The increasing complexity and often transboundary scope of complex emergencies are exceeding the capacity of humanitarian logistics systems. The military plays a growing role in supplementing and even leading humanitarian assistance and disaster relief logistics. However, issues relating to military involvement such as sovereignty and cost have refocused the conversation onto capabilities and capacities of commercial logistics providers, who have not been fully engaged and integrated into disaster preparedness, response, and recovery activities. The commercial sector is part of the larger supply chain management system that includes contracting, procurement, storage, and transportation of food, water, medicine, and other supplies, as well as human resources, and necessary machinery and equipment. Military and commercial logistics share many of these elements and tasks daily. The most effective and efficient response combines key elements from humanitarian, military, and commercial logistics systems. Such trilateral cooperation represents the next step in an evolving partnership paradigm that is truly synergistic. We present a Synchronized Disaster Relief Model, as well as multiple examples of how military, commercial, and humanitarian supply chains each bring unique capabilities to disaster relief operations, and how these three supply chains can complement each other in a synergistic manner, through synchronized action.

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Industry standards (API and MSS) for subsea blowout preventers (BOPs) requires ram BOPs to close within 45 seconds and annular BOPs within 60 seconds; however, it is an industry goal to close these critical functions as fast as is practical (1). Most existing subsea BOP control systems are Piloted All-Hydraulic. Directional control valves in the control pods on the subsea BOP stack are controlled via hydraulic pulses (pressure up and/or bleed off) through 3/16-inch ID pilot hoses. The directional control valves shift time is heavily dependent on the hose length, among other factors. Thus the pulse time to shift the valves is fairly constant regardless of the water depth, given that the umbilical length remains constant for a given outfitting of a Mobile Offshore Drilling Unit (MODU). Calculations and empirical data suggest that a typical subsea Piloted All-Hydraulic Control System, even with the faster "pressure-bias" type modification, has trouble meeting desired closing times when functioning through approximately 5,500 ft or more of control umbilical. In ultra deepwater depths (over 5,000 ft), electronic coded signal or Multiplex (MPX) systems have been used almost exclusively to solve reaction times; however, they have certain disadvantages. MPX system are very expensive, complicated, time consuming to troubleshoot and repair, and are impractical to economically retrofit to existing MODUs and BOP stacks. A newly patented (2) hybrid Electro-Hydraulic (EH) Control System has been developed that is readily retrofitable to Piloted All-Hydraulic Control Systems for deepwater upgrades. It utilizes the existing driller's and toolpusher's panels, pump/accumulator unit, UPS, most of the rig's electrical wiring, existing rig top side hydraulic umbilicals, both subsea pods, pod retrieving frames and, in all likelihood, requires no modifications to the BOP stack or its frame. The new concept centers around running electrical lines to critical solenoid pod functions (rams, annulars and possibly connector release) that are very time dependent and hydraulic pilot lines to all other non-critical time dependent functions. A module consisting primarily of solenoids and hydraulic/electrical connectors is packaged to fit on top of the existing all-hydraulic control pod. The overall "kit" is designed to be placed aboard the MODU and BOP stack during a long rig move or short non-shipyard installation. The EH Control System uses existing field proven technology and components. It can be used with or without guidelines. The subsea control pods can be retrieved on guidelines or via ROV with guidelineless drilling systems. This is very advantageous compared to existing deepwater MPX systems in that the marine riser and LMRP does not have to be retrieved in the event of an unplanned repair. The umbilical (less weight and OD than standard all-hydraulic umbilicals) can be run on guidelines or on the OD of the marine riser. The umbilicals have ROV remote mateable make-and-break junction boxes on the pods. The overall response time for critical functions of the EH Control System is as fast as a MPX system at a fraction of the capital and installation cost. It is technically simple and can be serviced easily by any qualified rig electrician. The EH Control System is very compatible with the Slim Riser concept, is retrofitable to any standard Piloted All-Hydraulic Control System, compactable with new build project, and can replace a MPX system.

