Drill Floor Research Articles

The Evolution of the Land Drilling Rig

_ The earliest land rigs used materials like bamboo and iron and were powered by animals such as horses or oxen. These rigs used percussive drilling to create the bore, repeatedly raising and dropping heavy iron bits—effective but slow. By the time Edwin Drake was drilling the Titusville well in 1859, steam engines had been introduced to help power now metal pipe down into the Earth’s crust. By the 1950s, steam-powered rigs gave way to diesel engines. The 1960s would see the advent of self-elevating rigs—the transition from derricks to mast. During the 1970s, electrical power using on-site generators was introduced to drive systems on the rig, and the advent of new downhole tools would allow drillers to directionally drill while maintaining rotation. In the mid-1980s, the first steerable drilling system was introduced. Soon, the evolution would move from the drill floor and downhole into the doghouse (driller’s cabin). Gone were the mechanical hand brakes and foot pedal systems, replaced by touchscreens and joysticks. The land rig has come a long way. Hoisting capability and rig-up requirements were key drivers in the design of older units rather than an ability to store materials and move. Older rig-floor configurations were modified to accommodate pipe-handling equipment instead of designed to integrate pipe-handling equipment. These units were not driven by location sizes nor multiwell pad capabilities. Most of this would change with the coming of the new millennia, and by 2010, it would seem like new innovations would be integrated into land rig design every year—from larger variable skid systems allowing for pad and batch drilling to app-based automation driving efficiency and safety profile. Topdrives? Onshore? Most of what drove innovation in land rigs can be traced back to development in the offshore sector. Much of what would become standard technology on land had its roots offshore, starting with one of the most important technology transfers of the 1990s—topdrives.

Connected FPSOs Thrive on Automation

Modern life is connected. Our computers, phones, and watches are all tapped into personal insights, from a daily planner to keep track of meetings and appointments to a health monitor tracking everything from heart rate to blood oxygen level in real time. This connectivity has bled over into many different facets of our lives, including work. Business and industry maintain critical connections allowing for simplification of complex tasks and the monitoring of machines for safety and performance. As the oil field has become more connected, increasing opportunities for automation have been introduced into both new and existing oilfield technologies with aims to achieve new levels of productivity and safety. Whether it is a robotic arm on the drill floor of a rig bringing pipe from the stand to the well or autonomous robots being used for inspections and other operation observations in hard-to-reach or remote places, if the connectivity is there it opens the door to a vast, new toolkit for contractors and operators alike. In 2023, a group of contractors came together to help define the next steps in automation for floating production, storage, and offloading (FPSO) vessels. The FPSO Coalition—made up of SLB, Rockwell Automation, Sensia, and Cognite—is a collaboration designed to accelerate the evolution of FPSOs by developing and employing new digital capabilities aimed at improving the reliability, availability, safety, and efficiency of the assets, while lowering the carbon footprint of their offshore operations. FPSOs have been invaluable tools for offshore development around the world for decades. Some older hardware does not have the benefit of being wired for connection or pieces of equipment being Internet of Things (IoT)-ready. As much as the coalition looks to solutions to integrate into new facilities, it also explores the limitations and potential for bringing older yet still viable components into the digital age. Under the venture, SLB was tapped to bring advanced digital solutions, subsurface domain expertise, and complex integration and project management capabilities to scale up efficiencies and lower the carbon footprint of operations across every stage of the FPSO life cycle. Rockwell would provide expertise in control and safety systems for FPSOs, as well as extensive experience in power systems. “Keeping in mind that the typical operating life of an FPSO can be 20-25-30 years, a lot can change in terms of technology, process conditions, regulatory requirements, etc.,” said Greg Trostel, global industry development manager for floating production at Rockwell Automation. “But ultimately, the main goal of automation is to ensure the reliable and safe operation of the vessel—no loss of containment, no personnel at risk, no environmental incidents. “Ideally, automation systems can adapt and grow with the changing technology and changing requirements. We depend on the automation systems to keep all the individual process modules connected to, and operating in concert with, the main vessel systems,” he said. One of the first things tasked to the coalition was a contract awarded to SLB for a multipurpose dynamic simulation solution providing an immersive digital twin environment to dynamically simulate operational processes and their control and automation systems, train personnel, and strengthen safety elements at five newbuild FPSO units to be installed in Búzios Field in the Santos Basin for Petrobras.

