SUMMARY OF API RP 53 – PART 1 –

SURFACE BOP
API RP 53 – BOP Equipment System for Drilling Wells – Part 1 –
Summary Surface Stack

API RP 53 is surely a critical guideline, this summary is only to cite things

we use and refer most frequently. Especially for guys at well site doing the
hand-on job and guys going to renew well control certificate. For full
explanation or more insight please peruse this standard.

Note: DIVERTER will be captured in a separate part of API 64, so

hereafter we will not discuss the guidelines, operations and installation of
diverter systems.

I will divide this whole standard into smaller parts for ease of reference,
such as surface stack, subsea stack, accumulator bottle calculation for
surface, accumulator bottle calculation for subsea, seals, etc… So now is
the first part – Surface Stack.

First off is the Class of a stack. What is a BOP Class?

BOP Class = quantity of total RAMS and ANNULARS on that Stack. For
instance, A Class 5 BOP has total 5 sealing components of Rams &
annulars, but how many rams and how many annular particularly then we
need further alphanumeric nomenclature following the class. That is
Alphabet – Numeric form, i.e A1 or R4. So if we read Class 5 – A1 – R4 it
means a stack of 5 components of 1 x Annular BOP + 4 x Ram BOP’s.

If a stack has Ram BOPs installed, it must have at least 1 set of Blind or
Blind Shear Ram (BSR) installed.
 Stack Component Code:

G = Rotating Head

A = Annular R = Ram Rd = Double Ram Rt = Triple Ram

BSR = Blind Shear Ram CSR = Casing Shear

Ram S=Spool

K = 1000 psi

Code interpret: 10K – 13 5/8” – SRRA = Stack rating 10’000psi, full bore
size 13-5/8”, from bottom up: Spool – Ram – Ram – Annular.
WP Rating Minimum Class Requirement
Class 2
<= 3K
If 1 set of Rams is installed then 1 set of Blind or BSR must be installed.
Class 3
1 set of Blind or BSR
5K
1 set of Pipe Ram
3rd component: Annular or Rams
Class 4
1 annular
10K 1 set of Blind or BSR: capable of shear and seal drill pipe
1 set of Pipe ram
4th component: at desired, usually a set of VBR or pipe ram.
Class 5
1 annular
>= 15K 1 set of BSR
2 sets of pipe rams
5th component: at desired, usually a set of VBR or pipe rams.

Minimum for class 6 arrangement is: 1 ea x Annular, 1 set x BSR, 2 sets x

Pipe Rams, 5 an 6 components may be rams (pipe, blind, BSR, Casing
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Shear, VBR) or Annular or combination.

 All rams must have locking devices. It can be either extension with hand
wheel or hydraulic locks. With hydraulic fluid supply cut off, we can rotate
the hand wheel to close the RAM BOP and lock it in place.

Minimum Spare Part Requirement:

 1 complete set of Ram rubbers for each size and type of Ram BOP in
used.
 1 complete set of bonnet door seal for each size and type of Ram BOP in
used.
 Plastic packing for BOP secondary seals.
 Rig gaskets to fit end connections.
 1 Annular BOP packing element + 1 complete set of seals.
 1 flexible choke/kill line if in use.

Storage: All parts and assemblies must be coated and maintained with a
protective coating to prevent rust.

Elastomer storage: wrapped in plastic bag, avoid direct sunlight, stored in

dark room with air-cond and following manufacturer’s guidance.

Spacer Spool:

To provide space for stripping, hang off and/or shearing. It must have
same bore diameter with mating equipment, same or greater WP, and
shall not expose wellbore to the environment.

Drilling Spool:

Beside serving function of a spacer spool, there are outlets connection for
Choke & Kill lines but it has to be below at least 1 BOP capable of closing
on pipe. Drilling spool is cheaper than Ram Body, hence we can localize
the erosion by connecting C&K lines onto drilling spool rather than
directly on the Ram body. However, connecting C&K lines onto ram body
 will reduce stack overall weight and height – that are sometime required if
we have limited space below sub-structure and platform load bearing
capability.

