Rotary steerable drilling systems are highly automated with inclination and azimuthal hold modes. These systems require only sparse communication downlinks to hold to a well plan or to compensate for geological "drift". Mud pulse transmission is one of the most complex communications technologies in any industry, yet measurement-while-drilling (MWD) companies have developed reliable bi-directional telemetry systems. The focus here has been on pulse generation and sophisticated decoding systems, able to detect signals, automatically, at a very low signal-to-noise ratio. Combining downhole automation and automatic mud pulse decoding with remote operations technologies delivers the technical-basis for unmanned MWD and directional drilling (DD) services. The infrastructure for unmanned services is a reliable surface communications network that connects the rig site with the remote operations center, and the realization that unmanned operations needs a new organizational structure for subject matter experts (SME's), in this case the MWD and DD engineers. This paper describes the now mature unmanned MWD and DD services (remote operations) in the US Land arena. These unconventional wells can reach in excess of a mile a day (so-called, MAD wells) with record footage in excess of 9,000 feet in a single 24-hour period. It will also describe the SME structure to deliver remote operations, and the key-role SMEs play in realizing unmanned operations. For example, moving directional drillers from the wellsite and into operator offices greatly improves decision-making. The paper will also examine the role of automation and digital technologies within this construct, especially how they will allow the unmanned model to migrate towards complex wells. Automated trajectory drilling systems, in which the rotary steerables can automatically correct for geologic drift, is the next step in downhole automation, soon to be followed by automated geosteering. Unmanned remote operations have only been around for a couple of years, but already operators are realizing efficiency and performance as they take advantage of a real-time digital infrastructure.

For decades, upstream personnel have struggled to efficiently gather offshore data and effectively analyze it to make better business decisions. One internal audit conducted by an oil and gas company found its upstream employees spent up to 80 percent of their time just looking for, then converting the data because the data historically has not been housed in one place within one platform. Traditionally, employees must collect large volumes of information from multiple data sources, including spreadsheets, data streams or tacit knowledge. Alone, the Internet of Things (IoT) sensors connected to equipment in the field can send 1,000 readings a minute to engineers, resulting in an insurmountable data for engineers to assess critically. All of this effort results in underutilized time and loss of money. The paper's topic addresses the digital twin technology solution which solves energy company's Big Data problems and recoups the wasted time and associated costs of field workers looking for data. Specifically, FutureOn's FieldTwin technology offers a cloud-based, comprehensive and secure platform with the ability to break up the barriers of the data silos built by legacy systems, creating accessible data across the company. Employees spend less time searching for data, and more time identifying trends and innovative ways to exploit the data, i.e., smarter drilling, greater field automation or improved safety. FieldTwin technology also provides a real-time, data-driven visual representation of the field that creates actionable data, whether it is an operator using the visualization of its subsea assets for field expansions or a renewable company utilizing the digitalization of its offshore wind projects for more effective planning. Studies show humans respond to and process visual data better than any other type of data. The human brain processing images 60,000 times faster than text, and 90 percent of information transmitted to the brain is visual. FieldTwin exploits this reality to enhance data processing and organizational effectiveness spanning project management to risk management in the field.

The objective of the paper is to show how dynamic machine learning modeling can help drillers and operators validate signals from their sensors. Data and signal quality are a big problem in the industry when it comes to digitization. The method will show the importance of having a validation pipeline, and how it can help other algorithms make better decisions. Our approach uses statistical principles, machine learning and advanced analytics. The method is ISO 8000 compliant and can provide a framework in data management and data quality for companies to use. Depending on the application the accuracy of our method will vary. Results are anywhere in the 88% - 99% range of accuracy. The process has been validated by a major drilling contractor in signals ranging from blow out prevention, dynamic positioning systems, and tripping. The process can save upwards of 50% of time spent cleaning, mapping, and validating sensor signals. The end product allows the user to understand problems in the data collection system from the sensor all the way to the enterprise historian. It will also reduce false positives and false negative that are present in maintenance, optimization, and automation.

