Datasheet API Standard 53

Standard Edition Section Inquiry # Question Reply

53 4th Edition,

Nov. 2012

6.3.1.1

7.3.1.1

7.4.1.1

53-01-13 Background: When a piece of equipment is built to an API equipment

specification it complies with the specification at the time it was built. If

it is repaired or remanufactured, it may be brought up to the latest

edition of the equipment specification if possible. Therefore, in service

equipment on a rig may not comply with all of the requirements of the

latest edition of the relevant equipment specification.

API 53, Section 2 (Normative References), states For undated

references (no date included in the listing), the latest edition of the

referenced document applies. Sections 6.3.1.1, 7.3.1.1, and 7.4.1.1

state Control systems for subsea BOP stacks shall be designed,

manufactured, and installed in accordance with API 16D. API 53 also

states in various sections that you shall meet API 16D, Method A, B, or C

for precharge calculations, which is calling out a specific requirement of

API 16D.

Question: Do Sections 6.3.1.1, 7.3.1.1, and 7.4.1.1 require in-service

control systems to always be 100% in compliance with the latest API

16D, or are these sections referring only to specific requirements of 16D

like the precharge?

The intent is that compliance with the normative references applies

at the time the rig is built and/or the BOP system or components

are installed. This can also be affected by a contractual

agreement or regulatory requirements.

53 4th Edition,

Nov. 2012

6.2.3.2.2 53-09-13 Section 6.2.3.2.2 a) advises what the minimum nominal I.D. for choke

lines by pressure rating only. For pressure rated systems 10K and

above, is a 3 in. nominal I.D. choke line required for 4-inch. and 7-inch.

through-bore BOP equipment?

No; 4-inch up to, but not including 7 1/16-inch. bore equipment, is

not addressed in API 53 or API 16A.

4th Edition,

Nov. 2012

6.2.3.2.2 53-02-14 Referring to Section 6.2.3.2.2, can you please clarify further the meaning

of the size range shown and your interpretation of nominal diameter?

The intent is that the pipe ID be as close as practical to the ID of

the valves.

53 4th Edition,

Nov. 2012

6.3.5 53-12-13 Is API 53, Sections 6.3.5.4 and 6.3.5.5 saying that the pumps need to be

checked on the initial test and the subsequent tests, only on the initial

test, or only when the equipment owners PM program requires it?

Yes; the intent of 6.3.5.4 and 6.3.5.5 is to conduct the test at pre-

deployment, initial latch-up, and not-to-exceed six months. Any

other testing is at the discretion of the equipment owner or other

applicable requirements that fall outside of API 53.

API Std 53 - Blowout Prevention Equipment Systems for Drilling WellsLast update: October 17, 2014

Page 1 of 7



53 4th Edition,

Nov. 2012

6.3.11.2.5

7.3.13.2.5

7.4.8.2.5

7.3.13.2.5

53-03-13 A drilling contractor has a new rig with a subsea MUX stack and subsea

conventional stack (for weight on older wellheads). They have stated

that the drape hose are below the moonpool and that the shielding is

more for wave motion than fire rating. The moon pool conduit lines are

hard pipe.

Sections 6.3.11.2.5, 7.3.13.2.5, 7.4.8.2.5, and 7.3.13.2.5 are ambiguous

with respect to the requirement of fire retardant hoses. It is our

understanding that the requirement in 7.3.13.2.5 takes precedence and

hence the hoses should not be fire retardant.

The note in Std 53 indicates that the API requirement assumes that a fire

in the moonpool would burn out the conduit hoses and hence trigger the

deadman system if the electrical signals are also lost. For our deepwater

semis however, it is not likely that the hoses are affected by a fire in the

moonpool as the hoses are hanging below bottom box of the rig. There

is no requirement in the API of how short time the hose should sustain a

fire, and hence the design will not be a proper form of weak link design.

Can you clarify if a fire retarded hose for the conduit line and hot line will

fulfil the requirements in Std 53?

Keep in mind that API 16D is the specification for control systems;

do not confuse the requirements of API 16D with those of API 16C

(choke and kill systems). Additionally, Section 6.3.11.2.5 applies

only to surface BOPs.

