BOP Control Systems Review

BOP Control Systems Review

- Deepwater BOP Control Systems – A look at reliability issues
(2003 OTC abstract)

- New generation of subsea BOP equipment
(2008 Drilling Contractor Magazine)

- Design evolution of subsea BOP
(2007 Drilling Contractor Magazine)

- Subsea Drilling Systems (Cameron)
Drilling control systems
Emergency systems

- Acoustic Control System for BOP Operation (Kongsberg)

- BOP Hydraulics and Fluid Requirements (Cameron)

- Code of Federal Regulations for a subsea BOP stack
Copyright 2003, Offshore Technology Conference
This paper was prepared for presentation at the 2003 Offshore Technology Conference held in
Houston, Texas, U.S.A., 5–8 May 2003.
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Abstract
Historically, drilling contractors have accepted without many
questions the reliability of the Blowout Preventer (BOP) com-
ponents and overall control system. A statistical reliability
approach to qualifying, purchasing, and maintaining deepwa-
ter BOP control systems should provide a high level of confi-
dence of being able to have long periods of time between
planned maintenance of these systems with very few, if any,
failures.
A study of deepwater BOP control systems has been per-
formed to look at reliability issues and a means to qualify
systems and components for a determined period between
maintenance. Of special attention are the regulators and how
they are typically arranged and used in the system. This paper
will describe a statistical process to determine the reliability
and failure rate necessary to accomplish the maintenance goal.
In addition, the qualification process will be described and a
discussion of the pressure control regulator issues discovered
in the study will be provided.
Introduction
Transocean, like many other offshore drilling contractors, re-
cently went through an extensive rig newbuild and upgrade
program, which required purchasing a significant amount of
customer-furnished equipment for the various shipyards. As
with most “boom” cycles, the industry activity before the
building cycle had developed ideas for new rig technology,
but lacked R&D resources to make them available to be manu-
factured as already proven systems. Therefore, this building
cycle, similar to all the rest, resulted in R&D efforts in parallel
with the manufacturing of new equipment to be installed on
new rigs. And, as before, this resulted in design and related
problems while in service that drove significant downtime, in
many instances.
At times, it appears the industry attitude is that we cannot af-
ford R&D in advance of a defined need. However, the indus-
try seems to be able to afford to fix the problems associated
with downtime due to an incomplete design.
Many of these problems are directly related to not having a
detailed set of design and functional specifications to give to
the equipment manufacturer. Plus, the purchaser usually does
not understand the duty cycle requirements, or demands, of the
particular equipment for an interval that is acceptable to per-
form maintenance on the equipment without sustaining down-
time.
For offshore floating drilling operations, especially in deep-
water, one of the most expensive downtime events is associ-
ated with having to pull the marine riser and subsea BOP be-
cause of a problem. Any problem or failure that requires the
riser and BOP to be round tripped will result in a cost of ap-
proximately $1.00 MM per event. And whether the contractor
or the operator absorbs this cost, it is expensive.
One of the more common causes for pulling the marine riser
and subsea BOP is associated with the BOP control system.
The deepwater BOP control system associated with dynami-
cally positioned (DP) rigs is typically a Multiplexed Electro-
Hydraulic (MUX) Control System. This is schematically
shown in Figure 1. The demand on the subsea control system
is initiated at the surface. The demand signal is multiplexed
down the control umbilical to the subsea control system.
There, the signal is decoded, confirmed, and performed. For a
demand that requires a BOP Ram to close, for example, the
multiplex signal would be received at the subsea control pod
and decoded. The decoded signal would cause a solenoid to be
opened electrically which would send a hydraulic pilot signal
to the proper hydraulic valve. This pilot signal would cause
the hydraulic valve to shift and send stored and pressurized
hydraulic fluid to the BOP Ram to be closed.
Therefore, the subsea BOP control system consists of two ba-
sic elements: electrical and hydraulic components. History has
shown that more subsea problems have been associated with
the hydraulic components than the electrical, causing the BOP
and riser to be retrieved for repair.
Each subsea BOP system has two complete control pods. Each
pod is capable of performing all necessary functions on the
BOP. While these systems may be considered redundant, any
major problem associated with one pod will cause the system
to be retrieved to the surface for repair. If a major problem is
found, the control of the subsea BOP is transferred to the other
OTC 15194
DEEPWATER BOP CONTROL SYSTEMS - A LOOK AT RELIABILITY ISSUES
Earl Shanks, Transocean; Andrew Dykes, ABS Consulting; Marc Quilici, ABS Consulting; John Pruitt, ABS Consulting
2 OTC 15194
pod and preparations will be made to retrieve the lower marine
riser package (LMRP) and riser to surface. Some minor prob-
lems may not require the system to be retrieved if considered
not necessary for critical operations.
Transocean has recently had an opportunity to review the ba-
sic design and requirements for Deepwater MUX BOP Con-
trol Systems. During this review, it was obvious: the best time
to perform major maintenance on a complicated BOP control
system was during the shipyard time of a mobile offshore
drilling unit (MODU) during its five-year interval inspection
period. This process would lead to minimal or no downtime
associated with BOP controls and allow for planning proper
resources during the maintenance period.
Therefore, a project was initiated to determine what would be
required to manufacture a control system that would require
major maintenance only on a five-year interval.
Reliability Discussion
A brief investigation into the specifications given to BOP
control vendors revealed that rarely was any equipment per-
formance requirements given. Very often, the system require-
ments were developed between the contractor engineers, op-
erations personnel, and vendors as the project progressed after
the purchase order was given. Reliability was assumed to be as
good as the previous systems built. Or, in the case of a new
design, it was assumed better than before.
During the bid and purchase negotiations between the con-
tractor and vendor, emphasis is typically given to the follow-
ing:
§ Number, type, and size of specific functions to be
provided. The BOP stacks of the newbuilds were
built with more functions and volume requirements
than in the past. Therefore, the control systems had
more components than before;
§ With a desire to make trouble-shooting problems
easier, the systems have more pressure and position
read-backs;
§ For ultra-deepwater applications, the working pres-
sure and volume of the stored hydraulic fluid in-
creased dramatically;
§ With the increased size of the two control systems on
the subsea riser package, careful attention was given
to the architecture of the system to fit in the space
available.
Currently, factory acceptance testing (FAT) requirements at
delivery of the system are generally were no more than func-
tion tests to ensure all functions work according to the piping
and function drawings.
When the systems are accepted and integrated in the BOP
stack, they are sent to the rig for continuing operations.
A new system on a rig generally has a learning curve associ-
ated with maintenance requirements. Maintenance schedules
are typically established as problems are discovered. Because
of the pressure on getting the equipment back to work, root
cause analysis of the failures is generally not performed. In
many operations, high maintenance is accepted as a necessary
evil to prevent downtime.
High maintenance can be a tool to reduce failures in operation.
However, this is a very expensive approach, and it is also an
opportunity to introduce human error into the system. Also,
this method does not establish reliability based on a failure
rate.
In general, operating reliability is maintained on rigs mostly
through regular maintenance intervals rather than specifying a
reliability of a system or component to minimize maintenance.
Project Scope of Work
Floating drilling rig downtime due to poor BOP reliability is a
common and very costly issue confronting all offshore drilling
contractors. Transocean, as a major player in offshore explo-
ration worldwide, operates numerous floating rigs of various
capabilities and configurations. Depending on the drilling
contract in place and the nature of the downtime cause, BOP
failure can result in substantial revenue loss for the drilling
contractor.
In order to reduce the risk of revenue loss to the contractor or
operator, Transocean is committed to actively pursuing im-
provements in BOP reliability at all levels during the equip-
ment lifetime, including the design stage. As part of this proc-
ess, individual BOP component reliability goals are necessary
to ensure that the desired overall BOP reliability target is
achieved.
Since the hydraulic components of the control system histori-
cally have had more problems that have required the riser and
BOP stack to be pulled, the first efforts were directed at the
hydraulic system, including all hydraulic stack-mounted com-
ponents. The systems under review consist of the solenoid
pilot valve through to the end function.
The following reliability goals were established for the sole-
noids and hydraulic components:
§ Overall service life of system is 20 years;
§ Pressure regulators maintenance 5 years, body 20
years;
§ Solenoids 20 years, body 20 years;
§ Solenoid shear seal valves maintenance 5 years, body
20 years;
§ SPM valves maintenance 5 years, body 20 years;
§ Shuttle valves maintenance 5 years, body 20 years;
§ Other valves maintenance 5 years, body 20 years;
§ Hoses with couplings 5 years;
§ Piping and connections 20 years.
OTC 15194 3
Also, a method was established to design a specification to
operate a Subsea BOP system for five years without needing
to pull the system to the surface for unplanned maintenance;
this project determined the method to design a specification to
meet this goal. This discussion focuses on the reliability test
specification that is necessary to ensure the use of highly reli-
able components that will result in the hydraulic control sys-
tem meeting this objective.
The need for highly reliable sub-sea BOP system components
results from the following assumptions that are based on ac-
tual experience.
§ The BOP has a large number of hydraulic control
system components;
§ During a 5-year period, an individual valve will get
cycled many times;
§ Within the current design, a failure of any one of the
control components may require pulling the BOP to
the surface.
This paper estimates the magnitude of the testing requirements
necessary to demonstrate the desired level of reliability. This
is accomplished by scoping the mission success criteria based
on a representative system configuration and a detailed analy-
sis of the required testing. Next, an estimate of the component
failure rate goals is established based on the desired opera-
tional reliability of the system and the test demands that vari-
ous component-type groups within the system are expected to
be exposed to over the desired duration (5 years). Then, an
estimate is made of the number of cycles of a reliability testing
program required to provide confidence that the components
will perform reliably to achieve the BOP hydraulic control
system reliability goal.
This scope of work is accomplished by addressing the fol-
lowing major categories:
§ Control System Design Considerations – This proc-
ess will look at all components to be considered in
the study and group the components into “Family”
types for further analysis;
§ Estimate of Component-Type Reliability Require-
ments – The requirements of each component for the
maintenance interval will be determined and a reli-
ability goal is established to meet the criteria;
§ Elements of the Reliability Testing Plan – Each fa m-
ily of components has its own failure rate goal to
meet the overall failure rate goal of the system;
§ Amount of Testing to Provide Statistical Confidence
– The amount of testing to satisfy the failure goals
and desired statistical confidence is specified;
§ Component Testing Program – Test program to meet
the stated goals.
Control System Design Considerations
Component Family Type Grouping Within System
A representative rig was chosen to perform the study. This
was a 5
th-
Generation DP semisubmersible capable of drilling
in water depths to 10,000 feet. A worksheet was developed to
provide a complete listing of the components in the hydraulic
control system. Family types group the components. The term,
“Family Type,” refers to the general function that the valves
accomplish (e.g., pilot valve, check valve, shuttle valves, etc.)
It is assumed that within a given component type the comp o-
nent designs are similar enough to assume that the reliability
performance of the components may be modeled by one fail-
ure rate, regardless of size. The family types are listed below
along with an indication of the number of components of that
family within the representative system.
Check Valves - There are 22 check valves.
Pilot Assisted Check Valves – There are 6 pilot as-
sisted check valves.
Piloted Hydraulic Valves – Dual Function –There are
38 dual-function pilot valves,
Piloted Hydraulic Valves – Single Function –There
are 42 single-function pilot valves.
Regulators - There are two types of regulators, four
manually set regulators and eight hydraulically con-
trolled regulators. The operational success criteria for
the regulator valve are still under evaluation. The
“demands” associated with the regulator relate to the
pressure control function performed during periodic
testing of specific functions, which is required over
the period during which the control valves are being
cycled. The severity of the challenges depends on
factors in the system that is still being investigated.
Shuttle Valves – There are 74 shuttle valves used in
the system.
Solenoid Valves – There is no variation in solenoid
valves. All 142 valves are 1/8”, 3 way, 2-position
valves.
Estimate of Component-Type Reliability
Requirements
The goal of this project is to develop a control system that has
the potential to operate 5 years between major maintenance
without a failure. However, to have a starting point for devel-
oping failure rates, it was established that an acceptable failure
rate would be one failure in 10 years that would cause a BOP
stack to be retrieved to the surface.
Operational Test Summary
An Operational Test Summary worksheet was established
showing the BOP operational testing program for the BOP that
constitutes the 5-year success criteria for the hydraulic control
system. The results for a 10-year period was also established
to develop targeted failure-rate goals. The mission is based on
the participation of valves in various subsystems of the BOP
in a functional testing program of the BOP, both on the sur-
face and subsea. The test program consists of 7 separate BOP
Control tests that are conducted over a typical 8-week well
drilling operation. An 8-week average per well drilled was
assumed. Therefore, for a 5-year duration, approximately 33
wells would be drilled. For a 10-year interval, 65 wells would
be drilled.
The component function cycles were established by the fol-
4 OTC 15194
lowing test sequences:
Test 1. – Function tests a BOP Control function when
the stack is retrieved to surface, without pressure
testing. This is to remove salt water in the pod.
Test 1A – Emergency Disconnect Test and Remote
Operated Vehicle Tests.
Test 2. – Surface pressure test prior to running BOP.
Test 3. – Run and land BOP, lock wellhead connector
and line up BOP valves for drilling operations.
Test 4. – Bi-weekly subsea pressure and function test
for the duration of the well.
Test 5. – Line up valves in preparation of pulling
BOP. Unlock wellhead connector and adjust accu-
mulator pressure on trip to surface.
This worksheet calculated the total number of component
functional cycles based on the years of service that will form
the basis for the reliability requirement. Figure 2 is a summary
of the component functional cycles occurring due to the op-
erational test sequences by Family Type. This summary shows
the resultant total number of demands for valve position
changes over the specified operational testing period. It can be
seen in this summary, over 87,000 valve-cycle demands would
have to be performed successfully subsea. And, almost
140,000 total cycles would occur during the 5-year period.
Specification of Reliability Goals
A Reliability Goal Evaluation provided a means to estimate
individual component failure rate goals based on system reli-
ability goals. Figure 3 represents a worksheet used to provide
an interactive tool for evaluating different reliability goals. As
shown, it is an estimate of the component-type group failure
rates required to produce an average of 1 failure, among all six
component types, within the hydraulic control systems per rig
per 10-years of operation.
The estimate is designed to produce component failure rates
that produce a system reliability that has been “balanced.” As
every component must function successfully when required
during tests, the BOP hydraulic control is a series system; its
reliability is modeled by the product of the reliabilities of all
the components. This is done in two stages. First, an equal
reliability requirement is allocated to each component-type
group. Then the reliability requirement is allocated to each
component within that group through the specification of a
failure rate that will produce the component-type reliability
when applied against the total number of test demands for that
group. The resultant component failure rates are given in the
column labeled “Comp onent Failure Rate Goal.”
Those component types that must respond to the most de-
mands should be the most reliable, which agrees with common
