Well intervention pdf

Article Topics. Show More Details. Defining Well Intervention Extending the life of producing wells At some point in the life of all oil and gas wells, parts will require maintenance, repair or replacement. Reference von Flatern, R. Share This. Don't have an account? Click below to get started. Sorry, you do not have access to this content Premium content requires special account permissions. Well intervention.

Khang Tran. A short summary of this paper. Download Download PDF. Translate PDF. Types of well work Pumping Main article: Pumping oil well Pumping is the simplest form of intervention as it does not involve putting hardware into the well itself. Frequently it simply involves rigging up to the kill wing valve on the Christmas tree and pumping the chemicals into the well.

Wellhead and Christmas tree maintenance Main article: Well integrity The complexity of Wellhead and Christmas tree maintenance can vary depending on the condition of the wellheads. Scheduled annual maintenance may simply involve greasing and pressure testing the valve on the hardware. Sometimes the downhole safety valve is pressure tested as well. Increasing trip gas Change in background gas composition Change in fluid properties e. PWD Abnormal temperature at flowline 4.

Formation strength can alternatively be described as injection pressure or even fracture pressure, depending on the nature of the formation, fluid, and circumstances.

It is important that formation strength is not exceeded during operations. Breakdown can be caused by excessive fluid weight, surge pressures, Equivalent Circulating Density ECD or backpressure applied at surface. The fluid weight including ECD shall not exceed fracture strength.

If sufficient offset data is not available, formation strength shall be confirmed via LOT, limit test or formation breakdown test. Local regulations may require formation strength testing at every casing shoe. Kick tolerance shall be calculated based on formation strength for every shoe. Casing is usually set with the shoe in an impermeable formation.

Consequently, the result often agrees with theoretical curves. However, remember that drilling ahead even a short distance may penetrate a natural fracture or permeable formation with much lower strength. LOTs investigate the capability of the formation below the shoe to support additional pressure to assess the kick severity that can be handled safely, and therefore allow proper selection of the next casing setting depth.

This aspect is particularly important when abnormal pressures are anticipated. In LOTs, the pressure is increased to the formation intake pressure. Limit tests also known as casing seat, shoe strength, and shoe integrity tests confirm the strength of the cement bond around the casing shoe and ensure that no communication will occur outside the casing if borehole pressures at the shoe exceed the hydrostatic head of the mud.

These tests are terminated at some predetermined pressure less than the formation intake pressure. These tests are also recommended for brittle formations that fracture with limited deformation and can suffer from considerable permanent reduction in formation intake gradient. Formation breakdown tests establish fracture initiation, propagation, and closure pressures of a formation in an attempt to gain regional knowledge of these parameters.

Formation breakdown tests are rarely if ever performed in conjunction with drilling operations except during abandonment and are normally used for well stimulation studies and not associated with well control. The pressures exerted during a limit or LOT shall never exceed the maximum burst pressure of the casing and the associated surface equipment. Formation strength test results shall be reported in the daily report. A pressure- versus-volume plot should be included as part of the reporting.

The external environment comprises surface environment above mudline in the offshore , other horizons and, in particular, groundwater aquifers. The barrier system shall be capable of being tested at installation and monitored at all times to verify its integrity.

Should one barrier be lost, then the focus of operations shall divert to regaining the two-barrier status. If the second barrier cannot be restored within 72 hours, then a deviation shall be written until it is restored or in the case that the second barrier cannot be restored. Well barriers should be independent of each other without common barrier elements. A barrier should be tested in the expected direction of flow. If testing in the direction of flow is not physically possible, the barrier shall be tested in the opposite direction.

Diverters are not shut-in devices and therefore are not considered to provide barriers in the direction of flow on top-hole sections, but only are required to divert flow. Barriers shall be identified and documented e.

Barrier plan and verification results including verification of established cement placement shall be entered into eWCAT. Barrier integrity pressure test, duration and acceptance criteria shall be defined and approved by the designated TA prior to commencing operation. A summary of testing requirements are provided in the following tables: a. Surface drilling operations in Table 14 Section 6. Subsea operations in Table 17 Section 7.

