fax 01-972-952-9435. AbstractMany 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).

Category: Deepwater Drilling or Case Studies 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.

As a result of the offshore oil and gas industry's ongoing expansion of technology frontiers, ever more challenging conditions are being explored. This paper is based on the research completed for the MMS (Minerals Management Service) titled, Assess the Acceptability and Safety of Using Equipment, Particularly BOP and Wellhead Components, at Pressures in Excess of Rated Working Pressure. Due to space limitations, limited content was selected from this project. The full text of the project will be available when published on the MMS website. With the exception of pressure testing, it is most unusual and almost universally considered a poor practice in the industry to use BOP (Blow Out Preventer) and wellhead components in excess of MWP (Maximum Working Pressure). In most cases, API (American Petroleum Institute) Specifications and Recommended Practices are acceptable relative to defining MWP. These and other industry standards use defined safety factors that are reasonable and not subject to inadvertent escalation or compounding. In contrast to operating equipment in excess of MWP is the ongoing concern about operating above equipment capability in its current condition. BOP equipment pressure de-rating is used in the industry, particularly when equipment fails to pressure test at its rated working pressure. This paper identifies factors that may compromise equipment pressure ratings so that the risks of exceeding current capabilities can be assessed. It is clear to the authors that the most successful and highest reliability systems are those that are systematically and consistently operated and maintained with clearly defined, quality controlled procedures by trained technicians, and tested as closely as possible to the expected operating conditions. This is consistent with reliability engineering principles. The highest value program of this sort will be performance based. Introduction The MMS is aware of exploration drilling prospects where reservoir conditions are as high as 28,000 psi. As current drilling and production standards frequently seek to utilize large bore drill through equipment, a limitation is encountered as there are no 18 3/4" BOPs with a working pressure in excess of 15,000 psi. With the current high commodity prices, the industry is exploring possibilities for using or modifying existing equipment to be fit for exploiting these opportunities more quickly. Additionally, to address the nameplate rating limitation and expand industry capabilities, an API work group has been formed to create a recommended practice for equipment rated above 15,000 psi. However, the expansion of this technical envelope will take time. Historically, occasions of use (outside of subsea testing) in excess of MWP were almost exclusively limited to accidental or emergency use. MASP (Maximum Allowable Surface Pressure) is a separate area where there are no industry standard safety factors; such should be developed and integrated with equipment safety factors for a single, composite factor. Although reviewed in the MMS research, MASP will not be covered in this paper. This paper, as with the research project, focused on two areas:Design, manuacture, and initial use, andCapabilities over time, including remanufacture and modification.

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. Introduction In an industry historically plagued with higher than average safety incidents, familiarity can breed an atmosphere of reduced attention to detail in the areas of both operation and maintenance. In particular, land drilling activities with over-emphasis on cost containment by the contractor in response to falling profit margins can proceed for quite some time as tributes to human ingenuity. However, the cumulative effects ultimately negatively impact operations, sometimes catastrophically. Each of the case studies reviewed herein were undertaken as a result of catastrophic incidents. A survey of the rig provided the data from which the most likely failure sequence was deduced. Prevention focused recommendations were then provided based on comparisons of rig performance compared to industry standards and observed "best practices" from similar operations. Case Study Information The incidents that resulted in these case studies all occurred in 2003 with land rigs operating in the United States. Mast Collapse While Drilling During routine drilling, a chain of events rapidly occurred that resulted in the catastrophic collapse of the mast shown in Figure 1. Data The incident investigation began with an inspection of the failed structural members. Figure 2 shows the weld between the forward driller's side leg and the substructure. As illustrated quite clearly in Figure 2, the failed weld exhibited numerous corrosion pits in the weld proper, indicating both cracks and porosity. The red lines in this figure indicate the nominal original placement of the detached leg. This, combined with the condition of the separated leg with no obvious deformation, confirms weld separation. Figure 3 illustrates the plastically deformed mounting bracket and plate (red arrows) from the opposite forward leg. The padeye retainer pin being pulled up into the drill floor mounting plate in conjunction with observed deformation provides evidence that high torsional loading of this connection existed.

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