sense. For example, Solenoid Operated Valves are exercised
about twice as much as any other component type. Conse-
quently, they should have the lowest failure rate. Conversely,
those valves that are not challenged as often as others can have
somewhat higher failure rates without becoming a dominant
contributor to failure.
A number of sensitivity studies with the worksheet developed
the table at the bottom of the worksheet. It illustrates the cur-
rent reliability of the system and the required improvement in
failure rates needed to achieve system reliability goals of up to
95% over a 5-year period. This table shows that very low fail-
ure rates are needed to achieve a high reliability.
As shown, the upper two tables reflect the goal of averaging
one failure per rig per 10 years of operation (65, 8-week test
cycles or wells drilled). The system reliability goal is varied
until component group failure rates are obtained that as a
composite produce an expected value of 1 failure over the
more than 171,000 subsea valve demands made during that
period. The values in the “Comp. Failure Rate Goal” column
then becomes the failure rates to be demonstrated by the reli-
ability testing program.
Elements of the Reliability Testing Plan
Each group of similar valve types needs to undergo reliability
testing to provide confidence of its failure rate. If any one of
the valve types has a significantly higher failure rate than its
failure rate goal, it will generate a “weakest link” system
whose reliability would be dominated by that component. The
failure rate goal for each of the Family Groups is shown in
Figure 4.
A binomial process for demand-related failures and the Pois-
son process for time-related failure modes may represent the
failure rate. Both of these processes assume that observed fail-
ures result from random failures of a population of comp o-
nents characterized by a failure rate independent of the previ-
ous life cycle of the valves under test. This implies that:
§ A FAT has verified that manufacturing defects and
any infant mortality failure mechanisms are not pres-
ent;
§ The total cycling of the valve is not of an amount to
cause wear that is significant enough to precipitate
wear-out failure mechanisms.
For demand-related failures, when the failure rate is low and
the number of demands is large, the binomial process may be
approximated by a Poisson process, so that the formulation of
the statistical analysis of both time and demand related is
mathematically the same, with only the units differing. (The
Poisson process relates a continuous time-related failure
mechanism with units of failures/unit of time. A large number
demands may be considered to occur over time, so the simi-
larity of form should not be difficult to accept.)
Valves placed under test must be randomly selected in order to
be representative of the population. If the vendor conducts the
test, the components to be tested should be selected by some-
one independent from the vendor.
The design of the test will depend on the historically observed
failure mechanisms that contribute to failure.
§ If cycling the valves put stress on them, then the reli-
ability tests should involve repeated operational
evolutions where they are demanded to open and
OTC 15194 5
close in accordance with the operational require-
ments;
§ If exposure to the subsea environment precipitates the
failures, the test must include exposure to these con-
ditions, or more severe conditions that can accelerate
the mechanisms, for a period of time that can simu-
late the total exposure.
As both mechanisms are most likely involved, the reliability
test needs to address both environmental exposure and opera-
tional evolutions.
Testing alone does not improve reliability or guarantee that no
failures will occur within a given time frame. It verifies that
systems and components are reliable or serves to identify
weak spots if they are not. To be effective, a reliability test
needs to account for the following:
§ The tests need to be similar to actual operational con-
ditions;
§ The duration and/or operational evolutions in the test
needs to be large enough to provide confidence that
the needed reliability can be achieved;
§ The root causes of any observed failures and anoma-
lies need to be identified and corrected.
Testing done by specific purposes, such as burn-in, FAT and
endurance testing to identify wear-out life, can provide indi-
rect evidence that will increase confidence that a group of
similar valves will perform its mission successfully.
Amount of Testing to Provide Statistical Confidence
Classical statistics relies strictly on outcome of valid tests or
actual experience to provide statistical confidence in the reli-
ability of a system or component. The higher the reliability
requirement, the more tests needed to provide that confidence.
The confidence limit is a means of judging the impact of the
uncertainty of the component failure rates. When one estab-
lishes failure rate estimates on the results of reliability tests or
samples from actual experience, it must be recognized that any
given sample result can be produced by populations with dif-
ferent failure rates. The confidence limit is a means of ex-
pressing the probability that the sample result might have been
the result of a “lucky” statistical outcome of a population that
actually has an unacceptably high failure rate. That is, if the
test were repeated again, the result would most likely be
worse.
For the BOP system, it is assumed that the failure rate of all
components within each of the 6 component-type groups, de-
fined previously, can be modeled by a single-component
group failure rate. The impact of component failure rate un-
certainty on the uncertainty of system failure rate is illustrated
by Figure 6. The curve on the left-hand side of the chart repre-
sents 1 of 6 components having equal failure rates (equivalent
to the 6 component-type groups in the BOP hydraulic control
system). The curve is typical of the uncertainty in failure rates.
It illustrates that one does not have to demonstrate component
reliability to a very high confidence limit when it is part of a
larger series system. With many random variables, the impact
of the higher end of the distribution of 1 component tends to
get balanced by the lower portions of the distributions of other
components. For this 6-component series system, an 80% con-
fidence that each component group failure rate <0.006/mission
produces 90% confidence that the system FR is no more than
0.036/mission. This means that one can achieve reasonable
confidence of a given system reliability with less test cycles
for the individual component groups.
Using the system reliability goal of 1 failure per 10 years of
subsea operation. Figure 5 was generated from a Poisson
worksheet. The table illustrates the number of test cycles with
no failures required to meet the failure rate goals with 80%
confidence for each of the component family groups.
Component-Testing Program
The component-testing program should focus on exercising as
many different hydraulic control system component types as
possible within an integrated test bed capable of mimicking
functions associated with the hydraulic control subsystems.
Such a test bed should require that subsystem and component
interfaces be adequately tested under the range of operational
and environmental conditions expected during actual subsea
operations. It is anticipated that there are many functional
similarities among the 8 subsystems, such that a representative
test bed could be designed and built which would also be at a
scale that would permit enclosing it in a suitable environ-
mental chamber
Each type of control system will probably have its own re-
quirements for a specific reliability test, such as number of
components and number of cycles that should be in the pro-
gram. However, the following types of tests should be i n-
cluded:
§ A test to verify that manufacturing defects that leads
to early infant mortality are not present. (The valve
manufacturer should be doing this before it delivers
the valve);
§ Tests that demonstrate the anticipated operational life
of the components in the anticipated subsea environ-
ments. This test would need to identify controlling
parameters and correlate accelerated testing condi-
tions to those parameters so that confidence in the
operational life can be obtained in a reasonable pe-
riod of time;
§ Reliability tests on a suitable test bed that simulates
subsea conditions of a set of components comprising
all the major component groups and interfaces. This
test bed should be able to exercise the components
over all the significant operational evolutions that
would be required in the actual BOP system;
§ Product-acceptance tests for batches of components
being delivered by vendors;
§ Post-maintenance tests for field use that can assist in
verifying that the component has been returned to an
acceptable condition.
6 OTC 15194
The program should focus on known problems based on
tracking previous problems, but it also needs to maintain some
kind of confirmatory testing for all component groups.
Pressure Regulators
Most components in a control system, such as solenoid valves,
piloted hydraulic valves, shuttle valve, etc., have a discrete
number of cycles in a 5-year life and can be determined by
knowing the frequency of BOP tests or operations. However, a
regulator typically has many cycles during a large volume
demand function such as an annular close. Figure 7 shows a
sample of the original modeling of a pipe ram close for a pre-
vious project. Obviously, there appears to be a lot of activity
of the regulator position during the function.
And, clearly, it would be impossible to determine the number
of cycles, or movements, of the regulator in a 5-year period.
Therefore, an additional project has been initiated to determine
if the regulator spool can be controlled or calibrated to be able
to determine its cycle behavior under various volume de-
mands. This project is on going.
Conclusions
The process described in this paper is contrary to how the off-
shore industry typically specifies its equipment. Historically,
functionality has been the primary focus of bid specifications.
However, the content of this paper shows it is feasible, and
should be practical, to specify the equipment used on our Mo-
bile Offshore Drilling Units (MODU’s) by performance speci-
fications which meet our planned requirements.
It must be noted that component failures are random events
and may still occur. However, demonstrated component reli-
ability at this level provides a high confidence that significant
downtime can be minimized over the drilling cycle.
Obviously, the requirements contained in this paper will re-
quire additional R&D by the vendors as well as a greater effort
by the purchasers to understand and specify the requirements
for any particular system. The end result of purchasing a more
reliable system will be some form of additional cost. Plus, the
vendors that can deliver a control system that can go 5 years
without maintenance will only see spare purchases once every
5 years for each rig. The desire of vendors to provide this type
of equipment and service should allow a possible new eco-
nomic model to be developed which allows the vendor, con-
tractor, and operator to share in the savings resulting from no
controls-related downtime.
OTC 15194 7
FIGURE 1. Multiplex Electro-Hydraulic Control System
FIGURE 2. Estimated Cycles
8 OTC 15194
FIGURE 3. Reliability Goal Spreadsheet
FIGURE 4. Component Failure Rates
OTC 15194 9
FIGURE 5. Component Testing
FIGURE 6. Confidence Level for Component Group and System
10 OTC 15194
FIGURE 7 Regulator Piston Position
96
March/April 2008
D R I L L I N G CON T R A CT OR
WE L L C O N T R O L
New generation of subsea BOP equipment,
controls smaller, stronger, cleaner, smarter
WITH THE HIGH price of oil , it’s
become more economical to go to deeper
water depths and more challenging reser-
voirs . With those more challenging reser-
voirs, comes a whole new set of problems
designing the next generation of drilling
rigs and subsea BOP equipment. Those
new challenges have inspired a new age
of BOPs that have been made smaller by
reducing the number of stack-mounted
accumulators, stronger by increasing the
available shear force, cleaner by develop-
ing a complete fluid recovery system, and
smarter by improving the control system
diagnostic systems.
DEPTH COMPENSATED
ACCUMULATORS
Today’s designed operating environment
for stack-mounted accumulators is chal-
lenging. Design criteria include 12,000-ft
water depths, temperatures as low as
40ºF and surface temperatures of 120ºF,
rapid discharge (Adiabatic), as well as
higher minimum system pressures.
All of these things add up to a large
number of bottles on a lower BOP stack.
It is not uncommon to see as many as
126 accumulator bottles on a lower BOP
stack, 98 of which are dedicated to the
shear system alone (Figure 1). This adds
weight to the overall assembly, increases
maintenance requirements and decreases
stack equipment access. By using the
water column pressure and mechanically
boosting the hydraulic pressure, a depth
compensated accumulator has reduced
the total number of stack-mounted shear
circuit bottles from 98 conventional
6,000-psi, 15-gallon accumulators to seven
depth compensated bottles (Figure 1).
Before we can understand how this hap-
pens, it is important to understand what
effect the subsea operating environment
has on accumulators and gas. There
are three major factors that effect gas
performance subsea: temperature, dis-
charge type and water depth.
TEMPERATURE
Colder gas equals d enser gas. Take
this example problem using a 15-gal-
lon, 6,000-psi accumulator. A surface
temperature of 120ºF is used, assuming
the bottles are in the sun on the vessel
before it is deployed and are charged to
the maximum rating for those bottles of
6,000 psi. The effect on the gas from a
reduction in temperature to 40ºF is the
gas pressure reducing to 4,785 psi. More
than 1,200 psi precharge pressure is lost
just from reducing the temperature.
ADIABATIC DISCHARGE
Adiabatic discharge equals rapid dis-
charge. T he definition of an “adiabatic
process” is a process by which no energy
is absorbed or released into the environ-
ment. When compressing a gas, that
process will heat the gas. Conversely,
when decompressing a gas (accumulator
discharge), the gas gets colder.
Accumulators dedicated to shear are
rapidly discharged, and there is no time
for the outside temperature to re-heat
the gas. Therefore, when the gas is dis-
charged, it is colder in its discharged
state. Remember, colder gas equals
denser gas; therefore more gas is needed
to compensate for this condition. About
twice as much gas is required for an
adiabatic discharge compared with
an isothermal discharge (isothermal
assumes the environment has time to re-
heat the gas, and it stays at a constant
temperature).
WATER DEPTH
Deeper water equals lower compression
ratio. To understand how water depth
effects gas performance, there is a basic
measure of gas performance called
“compression ratio.” Compression Ratio
is:
min
max
P
P
CR =
Where:
• CR = compression ratio
• P
max
= maximum system pressure, the
pressure at which the system pumps
turn off.
• P
min
= minimum pressure required to
operate a function, i.e., 3,000 psi for the
shear rams.
The higher the compression ratio, the
more springy the gas is, the better it
performs. For example the compression
ratio at surface is:
1. 7 6 6
3000
5000
min
max
= = =
psi
psi
P
P
CR
Surf
When the bottles are placed subsea,
the pressure created from the water
column from depth is additive to those
pressures. Therefore the compression
By Frank Springett and Dan Franklin,
National Oilwell Varco
Figure 1: In this comparison of lower BOP stacks, the configuration on the left has
15-gallon, 6,000-psi N2 accumulators that can add up to more than 100, with 98
dedicated to just the shear system. At right are depth compensated accumulators that
reduce overall assembly weight and maintenance needs.
97 March/April 2008
WE L L C O N T R O L
D R I L L I N G CON T R A CT OR
ratio at a 12,000-ft water depth (5,350 psi
pressure from water column) becomes:
1. 4 2
8350
10350
0 0 0 3 0 5 3 5
0 0 0 5 0 5 3 5
12000
= =
+
+
=
psi
psi
CR
ft
Therefore, the gas compresses less and
more volume (bottles) must be added to
compensate (Figure 2).
For the following condition, one 15-gal-
lon, 6,000-psi nitrogen accumulator
yields only half a gallon of usable vol-
ume.
• Discharge type = adiabatic.
• Surface pressure = 5,000 psi to 3,000
psi.
• Surface temperature = 120ºF
• Subsea temperature = 40ºF
• Water depth = 12,000 ft
For those same conditions but at a water
depth of zero (at surface), the usable vol-
ume is 2 ½ gallons. Imagine being able
to have accumulators perform subsea
like they do at surface. That is exactly
what has been accomplished with the
depth compensated accumulator. Figure
3 shows how it works.
The system is comprised of a double
piston accumulator, with the two pistons
connected by a connecting rod. This con-
figuration creates four distinct chambers
in the accumulator.
The first chamber has a vacuum or very
low pressure in it; the second chamber is
exposed to sea water pressure. The sea
water pressure (5,350 psi at 12,000 ft)
acting on the piston, with the vacuum on
the opposite side, creates a large force
on the piston connecting rod. The third
chamber has system hydraulic fluid, and
it counters the sea water pressure by
holding the same pressure (5,350 psi).
Now add nitrogen in the fourth chamber,
and it further adds to the third cham-
ber’s hydraulic pressure (5,000 psi),
boosting the hydraulic pressure to 5,000
+ 5,350 = 10,350 psi. The compression
ratio for the nitrogen pressure in opera-
tion at 12,000 ft water depths is the same
as it is at surface.
1. 7 6 6
2400
4000
=
psi
psi
CR
Surf
So how does the depth-compensated
accumulator perform relative to other
industry solutions? Figure 4 shows how
nitrogen and helium perform with a
6,000-psi and 7,500-psi bladder or piston
accumulator. Helium can only be used
with piston accumulators, and the gas
needs to be transported out to the rigs.
Nitrogen is available on some rigs via a
nitrogen generator and high-pressure
compressors. Note the comparison is
in percentages, which shows how much
gas is required for a particular function,
regardless of volume of the function.
As can be seen in Figure 4, the depth
compensated accumulator is a major
improvement over existing industry solu-
tions.
5000 psi
1
2
,
0
0
0