Minimum requirements for drilling spool:

WP Minimum Requirement
2 side outlets not smaller than 2” ID
3K & 5K
Flanged, studded or hubbed
2 side outlets: 1 x 3” + 1 x 2” ID- flanged,
>= 10K
studded or hubbed
Spool ID must be same as mating equipment or equals the maximum ID
of Well head or Well head assembly.
Equal or greater WP with RAM BOP’s

CHOKE MANIFOLDS

API 16C discusses Choke & Kill Manifold in a great deal of details for
designing, manufacturing and installation. Here we only capture a few
major points.

 Shall have 2 adjustable chokes either manual or remotely operated.

 Shall be able to connect to both mud standpipe and cement standpipe.
 Same WP with ram BOP’s or Well head whichever is lower
 Lines downstream of CHOKES shall have ID equal or greater than ID of
choke inlet and outlet.
 On 5K system, minimum 1 choke is remotely operated.
 On 10K system, minimum 2 remotely operated chokes to be installed.
 On C&K Line, the manual HCR is always installed upstream of the
hydraulic HCR valve for maintenance and operation purpose.
 Gauge calibration to follow recognized standard: NIST, ANSI on
YEARLY basis
 Control station shall provide overview of well control operation: Stand
Pipe Pressure, Casing Pressure, Pump Strokes.
 Remotely operated valves/chokes to have back up power or manual
override.
 CHOKE LINE INSTALLATION We’ll capture API 16C Choke & Kill
Line for more details of Choke & Kill lines.
WP Minimum ID
2K, 3K and 5K 2” ID
>=10K 3” ID

Choke by-pass line = Bleed line: To allow circulating the well with BOP
closed and lesser back pressure, it allows higher volume to bleed off if
desired. Must be same ID with choke line.

KILL LINE INSTALLATION

Again, we’ll capture API 16C Choke & Kill Line for more details of
Choke & Kill lines.

For 5K stack and above:

 If using 2 full bore Manual valves then must have a check valve
 If using 1 hydraulic HCR valve + 1 manual valve then no check valve

For 3K stack only need 2 full bore manual valve or 1 HCR + 1 manual.

Minimum ID: 2”

SURFACE STACK CONTROL SYSTEM (KOOMEY)

API 16D will be discussed separately to cover the major of designing,

manufacturing and installing. Here only captures some key requirements
that help you at the field and in the well control test room.

Control Fluid: If temperature is below 0 C (32 F) => Need to add sufficient

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glycol.
 Pump systems requirements:

 Minimum 2 pump systems. Each pump system may have 1 or more than
1 pump.
 Discharge of each pump system should equate the system full WP
(3,000psi)
 Each pump system is powered from independent source. Need to ensure
if 1 power source is lost the entire pump systems are not impaired.
 At least 1 pump system to operational and available at all times.
 With Accumulator bottles isolated, each pump system must be capable of:
Closing 1 x Annular on the minimum pipe size + Opening HCR valve +
Providing Pressure in system to keep Annular sealing for 2 Minutes.
 The total output of all pump systems MUST be able to charge up the
accumulators from PRECHARGE to system WP in 15 MINUTES
=> For a 3,000 psi system, all pumps run simultaneously will charge system
from 1,000 psi to 3,000 psi in 15 minutes.
 If 1 pump system failed or 1 power source is lost => The remaining pump
system MUST charge the accumulators from PRECHARGE to system
WP in 30 MINUTES => For 3,000 psi system, with either AIR (or Air
pumps) or ELECTRICITY (or electric pumps) is lost the remaining
pumps must charge up system from 1,000 psi to 3,000 psi in 30
MINUTES.
 DIVERTER hydraulic power is supplied from these pump systems so
DIVERTER take hydraulic pressure from 3,000 psi source then going
through a regulator 500-1,500psi.
 The pump systems are equipped with pulsation dampeners => These
dampeners are precharged with Nitrogen to 2/3 of system WP = 2,000 psi
precharged.
 When accumulator pressure drops before 10% (2,700 psi) => The
primary pump system must kick on to charge up, until accumulator
pressure reaches range 97% (2,910psi) – 100% the pumps must stop.
 When accumulator pressure drops before 15% (2,550 psi) => The
secondary pump system must kick on to assist the primary pump system
and it shall stop when accumulator reaches range 95% (2,850psi) – 100%.
 If using air pumps => they must be operable at 75 psi.
  Each pump system shall have 02 overpressure protective devices: 1 is
Pressure switch set at 3,000psi to protect over discharge of pump, 1 is
pressure relief valve set at 10% higher than system WP – 3,300 psi.