Table 22 Section 8. In case of a leak, this will facilitate removing the influx without having to strip to bottom or instigate volumetric procedures. The duration of an inflow test is influenced by the total hole volume, temperature difference of the displaced fluid and Bottom-Hole Temperature BHT , and the type of fluids.

Typically, in a High Pressure High Temperature HPHT well, this can be longer than 4 hours, especially if a cold fluid has been circulated above the barrier. An inflow test recording the flow vs. When using compressible fluids [e. Therefore, the final results of such tests shall be a combination of a successful Horner plot and a gas-free bottoms-up circulation afterwards under controlled conditions.

A Horner plot shall be used to document and report the results of the inflow test. The Horner plot results shall be filed as per record management requirements. If bottoms-up circulation has been used to prove integrity of the barrier after the inflow test period, the results shall be reported and filed together with the Horner plot results. For further details on acceptance criteria for inflow testing with fluid and procedures for inflow testing, see Appendix 6.

Inflow Testing with Hydrocarbon Gas To test barriers in wells filled with hydrocarbon gas, the inflow testing shall be done by incremental pressure reductions over time. After each fixed pressure drop, the stabilized final pressure after each fixed time period shall be measured and recorded.

If after the fixed time period, the pressure has increased or is still increasing , then a failed barrier could be the cause and further investigation is required prior to proceeding. When displacing the tubing or workstring to nitrogen, sufficient backpressure shall be applied and maintained to keep the BHP constant. The inflow test thereafter will be the same as for the inflow testing with hydrocarbon gas. All barrier elements require testing as a system prior to being considered a barrier.

For fluid hydrostatic barriers, fluid properties and level shall be monitored and maintained to be considered a barrier. Cement compressive strength unconfined and confined shall withstand the forces of pipe expansion, contraction and elongation during pressure loads. Downhole packers shall be qualified under ISO Bridge plugs shall also be qualified under ISO Mechanical Barrier Elements Examples of mechanical barrier elements include the following: 1.

Cemented, pressure-tested and inflow-tested casing 2. Cemented pressure-tested liners and inflow-tested liner lap and liner top packer 4. Tested annular side outlet valves or Valve Removal VR plugs in side outlet bore 5.

Tubing hanger seals, pressure-tested via the hanger test ports in the wellhead or against the casing 9. Casing hanger seals, pressure-tested via the hanger test ports in the wellhead Plugs and packers 4.

Examples of fluid barrier elements include the following: 1. Drilling fluid, brine or non-particulate fluid of sufficient density to overbalance any zones in the well capable of flow [in the event of losses, Lost Circulation Material LCM pill may be required to maintain hydrostatic].

Dynamic fluid column where continual fill is used to overbalance any zones in the well capable of flow a minimum fill rate shall be defined and monitored, below which the well will be shut-in.

The normal BOP arrangement is considered the second barrier in the annulus. Two workstring deployed non-return valves shall be placed in the bottom of the workstring as deep as possible.

The normal BOP arrangement is considered the second barrier for the workstring. The fluid column is typically the primary barrier. Loss of primary well control most frequently results from the following: a. Drilling into an adjacent well c. Excessive drill rate through a gas sand d. Insufficient drilling fluid density e. Lost circulation f. Failure to keep the hole full g.

Swabbing is a reduction in wellbore pressure caused by a piston-like effect of moving the workstring upwards. There are two main types of swabbing, "low volume" and "high volume", which vary in degree, indications and potential hazard. Low Volume Swabbing: Formation fluids or gases entering the wellbore as a result of a temporary BHP reduction below the formation pressure due to workstring upward movement in combination with mud friction losses in the annulus.

High Volume Swabbing: Formation fluids or gases entering the wellbore as a result of a temporary BHP reduction below the formation pressure due to pulling full gauge or balled-up tools e. High volume swabbing is therefore especially dangerous in large-diameter holes. To minimize the possibility of swabbing, the following shall be done: 1.