f
t
D
E
P
T
H
Pump
BOP
10350 psi
= 1.67
5000
3000
Surface
= 1.24
10350
8350
Subsea
100%
87%
63%
52%
0%
25%
50%
75%
100%
6000 psi - N2 7500 psi - N2 6000 psi - He 7500 psi - He DCB
NITROGEN
Helium
25%
DCB
Figure 2 (above): Compression ratio mea-
sures the effect of water depth on gas
performance, where deeper water equals
a lower compression ratio.
Figure 3 (left) shows how a depth com-
pensated accumulator works.
Figure 4 (below) compares the depth
compensated accumulator with existing
industry solutions.
98
March/April 2008
D R I L L I N G CON T R A CT OR
WE L L C O N T R O L
22-IN. 5,000-PSI
SHEAR OPERATORS
The more challenging drilling environ-
ments have required that drill pipe
become stronger, tougher and heavier.
Because of this, higher shear forces
are required. Previous systems have
been limited to 1.2 million lbs of shear
force, where as the next generation of
BOP operator is capable of 1.9 million
lbs . These shear rams have three basic
features : high shear force, tail shaft lock
and split piston .
HIGH SHEAR FORCE
Shear force is a function of cylinder
size, tandem booster configurations, as
well as hydraulic pressure capacity. The
largest system manufactured in the past
by National Oilwell Varco has been a
14-in. main piston with an 18-in. booster
at a maximum pressure of 3,000 psi,
which creates 1.2 million lbs of shear
force. The next generation of BOP opera-
tor has a single piston 22 in. in diameter
(approximately the same area as the
14x18 configuration, but shorter and
easier to manage) and is designed to use
a maximum continuous system operating
pressure of 5,000 psi, yielding a shear
force of 1.9 million lbs.
TAIL SHAFT LOCK
Industry regulations require that an
automatic lock be utilized that will
maintain BOP integrity should there be
a loss of hydraulic pressure. The 22-in.
5,000-psi shear operator has a tail shaft
locking mechanism that is both simple
yet robust. On the tailshaft of the opera-
tor, there is an upset (reduction in diam-
eter) at the end of the tail shaft. When
the shear operator closes nearly all the
way, a series of radial locking dogs are
exposed to the upset on the tail shaft. A
secondary piston drives the lock dogs
on to the tail shaft. Once the ram is all
the way closed, the lock dogs are com-
pletely recessed on the tail shaft upset,
and the secondary locking piston passes
completely over the top of the lock dogs,
preventing them from moving out radi-
ally again should hydraulic pressure be
lost. (See Figure 5.)
SPLIT PISTON
Further to this system, there is an inno-
vative split piston system integrated into
the 22-in., 5,000-psi shear operator. In
order to understand why this split piston
design is required, first we must look at
the force balance equation for the shear
operator, as well as the shear rams with
their associated seals. Once the tubular
has been sheared, and the shear opera-
tors are nearly fully closed, the shear
ram contacts the shear ram on the oppo-
site side. There are rubber seals inside
the shear ram blocks, which is what the
rams react against. The area of rubber
that makes contact is 12.5 sq in. Without
the split piston, the entire force from the
shear operator (1.9 million lb) is reacted
on that area (Figure 5), creating a poten-
tial rubber pressure of:

