bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Unconventional Resources
Authors: Chipperfield Simon 
Published: August 2020

The dramatic plunge in oil price will be the impetus to transform our industry again. No segment of the industry has embraced innovation more than have unconventionals. At the core of this innovation has been an approach to solving complex problems that had no known solutions before the 2000s.
An opportunity now exists to further develop the way we solve problems by adopting agile work flows. Originating from software development in 2001, agile work flows will be a key part of driving the oil and gas industry to its next level of efficiency. Here are three reasons why.
Accelerated Delivery of Executable Program. Developing projects that are economical in a depressed oil price environment requires multidisciplinary problem-solving in an accelerated, time-efficient manner.
The traditional subsurface work flow that generates these projects experiences difficulty because typically it is designed for known problems (e.g., standard well designs) and requires many handoffs between functional groups, leading to extended project cycle times. Critically, the longer the accepted project cycle time, the less optimization can occur and the less the business can tolerate.
An alternate agile approach is to perform key steps of the project as multidisciplinary sprints. These are fast-loop, multidisciplinary activities that require active involvement of the customer and decision-makers - temporary, fully dedicated, empowered teams that aim to reach completion within a defined time frame.
Stability in a Time of Change. Maintaining frequent staff engagement is critical during a time when staff members are uncertain about their jobs and often are working remotely. Agile work flows that include daily check-ins or standup meetings are required to provide a regular cadence for staff members and allow for course corrections in response to a volatile market.
Flexibility. A flexible, fully committed work force is never more necessary than now. Agile and sprint work flows promote flexibility, directing staff to the task of highest priority and thereby maximizing staff utility. An agile culture promotes staff members who work beyond their traditional geographical or even functional areas.
New Closed Blender Reduces Footprint, Gasification of CO2in Waterless Fracturing
Authors: Carpenter Chris 
Published: August 2020

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper IPTC 19770, “Design, Optimization, and Application of a Closed Blender for CO2 Waterless Fracturing,” by Qinghai Yang, Siwei Meng, and Chuan Yu, PetroChina, et al., prepared for the 2020 International Petroleum Technology Conference, Dhahran, Saudi Arabia, 13-15 January. The paper has not been peer reviewed. Copyright 2020 International Petroleum Technology Conference. Reproduced by permission.
Carbon dioxide (CO2) waterless fracturing uses liquid CO2 to replace water as the fracturing fluid in reservoir stimulation. The continuity and reliability of the blender are key factors determining performance of the operation. The complete paper proposes a novel closed blender that uses a vertical, rather than horizontal, tanker. This modification can reduce the footprint and effectively suppress CO2 gasification. The field practice suggests that the developed closed blender combines the advantages of both vertical and horizontal blenders and ensures successful implementation of CO2 waterless fracturing operations.
Introduction
The CO2 waterless fracturing process, as an alternative technology for developing unconventional reservoirs, greatly reduces consumption of water resources in the development of unconventional resources. In addition, compared with traditional fracturing measures, this technology has the advantages of low reservoir damage, complex artificial fractures, good energy-storage effect, and a high degree of recovery because of the unique physical and chemical properties of CO2.
The CO2 waterless fracturing process requires the following equipment: CO2 tank trucks, booster pump trucks, sand blenders, high-pressure pump trucks, and low-and high-pressure manifolds. The blender acts as the core equipment for dry fracturing of liquid CO2, its main function to mix CO2 with proppant. It then feeds the mixed sand fluid to the fracturing pump truck for CO2 water-less fracturing. In the fracturing process, CO2 on the ground is required to be under low temperature and high pressure continuously to maintain its liquefaction. In addition, CO2 fluid has characteristics of low viscosity, high friction resistance, corrosiveness, and poor lubrication. Compared with traditional hydraulic fracturing processes, the sand blender for CO2 waterless fracturing has specific requirements.
Components of the Closed Blender
Drawing lessons from design of internationally available closed blenders for CO2 waterless fracturing, the authors have developed independently a new generation of closed blender, mainly composed of a sand tanker, a sand-mixing system, a blender manifold (a discharge manifold and a suction manifold), a chemical-addition system, a hydraulic system, an electronic control system, and a data-acquisition system (Fig. 1).
Supercritical CO2Heat Recovery System Finds Application in Oil and Gas Operations
Authors: Feder Judy 
Published: August 2020

