This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191437, “ACA Practical Considerations: When Is It Accurate and How Should It Be Used To Improve Reservoir Stimulation,” by O.A. Ishteiwy, SPE, M. Jaboob, and G. Turk, BP; S. Dwi-Kurniadi, SPE, Schlumberger; A. Al-Shueili, SPE, A. Al-Manji, and P. Smith, BP, prepared for the 2018 SPE International Hydraulic Fracturing Technology Conference and Exhibition, Muscat, Oman, 16–18 October. The paper has not been peer reviewed.
The use of diagnostic fracture injection tests (DFITs) for prefracture investigation has become routine in the oil field, particularly for understanding reservoir properties and subsequently optimizing hydraulic-fracture design. A key component of an effective DFIT is an after-closure analysis (ACA) to assess the transmissibility of the formation and allow for effective design. This paper describes a DFIT-analysis program and the suitability of the results from ACAs for use in hydraulic-fracture design.
The Khazzan field is being developed currently and includes multiple gas-bearing formations. The primary development reservoir is the Barik sandstone, which is characterized by permeabilities on the order of 0.1 to 1 md. An additional reservoir under development is the Amin formation, which lies deeper than the Barik and is perhaps more unconventional in nature, with estimated permeabilities an order of magnitude lower than the Barik formation. Both reservoirs require hydraulic fracturing to produce at economically attractive rates and, as such, carry the same sort of challenges to reservoir understanding inherent to all unconventional plays. This was recognized in advance of the appraisal program, and an approach was taken to address these challenges in a more-holistic fashion, encompassing a full suite of data gathering, including surveillance and well testing.
One of the key tools used was DFIT along with associated ACA of the decline to determine reservoir properties. During the appraisal phase, significant rigor was aimed at ensuring high-quality data would be recorded and that an appropriate amount of time would be allocated to monitoring pressure declines to enable valid interpretations. This resulted in the ability to draw a good correlation between data gathered from the ACA operations and data collected from post-fracturing well-test data.
Methods and Process Stimulation and Testing Sequence. The approach taken to stimulate and test the wells in Khazzan was to use a dedicated well-test unit. The overall sequence was as follows:
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 27987, “Subsea-Fiber Wet-Mate Connectors: Achieving the Balance Between Consistent Optical Performance, Product Cost, and Compact Size,” by Elaine Saxton and Helyson Parente, SPE, Siemens Subsea, prepared for the 2017 Offshore Technology Conference Brasil, Rio de Janeiro, 24–26 October. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
As the hunger for data grows, long stepouts become more common, and fiber communication becomes standard, the use of fiber in subsea oil and gas fields is set to increase. While optical loss along fiber itself is low and data-collection possibilities are high, these applications will only be fully realized if wet-mate fiber connectors can achieve high optical performance consistently. Excellent results are achieved with compact design, a modular approach, and an emphasis on cleanliness.
Wet-mate fiber connectors have been on the market for years and are used increasingly in the subsea oil and gas industry. While they have been moderately successful, the technical challenges should not be underestimated. Industry specifications demand high levels of optical performance and extensive qualification programs. The balance between performance and cost of the finished product has always been difficult to achieve.
Subsea fields are seeing longer stepouts, which are suited to using fiber as the key communication network. Furthermore, the subsea industry is seeing an ongoing drive to use fiber sensors in downhole systems (e.g., distributed temperature sensing), allowing greater amounts of data to be transmitted topside. Other applications such as direct-current and fiber-optic distribution and pipe-in-pipe heating are also emerging. For reasons of flexibility and practicality, the wet-mate fiber connector plays an important role in all of these.
The key technical challenges are a mixture of mechanical design, operation and maintenance, and operational environment.
Mechanical Design. The core of a standard single-mode fiber is 9 µm, and it must be completely aligned in every dimension for optical performance to be achieved.
Manufacturing, Operation, and Maintenance. Cleanliness of the optical ferrule faces on every single mate is crucial. Without it, performance is degraded or lost. In the worst case, permanent damage is transferred by a dirty ferrule face mating with a clean one.
Operational Environment. A wet-mate connector is a sealed, oil-filled, pressure-balanced mechanical device that will be handled in harsh topside conditions in extreme temperatures before being deployed to sea depths of up to 4,000 m.