This paper is based on an ongoing multi-participant study which focuses on the development of concepts for unmanned or "Normally Unattended Installations" (NUIs) that can be used for the economic recovery of stranded oil and gas reserves considered too small for traditional floating production storage and offloading (FPSO) vessels, and too far away from existing facilities for tie-backs. The primary objective of the study is to apply existing technologies in novel ways and to utilize recent advances in digitalization to develop low manning concepts by facilitating remote control, remote monitoring, and reducing maintenance requirements. The study engaged key technology vendors and operators, who provided operational expertise and defined future operation philosophies. Concepts are being validated by classification societies, yards and installation contractors. The specific NUI concept explored in this paper is an unmanned production buoy that proved to be technically and economically feasible for the recovery of small hydrocarbon pools in deeper water. The case study is a realistic approximation of a small deepwater offshore development in the North Sea, however, it is not based on any specific prospect. The case study Basis of Design (BoD) has been defined to cover a range of API gravities, ensuring that the resultant topsides design concept is robust and applicable to a range of real field developments in the future without significant re-configuration. The study into the technical and economic feasibility of the unmanned production buoy considered alternatives for gas compression, treatment, separation; heating and cooling, power generation, automation systems, and digitalization. This paper presents the outcomes with respect to production buoy design, operating philosophy, automation and digitalization.

Augmented Intelligence (AI 2 ) involves fusing Analyst Intuition with Artificial Intelligence to deliver an optimised combination of human-machine decision support. AI 2 is being incorporated by i-Tech Services / Leidos into the physical inspection of offshore Oil, Gas, and Renewables assets, delivering valuable data driven insights that contribute to greater efficiency, enhanced condition monitoring, improved asset integrity and asset life extension. The deployment of vehicular and diver assets to obtain such inspection data, with associated support vessels, remains a major cost challenge for Operators. We believe the industry needs to approach this challenge from two key directions. Firstly, through the application of autonomous systems for data acquisition and delivery, reducing vessel reliance, and secondly through automating the acquisition and processing of data and maximising the insight provided by the data. This paper will examine the use of Augmented Intelligence to optimise the Subsea Inspection data workflow as a key use case, to demonstrate the principles. The historic paradigm consists of a fragmented evolving approach, with insufficient consideration and design across all the sensors, processing analytical engines and data visualisation. The approach being adopted is to closely link all aspects of the data workflow, within the context of delivering the data and beyond in terms of harvesting additional insight and value. To achieve the optimum workflow a number of developmental initiatives are being knitted into a modular platform, each element providing standalone value but the sum of the parts generates the most significant value and cost reduction. The elements being combined are automatic data quality control at acquisition source and through the full workflow, automated processing, machine vision for object recognition and reporting and machine learning to optimise the system intelligence. All of these are designed to augment the expertise of the analyst / user, detecting change to learnt parameters, by using real time data and critically by referencing large historical data sets and as-built data. The outputs from a system holistic approach will be improved data acquisition with more efficient high quality right first time data reporting. In addition layers of analytics, with smart, intuitive data access and retrieval will optimise delivery of key information within large data sets, together with maximising value and insight.

The wide-scale deployment of analytics to support the well construction processes based on rig data has opened a host of opportunities to improve performance, quality, and safety at all levels in the offshore drilling industry. As automation and high-stakes decision making starts to rely more on these types of classifiers, a topic of consideration is the validation methods employed during their development to ensure accuracy and precision, requiring the best available methods to help data scientists evaluate their soundness, features and limitations, and explain to key stakeholders who may not be familiar with such techniques. In the particular case of drilling states determination from signal data, there may be cases where the ground truth records are either at lower resolution than desired, or where some degree of uncertainty on the labeling exist, techniques such as inter-rater reliability (IRR) or inter-rater agreement (IRA) can help to demonstrate consistency among observational decision provided by multiple sources and be used as a way to show the level of agreement between, for example, a proposed drilling state generator classifier using drillfloor data and existing IADC codes from available logs at the same time. This approach can be used to help decisions on further development of the particular classifier before committing to stricter model validation. This paper will show examples of these techniques applied to automatic generation of certain IADC codes using signal data vs log records, and how IRR/IRA can help inform the quality of the results.

