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6.1. BOP STACK SYSTEMS

6.1.1. Land Rigs, Jack-Ups And Fixed Platform

a) The pressure rating requirement for BOP equipment is based on the ‘maximum anticipated surface pressure’ as stated in the Drilling Procedures Manual’. Projects that require a different working pressure in the whole system shall be agreed upon by the Company and Drilling Contractor.

The minimum BOP stack requirements are as follows:

A 5,000psi WP stack should have at least:

• Two ram type preventers (one shear ram and one pipe ram).

• One 2,000psi annular type preventer.

A 10,000psi stack should have at least:

• Three ram type preventers (one shear ram and two pipe ram).

• One 5,000psi annular type preventer.

A 15,000psi stack should have at least:

• Four ram type preventers (one shear ram and three pipe ram)

• One 10,000psi annular type preventer.

b) While drilling, all pipe ram preventers shall always be equipped with the correct sized rams to match drill pipe being used. If a tapered drill string is being used e.g. 3¹/2” and 5”, one set of rams will be dressed to match the smaller drill pipe size.

During casing jobs or production testing, the choice of pipe rams shall be defined by the Company, depending on external diameter(s) of the casing/drilling/testing string(s) in the operation and BOP stack composition.

c) At least one ram preventer, below the shear rams, shall be equipped with fixed pipe rams to fit the upper drill pipe in use. The minimum distance between shear rams and hang-off pipe rams shall be 80cm (30”).

d) The use of variable bore rams (VBRs) is acceptable but they should not be used for hanging off pipe which is near to the lower end of their operating range.

e) Rig site repair of BOP equipment is limited to replacing of worn or damaged parts.

Under no circumstances is welding or cutting to be performed on any BOP equipment. Replacement parts should only be those supplied or recommended by the equipment manufacturer.

f) Each choke and kill line BOP outlet shall be equipped with two full bore valves, the outer valve of which will be hydraulically operated (preferably fail-safe closed).

g) The minimum diameter of the choke line will be 3" ID, while the kill line should have not less than a 2" ID. Articulated choke lines (Chiksan) are not acceptable unless derogation is agreed for a particular application.

a) A number of various arrangements in the position of the choke and kill line outlets are used in BOP stack configurations throughout the oil industry. The rig operating manual should highlight these variations, their limitations and all the potential uses of a particular layout.

b) The inclusion of shear rams requires the choke and kill lines positions to be such that the direct circulation of the kick, through the drill pipe stub after shear rams activation, can be performed with the drill string hang-off on the closed pipe rams and holding pressure.

c) On a four ram BOP stack, Eni-AGIP recommends that the positioning of choke and kill line outlets below the lowest pipe rams be avoided as these are the like the last resort

‘Master Valve’ of the BOP stack.

6.1.2. Floating Rigs

a) The minimum BOP stack requirements for floating rigs are as follows:

A 10,000 psi stack should have at least:

• Four ram type preventers (one shear ram and three pipe rams)

• One or preferably two 5,000psi annular type preventers (one annular retrievable on Lower Marine Riser Package).

A 15,000 psi stack should have at least:

• Four ram type preventers (one shear ram and three pipe rams)

• Two 10,000psi annular type preventers (one annular retrievable on the Lower Marine Riser Package).

b) The upper hydraulic connector shall have a pressure rating equal to or exceeding the working pressure of the bag type preventers.

c) The BOP stack will contain pipe rams that are able to close on every size of drill pipe/tubing that will be run through the stack.