psi
in
lbs
in
psi in
P
rubber
2 5 1 , 0 0 0
2 1 .5
1, 0 0 9 , 0 0 0
2 1 .5
5000 380
2 2
2
= =
×
=
In order to alleviate this, there is an
outer and inner piston. The outer piston
has a diameter of 22 in., which is used
through all of the stroke of the shear
operator with the exception of the last
½ in. The inner piston has a diameter
of 12 in., and it slides inside the outer
piston during that last ½ in. of stroke.
The force created by the inner piston is
565,000 lbs (Figure 6), which in turn cre-
ates a much smaller rubber pressure of
45,000 psi.

psi
in
lbs
in
psi in
P
rubber
5 4 , 0 0 0
2 1 .5
5 6 5 , 0 0 0
2 1 .5
5000 113
2 2
2
= =
×
=
By reducing the rubber pressure, the
rubber has less of a tendency to extrude
which in turn increases rubber life.
Lower rubber pressure also reduces the
stresses on the shear ram blocks as it
does not need to contain as much rubber
pressure.
FLUID RECOVERY SYSTEM
Some area regulations require that the
BOP control fluid be recovered for envi-
ronmental reasons. Today’s systems are
designed such that the hydraulic fluid is
water-based with additives to add some
lubricity and anti-corrosion character-
istics. In many areas of the world, this
fluid is considered environmentally safe;
therefore, when a BOP is operated, its
exhaust fluid is dumped to the environ-
ment (sea). Figure 7 shows a basic lay-
out for a conventional system.
An easy way to recover the fluid could be
to run a return line to surface, wouldn’t
it? Unfortunately, this is not the case, as
the high return flow rates create high
Figure 5 (top): Without the split piston, a potential rubber pressure of 152,000 psi is
created. Figure 6 (bottom): By using an outer and inner piston, a much smaller rubber
pressure of 45,000 psi is created.
F = 1,900,000 lbs
A = 12.5 in2
22”
A = 380 in2
P = 152,000 psi
12”
F = 565,000 lbs
A = 12.5 in2
A = 113 in2
P = 45,000 psi
100
March/April 2008
D R I L L I N G CON T R A CT OR
WE L L C O N T R O L
back pressures. The high back pressure
can then cause other BOP functions to
inadvertently close. This phenomena
is created by the difference of area
between open and close side of a BOP
operator (area of close side > area of
open side). The high back pressure acts
on both those areas simultaneously,
which then creates a net force closing
the rams (Figure 8).

k c a B s s e r p Area k c a B s s e r p Area Force
Opening o l C g o l C g
. .
sin sin
× − × =
This force can be as high as 60,000 lbs,
plenty of force to close the BOP opera-
tor. The solution to this problem is to
pump the fluids to surface with a com-
plete fluid recovery system. The system
design and its components can be seen
in Figure 9.
PUMP
A reciprocating pump was designed to
keep the system simple, easily powered
by hydraulics and to use as much exist-
ing subsea technology as possible. The
flow capacity and the ratio of hydraulic
power section to discharge pumping sec-
tion is a function of discharge pressure.
Discharge pressure is a function of the
length and diameter of the return tube
and pump discharge flow. The piping
used to pump the fluid to surface is one
of the rigid conduit lines on the riser
(12,000 ft and 2.32-in. inside diameter).
Some annular functions can see inter-
mittent flows of up to 225 gallons/min ,
which equals a back pressure of up to
4,000 psi. A pump this size (225 gallons/
min , 4,000 psi discharge pressure) would
be exceedingly large and consume too
much hydraulic fluid to pump it to sur-
face. It was decided to design a more
reasonable, smaller pump and add a
reserve capacity. The decided ratio of
the hydraulic section to the discharge
section was 6:1, which yields a discharge
pressure of 500 psi.
At 12,000-ft water depths, the flow
capacity is approximately 60 gallons/
min. Over- and underpressure protection
was added to the returns line to ensure
the integrity of the system when it is
deployed or should the fluid recovery
pump fail, the fluid is dumped to the
environment and the BOP can still func-
tion in an emergency situation.
RESERVE CAPACITY
The reserve capacity serves two pur-
poses. First, it provides a surge capacity
for the high return flows from the BOP s
when the return flow is greater than the
Figure 7 (right) shows
the basic layout for
a conventional fluid
recovery system. Fig-
ure 8 (below, middle)
shows that in a
conventional system,
high back pressure
can cause other BOP
functions to inadver-
tently close. Figure
9 (bottom) shows a
fluid recovery system
that can resolve this
problem.
BOP Operator
VENT TO SEA
Pressure = 5350 psi
Subsea
Bottles
Surface Bottles
Pump
Valve
Control
POD
Area Open < Area Close
Return P = 2000+ psi
O
v
e
r

