Casing wear is often a problem in deep wells where doglegs and large tension loads on the drill string combine to produce high lateral loads where the drill string contacts the casing. Casing wear can result in blowouts, lost production, and other hazardous and expensive problems. A mathematical model which describes casing wear in terms of hole geometry, casing/tool-joint material, mud system, and drilling program, has been developed and verified. Over 300 laboratory wear tests have provided wear factors which allow the model to be applied to a wide range of drilling situations. The model has been incorporated into a computer program, CWEAR. The prediction of dogleg severity and casing wear is seriously compromised by directional surveys in which the station spacing is 100 ft or greater. Through the laboratory test program, means to reduce casing wear rate have been demonstrated and applied in the field. Mud lubricants, tool-joint materials, pipe protectors, and casing materials and internal coatings have all been examined as possible means to reduce casing wear. Some mud lubricants significantly reduce frictional drag; others do not. Because a mud lubricant significantly reduces frictional drag does not imply that it will also reduce the casing wear rate. Newer, proprietary tool-joint coating materials have proven effective in reducing casing wear, while continuing to protect the tool joints in open hole. Pipe protectors have proven to be one of the better means of reducing casing wear. Laboratory experiments have demonstrated severe operational difficulties of these protectors. Several of the protector manufacturers are now engaged in development programs to improve their products. Inadequacies in the available methods of measuring casing wear in the field have been demonstrated. As a result of this work, at least two new casing wear measurement tools are under development. GOALS OF THE PROJECT The goals of our casing wear technology project are to:Predict Casing WearMeasure Casing WearReduce Casing WearPredict Burst and Collapse of Worn Casing To predict casing wear requires a mathematical description of the casing wear process. To implement this model requires experimental determination of the wear factors which are an integral part of the casing wear model. Such a model has been developed and verified. The model has been incorporated into a computer program, CWEAR, which has been used as both a planning and operational tool. More than 300 laboratory tests have been performed to determine wear factors which allow the model to be applied to a wide range of well geometries and drilling programs. Measurement of casing wear in the field has proven to be poor at best. Experimental evaluation of casing wear logging tools showed the need for improvement.

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In the pre-Macondo blowout era the offshore industry had an impressive record of safety, especially considering the complexity and magnitude of the work being done in relatively harsh conditions. The failures and spillages of Macondo have indicated that there are a number of safety areas which have not received appropriate progress in large part because history had not experienced a major failure of a BOP stack at that depth of water. This paper addresses several areas of technology which can be implemented to increase safety on new deepwater drilling BOP systems or retrofitted on current BOP systems in the field. These safety areas include better use of accumulator capacity, greater control over BOP stack functions, more redundancy of control, and improved ability to shear wellbore components. The ready availability of these safety upgrades and methods for full BOP Subsea operation and control, high volume ROV operations, and shearing drilling collars represent significant upgrades to Subsea drilling equipment safety systems post Macondo. Depth Compensated Accumulators Depth compensated accumulators represent a major safety improvement post-Macondo, although they were already seeing market acceptance before Macondo. The problem with accumulators on Subsea stacks is that more than 100 accumulator bottles would be needed instead of approximately seven for the depth compensated version1. Additionally, the depth compensated accumulators can be retrofitted on the ocean bottom by using multiple frictionless controls, also a major safety upgrade presented later in this paper. The basic concept as seen in figure 1 is that a dumbbell piston has pressurized nitrogen in the top chamber and working fluid immediately below in a second chamber. The second chamber is divided from the third chamber by a central, stationary bulkhead. The third chamber is pressurized with environmental pressure, typically through an intermediate fluid for corrosion reasons. The fourth lower chamber is basically empty or a vacuum. This means that the pressure in the third chamber is not supported from below, but rather is mechanically added to the pressure in the second chamber. This means that at any depth, the pressure in the second working chamber exceeds environmental pressure by the amount of the nitrogen charge. Increased safety impacts of depth compensating accumulators are:High nitrogen (or helium) pressures associated with conventional accumulators in deepwater situations are not required. As the piston area in chamber 2 is slightly less than the area in chamber 1, the nitrogen pressure never exceeds the working fluid pressure.Complex calculations are eliminated, the accumulators are simply run and operate subsea similarly as they operate on the surface.When the accumulator comes to the surface, dumping the nitrogen in the accumulators is not required.When the accumulator is re-run, the nitrogen does not have to be recharged,There is no danger that only some of the nitrogen banks have been recharged, but not all of them.