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 197965, “Transforming Waste Heat to Electric Power in Oil and Gas Compression Systems Using Supercritical Carbon Dioxide,” by Thomas Soulas, Siemens, prepared for the 2019 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 11-14 November. The paper has not been peer reviewed.
The complete paper describes an advanced Rankine cycle process-based system that converts waste heat into usable electrical power to improve the efficiency of gas-compression stations on gas-production platforms and pipelines. Instead of steam, this system uses industrial-grade carbon dioxide (CO2) in the supercritical state as the working fluid.
Introduction
Globally, rejected heat is estimated to correspond to approximately 65% of net energy input across the industrial infrastructure, with numbers varying from 60 to 70% depending on the region. Considerable waste heat is ejected from equipment such as the gas turbines commonly used in mechanical drive applications found in the compression processes of gas-production platforms and transmission pipelines. Recently, a technology that supports energy recovery from heat rejected from a broad range of industrial processes has become available to the oil and gas industry. The system recovers usable, but often wasted, heat and converts it into higher-value, usable electrical power.
While most gas turbine heat-recovery systems use a bottoming steam cycle to improve thermal efficiency, the system described in the complete paper is based on an advanced Rankine cycle process. With revenue and cost predictability, the technology generates power at a competitive installed cost and delivers an estimated 10% increase in baseline efficiency for a gas-compression station to reduce effectively the overall cost of electricity. The main innovation of the technology lies in the selection of CO2 as the working fluid.
Advantages of CO2 in Heat-Recovery Cycles
CO2 has relatively moderate conditions for the supercritical state, with a critical pressure of 1,071 psi and a critical temperature of just above 88°F. With an approximately 50% increase in specific heat capacity at approximately the critical point and likely cycle conditions, and a reduced compressibility factor near the critical point, CO2 is ideally suited to recover heat energy across a broad range of temperatures and sources such as those found in exhaust gas streams.
Aker Solutions Shares New Details of Unmanned FPSO Concept
Authors: Jacobs Trent 
Published: August 2020

Large, unmanned floating facilities may be on course to become the embodiment of all that is promised by the oil and gas industry’s digital revolution.
Fewer people working in remote corners of the globe, leaving behind fewer carbon footprints. Thanks to the advent of the internet-of-things, all systems are monitored from the safety of an onshore center. In the background, a digital twin peers into the future for equipment failures.
Minor tasks, such as leak detection and corrosion monitoring, are done by a diverse cast of robots and fixed sensors. Bigger maintenance projects are performed by human crews who visit only once or twice a year via a service vessel - there will be no helipad. Also absent are any staff accommodations, cranes, or a control room.
This is a quick snapshot of Aker Solutions’ latest version of an unmanned floating production, storage, and offloading (FPSO) vessel. The Norwegian offshore engineering firm has been iterating on the idea since at least 2017 when it promoted unmanned FPSOs to drive down offshore development costs.
And while it remains today only an idea, there are just a few scalable barriers keeping an unmanned floater from being realized, according to Aker Solutions Senior Manager Anna Frostad.
“The unmanned FPSO concept improves both field economy and HSE - and I therefore think this is the design for the future,” Frostad said during an online presentation of a technical paper (OTC 30905) she coauthored for the 2020 Offshore Technology Conference.
In terms of savings, the paper suggests that the future owners of an unmanned FPSO will likely be oil companies that are committed to long-term results. To build one might only be 10% cheaper than to build a conventional FPSO. On the back end though, first adopters may see a reduction in typical operating expenses of up to 30%.
Frostad emphasized that whoever is first must also adopt a “subsea mindset” and a very large digital tool box. She outlined three key elements to the subsea mindset: design simplicity, high-quality equipment, and a modular layout that enables a “plug-and-play” approach to replacing critical systems.
Taking this approach conceptually also meant that the design engineers would need to forego the adaptation of existing FPSO designs. “The starting point was a blank sheet of paper,” with the overriding principle being that every system added to the design needed to be “justified in,” said Frostad. The result is what the company calls a lean design.
From the highest level, the lean FPSO she described shares many of the same characteristics of a typical manned FPSO, including a tanker-shaped hull.
The planned-for oil storage capacity is 1 million bbl, the maximum operating depth is 1000 m (about 3,280 ft), and its distance to shore is limited to 200 km (about 125 miles). As oil is stabilized on the topside, the natural gas is to be conditioned, compressed, and reinjected into the subsea reservoir.
Application of Multizone Water Injection Downhole Flow Control Completions With Fiber-Optic Surveillance
Authors: Joubran Jonathon 
Published: August 2020