Design of a Display Structure for an Anti-Collision System of Offshore Drilling Units Based on the Digital Twin Concept

The drill floor of an offshore drilling facility is equipped with a collision avoidance system to prevent collisions between moving equipment. In this paper, we present the visualization of the collision avoidance system using the digital twin concept. By classifying the core technologies of the digital twin, the elements necessary for the visualization of the collision avoidance system are derived, and the information for visualization is organized. We conduct 3D visualization of equipment and design IO devices necessary for the visualization. The movement of the floater is considered, and a database is built to efficiently search for the information required for the retrieval of stored 3D information. A collision detection situation is generated by operating the equipment using the input device required for simulation. Collision information is displayed as designed, and it is confirmed that the switching of the display between the present and past time is operating normally. The entire system functions normally as designed, including the input/output with other databases and equipment operation. Implementing a digital twin for an offshore platform is a time-consuming and costly process. It is expected that the improved anti-collision system can be expanded for the digital twin of an entire offshore platform.

Development of offshore drilling platform simulation for virtual onboard experience

As marine resources have been actively explored, a large number of offshore drilling platforms such as drillships and semi-submersible rigs have been built in many shipyards. The drilling system is the key feature that defines the characteristics of the platform. The operation of the drilling system is usually focused on the tubular handling, hoisting, and rotating systems which are directly handling drilling pipes and risers on the drill floor. Therefore, most of the training simulators have been developed only for controlling the drilling equipment. However, not only the drilling equipment handling on the drill floor, but also compensations systems such as heave compensation system and DPS (Dynamic Positioning System) to reduce the effect of the motion, ROV (Remotely Operated Vehicle) operation, well control including BOP (Blow-Out Preventer) should be integrated systematically because these systems on the offshore drilling platform are operated at the same time. Therefore, we propose the integrated offshore drilling platform simulation for virtual onboard experience which is composed of a virtual driller's cabin for handling drilling equipment, well control simulator to remove a kick, DPS simulator to control the motion of the platform, walk-through simulator to monitor the operation from the worker's viewpoint on the platform, and dynamic analyses of heave compensation system. All data such as the movement of the drilling equipment, platform position, driller's command, etc. are shared among systems in real-time. The proposed virtual offshore drilling platform can effectively show the various situations that occur during drilling operations.