The use of VBRs is acceptable but they should not be used for hanging off pipe which is near to the lower end of their operating range.

d) At least one ram preventer below the shear rams shall be equipped with fixed pipe rams to fit the upper drill pipe in use. The minimum distance between shear rams and hang-off pipe rams shall be 80cm (30”).

e) Each choke and kill line BOP outlet shall be equipped with two fail-safe, remotely controlled gate valves, rated to the BOP working pressure. The valves shall be fail-safe in the closed position.

f) The minimum diameter of choke/kill lines will be 3" ID. The function of each line must be interchangeable at surface to be able to line up with both the rig pumps and the choke manifold.

g) A number of various arrangements in the position of choke/kill line outlets are used in BOP stack configurations throughout the oil industry, The rig operating manual should highlight these variations, their limitation and all the potential uses of the particular layout.

a) The inclusion of shear rams requires choke and kill line positioning such that the direct circulation of the kick, through the drillpipe stub after shear rams activation, can be performed with the drill sting hang-off on closed pipe rams holding pressure.

b) Eni-Agip recommends that choke and kill line outlets are positioned above the lowest pipe rams as these are the like the last resort ‘Master Valve’ of the BOP stack.

c) For deep water operation, it is recommended to use a BOP stack equipped with an injection line to pump methanol or glycol, in order to reduce the likelihood of hydrates forming during well control operations. It is also recommended that pressure and temperature gauges are located on the BOP stack.

6.2. BOP CONTROL SYSTEM

6.2.1. Land Rigs, Jack-Ups And Fixed Platform

a) The accumulator system should be capable of closing each ram BOP within 30 secs.

The closing time should not exceed 30sec for annular preventers smaller than 18³/4” nominal bore and 45sec for annular preventers of 18³/4” and larger.

b) Hydraulic operating equipment shall have at least a 3,000psi accumulator unit equipped with two regulator valves, one to reduce the operating fluid pressure to 1,500psi and the other for further reduction of pressure for bag type preventer operations.

c) The capacity of the accumulators should be, at least, equal to the volume (V1), necessary to close and open all BOP functions installed on stack once, plus 25% of V1.

The liquid reserve remaining on accumulators should still be the minimum operating pressure of 1,200psi (200psi above the precharge pressure).

d) The control panel shall be fitted with visual and acoustic alarms for signalling of low accumulator pressure, as well as control fluid reservoir low level.

e) A minimum of two air-driven pumps and one electrically driven triplex pump is required for charging the accumulators. The combination of air and electric pumps shall be capable of charging the entire accumulator system from the precharge to full charge pressure within 15min or less.

f) In addition to the hydraulic master control panel, the BOP control system shall include at least one graphic remote control panel located on the rig floor near the Driller’s console. Offshore units shall have an additional graphic remote control panel located at a safe distance from the rig floor usually in toolpusher’s office or adjacent to the escape route from drilling unit. Each remote control panel shall be connected to the control manifold in such a way that all functions can be operated independently from each panel.

g) A safety device shall be installed on the BOP control manifold and remote panels to prevent accidental operations of BOP controls such as the closure of the rams (pipe or shear) on the drilling string while drilling or tripping.

h) The BOP end of the control hoses must be flexible and fire proofed.

i) The BOP accumulator electric-driven pump shall be connected to an emergency source of power.

6.2.2. Floating Rigs

a) The accumulator system should be capable of closing each ram BOP within 45sec and each bag type preventer in less than 60sec.

b) Two complete independent control systems (yellow pod and blue pod) are required to ensure redundant control of all stack functions.

c) The rig should be equipped preferably with an emergency and fully independent acoustic control system. This system shall be used when the rig is off location or in the event of a main control system failure. The associated subsea accumulator shall be mounted on the BOP stack, not attached to the LMRP and should have a capacity adequate for closure: one ram type preventer, shear rams, and for releasing the LMRP connector.

d) Hydraulic operating equipment shall have at least a 3,000psi accumulator unit complete with a soluble oil/water reservoir and equipped with two regulator valves, one to reduce the operating fluid pressure to 1,500 psi and the other one for further reduction of pressure for bag type preventer operations.

e) Accumulator capacity should be, at least, equal to the volume necessary to close, open and close (with charging pumps inactive) all ram type preventers and one bag type preventer with a resulting system pressure of 200psi above the precharge pressure.