This article focuses on the completion design of a multiple-zone water-injection project (MZWIP) that was initiated in 2016 in the Azeri-Chirag-Gunashli (ACG) fields in the Azerbaijan sector of the Caspian Sea. The MZWIP has ultimately proved a unique method of using intelligent completion interval-control valves (ICVs) in place of traditional sand-control completions.
Four years after MZWIP implementation, nine wells with a total of 25 zones are injecting at required rates with zonal-rate live reporting across all five ACG platforms. To achieve the multizone injection facility, the requirement for a standard ACG sand-control injector design was discounted and a non-standard sand-management control technique developed using a cased and perforated (C&P) and downhole flow-control system (DHFC). During this program, BP ACG has successfully installed the world’s first 10,000-psi four-zone inline variable-choke DHFC wells with full surveillance across each zone including pressure, temperature gauges, and fiber-optic distributed temperature sensors (DTS).
The development of this MZWI solution has significantly changed the ACG development plan and has been quickly expanded across all five ACG platforms. Accessing up to four zones in the same wellbore, this C&P DHFC well design is accelerating major oil volumes and will significantly reduce future development costs, maximizing wellbore utility in a slot-constrained platform. This could not be achieved by drilling more single-zone C&P injectors as it would erode business value through platform slot use, additional well costs, and slowing down field development. Multizone injection, therefore, became a necessity.
Technology Focus: Subsea Systems (August 2020)
Authors: Hanssen Birger Velle 
Published: August 2020

Despite uncertainties related to oil and gas industry dynamics and new requirements to reduce CO2 emissions, energy demand is expected to continue to grow. It is also expected that the mix of energy shares will change significantly in the next 10-20 years. Natural gas and renewables (wind and solar) gradually will represent a larger part of the energy mix, balanced by a drop in reliance upon fossil fuels such as oil and coal.
Some of the largest reserves of natural gas are located under deep waters, far from shore or any other existing infrastructure. Examples of areas where such field development is under way include western Australia, the North Sea, the Mediterranean, and southeast Africa. Among the many challenges often experienced in such fields is the requirement to transport gas in ultralong pipelines back to shore; in some instances, tie-backs are 100- to 250-km long and water depths can reach more than 2000 m.
Subsea gas-compression technologies have been developed, tested, and successfully deployed in recent years, and operators now are using these technologies to make remote subsea gas fields profitable.
Systems for subsea gas compression have reached Technical Readiness Level 7. After being in operation at the Gullfaks field and at the Åsgard field in the North Sea for several years, these technologies are now being considered for future field developments, not only in the North Sea but also in other parts of the world.
In the Åsgard subsea-compression system, the gas condensate is separated subsea so that the gas can be compressed by a centrifugal compressor and the liquids can be pumped. Gas and liquid then are commingled downstream of the compressor station, and the mix travels in a pipeline to a processing facility 40 km away.
The Gullfaks compression system uses a multiphase compressor technology that has been developed to handle mixtures of gas and liquid; hence, no separation or liquid pumps are required subsea. The result is that the weight and volume per unit of compression power are greatly reduced and the system becomes relatively small and less complex.
Both operational experience and studies of future offshore gas-field developments are showing that subsea gas-compression systems not only reduce investment costs but also increase recovery significantly.
New solutions, supported through relevant field studies, will be analyzed in the studies presented in this section.
Subsea Multiphase Gas Compression System Offers Competitive Advantage
Authors: Carpenter Chris 
Published: August 2020

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29391, “Bringing Forward the Next-Generation Multiphase Compressor,” by John Olav Fløisand, Bernt Helge Torkildsen, Joakim Almqvist, SPE, and Hans Fredrik Lindøen-Kjellnes, OneSubsea, prepared for the 2019 Offshore Technology Conference, Houston, 6-9 May. The paper has not been peer reviewed. Copyright 2020 Offshore Technology Conference. Reproduced by permission.
In 2015, the world’s first subsea multiphase gas compression system was installed offshore Norway. The system comprises two-off 5-MW machines configurable for serial or parallel compression. This system has now gained considerable and valuable operational experience. The multiphase compressor not only ensures efficient power system compatibility but also can contribute to stepout topologies because of the low transmission frequency required for the power supply. Minimizing the complexity of both process and power architecture is crucial in terms of cost, robustness, and system reliability.
Gullfaks Subsea Compression
The realization of the subsea multiphase gas compression system was made possible through major technology investments during 2007-2012, including facilities, design models, and engineering as well as component and full-assembly qualification testing. This extensive technology-qualification program made the technology robust and reliable and enabled the engineering, procurement, and construction delivery of the subsea multiphase compression system to the Gullfaks field in March 2015 per schedule (Fig 1).
The dynamic commissioning of the Gullfaks subsea wet-gas-compression (WGC) system was begun in July 2017. The work was first performed on both compressors in single mode to verify control-system functionality. Different wells and production lines were used to reach desired operation points. After initial commissioning, the compressors were run first in single mode and later in parallel at different suction-pressure setpoints.
The system has been operating successfully since its commissioning in 2017. The subsea compressor system is boosting multiphase gas, increasing the production from several wells, and has recently achieved Technology Readiness Level 7. The system flexibility is exploited in extended ways compared with the initial project phase approach and allows the operator to take advantage of many opportunities, including increased oil recovery. Some key achievements of the system include increased oil production by kicking off dead wells and enabling stable well backpressures.
Operation Planning Tool Improves Quality, Efficiency of Offshore Risk Management
Authors: Feder Judy 
Published: August 2020

