WEST pioneered the business of 3rd-party assessments of well control equipment and is still the preeminent leader in this field, with thousands of BOP/well control surveys. WEST is also an industry leader in survey assessments of drilling systems on rigs of all kinds, from ultra-deepwater to land rigs. These assessments cover a wide range of equipment and activities, such as:
Nothing is more frustrating than having new equipment and then finding that it does not work as you envisioned. Highly experienced WEST personnel will oversee, commission and accept new construction. When needed, WEST's engineering expertise may be called upon. Project management services are also available. Working with manufacturers, integrators and shipyards, these WEST personnel ensure that the equipment is fit for your purpose.
IADC/SPE Conference Presentations
WEST has presented several papers at various IADC/SPE conferences. The abstracts below summarize this information. If you would like additional details, please contact us. To obtain a complete copy of any of these papers, visit the SPE Library.
- SPE 119762 Pull Your BOP Stack - Or Not? A Systematic Method to Making This Multi-Million Dollar Decision
- SPE 119777 Drilling At The Limit, Can Your Top Drive Handle It?
- SPE 87957 Avoiding Drilling Equipment Downtime - Four Case Studies
- SPE 87157 Qualitative Risk Analysis of Emergency BOP Control Systems to Ensure Availability
- SPE 79837 Dropped BOP Stacks: Understanding Causes to Improve Prevention
- PE 74471 Using Predictive Testing to Circumvent Blowout Prevention Equipment Downtime
- SPE 74469 BOP Subsea Hydraulic Accumulator Energy Availability,
How to Ensure You Have What You Need - SPE 36391 Certification - The Same as Fitness for Purpose
Avoiding Drilling Equipment Downtime - Four Case Studies
Occasionally, equipment issues drift out of focus as long as the drill bit keeps turning to the right and no "incidents" are recorded, particularly when activity levels and utilization rates are high. Unfortunately, it sometime takes a significant event to regain compliance with established operating and maintenance policies and procedures. Investigations were undertaken as a result of events that occurred on four rigs. This paper will outline these incidents, describe the root causes determined, and delineate recommended steps that might be taken to prevent similar events.
Qualitative Risk Analysis of Emergency BOP Control Systems to Ensure Availability
Many of the latest generation of ultra deepwater capable rigs included emergency BOP (Blow Out Preventer) control capabilities, sometimes referred to as secondary intervention systems. Such systems represent the last line of defense in containing a well. Should it be necessary and unavailable, the result could be environmentally and humanly catastrophic.
Building on installations that have been in service for many years, these capabilities range in functionality and purpose, from providing an alternate means to operate BOP functions in the event of total loss of the primary control system to assisting personnel during incidents of imminent equipment failure or well control problems. They can be actuated automatically or manually, and utilize components of the primary BOP control system or be totally independent. With as many permutations as there were rigs built, an understanding of the capabilities and limitations that exist on a particular rig is of critical importance in assessing the risks associated with a drilling program.
While there currently are no standard terms in use to describe the essential attributes of systems, this paper recommends definitions and terms for a common understanding. The defined terminology is then utilized to compare and contrast system parameters, identifying various system strengths and weaknesses for use in risk analyses.
Possible enhancements to existing emergency control systems will then be discussed, as well as their benefits and anticipated costs. Finally, the paper will recommend best practices for moored rig operations and those for operations utilizing DP (Dynamic Positioning).
Dropped BOP Stacks: Understanding Causes to Improve Prevention
Although thankfully not a common occurrence, when a BOP stack is dropped, it is most often a catastrophe. With the understanding of the causes of dropped stacks provided in this paper, one will be able to identify specific steps to minimize the likelihood of this type of failure on future projects in any floating drilling operation.
Every dropped BOP stack is a significant event for all parties involved in the drilling program. In many cases, the retrieval process and subsequent equipment review to identify and rectify damage results in significant delays. The severity is further exacerbated if the dropped object lands on production equipment in the case of development drilling. As a result, a major operator conducted a study for a world class development project to enable them to identify and mitigate prospective dropped objects, with the primary emphasis on dropped BOPs. This paper will:
- categorize causes of documented dropped stacks and significant near misses,
- identify root causes within each category, and
- recommend steps that can be taken to reduce the likelihood of recurrences.