Automation provides many new and improved abilities for ships and offshore assets. Automation is more than the mere replacement of the functions of older (less optimal) systems; it requires system interoperability and integration. Interconnectivity of multiple systems adds new risk factors to the system as a whole. Two key risk factors are cyber security and system complexity. At a high-level, cybersecurity means understanding your systems and processes, your personnel's capabilities and limitations, as well as thoroughly evaluating your threat landscape. In other words, system owners must have a keen understanding that there will always be new threats to counter, and new technologies to harness. With improvements in cyber security systems, employees are now the preeminent target, thus making them a substantial vulnerability. Through negligence (human error) and malicious acts — including being the victim of phishing/whaling attacks, lost laptops, accidental disclosure of information, and actions of rogue employees account for up to two-thirds of all cyber-related breaches. Industry must be cognizant that added complexity (e.g., system design/arrangement, rules, policies, procedures, etc.,) can decrease an individual's situational awareness and increase the likelihood of human error. A key to effective systems-risk assessment and complexity management lay in understanding cyber safety system designs, and how people interact with those systems. This paper will discuss methods to engineer systems, control system complexity, and how to help mitigate human error, with the goal of creating an efficient and effective cyber security environment.

Oil and gas producers are challenged with addressing long-term business needs such as: improving health, safety, and environment; extending life of production equipment; increasing reliability to reduce maintenance cost; reducing losses; improving operability to reduce personnel cost; improving productivity; increasing production; and improving governance and regulatory compliance. To meet these business needs, operating companies are once again investing, now in digital transformation of how their sites are run and maintained. Personnel are digitally enabled. For safety this includes digital distress calls, digital safety checks for situational awareness, digital mustering and geolocating. For reliability, new ways of working include digital inspection and predictive maintenance of more of the equipment, digital collaboration with experts, digital documents on-the-go, and digital integrity management. For operations, new best practices include digital operator rounds including on EOR injection wells and digital logbooks. Also, instead of having people at site; some personnel instead work from a city office or equipment monitoring is outsourced to a service provider as Industrial Internet of Things (IIoT) -based connected services. This digital transformation is made possible with new technologies such as wireless sensor networks, analytics software, and cloud computing making condition monitoring for a broader scope of process equipment practical, and enable new business models without capital outlay. Wireless, non-intrusive sensors along with readymade software apps enable easy and rapid deployment of these solutions at low cost. Digital transformation with IIoT and advanced software does not require costly and time-consuming custom programming, but can be accomplished through purpose-built, readymade apps with embedded subject matter expert knowledge. Using platform-agnostic apps, operating companies can use their existing middleware instead of replacing it, and without adding another expensive platform layer, thus protecting existing investment. Results from digital transformation include: extended life of production equipment to ensure continued service of facilities and operations, maintenance cost reduction, operations cost reduction, improved productivity, and increased production. Further, all departments benefit from the same digital infrastructure, which also enhances integration across disciplines.

Given the recent fluctuation in oil prices, companies are presented with a dichotomy—while they've cut 2015 capital expenditures (CAPEX) by 25-40%, production levels for existing operations are likely to remain at 2014 levels, or higher. The challenge now lies in improving operational efficiency and productivity, reducing costs, and mitigating risk to remain profitable in this tough oil market. It's a delicate balance of return on invested capital with operations excellence. This paper will present the value a single solution for simulating, operating, and optimizing operations offers the upstream oil and gas business. The outlined real-time performance-based solution for complete performance modeling provides operators a single continuous view of their assets, thus empowering them to plan, manage, and optimize current and future oil and gas production.

