Drilling Contractors Research Articles

Meeting Increasing Demands for Upstream Scope 3 Reporting: A Framework for the Drilling Industry

Summary This paper details the scope and framework applied for quantifying upstream Scope 3 greenhouse gas (GHG) emissions of offshore drilling operations. A step-by-step methodological approach is presented, comprising environmental impact modeling of drilling and rig operational activities through the application of the life cycle assessment (LCA) methodology. The study aims to break down upstream Scope 3 emissions to a process level, demonstrating how upstream Scope 3 emissions can be quantified and evaluated to a greater detail level compared with what current Scope 3 reporting levels offer today. A North Sea drilling case study conducted in collaboration with a major drilling contractor is used for showcasing the impact burden levels, challenges, and prosperity of accounting, reporting, and tracking upstream Scope 3 emissions as a drilling contractor. A total of 141 drilling and rig operational activities were identified and prioritized for impact calculation, presenting a detailed breakdown of upstream Scope 3 emissions results for offshore well drilling. Impacts are quantified in tonnes of carbon dioxide equivalent (CO2eq.) emitted per day in operation. The study does not include downstream Scope 3 and reports limited to direct (Scope 1) emissions. Results show a total upstream Scope 3 emissions burden of 412 tCO2eq./d in operation. Of the eight assessed upstream Scope 3 categories, purchased goods account for the largest contribution of 32%. Activities related to the operation and maintenance of drilling equipment account for the largest impact contribution of 351 tCO2eq./d, corresponding to 86% of total upstream Scope 3 emissions. The reported outputs may serve as a benchmark for future Scope 3 accounting and reporting within the drilling industry, as well as for LCA inventories for oil and gas production. A set of system boundaries for assessing upstream Scope 3 emissions is suggested, along with recommended emission calculation methods. The presented framework may serve as an alternate supplement to the International Petroleum Industry Environmental Conservation Association (IPIECA) adapted version of the GHG Protocol’s Scope 3 Standard in terms of Scope 3 inventory boundary setting and data prioritization with relevance to drilling contractors, and finally to the International Association of Drilling Contractors (IADC) industry guideline for environmental, social, and governance (ESG) reporting.

SPE Board Announces Nominees for 2024 President and 2023 Directors

2024 SPE President Terry Palisch is the vice president of technology and engineering at CARBO Ceramics in Richardson, Texas. He began his career with ARCO, during which he served 4 years in Algeria and 10 years as a senior petroleum engineer in Alaska. Palisch joined CARBO in 2004 and in his current position leads a team of technologists developing and championing new products and services and advising clients on completion and fracture optimization. Palisch has been an active SPE member serving in various roles, including past chairman of the SPE Dallas Section, past chair of the SPE Annual Technical Conference and Exhibition (ATCE) technical program and former SPE Completions Technical Director. He is an SPE Distinguished Member and received the award for Distinguished Service, as well as the SPE Mid‑Continent Regional Completions Optimization and Technology Award and the Regional Service Award. In 2013, he was named one of the Top 15 Best Engineers by the Texas Independent Producers and Royalty Owners Association, and in 2015 he was named the SPE Dallas Section Engineer of the Year. He has authored more than 50 SPE technical papers and holds several patents. Palisch holds a bachelor’s degree in petroleum engineering from University of Missouri‑Rolla (now Missouri University of Science and Technology) and was recently recognized as a Distinguished Alumnus. North America Regional Director Robert C. Martinez is president and CEO of Titan Rock Exploration & Production and president of Alpine Gas. He has more than 23 years of experience developing and optimizing oil and gas assets throughout the US, including conventional assets, unconventional horizontal development programs, and enhanced oil recovery projects. Middle East and North Africa Regional Director Mohamed Al Marzouqi is senior vice president of development at ADNOC Upstream Directorate. He has been with ADNOC since 2005. He joined ZADCO (ADNOC Offshore) as a petroleum engineer in field development to head the maximum-reservoir- contact (MRC) well-design team during which first production began through MRC wells from an artificial island. As a senior manager for reservoir development at ZADCO, he developed reservoir management strategy to redevelop a multibillion-dollar project in the Upper Zakum field through artificial islands. He led the team in the development of integrated reservoir management for ADNOC Group. Drilling Technical Director Robin Macmillan is the chief sales officer at Data Gumbo. He was previously senior vice president for business development at NOV, manager of Schlumberger drilling and measurements in Canada, and president at drill-bit company ReedHycalog. In his early career he worked in offshore and onshore drilling operations in several countries across North and Latin America, Africa, the Middle East, and Europe. He is the current vice president of drilling services and a member of the Executive Committee at the International Association of Drilling Contractors, where he is also Chair Emeritus of the Advanced Rig Technology Committee and a member of the Drilling Engineering Committee. Health, Safety, Environment, and Sustainability Technical Director Susan (Sue) Staley is the sustainability director for vPSI Group LLC where she leads the company’s sustainability practice. Prior to joining vPSI, she was the general manager of soil and groundwater technology at Shell and held various positions there during her 18-year tenure. Prior to Shell, she worked as a consultant at ERM. Staley has been an environmental and safety engineer for 30 years.

