API Std 53 - Blowout Prevention Equipment Systems …...Standard Edition Section Inquiry # Question...

Standard Edition Section Inquiry # Question Reply

The cost of NDE/NDT inspection of some fasteners outweigh the cost to replace with

new. Since this is the case, many equipment owners and OEMs elect to replace many

types of fasteners based on visual inspection or time in service instead of paying to

inspect them. In the majority of cases, the OEM does not describe acceptance criteria

for used fasteners.

Does it meet the intent of 4.3.6 if the type of bolt NDE identified by an equipment

owner’s PM program is visual and bolts are replaced based on visual appearance,

torque checks and/or time in service?

Yes.

Question 1: In reference to API Standard 53 requirement 4.4.3, are pressure-

energized ring gaskets required for Surface BOP Choke Manifolds?

Reply 1: Yes.

It has been noted that there are requirements within the standard

(4.4.3 & 6.2.2.2) that are not requirements within the equipment

design specifications.

Question 2: Is API 6A, 16A and 16C considering change to the design requirements

based on the exclusion of non-pressure energized ring gaskets in API Standard 53

4.4.3?

Reply 2: This question falls outside the scope of S53 and does not

meet the requirements for submitting a technical inquiry. You may

consider submitting your question directly to each of the task groups

for the documents you reference in the question.

534th Edition,

Nov. 2012Section 6 53-15-17

Is the scope of API Standard 53, Section 6 meant to cover BOPs which are associated

with Snubbing Units and Hydraulic Workover Units, in addition to those which are

located on Drilling Rigs?

No, the scope of 53 includes BOP systems on land and marine

drilling rigs, but the definition of BOP (3.1.9) excludes

workover/intervention control packages and snubbing packages.

534th Edition,

Nov. 20126.1.2.12 53-03-15

Referring to Section 6.1.2.12, can a surface BOP stack arrangement with one annular,

one blind shear ram, and two pipe rams, with the fifth device being optional, be

considered a Class 5 stack arrangement?

No; a Class 5 surface BOP stack arrangement must contain five

devices at a minimum. The stack must contain one annular, one blind

shear ram, two pipe rams, and the fifth device can be an annular or

pipe ram.

534th Edition,

Nov. 20126.2 53-05-15

With regards to API STD 53, I am seeking further clarification as to whether a by-pass

line is required on a surface BOP choke and kill manifold. Section 6.2 which refers to

the general scope of a choke and kill does not mention a by-pass line. The sizing is

mentioned in considerations and the by-pass lines are also indicated on the

examples.

But I interpret examples and considerations as not mandatory. Is this correct? Yes, the bleed line (line that by-passes the chokes) is optional.

534th Edition,

Nov. 20126.2 53-06-15

Is this bleed line (that bypasses the chokes) a mandatory line to have on a surface

choke and kill manifold???No, the bleed line (line that by-passes the chokes) is optional.

534th Edition,

Nov. 20126.2 53-07-15 Can you please advise if a by-pass line is require on surface choke and kill manifolds. No, the bleed line (line that by-passes the chokes) is optional.

53-10-174th Edition,

Nov. 20124.3.6

4th Edition,

Nov. 20124.4.3 53-01-16

API Std 53 - Blowout Prevention Equipment Systems for Drilling Wells

53

53

Last update: August 12, 2015

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API Std 53 - Blowout Prevention Equipment Systems for Drilling WellsLast update: August 12, 2015

Minimum nominal inside diameter (ID) for lines downstream of the chokes shall be

equal to or greater than the nominal connection size of the choke inlet and outlet.

Question 1: The way this is written; it is conceivable that you could have a 4-1/16”

line entering the choke & kill manifold; reducing to 3-1/16” at choke bore inlet and

then maintain 3-1/16” downstream of chokes.

Do you concur?

Reply 1: Yes

Question 2: Why is it API concern if an operator wants to have a 2-1/16” outlet after

the buffer tank to go to strip tank, etc?

Reply 2: Unfortunately, the question you have asked is not in a

format that is acceptable for developing a response. Specifically,

API only addresses questions phrased in the form such that the

answer is “yes” or “no”. Please review the guidance for submitting

questions to API at:

http://mycommittees.api.org/standards/techinterp/transpipe/default.a

spx

534th Edition,

Nov. 20126.2.2.4 53-11-16

Regarding para 6.2.2.4 This paragraph states “Minimum nominal inside diameter (ID)

for lines downstream of the chokes shall be equal to or greater than the nominal

connection size of the choke inlet and outlet.” This paragraph does not state how far

downstream the piping needs to comply with this.

The lines downstream of the chokes utilized to flow well fluids during

well control operations shall maintain the minimum nominal ID until

it enters the next system (mud gas separator, overboard line, etc.).

Question 1: Regarding the choke on a choke manifold, some rig contractors give the

ID as the effective flow area of the choke trim. Does the “nominal connection size of

the choke inlet and outlet” in 6.2.2.4 actually refer to the ID of the flanges on the inlet

and outlet of the choke body and not that of the choke trim?

Answer 1: Yes. NOTE: This requirement was not intended to restrict

using a 3” line with a 3 1/16” connection. This will be clarified in the

next edition of the Standard.

Question 2: 6.2.2.4: Does the “minimum nominal inside diameter for lines downstream

of the choke” refer to the components on the choke manifold (valves, spool pipe, etc)

as opposed to the lines downstream of the choke manifold? If the answer to this

question is “No”, then it is unclear whether there are any requirements regarding the

ID of the choke manifold components.

Answer 2: Yes, 6.2.2.4 refers to lines downstream of the choke within

the choke manifold.

Question 3: 6.2.3.2.2 (a): Does the “minimum size for choke lines” refer to the lines

upstream and downstream of the choke manifold?

Answer 3: No, 6.2.3.2.2 specifically covers the ‘choke line’

requirements, which are upstream of the choke manifold.

Question 4: 6.2.3.2.2 (a): Does the “minimum size for choke lines” refer to the ID of

the line?

Answer 4: Yes. NOTE: This requirement was not intended to restrict

using a 3” line with a 3 1/16” connection. This will be clarified in the

next edition of the Standard.

534th Edition,

Nov. 20126.2.2.4 53-02-16

534th Edition,

Nov. 20126.2.2.4 53-03-18

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Internal discussions have been held in regards to the intent of the statement "direct

the flow path and to isolate a failure or malfunction of the buffer tank" with 2 different

interpretations of the requirement: 1) This demands that it be a 'split buffer tank' to

isolate and redirect the flow, or 2) The flow path can be redirected via an overboard,

line into the MGS, split buffer tank, etc. It is not limited to just the split buffer tank

option.

