1. General
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Secondary well control is the well control equipment including the diverter system, BOP stack, BOP control system, wellhead, casing, Kelly cocks, Kelly hose, drillstring safety valves, kill and choke lines, kill and choke manifold, mud gas separator and all associated pipework and valves.•
A BOP must be installed for drilling operations below the surface casing shoe on all wells penetrating hydrocarbon or aquifer formations which are capable of sustained natural flow to surface.•
In situations during drilling and well operations where the BOP stack cannot close in effectively to contain maximum expected surface pressure (for example running cables, control lines, etc), risk assessment must be carried out to determine the acceptability and reliability of contingency plans for securing the well in the event of a well control incident.•
All wireline and coiled tubing operations must be carried out through a BOP and lubricator System that must contain well pressure while the cable or tubing is moving through the wellhead.•
BOP and choke manifold must be set up for hard shut-in•
The BOP stack and wellhead used at any point during the course of the well must be of sufficient working pressure to contain the greatest anticipated surface pressure. The highest anticipated wellhead pressure for Category (A) High Risk Wells must take into account a gas column to surface, whilst for Categories (B) Medium Risk Wells and (C) Low Risk Wells reservoir fluid to surface must be used. The maximum anticipated wellhead pressure will be defined in the well programme. Consideration must also be given in all cases to pressures imposed by testing and stimulation.•
The Head of Drilling Operations and Drilling Manager must be made aware of any well control equipment which is not in full working order.•
Kick and kill drills must be held regularly until the Drilling Supervisor is satisfied that a good standard has been achieved by the rig crew.•
A well control incident report will be completed immediately following any well control incidents.2. BOP Components
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The BOP stacks must consist of an annular preventer and the number of ram-type preventers as specified later in this section. The pipe rams must be of a proper size(s) to fit the drill pipe, casing or tubing in use.•
All BOP systems must be equipped and provided with the following system components:o An accumulator system which must provide sufficient capacity to supply 1.5 times the volume of fluid necessary to close and hold closed all BOP equipment units with a minimum pressure of 200 psi above the precharge pressure without assistance from a charging system.
o Accumulator regulators supplied by rig air and without a secondary source of pneumatic supply, must be equipped with manual overrides or alternatively, other devices provided to ensure capability of hydraulic operations if rig air is lost.
o A backup to the primary accumulator charging system which must be automatic, supplied by a power source independent from the power source to the primary accumulator charging system, and possess sufficient capability to close all BOP components and hold them closed.
o At least one operable remote BOP control station in addition to the one on the drill floor. This control station must be in a readily accessible location away from the drill floor.
o A drilling spool with side outlets; if side outlets do not exist in the body of the BOP stack to provide for separate kill and choke lines.
o A choke and kill line each equipped with two full opening valves. At least one of the valves on the choke line must be remotely controlled. At least one of the valves on the kill line must be remotely controlled except that a check valve must be installed on the kill line in lieu of the remotely controlled valve provided two readily accessible manual valves are in place and the check valve is placed between the HCR valves and the pump.
o A fill-up line above the uppermost preventer.
o A choke manifold suitable for the anticipated pressures to which it may be subjected.
o Manifold and choke equipment subject to well and/or pump pressure must have a rated working pressure at least as great as the rated working pressure of the ram-type preventers.
o Valves, pipes, flexible steel hoses, and other fittings upstream of, and including, the choke manifold with pressure ratings at least as great as the rated working pressure of the ram-type preventers.
cock), essentially full-opening, and a similar valve of such design that it can be run through the BOP stack (strippable) installed at the bottom of the kelly (lower kelly cock).
o On a top-drive system equipped with a remote controlled valve, a second and lower strippable valve of a conventional kelly cock or comparable type either manually or remotely controlled.
o An Inside BOP and an essentially full-opening drill-string safety valve in the open position on the rig floor at all times while drilling operations are being conducted.
o Provision must be made to double valve all active openings from the well to the atmosphere. The valve closest to well pressure must be considered as a master valve to be used only in the event repair of the secondary valve is required.
