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Considering the danger of shallow steam or gas zones requires unique well control considerations. Whenever the necessary casing shoe integrity cannot be obtained due to the shallowness of the zones (before encountering pressure), a kick will need to be diverted because it cannot be shut-in. For this situation, a diverter shown in Figure 1 is a mandatory equipment to divert the undesirable flow to allow personal to have proceed the next plan; i.e., evacuation and/or dynamically kill a well.
By directing the flow from an unloading well, diverting allows physical damage to be limited to all equipment and rig personnel. With specialized procedures and equipment, the idea is to impose limited back pressure on the weak downhole formations. Although not strictly a well control procedure, diverting successfully will allow the well to be dynamically killed, to bridge over, or be depleted (without losing equipment or life).
Wherever possible, diverting needs to be avoided. In an ideal situation, if full shut-in will with a strong casing shoe should be chosen instead of a diverter. On conductor casing shoes, leak-off tests need to be performed to assess the likelihood of successfulness of shutting the well in. Any flow from the formation is likely to reach the surface in quick time since the gas is shallow and, therefore, the time available to detect the kick and then divert or shut-in is extremely small.
Purpose of Diverter System
A certain amount of protection can be provided by the diverter system before the rig can install the BOP onto the well. By design, diverter systems will direct the flow to a safe location by packing off around the drill string, Kelly, or casing. For the valves, they allow the well flow to be directed whenever the diverter has been actuated.
Diverter systems are often defined as a low pressure annular. As the name suggests, the flow cannot be stopped or shut-in with a diverter; the only goal is to direct the flow to a safe location away from the rig. To effectively remove the flow and well debris, the system must equip with a large internal diameter with sufficiently sized vent lines.
High Risk Operation
Associated with shallow gas, diverting presents serious risks. For the drilling industry, many incidents shows that shallow gas divert operations are more dangerous well control hazards than any other. Whether successful technically or not, all divert events are classified as blowouts by the US Minerals Management Service (MMS) because the very definition of a divert involves formation fluids in an uncontrolled flow. For the technical success of the diverting operation, the inherent risk needs to be managed carefully; the best management stance to risk will always be to avoid diverting at all costs.
How can diverting be prevented? Firstly, by not drilling through shallow gas. While seismic data can provide some help in avoiding shallow gas zones, drilling only where potential for shallow gas is non-existent is incredibly difficult. If drilling in this environment is entirely necessary, and the casing program cannot be designed to shut-in after kicks, not taking shallow kicks will be the only diverting avoidance technique possible.
While swabbed kicks are considered 'avoidable' kicks, hydrostatic imbalances that cause drilled kicks can be unavoidable with even the best planning. To reach technical success in these circumstances, an effective response plan needs to be in place and all elements of this plan need to be ready; this includes equipment, technique, people, and training.
For subsea and surface diverting, 'Recommended Practices for Diverter Systems Equipment and Operations' (Recommended Practice 64) is a reference document provided by the American Petroleum Institute (API). Considered the 'API RP 64', this is a useful resource for such events.
Criteria for Diverter or BOP
At the shoe, well integrity is often an issue with shallow casing strings and, in some cases, shutting in the well can cause too much pressure. Whenever a well with little/no shoe integrity is closed-in, this can cause formation fluids to broach to the surface or it can cause a shoe breakdown. When the shoe broaches, a bottom supported rig can be put into danger (along with its crew), including platform, jack-up, and land rig, but it won't considered as dangerous for a floating vessel. When inadequate casing is present and a shallow gas kick is encountered in a bottom supported rig, diverting is the best alternative to shutting in.
To allow time for remedial action and potential evacuation, and to reduce the risk of damage, the flow needs to be directed as the well begins to unload. When shallow gas potential is seen, a BOP or modified BOP system should be installed before penetrating the formation. By doing this, proven well control procedures can be used. This can only occur when formation integrity will allow for the well to be killed (through the application of back pressure and/or shutting in).
When considering a diverter system over a BOP stack, there are two main considerations;
' Diverting will be preferred when insufficient formation integrity means shut-in pressure would cause damage (when drilling below conductor). If the well were to be shut-in after a kick, the formation fluids would broach the casing shoe in this scenario.