Is the requirement a line that redirects to overboard, or the MGS (as examples)

meeting the intent of the requirement, and not just requiring a split buffer chamber? Yes. There is no requirement for a split buffer tank.

Background: A drilling contractor has a well control system with BOPs, choke and

kill manifolds rated at 10,000 psi. The equipment is being used on a 5000 psi well

head. The choke manifold has one remote operated drilling choke.

Question 1: Referencing 6.2.2.8 and 6.2.2.9, is it correct that the equipment is

technically de rated to 5000 psi for the wellhead?

Reply 1: API 53 does not address de-rating. For the specific well

mentioned in this question, the equipment can only be tested to 5000

psi (see 6.5.3.2.6).

Question 2: Is only one remote operated choke is required? Reply 2: Yes

534th Edition,

Nov. 2012Figure 3 53-16-17

10K WP choke manifold with two remote chokes and one manual choke. Section

6.2.2 outlines the requirements for a Surface BOP choke manifold. It doesn't mention

in that section that two valves are required up stream of a remote or manual choke.

Yet figure 3 shows an example 10K WP choke and it has 2 valves up stream of the

remote operated or adjustable choke

Does this mean it is a requirement to have two valves up stream of a remote operated

or adjustable choke? Or is it just a recommendation?

Yes, two valves are required on the outlet of the BOP or drilling

spool, upstream of the remotely operated chokes per 6.2.2.7.

NOTE: Figure 3 is an example choke manifold and may include items

that are not requirements of the document.

As per Clause 6.2.1.3 a manifold shall have two adjustable chokes. As per clause

6.2.2.9 a minimum of two remotely operated chokes shall be installed on 10K or

greater pressured choke manifold. which leads to think there should four chokes two

manually adjustable & two remotely adjustable. Where as in figure 3, it shows two

chokes only and it is optional for each choke could be adjustable or remotely

operated. If I go along with figure 3 and pick both chokes adjustable then it

contradicts the clause 6.2.2.9.

Question 1. Adjustable choke could be adjusted remotely or manually, is this true?

Answer 1: Yes.

534th Edition,

Nov. 20126.2.2.5 53-02-17

534th Edition,

Nov. 2012

6.2.2.8

6.2.2.953-14-14

534th Edition,

Nov. 2012

Figure 3

6.2.1.3

6.2.2.9

53-17-17

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Question 2. 10K and above manifold can have total two remotely operated chokes

only and do not need two more manually adjustable chokes per clause 6.2.2.9, is this

true?

Answer 2: Yes.

Question 3. Can I overlook figure 3 in configuring choke manifold layout based on

customer requirements? Answer 3: Yes, Figure 3 is an example.

534th Edition,

Nov. 20126.2.3 53-12-14

Referencing 6.2.3, there are some cases where we can't have a straight exit lines after

buffer chamber at choke manifold because of the position or space to flare pits on the

rig's location. Following the recommendations that we have for choke and kill bends,

can we use that for the choke manifold exit lines before buffer chamber?

See 6.4.11 for vent line recommendations.

534th Edition,

Nov. 20126.2.3.2.2 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.

534th 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.

534th Edition,

Nov. 20126.2.3.2.2 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.

534th Edition,

Nov. 2012

Figure 3

6.2.1.3

6.2.2.9

53-17-17

This intepretation has been rendered invalid as a result of publication of API S53, 4th Edition, Addendum 1 in July 2016. Therefore this interpretation

has been withdrawn as a result of these updated requirements.

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534th Edition,

Nov. 20126.2.3.2.2.b 53-08-16

Section 7.2.2.11 states "The bleed line (if installed, the line that bypasses the chokes)

shall be..." Section 6.2.3.2.2.b states "The bleed line (the line that bypasses the

chokes) shall be...". It does not contain the "if installed" language, but it is sub-

headed under 6.2.3.2 Other Considerations for Choke Lines.

Is a bleed line to bypass the choke lines REQUIRED on choke manifold assemblies on

surface BOP installations?

No, the bleed line (line that by-passes the chokes) is optional

(reference previous interpretations 53-05-15, 53-06-15 and 53-07-15).

534th Edition,

Nov. 20126.3.5 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 owner’s 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.

534th Edition,

Nov. 20126.3.6.1 53-28-16

Clarification on the wording for "rig substructure" in 6.3.6.1 and 7.3.5.14.

Please provide clarification in regards to the meaning of "rig substructure" when

talking about where to put the hydraulic control unit.

The intent was that it is placed outside of the drill floor. Reference

3.1.25

drill floor substructure

The foundation structure(s) on which the derrick, rotary table,

drawworks, and other drilling equipment are supported.

534th 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 BOP’s.

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”.


has been withdrawn as a result of these updated requirements and replaced with the following interpretation.

of 27



534th 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?

Section 6.3.11.2.5 applies only to surface BOP’s.

API 53 is making the fire retardant requirement of API 16D not

required for the control lines and hot line supply between the control

system and BOP. The intent 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.

534th Edition,

Nov. 20126.3.8 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.

534th Edition,

Nov. 20126.3.8 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

fluid supplies. See 6.3.8.4, 7.3.10.4, and 7.4.6.5.4.

On page 33 of the standard under 6.5.2.2.1 is stated "Inspection practices and

procedures vary and are outside the scope of this document."

Question 1: Does API have a document that states the frequency of inspections

performed?

Reply 1: Yes, API Standard 53 discusses frequency of inspections,

but not the practices and procedures. For surface BOP systems see

Section 6.5.7.53

4th Edition,

Nov. 20126.5.2.2.1 53-03-16


has been superceded as a result of these updated requirements and

of 27



Question 2: Or a document that goes in depth as to what level of service is required

for Onshore BOPs?Reply 2: No.

534th Edition,

Nov. 20126.5.3 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.

534th Edition,

Nov. 20126.5.3.2 53-14-16

BOPE should be pressure tested with low pressure and then high pressure. API 53

doesn't clarify if it low pressure must be bled off before we conduct high pressure

test.

Can we, without bleeding off low pressure, increase the pressure from 200 psi to high

pressure value and conduct the test in this way?

Yes, it is allowable to increase to the high pressure test immediately

following the low pressure test (250 psi to 350 psi) without bleeding

the test pressure off.