Circulate the hole clean and optimize mud rheology prior to POOH. Use trip tank and trip tank recorders. Apply trip margin before POOH, if possible. Assess hole conditions to determine need for short trip. Circulate bottomsup. Program tripping speed to minimize swabbing. Monitor overpulls. Avoid pumping a heavy slug before POOH when swabbing is anticipated. Pump out of hole with low pulling speeds. The circulating volume while POOH shall exceed the closed end displacement of the workstring.

When seepage partial losses are experienced and a round trip is being made, the degree of losses should be accounted for in the trip tank measurements during the round trip, otherwise, swabbing may not be detected. If low volume swabbing is assumed to have taken place and a flow check is negative, the workstring should be run back to bottom in a controlled manner with regular flow checks.

Account for dissolved hydrocarbons in OBM when circulating bottoms-up. Use trip sheets to record actual versus theoretical volume changes for each trip in and out of the hole, including workstring attachments.

Program tripping speed to minimize surging. Monitor drag. Assess hole conditions while RIH and ream down when required. Insufficient fluid density can be caused by: 1. Higher-than-anticipated PPs of the formation 2. The drilling or workover fluid becoming contaminated diluted by less dense fluids e. Gas cut mud due to high penetration rates through gas bearing formations. The well program shall identify potential loss circulation zones and shall have mitigations plans in place.

In offshore operations, lower operating margins can be expected. Care should be exercised to avoid fracturing the formation or surging; therefore, the lowest practicable overbalance should be employed to prevent fluid losses. In CWI operations, loss of fluid to the productive zone can occur during initial well control or remedial operations.

In multiple zone completion wells with considerable differences in formation pressures between separate producing zones, lost circulation can only be remedied by mechanically isolating the loss zone with a packer or cement or temporarily bridging the loss zone. Additionally, the hole shall always be kept full and monitored.

At a minimum, flow checks shall be performed on all trips out of the hole at the following locations: 1. On bottom 2. In the deepest casing shoe 3. The type of integrity test e.

Many directional wells may be drilled from the same offshore platform, onshore drilling pad or subsea template. If a drilling well penetrates the production string of an existing well, the formation fluid from the existing well may enter the wellbore of the drilling well, or the drilling fluid of the well being drilled may be lost to the penetrated wellbore.

Either of these circumstances can lead to a kick. Kick tolerance and acceptance criteria shall be defined in terms of pressure, volume and depth to determine when operations can no longer be continued safely without contingency measures.

Gas is highly soluble in OBM. The amount of gas that can go into solution is dependent on the mud and gas properties and the wellbore temperature and pressure. Shut-in pressures in combination with pit gain may not accurately reflect the true density of the influx, as a gas kick may appear to be light oil; therefore, apparent light oil kicks should be treated as gas kicks.

Unrestrained gas in solution will rapidly expand near surface. Precautions should be taken to handle the gas expansion when circulating. Gas breakout in the marine riser is particularly dangerous because the flow can only be diverted; therefore, while working with OBM in marine risers, the well shall be shut-in at any potential indication of flow increase influx.

The presence of an influx in the horizontal section, no matter how large, does not impact bottom-hole hydrostatic pressure.

Flow checks may not necessarily identify the presence of an influx. If a gas influx finds its way out of the horizontal section, it will migrate very rapidly, causing underbalance and inducing additional kick volume. Possible dispersion effect in the horizontal section will take place depending on hole and flow conditions , which may result in long circulating times to get the fluid in the well gas-free and filled with the proper fluid weight.

NOTE Rotation of pipe in a horizontal well is advised to improve the removal of gas. Different reservoir pressures may be present in each wellbore, requiring different kill-weight fluids. Potential for wellbores to flow simultaneously 3. Potential for cross-flow of well fluids during well and kill operations 4. Potential difficulties in getting kill fluid to a kicking lateral without the BHA 5.