Unfortunately from a quality enhancement perspective, difficulties in the drilling industry are neither well documented nor widely circulated. This makes gathering information difficult. Nevertheless, the 219 cumulative years of industry experience of eight WEST staff was pooled to identify both incidents and near misses. To the extent possible, contact was made with other individuals who had personal involvement with the incident under investigation. Because this methodology in general is subject to the recollections of the parties involved rather than documented analyses, one might not be surprised to learn that some of the details could be somewhat inaccurate. Nevertheless, the author believes that the major issues surrounding significant events such as dropped stacks are retained with a high degree of accuracy, thus supporting the validity of the overall conclusions.
Using Predictive Testing to Circumvent Blowout Prevention Equipment Downtime
Pulling the blowout preventer (BOP) stack or Lower Marine Riser Package (LMRP) on a floating drilling rig has always cost everyone involved a lot of money. However, when operating in the ultra-deepwater theater, those costs regularly exceed $1,000,000. As a result, developing and utilizing methods to ensure operative BOP equipment and systems continues to grow in importance to avoid this significant trouble cost.
The first known field predictive test on BOPs was conducted on ram locking systems in the North Sea in 1987. Since that time, the tests have been refined to identify other modes of failure so they can be corrected while on the surface, providing increased assurance of their ability to function when they are needed on the wellhead. Additionally, predictive tests have been devised and their effectiveness demonstrated on ram locking systems, connectors, annulars, failsafe valves and control systems.
This paper will outline each of the predictive tests developed and validated from field testing and working with equipment manufacturers, describe the principles upon which they are based, and provide case study examples where they have proven to identify pending failure.
BOP Subsea Hydraulic Accumulator Energy Availability, How to Ensure You Have What You Need
Blowout Preventer (BOP) hydraulic control systems have long used accumulator bottles to deliver energy to function equipment more quickly than the pumps can alone. With the advent of subsea stacks, people recognized the need to modify these accumulators and the operating procedure to reflect the effects of hydrostatic head. The continued expansion into deeper waters, coupled with an increase in the system operating pressure for the latest generation rigs, has necessitated new methods of calculating energy available in subsea accumulators.
Traditional accumulator calculations and regulatory standards assume isothermal (constant temperature) ideal gas behavior. Operating in deeper water and advances in shearing requirements and tubular strength affects the pressure required to operate BOPs. At the same time, API standards committees recognized the inaccuracies associated with these assumptions, and provided adequate safety factors in their standards to compensate. However, there are no guidelines at this time for how much energy is to be maintained in accumulators subsea. Changes to the operating environment today, combined with new operating sequences, e.g. deadman, autoshear, have made a good understanding of the science driving the operation of these accumulators a mandate.
This paper reviews the impact of subsea accumulators on fifth generation floating drilling rig BOP operation, energy requirements such accumulators must deliver, and different ways of calculating such energy. It concludes with an easy-to-use recommended method that reflects the specific operating requirements of a given rig and drilling program.
Certification - The Same as Fitness for Purpose?
Classification and certification are not the same, and fitness for purpose may or may not be determined by either. This paper compares and contrasts classification, certification, and fitness for purpose. Included are not only the general policies and definitions used by the major classification societies, but also how these services fit into the various quality certification schemes like ISO and API. As a result, when you have a need for third party verification of "quality", you will know what you should specify and the correct terminology used by those in this industry.
Definitions
An "administrative" item of ongoing concern for offshore rig owners is classification of their rigs and the equipment installed on them. This is required to maintain insurance coverage, as well as compliance with various regulatory bodies governing drilling activities around the world. What this exactly covers, and the relationship between classification, certification, and fitness for purpose is not clear for many people.
Accordingly, the first step is to review definitions. From that point, it will be easier to differentiate these procedures, as well as determine what benefits you can expect when soliciting and engaging these services.
Classification
As an early initiative toward maritime loss prevention, early ship owners banded together in groups to self-insure their vessels and cargo. These groups or insurance "clubs," established in the UK, Scandinavia and elsewhere, decided to form independent technical organizations, now called classification societies, that would provide standards and inspections for ships to be sure that they were built and operated in accordance with "agreed to" safety standards. There were no existing standards so classification societies published "Rules." There are a number of international classification societies, the three major ones involved with the offshore exploration and production industry are Det Norske Veritas (DNV), American Bureau of Shipping (ABS), and Lloyd's Register of Shipping (LRS). These companies are all more than 130 years old, with Lloyd's being the oldest, dating from about 1800.