All blow out prevention components than can be exposed to well pressure shall be

tested first to a low pressure between 250psi to 350 psi and then to a high pressure.

Question 1: Should the high pressure test be conducted immediately after the low

pressure test?

Reply 1: Yes, it should be tested in a reasonable time frame

following a successful low pressure test.

Question 2: Can the pressure be bled off to zero after the low pressure test before

proceeding to the high pressure test?

Reply 2: Yes, provided the component being tested is not cycled

after the low pressure test.

534th Edition,

Nov. 20126.5.3.4 53-07-16

Do the ram preventers and Annular preventer require Pressure Testing each time

before the equipment is put into operational service on the wellhead if it has not

exceeded intervals of 21 days.

Yes.

534th Edition,

Nov. 20126.5.3.4.1 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 won’t 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.

534th Edition,

Nov. 20126.5.3.4.1 53-05-16

If a lease/pad contained 5 wells ready for a completion rig to conduct work, would it

be a requirement to perform a full BOP test on each Well (Broken connections,

Hardlines, Pipe Rams, Blind Rams, Annular) upon installation of the BOP to each

Wellhead, if the previous BOP test was still within 21 days.

Yes.

53 53-03-174th Edition,

Nov. 20126.5.3.2

534th Edition,

Nov. 20126.5.2.2.1 53-03-16

of 27



534th Edition,

Nov. 20126.5.3.4.1 53-06-16

The operator has asked for reduction in Pressure Testing Operations. Section 3.1.59 -

The periodic application of pressure to a piece of equipment or a system to verify the

pressure containment capability for the equipment of system.

Does this mean all ram preventers and Annular preventer must be pressure tested

every time the BOP is installed on a wellhead?

Yes, 6.5.3.4.1 provides the frequency for pressure testing.

Question 1: Do we need a gage with our digital recorder (12” circular) for testing

purposes?

Reply 1: Yes, this gauge may be analog or digital. If a data

acquisition system is utilized, a gauge would not be required

(6.5.3.6.1).

Question 2: Or do need just the digital recorder? Reply 2: No.

Question 3: If the answer to Question 1 is “yes”, do we need to calibrate both of

them?Reply 3: Yes.

534th Edition,

Nov. 20126.5.3.6.2 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 equipment’s. 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 manufacturer’s

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 manufacturer’s

specified range, it conforms to API 53.

For some annular BOPs, the OEM recommended working pressure for the packing

element varies according to the pipe/mandrel size. For example, an 18 3/4" annular

BOP with a 10K RWP, may have an element with a working pressure of 10K on 6 5/8"

pipe, 7.5K on a 5 1/2" pipe, and 5K on a 5" pipe. With the annular having a RWP of

10K, 70% of RWP is 7K. This could be used for the 6 5/8" pipe and the 5 1/2" pipe, but,

cannot be used on 5" pipe that has a maximum working pressure of 5K.

Question 1: If an annular BOP has a RWP of 10K and has a packing element with a

working pressure of 7500 psi for 5 1/2" pipe is being tested prior to drilling a hole

section using a 5 1/2" pipe, should it be pressure tested to 7000 psi (70% of 10K)?

Reply 1: With the configuration of the annular element and pipe

installed, the annular should be tested to a minumum of 70% of 7,500

psi (5,250 psi) or MAWHP for the hole section.

534th Edition,

Nov. 2012

Table 3

Table 1053-01-17

534th Edition,

Nov. 20126.5.3.6 53-19-16

of 27



Question 2: If the same annular BOP has the same element with a 5000 psi rating on

5" pipe, should it be tested at 5000 psi on a 5" pipe?

Reply 2: With the configuration of the annular element and pipe

installed, the annular should be tested to a minumum of 70% of 5,000

psi (3,500 psi) or MAWHP for the hole section.

534th Edition,

Nov. 20126.5.3.8.8 53-16-16

Question: At what frequency shall the electrical power to the UPS and the rig air be

isolated:

• Each function test?

• Or prior to operations?

A frequency for this test is not defined. This will be clarified in the

next edition of Standard 53.

534th Edition,

Nov. 20126.5.4 53-02-15

In reference to API Standard 53 requirements in 6.5.4.3 and 6.5.4.5, is the smallest OD

pipe to include tubulars that are considered part of the bottom hole assembly?No; see 6.1.2.2 a).

Question 1. Is this section implying that the subsequent testing is required only at

each casing point or in accordance with the equipment owners PM? or

Answer 1: No, this requirement is only specifying when to conduct a

choke drill.

Question 2. Does this section imply that the choke drill is to be performed at every

BOP test after the initial test?

Answer 2: The choke drill shall be performed:

1. at initial BOP installation, subsequent BOP testing and at each

casing point

or

2. in accordance with equipment owner's PM program

534th Edition,

Nov. 2012

6.5.8.2.6

7.6.9.5.653-23-16

After the initial pressure test is completed, all bolts shall then be rechecked for proper

torque.

Request clarification on all bolts. Currently, common practice is to re-check torque

only on the disassembled component(s) after the initial pressure test. Torque is not re-

checked on components that were not disassembled.

7.6.9.5.6 and 6.5.8.2.6 were intended to be completed on newly made

up connections.

This section refers to assemblies.

Question 1: Are the requirements intended for individual parts as well?

Reply 1: This section provides requirements for assemblies.

Question 2: If yes, that makes sense.

If it only means assemblies, that leads to two follow up questions.

a) what constitutes an assembly?

(ie: if I sell you a ram block by itself that’s a part, but If I ship it with the seals installed

is that an assembly??)

Reply 2a: Assemblies are defined by the equipment manufacturer.

b) What requirements exist around single replacement parts? I don’t see them

mentioned separately elsewhere. Reply 2b: See 6.1.4.4 and 7.1.4.4.

534th Edition,

Nov. 2012

Table 3

Table 1053-01-17

534th Edition,

Nov. 20126.5.8.3 53-13-16

534th Edition,

Nov. 20126.5.5.4 53-18-17

of 27



534th Edition,

Nov. 20127.1.4.4 53-13-17

API has flange specifications that allow end connections from different manufactures

to be bolted together. The loose equipment that makes up an API flanged connection

then may be supplied by either manufacture or neither in some cases ( studs, nuts,

and gaskets). Note that 6A 3rd Ed 7.5.2 does not require the manufacturers to retain

records for studs, nuts, or gaskets.