Variable kick tolerances along wellbores and junctions 6. Long sections through the reservoir increase the potential kick intensity. The kill process is complicated due to the number of variables that could be involved.

Slim-hole wells are wells that are less than 6 in. Annular friction losses in a slim-hole well are high and can cause formations in the OH to fracture or take fluid, increasing the complexity of a well kill operation. The increased vertical height of even small influxes can significantly reduce BHP. Early kick detection systems should be considered to limit influx volume.

Increased chances of swabbing and surging. With high ECDs, it is possible to be unintentionally underbalanced. When the pumps are shutdown, the well will flow. The kill rate should account for increased ECD. The effect of annulus friction pressure during design and well operations should be accounted for. The Driller's method should be used, because the Wait and Weight method may give no advantage because of the reduced annular volume. The ECD while drilling will not be the same as that calculated for the well kill because there is no rotation factor while circulating to kill the well.

To prevent fracing the casing shoe, the kill circulating rate should be that rate which produces annulus circulating friction pressure which equals initial shut-in choke manifold pressure from slow circulating rates. If primary control is lost, the well shall be shut-in immediately, followed by secondary well control techniques aimed at removing an influx from the well, and if required increasing the fluid weight to regain primary control.

This section discusses these secondary well control techniques. The volume of influx allowed to enter the hole will directly affect the amount of additional pressure exerted on the OH, casing, BOP, and choke system. The hard shut-in method shall be the default method for operations. Any other shut- in method specified shall be used under deviation.

Pressures shall be monitored immediately and the pipe rams closed before pressure reaches the maximum operating pressure of the annular preventer. For offshore floating units, the hard shut-in method shall be followed with the workstring suspended in the motion compensators. The motion compensator, constant tension winches or tensioners should support the circulating head assembly.

There are three recognized shut-in techniques: 1. Hard shut-in 2. Soft shut-in 3. The hard shut-in closes the flowing well against a closed choke, whereas the soft shut-in in theory shuts the flowing well by gradually closing a choke. The hard shut-in is a simple, quick way to shut-in the well and thus minimize influx volume. Soft shut-in is slower than hard shut-in, thus allowing a greater volume of influx to enter the well. Fast Shut-In The fast shut-in method is similar to the hard shut-in method, except that the PRs are closed immediately instead of the annular preventer.

If well control is not jeopardized, the workstring should be kept reciprocating through the annular preventer to prevent stuck pipe. Additional criteria that shall be met for reciprocating the workstring while killing the well are: 1. BSRs are installed. Do not pull tool joint through annular preventer. Monitor the well closely for annular leakage while reciprocating the workstring, especially with marine risers.

Well teams shall be directly responsible for critically analyzing the entire operation and each well section in the planning stages to formulate a plan for secondary well control, if required.

Proper planning shall require a thorough evaluation and comparison of the possible techniques using risk analysis.

The well program shall recommend the appropriate technique that is most likely to deliver the best outcome for re- establishing primary control without compromising safety. Driller's method see Appendix 13 : Influx is removed from the hole in first circulation, and kill density fluid is introduced in the second circulation. Wait and Weight method see Appendix 14 : Kill density mud is introduced and influx is removed in one circulation; may require waiting to mix kill density mud.

Concurrent method: Circulation is started with increased mud density, but less than desired kill density; density is increased in stages. NOTE Circulating off-bottom should be considered when the influx is above the bit. The volumetric method can be used to control the expansion of an influx that is migrating during the shut-in periods of, e.

The lubrication method is used to remove influx fluids from the BOP stack or to lower surface pressures. The simplest form of this method is the static volume method, when the drillpipe is available for monitoring BHP. Bullheading is not a routine procedure in drilling, but it can mean the difference between a lost well and one that is under control and returned to normal operations. However, bullheading is the most commonly used method to kill a well prior to a well workover or intervention operation.

