bluuebunny/crossref_metadata_2025 huggingface dataset:
Perspectives on East Texas Archaeology
Authors: Perttula Timothy
Published: August 2020

A key to my career as an archaeologist working in East Texas has been a very successful professional-avocational collaboration on a wide range of projects with individuals and avocational organizations working in East Texas, such as the Northeast Texas Archeological Society, the East Texas Archeological Society, the Valley of the Caddo Archeological Society, the East Texas Caddo Research Group, as well as the Gregg County Historical Museum, among other museums in the region that hold ancestral Caddo archaeological collections. It has been my good fortune to work with a number of very knowledgeable and hard-working East Texas avocational archaeologists and Texas Archeological Stewardship Network members over the years, including Bo Nelson (who has gone on to establish a professional career as an archaeologist and also start his own CRM firm, Tejas Archaeology, in 1997), Mark Walters, Tom Middlebrook, Patti Haskins, Robert L. Turner, Jr., Kevin Stingley, Bryan Boyd, Mike Turner, Mark Thatcher, Gary W. Cheatwood, Clyde Amick, Lee Green, and Bill Young, among others.
The Taylor Site (41RK36) and 41RK31 on Martin Creek in Rusk County, Texas
Authors: Perttula Timothy
Published: August 2020

In the early 1970s, the Texas Archeological Survey at The University of Texas (UT) at Austin completed archaeological investigations in advance of the construction of Martin Lake by Texas Utilities Services, Inc. on Martin Creek in the Sabine River basin (Figure 1). Martin Creek is a northward-flowing tributary of the Sabine River. These investigations included an archaeological survey with limited test excavations (McDonald 1972), and then more extensive excavations at five ancestral Caddo sites (Clark and Ivey 1974), most particularly the Musgano site (41RK19) (Figure 2) (Clark and Ivey 1974; Perttula 2014), a Middle Caddo period (ca. A.D. 1200-1400) settlement.
Study on Effect of Aerodynamic Sound Hardening for Wear of Coated Carbide Metal Plates
Authors: Sheleg V. K. , Jigalov A. N. , Bogdan D. D.
Published: August 2020

To increase the durability of metal-cutting carbide plates operating during in harsh technological conditions with  impact  load, an aerodynamic sound  hardening  method  has  been developed  that can increase a life of  carbide  tools up to 3.7 times with a small added cost. The wear of plates hardened by the aerodynamic sound method, after 100 min of cutting, is 1.12–1.7 times less than their un-strengthened analogues. A coating on metal carbide plates does not have a prevailing value when a tool is working with impact loads. While working with impact loads viscosity of an internal plate structure occurs the greatest influence on increasing resistance. For metal-cutting carbide plates during interrupted cutting with significant impact loads, a method of aerodynamic sound hardening is more effective than a coating method, not only in terms of tool performance, but also in the cost of completion itself. Empirical dependences of wear on the rear surface of carbide plates hardened by a aerodynamic sound method and plates with PVD coatings have been obtained in the form of approximation by polynomials of the 5thand 2nddegrees, which are convenient to use in a production environment.  It has been revealed the higher carbide plate strength in bending leads to less influence of the method of aerodynamic sound hardening on the increase in wear resistance. So, taking into account the fact that for ВК8-base the ultimate bending strength is 1666 MPa, and for T5K10 it is 1421 MPa, wear reduction after hardening by the aerodynamic sound method for ВП3115-plates with ВК base is 11.5 %, while for ВП3225 – plates with ТК-base – 27.1 %.
Technological Features of Forming Flat Tool for Processing Axicons
Authors: Kozeruk A. S. , Dias Gonzalez R. O. , Sukhotzkiy A. A. , Filonova M. I. , Kuznechik V. O.
Published: August 2020