2
0
0
0

p
s
i
B
a
c
k

P
r
e
s
s
u
r
e
INADVERTANT
CLOSURE!!!
RETURN LINE TO
SURFACE
PRESSURE
PROTECTION
Sea Level
BACK PRESS REG VALVE
Compensates for Density difference
between SW & Hyd Fluid
Surface Bottles
Pump
BOP Operator
Subsea
Bottles
Valve
Return Press < Sea Water Press
RESERVE
CAPACITY
Allows for
smaller
pumps
MINI PISTON
Keeps Return
System below SW
Press
Pumps Fluid
Back to
Surface
FLUID
RECOVERY
PUMP
102
March/April 2008
D R I L L I N G CON T R A CT OR
WE L L C O N T R O L
pump flow rate. Once the high return
flow surge has ceased (the BOP has
closed/opened), the pump can continue
to pump out the reserve capacity. The
second function equalizes the pressure
between the environment (sea water)
and hydraulic returns. By equalizing the
pressure for the return fluids, the sys-
tem acts the same as a system without
the fluid recovery system. The reserve
capacity is comprised of an 80-gallon
bladder type accumulator . Hydraulic
returns are fed into the steel side of the
accumulator. Sea water is introduced
into the bladder side of the accumulator,
and the bladder is the barrier between
the two.
MINI-PISTON
The challenge is to keep the hydraulic
fluid evacuated from the reserve capac-
ity bottle when the BOP s have been func-
tioned. This is performed via an innova-
tive mini-piston that keeps the hydraulic
return side of the reserve capacity at
a slightly lower pressure (up to 45 psi)
than the sea water pressure. Figure
11 shows a cross section of the fluid
recovery pump, where the mini piston is
identified. It is simply a tube that always
has system pressure on it. This tube and
associated pressure forces the piston
down creating a negative pressure on
the return volume, as well as compensat-
ing for seal drag on the pistons of the
pump.
BACK PRESSURE
REGULATING VALVE
The density of sea water is heavier
than that of the water-based hydrau-
lic fluid. Although they are very close,
the difference in pressure at 12,000-ft
water depths can be as high as 150 psi.
Without a back pressure regulating
valve, the under-pressure protection
valve would open, allowing sea water
to enter the return line until the pres-
sures equalized. With the back pressure
regulating valve located on the return
line, this issue is resolved. The pressure
setting of the back pressure regulating
valve is set to the equivalent density dif-
ference between the fluids at depth.
PUMP CONTROLS
The hydraulic pump controls are
simple, passive and use existing valve
components. The MUX control system
only needs to command when the fluid
recovery system is to be turned on, the
reciprocating motion of the pump is done
via mechanical and pilot actuation of the
valves on the pump, no discrete input/
output is required for the reciprocating
motion of the pumps. Once the reserve
capacity is evacuated, the pump stalls
and waits for another BOP function to
be fired. The valves used are the same
types of valves used on BOP control sys-
tems for the past 20 years.
SMART CONTROLS
Imagine a control system that knows it
will fail before it fails. The more chal-
lenging reservoirs and higher burden
rates require this level of diagnostics.
Let’s look at a basic overview of the
control system to understand how this is
possible (Figure 10).
On the vessel, at the surface, are redun-
dant controllers, which communicate
commands to the BOP via the MUX
cable. Once the MUX cable reaches the
BOP stack, commands are received by
the redundant control pods. In the pod
are input / output bricks that convert
those commands to signals to drive the
solenoids or other field devices.
MUX CABLE MONITORING
The MUX cable is comprised of both
fiber cores for communication, as well
as copper cores to transmit power to the
BOP. It is probably one of the most criti-
cal, complicated, robust and expensive
cables on a rig today. Because of the
critical nature of the cable, continuous
monitoring has been implemented. The
fiber signal strength can be measure by
db of light signal, and the copper cores
are measured by ground fault monitor-
ing. The monitoring is then trended over
time to see if there has been any degra-
dation of any particular portion of the
cable and can be rectified prior to loss
of signal.
SYSTEM CHECK
Monitoring the MUX cable is only one
part of the electrical controls for the
BOP stack. To check the rest of the sys-
tem, a complete system test is performed
every 8 minutes. The system test checks
the signal from the controller to the pod,
through the output brick to the solenoid
by sending a command for each sole-
noid to fire for 5 ms. This time isn’t long
enough to actuate the hydraulic valve,
but it is long enough to confirm the
integrity of all the system components.
In the event that one of the redundant
system components fails, an alarm is
activated.
In conclusion, the next generation of
BOP stacks and controls are smaller, by
advent of an innovative depth compen-
sated accumulator; stronger, by increas-
ing the piston size and designed to con-
tinuously operate at 5,000 psi; cleaner,
by way of a complete fluid recovery sys-
tem; and smarter, by continuously moni-
toring MUX cables and doing frequent
complete system checks.
About the authors: Frank Springett, a new
product line engineer with National Oilwell
Varco, has 13 years of experience in the petro-
leum industry . He is a mechanical engineer
by training and holds a B.S. in mechanical
engineering and marine engineering technol-
ogy from the California Maritime Academy.
Dan Franklin is the engineering manager for
Koomey Control Systems at National Oilwell
Varco. He is an electrical engineer by train-
ing and holds a B.S. in electrical engineering
from the University of Nebraska.
This article is based on a presentation at the
IADC International Well Control Conference &
Exhibition, 28-29 November 2007, Singapore.
Figure 10: An overview of the subsea control system that provides high-level diagnostics.
36
May/June 2007
D R I L L I N G C O N T R A C T O R
S P E C I A L MA R I N E E D I T I O N
Desi gn evol uti on of a subsea BOP
THE FIRST RA M BOP was devel-
oped in 1920, and, in the last 90 years,
the principle of operation of a ram BOP
has not deviated much from the original
concept.
In a typical design, a set of 2 rams is
mechanically or hydraulically closed
either around a wellbore tubular to form
a pressure-tight seal against downhole
pressure or wellbore fluids. Shearing
rams were introduced in the 1960s.
These rams sheared the pipe in the
wellbore, but an additional BOP cav-
ity containing a set of blind rams was
required to seal the bore. Later, these
functions were combined into shearing
blind rams, commonly known as SBRs,
which reduced the number of BOP cavi-
ties required to 1.
From the 1st BOP design to the pres-
ent designs, the basic mechanisms
have remained constant: A BOP body is
sandwiched between 2 operating sys-
tems. The rams are opened and closed
mechanically either by manual interven-
tion or by hydraulically operated pistons.
What has changed, however, and is in
a constant state of flux are the oper-
ating parameters and the manner in
which BOPs are used in today’s drilling
activities. Today, a subsea BOP can be
required to operate in water depths of
greater than 10,000 f t, at pressures of up
to 15,000 psi and even 25,000 psi, with
internal wellbore fluid temperatures up
to 400° F and external immersed temper-
atures coming close to freezing (34° F).
THE C HA LLENG E
The deepwater challenges being expe-
rienced by drilling contractors and oil
companies alike are critical technical
challenges that must be overcome if
drilling is to move into deepwater envi-
ronments
Today’s deepwater BOPs can be required
to remain subsea for extended periods
of time ranging from 45 to 90 days for
a single well, to more than a year in
cases where drilling and completions on
multiple wells are required. In all cases,
however, when the BOP is called on to
function in an emergency situation, it is
the main barrier protecting human life,
capital equipment and the environment.
Therefore, it must function without fail.
One possible enhancement involves tak-
ing advantage of advances in metallurgy
to use higher-strength materials in ram
connecting rods or ram-shafts.
The newbuild drilling and production
facilities under construction for today’s
market are limited for space and han-
dling capabilities and, therefore, require
that BOP stacks be lighter-weight and
take up less space on the rig while pro-
viding the accustomed functionality. In
addition, existing limited capacity rigs
have the potential to be upgraded for
use in deepwater with higher-capabil-
ity equipment, but the upgrade must be
accomplished within limited height and
weight parameters. With deck space
and load capacity of these rigs already
at a premium, lighter weight BOPs can
help offset distribution of alternative
equipment such as subsea riser joints
necessary for increased water-depth
capability.
BOPs today are also being used not only
in drilling and workover applications but
also in completions and production envi-
ronments . The industry is not just deal-
ing with drilling mud anymore.
By Melvyn F (Mel) Whitby,
Cameron’s Drilling System Group
The above shows a typical BOP operating piston assembly with a transverse-mounted locking mechanism.
Bl owout preventer requi rements get tougher as dri l l i ng goes ever deeper
37 May/June 2007
S P E C I A L MA R I N E E D I T I O N
BOPs have traditionally evolved using
conventional design methodology. Today
the envelope is rapidly changing, forc-
ing some fundamental paradigm shifts.
Emerging technologies give way to new
manufacturing techniques and innova-
tion of design of operation. Sealing tech-
nology has improved radically with new
materials and compounds being used to
formulate sealing elements able to with-
stand extreme temperatures and hostile
fluid environments.
RELIA BILITY O F O PERA TIO N
The increased design complexity of mod-
ern-day BOPs can come at a price. While
high-tech solutions may seem desirable,
the intricate mechanical components
that may result must be considered,
along with other factors, such as pos-
sible leak paths and redundancy of criti-
cal seals.
In addition, control system functions can
be limited and, in order to save func-
tion availability, hydraulic functions are
often combined. An example of this is the
integrated closing and automatic lock-
ing of the BOP when the closing function
is initiated. This combined function has
now been discarded, in many instances,
in favor of separate close and lock func-
tions. It is now understood that the
chances of a locking system problem are
increased with a proliferation of locking
cycles.
Many drilling contractors today are reluc-
tant to operate the locks subsea in order
to prevent unnecessary unlocking prob-
lems. The locks are tested on the surface
for assurance that they will operate
should the situation arise. In the perfor-
mance characteristics section of API 16A,
API suggest that the locks be fatigue-
tested in concurrence with a 546 cycle, 78
pressure cycle API ram fatigue test.
This test initially was designed to
simulate 1 closure per day and a weekly
pressure test for an estimated period
of 18 months’ service. In combining the
locking system test into this test, it was
recommended that every 7th pressure
cycle be conducted in locked mode. This
means that during the course of an 18-
month service period, the locks were
expected to be used a total of 11 times.
Combining the closing and locking
system function meant that the locks
were being exposed to a locking opera-