Excluding well head end connections, if an equipment owner purchases and installs

monogrammed API gaskets, and studs and nuts stamped and manufactured in

accordance with 6A and 20E requirements for the API flange size ( i.2 B7/L7 and 2H +

20E requirements) from an API licensed manufacturer different than the equipment or

flange manufacturer, will the owner be in compliance with this section?

Yes, use of equipment from an API licensed manufacturer is not

mandatory for conformance to the standard.

534th Edition,

Nov. 20127.2.2.18 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.

of 27



534th Edition,

Nov. 20127.2.3.1.1 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.

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"?

Reply1: Yes.

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

Reply 2: No, but if R/D<10, the equipment owner’s PM program shall

include an inspection for erosion at the pipe bends at least every two

years.

534th Edition,

Nov. 20127.2.3.1.1 53-11-13


has been withdrawn as a result of these updated requirements and replaced with the following interpretation.

of 27



534th Edition,

Nov. 20127.2.3.1.1 53-11-14

Is it acceptable to use a special 90 degree elbow with a thickness more than 10 mm

greater than the straight pipe instead of target block? No; the standard does not currently allow this alternative.

534th Edition,

Nov. 20127.2.3.1.1 53-11-14

Is it acceptable to use a special 90 degree elbow with a thickness more than 10 mm

greater than the straight pipe instead of target block?

Yes, with the provision that the equipment owner’s PM program

include an inspection for erosion at the pipe bends at least every two

years.

534th Edition,

Nov. 20127.2.3.1.2 53-05-14

Referencing 7.2.3.1.2, for short radius bends (R/d < 10), ninety-degree block ells, and

tees, can the fluid cushions requirement be replaced with annual inspection of wall

thickness and or internal bore scoping since there is no past failure existing in these

components and provided the component wall thickness and internal surface

condition remain intact?

No; API 53 does not currently allow alternatives to fluid cushions

534th Edition,

Nov. 20127.2.3.1.2 53-10-14

Is it the intent of 7.2.3.1.2, that the flex loops on the LMRP, mainly the area directly

under the kick-outs on the riser adapter, and the riser adapters themselves have

either large radius bends or targeted ells? Typically on many BOPs, the first bend in

the flex loop, as you come out of the riser adapter and begin spiraling down the flex

loop, is a bend that has a radius less than 10 times the ID of the choke or kill pipe.

Also the riser adapter is typically supplied with short radius bend kick-outs.

The requirement is written such that it covers the flex loops and riser

adapter kick-out subs.

This intepretation has been rendered invalid as a result of publication of API S53, 4th Edition, Addendum 1 in July 2016. Therefore this

interpretation has been superceded as a result of these updated requirements and replaced with the following interpreation.



This intepretation has been rendered invalid as a result of publication of API S53, 4th Edition, Addendum 1 in July 2016. Therefore this interpretation has been withdrawn as a result of these updated requirements and replaced

with the following interpretation.

of 27



534th Edition,

Nov. 20127.2.3.1.2 53-10-14

Is it the intent of 7.2.3.1.2, that the flex loops on the LMRP, mainly the area directly

under the kick-outs on the riser adapter, and the riser adapters themselves have

either large radius bends or targeted ells? Typically on many BOPs, the first bend in

the flex loop, as you come out of the riser adapter and begin spiraling down the flex

loop, is a bend that has a radius less than 10 times the ID of the choke or kill pipe.

Also the riser adapter is typically supplied with short radius bend kick-outs.

Yes. When R/d > 10 is not possible, the equipment owner’s PM

program shall include an inspection for erosion at the pipe bends at

least every two years.

Item 7.2.3.1.2 states that short radius bends on choke and kill lines must be targeted

or have fluid cushion to minimize erosion

Question 1: Is there any requirement for the length of the cushion zone?

Reply 1: No, there are no design requirements for the fluid cushion.

Question 2: Would be acceptable a length of 4 inches, or equal to pipe internal

diameter, whichever is higher?

Reply 2: As there is no choke or kill fluid cushion design

requirements within Std 53, this committee cannot answer this

question.

Question 3: Is it acceptable to use fluid cushion made of pipes welded perpendicularly

instead of a block?

Reply 3: As there is no choke or kill fluid cushion design

requirements within Std 53, this committee cannot answer this

question.

534th Edition,

Nov. 20127.2.3.1.2 53-21-16

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534th Edition,

Nov. 20127.2.3.2.9 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.

534th Edition,

Nov. 20127.2.3.2.9 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.


has been superceded as a result of these updated requirements.



This intepretation has been rendered invalid as a result of publication of

of 27



534th Edition,

Nov. 20127.3.10 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.

534th Edition,

Nov. 20127.3.10 53-01-18 Is the Hot Line required to be able to perform EDS in time by itself?

Yes, if the hotline is the primary fluid supply.

No, if the hotline is not the primary fluid supply.

545th Edition,

Nov. 20127.3.10.1 53-02-18 According 7.3.10.1, is the EDS to be considered one function?

No, the EDS is a programmed sequence of events. NOTE: EDS

response time criteria is specified in Table 6 and Table 7, required by

7.3.17.5.

534th Edition,

Nov. 20127.3.12.8 53-20-16

For functions with varying pressure ranges it is impossible to comply with the 25%-

75% gauge rule. The Overshot Packer and the Flowline Seals (just an example but it

applies to more functions) can sometimes be run down to as low as 200 psi and as

high as 1,500 psi. To meet the API Standard 53 requirement on 7.3.12.8, you would

need to operate with a gauge with a high end of 2,000 psi which would make your low

end 500 psi (25% of 2000), which is above our low range for the function (200 psi).

To meet the API Standard 53 requirement on 7.3.12.8, you would need to operate with

a gauge with a high end of 2,000 psi which would make your low end 500 psi (25% of

2000), which is above our low range for the function (200 psi). Use two different

gauges?

The intent is not to require two gauges for normal operations; the

intent is for two gauges required for testing only. However, two

gauges would be required to meet the requirement with a span that

exceeds the 25%-75%.

534th Edition,

Nov. 20127.4.6.4.2 53-22-16

The API 53 has contraditory procedures to do the drawdown test. In section 7.4.6.4.2

says that you should close and open the largest volume annular plus four smallest

operation volume ram-type BOP, excluding test ram. However, the section 7.6.8.2.2 d)

request the largest annular plus the four smallest volume PIPE ram preventers.

