Continuous Motion Rig (CMR Technology) - A Step Change In Drilling Efficiency

Innovative solutions for development of new technology and business models are needed to meet the economic challenges of declining production from the mature North Sea oil province. Bed space limitations imposed by platform redesign and modification at Oseberg East as part of the operator's improved oil recovery (IOR) strategy dictate a manning solution which significantly reduces persons on board (POB) if tail production is to be economically viable. Previous POB reduction models have typically focused on reducing the drilling contractor and production-phase manning levels on the platform. This study extends operational efficiency by employing an Integrated Services Model that encompasses multiple service providers in addition to the drilling contractor. Considering the entire crew in the context of "manning by tasks instead of manning by services" results in a substantial reduction of headcount whilst maintaining quality of execution. The solution developed covers directional drilling, downhole fluids, cementing, logging while drilling and completion operations, as well as drilling contractor and operator tasks. Emphasis has been put on transfering all work tasks that do not require physical presence at the rigsite to the onshore organization, for which use of modern communication technology is key. The business model promotes operational efficiency between service companies and drilling contractor through the development of non-traditional working processes that transgress individual company boundaries. Employees from third parties will be cross-trained such that their presence onboard is utilized in mission critical operations even where responsibility for the operation does not rest with their home organization. Maximising the effectiveness of onboard headcount is considered a first step in developing long-term, cost-effective solutions that will help ensure the longevity of mature assets. This paper describes solutions developed during the detailed planning phase of the Oseberg East tail production project, challenges to implementation, and expected benefits of the new service delivery model.

Breathing new life into a mature oil field is a challenge that has been facing national and private oil companies for almost as long as the oil industry has been in existence. Oil production from mature fields accounts for approximately 70% of the worldwide oil production. Unfortunately, more often than not, mature oil fields equate to high cost and low productivity, making mature fields unattractive when competing for resources with other options in a company's portfolio of investments. The re-development project presented in this and its companion paper1 (SPE 104034) looked at the technical and business opportunities for two main re-development components. The first component aims to beat the natural production decline curve via the implementation of a massive infill drilling program; the second component aims to maintain production through the integration of Improved Oil Recovery (IOR) methodologies. A multi-disciplinary team studied and recommended the implementation of a program to drill a massive number of infill wells in a portion of Block 10, operated by Petrobras Energia Peru S.A. in the Talara area of Peru, to improve recoveries in a column of over 2,500 ft of shaly sands, with absolute permeabilities not higher than 1 md and with average well spacing already in the order of 20 Acre. A second objective for the study team consisted of evaluating the technical feasibility for a massive waterflood project, including a preliminary design of the surface facilities necessary to collect, process and inject seawater. The third objective consisted of investigating the technical feasibility for miscible gas flooding into an equally tight reservoir, together with the facilities to collect and inject the gas. Both injection projects required consideration of the processing needs for the incremental oil, water and gas production. Traditional optimization technologies were also revisited, including the hydraulic fracturing of the infill wells to attain initial productivity gains of 25% with respect to that of current wells, but without impacting the completion cost. Based on analytical and numerical analyses, it was found that a massive waterflood would extend the production plateau reached by infill drilling and produce additional reserves. The study also found that to be able to displace oil in the Mogollon formation it would be necessary to inject gas at pressures in excess of 3,000 psi. The approach and methodologies developed for this project can be used to give new life to mature oil provinces around the world.