' When drilling below drive or structural pipe, diverting will be the chosen method.
As mentioned previously, wherever possible, a shut-in will always be the preferred method.
On the vent line, diverter systems should offer a full opening hydraulic valve. This valve can be opened automatically as the diverter closes when the control system is plumbed correctly, or it will add value to the closing diverter. According to industry best practices, hydraulic ball valves are the suggested types with full bore to the vent line and outlet.
API also recommend always testing upon installation; from opposite panel, a function test can occur every 24 hours. When installed, any valves and the diverter should be actuated as well as doing so at 'appropriate times' to ensure the system is working as expected. To ensure the lines aren't plugged, fluid should also be pumped through the diverter lines during operation.
Diverting Operations and Equipment ' Installation and Equipment Requirements
Below the mud line, a short string of drive pipe or large diameter casing can normally be installed when commencing a well in the water. On land locations, at a shallow depth, casing string can be set and cemented. With the casing or drive pipe in place, it acts as a seal to support the hydrostatic head of the fluid column ' between the flow line outlet and the base of the casing. With the diverter installation occurring at the casing or drive pipe, either a low-pressure diverter is required or an annular preventer; if the latter, it requires sufficient internal bore to pass the tools used for drilling operation.
With the vent lines recommended by API RP 64, these extend between the outlets underneath the diverter and a safe space away from the well. The chosen location should allow for proper disposal of the fluid flowing from the well.
In place of proper diverters, some have previously used rotating heads or annular blowout preventers. This being said, it's now possible to acquire special low pressure diverters in various sizes. In terms of the working pressure of the vent lines and the diverter, this isn't too important because they're actually sized to minimize well bore back pressure while diverting well fluids. For land and offshore uses, many Operator Companies will recommend a minimum ID of 10' for vent lines while a diameter is 12' is recommended for floaters.
References
Cormack, D. (). An introduction to well control calculations for drilling operations. 1st ed. Texas: Springer.
Crumpton, H. (). Well Control for Completions and Interventions. 1st ed. Texas: Gulf Publishing.
Grace, R. (). Blowout and well control handbook [recurso electrónico]. 1st ed. Paises Bajos: Gulf Professional Pub.
Grace, R. and Cudd, B. (). Advanced blowout & well control. 1st ed. Houston: Gulf Publishing Company.
Watson, D., Brittenham, T. and Moore, P. (). Advanced well control. 1st ed. Richardson, Tex.: Society of Petroleum Engineers.
Cansco.com. . Diverter Packages ' Cansco Well Control. [online] Available at: <http://cansco.com/products/diverter-packages/> [Accessed 11 October ].
Bsee.gov. . Experimental Study of Erosion Resistant Materials for Use in Diverter Components. [online] Available at: <https://www.bsee.gov/sites/bsee.gov/files/tap-technical-assessment-program/008cb.pdf> [Accessed 23 October ].
Bsee.gov. . Integrity of Diverter System Under Abrasive and Multi Phase Flow. [online] Available at: <https://www.bsee.gov/sites/bsee.gov/files/tap-technical-assessment-program/008cb.pdf> [Accessed 23 October ].
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The function of a diverter system in oil and gas rigs (Check also types of drilling rigs) is to provide a low-pressure well flow control system to direct controlled or uncontrolled wellbore fluids or gas away from the immediate drilling area for the safety of personnel and equipment involved in the drilling operation. The diverter system is not designed to shut in or halt well flow.
Diverter system equipment that can be exposed to a hydrogen sulfide environment should comply with NACE MR-01-75: 'Material Requirements Sulfide Stress Cracking Resistant Metallic Materials for Oil Field Equipment', latest edition.
Where shallow casing strings or conductor casing pipes are set, fracture gradients will be low. It may be impossible to close the blowout preventer on a shallow gas kick without breaking down the formation at the casing setting depth (shoe). If a shallow gas kick is taken while drilling the top hole on the rig then the kick should be diverted through an oil and gas well control diverter system.
Drilling shallow sand too fast can result in large volumes of gas cut mud in the annulus and cause the well to flow, also fast drilling can load up the annulus increasing the Equivalent circulating density leading to lost circulation problems and if the level in the annulus drops far enough then well may flow which is considered one of the causes of kick.