It has been substantiated that in order to control the process of forming flat surfaces while using a free grinding method it is advisable to choose such machine setup parameters as a tool diameter and its rotation frequency, an amplitude of the reciprocating movement of the part along the tool (or vice versa) and frequency of this movement, as well as the value of  the working  force.  Mathematical  modeling  of  patterns  for abrasive processing of  flat surfaces in the conditions of  free grinding on lever machines has been carried out in the paper. A formula has been obtained for calculating a sliding speed at selected reference points on the surface to be treated while taking into account the pressure in their vicinity. Patterns of the part operation have been determined, for which a correct plate is used in the proposed axicon production technology with due account of the combination and size of the selected setup parameters for processing equipment. Self-organization of the processing process has been substantiated while using a free grinding method. Sensitivity of a kinematic response to a change in processing modes and efficiency of these modes in terms of process performance have been determined in the paper. It has been noted that an increase in a tool diameter, as one of the effective adjustment parameters for controlling the shaping process, is difficult to implement in practice, since this requires replacement of tools, each of which must be pre-configured while using a special rather time-consuming technique. The paper reveals that with an increase in the tool rotation frequency  and an amplitude of its oscillatory movements, there is an increased removal of material on the periphery of the surface being machined, and with an increase in  vibrational movements, on the contrary, the central zone of the part is more intensively activated.
Vehicle Adaptive Rear Combination Light with Non-Replaceable Light Sources
Authors: Sernov S. P. , Balokhonov D. V. , Kolontaeva T. V. , Isaev A. V.
Published: August 2020

Currently, due to the increase in the  average speed of vehicles to ensure their visibility, the luminous intensity of their lightning equipment is constantly increasing, that can lead to blindness of other road users, especially at night. On the other hand, if you do not increase the luminous intensity if lanterns, a vehicle will not be noticeable in difficult road conditions (fog, rain, dust) and it can cause an accident. To eliminate this contradiction, a fundamentally new modular design of the adaptive rear combined vehicle light with non-replaceable light sources based on single powerful light emitting diodes and effective secondary optics of  large diameter has been developed in the paper.  The design provides  for the use of an integrated microcontroller to control luminous intensity of its lights, depending on the conditions of external illumination, braking dynamics  of  a car  and surface condition  of  a lamp  diffuser  with  the  possibility  of  transmitting data via a CAN-bus. Thanks to the built-in microcontroller, the developed flashlight is suitable for installation on vehicles without an on-board computer. These properties allow the flashlight to ensure visibility of a vehicle, and to avoid blinding the remaining road users. The design of the adaptive lamp is small in thickness (up to 40 mm), high luminous efficiency (at least 85 %) and reliability. The conducted lightning  tests have  shown  that the developed  lamp fully  complies with UN Regulation  No  6, 7, 23, 38, 48. The design has been compared with existing analogues of foreign production, which  showed that such a lamp consumes less energy (30 %) and has a lower probability of failure due to the use of high-power LEDs used as a light source.
Empathetic remote death notification in the context of Covid-19
Authors: Landa-Ramírez Edgar , Domínguez-Vieyra Nadia Alejandra , Hernández-Núñez Myriam Eunice , Díaz-Vásquez Lesly Pamela
Published: August 2020

Not available
Guest Editorial: A Net-Zero Future Full of Opportunities for a New North Sea
Authors: Cohen Colette
Published: August 2020

Six months ago, if asked what the biggest challenge was facing our industry and perhaps the world, I would have said, “The transition to a low-carbon/net-zero world.”

Who knew that the biggest threat would actually be an invisible, but devastatingly brutal, enemy? And what impact will that have on our futures? Not only on our commitment to net zero but to our industry’s survival and to the industrialized world we know.

There will be many views, but as I lead a technology organization, I believe we can use this “industrial reset” to chart a new course for our industry and hopefully for our planet. This is a time for us to capitalize on the amazing collaboration we have seen locally, regionally, and globally, as society has pulled together to fight COVID-19.