Accumulator bottle requirements:

Before getting into requirements let us familiarize ourselves with some

definitions:

 Stored hydraulic fluid: Is the fluid volume between system WP (3,000psi)

and precharge pressure (1,000psi)
 Usable hydraulic fluid: Is the fluid volume between system WP (3,000psi)
and 1,200psi (200psi above precharge)
 Precharge: with N at 1/3 of system WP = 1,000psi.
2

Requirements:

 With all pumps isolated, accumulators should be capable of: {Close 1 x

Annular + Close all rams from fully open position + Open 1 x HCR } +
Maintain 1,200psi in the system (1,200psi = 200psi above precharge
1,000psi) => Note, for shear ram, substitute with opening 1 pipe ram.
The volume in the bottles after doing all those and maintaining 1,200psi
versus initial 3,000psi is called USABLE VOLUME of the accumulator.
 Response time requirement: response time is measured since pressing the
button, seeing pressure drop and flow meter run and stop when pressure
recovers back to normal setting.
Component Maximum time – second
Close Ram 30
Close Annular < 18-3/4” 30
Close Annular >=18-3/4” 45
HCR’s (Open/Close) Not greater than observed minimum ram closing time

Table of surface BOP response time – API RP 53

CONTROL FLUID TANK CAPACITY

System to have reservoir minimum twice the accumulator usable capacity

(as mentioned above) – By API RP 53 3 eidition.
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By API RP 53 5 edition: No mention to the reservoir capacity but only

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make reference to API 16D.

By API 16D 3 edition: Reservoir capacity shall be at least twice the stored
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hydraulic capacity of the accumulator systems.

Stored hydraulic volume of accumulators is volume between pre-charge

(1,000psi) and full rated WP (3,000psi).

We stick with latest editions which is now the API RP 5 edition and API
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16D 3 edition: reservoir capacity to be at least twice the stored hydraulic

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capacity of accumulator systems.

REMOTE CONTROL STATION

By API RP 53 3rd and 4th editions, only 1 remote station is required

which is Driller Remote Control Station. The extra station in Tool Pusher
office is “considered” but in practice we all have it there.

By API RP 53 5th edition and API 16D 3 edition there shall be 2 remote
rd

stations. 1 in Driller Dog House and another one at a safe location – Tool
pusher office.