tion every time the BOP was operated,
requiring a complicated mechanical or
hydraulic sequencing arrangement be
incorporated. In addition , a locking sys-
tem can be exposed to extremely high
load forces during a shearing operation
and is therefore required to be extremely
robust by design. The complexity of such
systems and their mechanical function
can be impaired by the acute mechani-
cal detail required to make them work
adequately.
FLUID C O NSUM PTIO N,
A C C UM ULA TO R VO LUM E
Fluid consumption is a double-edged
sword: Less fluid typically comes at a
high cost because conventional design
philosophy often means that smaller pis-
tons yield smaller force output. In deep-
water applications, this force is addition-
ally reduced by the hydrostatic column
of seawater and/or drilling mud. In order
to mitigate these factors, 2 things must
be considered — closing ratio and piston
area.
Smaller-diameter pistons mean that
wellbore-exposed areas are minimized
and, therefore, will not “rob” the oper-
ating system of much-needed power.
However, the piston area must be large
enough to provide sufficient power for
ram seal energizing and rubber feed,
and must provide the power to shear
high-strength, ductile tubulars when
necessary.
The downside of traditional design phi-
losophy is that a piston large enough
to provide the much-needed power is
almost the same area in opening as it
is in closing. Ergo, a BOP that requires
22 gallons of fluid to close will require
approximately 18 gallons to open, a fac-
tor that can affect the surface and sub-
sea accumulator bottle count.
Another negative impact is that a larger
BOP opening area can actually put the
equipment and the environment at risk.
If opening pressure is inadvertently
applied to a BOP that is retaining well-
bore pressure or residual pressure,
damage can result to the connecting
rod and/or the ram to connecting rod
interface. This damage can result in the
loss of sealing integrity or ram control,
leaving the rig at risk and increasing the
potential for environmental harm, not to
mention the associated downtime neces-
sary for repair.
By separating the closing function from
the opening function and reducing the
opening area, a number of benefits can
be realized:
• Reduced operating volume. More clos-
ing power can be achieved by using
D R I L L I N G C O N T R A C T O R
38
May/June 2007
D R I L L I N G C O N T R A C T O R
S P E C I A L MA R I N E E D I T I O N
a large closing piston diameter and a
second smaller piston diameter for the
opening function. For example a closing
area of 224 sq in. and an opening area of
41 sq in. results in 22 gallons to close but
only 8 gallons to open.
• Reduced opening area. Smaller oper-
ating piston diameter reduces the effec-
tive opening ratio of the BOP, thereby
protecting against accidental operation
with wellbore or residual pressure in
the BOP bore. In the event that open-
ing pressure is applied in this case, the
operating piston would stall, preventing
potential damage to the connecting rod
or ram.
• The closing piston and opening piston
seals may be separated, preventing pos-
sible leak communication. Additionally,
in the unlikely —but not impossible
— event that wellbore pressure was to
bypass the connecting rod seals, the
structural integrity of the BOP bonnet
would not be at risk.
LO C KING O PERA TIO N,
RELIA BILITY
Over the course of BOP development,
mechanical locking systems have by
nature become more and more complex.
Considerable BOP downtime has been
attributed to errant operation or inabili-
ty to unlock when required. These events
typically involve possible milling through
closed rams and eventual tripping of the
BOP back to the surface for repair or
remedial work. A lock should ultimately
be reliable, but with complexity comes
risk. Multiple parts must interface for
proper operation.
Taking a step back in time, surface BOPs
have utilized a simple but effective form
of mechanical lock — a simple rotating
threaded locking screw placed behind
the operating piston after hydraulically
closing the BOP. With recent
subsea advancements in
hydraulic gear motors
for torque applica-
tions, it may be time to
look down this path for a
simple, reliable locking
operation. A number of
benefits could be real-
ized, including simplicity, ease
of maintenance and reliability, to
name but a few.
SUBSEA INTERVENTIO N
C A PA BILITY
A simple, mechanical-type locking
system for subsea BOPs may open up
opportunities for intervention by a
remote-operated vehicle (ROV), thereby
allowing for intervention subsea. ROVs
are already doing this work in other
applications that require mechanical
intervention, such as on subsea trees
that require manual override and the
torque-up of API Class 1 – 4 flange con-
nections.
HEIG HT A ND WEIG HT
The height and weight of a BOP body is
determined by factors such as ram cav-
ity height and geometry, and the operat-
ing system or bonnet design. Minimal
cavity height can realize height savings
but at the sacrifice of ram packer vol-
ume, which is important for the longevity
of the sealing mechanisms in operation
subsea. Large operating systems require
excess distances between the cavities of
double and triple BOP bodies.
By careful redesign of the operating
system, cavity height can be increased
for effectiveness while minimizing height
impact. In one such case, using an 11.5-
in. tall cavity, the height of a double
BOP body was reduced from 83 in. tall
to 72 in. tall while maintaining a large
operating system area. This could be
achieved either by using a binocular-
style operating piston arrangement or
an oval-shaped piston instead of the tra-
ditional circular style piston. Shortening
the height of the BOP components in a
subsea stack either allows for a shorter
drilling substructure arrangement or
allows for the incorporation of BOP cavi-
ties within existing substructure height
envelopes.
M A INTENA NC E, O PERA BILITY
Ease of use and simplicity of operation
and maintenance are key components
to BOP design. In order to achieve these
goals, several factors should be consid-
ered:
• Leak paths between critical functions
should be minimized.
• Redundancy of seals should be utilized
wherever possible.
• A means of isolating hydraulic func-
tions to the BOP should be employed,
if possible, to minimize personnel risk
while conducting maintenance opera-
tions with the bonnets open.
• Provision should be made to allow safe
handling of the bonnets should removal
for repair or maintenance be required.
• Efforts should be made to minimize
the handling of components weighing
more than 20 lbs, or lifting arrangements
should be provided to assist in their safe
removal.
While efforts within the industry have
been made to reduce or even remove
the bonnet securing bolting, the benefits
have been offset by the associative com-
plexity and thereby increasing the risk
of serious mechanical problems. These
problems can cause excessive downtime
when the BOPs are finally pulled back
to the surface, not to mention the pos-
sibility of debris and cement causing
problems with internal bore style bonnet
retaining mechanisms. The complexity
of these arrangements, while appearing
to be high-tech, do little to enhance the
subsea performance and surface main-
tainability of the equipment.
One reasons that BOPs have changed
very little over the years is that it is
extremely difficult to improve on simplic-
ity without sacrificing reliability.
Melvyn F (Mel) Whitby is senior manager
of research and development at Cameron’s
Drilling System Group.
This article is based on a presentation at
IADC World Drilling 2007, 13-14 June 2007,
Paris.
A 3D view of a BOP operating piston
assembly with transverse mounted
locking mechanism.
An example of a 18 ¾-in. 15M subsea
BOP with 18-in. operating pistons.
Cameron supplies integrated subsea drilling systems designed
specifically to tackle the demands of deepwater, high pressure
applications including BOP stack systems, control systems, riser
systems and choke systems. Cameron subsea drilling components
include the following:
Subsea Drilling System Components (Surface)
Control System
1. Auxiliary Remote Control Panel and Battery Bank
2. Driller’s Panel
3. Hydraulic Power Unit
4. Accumulator Bank
5. Hose/Cable Reels
Choke System
6. Choke Manifold
7. Choke Manifold Control Console
Riser System
8. Telescoping Joint
Motion Compensation System
9. Drill String Compensator
10. Riser Tensioner
Subsea Drilling System Components (Subsea)
Control System
1. Hydraulic Conduit Supply Line
2. MUX Control Pod
3. Conduit Valve
Riser System
4. Riser Joint
5. Riser Connector
6. Termination Spool
Lower Marine Riser Package
7. Flex Joint
8. Annular BOP
9. Choke/Kill Connector
BOP Stack
10. Subsea Gate Valve
11. Double Ram-Type BOP
with Super Shear
12. Double Ram-Type BOP
13. Guide Structure
14. Collet Connector
9 S U B S E A D R I L L I N G S Y S T E M S
Riser
System
Stack
System
17 D R I L L I N G C O N T R O L S Y S T E M S
T
he subsea MUX electro-hydraulic BOP control system
from Cameron offers state-of-the-art controls for
Cameron BOP systems.
Each system is designed with a true systems approach
for maximum efficiency. The modular structure of the
system allows Cameron to look at each drilling program
from a total systems level, not just from an equipment level.
Only Cameron combines this approach with the full
technical and project management resources of the
Cameron organization, offering customers:
• Subsea retrievability Unlike any other system in the
industry, the modular design of the Cameron system
allows the subsea control pod to be retrieved and
replaced without pulling the riser stack.
• Redundant system architecture Component level
redundancy eliminates single point failures. All critical
system functions have been engineered with multiple
back-ups for continuous operations.
• Robust components Subsea components are rated for
up to 10,000 ft (3000 m).
• Smaller and lighter Cameron subsea MUX drilling control
systems are the smallest and lightest in the industry.
• Functionality Cameron MUX systems provide up to 112
hydraulic functions per subsea control pod.
L AND AND P L AT F ORM BOP CONT ROL S YS T E MS
Cameron offers
reliable, econom-
ical direct hydraulic
drilling control
systems for use on
land or platform.
Systems are design-
ed in accordance
with API 16D
specifications, as well as
all appropriate codes and standards for explosive and
hazardous area classification. Dual control panels provide
maximum flexibility, while the modular components deliver
maximum reliability and field serviceability.
Cameron cellar deck-mounted piloted control systems
are unprecedented
for control of
BOP stacks on
jackup type
rigs. Proven
through years
of field
applications,
these systems
provide significantly increased response time for control of
surface-mounted equipment.
MU X S U B S E A C ON T R OL P OD S
The Cameron subsea MUX drilling control pods combine
rapid response time with an array of features that make
them both reliable and economical at depths of 10,000 ft
(3000 m).
The Mark I Pod, capable of 72 functions, is designed for
most typical and deepwater applications, offering a compact
footprint and weight of
10,000 lb (4536 kg). The
Mark II Pod, capable of 112
functions, is designed for
ultra deepwater environ-
ments and weighs 15,000
lb (6804 kg). The pod
houses the hydraulic module
and electronic MUX
package. Two accumulator
banks are placed
conveniently around
the BOP stack.
The hydraulic
module is a standard
Cameron modular pod. Modules
feature seawater tolerant, stainless steel valves and pressure
