a For returns taken through the tree or wellhead below the well control stack see Figure 1, one stripper or annular preventer-type well control component in combination with a flow check
General
This recommended practice (RP) focuses on the assembly and operation of coiled tubing well control equipment in relation to well control practices It does not cover industry practices for conducting well control operations that utilize fluids for hydrostatic pressure balance.
This document covers well control equipment assembly and operation used in coiled tubing intervention and coiled tubing drilling applications performed through:
— christmas trees constructed in accordance with API 6A and/or API 11IW,
— a surface flow head or surface test tree constructed in accordance with API 6A,
— drill pipe or workstrings with connections manufactured in accordance with API 7 and/or API 5CT.
Operations Not Covered in this Document
This document does not encompass several specific operations, including coiled tubing well intervention and drilling without a christmas tree or surface test tree, capillary tubing well service operations involving tubing less than 3/4 inch in outer diameter, coiled tubing interventions within pipelines and flowlines, and reverse circulation operations.
The referenced documents are essential for the application of this document For dated references, only the specified edition is applicable, while for undated references, the most recent edition, including any addenda, is relevant.
API Specification 5CT, Specification for Casing and Tubing
API Specification 6A, Specification for Wellhead and Christmas Tree Equipment
API Specification 7, Specification for Rotary Drill Stem Elements
API Specification 7K, Specification for Drilling and Well Servicing Equipment
API Specification 16A, Specification for Drill-through Equipment
API Specification 16C, Specification for Choke and Kill Systems
API Specification 16D, Control Systems for Drilling Well Control Equipment and Control Systems for Diverter Equipment ASME B31.3 1 , Process Piping
NACE MR 0175/ISO 15156 2 , Sulfide Stress Cracking Resistant-Metallic Materials for Oilfield Equipment
1 ASME International, 3 Park Avenue, New York, New York 10016, www.asme.org.
2 NACE International (formerly the National Association of Corrosion Engineers), 1440 South Creek Drive, Houston, Texas 77218-8340, www.nace.org.
A pressure vessel charged with a non-reactive or inert gas used to store hydraulic fluid under pressure for operation of well control equipment.
An assemblage of multiple accumulators sharing a common manifold
An initial inert gas charge in an accumulator, which is further compressed when the hydraulic fluid is pumped into the accumulator thereby storing potential energy.
The closing and opening of a well control component to assure mechanical functioning.
A pressure-containing equipment component features end connections with varying API size designations and pressure ratings, designed to link other equipment that also has different API size designations and pressure ratings.
The device features a toroidal-shaped, steel-reinforced elastomer packing element that operates hydraulically It is designed to effectively close and seal around various sizes of coiled tubing, ensuring complete closure of the wellbore.
A device positioned between the stripper assembly's top and the injector gripper blocks is designed to support the coiled tubing as it is pushed into the well control stack, effectively preventing or minimizing the risk of tubing buckling in this critical area.
Pump, choke, and kill lines assembled as a unit with rigid pipe, swivel joints, and end connections designed to accommodate specified relative movement between end terminations.
Fluid flow in a direction opposite to the intended direction of flow
A flow check device that is installed on the deployed end of the coiled tubing string and prevents well fluids from flowing out of the well.
NOTE In coiled tubing services, a back pressure valve is typically disconnected from the end with applied internal coiled tubing pressure or with a mechanical release mechanism (shearout sub).
The coupling of two tube bending events
NOTE Bend cycling consists of one straightening event and one bending event, where the material strain is equal in magnitude.
The assembly of valves and piping used to release trapped pressure from the pump line(s) or kill line(s).
The rams in a well control stack are engineered to seal against one another within an unobstructed bore, effectively creating a seal that isolates pressure beneath the rams in the stack.
NOTE The blind rams are not designed to seal against the coiled tubing.
The assemblage of tools and equipment installed on the end of the coiled tubing string used to perform a prescribed service in the wellbore.
A mechanical device used to attach the bottomhole assembly tools to the coiled tubing.
A pressure-containing branch of the choke line manifold used to provide a means for unchoked flow to the atmosphere.
NOTE The by-pass line redirects fluid flow upstream of the choke.
A device with either a fixed or variable aperture used to control the rate of flow of liquids and/or gas.
A high-pressure line connected to the well control stack for the transmission of well fluids to the choke manifold during well control operations.
An assembly of valves, chokes, gauges, pressure sensors and lines used to control the rate of flow from the well during well intervention and well control operations
A combination of valves and fittings assembled above the top of the tubing hanger on a completed well to contain well pressure and control the flow of hydrocarbons and other fluids.