Operation and Maintenance. High optical performance is required on all lines for up to 1,000 mates. Subsea connectors typically are mated only a few times in deployment and lifetime operation, but the same connectors are used for testing topside where they see many more mates.
Compact Size. Space on subsea equipment structures is always at a premium, and designs always need to be as efficient with space as possible.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 190652, “Community Engagement, Commitments, and Partnership for Successful E&P Operations in Bolivia,” by Eva Calvimontes and Sergio Eduardo Ayala Sánchez, Vintage Petroleum Boliviana, and Krish Ravishankar, SPE, Occidental Petroleum, prepared for the 2018 SPE International Conference on Health, Safety, Security, Environment, and Social Responsibility, Abu Dhabi, 16–18 April. The paper has not been peer reviewed.
Relationships and engagement with communities in direct areas of influence is of paramount importance for successful exploration and production (E&P) operations. Since the beginning of operations in three major areas of Bolivia, a company has worked very closely with neighboring communities at all stages of design, planning, and implementation of projects and programs. The objective has always been the same: to improve the life quality of the society as a whole and be a partner with the communities.
The company’s E&P operations are located in three areas of Bolivia—Naranjillos, Porvenir, and Ñupuco fields (Fig. 1).
The business units in each of these areas have developed and implemented a social-responsibility program that supports company business objectives and positively affects people, communities, and the environment. A program has been developed that achieves a balance between the E&P interests of the company business and the communities’ expectations and needs. It is carried out through alliances between the company and the communities located inside the areas of influence.
The company’s social-responsibility commitments and ongoing initiatives are categorized into the following five pillars:
Following the core values of each of the five pillars and fully understanding the communities’ needs in the areas of influence, the company has developed and implemented the following steps as part of the stakeholder engagement and social-responsibility approval process:
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 190663, “Building Better Performance Measures for Better Conversations To Provoke Change,” by A.D. Gower-Jones, W.T. Peuscher, J. Groeneweg, SPE, S. King, and M. Taylor, Tripod Foundation, prepared for the 2018 SPE International Conference on Health, Safety, Security, Environment, and Social Responsibility, Abu Dhabi, 16–18 April. The paper has not been peer reviewed.
For the last 40 years, the oil and gas industry has measured safety performance using injury-frequency rates. Industry thinking is based on the premise that, if we do not have injuries, then we are safe and, if we have injuries, we are not safe. This paper examines the fallacy of that premise and the use of injury rates as a key performance indicator (KPI). It argues that, as a KPI, injury-frequency rate is no longer a valid measure.
The Current Situation
As a KPI, injury-frequency rate has served the industry well. It has driven ownership of safety performance as a line responsibility, allowed senior executives to hold managers accountable for performance, forced leaders to notice injuries, and driven many improvements.
A graph showing performance over a 2-year period would be discussed at management meetings, reasons argued, and actions given to business unit leaders. The data could create a discussion along the lines of “Overall performance is clearly going in the wrong direction. We all need to be concerned.” Pointing to one cause would be difficult, and many theories would be put forward on the basis of this data.
Why Measuring Injury Rates Is Misleading
Research into accident causation has revealed much in the last 30 years. Earlier work resulted in the Swiss Cheese Model (Fig. 1), the Generic Error Modeling System (GEMS) (Fig. 2), and the Tripod Model of Accident Causation (Fig. 3). Two software-based products have been produced from these models; Tripod Beta and Bow Tie analysis both are now mainstream.
Safety leaders no longer think that people are the only cause of accidents (i.e., stupid people doing stupid things). They understand that errors and violations are the product of systemic causes. Accidents happen because barriers fail. Barriers fail because of people’s action or inaction. People are generally trying to do a good job, but they are influenced by their environment. That working environment is created by the way the business is managed.
Accidents are complex events with multiple causes. Controls that fail can be a long distance from, and not related to, individuals who are injured. Normally, more than one control needs to fail before someone is injured. Often, those controls are put in place by different people at different times—an operator isolates equipment, a supervisor checks the isolation, and a technician works on the equipment.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 187048, “Shift-Work Fatigue in the Petroleum Industry: A Proactive Fatigue Countermeasure,” by Koos Meijer, KM Human Factors Engineering; Martin Robb, SPE, Human Factors Applications; and Jasper Smit, CGE Risk Management Solutions, prepared for the 2017 SPE Annual Technical Conference and Exhibition, San Antonio, Texas, USA, 9–11 October. The paper has not been peer reviewed.