Which one should I use for the BOP from background?

For drawdown testing, 7.6.8.2.2 shall be followed.



of 27



534th Edition,

Nov. 20127.4.6.6.3 53-26-16

If the main accumulator system drawdown test meets the requirement of precharge

verification for the main system as described in 7.6.8.2.1 and 7.3.7.1 and Table 9, is

the intention of 7.4.6.6.3 to require only the subsea (stack mounted) accumulator

bottles precharge to be checked and adjusted for depth every predeployment?

Yes.

7.4.6.6.2 The precharge pressure on each accumulator bottle shall be measured in

accordance with equipment owner's PM program and adjusted, if necessary.

7.4.6.6.3 The precharge pressure shall be measured prior to BOP stack deployment

and adjusted in accordance with the manufacturer-specified API 16D method (A, B, or

C).

These paragraphs relate to measurement and adjustment of precharge, however, they

do not specify if the requirements are for Main Accumulators, Stack Mounted

Accumulators, or both.

We conclude that 7.4.6.6.2 is meant to relate to the Main Accumulators on surface as

the pressure measurements can be scheduled at appropriate time intervals. Also, we

conclude that 7.4.6.6.3 relates to stack mounted accumulators as they must be

measured and adjusted prior to BOP stack deployment.

Question 1: Was the intent of 7.4.6.6.2 to relate to the Main Accumulators on surface

and was this measurement intended to be checked at time interval determined by the

equipment owner?

Response 1: Yes.

Question 2: Was the intent of 7.4.6.6.3 to relate to the accumulators that are stack

mounted?Response 2: Yes.

There has been some confusion within our organization as to whether or not Section

7.4.6.6.3 pertains to both the surface and subsea accumulator bottles. Since the

verbiage from Section 6.3.9, referring strictly to surface accumulator bottles is exactly

the same as that for subsea, it has been our interpretation that this section was meant

for ALL accumulator bottles of the BOP system. Furthermore, this section also refers

to API 16D methods (A, B, or C), of which includes the method for surface

accumulator precharge.

Is Section 7.4.6.6.3 applicable to both the surface and subsea mounted accumulator

bottles of a subsea BOP system?

No, the subsea accumulator precharge shall be checked prior to BOP

stack deployment.

The surface accumulator precharge shall be checked per equipment

owner's PM progam.

The next edition will include clarification to correct this.

534th Edition,

Nov. 20127.4.6.6.3 53-06-17

534th Edition,

Nov. 20127.4.6.6.3 53-29-16

of 27



Standard 53 does not define "system" or "control unit " in section 7.4 nor in section 3.

Section 7.4.9 is entitled Control Stations. Section 7.4.9.9 discusses the main control

unit

Is it correct that "the control unit" referred to in 7.4.9.10 is the "main control unit" ? No.

The next edition will include clarification to further define this.

Question 1: In reference to the requirement of 7.4.9.11, is it permissible for the system

to display no previous status upon restoration of power?

Reply 1: No, unless displaying the previous status could result in an

incorrect indication (API 16D 5.2.5.4 & 5.4.5).

Question 2: In reference to the requirement of 7.4.9.11, is it permissible for the system

to change the state of a BOP operator upon restoration of power, and display the

changed position? Example – unlocking a locked pipe ram?

Reply 2: No.

Question 3: In reference to the requirement of 7.4.9.11, API 16D requires not

displaying the last position when an electrical power loss in the surface panel(s)

could result in an incorrect indication (5.2.5.4). Please confirm the API 16D

requirement takes precedence and either include the requirement in API S53 or delete

the design requirement in API S53.

Reply 3: See response to question 1.

534th Edition,

Nov. 20127.4.9.11 53-08-17

In section 7.4.9.11 is it correct to assume “ the system” referred to is the 16D edition

2, definition of a BOP CONTROL SYSTEM (3.14) and includes all of the control and

display panels used to operate the BOP?

Yes.

When there is more than an interruption to power, rather a complete loss for several

hours, some MUX systems only retain the last know state at the CCU or in the

function logger.

Does it meet the intent of S53 if, after a complete loss of power, the location of the

information concerning the status of the BOP control system at the time of loss of

power is displayed at the CCU, or recorded in the function logger , and only at the

CCU or function logger as described in 16D 5.4.5 “..displayed/and or recorded in some

form” .

Yes.

Question 1: With respect to an EDS being completed, will the time stop when the

command has been sent to the LMRP connector to unlatch?

Reply 1: No, the time stops when the well is secured (see Table 6

and Table 7 Note C).

Question 2: Will the time stop when the LMRP connector has reached its fully

unlatched position?

Reply 2: No, the time stops when the well is secured (see Table 6

and Table 7 Note C).

534th Edition,

Nov. 20127.4.9.10 53-07-17


Nov. 2012

534th Edition,

Nov. 20127.4.13 53-05-17

7.4.9.11

534th Edition,

Nov. 2012

7.4.9.10

7.4.9.1153-04-15

of 27



Question 1: If a stack-mounted accumulator system (sized per API 16D, Method C, for

closing of shear ram(s) only) is utilized to meet the ROV closing time requirement,

and is shared with a deadman and autoshear system, shall it include a ROV

recharging function to comply with 7.4.16.1.2?

Reply 1: API 53 does not address this issue.

Question 2: Shall the stack-mounted accumulator option include a regulated circuit to

actuate critical functions listed in 7.4.16.1.1 if they have a rated working pressure

below the accumulator’s charged pressure?

Reply 2: The source of hydraulic fluid shall have necessary pressure

and flow rate to operate these functions”, as stated in 7.4.16.1.2, and

“All critical functions shall meet the closing time requirements in

7.4.6.5.4”, as stated in 7.4.16.1.6.

Question 3: A failure of the deadman or autoshear may be the reason for needing to

conduct BOP ROV intervention. If a shared system fails, shall the BOP ROV

intervention system include functions to isolate these systems so recharging of the

accumulator system is possible?

Reply 3: API 53 does not address this issue.

It is not clear in 7.4.16.1.1 whether shear ram ‘OPEN’, pipe ram ‘OPEN’, and ram locks

‘UNLOCK’ are considered critical functions as they are not included in Table 6.

Question 1: Are shear ram ‘OPEN’, pipe ram ‘OPEN’, and ram locks ‘UNLOCK’

considered critical functions?

Reply 1: No.

Question 2: Are the items on the list below inclusive of API Standard 53 critical

functions?