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 195750, “Improving the Quality and Efficiency of Operational Planning and Risk Management With Machine Learning and Natural Language Processing,” by Claire Emma Birnie, SPE, Jennifer Sampson, and Eivind Sjaastad, Equinor, et al., prepared for the 209 SPE Offshore Europe Conference and Exhibition, Aberdeen, 3-6 September. The paper has not been peer reviewed.
The complete paper discusses Equinor’s operation planning tool (OPT), developed to present planners with the technical conditions of a platform, identify potentially dangerous combinations of concurrent activities, and propose learnings from 8 years of incident recordings. The OPT provides a single interface detailing a plant’s technical conditions, all planned work orders, and relevant lessons from previous incidents. By reducing reliance on personal experience, the tool has improved risk identification and handling, achieved faster knowledge transfer to new employees, and focused cross-platform knowledge sharing.
Introduction
The operator’s requirement that all incidents or near-misses be reported has resulted in a database of over 108,000 incidents. Alongside lessons learned from previous incidents, planners must consider the suitability of concurrent jobs and any technical status that may affect the safety of executing a planned job at a specific time.
Before 2018, planners had to manually consult eight data sources, each with a separate user interface (UI), to obtain an overview of the plant’s technical status, concurrent jobs planned, and relevant lessons learned from previous incidents. This work flow had two clear bottlenecks:
Manual investigation of the separate data sources was time-consuming, often involving keyword searches or queries on structured data.
No easy way existed to obtain an overview of full asset status, with discipline leaders focusing individually on their jobs.
A high volume of planned jobs and the time-consuming nature of investigating multiple data sources dictated heavy reliance on personal experience of the production platform to accelerate searching of relevant data segments. However, this posed challenges to rapid onboarding of new employees and capture of cross-platform learnings. The OPT was developed to provide a single interface displaying data from all eight data sources.
Using natural language processing (NLP) techniques, the tool leverages unstructured data to supplement structured data, creating additional information that previously did not exist in a machine-readable format. Because of the technical vocabulary used to describe offshore operations, language models had to be generated to capture descriptions of equipment used and tasks being performed. This information was used to help determine relevance of an incident to a planned activity.
Technology, Innovative Approaches Enhance Road Safety for the Oil and Gas Industry
Authors: Carpenter Chris 
Published: August 2020

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199467, “Applying Technology and Innovative Solutions To Enhance Driver Engagement and Performance,” by Freddy Perez, Kirsty Walker, SPE, and Junaid Parkar, Schlumberger, prepared for the 2020 SPE International Conference and Exhibition on Health, Safety, Environment, and Sustainability, originally scheduled to be held in Bogota, Colombia, 28-30 July. The paper has not been peer reviewed.
The complete paper describes a service company’s approach to the development and application of technology and innovative solutions to improve driving performance on the basis of extensive data analysis. Driving-performance data identified potential scenarios in which outcome-focused solutions can be used to influence driver behavior. Tailored approaches were implemented, ranging from vehicle enhancements to mobile applications.
Introduction
The International Association of Oil and Gas Producers reports that land-transportation-related incidents historically have been the single largest cause of fatalities in its member company operations. Since 2000, such incidents have accounted for 22% of all work-related fatalities reported by the members.
The service company Schlumberger has a long-standing commitment to road safety, including mandatory driver safety training for all employees and contractors who drive on company business. The company has also invested in providing global journey-management centers to support company driving activities.
Task Force Updates Guide Presenting Best Practices in Environmental Management
Authors: Carpenter Chris 
Published: August 2020

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199456, “Environmental Management in the Oil and Gas Industry, Second Edition - A Guide to Environmental Management Good Practices in the Upstream Oil and Gas Industry,” by Wendy Brown, IOGP, Artemis Kostareli, IPIECA, and Ian Sealy, SPE, Schlumberger, prepared for the 2020 SPE International Conference and Exhibition on Health, Safety, Environment, and Sustainability, originally scheduled to be held in Bogota, Colombia, 28-30 July. The paper has not been peer reviewed.
Environmental Management in the Oil and Gas Industry was first published in 1997 by the E&P Forum [the predecessor of the International Association of Oil and Gas Producers (IOGP)] and the United Nations Environment Programme (UNEP) as a guide to best practices in environmental management throughout the lifecycle of upstream oil and gas projects. Since then, the industry has made substantial changes in environmental risk management and mitigation. IOGP’s Environmental Committee determined in 2016 that a revision of the publication (also known as IOGP 254) was required. The complete paper describes the development of, and summarizes the major changes and additions to, the guide’s content.