Deepwater wells are the most complex and challenging operations for today's petroleum workforce. These challenges push the limits of technology requiring high level personnel competencies and stringent safety requirements. Robust and consistent procedures aid in implementing reliable operational execution. When complex operations include multiple drill ships and TLPs, and when these activities are mirrored by separate support teams of engineers and operations there are opportunities for varying procedures, content, format, and technology applications. This misalignment evolves over time, based on individual preferences, lessons learned, and varying procedures from different service providers.
This paper discusses the efforts and outcomes of bringing standardization to Deepwater operations in the Gulf of Mexico (GOM) and to Shell's broader global Deepwater organization (DWO). Standardization efforts include full End-to-End well delivery from engineering design documents, recommended/best practices, operational procedures, workflow processes, after-action-reviews, knowledge sharing, and refreshing standards as required.
Ensuring a learning loop process is in place and actively used is a key element in keeping standard documents evergreen and has the overarching goal of preventing repeat failures and NPT events. An additional benefit is the ability to deliver documents with structured content, aligned format and standard language to both the operations teams and service providers.
The formation of a core team and central department has driven global standards, active sharing of learnings across all Deepwater business units, opened communication lines with areas previously siloed due to location, reduced cycle time for the engineering teams in re-creating procedures and demonstrated sustainable reductions in operational costs.
This seminar will teach participants how to identify, evaluate, and quantify risk and uncertainty in everyday oil and gas economic situations. It reviews the development of pragmatic tools, methods, and understandings for professionals that are applicable to companies of all sizes. The seminar also briefly reviews statistics, the relationship between risk and return, and hedging and future markets. Strategic thinking and planning are key elements in an organisation’s journey to maximise value to shareholders, customers, and employees. Through this workshop, attendees will go through the different processes involved in strategic planning including the elements of organisational SWOT, business scenario and options development, elaboration of strategic options and communication to stakeholders.
Decisions in E&P ventures are affected by Bias, Blindness, and Illusions (BBI) which permeate our analyses, interpretations and decisions. This one-day course examines the influence of these cognitive pitfalls and presents techniques that can be used to mitigate their impact. Bias refers to errors in thinking whereby interpretations and judgments are drawn in an illogical fashion. Blindness is the condition where we fail to see an unexpected event in plain sight. Illusions refer to misleading beliefs based on a false impression of reality.
Narwal, Tushar (Petroleum Development Oman) | Riyami, Yaqoob (Petroleum Development Oman) | Rashdi, Mansoor (Petroleum Development Oman) | Abri, Zahir (Petroleum Development Oman) | Sariri, Aisha (Petroleum Development Oman) | Benchekor, Ahmed (Petroleum Development Oman) | Hadhrami, Abdullah (Petroleum Development Oman) | Dsouza, Rylan (Petroleum Technology Company) | Brodie, Alan (Petroleum Technology Company) | Strom, Kyle (Halliburton)
In South Oman, PDO is producing from high Sour Fields (H2S 1-10%) with high reservoir pressures ranging from 50,000 to 100,000kpa for more than 20 yrs. Operating these high sour wells comes with huge challenges and risks, which can easily get escalated to very high levels in case of any integrity issues with the wells. These situations not only provide significant exposure to expensive and risky well interventions but also pose threats to production due to Simultaneous Operations (SIMOPS) issues.
The authors describe case studies where team was exposed to these challenging situations due to integrity failures in two such wells. New technologies were implemented which resulted in restoring the well integrity in a very cost effective manner (cost savings worth millions) and also reduced the HSE risks on the nearby operations. As a result, production was safeguarded (3-4% of Station Capacity) by allowing drilling of new wells and oil deferment from existing wells in the nearby area was avoided.
Diaz, Nerwing (Baker Hughes, a GE company) | Paila, Phalgun (Baker Hughes, a GE company) | Kirby, Cliff (Baker Hughes, a GE company) | Akl, Bassam (Baker Hughes, a GE company) | Mahmoud, Dalia (Baker Hughes, a GE company) | Al Kindi, Rashid Khudaim (ADNOC offshore) | Kasem, Youssef (ADNOC offshore) | Benygzer, Mhammed (ADNOC offshore) | Haddad, Mohamed (ADNOC offshore) | Leon, Vicente (Drilltech Services)
Directional drilling from artificial islands has become a common offshore practice in the United Arab Emirates, looking to minimize footprint while optimizing cost to reach maximum number of targets from a single location. This drilling practice brings some challenges such as torque and drag limitations, which is vital in order to safely reach wells total depth in well profiles with a high departure. The purpose of this paper is to discuss in detail the successful implementation of torque reduction techniques, focused on case histories from an artificial offshore island in the United Arab Emirates.