When kick fluids, such as H2S, are hazardous if circulated to the surface. When the drillpipe is plugged or parted so that kill mud cannot be circulated to bottom. When a kick is taken with the pipe off bottom, and it is not considered feasible to strip-back to bottom. To reduce surface pressures prior to implementing further well control operations. When a weak zone below the kick takes mud too fast for the well to be killed.

When there is a hole in the workstring. When bullheading with drilling or completion fluid, the pump rate should be fast enough to exceed the rate at which the influx migrates up the hole.

One indication of too low a pumping rate is an increase, rather than a decrease, in pump pressure. It is possible that bullheading will fracture a formation. Anytime high pressure is applied at the surface, a formation breakdown is possible at the casing shoe rather than at a point lower in the hole. Bullheading is not without risk, and caution should be exercised whenever the method is employed. In most cases, the chances of success of bullheading will be unknown until the operation is attempted and the results evaluated.

Consideration may have to be given to using a dedicated high pressure or cement pump if surface pressures are exceeding the high pressure mud system SWP.

Large fluid volumes and LCM pills should be available in case major losses are experienced during the bullheading operation. Where possible, bullheading should be carried out through an upper choke or kill line outlet on the BOPs so that in case of washout or equipment failure, a lower outlet and preventer can be used. A check valve should be installed between the pumping unit and the well. For this purpose, a Kelly cock may be used at the bottom of the drilling stand.

For critical operations such as HPHT, a drilling stand that contains a Kelly cock below each drillpipe single may be used.

When a top drive system is used on a floater, it should always be possible to pull back the workstring sufficiently high to be able to hang off the workstring in the subsea BOP stack.

Ballooning Ballooning and mitigation procedures shall be included in the well program if anticipated. However, in this context, MAASP is a straightforward concept used to calculate the maximum pressure that can be tolerated on the annulus without risk of causing formation breakdown at the shoe.

If choke manifold pressure exceeds MAASP while killing a well and the influx is still below the shoe, formation breakdown may occur.

The choke should not be opened because it will cause a drop in BHP and allow additional influx, which will ultimately increase well pressures, and therefore the chance of an underground blowout. The choke manifold pressure may fall as fluid is squeezed away. However, if it is possible to maintain the desired Pdp, sufficient BHP will be maintained and the kill should proceed.

If Pdp cannot be maintained, even with the choke fully closed, bullheading the annulus using mud with LCM should be considered. Mud and gas injected into a formation may bleed back into the well when the pressure is reduced. Kill Circulating Rate. Slow circulation rates shall be taken every tour, when exceeding ft m , after mud weight or significant mud property changes or prior to penetrating known hydrocarbon or trouble zone.

The main reason for this is to allow the choke operator to maintain control of the well at critical periods. The objective is to choose a circulating rate that brings the well control operation to the earliest conclusion. This slow killing rate should give the choke operator sufficient time to react to pressure changes.

Depending on the kick situation, the applied pump rate may be different or adjusted when gas reaches the surface to avoid overloading the MGS. These limitations are not all effective simultaneously, thus it is worth considering each phase of the kill procedure and determining the limiting rate for each phase. It should also be prudent to change the circulating rate for various stages of the kill. Advantages of higher kill circulating rates are as follows: 1.

BOP equipment under pressure for less time and a lower probability of becoming stuck. Operating the choke close to open reduces the risk of plugging the choke and forming hydrates. Choke adjustments are more controlled at the open end of the range. Small adjustments deliver small pressure changes. At the closed end of the range, small adjustments can deliver large pressure changes.

Annulus circulating friction pressure is higher, and therefore delivers a higher safety factor. High circulating rates help induce turbulence in a gas influx, which in turn causes bubble fragmentation and dispersion, resulting in lower shoe pressure and lower maximum choke manifold pressure. Traditional methods have no immediate application in circumstances such as: 1. Pipe is a considerable distance off-bottom 2. Out of the hole 3. Stuck off-bottom 4.

Plugged bit or workstring 5. Dropped, parted or sheared workstring The control of the well under such circumstances may require the use of techniques or combinations such as: 1. Volumetric 2. Stripping 3. Lubrication 4. Snubbing 5. These techniques should be practiced using rig-specific procedures.