• Each Shear Ram ‘CLOSE’

• Blind Shear Ram Locks ‘LOCK’

• One Pipe Ram ‘CLOSE’ and 'LOCK'

• LMRP Connector ‘UNLATCH’

Reply 2: Yes.

534th Edition,

Nov. 20127.4.16.2.2 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.

534th Edition,

Nov. 20127.4.16.1 53-01-15

534th Edition,

Nov. 20127.4.16.1.1 53-18-16

of 27



534th Edition,

Nov. 2012Table 7 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 45 seconds, 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?

Table 7 is a function test requirement without pipe in the stack.

7.6.6.5 states BSRs and/or CSRs shall not be tested when pipe is in

the stack.

7.4.16.1.2 states the source of hydraulic fluid shall have necessary

pressure and flow rate to operate these functions.

The intent is to secure the wellbore in 45 seconds or less with or

without pipe in the stack, but the test with pipe in the stack is not a

requirement of Standard 53.

534th Edition,

Nov. 20127.6.5.1 53-09-14

Referencing 7.6.5.1, for BOP functioning/intervention via a ROV, does the 45 second

requirement in Table 6 and Table 7 apply to an open bore or for a BOP with pipe in it?

Testing referred to in Table 6 and Table 7 is intended to be conducted

with an open hole for shear rams (see 7.6.6.5) and with pipe in the

stack for pipe rams.

534th Edition,

Nov. 20127.6.5.2.14 53-19-17

As per 7.6.5.2.14, are BHA components such as the bit, motor, stabilizers, etc to be

considered "large bore tools" for drifting the BOP upon completion of the initial BOP

test on the wellhead assembly, when no test plug is used and the wear bushing is

already installed? Example: Deepwater, shallow depth well with low MASP, where a

test plug is not used and the initial BOP test on the seafloor is conducted against a

cemented shoe and surface casing. The SSBOP is equipped with test rams.

Yes, the BHA components can be considered other large bore tools.

534th Edition,

Nov. 20127.6.5.2.6 53-24-16 Do you need to do a function test after relanding the LMRP onto the lower stack?

Yes, per 7.6.5.4.3 A function test of the BOP control system shall be

performed following the disconnection or repair, limited to the

affected component.

Release or latching type components are only required per 7.6.5.1.7.

7.6.5.1.7 Release or latching type components of subsea well control

systems (choke, kill, riser, wellhead connectors, etc.) and emergency

or secondary systems shall be function tested prior to deployment or

as defined in equipment owner’s PM program.

of 27



534th Edition,

Nov. 2012

7.6.5.2.6

Table 1053-25-16

Is it the intent that the portion of the manifold that is downstream of the chokes be

pressure tested to the RWP of the chokes outlet valves, lines or the same as the ram

preventers, whichever is lower even if the lowest RWP is higher than the MAWHP?

The intent was not to require a higher test pressure for downstream

of the chokes as compared to the upstream of the chokes.

This requirement will be reviewed for change at the next revision of

the document.

Question 1: Does each of the valves in the C&K manifold (about 35 valve) need to be

pressure tested in both directions?

Reply 1: No. Valves that are required to seal against flow from both

directions, shall be pressure tested from both directions.

Question 2: Or does each of the valves in the C&K manifold need to be pressure

tested from wellbore direction only? Reply 2: No, see above.

Question 3: Or does each of the valves in the C&K manifold need just 1 each shell test

in 15k & 10k side?

We heard same test need to be done each 21days during operation

Reply 3: Shell testing of choke manifold equipment is a

manufacturing requirement. See API Specification 16C second

edition 7.5.12.

See API Standard 53 7.6.5.4.2.d & Table 10.

Question 1: Are all “pre-deployment” and “prior to deployment” requirements of API

53 to be completed after a LMRP or BOP retrieval for repair before re-deploying to the

same well for continued operation.

Reply 1: No; a function test of the BOP control system shall be

performed following the disconnection or repair, limited to the

affected component, as stated in 7.6.5.4.3.

Question 2: Alternatively, does “pre-deployment” and “prior to deployment” refer to

deployment following between-well-maintenance and prior to new operations?”Reply 2: Yes.

7.6.5.4.1 a), Table 9, and Table 10 state Pressure tests on the well control equipment

shall be conducted predeployment of the BOP and upon landing the BOP. We test

predeployment; we land the BOP on wellhead & conduct a complete test. At end of

well 1 we unlatch pull 2 joints of riser, move the drill ship (short distance), land and

latch the BOP on wellhead 2, complete the program on site 2, then unlatch and repeat

the "BOP Hop" multiple times (4-7 well sites, some wells only 2 weeks long, between

moves) over the course of months before pulling the BOP back to surface to complete

between well maintenance and pre-deployment testing. 7.6.5.4.1 d) states 'not to

exceed intervals of 21 days, excluding BSRs.

534th Edition,

Nov. 20127.6.5.4.1a 53-04-17

534th Edition,

Nov. 2012

7.6.5.2.13

Table 1053-08-15

534th Edition,

Nov. 20127.6.5.3 53-07-14

of 27



Question 1: If we do not pull the BOP to surface do we have to complete a full BOP

test on each initial landing?

Reply 1: Refer to 7.6.5.9 of Standard 53 for subsea well hopping

requirements.

Question 2: As we are not pulling the BOP to surface between wells, and many of our

wells are not 21 days long: (if we complete the weekly function tests) & If we conduct

a complete pressure test every 21 days and a -pressure test / shell test against the

shear rams and wellhead connector/gasket with each new site BOP landing... does

meeting the 21 day pressure test interval full-fill the consideration and intention of

Standard 53?

Reply 2: Refer to 7.6.5.9 of Standard 53 for subsea well hopping

requirements.

534th Edition,

Nov. 20127.6.5.4.1d 53-20-17

Is it correct that point "d" is meant to apply only after the BOP is deployed and not

before. I.E. predeployment testing does not have a frequency or a specific window

before deploying other than it must be completed at least once before deploying.

Yes, the 21 day test frequency is while the BOP is in operation.

534th Edition,

Nov. 20127.6.6.3 53-17-16

I do not understand the intent to pressure test annular(s) and VBR(s) on the largest

and smallest OD drill pipe to be used in well drilling program on surface.

Should be enough to test only with the smallest OD drill pipe as stated in 7.6.6.4 on

subsea test?

No, 7.6.6.3 shall be followed for the pre-deployment test.