The movement of fluid from the pump(s) down through the coiled tubing string and returning to surface up the annular space in the wellbore.
NOTE The flow of fluids may exit the well control stack through the flow cross/flow tee or production flowline in the christmas tree
A dimensionless factor equal to the area of the piston operator divided by the area of the ram shaft.
Continuous tubing spooled onto a reel that is used in well intervention operations.
A mechanical device used to join two segments of coiled tubing together.
The flattening of coiled tubing due to the application of differential pressure (external to internal), with or without an axial tensile load
Well servicing operations conducted within conventional tubing or tubing-less completions.
NOTE These operations are normally performed with the christmas tree in place using a coiled tubing unit, wireline unit, hoisting unit, hydraulic workover (snubbing) unit or small rig.
Flanges, hubs, and studded connections manufactured in accordance with API specifications, including dimensional requirements.
An enclosure displaying an array of switches, push buttons, lights, valves, various pressure gauges and/or meters to control or monitor coiled tubing operation functions.
Hydraulic fluid (at atmospheric pressure) to be used for operation of the well control components, injector, stripper assembly and reel.
A pressure-containing fitting with a minimum of four openings.
NOTE Usually all four openings are oriented at 90 degrees to one another in the same plane.
Pressure-isolated bars in the bottomhole assembly facilitate the safe insertion and removal of tool strings across multiple sections, even when surface pressure is present This is particularly crucial when the length of the tool string surpasses the height of the well control stack above the tree.
The enlargement of the coiled tubing diameter due to the effects of applied internal pressure when the coiled tubing is subjected to bend-cycling events
A fluid having compressed gas potential energy
Progressive localized permanent structural changes in materials can occur when they are exposed to fluctuating stresses, potentially leading to cracks or complete failure after a certain number of stress cycles.
A protruding rim, with holes to accept bolts and having a sealing mechanism, used to join pressure containing equipment together by bolting one flange to another.
An assembly of a pipe body and end-fittings.
NOTE 1 The pipe body comprises a combination of materials that form a pressure-containing conduit
NOTE 2 The pipe structure allows large deflections without a significant increase in bending stresses.
A valve that permits fluid to flow freely in one direction and contains a mechanism to automatically prevent flow in the reverse direction.
Subsurface completion interval which serves as the source for production of accumulated hydrocarbons or the injection of disposal fluids.
A valve capable of passing a sphere of the valve’s nominal size through the closure mechanism when the valve is in its fully opened position.
NOTE The closure mechanism may or may not be of the same size as the end connections
The operation of a well control component, choke or kill valve, or any other component in one direction.
EXAMPLE Closing the blind rams is one function, and opening the blind rams is a separate function.
3.41 gauge and test port connection
Hole drilled and tapped into API 6A equipment through which internal pressure may be measured or through which pressure may be applied to test the sealing mechanism.
Protruding rim with an external angled shoulder and a sealing mechanism used to join pressure-containing equipment.
A pressure-sealing device used to join two items without using conventional bolted flanges.
NOTE The two items to be sealed are prepared with clamp hubs These hubs are held together by a clamp containing two or four bolts.
The pressure that exists at any point in the wellbore due to the weight of the column of fluid above that point.
Well servicing operations conducted within a completed wellbore.
The act of balancing the formation pressure in a wellbore with the hydrostatic pressure derived from a vertical column of fluid with a given density.
A high-pressure line extends from the pumps to a connection situated beneath the blind rams or shear-blind rams, enabling fluid to be injected into the well or annulus while the designated ram remains closed during well control operations.
An inlet on the well control stack allows for the pumping of fluids into the sheared coiled tubing segment, which is suspended either within the wellbore or in the annulus between the coiled tubing string and the completion tubulars.
The visible escape of pressurized fluid from the equipment's containment area, along with a corresponding drop in test pressure on the recording device, indicates a potential failure during testing.
An assembly of tube sections generally constructed with quick union-type integral seal end connections.
The term refers to the assembly of pressure-control tubular sections positioned between the stripper assembly and the upper-most well control stack-sealing ram, commonly utilized to accommodate the BHA tool string.
An assemblage of pipe, valves and fittings by which fluid from one or more sources is selectively directed to various systems or components.
A fluid that originates from the formation.
Connectors that are not specified in an API dimensional specification, including API flanges and hubs with non-API gasket preparations and manufacturer’s proprietary connections.
The change in roundness of a tube body due to external forces derived from bend-cycling activities.
During concentric well intervention operations, an upward force is generated by the well pressure acting on the cross-sectional area of the tube at the stripper element or pressure isolation ram This force can be less than the buoyancy-compensated weight of the deployed workstring, leading to specific operational challenges.