The fluid volume needed to meet this requirement is the theoretical volume to close, open and close the preventers increased by a 25% factor to compensate for fluid lost to function the SPM valves. When a portion of accumulator volume is located on the BOP stack, the additional precharge pressure required to offset the hydrostatic head of the seawater should be considered.

f) The control panel shall be fitted with visual and acoustic alarms for low signalling accumulator pressure, as well as control fluid reservoir low level.

g) A minimum of two air-driven pumps and one electrically driven triplex pump is required for charging the accumulators. The combination of air and electric pumps shall be capable of charging the entire accumulator system from the precharge to full charge pressure in 15min or less.

h) In addition to the hydraulic master control panel, the BOP control system shall include at least two graphic remote control panels. One panel shall be located on the rig floor near the Driller’s console, the other panel shall be located at a safe distance from the rig floor usually in toolpusher’s office or adjacent to the escape route from drilling unit. Each remote control panel shall be connected to the control manifold in such a way that all functions can be operated independently from each panel.

i) A safety device shall be installed on the BOP control manifold and remote panels to prevent accidental operations of BOP controls such as the closure of the rams (pipe or shear) on the drilling string while drilling or tripping.

j) The BOP accumulator electric-driven pump shall be connected on the emergency source of power.

6.3. CHOKE MANIFOLD

a) All choke, kill lines and choke manifold components which may be exposed to well pressure shall have a working pressure rating equal to or greater than that of the preventers in use.

b) The minimum recommended size for all choke lines and valves is 3” (76.2mm). All valves shall be of full-opening gate valve types.

c) Choke manifold shall be equipped with at least four flow lines.

• One line shall be capable of bringing the well return directly to the buffer manifold and shall be equipped with two gate valves.

• At least three lines shall be equipped with adjustable chokes, two gate valves upstream and an erosion nipple immediately downstream. At least one choke shall be remote hydraulically operated.

d) A graphic scheme of the choke manifold shall be posted on the rig floor.

e) The buffer shall be capable of diverting well returns to the mud gas separator, the shale shaker, the burner booms or the flare line.

f) A choke manifold of different design from that already installed on the drilling unit, may be acceptable but only if approved by the Company Drilling Manager.

6.4. INSIDE PIPE SHUT-OFF DEVICES

a) The Kelly or Top Drive, shall be equipped with an upper and a lower kelly cock in functioning condition. The kelly cock’s WP shall be equal to or greater than the rating of the preventer stack in use. The upper kelly cock of the top drive shall be hydraulically operated.

b) A spare full opening safety valve (lower kelly cock) that is compatible with drill pipe in use shall be stationed on the rig floor at all times, in the open position and complete with removable handles for ease stabbing.

c) Crossover for connecting the full opening safety valve to the drill collars or tubing in use shall be also stationed on the rig floor.

d) A Gray type inside BOP, with the appropriate connections for the drill string in use, shall be stationed on the rig floor at all times.

e) One drop-in type back pressure valve, complete with seating subs to fit the drill string in use, shall be available. The wireline retrievable is the preferred type.

f) Any type of string tools installed above this sub shall have an ID greater than drop-in valve OD.

g) A set of float valves, one for each size of drill collar, and one for drill pipes in use, shall be kept available.

6.5. MUD GAS SEPARATOR

a) A suitable atmospheric mud gas separator, arranged with the inlet line from choke manifold and the outlet line (discharging released gas) connected to a flare return, must be provided.

b) The mud gas separator design shall be based on the liquid seal system matched to one or more gas outlets (vent lines) leading a safe distance downwind from the well and/or to the top of the derrick. The liquid seal ensures that separated gas vents safely without breaking through to the mud tanks. The mud seal may be obtained by means of an external U-tube or may be based on a dip tube extending into the trip tank.

c) The mud seal should be at least 10ft (3m.) high.

d) Vent line should not be less than 6” nominal pipe diameter. For vent lines exceeding the length of 130ft (40m.), the diameter of the vent line should be not less than 8” to ensure that the back pressure in the vent line does not exceed the hydrostatic mud seal.

