height of the waves bridges to the top of the pipe and a slug is formed. Such slugs are often generated at or near the inlet point of the system, and can grow or shrink in length downstream of their formation point, due to changes in the inclination angle and/or compressibility effects. The length of hydrodynamic slugs is principally a function of the flowline diameter (but typically they are relatively short, being in the order of 20 to 40 pipe diameters in length) and hence the use of two smaller-diameter flowlines in place of one bigger line can assist in controlling this type of slugging. It should be noted, however, that these short high-frequency slugs can also merge into longer low-frequency slugs due to terrain/other effects. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsTerrain Slugging
Definition(s)
Terrain slugging
Terrain slugging is caused by the accumulation of significant amounts of liquid in low points along the line. Once the liquid bridges to the top of the pipe, the gas trapped upstream of the liquid slug starts to be compressed, until it reaches a pressure sufficient to overcome the hydrostatic head of the liquid and a chaotic blowout expansion will then occur. As the slug then moves through an uphill section of the line, liquid is shed from its rear and runs back down the slope to the low point, while at the same time stratified liquid is scooped up in front of the slug and added to its front. If insufficient liquid is available to be scooped up in front of the slug to replace that lost at the rear, then the slug will collapse before it reaches the next high point in the line. In systems with a steady liquid inflow, the amount of liquid in the line eventually accumulates to the point where terrain induced slugs successfully emerge from the system. Due to gravity effects, terrain slugging is worse in downward-sloping lines. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsRiser Slugging
Definition(s)
Severe or riser slugging
At the ultimate lowpoint (i.e. the riser base), terrain slugging can often be so dramatic that it is also known as severe or riser slugging. Severe slugging occurs when liquid accumulates at the riser base for an extended period of time under certain flow conditions, particularly if there is a downward slope in the line at the riser base and the flowrate is low. Severe slugging is a significant problem particularly in deepwater production systems, and hence has received an enormous amount of attention, both from an analytical viewpoint and also with respect to proposed solutions. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsSevere Slugging
Definition(s)
Severe or riser slugging
At the ultimate lowpoint (i.e. the riser base), terrain slugging can often be so dramatic that it is also known as severe or riser slugging. Severe slugging occurs when liquid accumulates at the riser base for an extended period of time under certain flow conditions, particularly if there is a downward slope in the line at the riser base and the flowrate is low. Severe slugging is a significant problem particularly in deepwater production systems, and hence has received an enormous amount of attention, both from an analytical viewpoint and also with respect to proposed solutions. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsOperational Slugging
Definition(s)
Operational slugging
Operational slugging can be defined as slugging that is due to deliberate changes in the operation of the system, such as pigging, start-up, blowdown and changes in rate. Source: API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global StandardsPassive Barrier
Definition(s)
Passive barrier
Passive barriers are typically “permanent” barriers that are not actuated or routinely disturbed once they are in place, such as the following: cement (and competent underground strata); downhole packers (including seal-bore extensions); downhole components, such as mandrels and valves for gaslift and chemical injection; subsea wellheads (including wellhead gaskets); casing and tubing strings (including hangers and seal assemblies); subsea tree bodies and valve blocks (including interfacing gaskets); pipeline systems (including jumpers, connector bodies, gaskets and pipe); tree and manifold piping; pressure-sealing caps (including gaskets).1Source(s)
1. API RP 17A, Design and Operation of Subsea Production Systems—General Requirements and Recommendations, Fourth Edition, Reaffirmed 2011. Global Standards