Using Cameras To Understand What Is Happening While Drilling

Can a camera do a better job than humans at creating a minute-by-minute record of drilling activity? Or evaluate damaged drill bits better? Based on two papers at the SPE/IADC International Drilling Conference and Exhibition, the answer might soon be yes. Schlumberger researchers showed that video from a camera on the drill floor and on the drilling cuttings shaker kept an accurate record of what the rig was doing at the time, also known as the rig state (SPE 204086). A paper from The University of Texas-Austin (UT-Austin) showed a camera phone could create images for use in their bit-evaluation program to assess the damage and offer a reasonable explanation for what caused it (SPE 204124). A year ago Teradata announced its Bit-Box, which houses cameras and lights to create 3D bit images. It is now on the market; other companies are working on competing products. Cameras have gotten small and cheap at a time when innovations like self-driving cars have driven tech companies to speed development of computer-vision tools. Schlumberger’s goal is to convert video from rig cameras into a constant record of the rig state. It is being done with data gathered by sensors while drilling, or by people if the sensors stop working or generate bad data. The system leaves gaps when sensor issues are missed or workers are otherwise occupied, which is a maddening problem for those who need to know what is going on at any moment to interpret drilling data. “We need to understand what the rig was doing when we look at and try to solve problems” using digital analysis, said Crispin Chatar, a drilling subject matter expert for Schlumberger, who presented the paper at the virtual conference. The bit-evaluation program used phone camera images as a lower-cost substitute for 3D imaging, like the system sold by Teradata. Mobile phone images come with the risk of bad lighting and varying angles, which the authors said affected the analysis. But those devices are small, and there are plenty of backups available. “Everybody has a mobile phone at a rig site,” said Pradeep Ashok, a research scientist in the petroleum engineering department at UT-Austin. He believes cameras on mobile devices are the future because “if you could build something that requires no added equipment it will allow more rapid adoption.” Mobile phone owners also worry about breaking their phone. They may not be so concerned about rig equipment, which is a concern to those selling more-complex imaging devices. Both projects were early efforts to test what can be done with camera data, which is likely to expand over time. Schlumberger’s goal of tracking the rig state more reliably and cheaper than when using sensors may not be enough to convince users to change their ways at a time when sensors are proliferating to support more digitally controlled activities. The Schlumberger data were gathered at a test well for an automated rig.

Automated Mud Skid Holds Promise of Safety, Efficiency Improvements With Real-Time Fluid Monitoring

As industry buzzwords go, “automation” has spent its time in oilfield vernacular climbing the ranks of widely used terms. It now resides as one of the go-to designations for signs of advancement in any number of disciplines. Its use has been tied most frequently with drilling operations as contractors look to keep employees out of harm’s way via a robotic take-over of most motion-intensive jobs on the rig’s drill floor—basically anything that grips, clamps, or spins. More recently, the term has moved away from the drill floor and into other well construction operations allowing for things such as remote, real-time measurements without the need for boots on the ground. For areas like west Texas and the Permian Basin shales, having the option for remote readouts and a component of automation that can allow for corrective actions should the need arise can go a long way in terms of safety and efficiency gains as well as better manpower application. Unsurprisingly, the area has become a solid testing ground for new, expanding efforts in automation. With dreams of new drilling-fluid-monitoring automation, Eric van Oort, a professor at The University of Texas at Austin and former Shell research scientist, and select students came up with a new way to automatically measure mud parameters such as viscosity without the use of a traditional viscometer. “The fact that we still use manual measurements, some of them now 90 years old, is quite puzzling in this day and age,” van Oort said. “The Marsh funnel, for instance, was introduced in the 1930s, and other mud tests go back to the 1950s and 1960s. These API measurements have served us well, but the question is, can you do something more now with modern measurement techniques and sensors? So, I started working on new ways of measuring the viscosity and density, and then later fluid loss and even solids and salinity in muds. That proved to be all very successful and promising.” Construction of a mud skid to house the equipment and sensors needed to conduct these tests in real time was the next step in the evolution of van Oort’s concept. That initial skid was a cannibalized and reworked version of a unit that was employed on Shell’s Rig 1, which the supermajor built for its in-house rig-automation research based in Pennsylvania. This early mud skid, considered the prototype of van Oort’s design, was abandoned before it was properly tested. “We generated quite a bit of IP [intellectual property], my students and I at UT,” he said. “The Shell skid hadn’t seen a significant amount of service, and it had some nice components that we could reuse. We took that skid apart and reconfigured it and put it out in the field with Pioneer Natural Resources for a set of field trials in the Permian. Those went well.” The field trial results were shared in a paper presented at the 2019 Unconventional Resources Technology Conference (URTEC 2019-964). The paper concluded that the pipe viscometer employed by the skid allows for the characterization of additional rheology parameters, which cannot be obtained with Couette-type viscometers, such as the critical Reynolds number, characterizing the transition from laminar into turbulent flow, and the friction factor in the turbulent flow regime.