The Ultimate Breakthrough for Drilling Automation May Be Simply Finding a Business Case

The biggest meeting of the year dedicated solely to the topic of drilling automation revealed that the ultimate barrier facing this emerging development is not the technology. It’s how the business of drilling is done. This is according to many of the technical professionals that participated in a recent symposium held jointly by SPE’s Drilling Systems Automation Technical Section (DSATS) and the IADC’s Advanced Rig Technology Committee. The annual event held in conjunction with the IADC/SPE International Drilling Conference and Exhibition departed from its usual format of speakers issuing well-rehearsed presentations. Instead, it took on the form of a multipronged focus group that saw dozens of participants hailing from operators, drilling contractors, and service companies who huddled into the four corners of a conference ballroom in Galveston, Texas. Their chief objective was to help update the DSATS’s “roadmap” that identifies which technological breakthroughs are needed to bring about a true step change in drilling automation by 2025. But as that year draws near, the odds of reaching most of the key milestones are dimming, and so, the symposium leaders decided to instead look toward what should be achieved by 2030. What DSATS wants to see become possible in the coming years is a rig in which “well plans are uploaded into an interoperable drilling system that automatically delivers a quality wellbore into the best geological location.” Though we have seen pieces of drilling automation come together in recent years—among others, this includes automated rig floors and automated rotary steerable systems (RSS)—we have not seen a truly automated rig as outlined above. And few of those attending the meeting expressed optimism that such a development is within reach. “We are not trending toward hitting this vision in 2025,” said Esben Thorup, who was speaking from the perspective of an offshore drilling contractor. “We see pilot projects heading in the right direction, but wide adoption of automation is not happening.” Thorup is the head of digital innovation with Maersk Drilling (and soon to be Noble Corp. upon the impending finalization of a $3.4 billion merger announced in November 2021). He was one of several panelists tapped to lead the four focus groups and offer back to the entire gathering some key points raised during those discussions. For Thorup, the biggest thorn in the side of drilling automation is the business case, or lack thereof. “We would absolutely love to put automation systems on all of our rigs,” he said while noting that some automated components have been deployed on Maersk’s rigs. “But we are not necessarily being rewarded often.” Dan Hoffarth, CEO of onshore contractor Citadel Drilling, led another group and seemed to echo his offshore counterpart in asking the big question of the day: “Does our business model work as individual companies?”

Hard Times in Canadian Oil Could Be Useful Experience

Combine a pandemic, plunging oil demand and prices, and a deep recession, and then consider how it may change things. It is not a question Steve MacDonald can answer, but the chief executive officer for Emissions Reduction Alberta (ERA) said it can be a useful way to get people to consider how things can change in un expected ways. “If you said to someone 4 months ago that oil could go to negative prices, they would say, it’s not going to happen. The range of what could happen is much wider now,” he said. A recent decision by the $1-trillion Norwegian Wealth Fund to exclude four major oil sands companies saying they have “unacceptably high greenhouse emissions” shows the need for change. The headlines in Canada have been harsh - the rising death toll from COVID-19, oil prices flirting with zero, job cuts, and the slow and unpredictable timeline to normal life. “Everything you’re hearing is true. It’s bad,” said Darcy Spady, but the 2018 SPE president is quick to add, “I see a ray of sunshine.” There is a connection between the bright and the dark sides, and it is forcing leaders from both inside and outside the industry to take a hard look at what works and what does not. “The pandemic has merely accelerated the disruption that was already occurring in Canada’s oil and gas sector,” wrote Kevin Krausert, the president and chief executive officer of Beaver Drilling, in an essay in a national newspaper, The Globe and Mail. The essay addressed a long-term future in which the industry undergoes fundamental changes, ranging from research into ways to make hydrogen fuel from gas to drillers digging geothermal wells to provide renewable energy. But at the moment, it is difficult to get the attention of decision makers about the future. “It is hard to focus on anything but the here and now. Where the next dollar is coming from rather than from 3-10 years from now,” said Mark Scholz, president of the Canadian Association of Drilling Contractors. Staying Alive The dramatic drop in oil demand and prices can kill jobs, companies, and ideas. MacDonald sees that threat firsthand. “Liquidity is an issue for everybody, cash flow has been a challenge, the ability to secure investors,” are all issues now affecting those trying to scale up promising ideas. Soon after the economic impact of the sweeping limits that were imposed to slow the spread of COVID-19 became apparent, Emissions Reduction Alberta (ERA) changed its policy to allow increases in progress payments to companies during this period when cash is hard to come by and when some lenders are delaying the release of loan funds, MacDonald said. By reducing the amount of money held back from progress payments, ERA expects to provide 74 companies with $10 million more in cash in the near term. The payments may help client companies pay some bills at a time when they are struggling to line up funding and customers for the large-scale tests needed to prove ideas that worked on a smaller scale.

ПЕРСПЕКТИВЫ РАЗВИТИЯ БУРОВОГО СЕРВИСА В РОССИИ

The article contents a short analyses of Russian drilling market as a segment of oilfield services including its launch history. Basic trends dominated in the technologies and the drilling methods during last years are counted. Noted, that the sanctions of 2014-2016 have had a negative influence for the Russian oilfield services market together with oil exploration limits because of OPEC+ agreement. The mentioned factors influences on drilling business as follows: oil companies started to increase their own oil-and-gas supply having a good effect on the drilling capacity to use. Meanwhile the conditions of the independent drilling contractors for working become much harder because of free-market reduction and a limited access to borrowed capital. As a result, it`s highly likely: finance crisis among the average and small independent drilling contractors; oilfield services consolidation by the large oil companies; “freezing” of drilling market prices. There`re possibilities for the independent drilling contractors as follows; the output of the related oilfield sectors for integration of services; unification; quality improvement and import substitution.