6.6. DIVERTER EQUIPMENT

a) Whenever possible, there must be at least two discharge lines always ending laterally in opposite points of the rig to enable the possibility of blowing to the leeward side.

b) Diverter outlets and lines shall have a minimum internal diameter of 12” for offshore rigs and 10” for land rigs. Welded flanges or clamped connections are mandatory.

c) Diverter lines shall maintain a uniform diameter throughout, and should be as straight as possible to reduce erosion and back pressure (90° or greater bends are to be avoided). Diverter lines should be securely anchored, especially at bends and at the end of the lines.

d) Diverter valves shall be full opening valves, preferably ball valves, and pneumatically or hydraulically actuated. The use of butterfly valves is forbidden.

e) The automated system shall be set, to allow for the immediately automatic opening of the discharge lines, followed by closure of the shale shaker line and before closing the diverter packing.

f) In the panel, bright indicators must show the working pressure of the accumulators and the actual pressure of the various functions. A regulator must permit changes from, the minimum to the maximum closing pressure of the diverter seal.

g) Each diverter system should incorporate a kill line (including a valve) to be able to pump water through the diverter system. Pumping water or mud through this line is important to reduce the risk of explosion or fire during a blow out. This line is also needed to fill up the hole, at all times, so that it can be kept full in the event of losses to the formation.

h) It should be possible to control pumping operations at the pumps as well as on the drill floor.

i) The control system of diverter should be capable of closing any diverter smaller than 20” within 30sec, and any diverter/annular of 20” or larger within 45sec. Diverter valves should be opened before the diverter element is completely closed.

j) The diverter control system should be capable of operating the diverter system from two locations, one to be situated near the drillers position. All control functions must be clearly labelled for identification.

k) When both the diverter system and BOP stack are employed as on floating rigs, control/accumulator systems of diverter and BOP stack shall be separate units and fully independent.

l) The control panel of the diverter assembly must be able to operate the diverter packing,

the discharge valves, the shale shaker valve (if installed) both simultaneously and/or separately.

m) The telescopic joint should incorporate double seals to improve sealing capability.

6.7. AUXILIARY EQUIPMENT

a) The trip tank system shall include centrifuge pumps, fill up the line, recirculating circuit and a mechanical mud level device equipped with reading indicator easily visible to the Driller. The minimum capacity of the trip tank should be 5m³ (30bbls).

b) A mud pit level volume indicator shall be installed on each tank of the active mud system. A continuous recording pit level indicator and totaliser, with audible alarm is required to monitor the volume of all active pits.

c) A mud return indicator with an audible alarm shall be installed on the flow line.

d) Each mud pump shall be equipped with stroke counters.

e) The rig shall be equipped with an adequate degasser, to condition gas-cut mud, installed on the mud active system.

f) The 5” OD standpipe manifold lines, connections, valves, and lines from the mud pump to the standpipe manifold shall have 5,000psi minimum WP with welded connections No thread connections are allowed except for 2" size and below.

g) The standpipe manifold shall be equipped with a connection which can be fully isolated to fit a 10,000psi cementing line and fully isolated.

h) Two 5" OD x 19mm wall thick stand-pipes and 3¹/2" ID x 5,000psi WP rotary hoses, with welded connections are required.

i) The rated working pressure of the cementing lines shall be the same as the BOP which will not be less than 10,000psi. A cementing line should be connected to the kill lines.

j) The burner booms/flare will be connected to the choke manifold. They will be tied in according to the safety regulations in force for the operating zone.

k) An air-operated, skid mounted, high pressure, low-volume testing unit, is required for hydraulic testing of the BOP and manifolds.