BOP Control Systems Review
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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
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
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. This paper was selected for presentation by an OTC Program Committee following review of information contained in an abstract submitted by the author(s). Contents of the paper, as presented, have not been reviewed by the Offshore Technology Conference and are subject to correction by the author(s). The material, as presented, does not necessarily reflect any position of the Offshore Technology Conference or its officers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Offshore Technology Conference is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of where and by whom the paper was presented.
Abstract Historically, drilling contractors have accepted without many questions the reliability of the Blowout Preventer (BOP) components and overall control system. A statistical reliability approach to qualifying, purchasing, and maintaining deepwater BOP control systems should provide a high level of confidence 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 performed 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, recently 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 manufactured 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 afford 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 perform maintenance on the equipment without sustaining downtime. For offshore floating drilling operations, especially in deepwater, one of the most expensive downtime events is associated with having to pull the marine riser and subsea BOP because of a problem. Any problem or failure that requires the riser and BOP to be round tripped will result in a cost of approximately $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 dynamically positioned (DP) rigs is typically a Multiplexed ElectroHydraulic (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 basic 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
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pod and preparations will be made to retrieve the lower marine riser package (LMRP) and riser to surface. Some minor problems may not require the system to be retrieved if considered not necessary for critical operations. Transocean has recently had an opportunity to review the basic design and requirements for Deepwater MUX BOP Control 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 performance requirements given. Very often, the system requirements were developed between the contractor engineers, operations 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 contractor and vendor, emphasis is typically given to the following: § 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 comp onents 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 pressure and volume of the stored hydraulic fluid increased 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 function 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 associated 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 exploration 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 improvements in BOP reliability at all levels during the equip ment lifetime, including the design stage. As part of this process, 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 historically 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 components. The systems under review consist of the solenoid pilot valve through to the end function. The following reliability goals were established for the solenoids 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.
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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 reliable components that will result in the hydraulic control system meeting this objective. The need for highly reliable sub-sea BOP system components results from the following assumptions that are based on actual 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 analysis of the required testing. Next, an estimate of the component failure rate goals is established based on the desired operational reliability of the system and the test demands that various 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 following major categories: § Control System Design Considerations – This process 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 Requirements – The requirements of each component for the maintenance interval will be determined and a reliability goal is established to meet the criteria;
§
Elements of the Reliability Testing Plan – Each fa mily 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 5th-Generation DP semisubmersible capable of drilling
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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 onent designs are similar enough to assume that the reliability performance of the components may be modeled by one failure 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 assisted 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 controlled 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 developing 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 surface 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-
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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 accumulator 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 operational 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 reliability 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 demands 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. Consequently, 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 current 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 failure 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 reliability 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 Poisson process for time-related failure modes may represent the failure rate. Both of these processes assume that observed failures result from random failures of a population of comp onents characterized by a failure rate independent of the previous 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 present; §
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 similarity 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 someone 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 reliability tests should involve repeated operational evolutions where they are demanded to open and
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close in accordance with the operational requirements; §
If exposure to the subsea environment precipitates the failures, the test must include exposure to these conditions, or more severe conditions that can accelerate the mechanisms, for a period of time that can simulate the total exposure.
As both mechanisms are most likely involved, the reliability test needs to address both environmental exposure and operational 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 conditions; §
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 anomalies 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 indirect 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 reliability 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 establishes 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 different failure rates. The confidence limit is a means of expressing 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, defined previously, can be modeled by a single-component group failure rate. The impact of component failure rate uncertainty on the uncertainty of system failure rate is illustrated by Figure 6. The curve on the left-hand side of the chart represents 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
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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% confidence that each component group failure rate 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).
Surface Bottles
Figure 7 (right) shows the basic layout for a conventional fluid recovery system. Figure 8 (below, middle) shows that in a conventional system, high back pressure can cause other BOP functions to inadvertently close. Figure 9 (bottom) shows a fluid recovery system that can resolve this problem.
Pump
ForceClo sin g = AreaClo sin g × Back . press − AreaOpening × Back . press
Subsea Bottles
BOP Operator
Valve
VENT TO SEA Pressure = 5350 psi
Control POD
PUMP
Return P = 2000+ psi
Over 2000
psi Back Pressure
INADVERTANT CLOSURE!!!