Insomnia is a common problem in offshore shift-work environments. In rotating shift-work environments, daylight and darkness cues are incongruent with sleep and work schedules. As a result, many shift workers find it hard to adapt to the schedule, resulting in suboptimal sleeping patterns and increased workforce fatigue. This paper presents a scientific method for reducing fatigue risks in oil and gas organizations that operate a slowly rotating shift schedule.
Sleep and Fatigue in Offshore Shift-Work Environments
Humans are diurnal (i.e., day animals); because of this, our circadian rhythm is programmed to ensure that alertness, concentration, and other aspects relating to job performance are highest during the day. Our circadian rhythm makes us feel sleepy in the evenings and ensures that we can maintain restorative sleep during the night. The bodily processes related to this are maintained in the suprachiasmatic nucleus (SCN), which is in the anterior hypothalamus in the brain and is synchronized with the day/night cycle. During the abrupt transition to an offshore night working schedule, the sleep and wake timings of our biorhythm become misaligned with those of the work schedule; this is referred to as circadian misalignment, a mismatch between our internal circadian clock and work, sleep, and eating activities.
Circadian misalignment also takes place during travel, but, in the case of jet lag, the time-of-day cues at our destination—particularly daylight that contains blue short-wavelength light—enables our biorhythm to realign with the schedule. These time cues include
During offshore night shifts, these time cues are missing or completely reversed. As a result, some shift workers only partially adjust to the imposed shift-work schedule. These circadian- misaligned shift workers have to work when their body prepares for sleep and have to go to bed when their body tells them to stay active.
Performance and Safety. Shift workers’ bodies are preparing for sleep when their schedule demands work, leading to significantly lower performance. This is supported by an increasing number of studies that show that alertness, cognitive capacity, and vigilance of unadapted shift workers are impaired. Job performance suffers as well, leading to a decreased work rate, more quality-control errors, and accidents. An elaborate meta-analytic study has shown that unadapted shift workers have almost a third greater risk of work-related accidents.
When shift workers are not able to obtain consistently their required number of hours of sleep after their shifts, a chronic sleep debt begins to accumulate. With each period of insufficient sleep, cognitive performance deteriorates further.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 190485, “Getting to Zero and Beyond,” by J. Jack Hinton, SPE, Baker Hughes, a GE company; Colette M. Glencross, SPE, True North Concepts; Tony Zamora, SPE, ERM; Tom Knode, SPE, Athlon Solutions; and Andrew Dingee, SPE, ADE, prepared for the 2018 SPE International Conference on Health, Safety, Security, Environment, and Social Responsibility, Abu Dhabi, 16–18 April. The paper has not been peer reviewed.
Between 2009 and 2016, the Society of Petroleum Engineers facilitated a series of global sessions to develop ideas for the continued improvement of health, safety, and environment (HSE) in the industry. The diverse group of participants generated many valuable ideas for improved performance. The resulting technical report, “Getting to Zero and Beyond: The Path Forward,” sets the stage for continuing the discussion across the industry of the essential steps the industry must take to sustain zero harm.
For more than 2 decades, the oil and gas industry has set HSE goals that are focused on reducing incidents with the ultimate intended outcome that no one is hurt and no releases occur. The concept of zero harm, therefore, is not new to the industry. What has been a challenge for decades, however, is aligning on an effective pathway to achieve these goals. To attain zero harm, a step change in thinking, performance, and alignment around HSE is required across the industry.
When faced with these challenges, the industry’s alignment on an expectation of zero harm must encompass managing its risks as a high-reliability industry, and, given this goal, many opportunities exist for companies to focus their efforts on moving toward implementing generative characteristics common to high-reliability organizations.