NOTE 1 In this condition, mechanical assistance is required to support the weight of the tubing during deployment or retrieval operations.
Buoyancy compensation of the workstring depends on three key factors: the weight of the fluid inside the workstring, the weight of the fluid displaced by the workstring, and the air weight of the workstring itself.
During concentric well intervention operations, an upward force is generated when the well pressure acting on the tube's cross-sectional area at the stripper element or pressure isolation ram exceeds the buoyancy-compensated weight of the deployed workstring.
NOTE 1 In this condition, mechanical assistance is required to apply thrust to the tubing during deployment or to maintain control of the workstring when retrieving from the well
General
Coiled tubing well control equipment is essential for conducting safe well intervention services under pressure, but it is crucial to maintain minimal well pressure to prevent excessive wear on the equipment All such equipment must comply with API 16A, API 16C, and API 6A standards, as applicable Additionally, the choice of well control equipment should align with the manufacturers' recommendations for optimal performance.
Coiled Tubing (CT) Operations
Well control equipment must be properly identified, installed, tested, and utilized to ensure continuous control of the well Key factors to review for compliance include the maximum anticipated surface pressure (MASP), maximum anticipated operating pressure (MAOP), well control barriers, coiled tubing (CT) operational pressure categories, well control stack configurations, and the bore size, rated working pressure, and connections of the well control equipment.
4.2.2 Maximum Anticipated Surface Pressure (MASP)
The Maximum Anticipated Surface Pressure (MASP) represents the highest pressure expected at a well's surface This prediction is derived from the formation pressure, adjusted for a wellbore filled with native formation fluid under current conditions In cases where the formation fluid data is unavailable, the MASP should be calculated using the formation pressure minus a wellbore filled with dry gas extending from the surface to the completion interval.
4.2.3 Maximum Anticipated Operating Pressure (MAOP)
The Maximum Allowable Operating Pressure (MAOP) is defined as the highest calculated pressure that a specific equipment component can endure during normal operations and potential contingency scenarios.
NOTE The MAOP may be equal to or greater than the MASP.
A CT well control barrier is a verified mechanical device or a combination of such devices designed to prevent the uncontrolled release of wellbore fluids to the surface These tested barriers must be integrated into the well control stack and bottomhole assembly for the specified service.
CT well control barriers consist of various mechanical devices, including: a combination of an annular sealing component or pipe ram sealing component along with a flow check assembly within the CT BHA; a single blind ram paired with a single shear ram; and a shear-blind combination ram.
The flow check assembly at the end of the CT string, along with an annulus-sealing component in the well control stack, serves as a single barrier, irrespective of the number of sealing devices present In pressure categories that recommend multiple pipe rams, these rams are strategically placed to provide necessary annulus-sealing capability, but they do not enhance the number of barriers within the stack.
When selecting the minimum stack rated working pressure, it is essential to ensure that it accommodates a kill program The recommended pressure margin is indicated by the difference between the Maximum Allowable Surface Pressure (MASP) and the minimum stack pressure rating in Table 1 Various kill margins can be utilized, provided that calculations are conducted for the pumped-fluid kill program The kill procedure may involve methods such as circulation, the lubricate and bleed technique, flowing the well to decrease surface pressure, or pumping at reduced rates to lower friction pressure.
MAOP or MASP which exceeds the limits of Pressure Category (PC) 4 pressure category are beyond the scope of this document.
The configuration of the well control stack is influenced by various factors such as the Maximum Allowable Operating Pressure (MAOP), Maximum Allowable Shut-in Pressure (MASP), and the design of the casing and tubing (CT) string Additionally, the execution of the prescribed service plays a crucial role It is essential that all annular preventer and ram-type well control components, along with any necessary hydraulic valves, are operated from a remote station for safety and efficiency.
The standard well control stack configuration for all pressure categories, excluding PC 0, must consist of specific components The recommended arrangement of these components is outlined from the top down.
1) one stripper or annular preventer-type well control component (see 4.3.1),
2) one blind ram well control component (see 4.3.2.1),
3) one shear ram well control component (see 4.3.3),
4) one kill line inlet (see 4.3.8),
5) one slip ram well control component (see 4.3.4),
6) one pipe ram well control component (see 4.3.2.2).
A manufacturer may utilize a single combination of the blind and shear ram, or a single combination of the slip and pipe ram In a combination ram stack, it is essential to install a kill line inlet between the shear-blind ram and the pipe-slip combination ram positions.
When utilizing a dual combination well control stack alongside the standard configuration, the arrangement of well control components may be altered In this setup, the pipe-slip rams are generally positioned beneath the shear-blind rams.