Mature oil fields tend to face drastic changes at both levels of production and operational efficiency leading to increasing demand of manpower & logistics as well as decreasing trend of equipment uptime that results in associated production deferrals. A key to sustainability of mature oil fields is to ensure high levels of utilization of existing resources and defy the progressive logistical demand to maintain profitability margins at maximum levels. such objectives can be approached by transformation to digital oil field. Digital oilfield incorporates data acquisition through installation of necessary sensors & meters, data management & analytics, remote monitoring, remote control & automated workflow. Gulf of Suez Is one of the mature oil basins that started oil production in mid-1960s and suffers from the same challenges facing mature oil fields. A vision of going digital was adopted and various digitalization projects are being deployed to allow remote monitoring & Control of gas lifted wells. which suggest several values ; Productivity: Digital oil field supported production optimization by optimum lift gas utilization giving more room for reactivation of shut in wells. Accessibility to all wells allows proper production deferral management during any production upset. Innovative data driven diagnostic tools supports troubleshooting and setting priorities of interventions. Operational Efficiency: harmony of production system can be improved dramatically with remote monitoring and control resulting in higher uptime of key equipment such as gas lift modules. logistics and manpower is a major part of operating cost of any mature field, incorporating remote monitoring and control will decrease the need of helicopter & boats trips to manual investigate production drops, efficient distribution of lift gas resulted in less gas lift demand & lower load on compression facilities. Profitability: Imperative impact of digital oil field hitting two birds with one stone; production & cost optimization will boost the profitability margin. the progressive implementation of digital oilfield in the subject asset succeeded to achieve 3% production increase, alleviate the demand of logistics and manpower, decrease the gas lift demand and managed to stop one gas lift module which had positive impact on asset profitability. Digital oil field is a good investment for green fields but it is a vital investment for mature field and a key enabler for business sustainability.

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper OTC 17437, "Continued Evolution of the One-Trip-Expansion, Single-Diameter Wellbore," by A. Filippov, SPE, and D. Zijsling, SPE, M. Akhideno, SPE, Shell, and K. Waddell, S. Costa, B. Watson, and B. Bell, Enventure Global Technology LLC, prepared for the 2005 SPE Offshore Technology Conference, Houston, 2–5 May. Copyright 2005 Offshore Technology Conference. Reproduced by permission. With more than 300 commercial installations in place, solid-expandable-tubular technology has proved to be a viable and economically feasible alternative to conventional drilling technology. The need for lower lifting costs and to maximize recovery has provided the impetus for the latest step change toward the one-trip section, single-diameter wellbore. In addition to the unique equipment needed to expedite this game-changing technology, new implementations essential to realize the tool components and contingencies had to be developed and tested. The full-length paper explains the overall design and testing approach necessary for the construction of a single-diameter well. Introduction Installation of successive single-diameter expandable liners will revolutionize the way many wells are designed and executed. The potential cost savings of an ultraslim wellbore and maximized reservoir potential have been well documented. Single-diameter technology offers the following benefits.Significant increases in potential lateral reach.Significant increases in potential lateral and trouble time.Improvements in capital efficiency on drilled wells and overall field development. This technology allows enhanced field-development flexibility and cost reductions in many worldwide field developments. For example, increasing lateral reach and thus reservoir contact and drainage creates the potential for reduced well count and greater production per well. More production from fewer wells can lower the number of wells required and result in reduced drilling costs. Reduced trouble time and risk lowers drilling costs. This drilling optimization can result in lower facility and project capital requirements. Field Applications Use of single-diameter expandable-casing technology has the field-proven potential to reduce drilling and completion costs significantly. These savings are realized by reducing drilling risk and resultant trouble time by successively isolating problem lithology and/or underpressured zones while preserving a single-diameter wellbore. Gulf of Mexico (GOM) operators, who often encounter severe lost-circulation zones at shallow depths, are watching this technology development in hopes of expanding long drilling liners to isolate these underpressured zones and later case off the expanded liner and problem zones. Successive installation of expandable, single-diameter wellbores can reduce the friction/drag forces that can limit lateral reach while preserving a single-diameter wellbore as deep as required. This application can provide higher weight on bit than conventional drilling technology at comparable depths.

This paper will discuss the concept and application of risk management in the North Sea, a mature oil province which now presents increasingly high cost, marginal development prospects. Examples of an integrated approach to risk assessment in field development planning, involving both petroleum and well engineering disciplines, will be examined using case histories from both mature fields and new projects. The use of leading edge technologies in this process will be discussed, in the context of introducing risk and the quantification of possible upsides and downsides in the process of optimising the overall economic return of a project.

