The Drilling Systems Automation Roadmap (DSA-R) initiative is a cross-industry effort launched in June 2013 to help accelerate the adoption of advancements in drilling systems automation for both onshore and offshore wells. When completed, this technology roadmap will provide the drilling industry with a well-defined guide on the expected development and adoption of drilling systems automation technology in the near and long terms. The focus on needs, vision, scope, and boundaries will enable development of solutions to implement Drilling Systems Automation (DSA) in a manner that effectively improves performance, reduces well costs, removes people from high-risk operations, and promotes general drilling safety, among other key goals. To enhance consensus, the DSA-R initiative decided to affiliate with the SPE, IADC and the Association for Unmanned Vehicle Systems International (AUVSI). This technology roadmap uses the well-known template developed by Sandia National Laboratories to provide a mechanism to forecast how DSA developments can progress, and to provide a framework to coordinate among disparate players. The process also will enable players outside of the oil and gas industry to envision how to participate and contribute to the implementation and advancement of DSA. From the onset, the roadmap was segmented into eight key challenges, each individually defined in terms of functional description, performance targets, current status, problem statement, and development to meet the vision. The eight challenges are (1) Systems Architecture, (2) Communications, (3) Instrumentation and Measurement Systems, (4) Drilling Machines and Equipment, (5) Control Systems, (6) Simulation Systems and Modeling, (7) Human Systems Integration, and (8) Certification and Standards. Interdisciplinary challenge teams formed by subject-matter experts from both inside and outside the oil and gas industry are developing the maps for the challenges. The interdependencies and related interfaces among the challenges are being coordinated through the committee to ensure consistency of approach and timelines. The purpose of this paper is to describe the launch of the DSA technology roadmap initiative, the processes being applied and key details on the status of each of the challenges. All roadmaps are invariably long-term projects, but the sharing of information at this critical stage is important to encourage wide industry involvement and participation to accelerate the implementation of automation in drilling.

1202 PROGRAM ALARM This disturbing alarm, displayed to the men on location and in a remote center during the most critical part of the operation, signaled that the onsite computer system was no longer able to handle its automated multitasking requirements. The crew was forced to assume manual control to complete the operation, but not without continued assistance from onsite computers and engineers monitoring the event in the remote center. A short time later came the announcement heard by 600 million people around the world - "Houston, Tranquility Base here. The Eagle has landed. " Neil Armstrong had safely landed the Apollo 11 Lunar Module on the Moon . Automation, perhaps the most game-changing opportunity in drilling today, is improving operational safety, efficiency, quality, and economics. More importantly, automation is making possible the execution of operations and activities difficult or even impossible for rig crews to complete using traditional methods. Notable recent success notwithstanding, the uptake of automation could be accelerated by the creation of industry-wide and segment-specific technology roadmaps to define short- and long-term goals and track progress. While most technology roadmaps are extensive and detailed documents, they must be built on a solid foundation that represents an overall view of the technology. Presented in this paper is a new design aid developed precisely for creating and displaying this view. For drilling automation in general and any number of specific operations and supporting technologies, the design tool can visually illustrate current and future (desired) states and the path(s) connecting the two. This visual approach also serves to catalyze discussion of this important topic. The design tool presented here is a radically different way to create a technology roadmap overview. It is based on the common ternary chart, a triangular diagram that graphically depicts the composition of three-component systems. For drilling automation, the three components are rig equipment automation, rigsite manpower, and engagement from remote operation centers. Proportions of the three variables total 100% by definition. Simply stated, this means that a reduction of personnel on board, for example, must be balanced by increased automation of rig equipment and/or a higher level of engagement from remote operation centers. The primary objective of this paper is to describe the underlying technology of this drilling-system automation design aid and to demonstrate how it can be used for real-world applications. There is no intent to present hard data that could be used directly to generate automation roadmaps for drilling.