ГРАФИЧЕСКИЙ МЕТОД ВЫБОРА БУРОВЫХ ДОЛОТ

Актуальность исследования обусловлена необходимостью выбора перспективных буровых долот на стадии проектирования технологии бурения. Это направление является ресурсосберегающим, минимизирующим объем промысловых испытаний при поиске оптимальных технологических решений. Цель: разработать уточненную методику выбора буровых долот по статистическим данным о показателях механических свойств горных пород. Объекты: идентификация буровых долот различных фирм и их выбор в соответствии со статистическими характеристиками механических свойств горных пород. Эти вопросы слабо изучены и вызывают затруднения при проектировании режимов бурения скважин. Методы: графоаналитическое изучение соответствия типов буровых долот прочностным характеристикам горных пород, определяемым методом одноосного сжатия и методом статического вдавливания штампа с плоским основанием. Результаты. Для идентификации долот различных изготовителей Международная ассоциация буровых подрядчиков (МАБП) разработала единую классификацию в кодах МАБП. Для отечественной практики возникла дилемма: горные породы охарактеризованы твердостью горных пород по штампу и в категориях, а долота – прочностью горных пород при одноосном сжатии и в кодах МАБП. Предложен переход к показателю прочности горных пород, выраженному в кодах МАБП долота. Это обеспечивает единство характеристик как для долот, так и для горных пород. Соответственно предложены номограммы для выбора долот по статистическим величинам прочности горных пород в кодах МАБП, рассчитанных с надежностью 0,95. Показано, что можно аналогично выбирать долота и при представлении твердости горных пород в категориях. В случае лопастных алмазно-твердосплавных долот их выбор распадается на два этапа: выбор типа вооружения в соответствии с прочностью горной породы в кодах или твердостью в категориях и расчет числа лопастей долота, которое зависит как от прочностных характеристик горной породы, так и от диаметра долота. Для упрощения выбора долот предложено характеризовать буримость выделяемых интервалов бурения не словесно (мягкие, средние и т. д.), а их статистическими характеристиками в кодах МАБП или в категориях буримости с заданной вероятностью.

Real-Time Analytics Improves Process Safety in a Drilling-Contractor Operations Center

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper OTC 28824, “Operational and Safety Improvements of Applying Real-Time Analytics in a Drilling-Contractor RTOC,” by A.L.F. Madaleno, S.L.S. Neto, L.A. dos Santos, and C.A.L. de Oliveira, QGOG Constellation, prepared for the 2018 Offshore Technology Conference, Houston, 30 April–3 May. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission. Digitally enabled collaboration between operators and service companies is driving significant improvements in process safety in the upstream oil and gas industry. However, drilling contractors generally have been considered only the owners of the systems that generate part of the surface drilling data and, as such, have not been engaged in the development of real-time analytics tools. The role of a real-time operations center (RTOC) with a drilling contractor is itself a new factor. This paper explains how an ultradeepwater drilling contractor is applying real-time analytics and machine learning to leverage its RTOC to improve process safety and performance. Introduction The increasing availability of digital drilling data and the emergence of reliable communication between offshore rigs and well operators’ offices enabled a proliferation of RTOCs in the 2000s, spawning a collaborative environment between well operators and service companies that enabled enhanced support and optimized use of expert resources to improve process safety and operational efficiency. Drilling contractors generally were not engaged in developing the real-time analytics tools for the RTOCs. One consequence is that the majority of RTOC software solutions are only appropriate for wellsite information transfer standard markup language (WITSML) data visualization, or they feature embedded tools for well operators and service companies focused on drilling efficiencies but the data and models they use are not accessible to the rig operators. Essential aspects of process safety and operational performance, such as procedural discipline and critical equipment health, can be addressed by drilling contractors in real time if appropriate resources are in place. The contractor’s RTOC has enhanced process safety and surveillance after moving to an approach in which drilling engineers, assisted by software developers with robust experience in real-time data analytics, began writing automated operation-identification and problem-detection algorithms. The cooperative work allowed the creation of tools adapted to the company’s needs and provided a streamlined process to implement, customize, and repair these tools over time. During the planning phase, it was agreed that initial developments should be grouped into six important dimensions that strongly influence the overall process safety and operational performance of the rig. The contractor applied real-time analytics and machine learning to identify and alert RTOC engineers of abnormal situations automatically. The detection of the abnormal situations by RTOC engineers and the comparison of the standard by which various drilling crews react to them feeds a lessons-learned data base, which, in turn, sustains the procedural advancement initiatives, ensuring continuous improvement.

Influences of bit profiles on possible fracture modes

Abstract The influence of different bit profiles on possible fracture modes was investigated using Finite Element Method. The International Association of Drilling Contractors (IADC) classification was used to design 14 types of profiles. The formation model was built, with given bit size, formation properties, meshing method and boundary conditions, etc. Moreover, the pseudo-static state and mass scaling were used to reduce the simulation time and increase the simulation accuracy. The simulation results showed that, for nine common bit profiles, larger cone height led to larger area of high stress zone, and the gauge height was not apparently related to the stress generated. When the gauge height decreased, the high stress zone turned from the nose and center to the gauge zone. For the non-common bit profiles, the convex bit produced larger high stress field, and the pilot section bottom of bicentre bits had concentrated stress. Fractures were created in the gauge zones and noses, and the bits with larger cone height and gauge height induced longer vertical fractures. The flat and convex bits did not generate longer vertical fractures. The bicentre bit can hinder the vertical fractures in the gauge zone, but enables the horizontal fractures easier. The bit with intermediate reamer has less damage to sidewall.