The intent is to verify the full range of variable BOP sealing elements

prior to deployment.

534th Edition,

Nov. 20127.6.6.9 53-13-14

In section 7.6.6.9 it requires testing on the ram locks only during pre-deployment

testing. What about the 21 day testing regimen?

The use of ram locks is not required for subsequent testing. Section

7.6.6.10 states “The BSR(s) and the hang-off ram BOP shall be

pressure tested with locks in the locked position and closing and

locking pressure vented, during the initial subsea test only.”

Question 1: In reference to 7.6.6.17, is totally impractical to suggest that a surge

bottle can be installed adjacent to the annular preventer if contingency well control

procedures include stripping operations as this implies that a bottle may be used on

some wells and not on others. Would it not be better to simply state that an annular

surge bottle is optional for subsea use?

Reply 1: This is a question based on an opinion and does not meet

the requirements for technical interpretation. Note that a surge

bottle is not required per this standard, as the statement utilizes the

word “can” which allows the possibility without inferring it is a

requirement.

Depending on system configuration and plumbing, a surge bottle

may improve stripping capability. Use of other equipment may

accomplish the same result as a surge bottle.

Question 2: Per the Standard, would it be better to state that the surge bottle is

optional than simply deleting 7.6.6.17? Stating that it is optional is clear. Deleting the

statement could be interpreted as an error.

Reply 2: See response above. However your comment will be

considered during the next revision of the document.

534th Edition,

Nov. 20127.6.5.4.1a 53-04-17

534th Edition,

Nov. 20127.6.6.17 53-04-16

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Question 1: Is it acceptable to pressure test a riser connector to 70% as like an SBOP

after breaking this connection, if the wellhead RWP is 15 000psi and the anticipated

wellhead pressure is just over 10 000psi?

Reply 1: No.

Question 2: Is it acceptable to complete function test and drawdown test then split

the LMRP off the BOP and change riser connector, choke and kill gaskets then

deploy? Confirmation required please.

Reply 2: No.

We are doing pre deployment testing according to S53 table 9 (page 86), my question

relates to table 10 (subsea testing) and the interpretation of “initial pressure test,

upon landing the BOP”

Question 1: Shall this be understood in the most conservative way, that one shall first

do a full pre-deployment test, run BOP, and then repeat all testing again after landing

on a wellhead?

Reply 1: The testing listed in Table 10 shall be conducted after initial

latch-up.

Question 2: Or could the pre-deployment test (as long as BOP is run within

reasonable time, say a week) be considered as the initial pressure test (with WH

connector pressure test and full function test after landing)?

Reply 2: No.

We have been requested to change our practice for BOP testing upon latching on a

new subsea wellhead. So far the common understanding was to follow the

instructions reported in Table 10 where the pressures were intended as readings at

surface gauges. The latest request was to pressure test the Blind Shear Rams and the

Wellhead Connector upon latching at MAWHP reduced by the Hydrostatic Head (test

medium seawater). As per our previous practice we would have applied MAWHP at

surface (see also API RP 96, 5.4.2.2 "The MAWHP is an internal pressure, and does

not account for the effect of the external seawater gradient down to the wellhead").

Question 1) Is the MAWHP to be intended as the pressure readings at the BOP

sensor?

Answer 1: Yes, if the units of measurements are the same. NOTE:

MAWHP can be expressed as either an absolute (psia) or a relative

gauge pressure (psig).

534th Edition,

Nov. 2012Table 9 53-10-16

534th Edition,

Nov. 2012Table 10 53-21-17

534th Edition,

Nov. 2012Table 9 53-12-16

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Question 2) Is testing the Wellhead Connector at a surface pressure equal to MAWHP

reduced by Hydrostatic Head in line with API requirements?

Answer 2: Yes, if MAWHP is presented as an absolute pressure

(psia) the surface test pressure should be reduced by the hydrostatic

head of the test medium (seawater).

No, if MAWHP is presented as a relative gauge pressure (psig), it is

the surface test pressure with a seawater test medium.

Question 1: The drawdown test requirement outlined in section 7.6.8.2 for drawdown

testing, after the completion of the drawdown test, do we require to perform a pump

up test for the system to confirm the pumps capability, or we are only required to

perform the drawdown test and confirm the minimum pressure?

Reply 1: No, 7.6.8.2 does not require a pump capability test.

Question 2: The pump capability test is required to be done based on table 9 for

predeployment testing, does the system need to be bled down to precharge pressure

prior to performing the test or only the pressure after the drawdown test which is as a

minimum should be 200 psi over precharge pressure?

Reply 2: Yes, the pressure is required to be bled down to precharge

pressure.

534th Edition,

Nov. 20127.6.8.2 53-22-17

The relevant API S 53 section is 7.6.8.2. Our interpretation, and what appears to be

pretty straightforward, is that a drawdown test should be carried out:

• During BOP Pre-Deployment testing

• Once the BOP has been landed following deployment

• After repairs to the system which has included isolation of the accumulator system

• If the BOP is Subsea for over 6 months, 6 months from previous test.

During discussions with a contractor we have been informed that they only carry out

drawdown testing every 6 months and not the pre-deployment and landing

requirements

Is our interpretation correct?

Yes, the drawdown test shall be conducted:

• prior to deployment

• upon initial landing the BOPs

• after any repairs that required isolation/partial isolation of the

system

• and subsequently every 6 months from the previous test

Figure A.4 Note 2 seems to be contradictory regarding confirmation of closing times.

Question 1: 7.6.8.2 Drawdown Test

Is it the intent of this test to test (verify) the main accumulator volume and pressure?

Yes, the intent is fully explained in 7.6.8.2.1, ‘The purpose of this test

is to verify that the main accumulator system, as described in 7.3.7.1,

is properly sized to support the fluid volume and pressure

requirements of the BOPs on the rig to secure the wellbore’.

534th Edition,

Nov. 20127.6.8.2 53-15-16

534th Edition,

Nov. 2012

7.6.8.2

Figure A.453-04-18

534th Edition,

Nov. 2012Table 10 53-21-17

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Question 2: Are the pod function test tests with pump systems online the appropriate

tests for confirming closing times?

Yes, this is an appropriate test for confirming closing times.

NOTE: The Standard 53 5th edition draft does not require closing

time conformance during the accumulator drawdown test.