Development of a Framework for Anti-Collision System of Moving Drilling Machines on a Drill Floor

Development of a Framework for Anti-Collision System of Moving Drilling Machines on a Drill Floor

Technology of eliminating outburst by downward drilling in highground pressure and serious outburst area

The high-drainage roadway construction face of the working face is used to pre-drill the borehole under the tunneling face, and the problem of poor water return in the hole is solved by grouting the surrounding rock cracks in the deep and shallow holes of the drill floor. The “two plugs and one note” sealing method was adopted to ensure that the sealing holes were tight and airtight; the water pipes were blown all the way in the hole, and the single hole, grouping and timed water blowing work targets were realized, and the drilling effect of the downhole drilling was improved. A set of efficient and rapid down-drilling and hole-dissipation management mode has been formed, which has achieved the goal of high-efficiency outburst of coal seams and technical and economic integration in areas with high ground pressure and serious safety and economic benefits.

Dynamic Response of Drill Floor Considering Propagation of Blast Pressure Subsequent to Blowout

Explosions and fire have very critical safety hazard impacts on offshore oil and gas facilities since they are mostly located in remote areas and could induce serious environmental issues. Explosion risk assessment and structure blast analysis are essential for these production facilities, and research studies have been carried out. Explosion due to blowout during drilling operation is also a critical risk for drilling units, and this has not been researched much until the accident of the drilling unit in the Gulf of Mexico in 2010. This paper provides the risk and evaluation of explosion and structure under blast pressure during the drilling operation, whereas previous research studies have mainly been interested in process plants. This study suggests weight saving in drilling units through the consideration of the actual behavior of gas explosion. Weight saving is the priority of offshore unit design due to payload. This research also gives guidelines to select the material-grade-appropriate anti-explosion system through the comparison of several materials by design and result.

Dynamic Response of Drill Floor to Fire Subsequent to Blowout

Dynamic Response of Drill Floor to Fire Subsequent to Blowout

Modeling and analysis of flammable gas dispersion and deflagration from offshore platform blowout

Blowout is a catastrophic accident in offshore drilling operations, and it poses a serious threat to the operational safety of an offshore platform. This paper uses a computational fluid dynamics (CFD) model to simulate an offshore platform blowout accident and to assess its impact on the assets and personnel. It integrates the dispersion of flammable gas with the subsequent deflagration due to the accidental ignition. The dispersion behavior of blowout gas with wind is predicted and the hazardous area generated on an offshore platform is assessed. Also, the effect of well productivity on the blowout gas dispersion is examined. Subsequently, the deflagration scenario due to ignition of flammable gas is simulated to predict the deflagration loads including overpressure, high temperature and heat radiation. Eventually, the impact of blowout gas deflagration on offshore platform and personnel is assessed. The hazardous area generated by blowout gas dispersion is mainly distributed on the drill floor. The increase of well productivity can cause an increase of the hazardous area. The minimum radius to ensure the safety under deflagration overpressure is 30.63 m. The present work could help in conducting a prior risk assessment and tomake an emergency response plan.

Pneumoproteins in Offshore Drill Floor Workers.

The aim was to assess pneumoproteins and a certain biomarker of systemic inflammation in drill floor workers exposed to airborne contaminants generated during drilling offshore, taking into consideration serum biomarkers of smoking, such as nicotine (S-Nico) and cotinine. Blood samples of club cell protein 16 (CC-16), surfactant protein D (SP-D) and C-reactive protein (CRP) were collected before and after a 14-day work period from 65 drill floor workers and 65 referents. Air samples of oil mist, drilling mud components and elemental carbon were collected in person. The drill floor workers were exposed to a median air concentration of 0.18 mg/m3 of oil mist and 0.14 mg/m3 of airborne mud particles. There were no differences in the concentrations of CC-16 and SP-D across the 14-day work period and no difference between drill floor workers and referents at baseline after adjusting for differences in sampling time and smoking. CRP decreased across the work period. There was a strong association between the CC-16 concentrations and the time of sampling. Current smokers with S-Nico > detection limit (DL) had a statistically significantly lower CC-16 concentration, while smokers with S-Nico < DL had CC-16 concentrations similar to that of the non-smokers. Fourteen days of work offshore had no effect on serum pneumoprotein and CRP concentrations. However, the time of blood sampling was observed to have a strong effect on the measured concentrations of CC-16. The effect of current smoking on the CC-16 concentrations appears to be dependent on the S-Nico concentrations.