Objectives/Scope Human error and human factors are contributing causes in over 50 percent of well control incidents, according to SINTEF data. While straight-forward cognitive errors and wrong actions contribute to 15 percent of incidents, the larger span of human factors includes communication failures, workload, management practices, and information availability and presentation problems that lead to mistakes, such as imperfect kick detection or underbalanced wells. Yet human factors is often treated as an issue of human reliability estimates and the need to define better procedures that design human error out of the system. There are, however, many shortcomings to the focus on procedures and human reliability estimates, for example, variations among installations, situations that lie outside existing procedures and estimates, and analyses of rote procedure-following that exclude situation variability and expert problem solving. What is needed is a deeper, human factors-centric, approach that looks beneath the procedures for underlying systemic causes: operator situation awareness and decision making, team common ground and collaboration, and resilient socio-technical organizational processes. Our project is taking this human factors approach with a comprehensive analysis of well control during deepwater drilling. Methods, Procedures, Process Our novel approach is to marry the risk management framework of threats and barriers with the human factors concept of the decision cycle. The decision cycle concept outlines the cognitive steps involved in decision making from detection, to interpretation, deciding, and acting. Our innovation is that these concepts can be brought together to identify a set of 117 "human factors barriers" for effective detection of an influx. These human factors barriers support team situation awareness, communication, and decision making. These barriers include the availability and representation of data, user vigilance, support for critical thinking, crew resource management, shift change hand-off processes, system status availability, and change management processes. These human factors barriers can be applied readily to other decisions within well control. Results, Observations, and Conclusions We have created a database of BSEE/BOEM incident reports and reviewed these incidents against the human factors barriers. We have identified a number of "hot spots" or trends where specific human factors barriers were frequently compromised. These trends include sensor placement for situation awareness, shift hand-off processes and team communication, and decision support for critical thinking and diagnosis of uncertain situations. Novel/Additive Information These human factors barriers and the identified trends can be used a) pre-incident to review and audit drilling rigs and well plans to identify and then avoid potential problems, b) post-incident to investigate and report on incidents from a human factors perspective and thereby better inform the industry concerning these topics, and c) to identify key topics for further research and development of improved systems and processes.

The key to unlocking innovation in the Upstream is standards. WHAT!? Does this sound backwards and non-intuitive? Don't we usually associate innovation with free-wheeling, no-boundaries kinds of approaches? How can people feel free to innovate if you tell them to "do it this way"? Well, it all depends on where you think the value comes from. Technical computing in the Upstream oil and gas industry has evolved into extremely powerful, yet extremely complex systems. Varied and coagulated connectivity networks underlie a myriad of platforms, from UNIX to PC to mainframes to supercomputers...to server farms, to thin clients and Blackberries, etc. At the other end of these systems, a multitude of user interfaces become the most visible aspect of these complexities to the user community. At the center of such complex technical computing system are the varieties of software applications: geoscience, engineering, operations, business, personal productivity, and IT, etc...usually supplemented out of necessity by a veritable foundry of line-coded "tools", "agents", or "macros". This software or line code is written by one of, or all of, several million developers, sometimes including end users themselves, in many different "languages". The fuel and lifeblood for this technical computing system is data. This data comes in a million different formats, sizes, and shapes. It comes in logarithmically increasing volumes...in numbers making "a million" seem like a quaint and archaic term. With the complications of these various elements and their inter-relationships in the systems, complexity has become the enemy of innovation. Too many engineers, geoscientists, field operators, accountants, and managers (not to mention IT specialists, and others) spend too much time dealing with the complexity and moving parts of the "system"...and so far too little time evaluating, analyzing, sciencing (is that a word?) and innovating in the environment. While there are many targets for simplification in these technical computing systems, DATA rises to the top of the list as the most critical element. In this upstream environment, data is at the core of the systems - resting upon the networked infrastructure, and feeding the applications and user interfaces. Data is what the systems were built for and around. After all, scientific software applications without data are, in essence, just theory. And, I don't need computer infrastructure if I don't have any data or even software without data. Data is king. Yet data is probably in the worst shape of all the elements of the system in terms of its wild, complex nature. Historically, geoscience based UNIX systems have involved large data file sizes (think seismic). Engineering and business productivity systems have grown from environments with relatively small data file size, but with numerically many more files. While the systems continue to evolve and converge, the Upstream industry is faced with a tidal wave of information; 2-D becomes 3-D, now 4-D seismic. Real-time data capture systems and others have led to an explosive exponential growth in data volumes and storage requirements. This reality has placed the technical user in the proverbial needle in the haystack situation. Another reality of this information overload environment is that all data is not created equal. Some data have greater importance than others. Imagine looking for that needle in not just one haystack, but a field of haystacks. Maintaining data quality will require progressively better automation as data has entropy, always seeking a lower state.