Legacy gas fields face major challenges in field development planning, particularly in overcoming economic viability constraints caused by limited reservoir resources. Various cost-reduction initiatives have been undertaken. COMPANY has successfully implemented one such strategic initiative, which aims to maximize the lifespan of existing assets by repurposing wellhead platform topsides. Building on the success of reused two wellhead platform topsides in Great Bongkot North field and one wellhead platform topsides in Arthit field. These projects have extended platform life and provided significant cost savings and operational efficiencies. These successes serve as a strong foundation for future Topside Reuse initiatives. Future opportunities have been identified, and key insights from these initiatives have been analyzed. Lessons learned, technical assessments, and cost optimization of topside reuse can be integrated into other legacy gas field's master plan to enhance efficiency and sustainability in the oil and gas industry. A comprehensive Topside Reuse Screening initiative conceptual study was conducted to evaluate the feasibility and suitability of reusing existing wellhead platform topsides in the Gulf of Thailand. This initiative involved assessing technical aspects, which served as the foundation for potential modification work. High-level cost estimations were performed to provide a clear financial perspective on reuse of topsides. To evaluate topside reuse, a screening database and assessment tools were developed to identify modification costs if the topside is reused, categorized into base, recommended, and optional costs. These tools provide a comprehensive financial view and help determine topside reuse candidates in line with the depletion plan. The final donor and receiver candidate wellhead list is determined and developed into a Topside Reuse Master Plan for maximizing benefit to asset. The strategic depletion plan implementation with the reuse of existing wellhead platform topsides presents significant opportunities to reduce capital investment and operating expenses, particularly in maintenance, inspection, and decommissioning. By reusing wellhead topsides, we can enhance the value of existing assets and improve economic viability in mature fields. Key finding of this study is potential for substantial cost savings. With appropriate matching between reused topsides (donor) and designated platforms (receiver), and required minimal modifications, cost savings of approximately 5 - 10 million USD per new wellhead platform can be achieved. This estimate underscores the financial viability and attractiveness of the topside reuse strategy for field development with enormous benefit regarding the numbers of topside reuse. In conclusion, the topside reuse screening initiative conceptual study demonstrates that reusing existing wellhead platform topsides is a viable and economically beneficial strategy. Leveraging existing infrastructure can achieve significant cost savings, enhance asset value, and promote sustainable practices. Developing the Topside Reuse Master Plan, guided by this study's findings, will be crucial in realizing these benefits and ensuring the successful implementation of this strategy in the Gulf of Thailand. This is an attractive initiative and proactive approach that serves as a key success enabler in overcoming the challenges of legacy gas fields, particularly those with marginal resources and declining margins. Moreover, this innovative practice can be adopted and applied by other operators in oil and gas industry who are facing same challenges.

More than 200 exploration Wells have been drilled in the Northern North Sea (60°-62°N), and about 50% of the total acreage has been awarded. In a mature oil province new discoveries (as opposed to appraisals) will be based on new play concepts, probably within alternative or multiple stratigraphic levels. In the Northern North Sea this includes deep Middle Jurassic reservoirs buried to more than 4 km and Upper Jurassic to Tertiary reservoirs where the sand distribution and quality is just beginning to be understood. Since the economic potential is small compared to the risk of the prospects it is very important to have an updated geological model of high quality.