The suitability of these techniques for a particular situation and their methods of implementation are well and rig-specific. Any rig-specific instructions should be agreed by the operating company and drilling contractor.

The decision as to whether to strip to bottom will depend on: 1. MAWHP 2. The workstring is not too light to be stripped into the well. The annular preventer seal element s condition does not provide a seal at the required stripping pressure.

Control system problems that will not allow the annular s closing pressures to be properly adjusted. The stripping procedure shall be rig-specific and available prior to commencement of stripping operations. The trip tank shall be calibrated, and a stripping tank should be installed on the rig see Figure 4 below. Mud defoamer should be available for use in the trip and stripping tank to ensure a clear interface on the mud to allow accurate gauging. The choice of whether to use a manual or hydraulic choke should be made depending on the rig and its equipment.

All gauges used shall be of adequate resolution and regularly calibrated. If well pressure exceeds 2, psi 14, kPa , it may be necessary to use the annular and ram-type preventer in sequence to pass the tool joint through the BOP preventer annular to ram stripping.

This requires an equalizing line between the annular and ram preventer. This option is very time consuming and imposes the risk of losing the sealing capability of the Pipe Ram PR. On all rigs equipped with a surface BOP stack, the annular preventer shall be used whenever possible to strip pipe in hole. Work instructions shall be in place for changing out annular elements with pipe in the hole.

On all rigs with subsea BOPs, only the annular preventer shall be used for stripping. Care should be taken to ensure that the rig heave allows the bit to move freely between the annular preventer and the BSR when entering a well under pressure. Care should also be taken to avoid buckling drillpipe in the marine riser. These should be readily available on the rig. It is recommended to lubricate oil, diesel or viscosified water on the annular BOP and to apply drillpipe dope or grease to the tool joint.

The fluids used for this purpose shall be agreed with the drilling contractor and confirmed with the BOP manufacturer for suitability. Slow tool joint stripping speeds reduce surge pressures and prolong the annular preventer service life. Upon passing the tool joint through the bag-type preventer, the stripping speed shall be reduced.

The pressure gauge on the BOP closing port should be observed when a tool joint approaches and enters the seal element. If the workstring is moved slowly enough, the pressure surge in the closing chamber during entry of a tool joint should be psi kPa or less.

The faster the tool joint enters the packer, the greater the pressure surge will be. If the pressure surge as a tool joint enters the packer is greater than psi kPa , packer wear will be excessive. The packing element of an annular preventer shall be allowed to expand slightly when a tool joint passes through.

The pressure regulator valve of the BOP control unit should be set to provide and maintain proper control pressure.

A surge bottle shall be connected to the closing line of the annular preventer to improve BOP control when stripping tool joints through the annular preventer. Such measures are sometimes known as tertiary control and may lead to partial or complete abandonment of the well. Prudent application of tertiary control techniques at an early stage may avert much more serious consequences. During secondary well control operations, tertiary well control methods should be prepared to address failure scenarios.

Tertiary control depends on the specific operating conditions encountered. Although specific recommendations regarding appropriate procedures cannot be listed, four common techniques should be noted: 1. Cement plugs 3. Reactive squeeze plug mixes 4. Standard well control equipment is defined as equipment and its controls that is flow- wetted and pressure-containing.

In such cases, a formal deviation shall be required. All rig engines onshore and offshore shall be equipped with rig saver valves. All maintenance on well control equipment shall be recorded and maintained in a register providing full traceability on the work performed and parts used.

Contractors shall have a Preventative Maintenance PM system in place for all drilling and CWI pressure-containing equipment requiring maintenance. Inspection and Certification A BOP visual inspection, body pressure test and full function test shall be carried out once a year, in accordance with the OEM specification and witnessed by a third- party verification company that meets regulatory requirements, where applicable.

The results of the inspections and tests shall be documented, including follow-up, providing full traceability and formal service history. Similar inspections shall be carried out on all other site-based well control system components e.