The intent in API 53 is to provide a weak link between the control

system and the BOP because the fire retardant properties would

be counter to the intended purpose of the emergency system.

Since there are many vessel designs in operation it is not practical

to have a different option for each. Sections 7.3.18 and 7.3.19

require floating rigs to have an autoshear and deadman

respectively, therefore should be interpreted as: Rigid conduit and

hot line supply hoses between the control system and the BOP

shall NOT be fire retardant.

53 4th Edition,

Nov. 2012

6.3.8 53-16-14 In reference to 6.3.8 on response time and 7.6.5.1.1 on function tests, if a

system includes a high pressure shear circuit (used for emergencies)

and a regulated shear circuit, which circuit should be used to determine

if closing times are met, the high pressure shear circuit that would be

used in a well control event, or, the regulated circuit with lower

pressure?

Response times shall be met by at least one of the surface/subsea

power circuits. See 6.3.8.4, 7.3.10.4, and 7.4.6.5.4.

4th Edition,

Nov. 2012

6.5.3 53-01-14 Referring to Table 2 and Table 3 in 6.5.3, do the terms "upstream and

downstream" mean that the pressure test must be carried out in both

directions (bi-direction) on all the valves?

Section 6.5.3.2.13 requires valves that are required to seal against

flow from both directions be tested from both directions.

53 4th Edition,

Nov. 2012

6.5.3.4.1 53-05-13 We are seeking a clarification of Section 6.5.3.4.1. Our drilling rig is

skidding about every six to seven days and our operator is asking us to

only do a connection test on our BOP stack every time we nipple up to

start drilling the new well, but we wont be exceeding the 21 day

maximum required to test the BOP stack. Is this acceptable?

No; all of the items listed in 6.5.3.4.1 shall be followed to be in

compliance with API 53.

Page 2 of 7



53 4th Edition,

Nov. 2012

6.5.3.6.2 53-08-13 Background: Section 6.5.3.6.2 states analog pressure measurements

shall be made at not less than 25% and not more than 75% of the full

pressure span of the gauge. We currently have chart recorder with a

range of 30,000 psi and would like to perform pressure test of 3,000 psi,

which represent 10% of the maximum range of our chart recorder. These

tests are to perform integrity test of our operating chambers of various

equipments. Our customer refers to Section 6.5.3.6.2 regarding the

pressure test and does not want to pursue the test and require

replacement of the chart recorder.

Question: If I refer to section 6.5.3.6.3 which states electronic pressure

gauges and chart recorder or data acquisition systems shall be used

within the manufacturers specified range, am I still operating within

range?

Yes, only if the chart recorder is electronic (e.g. uses a pressure

transducer), and the test pressures are within the manufacturers

specified range, it conforms to API 53.

53 4th Edition,

Nov. 2012

7.2.2.18 53-04-14 Background: Section 7.2.2.18 states, The choke control station shall

include all instruments necessary to furnish an overview of the well

control operations. This includes the ability to monitor and control such

items as standpipe pressure, casing pressure, and monitor pump

strokes, etc.

Question: Does 7.2.2.18 require the stations where the manual chokes

will be controlled (i.e. at the choke manifold) to have the instruments

necessary for carrying out the well control operations such as the drill

pipe pressure gauge, casing pressure, and pump stroke counter?

The choke control station in this section (and 6.2.2.18 as well) is

intended to be the same as a drilling choke control console system

as defined in API 16C, Section 10.9, i.e. the function of the remote

hydraulic choke control system is to provide reliable control of the

drilling choke from one or more remote locations with the sensitivity

and resolution required to perform all well control procedures that

the choke valve is designed to provide. It is not the intent to require

pump stroke counters on a manual choke.