This acoustic ball-joint angle and azimuth indicator has proved, in deep water and in severe weather, that it can monitor reliably and directly the structural integrity of the riser. The knowledge it provides of the ball-joint angle can give the operator the confidence to delay or avoid disconnecting the riser without fear of adverse consequences. Introduction The two prime objectives of the riser are to provide a return path for drilling fluids and to guide tool assemblies in and out of the wellhead. Because of its important role in maintaining well control and its high initial cost, strong efforts are made to prevent overstress, excessive fatigue, and excessive internal wear. In the brief 16-year history of floating drilling, risers of various types have been used, with the most common and successful being the single-wall tensioned riser. Through improvements in design, construction, and operating technique, the single-wall tensioned riser system has been used successfully and with confidence in water depths up to 1,500 ft. In general, the riser system (Fig. 1) is composed of a hydraulic riser connector that fastens the riser to the blowout preventers (BOP's), a lower pivot point (ball joint) next to the riser hydraulic connector, a number of joints made of pipe with end connectors, a slip joint that allows vertical motion between the drilling vessel and the riser, a gimballed connection of the inner barrel of the slip joint and the vessel, and a means of applying tension to the riser. In deep water the addition of a ball joint below the slip joint can reduce riser stress and fatigue. There are a number of excellent papers on the prediction of the behavior of risers and on criteria prediction of the behavior of risers and on criteria for successful riser design. These papers all show that the forces resulting from wave action, current action, riser weight, drilling fluid density, horizontal offset of the fluid density, and horizontal offset of the top of the riser from the wellhead tend to increase riser stress and to deform the riser. These forces are resisted by tension applied at the upper end of the riser and in some cases by the addition of buoyant material to the riser. In general, available methods are used to calculate the tension that should be used with a given set of assumed maximum conditions. If the actual conditions are less stringent than the assumed conditions, the resulting tension causes unnecessary wear and reduces the life of the tensioning system. If actual conditions are more stringent than assumed conditions and the tension is not increased accordingly, overstress, excessive fatigue, or excessive internal wear may result. Riser operations are particularly vulnerable to unfavorable changes in ocean particularly vulnerable to unfavorable changes in ocean current profiles, which are difficult to measure, especially during critical times. Studies based on the calculational methods described by Tidwell and Ilfrey showed that the angle of the riser with the vertical at the lower ball joint is directly related to the maximum stress in the riser. In essence, the angle of the ball joint shows the net effect of all the forces acting on the riser. For a given riser operating under a given set of conditions the angle of the lower ball joint is related to vessel offset and applied tension. Therefore, if that angle and its azimuth could be continuously monitored, the angle could be controlled by manipulating vessel offset and applied riser tension so as to minimize riser stress, fatigue, and internal wear. JPT P. 337

SPE and IADC Members Abstract For the past 2 1/2 years and over 250, 000 MODU operating hours, which included up to 8 floating drilling rigs and 17 bottom sitting drilling rigs, downtime data was inputted into a defined matrix for analysis. By use of 6 categories (drilling, subsea, mechanical/electrical, etc.) and 5 causes (operation, manufacturer/warranty, maintenance, etc.) of downtime a 6 by 5 matrix was developed to pinpoint fleet wide as well as individual rig pinpoint fleet wide as well as individual rig problem areas. Downtime data was inputted into the problem areas. Downtime data was inputted into the computer weekly as well as accidents, lost time accidents, rig status and "flags" of interest that include up to 100 different printout options. Each downtime incident has a succinct description with corresponding corrective action. The system has proven objective, useful in spotting problem areas, proven objective, useful in spotting problem areas, and with its strict definitions very repeatable. With the aid of the downtime system and reinforcement by the companies Preventative Maintenance Program, downtime LTA's and accident rates have all decreased. Introduction For years Drilling Contractors have tried to keep and show downtime statistics for internal as well as external (customer) use. Downtime can be highly interpretive and subjective with results historically dictated by the anticipated end use. For example there is contract downtime", "operating downtime", "trouble time", etc. all of which when evaluated give drastically, non-comparable results. To avoid biased, favoritism or subjective analysis requires a clear, definitive definition of rig downtime. The brief definition of downtime is non-productive operating time caused by equipment and/or personnel failure either by the contractor, operator or third parties- This paper will define downtime and how contractor downtime incidents are classified. The paper will discuss usage of the computer to manipulate the data and present several output and trend analysis curves. Finally this paper will examine uses of the information along with the authors conclusions. DOWNTIME DEFINITION If the rig is delayed from conducting normal operations due to personnel or equipment failure then downtime has occurred and should be included in the database. Five major exceptions are:Preparing for a hurricane, evacuation, and time spent putting the rig back in operation is not included in any way in the database.Fishing for downhole tools/tubulars regardless of the cause is not considered downtime.Circulating out a kick is not considered downtime.Waiting on cement is also not considered downtime.Other problems that are not caused by equipment or personnel directly. Contractor and Non-Contractor downtime is listed. The entire scope of time is listed for each incident not just the repair time. If a repair requires pulling up into the casing, making a repair and tripping back to bottom, then the incident's time would include that short trip.