To accomplish a drawdown test and minimize pipe handling S53 Annex A infers you

can use another BOP operator such as a pipe ram to simulate the volumetric draw of

the shear rams. In practice we see that some equipment owners will use the annular

to simulate the volume of a large shear ram operator. Sometimes the packer sizes

differ such that one pipe cannot be used and close all rams, so a ram is closed twice

to simulate the other ram. To decrease wear and tear on the pipe ram packer and

automatic locks, as well as the annular packer an equipment owner wants to function

only the casing shear ram a sufficient number of times to simulate the volume drawn

by 1 annular and 4 of the smallest rams. This also reduces pipe handling in and out of

the BOP.

Does functioning a casing shear ram sufficient times to drawdown the same or more

volume than would be drawn down by closing and opening one annular and 4 rams

meet the intent of the drawdown test?

Yes, the intent is to operate the equivalent, or more, volume required

to verify the accumulator system functionality.

534th Edition,

Nov. 20127.6.8.2.2 53-09-16

Section 7.6.8.2.2 Requires a main accumulator system drawdown on initial land out

and every 6 months there after. The requirement does NOT mention the pump

efficiency test specifically but does refere to Annex "A" which DOES include a pump

systems test . I am referring to a test to determine if the pumps meet the requirements

of 7.4.5 which, consequently does NOT have a frequency stated but because the

annex references both requirements rigs have assumed they have the same testing

frequency requirements. This prolongs the time in which the system is incapable of

carrying out an EDS.

Upon landing the BOP , in addition to the drawdown test, is the pump systems test -

timing top off from precharge- required?No.

534th Edition,

Nov. 20127.6.8.2.2 53-14-17

534th Edition,

Nov. 2012

7.6.8.2

Figure A.453-04-18

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

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

function?Reply 3: Yes.

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

after connection to the first well?

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

hopping operation.

Reading between section 7.6.9.3.1 and 7.6.9.3.2 , the section refers to suspending

initial maintenance calendars based to start on the date the equipment is installed in a

system and section 7.6.9.3.2 advises that a variation from calendar based

maintenance can be carried out given equipment data to justify a different frequency.

In Addendum 1, section 7.6.9.3.1, is it correct to infer that equipment overhauled and

tested in the field then stored in accordance with 7.6.9.7 Equipment Storage may

pause its five-year period on the date it is put into storage, then restart the

maintenance calendar on re-installation and meet the intent of this section concerning

maintenance and inspection?

If the equipment is inspected per 7.6.9.3.1 and then stored in

accordance with 7.6.9.7, the 5 year period will begin upon

installation.

Once a start date is determined, there is no pausing of the five year

inspection period.

In Addendum 1, section 6.5.7.3.1 (c ) reads …" if preservation and storage records in

accordance with 6.5.8.4, are not available". The sister section 7.6.9.3.1 (c ) is nearly

identical to 6.5.7.3.1 except it does NOT refer to section 7.6.9.7 to describe the

preservation.

Was it the intent of Addendum 1 to use section 7.6.9.7 Equipment Storage as

guidance for the preservation referred to in section 7.6.9.3.1? Yes.

534th Edition,

Nov. 20127.6.9.3 53-11-17


Nov. 20127.6.9.3.1

534th Edition,

Nov. 20127.6.8.3 53-15-13

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534th Edition,

Nov. 2012

7.6.9.3 &

6.2.5.153-27-16

API STD 53, Section 7.6.9.3 states “Well control equipment system components shall

be inspected at least every 5 years in accordance with the equipment owner’s PM

program. Individual components and subassemblies may be inspected on a staggered

schedule. The inspection results shall be verified against the manufacturer’s

acceptance criteria.”

API STD 53, Section 6.2.5.1 addressing the inspection, testing and maintenance of

Choke Manifolds, Choke Lines, and Kill Lines states “Maintenance and inspection

shall be performed on the same schedule employed for the BOP in

use and shall include checks for wear, erosion, and plugged or damaged lines.”

Is it a requirement to tear down the Choke Manifold to meet this requirement?

No.

534th Edition,

Nov. 20127.6.9.3.1 53-06-14

Background: We have one rig where the COCs of the subsea components expired at

the end of last year (2013), however; the components have been in storage for more

than two years and only been in service for 740 days. All equipment is fully functional

and documents of testing and annual inspection are well maintained.

Question 1: Referencing 7.6.9.3.1, does the term “At least every 5 years” begin on the

component COC date or on the date that the component is put in service?

Question 2: Referencing 7.6.9.3.1, does API 53 require the COCs of this equipment to

be active if the equipment owner’s PM program requirements include all subsea

equipment to be inspected annually and/or every five year by a competent person(s)

(the frequency of inspection is derived from the equipment as owner collects and

analyzes condition based data (including performance data) and the result of the

inspection meets the equipment owner’s PM program and the manufacturer’s

guidelines?

Reply 1: Neither; it begins from the date the equipment was last

“inspected for repair or remanufacturing, in accordance with

equipment owner's PM program and the manufacturer’s guidelines”.

Reply 2: No, API 53 does not require COCs.


has been superceded as a result of these updated requirements and replaced with the following interpretation.

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534th Edition,

Nov. 20127.6.9.3.1 53-06-14

Background: We have one rig where the COCs of the subsea components expired at

the end of last year (2013), however; the components have been in storage for more

than two years and only been in service for 740 days. All equipment is fully functional

and documents of testing and annual inspection are well maintained.

Question: Referencing 7.6.9.3.1, does API 53 require the COCs of this equipment to be

active if the equipment owner’s PM program requirements include all subsea

equipment to be inspected annually and/or every five year by a competent person(s)

(the frequency of inspection is derived from the equipment as owner collects and

analyzes condition based data (including performance data) and the result of the

inspection meets the equipment owner’s PM program and the manufacturer’s

guidelines?

Reply: No, API 53 does not require COCs.

534th Edition,

Nov. 20127.6.9.3.3 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 manufacturer’s 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 owner’s preventive maintenance

program.

534th Edition,

Nov. 20127.6.9.3.4 53-08-14

Section 7.6.9.3.4 states inspections shall be performed by a competent person(s).

Must this "competent person (workshop)" have the certification or permission of the

manufacturer to fulfill the repairs?

No; these are not required by API 53. See 3.1.20 for the definition of

a competent person.

534th Edition,

Nov. 20127.6.11.7.6 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.

This intepretation has been rendered invalid as a result of publication of API S53, 4th Edition, Addendum 1 in July 2016.

Therefore this interpretation has been withdrawn as a result of these updated requirements.

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