Page 3 of 7



53 4th Edition,

Nov. 2012

7.2.3.1.1 53-11-13 Background: Section 7.2.3.1.1 states "... flow targets or fluid cushions

shall be used at short radius bends, on block ells, and tees." Section

7.2.3.1.2 states "Short radius pipe bends (R/d < 10) shall be targeted or

have fluid cushions installed in the direction of expected flow or in both

directions if bidirectional flow is expected,..." For subsea BOP Stacks, it

is common practice to use short radius bends (or kickouts) at the riser

termination adapter and directly above the choke/kill test (or Isolation)

Valves on the LMRP. These kickouts would be connected to the

choke/kill flexible hoses or flex loops. Due to space restrictions on the

stack, these kickouts do not have a fluid cushion/target located directly

"at" the bend. Instead, the cushion/target is generally located at the end

of the choke or kill line when the flow changes direction at the

lowermost well control valves. The choke/kill pipework from the kickout

to the lowest valve is made as straight as possible for this run.

Question 1: Does a fluid cushion flange installed at the lowest well

control valve (leading into the wellbore below the lowest choke or kill

ram) meet the requirement of 7.2.3.1.1 for "shall be used at short radius

bends"?

Question 2: Is it required to have a cushion/target directly at a short

radius bend?

Question 3: Can the cushion/target be further down the choke/kill piping,

if no 90 changes in direction are made between the short radius bend

and the cushion/target (as stated in 7.2.3.1.2)?

Reply1: Yes.

Reply 2: Yes.

Reply 3: No.

Page 4 of 7



53 4th Edition,

Nov. 2012

7.2.3.2.9 53-10-13 Background: Regarding Section 7.2.3.2.9, I would like to address the

issue of the 12 inch spools between the choke and kill valve bodies and

the BOP body. The spool pieces were originally added by the

manufacturer to extend the position of the choke and kill bodies away

from the BOP. This added length prevented damage to the valves and

BOP bonnet doors during maintenance. Without the spool pieces the

doors could not be opened fully, thus adding the potential to damage the

door face during ram block installation and removal. Since the original

design of the BOP the manufacturer has manufactured an extended neck

valve body design. But, it must be noted there are problems with this

design. With the addition of a welded spool to the valve body alignment

becomes critical. If the welded extension is not square to the flange and

to the valve body, proper alignment can never be achieved. This also

adds the probability that the valves are no longer interchangeable within

the system. Example; if the lower inner and outer choke body is

prepared and fitted in place; potentially it could not be moved to a

different valve position without remanufacturing the associated choke

and kill pipework. If the valve in fact is moved to a different position and

the original pipework is utilized, it could allow the associated flanges to

be out of position and over stressed after installation. We believe the use

of the short spools is the better solution, and reduces the exposure to

leak via a ring gasket, due to possible over stress of the flange

connections, if a valve is replaced.

Question: We request an interpretation of API 53 to allow the use of

spools between the BOP and choke and kill valves.

API does not grant deviations to the requirements stated in its

standard; we can only issue interpretations in response to

questions concerning the meaning of the requirements. Your

comments have been forwarded to the task group responsible for

API 53 for consideration as a future revision to the standard.

53 4th Edition,

Nov. 2012

7.2.3.2.9 53-14-13 Is the intent of Clause 7.2.3.2.9 to prohibit a properly designed spacer

spool between the BOP outlet on the body and the failsafe valves and

spacer spools for the drill-through and all of the choke and kill lines on

the stack are spools)?

Yes; API 53 does not allow for use of spools between the BOP

outlet and the choke and kill valves.

53 4th Edition,

Nov. 2012

7.3.10 53-02-13 Background: A particular rig with casing shear rams has response time

of 51 seconds. When asked about the required closing time in API 53 for

subsea casing shear rams, I stated 45 seconds, the same as pipe

rams. Rig personnel believed that the requirements in 7.2.10 do not

apply to casing shear rams because they do not seal and thus are not

considered a BOP.

Question: Are casing shear rams required to comply with the closing

times stated in 7.3.10?

Yes; Tables 6 and 7 require the well to be secured in 90 seconds

or less. If a casing shear ram is part of that sequence then it shall

be within that same timeline to achieve a secure well.

Page 5 of 7



53 4th Edition,

Nov. 2012

7.4.16.2.2 53-04-13 Background: I have a four-ram stack (one blind shear and three pipe

rams). I have an acoustic pod that closes the blind shear rams, closes a

hang-off ram, and disconnects the LMRP. The acoustic pod is capable of

operating critical functions, just not all of them.