4.2.6.1.4 The recommendations for flow tee/cross choke(s) and valve assemblies are specified in Section 8, with the recommendations for kill line(s) and valve assemblies provided in Section 9.
Table 1—Pressure Categories for CT Well Control Equipment
Minimum Rated Working Pressure of Stack psig
The minimum rated working pressure of the stack must meet or exceed the Maximum Allowable Operating Pressure (MAOP) A PC-0 designation is applicable to wells that have been shown, according to local regulatory agency guidelines, to be incapable of unassisted flow to the surface.
The PC-0 well control components that satisfy the barrier requirements outlined in Table 1 include a stripper or annular preventer-type component, along with a flow check assembly within the CT BHA for returns taken through the tree or wellhead below the well control stack Additionally, for returns managed through the flow cross or flow tee in the well control stack, specific configurations are utilized to ensure effective well control.
— one stripper or annular preventer-type well control component in combination with a flow check assembly installed within the CT BHA,
— one flow tee or flow cross,
— one pipe ram or annular well control component (optional).
A pipe ram or alternate annular well control component must be installed below the flow tee or flow cross when abrasive, corrosive, or high-velocity fluid returns are anticipated, particularly if these returns exceed the erosive velocity threshold This is crucial to prevent issues during well servicing operations, especially where relative motion may occur between the well control stack and the return lines.
In lieu of the use of a flow check assembly, one blind ram and one shear ram or a shear-blind ram well control component shall be installed
4.2.6.3 Pressure Category 1 (1 psig to 1500 psig)
The PC-1 well control stack configuration and its components, which adhere to the barrier requirements outlined in Table 1, are detailed from top to bottom Firstly, for returns managed through the tree or wellhead beneath the well control stack, a standard configuration is utilized alongside a flow check assembly integrated within the CT BHA Secondly, for returns processed through the flow cross or flow tee within the well control stack, specific configurations are employed to ensure effective management.
— the standard well control stack configuration in combination with a flow check assembly installed within the
— one flow tee or flow cross,
— one pipe ram or annular well control component (optional).
Well Control Components
4.3.1 Stripper/Annular Preventer-type Device
The stripper or annular preventer is a crucial pressure-containing device used to isolate well pressure and effluents from the atmosphere during coiled tubing (CT) operations Its primary function is to create a seal around the coiled tubing in both static and dynamic scenarios.
4.3.2 Pressure Sealing Rams (Blind and Pipe)
Blind rams are engineered to effectively seal the wellbore and isolate pressure when the ram's bore is clear Typically, they serve as the primary well control component in the standard configuration of a well control stack.
Pipe rams are essential for isolating annulus pressure between the outside diameter of coiled tubing (CT) and the inside diameter of the well control stack bore It is crucial that the pipe rams are appropriately sized for the specific CT being utilized and configured accordingly.
CT guides are essential for centering the tubing within the well control stack bore In a standard well control stack configuration, pipe rams typically serve as the bottom ram component.
Pipe rams should hold at least the kill pressure margin differential pressure from above the ram
NOTE For the differential pressure seal from above the ram, a bubble tight seal is not required and some percentage of leakage may be acceptable.
The shear rams must effectively shear the coiled tubing (CT) body and any internal spoolable components at the maximum allowable surface pressure (MASP) of the well, without any tensile loads on the tubing Typically, these shear rams are positioned directly beneath the blind rams in a standard well control stack configuration Additionally, the shear rams should be appropriately sized for the specific CT being utilized.
The shear rams must be designed to perform multiple cuts, ensuring that the shear cut supports effective through-tubing pumping and well-killing operations Additionally, the geometry of the shear cut should be optimized to facilitate fishing operations.
4.3.3.3 The shear rams shall be capable of shearing the CT when the tubing is secured within the slip rams.
The closing pressure needed to shear the coiled tubing (CT) at the maximum allowable surface pressure (MASP) of the well must be lower than the stabilized operating pressure of the well control accumulator system and should not surpass the manufacturer's specified working pressure for the ram operating system.
4.3.3.5 The shear ram blades shall be replaced after each CT shearing operation as soon as practically possible.
The slip rams must be appropriately sized for the coiled tubing (CT) in use and should include CT guides to ensure proper centering of the tubing within the well control stack bore Typically, slip rams are positioned directly above the pipe rams in a standard well control stack configuration.
The slip rams must securely hold the maximum expected hanging weight of the coiled tubing (CT) in heavy conditions without any movement within the slips Additionally, they should also be able to maintain the CT in light conditions, with a force equivalent to the Maximum Allowable Surface Pressure (MASP) multiplied by the cross-sectional area of the tube body, ensuring stability without tubing movement.