Initially, there were various levels of classification which were reflected in different insurance rates. Most vessels are today classed with a notation +1A1 which indicates that the vessel is built and maintained to the highest standards of the particular classification society. Therefore, strictly speaking, when the word classification is used today, it references a set of standards established and maintained by a specific classification society.
For example, classification based on DNV rules and the related certification imply fitness for purpose in the sense that DNV approves the completed "object" and certifies (reviews, inspects and tests) all the systems. Thus all power, safety, control, drilling, etc. systems will be certified as both safe and fit for purpose. DNV is not a designer or operator and thus will not influence operational factors such as reliability and efficiency.
Certification
Certification may be defined as steps taken to confirm that an "object" satisfies specific standards. "Object" can be a complete platform, ship, or drilling semi-submersible; it can be a system within these vessels or one component of a system. The object also could be "the most basic" part of a component, i.e. the steel, the electrical cable, etc.
Certification may or may not insure fitness for purpose, depending on a number of factors. Because of this, it is the responsibility of those designing or using an object to understand what is implied by its certification.
Using Predictive Testing to Circumvent Blowout Prevention Equipment Downtime
Pulling the blowout preventer (BOP) stack or Lower Marine Riser Package (LMRP) on a floating drilling rig has always cost everyone involved a lot of money. However, when operating in the ultra-deepwater theater, those costs regularly exceed $1,000,000. As a result, developing and utilizing methods to ensure operative BOP equipment and systems continues to grow in importance to avoid this significant trouble cost.
The first known field predictive test on BOPs was conducted on ram locking systems in the North Sea in 1987. Since that time, the tests have been refined to identify other modes of failure so they can be corrected while on the surface, providing increased assurance of their ability to function when they are needed on the wellhead. Additionally, predictive tests have been devised and their effectiveness demonstrated on ram locking systems, connectors, annulars, failsafe valves and control systems.
This paper will outline each of the predictive tests developed and validated from field testing and working with equipment manufacturers, describe the principles upon which they are based, and provide case study examples where they have proven to identify pending failure.
Drilling At the Limit, Can Your Top Drive Handle It?
As deepwater drilling has advanced, the weight expected to be borne by a top drive has increased to levels at or near the load rating of the machine. The single load rating number normally associated with a top drive model (e.g. 1,000 tons) is a nominal figure that may not apply to every operating situation. A typical top drive has two main load paths: hoisting and drilling. Hoisting load passes through the elevators and link hanger, while drilling load passes through the saver sub, IBOPs, and main shaft bottom end connection. Limitations inherent to rotary shouldered connections can lead to diminished drilling load capacity vis-à-vis hoisting. Further complicating matters is the fact that the drilling load path is governed by disparate API specifications: 7 and 8C. These two specifications provide different calculation guidelines with regard to safety factors and are subject to a certain amount of interpretation.
The end result is confusion about how much load a top drive can realistically handle. A 1,000 ton top drive may not be officially rated to hoist 1,000 tons through its IBOPs. Additionally, API sets forth a different load rating for the swivel bearing, so load rating for rotation differs from overall top drive load rating. This paper discusses the technical aspects of top drive load rating and clarifies the usable load capacity of a top drive in real-world conditions.
Pull Your BOP Stack - Or Not? A Systematic Method to Making This Multi-Million Dollar Decision
Pulling your BOP stack, particularly in deep water, is one of the singularly most costly events in the drilling of a well if it occurs. While in most cases this course of action is correctly undertaken, occasions occur when the stack pull could have been avoided. These regrettable incidents occur for a variety of reasons, including inadequate information and/or staff training, unclear understanding of regulatory or company requirements, and non-availability of experts to assist in the decision making due to time zone differences, among others. This paper presents several case studies where planned stack pulls were circumvented or could have been, as well as a systematic protocol that can be developed prior to starting a well to define the decision making process for stack pulls for your specific program.