Section 7.4.16.2.2 states the acoustic control system should be capable

of operating critical functions, with the term critical functions being

defined in 7.4.16.1.1 as each shear ram, one pipe ram, ram locks, and

unlatching of the LMRP connector.

Question: Is the intent of 7.4.16.2 to require the acoustic pod to operate

all critical functions, specifically every shear ram?

No; this provision is implemented with a should and therefore is a

recommendation.

53 4th Edition,

Nov. 2012

7.5.6.1 53-07-13 Question: Are the blind shear ram closing times stated in Table 7 to

mean if pipe is in the BOP it must shear and seal in 45seconds, and if

drill pipe is not in the BOP, the ram must close in 45 seconds with

sufficient pressure that could have sheared the drill pipe had it been in

the BOP?

The rams shall close in 45 seconds to secure the wellbore with or

without pipe in the stack.

53 4th Edition,

Nov. 2012

7.6.8.3 53-15-13 Question 1: Referring to 7.6.8.3, do the following meet the intent of the

greatest consuming emergency sequence (excluding hydraulic

connectors) supplied by the dedicated emergency accumulators shall be

discharged?

a) Operating HP shear functions by the primary control system that are

supplied by the emergency accumulators?

b) Operating HP shear functions through an ROV flying lead supplied by

the emergency accumulators?

c) Flowing a volume of fluid by an ROV flying lead supplied by the

emergency accumulators into a measured test apparatus?

d) Conducting the greatest consuming deadman or autoshear

sequence?

Reply 1: Item a) does not meet the intent of 7.6.8.3 because it

refers to a primary control system function. Items b) through d) do

meet the intent of 7.6.8.3.

Question 2: If the greatest sequence includes a hydraulic timer, is the

hydraulic timing volume required to be included in this test?

Question 3: If the answer to Question 2 is yes, can it be simulated by

another function?

Question 4: If well hopping, does the test at initial landing only have to

be completed after connection to the first well?

Reply 2: Yes, all involved volumes shall be included.

Reply 3: Yes.

Reply 4: Yes, if the hydraulic supply system remains intact during

the hopping operation.

Page 6 of 7



53 4th Edition,

Nov. 2012

7.6.9.3.3 53-03-14 Background: Section 7.6.9.3.3 states certain equipment shall undergo a

critical inspection (internal/external visual, dimensional, NDE, etc.)

annually, or upon recovery if exceeding 1 year: e.g. shear blades, bonnet

bolts (or other bonnet/door locking devices), ram shaft button/foot,

welded hubs, ram cavities, and ram blocks. The actual dimensions shall

be verified against the manufacturers allowable tolerances.

Question 1: Was this meant to be a requirement for the listed example

equipment?

Question 2: Does API 53 specify who determines which inspection

method is used?

Reply 1: Yes; the example equipment listed shall be inspected at a

minimum.

Reply 2: Yes; Section 7.6.9.3.1 states inspections shall be

performed in accordance with the equipment owners preventive

maintenance program.

53 4th Edition,

Nov. 2012

7.6.11.7.6 53-01-12 Section 7.1.3.6 requires a subsea BOP on a non-moored (ie DP) semi to

have two shear rams. Is the expectation that both shear rams are

capable of shearing the drill pipe in use at the maximum anticipated

wellbore pressure, or does only one need to be capable of shearing in

these conditions?

The confusion arises out of the wording in 7.6.11.7.6 which states

"Consider one set of shear rams capable of shearing drill pipe and

tubing that might be across the stack at MEWSP."

If the first shear is activated it would be expected to experience the

worse conditions. The second shear or closure may not be

shearing, but just closing and sealing.

Two shearing rams must be capable of shearing the pipe and only

one is required to be capable of sealing the wellbore. It is

preferred that this be achieved on the first attempt but the BOP

system must be prepared to at least shear on the first closure and

seal on the second.

It was not the intent of the committee that the second closure be

capable of shearing the pipe and sealing the wellbore.

Page 7 of 7

Documents

Datasheet API Standard 53