The drive to industrialize the drilling process through automation is gaining greater acceptance within the upstream oil and gas industry. The concerted, multi-faceted effort is being spearheaded by SPE and IADC committees working with industry on a common automation language, fit-for-purpose interface protocols, and a disciplined technology roadmap. The primary purpose of this paper is to define the Well-Construction Fluids (WCF) domain in order to contribute to the roadmap foundation. Also discussed are existing technology gaps related to fluids automation, and targeted efforts to find practical solutions for these gaps. The WCF domain encompasses the fluids used in drilling and completion operations, as well as the flow conduits, tanks, and process equipment required for optimum performance. At the highest level, the domain is represented by four major systems: (a) fluids treatment and pumping, (b) downhole, (c) solids control, and (d) waste management. Understandably, the WCF domain has a broad sphere of influence and interacts with all well-construction processes, including conventional drilling, well control, managed-pressure drilling, tripping, and running and cementing casing. Because of this interdependence, numerous projects have been initiated to develop robust, automated equipment to measure critical fluid properties required by all these processes. Within the WCF domain, systems also are being developed to automate and control different fluids processing equipment and to mechanize chemical additions and mixing operations. Ultimate success will depend not only on improved data from better monitoring, but also comprehensive data management systems linked to interpretative schemes and predictive analyses that convert the data into useable knowledge.

Abstract Tailoring drilling fluid hydraulics is one important key to the success of a drilling operation. Failure to do so can result in costly problems, negatively impact equipment longevity and performance, and ultimately jeopardize overall well objectives. In recent years the industry methods have deviated from API RP13D Standard Practice. This departure has been driven primarily by the increasingly onerous demands of critical wells, coupled with readily accessible computer power. In 2003 a Task Group was formed to modernize the existing API Recommended Practice Bulletin on Rheology and Hydraulics. It comprised a cross-functional team of operators, suppliers and academics which set an aggressive target to modernize the existing standard within two years. The focus was to develop simple, yet accurate methods, which could be readily implemented with basic spread-sheeting skills. This paper describes improvements made to the existing procedures and provides an illustration of how these methods can be applied to complex well designs. The paper also serves to introduce the industry to a modernized API Standard which offers an ideal foundation to inform new engineers of the fundamental concepts of hydraulic design and optimization. Introduction Rheology and hydraulics are central to successful well planning and execution of drilling operations, and there has been an API Recommended Practice (RP) in place since the mid 1980's. API RP13D1 has served the industry well as a guide to support these important issues. However it was widely recognised that the most recent version of this recommended practice required modernization. The primary drivers for this included: Increased well complexity beyond the scope of the current document Extensive use of drilling fluids with physical properties sensitive to high pressure / high temperature (HP/HT) environments The need to integrate wellbore engineering technologies to give a holistic approach. In addition a recently published paper2 concluded that the timing was right to effectively bridge the widening gap between field practices and the technology being introduced into advanced hydraulics software. By incorporating the basic fundamentals it is believed that the revised standard will serve both as a practical reference and a training guide. The intended target audience includes the office-based planning engineer and the wellsite operational staff (drilling engineer and drilling fluids engineer). A review of the existing RP13D identified the following areas as the primary focus for attention in enhancing the document: downhole behavior (rheology and density); pressure-loss modeling; hole cleaning; drilling optimization; swab-surge pressures; wellsite monitoring and rheological testing. A full listing of the revised sections is shown in Table 1. This paper introduces the modernized recommended practice which is currently undergoing final editing by the API. Also presented are revision improvements and their application to complex well designs, together with the project planning and management methods employed to complete the new document to meet an aggressive timeline.