Technology Update: Retrofitting MPD Systems to Deepwater Rigs Aids Drilling, Efficiency, and Process Safety

Technology Update The unique properties of deepwater formations pose significant challenges to the capabilities of conventional drilling rigs. By retrofitting rigs with automated drilling systems, including managed-pressure drilling (MPD) equipment, operators and contractors in global deepwater basins can optimize efficiency and economics while maintaining the level of safety that the industry and regulatory community have mandated for this high-stakes arena. MPD, an adaptive drilling process that actively controls annular pressure throughout the wellbore, is increasingly being integrated into the risers of existing deepwater drilling vessels (Fig. 1). It is the cornerstone of an automated well-control strategy that augments and enhances standard well-control protocols. The technique provides distinct drillability, efficiency, and process safety benefits in deepwater environments. It addresses the higher level of priority that the industry has placed on process safety, which largely involves the ability to accurately and actively monitor and control operations while drilling. Long used in land and shallow-water drilling, MPD-ready rigs are proving their value in deepwater operations by delivering a reliable level of automation and process control when the risk of a well-control incident is highest. Fluctuations in wellbore pressure often create drilling hazards that result in lost circulation, kicks, and other problems that can significantly increase rig time and cost, or lead to catastrophic well-control incidents. An automated MPD system installed onto a deepwater semisubmersible rig or drillship can effectively monitor and maintain the annular hydraulic pressure profile by applying common MPD variants, such as constant bottomhole pressure (CBHP) and pressurized mud cap drilling (PMCD). The ability to continuously monitor various wellbore parameters—particularly those related to downhole pressure—while drilling and making connections also enhances personnel preparedness by serving as an extra set of eyes to supplement those of less-experienced drillers. While expanding the drilling envelope and monitoring wellbore pressure profiles, an MPD system that provides automated advanced flow detection, including early kick detection, also reduces the risks of human intervention by mitigating the possibility of gas in the riser.

Guest Editorial: Isn’t It Time for Our Own Spielbergian “Idea Summit”?

Guest editorial Three years before the 2002 release of his science fiction film Minority Report, director Steven Spielberg brought together an ad hoc think tank to help him realistically imagine how the future might look in 50 years. More than a dozen visionaries and futurists came together for the 3-day event, an “idea summit,” which proved surprisingly prescient. Several intelligent technologies envisioned in the film have since been developed—including biometric iris scanners, robotic insects, crime prediction software, multitouch interfaces (you probably have one in your pocket or purse), and autonomous or self-driving cars. At almost 2 years into the oil industry downturn, I believe now is the ideal time, a pivotal moment, to come together for our own “idea summit” and begin to realistically imagine the future so that we can respond to the “upturn” in the oil and gas industry when it arrives, as it inevitably will as we have witnessed in the past cycles. The seventh SPE Intelligent Energy International Conference & Exhibition will meet for 3 days this September in Aberdeen to consider how we can take emerging digital technologies, big data analytics, and intelligent and autonomous systems to create our own future. This will enable us both to survive our current challenges and to thrive in the years to come. Consider the difference between invention and innovation. Invention develops new ideas and concepts; innovation combines existing elements and applies them in new ways. Today we need innovation to take advantage of the technological inventions that we already have, and we need inventions to sustain the future. Of course, we also need to leverage human potential, processes, and organizational ingenuity. To shape this future vision, we will bring together the industry’s brightest scientists, engineers, and visionaries, as well as executives and decision makers who can implement new corporate strategies and business models that will catalyze technological and organizational changes. This conference is organized to enable us to engage in candid conversation, ask one another hard questions, dream out loud, and open ourselves to fresh possibilities. Take, for example, the application of digital technology in my area of expertise, drilling: I believe one way out of the current downturn to a stronger future is to embrace digital innovation and new levels of automation. I’m not alone. Last fall, a survey conducted at the International Association of Drilling Contractors Advanced Rig Technology Conference indicated that many of its members believe now may be the best time to adopt new technology. Forty percent said a down market encourages automation. Another 38.5% agreed, as long as automated processes are properly deployed to meet specific operator requirements. Only 17% felt a down market discourages automation, largely because companies cannot afford new investments. This would not be the first time the drilling industry has innovated in a downturn to profit in the upturn. During a previous downturn—the oil price collapse of 1998—one major contractor developed next-generation, semi-automated land drilling rigs. Even charging a premium coming out of the downturn, these high-tech rigs lowered the drilling cost per foot by nearly “two-thirds.” They consistently drilled record wells. A second effect, revealed by a Schlumberger study several years later, found that downhole tool reliability improved almost “threefold” on these rigs. While it took tremendous courage to innovate in such an economic environment, ultimately it paid off, not just for one service provider, but for the industry as a whole.