This paper discusses specialized completion tools and techniques developed while drilling and completing the open hole sections of 20 horizontal gravel packs and 3 Level 5 multi-lateral wells completed in Campos Basin, offshore Brazil. The discussion covers wellpath planning, pumping operations, wellpath selection, multilterals, the use of extended-longevity well screens, floating rig operations, and fluid systems to prevent formation damage. Open hole horizontal wells are attractive in ultra-deep water because the approach eliminates a liner and allows a larger casing string at the reservoir. This method also provides extensive reservoir exposure. Couple this technology with multi-laterals and a significant reduction in the number of wells to adequately drain the reservoir may be achieved. Twenty open hole completions have been successfully performed in the deepwater Marlim field offshore Brazil. These include both gravel- and non-gravel-packed completions in horizontal producers and injectors. Additionally, three Level 5 multi-lateral wells with open hole completions have been successfully installed in the same field. Multi-lateral (ML) completions have been classified as Levels 1 through 6, depending upon junction functionality. Only Levels 5 and 6 pertain to this discussion. Only Levels 5 and 6 provide pressure integrity at the junction. Level 5, a cased and cemented main bore and laterals, achieves pressure isolation at the junction with packers. Level 6 is similar to Level 5 except that pressure isolation at the junction is achieved using the casing. Introduction The economic viability of deepwater projects requires effectively draining the reservoir with a minimum number of wells. The completion types of choice are either long horizontal wells or multi-lateral completions.4 In unconsolidated formations, it becomes necessary to control sand production to effectively produce the reservoir. Open hole gravel packing has been gaining in popularity as the preferred sand control technique for horizontal wells. Significant advances have been recently achieved to substantially extend the length of laterals that can be successfully packed (with lengths exceeding 1000 meters being relatively common). Technology is also under development to reduce the negative effects associated with the presence of hydratable shales in the production interval. The fact that gravel packing helps to minimize well interventions and risk if planning and execution are properly carried out leads to this completion type being very desirable to deepwater applications. While stand-alone screens are often used for this purpose, it has become clear that gravel packing extends well life as required for economic viability of deepwater installations.5,6 Petrobras has been employing open hole gravel packing as well as stand-alone screen completions in their horizontal well and multi-lateral completions in the Campos Basin (Figure 1).1,2 To date, 20 horizontal open hole gravel packs and 3 Level 5 multi-laterals have been successfully installed from floating rigs. Both of these innovations were the first of their kind. With the success of isolated junction technology, both laterals of a Level 5 or Level 6 multi-lateral well can be effectively gravel packed. This can provide extended well life and improved reservoir management. Additionally, with the proper use of inflow control devices, relative flow from each branch of a multi-lateral can be controlled. The Campos Basin, home for 61 separate fields (seven of which are classified as giants)7 in water depths ranging from 100 to 2,000 meters, is one of the major deepwater developments in the world. In this challenging environment, Petrobras first performed horizontal gravel packs in water depths exceeding 700 meters, and the first Level 5 multi-lateral wells were constructed from a deepwater floating rig. For both of these applications, operating from a floating rig in a deepwater environment posed significant challenges that had to be overcome. In particular, successful horizontal gravel packing required that hole cleaning be effectively employed (even with the presence of a long, large-diameter riser).

Fiber optic sensors are currently being deployed in novel completions throughout the world. The first completions being targeted are wells where specific problems associated with temperature need to be addressed. Fiber optics provide unique solutions in challenging environments in both existing fields and new frontiers such as deepwater. Fiber optics provide a high degree of reliability as no electronics are deployed downhole. Reliability issues are especially important in deepwater applications to reduce risk associated with high failure rates. Having an inherent tolerance for high temperature, fiber optics can provide distributed temperature data at one-meter intervals throughout the wellbore and the flow conduit. Due to their long data transmission length (12km), fiber optic systems have the potential to provide unique solutions to problems encountered in deepwater environments. This paper discusses the current state of fiber optic distributed temperature monitoring and shows how this technology can be employed in deepwater situations. Temperature measurements at one-meter intervals along the entire flow conduit allow operators to:Define inflow performance without well intervention, thus reducing operating expenseDetect and monitor the progression of water coningDetermine flowing temperature at various positions in the well to help avoid phase change problems such as paraffin or hydrate deposition. Through early detection of these and other problems, operators can make changes in production profiles or chemical injection programs to minimize the effects of the problem and increase overall wellbore performance. Case histories illustrate the results seen to date and exemplify unique completion techniques that take advantage of fiber optic technology. Introduction Fiber optic sensors are widely used throughout many industries and are now becoming established as a way to gather data in the petroleum industry. Considered a superior alternative to conventional electronic sensors in hightemperature pplications (>150°C), fiber optic sensors also have other advantages over electronic sensors, including:Higher sensitivityElectrical passivityHigh temperature tolerance (>350°C)Intrinsic safetyWide band widthImmunity to electromagnetic interferenceSingle point and distributed sensing capabilityMultiplexing capabilitiesExtremely small size. Among many measurands that currently can be accomplished with fiber optic sensors downhole are temperature, vibration, pressure, acoustics, flow, strain, pH and chemical species. Principles of Fiber Optic Downhole Temperature Sensing Fiber optics operate downhole in the following manner. A laser light pulse is sent down a multi-mode fiber optic waveguide. As this pulse travels along the waveguide, specific, temperature-induced molecular vibrations cause a very weak reflected signal to travel back up the fiber to the source. This weak signal is filtered out and measured by the surface opto-electronics system. The surface system compares the launch time of the light pulse to the time taken for the reflected light to get back to the source. The time differential determines the point of the temperature measurement, as the speed of light in the fiber is constant and known.