Can we not put this can-do attitude into action on our biggest global challenges and work together to find a solution? While many of the changes required will be either behavioral or regulatory, a number will be technology-led - and that is where technical industries can have the biggest positive impact in the coming years.

As I look around the world, I can already see countries launching major public/private initiatives to grasp the low-carbon agenda. These are partnerships where businesses innovate and collaborate, with government backing, to create powerful collectives driving both decarbonization and economic growth.

I strongly believe this is the route we should take in the UK - forming deep collaborations to capitalize on our expertise and collective know-how to transform the North Sea into a low-carbon powerhouse.

Progress Made So Far

The good news is, we have already begun.

The UK Continental Shelf has already committed to a net-zero future in the industry’s Roadmap 2035, introduced by Oil and Gas UK.

The Oil & Gas Technology Centre (OGTC) has been supporting the industry with more than £150 million co-invested in emerging technologies in the past 3 years. And in 2019, we opened a center dedicated to the development and deployment of net-zero technologies.

We have worked closely with industry to develop a technology vision and road-map that focuses on three big goals:

Reducing emissions from existing operations

Developing new technologies - including carbon capture, utilization, and storage (CCUS) and also hydrogen - to unlock the potential of our assets and expertise

Transforming to a net-zero industry in the longer term

No one imagines this will happen overnight - the Committee on Climate Change, for example, recognizes that oil and gas production will continue to 2050 and beyond - but at the same time, it predicts massive growth in other sectors, most notably in offshore wind, blue hydrogen, and CCUS.

The current confluence of global challenges, therefore, offers a huge opportunity for the industry to set itself new goals on efficiency, performance, carbon footprint, and the transition to a net-zero future.
AI Meets HMI: Next-Gen Robots Take on the Tough Tasks To Reduce Risks on Rigs
Authors: Flowers Lynnmarie P.
Published: August 2020

Often located hundreds of miles away from land, offshore oil and gas platforms pose challenges with their unsheltered maritime environment, heavy weather, and risk of explosive, toxic, and corrosive atmospheres - with limited resources.

Sounds like conditions are ripe for robots on rigs.

In 14 years at Equinor, robotics researcher Anders Røyrøy has explored the application of robots in jobs that he describes as “dangerous, dirty, distant, or dull,” where use of a robot can serve to mitigate or eliminate safety risks for humans.

One of the highest priorities for robotic development and deployment, in view of their impact on inspection and maintenance routines, are remote operators for onshore and offshore platforms.

Failures in such harsh environments could jeopardize the lives of human operators, the environment, and process equipment. Semi- or unmanned operations can yield significant reductions in the risk of personnel exposure to dangerous chemicals. And in this age of social distancing, robots can be essential in providing contactless support.

Traditionally, bases of design have been focused on improving the safety of existing manned installations sites (brownfield) - those not designed with robots in mind - during potentially dangerous operations. Although it is possible to enhance safety, efficiency, and production availability on a brownfield site, French supermajor Total E&P is challenging that approach by developing remote or unmanned robotic solutions for specific functions on greenfield sites - that is, on automated, unmanned platforms designed to accommodate newly developed technology.

Generally unattended/unmanned installations are those that are visited only every 2 to 3 months. However, if the duration is pushed to one visit per year to perform annual maintenance tasks, it is possible to reduce the complexity of the platforms by removing equipment meant for human presence on site. There are several safety and cost advantages for operating remote production sites using robotics in place of crews.

For example, without the presence of personnel on site, an operator can often remove human-related systems such as living quarters, catering, evacuation boats, and staff transportation to and from its installation, along with inherent risks and high costs. Fewer boats, helicopters, and less road transportation leads to reduced operating costs and CO2 emissions. On such unmanned sites, Total is considering mobile, multipurpose, and ground robots that are ATEX-compliant (safe to operate in potentially explosive environments) and suitable for harsh and dangerous conditions.