SELF CHECK TIME

So the above are the excerpts from API RP 53 and of course some from
API 16D. Now let’s look at the operational things that we all need to
master:
 All RAMS + HCR: are supplied from Manifold pressure which is
regulated and set at 1,500 psi. There is a By-Pass Valve to by-pass this
regulator so that in case of shearing requires more than 1,500psi we will
activate this By-Pass Valve. At driller remote control station we CAN’T
adjust this manifold pressure.
 Manifold Regulator By-pass valve has 3 position: LOW position = 1,500
psi – this is where it is normally placed. Middle position = Will block
hydraulic supply to manifold – keeping manifold 3,000psi. HIGH
Position = Will send accumulator pressure 3,000psi to the manifold.
 Annular BOP: is supplied from 3,000psi main line, go through an
Annular Regulator set in range 200 – 1,500psi to the 3way-4position valve.
This is adjustable at driller control station.
 Diverter packer element + Port + Starboard ball valves: is supplied from
3,000psi main line go through Diverter Regulator regulating in range 500 –
1,500psi to the 3way-4position valves.
 Overshot Packer for bell nipple: is supplied from 3,000psi main line, go
through Overshot Packer Regulator set at 1,500psi to the 3way-4position
valve.
 How to operate the remote control station?
=> Remote panels are air interlocked, so there must be rig air supply (75-
110psi) to enable it.
=> Press and hold the master button while pressing the desired function
button – i.e “UPPER PIPE RAM CLOSE” or so.
 What happen when we press the CLOSE function of RAMS and HCR’s
(while pressing the master button of course)?
=> The 3way-4position manipulator will move, while it’s moving the Green
light is blinking, the operating piston moves and Accumulator Pressure will
be dropping, Flow meter will be running, Manifold Pressure will be
dropping. When the operating piston reaches its final travelling and forms
a seal, the flow meter will stop running, the accumulator pressure will
build back up to 2,910-3,000psi, the manifold pressure will build back up
to 1,500psi, the 3way-4position manipulator handle reaches the other side
and activates the proximity switch and the light stops blinking, the RED
light is ON now. There are proximity switches behind the handle of the
3way-4position valves to indicate its position.
 What happen when we press the CLOSE function of Annular BOP (while
pressing the master button of course)?
=> The 3way-4position manipulator will move, while it’s moving the Green
 light is blinking, the operating piston moves and Accumulator Pressure will
be dropping, Flow meter will be running, Manifold Pressure will not
change. When the operating piston reaches its final travelling and forms a
seal, the flow meter will stop running, the accumulator pressure will build
back up to 2,910-3,000psi, the 3way-4position manipulator handle
reaches the other side and activates the proximity switch and the light stops
blinking, the RED light is ON now. There are proximity switches behind
the handle of the 3way-4position valves to indicate its position.
 Confusion may incur when the light is blown off or the proximity switch is
damaged, thus we have to look at the pressure gauges and flow meter to
ensure the function is performed.
 For RAMS and HCR, what happen if we go down to the Koomey Unit
and put the 3way-4postion manipulator at MIDDLE position?
=> For RAMS & HCR’s, the 3way-4position valves are same type and they
look like this
When we put the lever/handle at the middle position the hydraulic power
supply is BLOCK and drain to reservoir on the supply side. On the
operating side (BOP side) the pressure in the lines is maintained, the
operating piston remains the last position. We only put the handle in the
middle position in Rig Move or when undergoing maintenance on BOP.

For ANNULAR BOP and DIVERTER, what happen if we go down to

the Koomey Unit and put the 3way-4postion manipulator at MIDDLE
position?
=> For Annular & Diverter, the 3way-4position valves are same type but
different from the ones for Rams and HCR’s, and they look like this

At middle position, the supply hydraulic line is BLOCKED, the element

of annular and diverter relaxes to original state so it pushes fluid in the
line, therefore the operating side lines are connected to the returning line
on the supply side and all drain back to reservoir.

Allow me to stop Part 1 here. If you have queries please put in comment
box and we’ll discuss. It takes time to compose the next part.

P/S – Additional notes:

1. At driller remote control station we can regulate the pressure for annular
BOP but we can’t regulate manifold pressure.
2. At normal drilling line up for hard shut in what should we see: All BOP
lights shall be green and the HCR’s shall be RED. Remote chokes and
manual chokes shall be closed. The manual gate valves upstream of the
chokes to be opened. Predetermine which remote choke to use and open
valves downstream of that choke to line up from choke to buffer tank to
MGS, and also pressure gauges.
3. On the Choke & Kill manifold – the gate valves are float type. So after
closing fully we need to back up 1/4 turn the hand wheel to ensure a good
seal of the floating gate.