Abstract Visualization technology has evolved into an important G&G tool to view and interpret seismic data, 3D logs, geocellular models, grids, horizons, and well placements. Directional drillers also benefit from visualizing complex placements in 3D; however, this is one of very few drilling applications that currently exists for this technology. Introduced in this paper is software that for the first time permits interactive 3D visualization of the inside of a virtual wellbore. In this initial offering, downhole drilling hydraulics and related conditions can be critically examined while navigating the well from surface to TD using a standard PC and a joystick. The new software system has application for interpreting large data sets, mitigating drilling problems, training, and encouraging collaboration among multi-disciplinary teams. Stunning 3D perspective rendering can show internal and side projections of well tortuosity, cuttings beds, drill string (including eccentricity), annular velocity profiles, formations (texture, rugosity, and breakout), downhole engineering parameters (temperature, ESDs, etc.), and downhole tools, among others. "Intelligence" is incorporated that can direct the software to automatically find, display, and visually inspect anomalies and potential hydraulics-related problems. Simulated data are provided by an advanced hydraulics program; a real-time version is planned that also will include other key drilling and wellbore parameters. Both options are suitable for use in real-time drilling centers. The purpose of this paper is to discuss the development, application, and opportunities of this wellbore visualization software. Special emphasis is placed on the quality and uncertainty of models, and methods used to drive the 3D graphics. The design, development, and implementation of the fit-for-purpose graphics platform also are discussed. Introduction It is no wonder that the oil industry often uses 3D visualization to showcase its exploitation of the latest high-tech developments. After all, the power of visualization is indisputable. Its bottom-line benefits in oilfield applications, however, are not. One recent technical paper1 questioned whether visualization was a "game changer, facilitator or gimmick?" and another2 asked "does it make a difference?" Both questions were rhetorical, since visualization already had been a well-established planning and analytical tool3–4 for the geological and geophysical (G&G) segment of the industry. Benefits extend beyond technical issues, as communal visualization has promoted multi-disciplinary discussion5 and created opportunities "to bring people together and improve the dynamics of the team by providing clarity in the face of the ever increasing amount of data that forms the modern well construction process."1 Similar success is being achieved in drilling. Early applications focused on well placement in complex reservoirs, and directional drilling to control well tortuosity and avoid collisions on multi-well platforms.1,6 More recent applications use 3D visualization to address drilling problems7 and link drilling operational data to earth models.8,9 Countless other drilling prospects should exist, especially considering that "making hole" occurs out of sight, miles below the earth.s surface. The subject of this paper is innovative software developed to exploit additional drilling visualization opportunities. The software for the first time permits interactive 3D visualization of the inside of the wellbore, a more natural view for most drillers, whether on the rig floor or in the office. Simulated downhole conditions can be critically examined while navigating the well from surface to TD using a standard PC and a joystick. This capability is useful for interpreting large data sets, mitigating drilling problems, training, and maximizing collaboration among multi-disciplinary teams and some drilling teams separated by a common language. It also has placed downhole modeling under the microscope and helped highlight important areas where renewed effort is required.