Subsea maintenance and production represent critical aspects of offshore operations, vital for sustaining energy production and ensuring operational efficiency. However, these endeavors face numerous challenges, including the complexities of deepwater environments, harsh weather conditions, and the high costs associated with traditional maintenance methods. To address these challenges, this paper explores the integration of technological innovations and optimized work methods in subsea operations. Technological innovations play a pivotal role in revolutionizing subsea maintenance and production. Remote monitoring and control systems enable real-time data collection and decision-making, enhancing operational visibility and efficiency. Autonomous underwater vehicles (AUVs) offer the capability to conduct inspections and repairs in remote and hazardous environments, reducing human intervention and associated risks. Robotics and automation further streamline maintenance tasks, improving accuracy and reducing downtime. Advanced materials and coatings enhance equipment durability and corrosion resistance, prolonging asset lifecycles and reducing maintenance requirements. In parallel, optimized work methods offer strategic approaches to enhance subsea operations' effectiveness. Predictive maintenance strategies leverage data analytics and machine learning to anticipate equipment failures, enabling proactive interventions and minimizing downtime. Condition-based monitoring facilitates real-time assessment of asset health, enabling timely maintenance interventions and cost savings. Integrated asset management systems provide holistic insights into asset performance and facilitate informed decision-making. Lean operations and continuous improvement methodologies further optimize workflows, driving operational excellence and cost efficiency. Through case studies and industry examples, this paper highlights the successful implementation of technological innovations and optimized work methods in subsea maintenance and production. Furthermore, it explores future trends, regulatory considerations, and the importance of industry collaborations in shaping the future of subsea operations. Ultimately, the integration of these approaches offers a pathway towards enhanced operational efficiency, reduced costs, and sustainable subsea operations. Keywords: Technological Innovations, Optimized Work Methods, Subsea Maintenance and Production.

The urban railway system plays a critical role in modern transportation, demanding constant operational efficiency and cost-effectiveness improvement. The problem statement identifies the existing gaps and challenges in Operation Expenditure (OPEX). Managing operation costs in urban railways is a multifaceted challenge involving intricate interdependencies and considerations. In this context, integrating blockchain technology presents a promising approach to optimise the operation and maintenance processes, potentially reducing costs while enhancing transparency, security and efficiency. The traditional operation and maintenance practices of urban railway systems often suffer from inefficiencies, lack of transparency and high administrative overheads. This results in inflated operational costs, which ultimately burden both operators and passengers. Moreover, conventional methods often struggle to effectively manage the complex network of assets, maintenance schedules and service providers, leading to suboptimal resource allocation and prolonged downtime. These include a variety of approaches, such as simulation techniques, optimisation models, machine learning algorithms and detailed analytical frameworks like the Analytical Hierarchy Process (AHP), which is based on PRISMA. The advanced searching techniques on SCOPUS, Web of Science (WOS) and IEEE Xplore database using the keywords “blockchain technology”, “operating costs”, “maintenance”, “financial” and “urban railway” were applied. The final primary data (n=24) was analysed using the quantitative data method. The themes were decided, which are Theme (1) on railway operations and efficiency, Theme (2) on Deep Learning and Financial Technology and Theme (3) on Financial Risk Management and Evaluation. The integration of blockchain technology into urban railway operations and maintenance holds significant promise, offering improved transparency, efficiency and security. By enhancing trust among stakeholders through increased transparency and auditability as well as fostering collaboration and accountability, blockchain can revolutionise traditional practices. Furthermore, the automation of tasks and optimised resource allocation are expected to yield cost savings and operational efficiencies. Additionally, the decentralised nature of blockchain technology mitigates the risk of data tampering and cyberattacks, ensuring the integrity and security of critical infrastructure systems. Overall, blockchain presents a paradigm shift in managing urban railway operation and maintenance costs, paving the way for more sustainable, reliable and cost-effective transportation systems worldwide.