When drilling the top hole a diverter should be installed and it is good practice to leave the diverter installed until 13 3/8' casing has been run.
Aramco Well Control Manual
If any of the kick warning signs are observed while drilling the top hole, close the diverter immediately as the gas will reach the surface in a very short time and it is inadvisable to attempt a flow check.
Where shallow casing strings are set, fracture gradients are often very low and wells may not be able to be safely closed in on a kick without danger of lost circulation and possible broaching to the surface. Gas from shallow sands can be abnormally pressured, increasing the possibility of lost circulation and the possibility of vertical fracturing of shallow formations allowing formation fluids to vent to the surface outside of the drilled hole.
The time needed to get formation fluids to surface from shallow formations may be less than one minute. This short amount of time leaves the driller little time to react. It is absolutely necessary that the driller know the signs of and the appropriate actions to take in the event of a shallow gas kick.
Drilling shallow sands too rapidly can cause excessive gas-cutting of the drilling fluid with cuttings gas to the extent that expansion while being pumped to the surface lowers the hydrostatic pressure enough to cause formation flow because of the lack of Bottom-Hole pressure.
Conversely, large amounts of drilled cuttings in the drilling fluid from drilling at high rates of penetration may cause the drilling fluid density to increase to a point that circulation may be lost. When lost circulation occurs the level of fluid may fall in the well, causing the hydrostatic head to drop to a point that may allow the well to flow.
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A drilling diverter system may be used in those areas with possible shallow gas sands to direct well flow away from the rig during kicks. the diverter should be arranged so that a diverter linc automatically opens or is open when the diverter is closed in order to divert the kick fluids and prevent back pressure on the hole.
Diversion is usually away from the rig, resulting in lost circulation of drilling fluid from the circulating system. Under these conditions, formation fluid flow continues during the well control operation until the hole bridges or hydrostatic pressure can be built enough to regain primary well control or until the formation is depleted.
Pumping at a fast rate tends to improve the drilling fluid/gas ratio and also creates a small increase in bottom-hole pressure due to annular friction pressure. Increasing the drilling fluid density at a fast rate increases hydrostatic pressure and may eventually stop flow. Thus, whoa a shallow gas flow occurs, the following actions should be taken immediately:
On large drilling rigs in areas with possible shallow gas, a reserve supply of drilling fluid weighted above the current mud weight may be carried in reserve for use in shallow gas kick remediation. Immediate pumping of a pre-weighted kill mud into the well by using wait and weight method, if shallow gas kick occurs, should be considered as part of a shallow-gas kick contingency plan.
If the drilling fluid supply is exhausted, a plug may be attempted. This procedure may serve to
The diverter packer regulator will provide a maximum pressure of psi on the packer.
The manifold pressure regulator provides a maximum pressure of psi.
Recommended pressure settings generally are:
A diverter system is comprised of the following components:
The annular sealing device is available in three different designs. These designs are:
Figure 1 is an example of an annular sealing device that utilizes an annular packing element as the sealing mechanism.
Figure 1 Diverter w/Annular Packing ElementThe annular packing element can affect a seal on any pipe or kelly size in the wellbore, or can affect a seal on open hole where no pipe is present. This is oftentimes referred to as 'complete shut-off' (CSO).
Figure 2 is an example of an annular sealing device that utilized an insert-type packing element as the sealing mechanism.
Figure 2 Diverter w/Insert Type Packing ElementAn insert-type packing diverter element uses a group of inserts. The inserts are placed one inside the other. Each insert in the group is designed to close and seal on different ranges of pipe diameters. A hydraulic or mechanical function serves to latch each insert in place. The correct size insert should be in place for the pipe size in use. In order to pass large bottom hole assemblies, it is necessary to remove some or all of the inserts. An insert-type packing element can not CSO.
A rotating head can be used as a drilling diverter to complement a blowout preventer system. The stripper rubber is energized by the wellbore pressure to seal the rotating head element against the drill pipe, kelly, or other pipe to facilitate diverting return wellbore media and can be used to permit pipe movement.