Pulmonary function and high-resolution computed tomography examinations among offshore drill floor workers

PurposeThe aim of this study was to assess short-term changes in pulmonary function in drill floor workers currently exposed to airborne contaminants generated as a result of drilling offshore. We also aimed to study the prevalence of pulmonary fibrosis using high-resolution computed tomography (HRCT) scans of another group of previously exposed drill floor workers.MethodsPulmonary function was measured before and after a 14-day work period in a follow-up study of 65 drill floor workers and 65 referents. Additionally, 57 other drill floor workers exposed to drilling fluids during the 1980s were examined with HRCT of the lungs in a cross-sectional study.ResultsThe drill floor workers had a statistically significant decline in forced expiratory volume in 1 s (FEV1) across the 14-day work period after adjustment for diurnal variations in pulmonary function (mean 90 mL, range 30–140 mL), while the small decline among the referents (mean 20 mL, range − 30 to 70 mL) was not of statistical significance. Larger declines in FEV1 among drill workers were associated with the fewer number of days of active drilling. There were no signs of pulmonary fibrosis related to oil mist exposure among the other previously exposed drill floor workers.ConclusionAfter 14 days offshore, a statistically significant decline in FEV1 was observed in the drill floor workers, which may not be related to oil mist exposure. No pulmonary fibrosis related to oil mist exposure was observed.

Improvement of Wired Drill Pipe Data Quality via Data Validation and Reconciliation

Wired drill pipe (WDP) technology is one of the most promising data acquisition technologies in today’s oil and gas industry. For the first time it allows sensors to be positioned along the drill string which enables collecting and transmitting valuable data not only from the bottom hole assembly (BHA), but also along the entire length of the wellbore to the drill floor. The technology has received industry acceptance as a viable alternative to the typical logging while drilling (LWD) method. Recently more and more WDP applications can be found in the challenging drilling environments around the world, leading to many innovations to the industry. Nevertheless most of the data acquired from WDP can be noisy and in some circumstances of very poor quality. Diverse factors contribute to the poor data quality. Most common sources include mis-calibrated sensors, sensor drifting, errors during data transmission, or some abnormal conditions in the well, etc. The challenge of improving the data quality has attracted more and more focus from many researchers during the past decade.

Load Torque Estimation Method to Design Electric Drivetrains for Offshore Pipe Handling Equipment

One of the main design objectives for electric drivetrains operating in offshore drilling equipment is to keep them as small, yet as effective, as possible, to minimize space they occupy on drill floor and maximize their performance. However, practical experience shows that typically choices made by design engineers are too conservative due to the lack of enough data characterizing load conditions. This results in too costly and too heavy selected components. Therefore, in the current paper we present a method to estimate required full-scale motor torque using a scaled down experimental setup and its computational model. A gripper arm of an offshore vertical pipe handling machine is selected as a case study for which the practical significance of the current work is demonstrated. The presented method has a potential to aid design of electrically actuated offshore drilling equipment and help design engineers choose correctly dimensioned drivetrain components.