Shift From Zero as a Goal to Zero as an Expectation. To eliminate catastrophic events in the oil and gas industry, it must revise the vision of zero. Defining zero harm as a goal implies that incremental safety-performance targets can be set, acknowledging that operations will harm today. Further, this thinking can lead to a detrimental focus on incidents and injuries that may lead to under-reporting of incidents, gaming of statistics, manipulation of incident definitions, and overly aggressive management of injury cases. A goal of zero suggests an unattainable numerical target of perfection. Rather, the industry needs to think of zero harm as an expectation at each and every moment. It must acknowledge the risks in the industry and, at the same time, expect that its people will go home safe today.
Perhaps this is a nuanced, subtle shift in thinking—from a goal of zero harm to an expectation of zero harm—but the difference between the two is the difference between focusing on future improvement and focusing on safety in the moment. This shift in mindset is imperative to eliminating catastrophic incidents.
Continue To Progress the Application of Human Factors. The cultural shift to being proactive, and ultimately to being generative, is causing a healthy questioning of how the industry has managed HSE.
To this end, the existing normative framework, the natural and socioeconomic conditions of the area, and the applicable technologies are considered. The novelty of this work is the analysis of the factors that determine the environmental risk including technologies, environmental conditions at the site, and the legal context in the region. A review and comparative analysis was performed of the general and environmental regulatory framework in Argentina where unconventional exploration or exploitation activities are carried out. This analysis was completed with a review of the effluent-management strategy, comparing it with criteria used by other countries, especially the United States. In order to perform a preliminary evaluation of the environmental risk, a structured, conceptual, and qualitative analysis was conducted in specific sectors corresponding to each of the areas of exploration and exploitation.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper OTC 28121, “Cybersecurity for Upstream Operations,” by Mohammed A. AlGhazal, SPE, and Mohammad J. AlJubran, SPE, Saudi Aramco, prepared for the 2017 Offshore Technology Conference Brasil, Rio de Janeiro, 24–26 October. The paper has not been peer reviewed. Copyright 2017 Offshore Technology Conference. Reproduced by permission.
During well drilling and completion, cybersecurity is critical for securing data to prevent hacking or the loss of software programs. Paying attention to data flow, with the goal of protecting the data as well as the facility, while developing capabilities to deal with intrusions is important. This is the essence of cybersecurity and operational leadership. This paper emphasizes the value gained by investing in cybersecurity for drilling, workover, and completion operations.
Countless engineering and research projects have addressed cybersecurity for downstream operations. Other works have discussed remote upstream operation models along with data flow and information management that have been implemented to digitize the upstream industry, moving it to a new level of automation, efficiency, and improved overall performance. The benefits of the transforming digitization include assurance, cross-organizational collaboration, leveraging of knowledge, and safer operations with minimal human presence on the well site because of remote control. On the other hand, sensors, controls, and networks are added when intelligence is added. This digital expansion creates vulnerability and more entry points—back doors—to exploit defects and weaknesses. One of the reasons for this proliferation of weaknesses is that no logical system can describe a physical system perfectly because too many pieces are involved.
The Pressing Threat
Upstream oil and gas represents the world’s largest supply chain, involving numerous subcontractors who supply equipment, fluid, and other services to the operating company. The life of upstream assets and resources lasts for decades with multiple time scales for different facilities.
Threats and security defenses continuously evolve and change, but much of a facility does not. This makes cybersecurity of long-lived assets very complex, especially because decisions taken will last a long time and be costly. Additionally, the extended reach of oil and gas infrastructures into remote operational areas creates vulnerability and security exposures alongside environmental risk. Accidents in such extended facilities result in liability increases, revenue losses, and the loss of safety standing with society and authorities.
While substantial emphasis has been placed on physical security for decades, cybersecurity is still evolving and is building an experience curve as threats keep moving.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181216, “Proactive Rod-Pump Optimization: Leveraging Big Data To Accelerate and Improve Operations,” by Tyler Palmer, SPE, and Mark Turland, SPE, Denbury Resources, prepared for the 2016 SPE North American Artificial Lift Conference and Exhibition, The Woodlands, Texas, USA, 25–27 October. The paper has not been peer reviewed.
This paper presents how a US onshore operator took a three-step approach to optimize more than 100 rod-pump wells. The approach involved data consolidation, automated work flows, and interactive data visualization. This approach led to increased unit run times, decreased unit cycling, improved production and equipment surveillance, and increased staff productivity. The ultimate goal was to increase profitability by decreasing lifting costs and increasing operating efficiency.