Vent outlet(s) for the oil and gas diverter system are located below the annular packing element. One or more vent outlets can be used in a system. Vent outlet(s) may either be incorporated in the housing of the annular sealing device or may be an integral part of a separate drilling spool/mud cross that is assembled using a flange or clamp type connection just below the annular sealing device.
Design considerations for the connection between the vent outlet(s) and the vent line(s) should include ease of installation, leak-free construction, and freedom from solids accumulation. Regarding the size of the vent outlet(s), different regulator bodies have different requirements, depending on the area of operation. For example, the requirements for drilling operations that utilize a surface wellhead configuration in areas regulated by the U.S. Minerals Management Service (reference CFR 30, Chapter II, 7-1-88 Edition, paragraph 250.59) require that no spool outlet or drilling diverter line shall have an internal diameter less than 10 inches; except in the case where dual outlets are provided, in which case the minimum internal diameter of each vent outlet is 8 inches. For drilling operations where a floating or semi-submersible type drilling vessel is used, the vent outlet internal diameter shall not be less than 12 inches. For drilling activity outside the United States, the drilling contractor is advised to become familiar with the regulations for that particular area of operation.
If a drilling spool/mud cross is utilized under the annular scaling device, the through bore diameter of the drilling spool/mud cross should be equal to the through-bore diameter of the diverter annular sealing device. The design working pressure rating of the drilling spool/mud cross should be equal to the design working pressure rating of the annular sealing device.
Valves used in a diverter vent line(s), or in the flow line to the shale shaker in a floating drilling operation, should be full-opening, have at least the same through-bore opening as the vent outlet that it is attached to, and should be capable of opening with maximum anticipated pressure across the valve sealing mechanism. Several types of full-opening valves which can be used in this application are gate valves (various types), ball valves, knife valves, switchable three-way targeted valves (see Figure K1-3F), and valves that are integral to the annular sealing device.
Any valve used in oil and gas diverter system application should be fitted with remote actuators capable of operation from the drilling rig floor. The actuators can be operated either with hydraulics or pneumatics. The actuator should be sized to open the valve with the maximum system rated working pressure across the closed valve sealing mechanism, with hydraulic or pneumatic pressure that is available from the diverter system remote control unit. The trim of the internal components of the valve actuator should be suitable for the media that is going to be used to operate the actuator. If a water-based fluid is the media, the actuator trim should be suitable for water service; corrosive. Excessive resistance due to drilled solids in the valve should be kept in mind, especially if using a pneumatic system where variations in rig air pressure are common.
Figure 3 Switchable 3-Way Target ValveFigure 4 Typical Diverter System with Control Sequenced Flow SystemFigure 5 Example of Purpose Designated Diverter with Built-In Vent ValvingFigure 6 Substructure Mounted Diverter System for Onshore and/or Bottom-Supported Offshore InstallationFigure 7 Substructure Mounted Diverter with Annular Packing ElementFigure 8 Diverter for Foater Installations with Built-In Flow Line and Vent Line Packing In oil and gas rigThere are various considerations that need to be investigated for the vent line piping in a drilling diverter system. These considerations are as follows:
The vent line piping in a diverter system should be sized to minimize back pressure on the wellbore while diverting wellbore media. The vent line should be run as straight as possible, keeping in mind that bends, tees, and elbows not only create higher back pressure than straight pipe, but are more susceptible to erosion during a diverting operation than straight piping. Just as with the vent outlet(s) discussed in the above paragraph, government regula- tory bodies have minimum requirements for the internal diameter of the vent line piping. The drilling contractor should be familiar with the requirements for the area where the drilling operation is going to take place.
Flexible lines with integral end couplings can be employed in a diverter vent line piping system. If used, the flexible lines should have the same or larger internal diameter as the vent outlet and valve, they should be resistant to fire and erosion, have end couplings that are compatible with those utilized in the hard piped section(s) of the vent line piping system, and supported adequately.
The vent line(s) used in a diverter system should be routed so that at all times one line can vent wellbore media to the downwind side of the oil and gas rig. Routing changes should be as gradual as possible. Long radius bends are preferred over short radius bends. In the ease of a 90
Diverter Types Brief Description:
NORMAL AUTO SEQUENCE:
Placing the diverter packer control valve in the close position automatically opens the pre-selected overboard valve.