The closing pressure needed to maintain the CT at the well's Maximum Allowable Surface Pressure (MASP) must be lower than the stabilized operating pressure of the well control accumulator system and should not surpass the manufacturer's specified working pressure for the ram operating system.
Shear-blind combination rams integrate two ram functions into one well control component, allowing for simultaneous shearing and sealing operations These rams are designed to shear the coiled tubing (CT) body and any internal spoolable components at the maximum allowable surface pressure (MASP) of the well, without applying tensile loads to the tubing Additionally, they can isolate the wellbore without necessitating any movement of the CT, and are specifically sized to accommodate the CT in use.
The shear-blind rams must perform multiple shear and seal operations effectively The design of the cut should support subsequent through-tubing pumping and well-killing activities, while also allowing for efficient fishing operations.
4.3.5.3 Shear-blind rams shall be capable of shearing the CT when the tubing is secured within a slip or pipe-slip ram.
The closing pressure needed to shear the casing and seal the wellbore at the Maximum Allowable Surface Pressure (MASP) must be lower than the stabilized operating pressure of the well control accumulator system and should not surpass the manufacturer's rated working pressure for the ram operating system.
4.3.5.5 The shear-blind ram blade and required components shall be replaced after each CT shearing operation as soon as practically possible.
Pipe-slip combination rams integrate two ram functions into one well control component, effectively holding the coiled tubing (CT) while simultaneously isolating annulus pressure between the CT's outer diameter and the well control stack bore's inner diameter in a single operation.
The pipe-slip rams must be appropriately sized for the coiled tubing (CT) in use and equipped with CT guides to ensure proper centering within the well control stack bore They should effectively seal the annulus while supporting the maximum anticipated hanging weight of the CT, preventing any movement of the tubing within the slips Additionally, the rams must maintain a seal in the annulus while holding the CT in a pipe light condition, with the force calculated as the maximum allowable surface pressure (MASP) multiplied by the tube's cross-sectional area, again without allowing any movement of the tubing within the slips.
Pipe-slip rams should hold at least the kill pressure margin differential pressure from above the ram
NOTE For the differential pressure seal from above the ram, a bubble tight seal is not required and some percentage of leakage may be acceptable.
Additional Well Control Components
Elastomers utilized in well control equipment that come into contact with well fluids or corrosive gases must be qualified for well intervention services For a detailed review of the elastomers and materials mentioned in this document, please refer to Section 7.
The well control stack shall have a means for equalizing pressure between cavities across each pressure-sealing ram set prior to opening the rams.
All ram-type components in well control stacks must include a locking system to secure the rams in the closed position This locking mechanism must effectively maintain the rams' closure even when closing pressure is not present.
The anti-buckling guide is a crucial mechanical device positioned between the stripper assembly's top and the injector chains' bottom Its primary function is to offer lateral support for the coiled tubing (CT), significantly minimizing the risk of catastrophic buckling.
4.4.5 Spacer Spools, Adapter Spools, and Lubricators
Spacer spools, adapter spools, and lubricators are essential components used when bottomhole assemblies exceed the capacity of the well control stack or when the work environment requires additional spacing of the well control equipment These components must comply with the standards set forth in API 6A, as well as sections 4.2.5 and 4.2.7.
Spacer spools, adapter spools, and lubricators must be designed to endure the minimum applied loads, which include: a) compression loads from the weight of the injector and well control equipment, along with axial tensile loads from the coiled tubing suspended in the well; b) bending loads caused by reel back tension, dynamic motion, and wind forces; and c) loads resulting from internal pressure.
4.4.5.3 External supports (e.g guy wires, crane, support structure) shall be used to reduce the bending and transmitted loads from the equipment onto the connections
When bottomhole assemblies exceed the length that can be accommodated within the well control stack, alternative methods or processes that satisfy the barrier requirements outlined in Table 1 are permissible These alternative methods may involve the use of deployment bars, remotely-actuated connectors, and similar solutions.
Well Control Equipment for Hydrogen Sulfide Service
All well control equipment, inclusive of surface piping, manifolds, valves, and fittings exposed to hydrogen sulfide shall be in accordance with NACE MR 0175/ISO 15156.
CT String
The CT string is crucial for the well control equipment system, as it ensures pressure integrity within the wellbore Effective barriers, such as pipe rams and stripper assemblies, rely on the CT string's geometry remaining within the sealing tolerance of the equipment Comprising the CT and all tube-to-tube connections, the CT connector must provide a reliable seal to function as part of a well control barrier.