Advanced Analysis Identifies Greater Efficiency for Testing BOPs in Deep Water

Summary Pressure testing blowout preventers (BOPs) with synthetic-based mud (SBM) requires lengthy testing times resulting from pressure/volume/temperature (PVT) influences associated with SBM. PVT influences are especially pronounced indeep water and high-pressure test environments. A project was initiated in an effort to better understand the mechanics that transpired during BOP testing. The primary objective was to demonstrate that the pressure decline was quantified by the fluid-PVT behavior, mechanical influences and thermodynamics of pressurization, and subsequent cool down. The secondary objective was to demonstrate that the pressure decline resulting froma leak could be reliably and efficiently detected with high-resolution pressure data. It was theorized that the gradual decay of pressure during the shut-in phase was a result of the heat added to the system during pressurization. To pursue this investigation, real-time PVT data were gathered at the cementing-unit (CU)suction and discharge while testing the BOP. In addition, pressure/temperature(P/T) gauges were placed in the drillstring—one at the drill floor, one at the midpoint between the drill floor and the BOP, and one above the BOP stack. The gauges confirmed significant heat up as the system was pressured up for each test. The pressure decreased as the system cooled back toward the ambient temperature. Modeling techniques were developed to understand the system response. This paper presents salient aspects of data acquisition, data interpretation, and modeling techniques. Results demonstrate the potential to significantly impact the industry, with respect to safety, time, and costs for BOP testing.

Development of an Ultraharsh- Environment Jackup Drilling Rig

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 92760, "Development of the Ultimate Ultra Harsh Environment Jack-up Drilling Rigs," by Frederik Smidth, SPE, and Per Wullf, M ærsk Contractors, prepared for the 2005 SPE/IADC Drilling Conference, Amsterdam, 23-25 February. Drilling with jackups in harsh environments has moved into deeper water during the last 10 years. Before, 300 ft was the maximum operating water depth, but now operations are possible in water depths as great as 500 ft. Several new features are available on harsh-environment jackups that increase drilling efficiency by as much as 25%. The full-length paper describes the process of creating the next-generation deepwater jackup drilling rig and operational experience with the Mærsk I-Class rigs. Design Phase Mærsk Contractors operate several ultra-harsh-environment rigs in the North Sea. On the basis of experience with these rigs, functional requirements were developed for the next generation of ultraharsh-environment jackup rigs. The main focus was to improve the safety level on board and provide more value for money to the clients. A large number of North Sea operators were consulted to obtain their view of the ideal rig of the future. More than 650 suggestions were received from the rig crews in the existing fleet, more than 450 of which were incorporated in the final design. A 1:1 mockup of the drill floor with simulated work situations was used to gather input about drill-floor layout. Use of the rigs in subsea and production mode also was considered. The MSC-CJ70 was chosen as the basic design. This included an XY cantilever system that provides opportunities to increase efficiency and introduce improvements on the drill floor.

Evaluating the motions of a semi-submersible platform with respect to human response

The motions of a semi-submersible drilling platform have been evaluated so as to predict the effects on the comfort and activities of the crew. The horizontal motions at the drill floor exceeded the ‘average threshold of perception’ defined in International Standard 6897 (ISO 6897, 1984) by more than a factor of two; they were about half of the limit for the worst 10 min in five years for ‘fixed offshore structures where work of a somewhat critical nature is carried out’. Other standards predict that the vertical motion would cause vomiting due to motion sickness in less than 5% of unadapted adults within the first 8h of exposure. The calculated probability of ‘motion-induced interruptions’ (loss-of-balance events) caused by deck motion was negligible. Notwithstanding the above conclusions, it is considered that current standards are insufficient to predict the effects of the motions of ships and floating platforms on the activities of the crew.

Pipe-Racking Systems: Are They Cost Efficient?