Area Open < Area Close RETURN LINE TO SURFACE
BACK PRESS REG VALVE Compensates for Density difference between SW & Hyd Fluid
Surface Bottles Pump Sea Level
RESERVE CAPACITY
BOP Operator
Valve
Subsea Bottles
MINI PISTON Keeps Return System below SW Press
Allows for smaller pumps
FLUID RECOVERY PUMP Pumps Fluid Back to Surface
Return Press < Sea Water Press PRESSURE PROTECTION
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This force can be as high as 60,000 lbs, plenty of force to close the BOP operator. The solution to this problem is to pump the fluids to surface with a complete fluid recovery system. The system design and its components can be seen in Figure 9.
A reciprocating pump was designed to keep the system simple, easily powered by hydraulics and to use as much existing subsea technology as possible. The flow capacity and the ratio of hydraulic power section to discharge pumping section 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 intermittent 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 surface. 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 function in an emergency situation.
RESERVE CAPACITY The reserve capacity serves two purposes. First, it provides a surge capacity for the high return flows from the BOPs when the return flow is greater than the
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WELL CONTROL
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 system 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 capacity bottle when the BOPs have been functioned. This is performed via an innovative 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 compensating 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 hydraulic 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 pressures 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 difference 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 systems for the past 20 years.
SMART CONTROLS Imagine a control system that knows it will fail before it fails. The more challenging 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 redundant 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 critical, 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 monitoring. The monitoring is then trended over time to see if there has been any degradation 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 system, 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 solenoid 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 compensated accumulator; stronger, by increasing the piston size and designed to continuously operate at 5,000 psi; cleaner, by way of a complete fluid recovery system; and smarter, by continuously monitoring 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 petroleum industry. He is a mechanical engineer by training and holds a B.S. in mechanical engineering and marine engineering technology 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 training and holds a B.S. in electrical engineering from the University of Nebraska.
Figure 10: An overview of the subsea control system that provides high-level diagnostics. 102 March/April 2008
This article is based on a presentation at the IADC International Well Control Conference & Exhibition, 28-29 November 2007, Singapore.
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SPECIAL MARINE EDITION
The above shows a typical BOP operating piston assembly with a transverse-mounted locking mechanism.
Design evolution of a subsea BOP Blowout preventer requirements get tougher as drilling goes ever deeper What has changed, however, and is in a constant state of flux are the operating 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 ft, 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 temperatures coming close to freezing (34° F).
By Melvyn F (Mel) Whitby, Cameron’s Drilling System Group
THE FIRST RAM
BOP was developed 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 cavity 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 cavities required to 1.
THE CHALLENGE The deepwater challenges being experienced by drilling contractors and oil companies alike are critical technical challenges that must be overcome if drilling is to move into deepwater environments
From the 1st BOP design to the present designs, the basic mechanisms have remained constant: A BOP body is sandwiched between 2 operating systems. The rams are opened and closed mechanically either by manual intervention or by hydraulically operated pistons.
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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 taking 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 handling capabilities and, therefore, require that BOP stacks be lighter-weight and take up less space on the rig while providing the accustomed functionality. In addition, existing limited capacity rigs have the potential to be upgraded for use in deepwater with higher-capability 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 environments. The industry is not just dealing with drilling mud anymore.
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SPECIAL MARINE EDITION
BOPs have traditionally evolved using conventional design methodology. Today the envelope is rapidly changing, forcing some fundamental paradigm shifts. Emerging technologies give way to new manufacturing techniques and innovation of design of operation. Sealing technology has improved radically with new materials and compounds being used to formulate sealing elements able to withstand extreme temperatures and hostile fluid environments.
RELIABILITY OF OPERATION The increased design complexity of modern-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 possible leak paths and redundancy of critical seals. In addition, control system functions can be limited and, in order to save function availability, hydraulic functions are often combined. An example of this is the integrated closing and automatic locking 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 functions. 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 reluctant to operate the locks subsea in order to prevent unnecessary unlocking problems. The locks are tested on the surface for assurance that they will operate should the situation arise. In the performance characteristics section of API 16A, API suggest that the locks be fatiguetested 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 18month 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 operation 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 mechanical detail required to make them work adequately.
FLUID CONSUMPTION, ACCUMULATOR VOLUME Fluid consumption is a double-edged sword: Less fluid typically comes at a high cost because conventional design philosophy often means that smaller pistons yield smaller force output. In deepwater applications, this force is additionally 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 operating 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 philosophy 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 factor that can affect the surface and subsea 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 wellbore 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 necessary 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 closing power can be achieved by using
D R I L L I N G CONTRACTOR
May/June 2007
37
SPECIAL MARINE EDITION
closing the BOP. With recent subsea advancements in hydraulic gear motors for torque applications, it may be time to look down this path for a simple, reliable locking operation. A number of benefits could be realized, including simplicity, ease of maintenance and reliability, to name but a few.