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A Diverter must be used in shallow sections of hole to direct the flow of hydrocarbons or formation water to atmosphere where the MAASP does not permit the closing in of the well (weak casing shoe or formation).•
The diverter system (diverter sealing element, diverter lines, and control systems), must be designed, installed and maintained so as to divert gases, water, mud, and other materials away from the facilities and personnel.3. BOP’s Classification and Minimum Requirements
BOP’s systems in ADCO are classified to three classes:
1) Class (I) BOP Stack consists of
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1 Annular 5000 psi•
3 Rams 10000 psi (35% H2S Materials) 2) Class (II) BOP Stack consists of•
1 Annular 5000 psi•
3 Rams 5000 psi (35% H2S Materials) 3) Class (III) BOP Stack consists of•
1 Annular 5000 psi•
2 Rams 5000 psi (35% H2S Materials) 4) Class (IV) BOP Stack consists of•
1 Annular 5000 psi3.1 BOP Stack Minimum Requirements
BOP stack configuration may vary with the degree of risk associated with the drilling operation. Following the BOP stack minimum requirements.
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BOP shall be pressure rated to close on the maximum anticipated reservoir pressure in the event of loss of well control.•
The minimum BOP configuration for BOP stacks used on wells where a surface pressure up to and including 4500 psi is possible is :o One Annular preventer o Two Rams type preventers
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The minimum BOP configuration for BOP stacks used on wells where a surface pressure of over 4500 psi is possible is :o One Annular preventer o Three Rams type preventers
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All stacks will incorporate one set of blind or blind/shear rams.•
Shear ram must be able to shear and seal any pipe planned to be run through the BOP stack.•
Manufacturer’s certification for compliance with NACE Standard MR0175 must be available and reviewed for all well control equipment.•
For wells where H2S content is > 5%, all BOP rams must be fitted with 35% H2S elastomers.•
For wells where H2S content is < 5%, all BOP rams must be fitted with 5%H2S elastomers.
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The BOP elastomeric components that may be exposed to well fluids must be verified by the BOP manufacturer as appropriate for the drilling fluids to be used and for the anticipated temperature to which they are exposed.•
All stacks will incorporate at least one choke line and one kill line which enters the stack above the lower most set of rams.•
Kill and choke lines, installed below the lower most set of rams, will normally be used for pressure testing or monitoring the well only.•
Dual rams must be installed when running dual completion.•
The lower most ram must be preserved as a master valve and should not be used as a stripping ram.•
Dual full opening valves must be provided on each choke/kill line for all stacks. One valve on the choke line must be remotely activated.•
Ram type preventers will have ram locking devices (Mechanical) installed.•
The kill line must have double isolation from the standpipe manifold.•
The kill line must have an operated kill valve or an NRV as a means of preventing flow of wellbore fluids into the wellhead area should the kill line fail.•
Refer to Chapter-3, Section-7 for BOP stack testing procedure.4. Pressure Rating
The working pressure rating of any BOP component must exceed the anticipated surface pressure to which it may be subjected (safety factor employed as per API standards).
5. H
2S Environment
When operating in an H2S environment, the equipment must be constructed of materials with metallurgical properties that resist or prevent sulfide stress cracking (also known as hydrogen embrittelment, stress corrosion cracking, or H2S embrittelment). All BOP system components, wellhead, pressure control equipment, and related equipment exposed to H2S bearing fluids must conform to NACE Standard MR.01-75- latest edition.
Blowout preventer systems on ADCO’s rigs are rated to 5% or 35% H2S as follows:
Table 1- 4: BOP’s H2S rating on ADCO’s rigs
Rig H2S Rating (%)
NDC-1, NDC-2, NDC-8 and NDC- 10 5
NDC- 9, NDC- 16, NDC- 17, NDC- 21, NDC- 22, NDC- 11, NDC-24, NDC- 25, NDC-31, NDC-32, NDC-33 and NDC- 34
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6. Tapered Drill Pipe Operations
Prior to commencing tapered drill pipe operations, the BOP stack must be equipped with conventional and/or variable bore pipe rams installed in one or more ram cavity to provide a sealing around the larger size drill pipe and smaller size of drill pipe.