During the planning phase, Drilling Engineers estimate expected torque and drag for the different sections based on modeling and historical data, this process is key to assess the limitations and initiate the process of evaluating the different torque and drag reduction techniques to be implemented based on the application. The case histories presented in this paper show the successful implementation of proven torque and drag management techniques, such as; well profile optimization, torque reduction subs, deployment of lubricated mud, use of real-time directional data to minimize hole tortuosity, and deployment of Rotary Steerable Systems from top to bottom for improved hole quality.
There are different factors considered in the planning phase that make torque and drag management crucial, but drill pipes torque limitation was the main challenge to overcome in order to reach planned total depth in the case histories discussed in this paper. Wells trajectory and BHA optimization played an important role during the execution phase, as well as the deployment of lubricated mud and torque reduction subs which in conjunction provided an overall surface torque reduction of up to 28%.
The implementation of different torque and drag reduction methods are illustrated with the modeling results and actual drilling data collected during the drilling of these wells. Information and data discussed in this paper can serve as documentation to aid in the planning phase for wells with similar challenges.
The PDF file of this paper is in Russian.
This paper describes the implementation of pressurized mud cap drilling (PMCD) technology, a variant of Managed Pressure Drilling (MPD), a successful technique frequently used on oil and gas fields in Kazakhstan. It also considers the planning phase, operational aspects, and results of drilling with the PMCD technique through challenging formations.
PMCD technology with a rotating control device (RCD) is a form of blind drilling, where the drilling fluid and formation cuttings are not transported to the surface. It is a non-conventional drilling technique designed to maintain annular wellbore pressure to prevent total loss of circulation. A sacrificial fluid (SAC) is injected through the drill string and light annular fluid is pumped down from the annulus to maintain borehole fill and prevent annular gas migration.
Wells in this field have encountered uncontrollable losses while drilling sections of the fractured carbonate. As a result, the application of PMCD technology to meet those challenges was an obvious choice in order to achieve target depth. Conventionally drilling of the 8-in. section resulted in fluid losses of more than 450 m3. Consequently, passing through these challenging zones the rig crew switched from conventional drilling to PMCD. The wells were then successfully drilled using the PMCD method, without any issues or well-control incidents, and planned TD was attained. By enabling the client to reach TD, Weatherford PMCD equipment transformed a previously undrillable well into a potentially valuable asset. This operation demonstrated that PMCD can be a viable drilling technique for future wells in the field.
PMCD technologies included reduced consumption of lost-circulation material (LCM) and reduced loss of mud to the formation, keeping the wells economically viable. The main objectives of these wells were to drill safely and efficiently to target depth (TD), to deliver the wells for production on schedule, reduce non-productive time (NPT), minimize the drilling risks and hazards, and optimize the drilling program.
Most US onshore shale operators work with extremely limited budgets to be profitable in a low margin, low oil price environment. There is a significant emphasis on footage drilled per day, with solutions like better well plans, drill bits, and innovative bottom-hole assemblies (BHA). However, the smaller activities that add up to achieve higher footage per day include weight to weight (W-W) and connection times. The traditional ways to measure these key performance indicators (KPIs) and identify operational inefficiencies are manual, time consuming and after-the-fact.
To increase the overall drilling performance even with proven BHAs, an operator in Marcellus Shale leveraged a web-based application using industry-standard wellsite information transfer standard markup language (WITSML) protocol for automatic real-time drilling performance KPI monitoring and advisory services to focus on standardizing and reducing the W-W time. Weight to Weight time was divided into weight to slip (W-S), slip to slip (S-S) or connection times, and slip to weight (S-W) times to analyze trends and practices during the drilling process. The study focused on average W-W time improvement, and operational consistency on two rigs while drilling 32 wells from seven pads.
During this continuous improvement process, the operator identified best crew performance using automated crew comparison KPIs and disseminated best practices among the crews. At the end of the study, one rig W-W goal attainment rate increased by 50%. The operator also worked with the rig contractor to shuffle the rig crews by including the competent personnel from the most-efficient rig crew to the less-efficient rig crew to accelerate the sharing of best practices. This approach led to a 19% improvement of average W-W time over the course of the drilling campaign, and improved overall drilling performance. The best well was used for benchmarking and updated throughout the drilling campaign for continuous improvement of drilling performance.
Digital technologies combined with existing proven downhole technologies can help identify operational inefficiencies. Operators that use remote operations centers for planning, execution and risk reduction can benefit from real-time monitoring of drilling KPIs by taking timely and proactive measures.