Onward: Propelling hospital pharmacy technician roles forward

After 70 years of continuous exploitation in the Bolivar Coast region of Lake Maracaibo, Venezuela (Fig. 1), advanced reservoir depletion is causing drilling problems such as severe loss of circulation, hole instability, and extensive formation damage. In an attempt to optimize drilling performance, several operation practices were implemented through 1997, such as air-, mud-, foam-, and oil-base mud systems, etc., without achieving the expected success. Fig. 1Geographic location. Because of the challenges of working in these mature fields, the operator and the oilfield services company created a services alliance contract called PRISA (a Spanish acronym for Integrated Drilling and Workover Alliance Services). This paper describes the drilling technologies and best practices used to improve drilling performance in these mature reservoirs, the learning curve evolution, and process improvement. The results included a cost reduction of 12% (in investment cost/barrel), a production increase of 4%, a 58.7% reduction in drilling time, and a drilling cost reduction of 3.6% (Figs. 2 through 3B). In addition, nonproductive time (NPT) has been reduced from 24.1% in 1999 to 3.8% in 2002 (Fig. 4). Fig. 2Drilling time evolution in mature fields in Lake Maracaibo.Fig. 3ADrilling costs evolution in mature fields in Lake Maracaibo.Fig. 3BProduction evolution in mature fields in Lake Maracaibo.Fig. 4NPT evolution in drilling operations in mature fields in Lake Maracaibo.

This study presents a comprehensive examination of the impact of integrating solar energy into healthcare delivery in rural Uganda. Utilizing an extensive equation encompassing factors such as cost savings, operational efficiency, healthcare outcomes, and environmental impact, the research uncovers a holistic benefit of sustainable energy adoption into Uganda Health Centers. Key findings suggest that beyond serving as a reliable and sustainable power source, solar energy integration has the potential to revolutionize rural healthcare. The equation reveals promising outcomes, including redirected resources for critical healthcare needs, improved operational efficiency, and positive healthcare outcomes. The environmental benefits, coupled with the scalability of solar models, emphasize a sustainable future for rural healthcare. The study concludes with a compelling call to action, urging stakeholders to collaborate in swift implementation, policy development, and research initiatives. Recommendations include targeted policies, funding for solar infrastructure, and ongoing research into region-specific considerations. This work serves as a reagent for a sustainable transformation in healthcare delivery, advocating for a brighter and healthier future for underserved communities in Uganda and other countries with similar challenges. Keywords: Solar Energy Integration, Rural Healthcare, Cost Savings, Operational Efficiency, Sustainable Transformation

The potential coupling of two leading-edge technologies has garnered much attention for its substantial business case regarding field development optimization. This specific application consists of marrying single-diameter technology and extended reach drilling (ERD). Using these two technologies as companion pieces in a drilling design can positively impact capital cost structure, resulting in economically superior alternative development scenarios. Single-diameter technology, a natural derivative of the conventional solid expandable tubular system, provides the foundation for a significant increase in the lateral reach of many extended-reach wellbores. This extended lateral reach results in increased reservoir contact that can lead to increased production per well. Increased lateral reach and production per well can ultimately reduce the required field well counts and infrastructure, resulting in improved field development economics. This paper will describe how combining these technologies mitigates critical factors that limit achievable reach including dogleg severity, casing openhole size vs. drillstring size, and ultimately torque and drag. Using solid expandable tubular single-diameter technology with significant friction reduction could extend the current ERD envelope 25 to 100%. More efficient reserves access, economic benefits and technical advantages will also be presented. In conclusion, this paper will discuss the technology's proven, simulated and engineered potential and how it can put more reserves within reach. Introduction Solid expandable tubulars have rapidly evolved over the last few years into a proven openhole drilling liner and cased-hole remedial liner alternative to conventional technology. These systems improve capital efficiency, reduce drilling trouble time, improve field development economics and extend lateral drilling reach, and/or perform extensive remedial work while preserving the required completion and/or completion size. The use of expandable technology has proven to be highly effective as a contingency and a planned well design application. The single-diameter system offers a truly enabling technology to complement the reliable and cost-effective solid expandable tubular applications. As part of the front-end engineering and design for a major North Sea operator, a well design feasibility study was conducted over an existing and planned field development. This study was conducted to assess the relative merits of applying conventional drilling technology versus expandable tubular technology regarding lateral reach and the impact on capital efficiency and potential field development. This welldesignmodeling study indicated potential lateral reachincreases of 25 to 100% with significantly reduced drilling trouble in both fields. Complementary drilling performance and cost studies have also indicated that existing and planned operator well costs and times in the same two North Sea fields can be reduced by over $40MM, or 30 to 50% of the current and forecast drilling cost and time, with the application of solid expandable tubulars and/or single-diameter technology. These well design studies also indicated preservation of desired completion size, which led the operator to conclude that planned subsea templates and associated infrastructure and/or satellite tie-ins can be eliminated from their field developments with solid expandable tubulars and/or singlediameter technology.