regulators with sliding, metal-to-metal, shear type seals.
The electronic MUX package consists of the Subsea
Electronics Module (SEM) and the solenoid valve package.
The SEM contains dual redundant electronics which provide
communications via modem with the surface electronic
system. The solenoid valve package converts the electronic
commands into hydraulic signals which actuate the large
valves in the hydraulic module.
S U B S E A P I L OT E D A N D D I R E C T H Y D R A U L I C
C ON T R OL S Y S T E MS
For operating the BOP stack and associated equipment in
shallower depths of 5000 ft (1500 m) or less, Cameron
offers piloted hydraulic drilling control systems.
These systems offer the same robust, field-
proven components as the MUX system,
but they are controlled via hydraulic
connections between the surface
controls and subsea control pod.
Like the subsea MUX systems,
the piloted systems feature
redundant architecture for absolute
reliability, and are fully retrievable
without pulling the riser. Subsea
system functions can be operated by
either the driller’s control panel, tool-
pusher’s control panel or touchscreen, as well as by the
tertiary operator panel located on the diverter control unit.
MUX Control Pod
Hydraulic Control Pod
Platform Control System
Land Closing Unit
M o R P H D R I L L I N G C O N T R O L S Y S T E M 18
T
he new Cameron MoRPH
™
Drilling Control System is the
blending of technologies to provide a simple, quick,
economical solution for extending the water depth range
of second to fourth generation drilling rigs.
The MoRPH system offers a hybrid design which is ideal
for rigs drilling in mid-range water depths. MoRPH systems
control time-critical functions
by electrical signals (similar to
MUX systems) while non-critical
functions are controlled by pilot lines
(like the current shallow water systems).
In order to do this, MoRPH systems divide BOP stack
control functions into two basic categories:
• Time-critical functions such as opening and closing
ram and annular BOPs that must meet the API timing
requirement
• Non-time-critical functions
Time-critical functions are controlled by electrical signals,
while non-time-critical functions are controlled by pilot lines
like the current shallow water systems. This ensures
adherence to the API requirement by converting critical
“shut-in” functions to an electro-hydraulic system, yet
retains the simplicity of direct hydraulics for other functions.
The MoRPH system is easily adapted to existing piloted
hydraulic systems.
Toolpusher’s
Control Panel
Driller’s
Control Panel
Hydraulic
Interface
MoRPH
Umbilical Reel
Umbilical Clamps
LMRP, FITA and
Clamp assembly
Existing
Hydraulic Pod
Subsea Stack
MoRPH Pod
Electric/Hydraulic
Flying Leads
Complete MoRPH system
Mo R P H C ON V E R S I ON R E QU I R E ME N T S
Existing Equipment MoRPH System
Driller’s and toolpusher’s control panels, Use as is
surface wiring, manifold, accumulators,
pumps, reservoir, UPS, surface hose
umbilicals, guide arms, BOP and LMRP
plumbing, shuttles valves, etc.
Riser hydraulic line(s) Use if over 2-7/8”
Hose clamps Use w/ adapting bushing
All hydraulic pods Use w/ new mounting holes
All hydraulic hose reels and umbilical Remove
Hydraulic interface New
Distribution junction box New
ROVs parking plates New
Umbilical and reel New
controls and major catastrophes (such as damage to the
riser system). Cameron offers a variety of emergency, back-
up and deepwater control systems to meet the needs of all
three types of situations. The choice of which system is
required in a particular situation depends upon the specific
needs of each individual application.
19 E M E R G E N C Y S Y S T E M S
G
reater concerns for our environment and for the safety
of employees are making the automated systems for
shutting in a well become standards on all drilling rigs.
Three types of systems emergency situations could poten-
tially require use of emergency backup systems: operator
initiated procedures, emergency mitigated by loss of main
EDS (Emergency Disconnect Sequence)
A system to close the rams with a program-
med sequence of events when a button is
actuated by an operator.
Acoustic
A system to activate a limited number of
functions from the rig when no other
communications are possible.
ROV Panels
A system to operate a limited number of
functions by the use of an ROV when
normal operation is not available.
Deadman (Automatic Mode Function)
A system to automatically close the shear
rams when there is catastrophic loss of the
riser systems.
Automatic Disconnect System
A system to automatically close the shear
rams when the riser angle exceeds a certain
predetermined limit.
Autoshear
A system to automatically close the shear
rams when there is an unplanned disconnect
of the LMRP
ACS
Acoustic Control System for BOP operation
System description
The ACS (Acoustic Control
System) is designed Ior
acoustic control oI BOP operation,
and other subsea production units
requiring a control system.
The ACS system may control
up to 12 diIIerent Iunctions with
readback, and monitor up to seven
analogue inputs. Two systems are
available;
1. Emergency BOP control system
2. Primary surIace BOP control
system (QHZ)!
A BOP system is divided in two
parts, comprising:
· Surface equipment
· Subsea equipment
Both parts have transceivers that
are connected to transducers. An
advanced acoustic telemetry link
is established between the surIace
and the subsea parts. The telemetry
system is based on Spaced
Frequency ShiIt Keying (SFSK),
implying that the inIormation is
coded as a sequence oI diIIerent
Irequencies. SFSK is the only
reliable type oI coding Ieasible
in noisy and reverberant oIIshore
environments.
The acoustic control Iunction can
also be operated Irom a standard
Hydroacoustic positioning system
like HiPAP or HPR 400.
DiIIerent transducers with diIIerent
beamwiths are available Ior
optimal perIormance in deep and
noisy environments. Kongsberg
Maritime can supply solenoid
connector alternatives Irom leading
suppliers and can also, on request,
oIIer engineering in BOP stabbing
solutions.
Now with functionaIity for Surface BOP appIications
Features
· Acoustic BOP Control System and telemetry
· Acoustic control communication with spaced Irequency shiIt keying
(SFSK)
· Acoustic communication with high reliability in noisy and
reverberant oIIshore environments
· Unique address Ior each subsea controller unit
· Two-way communication
· Operator override oI two-way communication
· OII-line BOP status reading and command test
· Dual transceiver in the subsea unit
· Dual transducer in the subsea unit
· Long range option Ior production tree control
· System selI-test diagnostics
· OII-line checking oI Iull system without actually operating the
valves
· Portable control unit with range measurement Ieature
· Integration oI the Acoustic Control System with the HiPAP/
HPR systems, will simpliIy the daily check oI the subsea control
electronics.
Subsea BOP solution
Surface equipment
The surIace equipment consists oI
a portable Acoustic Command and
Control Unit, the ACC 401, and
a dunking transducer with hand
operable cable winch.
The ACC 401 unit is portable and
it has an internal rechargeable
battery with charger, which gives
10 hours normal operation.
The dunking transducer may be
lowered into the sea Irom a rig,
a stand-by vessel, a liIeboat, a
helicopter and so on.
The ACC 401 is operated Irom
the LCD display, using a cursor
operated menu and dedicated
push-buttons. The display has
background lights Ior operations
at night. To secure saIe operation
oI critical subsea Iunctions, the
operator has to use both hands
during activation oI critical
commands.
Subsea equipment
The subsea equipment consists oI
the Subsea Control Unit (SCU),
two transducers with cables and
waterprooI connectors, and an
interIace cable Ior solenoid pack
connection. The SCU holds the
subsea electronics. It includes
two transceivers with transducers,
which makes the system 100°
redundant. The SCU is powered
Irom internal lithium batteries, and
has one solenoid connector and
two connectors Ior transducers.
Surface BOP solution
The ACS 433-S system is designed
Ior acoustic control oI the seabed
POD in a Drilling package having
a SurIace BOP Iunctionality.
Surface equipment
Same equipment as the Subsea
BOP solution.
Subsea equipment
The SCU includes a serial line
communication controller board
(SIT), that enables fexible
communication and protocols
with the POD. Else; same ACS
electronic container as the Subsea
BOP solution.
BOP Simulator Unit
Each delivery is supplied with
a BOP Simulator Unit with test
cable.
Via the test cable, the simulator
is connected to the end oI the
interIace cable. The simulator is
manuIactured using the parameters
Ior the actual BOP it will be
simulating, and contains loads that
correspond to the nominal loads
oI the solenoids which would
normally be controlled.
· The simulator has a current
sensor circuit that lights an LED
iI the solenoid current is too low.
· The simulator is marked with
the names oI the actual valves
that should be controlled.
When a valve operation is
perIormed, the LED corresponding
to the valve Iunction will light up
Ior the specifed period oI time.
II the system is equipped with
Ieedback sensors, the sensors are
simulated by switches Ior each
valve.
Acoustic Control System
System units
When a two-hand operated
command Iunction is carried out, a
two-way subsea communication is
perIormed as Iollows:
1 The surIace unit transmits
address and command set-up
inIormation down to the subsea
unit.
2 The subsea unit verifes the
reception oI address and
command data.
$FRXVWLF&RQWURO6\VWHPVXUIDFHHTXLSPHQW
$FRXVWLF&RQWURO6\VWHPVXEVHDHTXLSPHQW
3 An execute command is
automatically transmitted
down as a result oI the
received verifcation message.
The operator may Iorce the
transmission oI an execute
command by a two-handed
operation iI the verifcation
message Iails to be received.
4 The subsea system confrms
that the activation command
has been correctly received and
executed.
The principle oI two-way
communication provides the
Iollowing advantages:
· Check oI a transmitted address
and command ensuring that
erroneous messages are avoided.
· Status readback oI BOP
Iunctions is perIormed beIore
and aIter a command has been
carried out.
· Allows routine checking oI
BOP status, and oII-line testing
oI command Iunctions at both
surIace and subsea levels.
· Prevent unwanted operations.
The acoustic control Iunction can
also be operated Irom a standard
HiPAP / HPR 400 system.
$&66LPXODWRU
Operational principles
855-160518 / Rev.E / April 2006
Technical speciñcations
System description ACS 431 MF ACS 433 MF ACS 413 LF
Communication principle SFSK SFSK SFSK
System depth rating (performance) 1500 m / 4500 ft 3000 m / 10.000 ft 3000 m / 10.000 ft
PortabIe Acoustic Command and ControI Unit (ACC 401): Same unit for all systems
Battery lifetime Normal operation / continuous operation 50 hours / 10 hours
Dimensions HxLxW 228 x 383 x 320 mm HxLxW 228 x 383 x 320 mm HxLxW 228 x 383 x 320 mm
Weight 14 kg 14 kg 14 kg
Dunking transducer (TD): As standard all dunking transducers are delivered with a 70 m Kevlan armoured cable on a drum
TD Name TDD 303 MF TDD 301 MF TDD 103 LF
TD Opening angle +-30 degrees +/-15 degrees +/-30 degrees
TD Dimensions Height / diameter 322 / 112 mm Height / diameter 346 / 156 mm Height / diameter 355 / 128 mm
Cable drum Dimensions HxLxW 500 x 590 x 225 mm HxLxW 500 x 590 x 225 mm HxLxW 500 x 590 x 225 mm
Weight:
- Cable drum with cable and TD
- Separate TD
21.5 kg
5.0 kg