Figure 1—When capital is a limited resource, a bottoms-up approach to budget proposals does not provide a clear view to the optimal suite of projects to fund. This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187162, “People and Process: Integration of Technology and Organizational Alignment for Successful Implementation of a Strategic Capital Investment Portfolio,” by David S. Fulford, Gregory P. Starley, and Michael Berry, Apache; Derrick W. Turk, Terminus Data Science; and James R. DuBois, 3esi-Enersight, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–11 October. The paper has not been peer reviewed. This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187162, “People and Process: Integration of Technology and Organizational Alignment for Successful Implementation of a Strategic Capital Investment Portfolio,” by David S. Fulford, Gregory P. Starley, and Michael Berry, Apache; Derrick W. Turk, Terminus Data Science; and James R. DuBois, 3esi-Enersight, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 8–11 October. The paper has not been peer reviewed.
Although asset model based workflows are not new in digital oil field, drive towards automation is more and more increasing to move from periodic to continuous optimization for improving process and operational efficiencies. Integrated asset model forms the basis for number of well & reservoir workflows and can aid in standardization and automation. Models are heart of number of activities such as surveillance, calibration, optimization and forecasting within asset. These activities are inherent in most of workflows performed by engineers on any project or task. This paper is intended to discuss the best practices based on lessons learned from implementations in large mature brown fields in ADCO where sustaining allowable production, well performance issues, Production reconciliation, facilities bottle-necks & real-time data availability were major challenges.
The corporate asset strategy shall have a vision towards automation and its benefits to organization's strategic objectives. Workflow automation for an asset will depend greatly depends on the objectives from a business process to accomplish and should be bringing maximum value. This must result in tangible impact whilst providing means to start establishing a new mindset. The initial efforts must focus on ‘fixing the basics’ such as mapping of existing detailed workflow steps of a process, identify key data required, thorough gap-analysis, improve data reporting & QA and agree on common definitions before automation takes place. Expectation setting with stakeholders should be done early in process and operations staff need to be involved early to help establish objectives and ensure workflows are adequate to their use. Prototype and phased workflow deployment approach shall be adopted. Engineers need to be given a chance to develop to trust automated system before workflows can be fully automated.
Improving just process efficiency should not be end of goal of automation however engineers should be able to identify optimization opportunities in quick time. Automated model calibration can pinpoint data of poor quality and justify its improvement. Exception based well & facilities network surveillance is a common feature of automation hence rate estimation what if methodologies, validation limits, exception handling, pressure drop thresholds & pre-configuration of multiple operations scenarios shall be thoroughly discussed. Historical data trending in workflows can support decision making and add a value. Workflow and model governance need to be managed efficiently for automation to survive. Coherent and effective management information such as rolling-up of production volumes, deferment, operations KPIs need to be reported as a result of this automation to increase transparency. Agility, scalability and interoperability are key factors and must be supported by automation system.
The authors primarily discuss challenges addressed in workflows deployment, data integration & improvements, capability development and change management mechanism in these implementations.
Established in March of 1986, the National Construction Safety Executives (NCSE) is a group of Executive Safety Professionals from 30 of the top design, engineering and construction firms in the nation. These individuals meet regularly to discuss and share information, ideas, and construction industry best practices.
The NCSE assembled the Future Leaders of Construction Safety (FLOCS) in the fall of 2015. The FLOCS is a group of safety, health & environmental (SH&E) young professionals under the age of 35 who exhibit high potential and an inclination to expand their industry expertise. The NCSE tasked the FLOCS with collecting, reviewing, and sharing SH&E best practices. The project allowed the FLOCS to network with experienced SH&E professionals, and further develop their understanding of SH&E best practices currently deployed throughout the construction industry.
This paper reviews the Future Leaders of Construction Safety SH&E Best Practices Project. The definition of best practice, challenges faced when implementing a best practice, effective persuasion strategies, and advice and recommendations for SH&E young professionals are examined herein.
What Is a Best Practice?
Best practice is a term or expression that has long been used throughout various industries. Organizations often develop, implement, and utilize best practices with the goal of increasing production, reducing costs, and separating themselves from the competition. But what exactly is a best practice? More specifically, what is an SH&E best practice with regard to the construction industry?
The FLOCS interviewed NCSE members in an effort to uncover the true connotation of a best practice. During the interview process, the FLOCS asked, “What is an SH&E best practice?” When this question was asked, many of the members’ responses, though insightful, were not immediate. The FLOCS believe this is because commonly used terms, such as best practice, tend to take on an identity of their own, thus the true definition is forgotten.