Abstract Economically marginal wells, sometimes critical in their own right, can require tight equivalent-circulating-density (ECD) control just like their expensive HTHP, deepwater, and extended-reach counterparts. Limited budgets or well conditions, however, may preclude use of pressure-whiledrilling (PWD) technology. This paper presents a case history where the ability to manage ECDs from within a remote, realtime operations center was tested on an HTHP well in the Gulf of Mexico and subsequently on a low-budget land well in the western United States. Field results demonstrate that it is possible to obtain high-quality ECD information without running PWD tools. Special hydraulics software run at the operations center provided virtual sensors for equivalent circulating and static densities while drilling, tripping, and running casing. PWD data was available for comparison on both wells, except for the lower intervals of the HTHP well. In the latter well, high formation temperatures exceeded tool limits, so it was necessary to rely strictly on computer simulations for ECD management. The primary purpose of this paper is to critically review these case histories to help assess the spectrum of opportunities for ECD management from remote operations centers. Field results, operational issues, planning requirements, training efforts, and technical and business drivers are among the topics that will be presented and discussed. Lessons learned and recommendations for future efforts are also included. Introduction ECD management is among the most pressing concerns for drilling wells safely, economically, and efficiently. Narrow operating windows in today's most critical wells are continually tested by elevated ECDs during drilling, tripping, and casing operations. Drilling fluid density is required for pressure control and wellbore stability; viscosity and flow rate are needed for hole cleaning and barite-sag mitigation; gel strengths are required for static suspension of cuttings, etc. Finding the proper balance among these parameters is the goal of ECD management. The advent of pressure-while-drilling (PWD) technology and the resurgence of real-time operations centers (OCs) independently and collectively have increased ECD-management opportunities. PWD and other real-time data transmitted from the rig allow drilling teams, OC personnel, and others to interact with rig personnel to achieve quality ECD programs. However, this combined service basically has been limited to high-budget, critical wells. The term "critical" previously has been applied to drilling projects that "possess several of the following attributes: high risk, frontier location, remote, deepwater, great depth, expensive, technically difficult, adverse environment, environmentally sensitive". 1 Clearly, "narrow operating windows" should be added to this list. Other wells also have this need, but a high percentage of these probably cannot take full advantage of this PWD/OC combination for ECD management. Many do not have the budget to run PWD tools, or the drilling visibility to rate OC attention. In other cases, high temperatures preclude use of PWD in intervals where the data would be most valuable. Furthermore, PWD technology is not available on any well during certain critical operations such as running casing. PWD "technology gaps" have been successfully addressed by a real-time hydraulics system 2,3 (RTHS) that complements PWD when measurements are available and substitutes for PWD when real-time measurements are not. The RTHS has primarily been a wellsite service; however, new opportunities are created when it is used in conjunction with a real-time OC. This refinement was tested when the simulation computer was installed in Shell's New Orleans real-time operations center (NOOC) instead of at the rigsite. The first two case histories involving real-time hydraulics simulations from within an OC are discussed in this paper. The first test was conducted on a critical Gulf of Mexico shelf well. It was expected that HTHP conditions would eventually prohibit use of PWD tools. The second case was a high-visibility, but low-budget land well in the Pinedale field in the western United States.

Abstract Barite sag continues to be a recurring, potentially serious problem on many directional wells. Despite concerted efforts by the drilling industry and early progress, recent continued improvements in sag mitigation have been limited. Sag is a particular problem on HTHP wells and in deepwater wells where ECD management is required. These wells pose difficult drilling conditions where drilling practices may offset sag-management advancements. The sag "magic bullet" has thus far been elusive. This is understandable since sag is affected by many parameters and their interactions are difficult to quantify. While the importance of mud rheology is well known, attempts to find the key rheological parameter have not been completely successful. Furthermore, lack of industry standards to measure and report barite sag has limited the availability of usable field data. Sound engineering strategies and guidelines have helped, but clearly more developments are needed. The primary objectives of this paper are to (a) examine key barite-sag challenges, (b) characterize current best practices, and (c) discuss strategies, opportunities, and active programs for step improvements. Recent barite-sag case histories from the Gulf of Mexico, West Africa, and Atlantic Canada are included to set the proper perspectives. Introduction Barite sag is a concern on all directional wells drilled with weighted mud. Failure to properly plan and execute a sag-management program could lead to a variety of major drilling problems, including lost circulation, well-control difficulties, poor cement jobs, and stuck pipe, casing, and logging tools. HTHP, extended-reach, and deepwater wells are particularly at risk for a combination of reasons. Recent case histories from four major drilling locations are presented in this paper to emphasize that barite sag is a persistent drilling problem. They also show that sometimes it is necessary to violate accepted barite-sag management principles to address more pressing drilling issues. ( Note : The term "barite sag" is used for convenience because barite is the traditional weight material used in drilling fluids. Sag can apply to any mud weighted with an inert material.) Unfortunately, barite sag is proving to be a real conundrum for the drilling industry. The physics of the phenomenon are deceptively complex, and the problem is often unanticipated. Despite continued and concerted efforts, universal solutions are not readily at hand. Moreover, increasingly difficult drilling situations in critical wells are effectively limiting the application of common remedies to mitigate sag, even suggesting that new or different strategies may be in order. Prior to around 1990, the consensus was that sag was predominately a static settling problem. This is understandable, since barite sag is a significant mud density variation, lighter and heavier than the nominal mud weight, observed when circulating bottoms up after any operation where the mud has been static for a period of time. However, an early study 1 concluded most sag beds form during circulation, and the density variations are caused by circulating out beds that have slumped towards the bottom of the hole. Practical guidelines 2,3 followed that are still applicable and suitable for mitigating sag in all but the most severe cases. Proper sag management requires careful and concurrent consideration of both mud and operations-related parameters. There is no "magic bullet", although mud rheology seemingly has been given an inordinate amount of attention. Despite the clear and important connection between rheology and sag, the additives used to achieve an "optimum" rheology 4,5,6 in different mud types are equally important.