A risk management approach to safe mooring systems in Australia

In March 2015, during cyclone Olwyn, a mobile offshore drilling unit (MODU) experienced a mooring failure and loss of position event. The MODU was blown some three nautical miles off location in the vicinity of subsea and surface infrastructure. There are serious safety, environmental, financial, and reputational risks that can be presented by a loss of mooring position. In response, NOPSEMA hosted a workshop with members of APPEA, the International Drilling Contractors Association (IADC) and with mooring contractors with a view to collectively improve the management of risks associated with the mooring of MODUs in Australia’s tropical waters, both in the short and longer term. Following this workshop, NOPSEMA issued an Information Note for the 2015/16 cyclone season, describing the regulators’ expectations of industry duty holders in respect of MODU mooring system management. At the same time, APPEA’s Drilling Industry Steering Committee (DISC) members aligned on the key principles underpinning a MODU mooring system approach. In late 2015, the APPEA DISC members commissioned a working group to develop a guidance framework for MODU mooring management in Australian tropical waters. DISC aims to work closely with industry partners such as IADC and specialist mooring contractors in the development of this framework. DISC has tasked the working group to have the guidance framework ready for the 2016/17 cyclone season, and for presentation at the 2016 APPEA Conference. The completed case study, presented at the APPEA Conference, provides an excellent example of a goal-setting and continuous improvement regulatory regime working as designed and intended.

Drilling-Systems-Automation Roadmap: The Means To Accelerate Adoption

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 173010, “Drilling-Systems-Automation Roadmap: The Means To Accelerate Adoption,” by John P. de Wardt, SPE, De Wardt and Company; John D. Macpherson, SPE, Baker Hughes; Mario Zamora, M-I Swaco; Blaine Dow, SPE, and Slim Hbaieb, SPE, Schlumberger; Robin A. Macmillan, SPE, National Oilwell Varco; Moray L. Laing, SPE, SAS Institute; Amanda M. DiFiore, QinetiQ North America; Calvin E. Inabinett Jr., SPE, Aerojet Rocketdyne; and Mark W. Anderson, SPE, Shell International E&P, prepared for the 2015 SPE/IADC Drilling Conference and Exhibition, London, 17–19 March. The paper has not been peer reviewed. 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 (DSA) 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 DSA technology in both the short and the long term. The roadmap uses a well-known template developed by Sandia National Laboratories to provide a mechanism to forecast how DSA developments can progress. Introduction Despite the well-known potential benefits of drilling automation, there is a perception by some that automation in other major industries has outpaced that achieved in drilling. Issues and barriers associated with automation in complex drilling operations coupled with a fragmented business environment have been reported. A concerted cross-industry technology-roadmap initiative was launched in June 2013 driven by the need identified at an industry workshop. This independent initiative supported by an all-volunteer committee became affiliated with three organizations with members interested in this technology development: SPE, the International Association of Drilling Contractors, and the Association for Unmanned Vehicle Systems International. A technology roadmap is a detailed, structured document that articulates the clearly defined objectives and the technology resources needed to meet specific long-term goals. It differentiates various technology elements and ties them together though a coordinated timeline identifying when and how business value can be realized. The process developed by Sandia National Laboratories was the most appropriate example for adoption for the DSA-road-mapping process.

Deepwater Well Control: Training and Education in a State of Transition

Well Control Well control training programs for deepwater drillers and key rig personnel are undergoing a major overhaul that has been years in the making. It is hoped that introducing new well control courses and exams will address recent incidents and new technologies. The overarching goal is to better prepare drillers for the challenges of deepwater wells. The changes were made by the industry’s two largest well control certification bodies: the International Well Control Forum (IWCF) and the International Association of Drilling Contractors (IADC). The IWCF began rolling out new programs last year and is continuing to add new changes. The IADC introduced its updated program in April and also said it has more work to do. The IWCF’s new program is based on the recommendations made in a 2012 review by the International Association of Oil and Gas Producers (IOGP) that found the certification process needed improvements in a number of key areas. The report, which serves to redefine well control training, was drafted in response to the 2010 Macondo subsea blowout and the lesser known Montara blowout that occurred offshore Australia a year earlier. The IADC began reviewing its program in 2009 and said it accelerated the process after Macondo. To address shortcomings, the organizations have added a long list of new courses and requirements that seek to strengthen a driller’s ability to deal with well control issues. Some of the new topics cover physical barriers, kick prevention and detection, shut-in procedures, and well kill procedures. Additional focus has been placed on the instructors through new “train-the- trainer” and assessor training programs. The IWCF also conducted an internal audit of its accredited assessors and instructors. “As a result of the audit process, IWCF has suspended assessors and instructors at training centers who are not competent in conducting practical assessments or delivering courses to the required standard,” said Antony Quin, general manager of the IWCF. In June, the group also appointed its first chief technical officer, Dave Conroy, previously of Schlumberger. On the organization’s website, Conroy said he plans to make more “significant changes.” A Time for Change For some veteran deepwater drilling experts, the changes are long overdue. Aside from a few exceptions, they argue that because the industry’s training and education programs have failed to reflect deepwater challenges, rig crews and drillers have been less prepared. They say this deficiency has led to major cost overruns and delays in deepwater projects around the world.