All CT and tube-to-tube connections shall be in accordance with Table 1 as integral parts of the well control equipment.
CT String Selection
Bend-cycling during the service life of a string leads to alterations in the CT material properties and tube body geometry Specifically, the yield strength of the material often diminishes due to work softening, which negatively impacts the tube's performance capability Additionally, the tube body may experience changes such as ovality, diametral growth, and wall thinning, with these geometric alterations not being uniform along the string's length.
The CT string should be selected such that the combined stresses of pressure and tension do not exceed the working limits, based on the material properties.
The use of coiled tubing (CT) leads to an oval cross-section of the tube body, particularly when subjected to bend-cycling under internal pressure, resulting in an increased diameter This ovality and diametral growth negatively impact well control by reducing the collapse pressure rating compared to a round tube, impairing the pressure seal capability of pipe rams and stripper assemblies, complicating the installation of CT connectors, diminishing the pressure integrity of flow check assemblies, affecting the performance of slip rams, and decreasing clearance between the CT, stripper bushings, and anti-buckling guides.
Closing well control rams on tubing with excessive diametral growth and/or ovality may result in significant damage to the CT.
The use of CT in service can lead to a reduction in wall thickness due to factors such as corrosion, erosion, mechanical wear, diametral growth, or permanent lengthening of the string This thinning of the tube body wall significantly impacts well control by decreasing the collapse and burst pressure ratings, diminishing the load-carrying capability, impairing the performance of slip rams, reducing the buckling resistance, and shortening the bend cycle fatigue life.
CT Collapse
The collapse of coiled tubing (CT) occurs when differential pressure causes the tube to flatten, which can happen with or without an axial tensile load While a collapsed CT within the wellbore does not release wellbore effluents into the atmosphere, its presence across the well control stack can adversely affect the functionality of pipe rams and slip rams Therefore, it is essential to develop a contingency plan for conducting well control activities in the event of a CT collapse.
A method used to predict the width of a plastically-collapsed tube is shown in Equation (1):
W COL is the predicted collapse width of coiled tube body (inches),
D is the outside diameter of coiled tube body (inches), t is the wall thickness of coiled tube body (inches).
For a given CT string OD size, the predicted collapse width increases when the wall thickness decreases See Table 2 for examples of collapse width predictions and minimum stack bore sizes.
Bend Cycle Fatigue
The CT string experiences cyclical stresses that exceed the material yield strength during regular operations These yield stresses arise from bend cycles on the service reel and over the tubing guide arch Throughout the service of a CT string, the continuous bending contributes to the accumulation of stress.
+ fatigue damage and impact the service life of the string Further, the addition of internal pressure during bend cycle events significantly reduces the service life of the CT string.
CT String Management
To manage the integrity of the CT system, the following information should be recorded and tracked:
— string design, traceability and identification;
— bend cycles and internal pressure;
— string history (repairs and maintenance);
— service history (including pumping of abrasive and/or corrosive fluids and/or exposure to H 2 S and/or CO 2 environments) and inspections.
It is recommended to use a fatigue prediction model to estimate the remaining CT bend-cycle fatigue life.
General
The downhole flow check assembly is a crucial well control component, featuring a pressure-sealing CT BHA connector and a flow check device This assembly must be utilized unless specific job design criteria indicate otherwise.
CT Bottomhole Assembly (BHA) Connectors
CT BHA connectors are essential for connecting the bottomhole assembly to the coiled tubing (CT) When functioning as a barrier component, these connectors must create a reliable pressure seal between the CT and the connector body, as well as between the connector body and its attached components Additionally, the CT BHA connector is designed to maintain this pressure seal while enduring the anticipated combined loads throughout its intended service.
Downhole Flow Check Devices
A flow check device is essential for preventing backflow in the CT, functioning as a pump-through mechanism When the flow check assembly is utilized to satisfy barrier requirements, it is important to implement a dual flow check device.
For CT installations, including CT hang-off and straddle assemblies, various flow isolation devices can be utilized instead of a flow check device to meet flow check requirements.
Table 2—Example Collapse Width Predictions and Minimum Stack Bore Size for CT
(in.) D / t Ratio Predicted Collapse Width
3.500 OD × 0.203 wall 17.2 5.003 5 1 /8 a) pump-off plugs; b) plugs (wireline deployed, pump down, etc.); c) flow actuated valves (e.g storm chokes); d) burst discs; e) pump-out back-pressure valves.
In situations where a flow check assembly is not applicable, it is essential to have a well control contingency plan in place and regularly reviewed This plan must comply with the well control barrier requirements outlined in section 4.2.4 and Table 1.