The processes and tools described in this paper cover a subset of approximately 125 wells in eastern Montana and western North Dakota, but they have been designed to be applicable and scalable to any fields that use rod-pump artificial-lift systems with supervisory control and data acquisition (SCADA). Simple modifications can be made to the tools and processes for wells that do not have SCADA capabilities.
While optimization efforts and best practices have been implemented for the subject rod-pump systems during the past 6 decades, many opportunities remain to create additional value. Empirical knowledge from field personnel serves as the basis for the analytical model. Categorizing and quantifying the observations made by the field personnel is critical to developing any analytical model involving oil and gas operations. On the basis of feedback from field personnel and engineers, the following areas had the most potential for improvement: data consolidation, automated work flows, and data visualization.
The data-consolidation issue stems from data being located in multiple file locations, sometimes being stored in nontabular formats and initially lacking the necessary unique identifiers for mapping between databases. Automated work flows were essentially non-existent; wells were analyzed individually using deterministic, static data. Data were previously visualized in multiple locations but never integrated into a single, interactive visualization tool.
The opportunities to maximize asset value led to the development and implementation of the rod-pump optimization tool (RPOT). The RPOT is a data-visualization tool that generates a single recommended optimization action (ROA) for each well being analyzed. The ROA logic calculates the optimal amount of fluid for a well to produce on the basis of its inflow, while accounting for surface and subsurface equipment constraints.
General examples of ROAs include slowing wells down by making a specific sheave adjustment, speeding wells up by a specified strokes/minute (spm) amount, upsizing the downhole pump to a specific pump size, or upsizing or converting to a different artificial-lift system. If in accurate or incomplete data are brought into the database, the ROA specifies the data source that needs to be quality-checked.
This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 186043, “An Integrated Study To Characterize and Model Natural-Fracture Networks of Gas-Condensate Carbonate Reservoirs, Onshore Abu Dhabi,” by Budour Ateeq, Mohamed El Gohary, Khalid Al Ammari, and Rashad Masoud, ADCO; Abdelwahab Noufal, ADNOC; Ghislain de Joussineau and Martin Weber, Beicip Franlab; and Dinesh Agrawal, IFP Middle East Consulting, prepared for the 2017 SPE Reservoir Characterization and Simulation Conference and Exhibition, Abu Dhabi, 8–10 May. The paper has not been peer reviewed.
Natural fractures can have a significant effect on fluid flow by creating permeability anisotropy in hydrocarbon reservoirs. They can also play an undesirable role in reservoir subsidence and compaction during depletion, with important consequences for production strategy. The investigation of these effects motivated a comprehensive integrated fracture study of three reservoirs from a giant gas-condensate field in Abu Dhabi. The main objective was to build 3D fracture models and compute fracture properties of each reservoir, to be used in dynamic simulations.
The studied reservoirs are gas-condensate-bearing in a carbonate field onshore Abu Dhabi. The field has an anticlinal structure and consists of a series of stacked reservoirs, among which three (Reservoirs A, B, and C) were part of this study. For each reservoir, the production comes mainly from the large gas-bearing area above the gas/oil contact, which is surrounded by a thin peripheric oil rim.
The studied field has a long production history; Reservoir A has produced oil and gas for 30 years. Minor fracturing was observed during routine core analyses in the past, but a comprehensive fracture characterization at field scale was never conducted. Because fractures may have a major bearing on production and could play a significant role in rock compaction and collapse during reservoir depletion, an important objective was to ascertain the risk related to the geomechanical stability of these reservoirs because of the presence of natural-fracture networks.
An integrated work flow was applied in order to characterize fracture distribution and flow effect in the reservoirs properly. The work flow consisted of the following key steps:
Static Fracture Characterization
Fracture characterization using the seismic data initiated the work flow and was followed by the interpretation of fractures from borehole images and core data.
Fracture Characterization From 3D Seismic Data. This task was performed to detect the seismic and the subseismic faults and fracture corridors within the three reservoirs. Seismic fracture-facies maps and fracture-index maps were created on the basis of post-stack discontinuity attributes (e.g., curvature, polar dip, and similarity) computed from the inverted seismic cube.