Abstract The economics of offshore and deep water production has been steadily improving through the continual introduction of improved technology. Up to now, a majority of such improvements have been derived from the implementation of mechanical systems both above the surface and subsea. Today, with the high reliance on sophisticated systems, telecommunications is becoming a critical factor to efficient offshore productivity. PETROBRAS has recognized this importance and has embarked on the Digitization Project for the Campos Basin. This project will result in a high capacity, highly reliable offshore, undersea fiber optic network utilizing SDH transmission equipment at the terminal points. The network, the first of its kind in the world, is achieved by interconnecting its offshore oil rigs with its Macae operations center, using undersea fiber optic cables as its backbone. This paper provides a review of the technical alternatives and economic factors that were considered in developing the solution; a summary of the resulting undersea network; and a summary of the benefits that will be realized with the fully operational network. PETROBRAS Campos Basin PETROBRAS is one of the world's leading companies in offshore petroleum production, with a history of successive records in the Campos Basin fields 1 . The Campos Basin lies on the Brazilian continental shelf north of Rio de Janeiro state. Its area covers approximately 100,000 sq. km and has a maximum depth of 3,500 meters. With the mixture of 13 fixed and 16 semi-submersible platforms, Campos production accounts for 70% of the energy needs of Brazil. PETROBRAS has adopted the following goals in order to achieve the higher production rate and cost reduction needs 2 : Improving marine surveys with the objective of increasing success rate of exploration Minimizing elapse time between discovery and Production Increasing oil fields recover rates Lowering operational costs and investment costs Incorporating automatic processing in risk scenarios. In many ways, these goals will be achieved by the deployment of a high quality, highly reliable telecommunication network. Telecommunications throughout the company must be at comparable levels to ensure adequate access to data and applications. Today, the terrestrial links are adequate however, the offshore links are in need of upgrade. Enhanced Offshore Telecommunications The present telecommunications system in the Campos Basin was developed in the early 80's to meet voice transfer demands. This system employs low speed analog data transmission with rates only up to 9,600 bps. This capacity had been adequate to meet the first generation offshore operational telecommunication needs but presently falls short of meeting the quality and reliability demands necessary for today's systems. Since PETROBRAS is a vertically integrated company, a sound telecommunications infrastructure is therefore critical. In total, the functions it integrates include operating, exploration, production, refining, transportation, marketing, and import/export of oil and oil by-products. For a majority of the land base operations, telecommunications has been steadily improved with the various upgrades in the system provided by Embratel. For the offshore situation, this network is entirely a PETROBRAS operation. Therefore for the onshore and offshore operations to be fully compatible, comparable high quality offshore telecommunications must exist.