Finally, the third party shall verify the relevant maintenance documentation and records are complete. As per policy, well control system components shall be inspected for repair or remanufacturing at least every 5 years by the OEM or an OEM-approved service provider.

Individual components e. Operation in an H2S environment may lead to a more frequent re-certification interval, such as every 3 years based on equipment condition and local law. Copies of the certification shall be kept on-site. Threaded connections should be avoided if possible. Threaded end connections on well control equipment should have stainless steel box and pin threads to prevent SWP reduction as result of thread corrosion.

Threaded connections that do not have stainless steel pin and box threads shall be on the yearly PM scheme for thread inspection and thread gauging. Properly certified connections in accordance with the Temporary Pipe Work Standard e. Valves on side outlets of wellheads shall be flanged. Threaded connections shall be inspected regularly as part of the PM system. Threaded connections on hydraulic control hoses and hard piping in BOP control systems containing clear and non-corrosive fluid are allowed.

Threaded gauges shall be fitted with pressure load cells to separate wellbore fluids from the threads. In wells where H2S may be encountered, well control equipment suitable for sour service shall be used. In such cases, the complete HP BOP system including ring grooves, O-rings and gaskets shall be made of materials resistant to the expected concentration of H2S as defined under ISO 15 part -1, 2 and 3.

Where hard-steel SR blades are not in compliance for H2S service, the SRs should be placed in the uppermost ram cavities such that exposure during killing operations, with the PRs positioned lower, is limited.

However, shear blades integral with the ram block that are from the same and suitable H2S-resistant material as the ram blocks are acceptable. All ring gaskets installed shall be of the right type for the environment in which they are employed e. Dedicated kill lines for surface stacks shall not be smaller than 2 in.

Choke lines shall not be smaller than 3 in. The BOP shall consist of remotely controlled equipment capable of shutting-in the well with or without pipe in the hole. Control systems of surface BOPs shall be capable of closing each ram preventer in 30 seconds.

Control systems of subsea BOPs shall be capable of closing each ram preventer within 45 seconds. The closing time shall not exceed 60 seconds for annular preventers. The remote control unit s shall diagrammatically represent the stack-up arrangement.

Valves, handles and buttons not in use shall be removed or locked out. All four-way valves in operation should be in either the fully open or fully closed position as required, and should not be left in the blocked or center position.

All spare operating lines and connections not used in the system should be blanked-off with blind plugs at the hydraulic operating unit. The BOP control unit manifold pressure while operating not pressure testing shall be sufficiently high to close the PR against the SWP of the ram preventer and subsequently provide a seal.

Ram-type BOPs shall always be installed the correct way up because in most cases, the seal is pressure-assisted and will only hold pressure in one direction. A test ram shall not be considered a ram-type BOP.

Ram BOP hand wheels are not a general requirement. The locking screws should be operated each time the BOPs are tested to ensure free turning. Rams shall be locked whenever used for secondary control.

Surface wellhead side outlets shall not be used for killing purposes, except in emergencies or when not otherwise technically possible. In an emergency situation, the kill line may be connected to the side outlet of the casing spool when circulating access to the wellbore is required. However, the casing spool outlet should have the proper connection to allow changing over the permanent kill line. Valves shall be of the flush through-bore type when in the open position. Two valves shall be installed on either side of the surface wellhead on the live annulus during drilling, completion and well intervention operations.

All manually operated valves, including the valves on the surface wellhead, should be equipped with hand wheels and be ready for immediate use. When installed, all ring gaskets shall be new, checked for cleanliness and coated with light oil. All boltholes shall be used. All connections shall be pressure- tested before operations are commenced or resumed.

A calibrated torque device for making-up bolted connections should be used. When critical operations are carried out on HP wells, a second kill line should be employed and tied into the kill line near the BOP stack.

A HP pump should be lined up to this kill line. All HP lines shall be securely anchored and non-flanged connections fitted with snub lines across the connections. Stress due to connection misalignment should be avoided.