NORMAL SAFETY INTERLOCK:
Hydraulic pressure to close the diverter packer is prevented until at least one overboard control valve has been shifted to open.
OPERATING FEATURES
NORMAL AUTO SEQUENCE:
Placing the diverter packer control valve in the close position automatically opens the pre-selected overboard valve and locks The insert packer.
NORMAL SAFETY INTERLOCK:
Hydraulic pressure to close the diverter packer is prevented until at least one overboard control valve has been shifted to open and the insert packer control valve has been shifted to lock.
NORMAL AUTO SEQUENCE:
Not required in the control system. NORMAL SAFETY INTERLOCK ' Not required in the control system.
NOTE: The FSP diverter is designed so that when the piston moves up to close the diverter packer closing the flow line out of the top mounted bell nipple, it clears the bottom outlet to the vent line which is blocked when the piston is down (diverter packer open). The vent line cannot be closed. There is a selector deflector to select port or starboard.
NORMAL AUTO SEQUENCE:
Placing the diverter packer control valve in the close position automatically shifts The pre-selected overboard control valve to the open position, and ensures The inflowing valves shifts to the position indicated if they are rot already in that position:
Insert PackerLockDiverter Lock DogsLockFlowline SealsPressurizedOvershot PackerPressurizedFlowline / shaker ValveCloseDrilling Trip Tank ValveClose (if applicable)Fill-Up ValveClose (if applicable)NORMAL SAFETY INTERLOCKS:
Hydraulic pressure to close the diverter packer is prevented until the following pilot signals are sensed:
TIME DELAY CIRCUITS:
The following circuits should be designed so they can be overridden after a 10 to 60 second delay:
NOTE: If overriding these functions is desired by the operator with the overboard valves closed, the diverter-test valve can be placed in the test position interrupting the auto sequence. This is normally required for low pressure testing of the diverter lines.
The normal auto sequence, safety interlocks, delay circuits and additional features described in the KFDJ diverter brief descriptions are generally applicable to the KFDS diverter controls for subsea systems. KFDS systems usually have more hydraulic functions than the KFDJ and will include a slip joint packer which may be energized by air or hydraulic pressure.
An automatic diverter system should first:-
Suggested diverting procedures in the event of a shallow gas kick (well control) on oil and gas drilling rig are as following:
The master hydraulic diverter control manifold or control panel should be located off the drill floor in an area relatively safe from gas, fire, and falling debris and should be accessible to the drilling crew for operation in an emergency. This means that the diverter control functions should be capable of remote control from the driller's location. On offshore drilling rigs, the control panel at the driller's location should as a minimum include the following features:
The driller's remote control panel should be designed in accordance with the recommendations of API RP16E.2.6 (see API RP16E.5.6). Driller panels should be suitable for installation in explosive gas environments.
Diverter control panels can frequently be incorporated with the B.O.P. control system panels to conserve space. Diverter functions should be electrically independent of the B.O.P. control functions.
The response time recommendation to sequence the diverter system and close the diverter packer within 30 seconds for diverter packers up to 20 inch nominal bore size and 45 seconds for diverter packers over 20 inch nominal bore size (Ref. API RP16E.5.1) can be met with a nitrogen back-up system or dedicated hydraulic BOP accumulators (Ref. API RP16E.5.3.2). The backup system can have manual intervention as long as it is selectable on-demand (remote control from the driller's panel) or otherwise, automatic. Automatic hydraulic backup systems sense the loss of a hydraulic pilot signal and automatically open the backup accumulator supply into the hydraulic control manifold of the diverter control system.
Automatic nitrogen backup systems likewise sense the loss of hydraulic pilot pressure and automatically inject stored nitrogen pressure into the manifold circuit for sequencing the diverter functions and closing the diverter packer.
Either system can be 'unit' mounted or 'separate skid' mounted. Hydraulic backup systems, whether the unit mounted or separate skid-mounted, must be designed with consideration of the reservoir size for the additional fluid volume of the backup accumulators.
Pump-up time for initially charging the backup system accumulators need not be considered when sizing pump systems in accordance with API RP16E.5.31. The backup accumulators will remain charged after the initial charging unless operated in an emergency according to their design intent.
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