Abstract Automation of offshore platforms and other offshore facilities have always presented unique challenges. Traditionally only the largest platforms could accommodate a DCS but the continuing evolution of Open Control Systems (OCS's) has opened the door for modem automation on nearly all offshore facilities. This paper is based upon several offshore automation projects which demonstrate the unique and valuable benefits of OCS's applied offshore. Actual project details will be presented in as much detail as permitted by the end users. Offshore automation options will be summarized along with the features and benefits of various options. The use of conventional analog controls, PLC's, DCS's, and OCS's will be considered. Design guidelines for automation of new offshore facilities as well as retrofits of existing facilities will be included. The material to be presented is highly significant in that it covers the application of leading edge automation technologies for economic benefit in offshore applications. Introduction Prior to the introduction of microprocessor based control systems, plant automation was, for the most part, limited to Single Input - Single Output (SISO) continuous control and electromechanical relay based discrete control. Operators worked with such control systems at a panel board filled with dials, gages, strip charts, lights, and switches. Using such systems, the operators job was to keep the plant operating safely. The introduction, in the late 1970's, of microprocessor based, or "Distributed Control Systems (DCS)," opened the door for the operator to not only focus on safe operation but, really for the first time, to also accept some additional responsibility for the profitability of the process. The first DCS's emulated their panelboard predecessors in look and feel but did so utilizing CRT displays. These early systems were limited to continuous control functions. They did significantly enhance the practical ability to implement more sophisticated control strategies whose purpose was to improve the process economically. Other features of early DCS's which were of benefit included their ability to interface with a supervisory computer and to automatically produce reports. The application of early DCS's was essentially limited to large, continuous processes such as those found in the petroleum refining industry. With these early systems, it was rarely economically feasible to implement DCS control on any process, including offshore facilities, where continuous I10 quantities were less than approximately 300 inputs and 100 outputs. Offshore facilities presented additional beamers to DCS control due to the often harsh environments and impracticality of "computer rooms" offshore. During the 1 980's' numerous microprocessor based systems came onto the market; each one an attempt to overcome one or more of the limitations presented by other systems. Programmable Logic Controllers (PLC's) came into common use in discrete control applications. Relative to electromechanical relays, PLC's had many advantages in terms of lower engineering and maintenance costs. Personal Computer (PC) based systems were introduced to address the smaller 110 count market. PC reliability was significantly less than that of DCS's which was a significant problem in many applications. Hybrid systems which combined DCS's, PLC's, and I or PC's were also offered in an attempt to offer the advantages of each type of these control systems.

ABSTRACT This paper is a follow up to the OTC 91 paper. The on going joint industry project to build and test a Proof-of-Concept Automated Drilling Rig is progressing well on its land-based test site at Aberdeen, Scotland. This 1,000,0001b hook load, all hydraulically powered, computer controlled rig has been installed onshore and is already producing initial trial results that confirm the benefits of mechanisation and automation. These are improved safety, reduced manning, low weight and consistent operational performance. The project has pushed through commercial and technical difficulties as well as barriers of tradition, to show that technology, well proven in other industries is suitable and relevant to the drilling operation for oil and gas. The RA-D concepts in whole or part are applicable to all drilling scenarios - platforms, jack-ups, semTs, land and modular packages. The paper will discuss some of these applications and will show the benefits to Operators and Drilling Contractors. The project is showing that the application of the RA-D concept yields significant cost reductions in the drilling operation and from a combination of field results and engineering studies, these can be demonstrated against specific cases. The most significant aspect of this project is the benefit of collaboration between Operators, Drilling Contractors and Equipment Suppliers to develop and demonstrate new technology to the industry at large. The demonstration that this technology will meet the increasing needs for maximum safety and minimum cost operations is of paramount importance. INTRODUCTION Major advances are being made in the reduction of overall platform weight and, hence, overall cost. A principle aim of the project has been the reduction of the number of men from this potentially dangerous work area. Strachan & Henshaw Ltd (S&H) in collaboration with four oil companies - three British and one Norwegian with support from the UK Government and European Community - look at reducing considerably the cost of development drilling. The RA-D project which started 5\ years ago is nearing its commissioning trials prior to drilling at the International Downhole Drilling Technology Centre in Aberdeen, Scotland. The Drilling proving tests of the powerful but compact light-weight offshore derrick and pipe handling system are due in the Summer. Based on fast handling of single tubulars from 3" to 20" diameter and rated to 20,000' depths with a 1,000,0001b hook load the system is aimed at meeting the requirements of the North Sea and worldwide locations offshore and on land. An analysis of the market showed that rig design techniques have changed little over many years. This convinced the Company that there was a potential for a rig to be designed without preconceived ideas and which can comprise sensible applications of modern proven technology. RA-D has been created from the technology transfer of several industries and represents a significant change in the way drilling facilities and operations can be planned and managed in the future. The project has crossed many boundaries and overcome technical and commercial difficulties to produce marketable technology.