Abstract Accurate downhole and surface measurements of a synthetic-based drilling fluid were taken in a Gulf of Mexico well to resolve variances between actual and calculated pump pressures, and to quantify equivalent circulating densities. Current API equations seriously underestimated drillstring losses, which accounted for the pump-pressure differences. Conversely, annular losses were much lower than predicted. Introduction The drilling industry cannot consistently match calculated and actual pump pressures and is uncertain with the reliability of equivalent-circulating-density (ECD) predictions when using oil-based muds. Sensitivity to temperature and pressure is the most often cited reason for the discrepancies. Attempts to compensate for these effects with oil-based muds have not met with widespread success. Similar difficulties are encountered with synthetic-based muds (SBMs); however, concerns are more acute. Pump-pressure calculations with SBMs can be off as much as 35%. The high unit cost per bbl of SBMs makes lost circulation a serious risk if ECD values are unreliable. Related problems which also are affected by hydraulics include surge/swab pressures while tripping, sizing of mud pumps, hydraulic optimization, well control, and general well planning.

SPE Members Abstract Field data have been collected and analyzed to 1) identify the characteristics of a drilling fluid that enhance rate of penetration, and 2) quantify the impact of particular fluid properties on rate of penetration. The information is being used to evaluate the economics of a fluid treatment program in order to deliver optimal drilling performance and minimum drilling cost, rather than minimum fluid cost. Additionally, it is demonstrated how bit hydraulics can be improved through rheological modification without adjusting flow rate or nozzle size. Introduction It has long been known that drilling fluid properties can dramatically impact drilling rate. This fact was established early in the drilling literature, and confirmed by numerous laboratory studies. Several early studies focused directly on mud properties, clearly demonstrating the effect of kinematic viscosity at bit conditions on drilling rate. In laboratory conditions, penetration rates can be affected by as much as a factor of three by altering fluid viscosity. It can be concluded from the early literature that drilling rate is not directly dependent on the type or amount of solids in the fluid, but on the impact of those solids on fluid properties, particularly on the viscosity of the fluid as it flows through bit nozzles. This conclusion indicates that drilling rates should be directly correlative to fluid properties which reflect the viscosity of the fluid at bit shear rate conditions, such as the plastic viscosity. Secondary fluid properties reflecting solids content in the fluid should also provide a means of correlating to rate of penetration, as the solids will impact the viscosity of the fluid. As the technical literature began to focus on the effect of different types and concentrations of solids, the industry began to turn its attention to the removal of those solids, but with little regard for the resulting viscosity of the fluid. Industry also began to recognize the wellbore stability benefits gained from low fluid loss muds, but once again ignored the effect that polymers and bridging solids added to the fluid to gain filtration control had on rheology, particularly high shear rate rheology. Low shear-rate rheology is often modified to provide for cuttings transport, which often raises the high shear-rate rheology as well, with potential detrimental effects on rate of penetration. P. 333