Getting to Grips with Human Factors in Drilling Operations

Management Since the events at Montara in late 2009 and Macondo in 2010, the exploration and production industry has undergone a substantial change in culture and regulation. However, investigations still tend to focus on technological and managerial deficiencies rather than probing deeper into the causes of human error. Nonetheless, there is a growing desire to understand human and organizational factors that influence potential process safety incidents during drilling and completion operations. The topic of human factors as a contributor to well-control incidents was first discussed in 1992 by Paul Sonneman at an International Association of Drilling Contractors well-control conference in Houston (Sonneman 1992). The subject subsequently received attention from the UK Health and Safety Executive (Wilson and Stanton 2004), which assessed five human factors techniques relating to offshore personnel in combination with interviews of key personnel. Both of these studies were preceded by a 1990 analysis of the effect of human factors in stuck-pipe incidents in the US Gulf of Mexico. More recently, the topic has forced its way firmly onto the agenda in the wake of the 2010 Macondo accident and as a result, industry organizations have published a number of relevant texts. In 2014, SPE published a white paper (SPE, 2014) covering a wide spectrum of human factors issues and made a number of recommendations to politicians and the industry at large. The International Association of Oil and Gas Producers (OGP) published Report 460 (OGP 2012) on the cognitive issues relating to process safety, Report 501 (2014a) on recommendations for the implementation of training in nontechnical skills, and Report 502 (2014b), which proposed recommended practices for such training programs. The Energy Institute in the UK published its guidance on crew resource management, which made the case for such training based on the experience in other high-hazard industries, such as aviation, rail, nuclear, and mining (Energy Institute 2014). The North Sea Offshore Authorities Forum (NSOAF) carried out a joint human and organizational survey of the factors relating to well-control preparedness (NSOAF 2013). The common thread throughout all of these publications and activities is that they are directed toward a narrow audience of human factors specialists who are concerned with researching human-factors-related issues or setting up of training programs. However, there has been little attempt to communicate the central ideas to those who deal with the problems of human error in all its forms on a daily basis; in particular, the drilling operations community where, in the recent past, some of the major accidents have occurred. To address this, SPE held a workshop titled “Getting to Grips with Human Factors on Drilling Operations” in London in October 2014 to define and clarify the underlying ideas about human factors related to the drilling community. The purpose of the workshop was primarily to expose ideas and engage with a more hands-on and operational audience of drilling operations professionals. The main points from the presentations and ensuing discussions are summarized here and references are provided for further reading. Practical tools and insight that can be applied in day-to-day operations are also presented.

Managed-Pressure Drilling - A Solution for Challenging Wells in Vietnam

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 165775, ’Managed-Pressure Drilling - A Solution for Drilling the Challenging and Undrillable Wells in Vietnam and Southeast Asia,’ by Ben Gedge, SPE, Harpreet Kaur Dalgit Singh, Elsofron Refugio, and Bao Ta Quoc, Weatherford Asia Pacific, and Nguyen Viet Bot, PVD Well Services, prepared for the 2013 SPE Asia Pacific Oil and Gas Conference and Exhibition, Jakarta, 22-24 October. The paper has not been peer reviewed. Managed-pressure drilling (MPD) has been used in Vietnam since 2007 to address a number of drilling and reservoir challenges. The main application of MPD has been to overcome the challenges of granite-basement, fractured and vugular carbonate, high-pressure/ high-temperature (HP/HT), and overpressured clastic reservoirs. This paper examines the procedural approaches of MPD, including constant bottomhole pressure (CBHP), equivalent-circulating-density (ECD) management, early kick detection, and pressurized-mud-cap drilling (PMCD). MPD Techniques and Applications The International Association of Drilling Contractors (IADC) defines MPD as “an adaptive drilling process used to precisely control the annular pressure profile throughout the wellbore. The objectives are to ascertain the downhole pressure environment limits and to manage the annular hydraulic pressure profile accordingly. MPD is intended to avoid continuous influx of formation fluids to the surface. Any influx incidental to the operation will be safely contained using an appropriate process.” MPD Variants The definition of MPD covers a wide range of variations and applications, but the most commonly used among them are the PMCD and CBHP variations (Fig. 1). PMCD as defined by the IADC as “a variation of MPD that involves drilling with no returns to surface and where an annulus fluid column, assisted by surface pressure [made possible with the use of a rotating control device (RCD)], is maintained above a formation that is capable of accepting fluid and cuttings. A sacrificial fluid with cuttings is accepted by the [lost] circulation zone. This technique is applicable for cases of severe [lost] circulation that preclude the use of conventional wellbore construction techniques.” The PMCD variant of MPD allows conventional drilling operations until losses are experienced and has been used successfully to drill through fractured and vugular carbonate formations where circulation losses can be simultaneously sudden and severe. This allows drilling to target depth despite massive losses being encountered. The CBHP variant of MPD involves the ability to maintain a constant bottomhole pressure (BHP), especially when drillpipe connections are made and the rig mud pumps are turned off. In this instance, the MPD system exerts a backpressure value that corresponds to the frictional pressure loss. This backpressure is slowly relieved once the connection has been completed and the rig mud pumps resume operation. However, given the sophistication of current MPD-control systems, BHP not only can be kept constant but also can vary to ascertain the downhole-pressure-environment limits and allow drilling personnel to manage the annular- hydraulic-pressure profile accordingly, thereby making the drilling operation more effective and more efficient.