Summary The development of pipe-racking equipment on offshore rigs is reviewed. A method is developed to evaluate the economic return on investment. Using an available industry-computer program, a typical well profile is selected and a sample analysis is conducted to illustrate the process. For most large offshore drilling operations, payback may be expected in about a year. Introduction It is generally accepted that the first floating vessel completely dedicated to offshore drilling in areas not accessible to bottom-supported rigs was the drillship CUSS-1 owned by a consortium of Continental Oil Co., Union Oil of California, Shell Oil Co., and Superior Oil Co.1 In 1956, this rig was equipped with the first practical mechanized pipe-handling system. Since then the mobile rig fleet reached nearly 1,000 vessels and more than 100 racking systems have been built and installed. The industry learned that racking systems were usually good to have, but were expensive to acquire and to own. They were bought for a variety of reasons, all of which were claimed to be economic. Yet today there are virtually no performance data and no known analyses that can tell owners whether their decisions were good or if future investment should be made in this type of equipment. This paper suggests a method of analysis that permits the evaluator to use his own experience of operational cost and performance factors. An existing computer program, designed to evaluate well drilling costs, illustrates the method, and a sample analysis is carried out. Although the model example shows a very attractive investment payback of about 1 year, the figures are much less important than the methodology and the experience-based costs that the reader will use in his own analysis. All cost and performance factors are arguable. The purpose of this paper is to expose the relevant factors and let the reader judge how significant they are to his own situation. It is helpful to look first at the history of racking systems, their development and performance, their usage in today's rig fleet, the variety of available racking machines, and some considerations in their selection. Historical Perspective In 1956, CUSS-1 was equipped with the first practical mechanized handling system, which was a horizontal lay-down system, handling stands in racks on the aft pipe deck. A mechanized pipe ramp transported the stand to well center, where it was picked up by the elevators. Meanwhile, parallel development had resulted in a vertical system that would handle stands within the derrick in a more traditional manner. A working prototype was installed on Humble Oil Rig No. 30 in the late 1940's and successfully drilled more than 75,000 ft.2 Nearly 20 years passed before any type of fully mechanized system allowing handsoff tripping was commercially worthwhile. During this time, the only type of tripping assists were various designs of rig-floor manipulator arms used primarily for pushing and guiding heavy pipes around the drill floor. The evolution of mechanized pipe racking began in earnest in 1968 when The Offshore Co. installed a vertical pipe-racking system on one of its turret-moored Discoverer drillships.3 The basic motivation was to eliminate the difficulty of manual pipe handling caused by vessel motion. The success of this equipment led to many other drillships being fitted with similar machinery, including several horizontal systems similar to the CUSS-1. In 1973, the Norwegian rig Smedvig West Venture became the first semisubmersible to be outfitted with a fully mechanized racking system.4 However, in this case, the rationale for installation differed from that of drillships. For this heavy semisubmersible built for drilling in the Norwegian North Sea, equipment was justified on the basis of offsetting the effects of high winds and cold temperature, not vessel motion. This too was successful and was followed by a number of North Sea class rigs being similarly outfitted. It was not until 1980 that different designs of vertical rackers offered alternatives in vendors and operation. This was prompted by a third factor: national regulations, primarily Norwegian. These regulations stipulated that rigs working in their jurisdictional waters would be equipped with a fully mechanized pipe-racking system, power slips, and mechanized means for making, breaking, and spinning tool joint connections for reasons of personnel safety. The various arrangements of systems also produced a fourth tangible benefit, trip-time savings.

Evaluation of an occupational injury intervention in the petroleum drilling industry

Installation of power makeup equipment (PME) on 13 of 30 mobile offshore drilling units (MODUs) under study in the Gulf of Mexico provided an opportunity to evaluate the effectiveness of this device in reducing drill floor injuries. Two groups of injuries were defined on the basis of worker activity at the time of injury and the vehicle of mechanical energy; one group, “related” injuries, were preventable by the PME; the other group, “unrelated” injuries, should not have been affected by the PME. Two quasiexperimental evaluation designs were employed. The first, a multiple time series comparison of MODUs equipped and not equipped with PME, yielded a quantitative estimate of injuries averted. The second, a pretest-posttest design, compared related and unrelated injuries before and after PME installation. Because this method was subject to bias if different trends were present for related and unrelated injuries, only qualitative results could be obtained. Both methods indicated a significant reduction in related injuries attributable to the PME. A cost-savings analysis indicated savings that could conservatively pay for the equipment within six years time.