1. ABSTRACT Major advances are being made in the reduction of overal1 platform weight and, hence, overall cost. A principle aim of the project has been the reduction of the number of men from this potentially dangerous work area. One result from the '86' price drop was the coming together of Strachan & Henshaw Ltd. (S&H) in collaboration with four oil companies, three British and one Norwegian with support from the UK Government and European Community to look at reducing considerably the cost of development drilling. The RA-D project which started 4½ years ago ends in late 1991 with 'spudding' (FIG. 1) of the first hole, to initiate the proving tests of the powerful but compact light-weight offshore derrick and pipehandling system. Based on fast handling of single tubulars from 3½" to 20" diameter and rated to 20,000 ft. depths with a 1,000,000 lbs hook load the system is aimed at meeting the requirements of the North Sea and Worldwide. 2. INTRODUCTION The RA-D concept was conceived during an exploratory visit by S&H engineers a few years ago, to the North Cormorant offshore platform whilst looking for ways in which the company's handling capability could be applied offshore. An investigation into the automation of drilling followed after a serious paralyzing accident to a floorman when handling drill collars which was just one of the many hazardous jobs in drilling and indeed the oil industry. Drilling rig automation is a long held ambition of many offshore Operators. A number of automated drilling projects have been undertaken around the world as a result of the drilling industry's great interest in automation. Drillers see automation offering them smaller, lighter rigs with lower manning levels which will reduce the risks of injury and at the same time, reduce platform size and cost. Drilling rig designers see that automated rigs are now more feasible as a result of better and more reliable components available from other allied industries. There have been significant improvements in the elements of automated drilling systems, from the sensors and computers needed to control them, to the automatic torque wrenches and power swivels which manipulate the drill string coupled with the versatility of automated pipe handling systems. However 'progress' results from a desire of man to improve what he has but unfortunately the changes that 'progress' requires are not always readily accepted by him. The 'Cullen' report makes 106 recommendations relating to safety management, design and equipment, planning and provision for emergencies, Whilst not addressing drilling specifically, there was a very clear message that industry must develop equipment which is reliable and reduces manning on the platform, Each Operator will be required with its contractors to provide a safety case demonstrating that the safety management system of the design build and operation of the installation and equipments are as safe as reasonably possible. S&H came into the rig design business from a non-oil industry background.

ABSTRACT The purpose of the project is to develop the "Automated Offshore Drilling System" and to establish its basic design. Since 1984, research. investigation work. design. fabrication, and field test have been executed to develop the "Automated Offshore Drilling System" by Japan Ocean Industries Associations (JOIA), jointly with Mitsui Engineering & Shipbuilding CO., Ltd.(MES), and other member companies under the auspices of the Ministry of Trade & Industries (MIT!). Field tests of prototype mud pulse MWD and demonstration tests of 1/2 (one-second) scaled pipe handling systems including racking system, top drive system, draw works, Auto Roughneck, Pipe Handler, etc. had been completed successfully. INTRODUCTION The oil & gas extraction from offshore fields has become one quarter(1/4) of the world product. This percentage is expected to increase, and the development targets of future offshore fields will move toward a harsher environmental area, i.e., deeper water and arctic areas. On the other hand, "automation" is the demand of the times, in the industries and all human lives. however, the equipment and system on the drilling rigs seem to be far from automated. The major reason of the above is, the drilling operation strongly depends on experience and special skills of drilling crews. At the same time, a shortage of skilled drilling crews will become a critical issue. The current low level of the day rates earned by offshore drilling rigs and the reduced level of drilling by oil companies, has reduced the R&D efforts. The oil companies and contractors are rather conservative, then the rigs with totally different drilling system such as National A10-32 are very few. Developments of robotic drill pipe handling unit such as Temco in Norway have not been succeeded. R&D PROJECT To meet the demands of the times, MITI has been promoting the "Highly efficient offshore oil & gas drilling project", to develop an "Automated Offshore Drilling System", and entrust its practice to JOIA. This project, started in 1984, has a goal aimed atthe 1989 fiscal year to establish the basic design of the "Automated Offshore Drilling System". The project committee has been organized by JOIA with 12 member companies in Japan, to discuss the R &D work. The philosophy of this project is to develop the "Automated Offshore Drilling System" as an extension of the present concept, the system can be applied to any type of existing drilling rigs with small modifications to some extent. Among many sub-systems to be automated, the following five have been selected for this project: Central control &monitoring system Real time measuring system (MWD) Mud control system Pipe handling system Barge control system