Drilling Performance Is a Function of Power at the Bit and Drilling Efficiency

This article is a condensed version of paper IADC/SPE 151389, presented at the 2012 International Association of Drilling Contractors (IADC)/SPE Drilling Conference and Exhibition, held in San Diego, California, USA, 6-8 March 2012. Understanding of basic drilling mechanics has been greatly enhanced by the use of today’s sophisticated data acquisition systems for both surface and downhole drilling data. These systems have also helped in identifying major dysfunctions—particularly, harmful downhole vibrations. Various methods are used to optimize drilling practices, including monitoring efficiency indicators, such as mechanical specific energy (MSE), as well as preventing harmful vibrations by adjusting drilling parameters real time. However, focusing on the efficiency of components and the prevention of dysfunctions is only a partial solution. It is also necessary to focus on the magnitude of mechanical power delivered to the bit, as that defines the capacity of the system and directly affects efficiencies, operating practices, and performance. The paper shows how the power at the bit and drilling efficiency vary as a function of drillstring and bottomhole assembly (BHA) configuration, bit selection, and drilling parameter. Field examples illustrate the magnitude of parasitic losses caused by well geometry and the downhole environment. In many cases it is striking to learn how little power is left for the drill bit, which in the end dictates the potential rate of penetration (ROP) and thus the cost per foot and economics of the drilling process. Particular emphasis has been put on new and intuitive ways to visually display the power at the surface and downhole. These make it possible to quantify system limits and identify key dysfunctions in one simple graph that can be used in real time as well as in both pre- or post-well analysis. Better understanding of the entire drilling system and the functional relationship of its parts can be a strong driver for both short- and long-term improvements in system design, drilling practices, and bit selection, ultimately resulting in higher productivity and lower well construction cost. Introduction The oil and gas industry, unlike others, seldom focuses on power requirements for the rotating drilling system and their effect on performance and efficiency. This might be explained in part by the fact that for about 100 years roller cone bits have been the industry’s preferred drilling tool. Roller cone bits require relatively little torque due to their low aggressiveness, and, due to the limited load capacity of the bearings, they act as perfect torque limiters. The rotating power system therefore utilized only a small fraction of the total installed power of a rotary drill rig; lack of power was not considered a limiting factor.

Operator Recommendation for a Uniform Dull-Grading System for Fixed-Cutter Hole-Enlargement Tools

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 139870, ’Operator Recommendation for a Uniform Dull- Grading System for Fixed-Cutter Hole- Enlargement Tools,’ by L. Ulvedal, SPE, Statoil, and J.D. Enterline, SPE, D. Scott, SPE, S. Radford, SPE, J. Clinkscales, L. Shale, and M. Croxton, Baker Hughes, prepared for the 2011 SPE/IADC Drilling Conference and Exhibition, Amsterdam, 1-3 March. The paper has not been peer reviewed. To standardize and permit the accurate dull grading of fixed-cutter bits, an International Association of Drilling Contractors (IADC) standard system was defined and implemented in 1987, with revisions in 1992. With hole enlargement becoming a fast-growing sector in the drilling industry, there is a greater need for an accurate and uniform dull-grading system for fixed-cutter hole-enlargement tools. Through collaboration between an operator and a bit manufacturer, a new dull-grading protocol is proposed to characterize hole-enlargement-tool dull conditions better. Adoption of this new dull-grading system for fixed-cutter hole-enlargement tools would facilitate an industrywide standard to communicate dull conditions more accurately. Introduction Because the oil and gas industry is familiar with the current IADC fixed-cutter-bit dull-grading system, service companies and operators often use a variation of this system to grade hole-enlargement tools. With these tools becoming increasingly advanced and as more designs are introduced, a new dull-grading system needs to be developed to evaluate these tools’ unique features and applications more consistently. The system to grade reamers uniformly must allow those without visual reference to the tool to have an accurate description of the dull condition. The first objective is to establish a means to evaluate reamer dullness. The second objective is to provide uniformity and simplicity. This uniformity should be in use of similar terminology, format, and scales for grading reamer dullness. To gain industry acceptance, the new grading system should be consistent with current bit formats and provide adequate detail of the subject reamer. The simplicity will come from the recommendation to use the current dull-grading system established for bits, with minor additions for use with reamers. History Hole enlargement has been used in the oil and gas industry for nearly a century, with initial tools designed as fixed-blade concentric tools used to enlarge or clean previously drilled boreholes. These tools have evolved to include bicenter, eccentric, and concentric-expandable tools, each with specific design aspects. Bicenter and eccentric tools were developed because of a need to expand boreholes below a restriction, such as a blowout preventer or casing. These tools enlarge boreholes to prevent issues with sloughing, swelling, and tectonically stressed formations. Eccentric reamers are fixed-blade tools with an offset cutting structure used to enlarge the borehole by centralizing the rotation of the tool body and forcing the eccentric cutting structure into the formation to enlarge the borehole. Bicenter bits are single-piece tools combining a pilot bit with eccentric-reamer blades.