SUBSEA INTERVENTION CAPABILITY
An example of a 18 ¾-in. 15M subsea BOP with 18-in. operating pistons. 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 operating piston diameter reduces the effective opening ratio of the BOP, thereby protecting against accidental operation with wellbore or residual pressure in the BOP bore. In the event that opening pressure is applied in this case, the operating piston would stall, preventing potential damage to the connecting rod or ram.
The height and weight of a BOP body is determined by factors such as ram cavity height and geometry, and the operating system or bonnet design. Minimal cavity height can realize height savings but at the sacrifice of ram packer volume, 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.
LOCKING OPERATION, RELIABILITY 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 inability 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 May/June 2007
• Leak paths between critical functions should be minimized. • Redundancy of seals should be utilized wherever possible. • A means of isolating hydraulic functions to the BOP should be employed, if possible, to minimize personnel risk while conducting maintenance operations 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.
HEIGHT AND WEIGHT
• The closing piston and opening piston seals may be separated, preventing possible 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.
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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 connections.
goals, several factors should be considered:
By careful redesign of the operating system, cavity height can be increased for effectiveness while minimizing height impact. In one such case, using an 11.5in. 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 binocularstyle operating piston arrangement or an oval-shaped piston instead of the traditional 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 cavities within existing substructure height envelopes.
MAINTENANCE, OPERABILITY Ease of use and simplicity of operation and maintenance are key components to BOP design. In order to achieve these
A 3D view of a BOP operating piston assembly with transverse mounted locking mechanism. 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 complexity 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 possibility 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 maintainability of the equipment. One reasons that BOPs have changed very little over the years is that it is extremely difficult to improve on simplicity 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.
D R I L L I N G CONTRACTOR
S U B S E A
D R I L L I N G
S Y S T E M S
9
Riser System
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
Stack System
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 A N D A N D P L AT F O R M B O P C O N T R O L S Y S T E M S
Cameron offers reliable, economical direct hydraulic drilling control systems for use on land or platform. Systems are designed in accordance with API 16D Platform Control System 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, Land Closing Unit these systems provide significantly increased response time for control of surface-mounted equipment.
MUX SUBSEA CONTROL PODS
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 environments 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 MUX Control Pod 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. SUBSEA PILOTED AND DIRECT HYDRAULIC CONTROL SYSTEMS
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, fieldproven 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 Hydraulic Control Pod either the driller’s control panel, toolpusher’s control panel or touchscreen, as well as by the tertiary operator panel located on the diverter control unit.
17
M o R P H
18
D R I L L I N G
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:
C O N T R O L
S Y S T E M
Toolpusher’s Control Panel Driller’s Control Panel MoRPH Umbilical Reel Hydraulic Interface
• 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.
MoRPH CONVERSION REQUIREMENTS Existing Equipment
MoRPH System
Driller’s and toolpusher’s control panels, surface wiring, manifold, accumulators, pumps, reservoir, UPS, surface hose umbilicals, guide arms, BOP and LMRP plumbing, shuttles valves, etc.
Use as is
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
Umbilical Clamps
LMRP, FITA and Clamp assembly
Electric/Hydraulic Flying Leads
MoRPH Pod
Existing Hydraulic Pod
Subsea Stack
Complete MoRPH system
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 potentially require use of emergency backup systems: operator initiated procedures, emergency mitigated by loss of main
19
controls and major catastrophes (such as damage to the riser system). Cameron offers a variety of emergency, backup 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.
EDS (Emergency Disconnect Sequence)
Acoustic
ROV Panels
A system to close the rams with a programmed sequence of events when a button is actuated by an operator.
A system to activate a limited number of functions from the rig when no other communications are possible.
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)
Automatic Disconnect System
Autoshear
A system to automatically close the shear rams when there is catastrophic loss of the riser systems.
A system to automatically close the shear rams when the riser angle exceeds a certain predetermined limit.
A system to automatically close the shear rams when there is an unplanned disconnect of the LMRP
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Standard
Tandem
Pipe Bonnet
Pipe Bonnet
Close Pressure
Open Pressure
Close Pressure
Shear Bonnet
Open Pressure
Shear Bonnet
UM BOP Open and Close Hydraulics (13-5/8” 10,000 Shown) SD 034582
TC1542
20
UM BOP Operating Data and Fluid Requirements Bore Size and Gals to Open Pipe Rams Working Pressure (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 Gals to Open Pipe Rams Working Pressure (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
A
C
D
G
B F
E
UM BOP Assembly, Single with Tandem Boosters SD 034566
TC1542
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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]
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