General
Elastomers and seals in well control equipment must be compatible with all expected liquids, gases, and treatment chemicals The sealing assembly and seal gland should match the pressure rating of the equipment in use It is crucial to install the recommended elastomers and seals, as degradation of their physical and mechanical properties can lead to a loss of pressure containment.
When selecting an elastomer, it is essential to consult the equipment manufacturer, as there is no one-size-fits-all compound for every operating condition Key criteria for elastomer selection should encompass rapid gas decompression, chemical compatibility, temperature performance range, extrusion resistance, abrasion and erosion resistance, and pressure rating.
NOTE The listed criteria are not exclusive and are interrelated See API 6J for additional information on testing of oilfield elastomers.
Rapid Gas Decompression (RGD)
Certain elastomers exhibit varying levels of resistance to RGD effects, with seal performance being significantly influenced by the materials and geometries used in seal assembly and gland design While there are specialized decompression-resistant materials available, certain seal geometries, such as exposed and relaxed seals on rams, remain vulnerable to RGD damage.
The decompression rate is crucial when pressure falls below 1000 psig, as seal damage typically occurs in this range Unless specified by the manufacturer, it is advisable to keep the decompression rate at or below 75 psig/min under 1000 psig Additionally, the rate of depressurization to 1000 psig should be controlled to prevent mechanical damage to the seal assembly.
NOTE Carbon dioxide (CO 2 ) can increase susceptibility to RGD damage in some materials.
Chemical Compatibility
Incompatibility between sealing elements and fluids can significantly degrade performance, causing either softening or hardening of the materials involved Solvents typically result in softening and may lead to mechanical damage, such as extrusion Additionally, elevated temperatures can enhance chemical activity, further impacting the integrity of the sealing elements.
To mitigate the harmful effects of chemical exposure on elastomers in the well control stack, several operational procedures can be implemented These include the continuous injection of inert fluids or inhibitors to displace chemically active fluids, measures to prevent the entry of such fluids into the well control stack, and the application of protective coatings.
Temperature Performance Range
Elastomers must maintain their performance across the full spectrum of operational temperatures When the temperature limits of an elastomer are surpassed, it can lead to softening, hardening, and other alterations in its physical properties Typically, changes that occur at low temperatures are reversible, whereas those at higher temperatures are often chemical and irreversible.
Temperature variations can occur due to several factors, including extreme ambient temperatures before, during, and after operations, wellbore temperatures, cooling effects from bleed down operations related to the Joule-Thomson effect, the use of heated treatment fluids, and the presence of cryogenic fluids.
To maintain elastomers within the original equipment manufacturer (OEM) temperature range, operational procedures can be implemented These procedures involve the continuous injection of cooling fluids in hot environments or heated fluids in cold environments across the well control stack rams and piping Additionally, controlling the external operating environment of the well control stack and piping is essential for optimal performance.
Extrusion Resistance
For some seal glands, the seal geometry requires mechanical support from either thermoplastic or metallic anti- extrusion devices, as per the manufacturer’s recommendations, to avoid extrusion damage.
Abrasion/Erosion Resistance
To maintain the sealing integrity of elastomers and mitigate abrasion and erosion issues, it is essential to retract the well control stack rams from the fluid flow path when not in use, choose elastomer materials suitable for the stripper's operating conditions, and account for abrasion caused by pumped fluids in elastomer-lined piping systems, particularly in high-pressure pump line hoses.
Pressure Rating
The elastomers shall be suitable for the pressure rating of the equipment component in service.
Other Considerations
If the elastomers in the well control stack have been subjected to conditions beyond their limits, such as rapid gas decompression (RGD), extreme temperatures, or harmful chemicals, it is crucial to replace the pressure-sealing components with the affected elastomers as soon as possible.
7.8.2 Fatigue Life of Well Control Stack Ram Packers
The fatigue life of elastomers is assessed according to API 16A, which outlines the operational characteristics test procedure for fatigue testing It is essential that the fatigue life of ram elastomers surpasses the expected cycle frequency during well intervention operations.
All elastomers shall be stored as per OEM recommendations.
NOTE Ultraviolet light, heat, and ozone are damaging to some types of elastomers.
Manufacturers’ marking on well control elastomers or packaging should include the following: a) manufacturer, b) durometer hardness, c) generic type of compound, d) date of manufacture (cure date), e) part number, and f) shelf life.
Elastomers can degrade while in stored equipment Stored equipment should be tested before use and elastomers replaced as necessary.