26.6 kg
10.0 kg

27.0 kg
10.0 kg
Subsea ControI Unit (SCU):
Name
Subsea Control Unit,
SCU 400 MF
Subsea Control Unit,
SCU 400 MF
Subsea Control Unit,
SCU 400 LF
Depth rating 1500 m 3000 m 3000 m
Dimensions Height / diameter 1000 / 440 mm Height / diameter 1000 / 440 mm Height / diameter 1000 / 440 mm
Weight in air 300 kg 300 kg 300 kg
Subsea transducer (TD):
TD name TDA 324 MF TDA 331 MF TDA 133 LF
Opening angle +/- 45 degrees +/-15 degrees +/- 30 degrees
Dimensions Height / diameter 185 / 142 mm Height / diameter 210 / 178 mm Height / diameter 335 / 194 mm
Weight in air including cable 13 kg 9.6 kg 35 kg
ACC 401 Unit
· Transmitter and receiver
Irequency:
MF: 24 to 26.5 kHz
LF: 11.5 to 13 kHz
· Receiver bandwidth:
MF: 250 Hz
LF: 125 Hz
· Maximum power output: 500 W
· Supply voltage: 90 to 240 Vac
· Battery liIe,
normal operation: 50 hours
· Battery liIe,
continuous operation: 10 hours
SCU Unit
· Channels: Two Iully redundant
electronic control channels
Solenoid drivers:
· Standard / additional (option):
8 / 4 outputs
· Solenoid output:
48 Vdc or 24 Vdc
(other voltages on request)
· Electronic short circuit control
· Electronic solenoid current
measurement
· Outputs are galvanically
insulated
Solenoid feedback:
· Eight (8) external switch
Ieedback inputs (standard)
· Seven (7) analogue:
4 to 20 mA sensors
· Operating temperature:
- 0° - 55° C
Internal battery (two units):
· Type : L 10/50
· Operation liIetime:
1.5 to 2 years
· Supply voltage: 48 Vdc nominal
· Housing: Steel, St 52 and
corrosion prooI alloy in fanges
and connector bases
Receiver:
· Frequency, MF: 24 to 26.5 kHz
· Bandwidth, MF: 250 Hz
SCU 400 MF speciñc data
Transmitter:
· Reply Irequency, MF:
24 to 26.5 kHz
· Maximum power output: 500 W
Receiver:
· Frequency, MF: 24 to 26.5 kHz
· Bandwidth, MF: 250 Hz
SCU 400 LF speciñc data
Transmitter:
· Reply Irequency, LF:
11.5 to 13 kHz
· Maximum power output: 500 W
Receiver:
· Frequency, LF: 1.5 to 13 kHz
· Bandwidth, LF: 125 Hz
Simulator unit dimensions
· HxWxL (w/handles):
175 x 200 x 253 mm
· Weight: 1.5 kg
Strandpromenaden 50
P.O.Box 111
N-3191 Horten,
Norway
Kongsberg Maritime AS
Telephone: +47 33 02 38 00
Telefax: +47 33 04 47 53
[email protected]
www.kongsberg.com
SD 034582
Pipe
Bonnet
Shear
Bonnet
Close
Pressure
Tandem Standard
Open
Pressure
UM BOP Open and Close Hydraulics
(13-5/8” 10,000 Shown)
Pipe
Bonnet
Shear
Bonnet
Close
Pressure
Open
Pressure
TC1542 20
UM BOP Operating Data and Fluid Requirements
Bore Size and
Working Pressure
Gals to Open Pipe Rams
(1 set)
Gals to Close Pipe Rams
(1 set)
Gals to Close Shear Rams
(1 set)
Closing Area
(Sq. inches)
Locking Screw Turns
(Each End)
Closing
Ratio
Opening
Ratio
7-1/16” All WP
2.2 2.3 2.4 67.3 18 11.7:1 3.8:1
11” Except
15,000 psi
6.2 6.2 7.4 113.8 27 13.7:1 3.7:1
11” 15,000 psi
- - - - - - -
13-5/8” Except
15,000 psi
7.5 7.5 8.8 110.15 32 8.7:1 2.3:1
13-5/8” 15,000 psi
Model B
- - - - - - -
Bore Size and
Working Pressure
Liters to Open Pipe Rams
(1 set)
Liters to Close Pipe Rams
(1 set)
Liters to Close Shear Rams
(1 set)
Closing Area
(Sq. cm)
Locking Screw Turns
(Each End)
Closing
Ratio
Opening
Ratio
7-1/16” All WP
8.3 8.7 9.1 434 18 11.7:1 3.8:1
11” Except
15,000 psi
23.5 23.5 28.0 734 27 13.7:1 3.7:1
11” 15,000 psi
- - - - - - -
13-5/8” Except
15,000 psi
28.4 28.4 33.3 711 32 8.7:1 2.3:1
13-5/8” 15,000 psi
Model B
- - - - - - -
UM BOP Tandem Booster Operating Data and Fluid Requirements*
Bore Size and
Working Pressure
Gals to Open Pipe Rams
(1 set)
Gals to Close Pipe Rams
(1 set)
Closing Area
(Sq. inches)
Locking Screw Turns
(Each End)
Closing Ratio Opening Ratio
7-1/16” All WP
- - - - - 3.8:1
11” Except
15,000 psi
6.2 13.1 201.8 27 24.3:1 3.7:1
11” 15,000 psi
- - - - - -
13-5/8” Except
15,000 psi
7.5 10.4 198 32 15.6:1 2.3:1
13-5/8” 15,000 psi
Model B
- - - - - -
*All volumes based on shear ram configuration
Bore Size and
Working Pressure
Liters to Open Pipe Rams
(1 set)
Liters to Close Pipe Rams
(1 set)
Closing Area
(Sq. cm)
Locking Screw Turns
(Each End)
Closing Ratio Opening Ratio
7-1/16” All WP
- - - - - 3.8:1
11” Except
15,000 psi
23.5 49.6 1302 27 24.3:1 3.7:1
11” 15,000 psi
- - - - - -
13-5/8” Except
15,000 psi
28.4 39.4 1277 32 15.6:1 2.3:1
13-5/8” 15,000 psi
Model B
- - - - - -
*All volumes based on shear ram configuration
TC1542 21
The capital letters in the following designations refer to the UM BOP dimensional views below and dimensional charts shown on the
following page.
A-1 Length - bonnets closed, locking screws locked
A-2 Length - bonnets opened, locking screws unlocked
B-1 Height - flanged
B-2 Height - studded
C Width - no side outlets
D Centerline of preventer to outlet flange or hub face. This distance is variable and must be determined per individual specifications.
E Centerline of side outlet to bottom flange face
F Top of ram to top flange face
G Height of ram
UM BOP Assembly, Single with Tandem Boosters
SD 034566
A
C
B
E F
G
D
TC1542 10
Code of Federal Regulations

TITLE 30 - MINERAL RESOURCES (December 2005)

CHAPTER II - MINERALS MANAGEMENT SERVICE, DEPARTMENT OF THE
INTERIOR

SUBCHAPTER B - OFFSHORE

PART 250 - OIL AND GAS AND SULPHUR OPERATIONS IN THE OUTER
CONTINENTAL SHELF

subpart d - OIL AND GAS DRILLING OPERATIONS

250.442 - What are the requirements for a subsea BOP stack?

(a) When you drill with a subsea BOP stack, you must install the BOP system before drilling
below surface casing. The District Supervisor may require you to install a subsea BOP system
before drilling below the conductor casing if proposed casing setting depths or local geology
indicate the need.

(b) Your subsea BOP stack must include at least four remote-controlled, hydraulically operated
BOPs consisting of an annular BOP, two BOPs equipped with pipe rams, and one BOP equipped
with blind-shear rams.

(c) You must install an accumulator closing system to provide fast closure of the BOP
components and to operate all critical functions in case of a loss of the power fluid connection to
the surface. The accumulator system must meet or exceed the provisions of Section 13.3,
Accumulator Volumetric Capacity, in API RP 53, Recommended Practices for Blowout
Prevention Equipment Systems for Drilling Wells (incorporated by reference as specified in
250.198). The District Supervisor may approve a suitable alternative method.

(d) The BOP system must include an operable dual-pod control system to ensure proper and
independent operation of the BOP system.

(e) Before removing the marine riser, you must displace the riser with seawater. You must
maintain sufficient hydrostatic pressure or take other suitable precautions to compensate for the
reduction in pressure and to maintain a safe and controlled well condition.


[68 FR 8423, Feb. 20, 2003]