Many drilling provinces throughout the world have high reserve potential but relatively low production rates from typical wells. This low productivity may preclude economic development drilling using conventional techniques. The increasingly marginal nature of finding and producing natural gas has increased the need for technologies that reduce the cost of drilling and completing wells beyond mere incremental steps. Slim-hole drilling and completion is one technology with the potential to make a substantial impact on costs. In mid-1995, a major operating company, with support from the Gas Research Institute (GRI), undertook a three well slimhole drilling project in the Greater Green River Basin of Wyoming. Barriers to slim-hole drilling, both real and imagined, were overcome during the course of the project, and the performance capability of modern slim-hole technology was determined. Slim-hole drilling and completion will allow additional economic development of marginal areas, particularly in natural gas provinces where there is minimal need for high-volume artificial lift. Introduction and Background Early in 1995, GRI began a major project to define "Emerging Resources in The Greater Green River Basin" and to determine the optimum means of developing the area's large tight gas resource. A primary objective of this project was to identify technology that could be utilized immediately to this end. Other work underway for GRI had already identified slim-hole technology as a promising approach for reducing drilling and completion costs while maintaining well productivity. An opportunity for a three well slim-hole drilling and completion project on the Cow Hollow lease in the Moxa Arch field of Wyoming (Figure 1) was presented by a major operator, and GRI agreed to participate. The term "slim-hole" means many things to many people. Most commonly it is defined as one or more bit-sizes smaller than what is normally used in an application. The three slim production holes at Moxa Arch were all drilled with a 4 3/4-inch bit, which is slim-hole by almost anyone's definition. Interest in slim-hole drilling and completions peaked in the United States in the early 1960s, but then declined due to the absence of strong economic forces to drive development of the technology. As producers began to seriously search for methods to reduce costs in the early 1990s, interest in slim-hole technology began growing again. From the mid-1980s to the mid 1990s, the percentage of wells completed as slim holes in the United States rose from 3 to 5 percent, and the percentage is even higher for gas wells. An industry-wide survey to find barriers to slim-hole technology growth revealed that drilling was not perceived to be a large barrier. For barriers related specifically to drilling, the two topics perceived as the largest barriers were fishing and directional drilling in slim holes, as shown by the chart in Figure 2. Other topics perceived to be large barriers by the industry included mud motors, well control, and bits for slim holes. The Moxa Arch project addressed three of the top six perceived barriers to slim-hole operations, and demonstrated that, in many cases, these are only perceptions. Technology has advanced to the point that expectations and perceptions based on past history are often no longer valid. Slim-Hole Project Objectives The two major objectives of the slim-hole work were to (1) determine the current performance capabilities of modern slimhole technology and (2) determine the cost savings potential of slim-hole drilling in the Greater Green River Basin. Several areas of modern drilling technology were addressed by the project. P. 155^

Multi stage fracturing of horizontal wells is quickly creating the same "step change" as when vertical wells first went horizontal. As improved advances are made in drilling and completing horizontal wells, new solutions are required to address the limitations of today’s multi-stage fracturing methods. A new process, conceived and licensed from ExxonMobil Upstream Research Company, offers an alternative to existing multi-stage fracturing methods. This paper will discuss the benefits, cost savings and case histories of a newly released single trip coiled tubing conveyed annular fracturing & perforating assembly.