8 Choke Manifolds and Choke Lines
Purpose
The choke manifold and choke line components are essential for well intervention operations, allowing for effective control of pressure and flow from the wellbore and well control stack These components include piping, fittings, connections, valves, pressure monitoring devices, and adjustable chokes, all designed to meet API 16C standards.
Choke Line Installation
Choke lines must be installed using rigid piping, flexible lines, or articulated line assemblies, as illustrated in Figures 17 to 19 These lines are defined as the piping assembly and flow control components situated between the well control stack and the inlet of the choke body or manifold It is essential to design choke line installations to reduce erosion effectively.
Choke lines must be installed following specific guidelines to ensure safety and compliance All components should have a rated working pressure that meets or exceeds the minimum well control stack pressure rating for the operational pressure category End connections must be integral or welded, adhering to API 6A and/or API 16A standards At least one full-opening valve is required between the well control stack and the choke line, with two valves necessary for wells capable of unassisted flow; these valves should not be used for throttling For wells with unassisted flow, flanged or hubbed connections are mandatory between the well control stack and the first full-opening valve In PC-3 and PC-4 operations, at least one full-opening valve should be remotely controlled The minimum recommended size for choke lines is a nominal diameter of 2 inches, and all gauge and test port connections, including isolation valves, must be rated for the appropriate pressure service and comply with API 6A standards.
Choke Manifold Installation
The choke manifold is a crucial assembly of piping and flow control components designed to manage the flow from the choke line to various choke devices In cases where a by-pass line is included in the choke manifold, it must feature a minimum of two full-opening valves for effective operation For visual references, please refer to Figures 20 through 25, which illustrate different choke manifold assemblies.
When installing choke manifolds, it is essential to ensure that the manifold equipment can withstand the minimum well control stack pressure rating as per the operational pressure category All end connections must comply with API 6A and/or API 16A standards, with line pipe threads prohibited for PC-2 operations and above At least one full-opening valve should be placed between the choke line and each adjustable choke, and these valves must not be used for throttling flow In multi-choke manifolds, two full-opening valves are required for each choke device to facilitate repairs while maintaining flow through an alternate choke For PC-4 operations, adjustable chokes and their adjacent inboard valves should be remotely controlled, and pressure monitoring devices must be installed to track wellbore and choke pressures, adhering to API 6A standards.
Figure 17—Single Inline Choke Installation (PC-1 and PC-2)—for Returns Taken Through the Flow Cross or
Flow Tee Installed in the Well Control Stack
1 choke line valves at well control stack flow cross/flow tee
3 choke line (in accordance with API 16C)
6 flow back iron (not covered in this document) a Rated working pressure [see 8.3 a)].
Purpose
The kill line system provides an alternate means for pumping into the wellbore Kill line components shall be in accordance with API 16C.
Kill Line Installation
A kill line assembly consists of full-opening valves and a flow check device, as illustrated in Figure 26 These assemblies can be made from rigid piping, flexible lines, or articulated line assemblies It is essential to design kill line installations to reduce erosion effectively.
Kill lines must be installed following specific guidelines: all components should have a rated working pressure that meets or exceeds the minimum well control stack pressure rating for the designated operational pressure category Additionally, for all pressure categories, end connections must be either integral or welded, adhering to the standards set by API 6A and/or API 16A.
Figure 18—Single Inline Choke Installation (PC-3)—for Returns Taken Through the Flow Cross or Flow Tee
Installed in the Well Control Stack
1 choke line valves at well control stack flow cross/flow tee
3 choke line (in accordance with API 16C)
6 flow back iron (not covered in this document)
According to section 8.2 e), at least one valve must be remotely controlled For wells with unassisted flow, a minimum of two full-opening valves and a flow check device must be installed between the well control stack and the pump line, while at least one full-opening valve and a flow check device are required for other wells These full-opening valves should be positioned between the well control stack and the flow check device Additionally, all connections from the well control stack to the first full-opening valve must be flanged or hubbed for wells capable of unassisted flow The recommended minimum size for kill lines is 1 1/2 inches in nominal diameter Furthermore, all gauge and test port connections, including isolation valves, must be rated for the appropriate pressure service in accordance with API 6A Finally, overpressure protection is essential to prevent pump pressure from exceeding the maximum allowable working pressure of the kill lines.
Figure 19—Single Inline Choke Installation (PC-4)—for Returns Taken Through the Flow Cross or Flow Tee
Installed in the Well Control Stack
1 choke line valves at well control stack flow cross/flow tee
3 choke line (in accordance with API 16C)
6 flow back iron (not covered in this document)
NOTE As per 8.2 e), one valve should be remotely controlled. a Rated working pressure [see 8.3 a)].