[For abstract and indexing, see Abstract #1,267,524]

The platform air gap (the distance from the sea level to the underside of the topsides) is a critical design parameter intended to prevent topsides inundation during storm wave events. Design codes such as API RP2A assess the air gap using the 1,000-year return period crest elevation combined with storm surge effects. Platform loads (shear and overturning moment) can increase by between 50% and 100% when the storm crest elevation exceeds the air gap and inundates the structure of the topsides. The consequences of a storm wave impact on a platform's topsides can be catastrophic. This was graphically shown by the collapse or near destruction of a number of offshore structures in the US Gulf of Mexico (GOM) during hurricanes Ivan in 2004 and Katrina and Rita in 2005. Approximately 250 significant structures, including eight-leg drilling and production platforms in water depths of up to 450 ft, were destroyed by these storms collectively. The air gap may be insufficient because of an increase in design wave height or platform settlement as a result of reservoir compaction.

Expandable reamers were developed to improve efficiencies and reduce risk while drilling through problematic formations in deep water and other offshore wells. Lean-profile well designs were implemented to enable operators to drill faster and more efficiently, with better well control and less material, within a narrow pressure window between formation fracture and shale collapse. Using this concept, the well is drilled using the smallest possible hole sections and minimum clearances between casing strings. This allows access to the reservoir with a larger-diameter hole to increase production flow rate or access to additional reserves that otherwise would be unreachable because of their extreme depth. Lean-profile wells require rotary steerable systems to create smooth wellbores and expandable reamers to manage equivalent circulating densities and maintain wellbore stability while enlarging the hole under the casing sufficiently to allow reliable cementing. The first concentric expandable reamers were ball-activated. Once expanded, they could not be closed without stopping circulation. The second iteration was modified so that the reamer could be deactivated to allow circulation after reaming for better hole cleaning.

For the past several years, automated drilling has promised to deliver major improvements in drilling performance. However, the technology is facing new obstacles that might affect its progress and commercialization. Globally, there remain significant shortcomings in the capabilities and availability of rig crews, which underpin the need to deliver automation in the near future. Whether the goal is met rests on the shoulders of a small group of early adopters and innovators. If successful, their work will bring about a major departure from how drilling systems are designed and operated today by proving that, with data and algorithms in the driller's seat, drilling can be made safer, more consistent, and ultimately cheaper by way of reducing nonproductive time (NPT).

The challenges encountered in deep-water development have led to the use of increasingly complex subsea systems. Consequently, operators have become more reliant on subsea monitoring equipment and instrumentation to provide field information for understanding production and equipment conditions. Production monitoring is typically the field operator's main priority, and equipment condition and performance are sometimes overlooked, resulting in equipment failures and long production downtimes because of unplanned maintenance. Equipment failures often occur without warning and may sometimes, when caused by environmental factors, become inevitable. To determine the cause, field operators sift through vast amounts of distributed data from the subsea control system. The system downtime can be reduced and system availability can be increased by performing an effective equipment diagnosis. With the current low-oil-price environment, subsea operators are looking to maximize returns on investment, and condition-based monitoring offers the possibility of lowering operational expenses while increasing field production.

[For abstract and indexing, see Abstract #1,239,075]

An ongoing research project started nearly three years ago by the US Department of Energy's National Energy Technology Laboratory (NETL) is shedding new light on what really happens to foamed cement as it is pumped deep down offshore wells during completions. After six months of interviewing experts in the offshore industry, lead researcher and NETL scientist Barbara Kutchko, who served as an objective expert in the federal litigation over the Macondo incident, decided to focus on foamed cement based on the clear need for more information about how the technology performs outside of the laboratory. Cement specialists who are lending their expertise to the research said initial findings confirm long-held theories about how the 25-year-old technology performs. As the work progresses, they also said it may result in improvements in how foamed cement is made and applied.