Digital Technology, Integrated Disciplines Driving Changes in Service Sector

Evolving deepwater operations, the emergence of unconventional plays such as shale, and the increasing digitization of the oil field are driving the evolution of the oil and gas industry service sector and changing the way service companies posture themselves in the global market. “Back in the 1970s and 1980s, service companies were very specialized,” said John B. Parry, principal energy analyst with the consultancy IHS Herold. “What you have been seeing is a merger of a lot of these disciplines.” Merger and acquisition (M&A) activity in the service sector was robust last year with takeovers involving several venerable names, including Smith International, BJ Services, and Boots & Coots. Contributing to this trend are operators that like to have a “one-stop-shop” business experience on big projects—to be provided with as many services as possible from one company, Parry said. And service companies are learning from and growing through their acquisitions, he added. “Even Schlumberger is going to learn from Smith. Baker was a huge supplier of services downhole, but they did not have a workover. So now, they have BJ. It makes them stronger financially, and reduces their risk in any one given area,” Parry said. Minimizing Risk Service companies are growing larger to share more risk, and to have more discipline and technology to minimize risk, Parry said. Current merger and acquisition trends in the service sector reflect the increasing need for integrated service disciplines, consolidated geographical operations and fortified financial posturing. For example, a service company that only specialized in Gulf of Mexico jackup rigs would be in big trouble right now because of the recent drilling moratorium, so a geographical balance is important just as is diversity in service, he said. An IHS Herold report titled “Review on the Oil Field Services Sector” predicts a healthier growth outlook for oil and gas service companies this year after being hard hit by the Gulf of Mexico drilling moratorium in 2010. The review compared oil company financial performance against performance for service companies and off-shore drilling contractors. The service sector still faces challenges. Even with the moratorium lifted, the return to drilling has been slow, which has fed a decline in rig utilization rates while new-build rigs continue to enter a sluggish market, the report said. And the service sector is facing some of the same issues as operators. “The industry will be challenged by more remote operations, deeper waters, more difficult logistics, increasingly complex geological settings, and greater degrees of temperature and pressure,” Andrew Gould, chief executive officer of Schlumberger, said in a recent speech. At a recent Bank of America/Merrill Lynch Global Energy Conference, Baker Hughes discussed its geomarket management teams’ more holistic view of the market. The company’s priorities are to improve international profitability, eliminate inefficiencies, and to revise its geomarket structure with particular attention to deepwater, unconventional, conventional and alternative energy market segments.

Managed Pressure Drilling 101: Moving Beyond “It’s Always Been Done That Way"

Tech 101 - The basics of managed pressure drilling. In his book The Nature of Technology, W. Brian Arthur remarked, “The story of this century will be about the clash between what technology offers and what we feel comfortable with.” Although Arthur meant this in technology’s general sense, the same can be said about the clash between underbalanced drilling (UBD) and managed pressure drilling (MPD). The International Association of Drilling Contractors (IADC) defines UBD as follows: A drilling activity employing appropriate equipment and controls where the pressure exerted in the wellbore is intentionally less than the pore pressure in any part of the exposed formations with the intention of bringing formation fluids to the surface. While the benefits of UBD technology include reservoir damage prevention and increases in production and rate of penetration, users can experience discomfort—mainly from operational and safety standpoints, especially offshore—because the well continuously flows to surface while drilling. It can also be expensive, requiring more complex modeling and prediction of compressible drilling fluids behavior during operation. Furthermore, it is not always possible to maintain a continuously underbalanced condition and, since there is no filter cake in the wellbore, any period of overbalance might cause severe damage to the unprotected formation.

Alternative Initial Responses to Kicks Taken During Managed-Pressure Drilling

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 128424, ’Evaluation of Alternative Initial Responses to Kicks Taken During Managed-Pressure Drilling,’ by Majid Davoudi, SPE; John Rogers Smith, SPE; Bhavin M. Patel, SPE, and Jose E. Chirinos, SPE, Louisiana State University, prepared for the 2010 IADC/SPE Drilling Conference and Exhibition, New Orleans, 2-4 February. The paper has not been peer reviewed. An industry-supported research project completed its evaluation of alternative initial responses to kicks taken during the constant-bottomhole-pressure (CBHP) method of managed-pressure-drilling (MPD) operations. This first phase was intended to provide a basis for comprehensive, reliable well-control procedures for MPD operations. Three responses were concluded to have general application: increasing casing pressure until flow out (Qout) equals flow in (Qin), shutting in the well, and adapting an MPD pump-shutdown schedule to detect and shut in low-rate kicks. Selection of the most practical response depends on well conditions and the equipment being used. Potential advantages of and constraints on the use of these responses were summarized. Introduction MPD is an evolving technology used to address drilling problems encountered when using conventional, hydrostatically overbalanced drilling methods. MPD is defined by the International Association of Drilling Contractors (IADC) as a “drilling process used to control precisely the annular pressure profile throughout the wellbore.” The definition also points out that an influx of formation fluids (i.e., a kick) “will be safely contained using an appropriate process.” Establishing the basis for identifying an appropriate process or processes was the focus of this study. CBHP Method of MPD. This method keeps the wellbore pressure relatively constant at a selected depth. This constant wellbore pressure is achieved by adjusting the surface pressure on the annulus to offset changes in the wellbore frictional pressure losses as the pump speed is varied or stopped, such as when making connections. The ability to adjust the surface pressure on the annulus is provided by a rotating control device (RCD), such as a rotating control head, by closing the annulus and directing flow through an adjustable drilling choke. Therefore, the CBHP method of MPD avoids the wellbore-pressure fluctuations that occur when starting and stopping pumps in conventional operations. Consequently, it allows drilling within a narrower “window” between fracture and pore pressures than is safe or practical with conventional methods.