A fully autonomous robot can gain information about the environment, move around and work for an extended period without human intervention, avoid harmful situations (unless those are part of its design specifications), and learn new ways to execute its tasks while adapting to changing surroundings.
Use of Low-ECD Synthetic-Based Mud During Topdrive Failure
Authors: Kratzer Matthew
Published: August 2020

While drilling in deepwater Gulf of Mexico, a topdrive failure forced the shutdown of all drilling operations for the rig operator and lasted for 114 hours (almost 5 days). At the time of the failure, the equivalent static density (ESD) was 11.36 ppg and the equivalent circulating density (ECD) was 11.5 ppg. The rate of penetration (ROP) was 100 ft/hr.

Troubleshooting

It was recommended that there be no utilization of the pumps while drilling was stopped, to reduce the chance of packing off the annulus with cuttings until the rotating and reciprocating could continue. During this time, a 100-psi backpressure was maintained using the managed-pressure drilling system. Kronos low-ECD synthetic-based mud (SBM) at a weight of 10.9 ppg was utilized during this event.

During troubleshooting and repair work, a 1,500-bbl 11.4-ppg riser cap was spotted. Following the repair of the topdrive, a malfunctioning packer had to be replaced, causing additional delays.

After the packer was set and the blowout preventers tested, the 11.4 ppg riser cap was displaced and subsequently replaced with 10.9-ppg low-ECD mud. The Kronos system was designed and maintained to have adequate suspension properties to maintain wellbore integrity without sag during unexpected downtime, even with cuttings left in the hole. The rig continued to trip into the hole to 9,800 ft. At that time, a bottom-up was circulated and a maximum of 575 units of gas was circulated out.

Drilling then continued using a base oil and premix for dilution. The lost circulation material in the background continued to be blended into the dilution products being used at the time. During the drilling from 11,636 to 12,845 ft, the decision was made to increase the mud weight to 11.15 ppg.

When the drilling continued from 12,845 to 13,234 ft, formation water was detected from the mud check entering the mud system.

The system was treated to minimize the damage caused by formation water and maintain the properties sought by the operator. To assist in maintaining the desired weight and to prevent low-gravity solids from impacting the mud weight, two shakers were screened up to API Standard 120. At roughly the same time, the mud weight was increased to 11.2 ppg and then to 11.4 ppg.

While continuing to drill, one of the engines that provided power to the mud pumps broke down, reducing the flow rate required to clean the hole. A cement unit was added to the pump to replace much of the volume lost with the broken mud pump.

At 13,155 ft, the decision was made to call this current interval at total depth. The back-reaming process also started at that time. To assist with the hole cleaning, a high-viscosity sweep was blended and circulated. An additional high-viscosity sweep was blended and circulated, the second time at 9,058 ft.

With continued back reaming through some tight spots to 7,272 ft, operators decided to wash back down 7,938 ft and pump one more high-viscosity sweep. Once the hole was clean, a flow check was performed and operators began to pull out of the hole.
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.
Studies on the Prevalence of Hepatitis C Virus Infection in Diabetic Patients attending a Tertiary Health-care Facility South-west Nigeria.
Authors: NDAKO James A. , Owolabi Akinyomade O , Olisa Joseph A. , Akinwumi Jeremiah A. , Dojumo Victor T. , Olatinsu Oludolapo , Adebayo Blessing A.
Published: August 2020

Background: Hepatitis C virus (HCV) infection and type 2 diabetes mellitus (T2DM) are two major public health problems associated with increasing complications and mortality rates worldwide. The objective of this study to evaluate the prevalence of hepatitis C virus (HCV) infection in diabetic patients and to investigate the influence of several epidemiological and clinical factors on HCV infection. Method: A total number of one hundred and eighty diabetic patients were recruited for this study. Consented subjects made up of 71(39.4%) males and 109(60.56%) females were recruited for the study. While one-Hundred (100) Non-Diabetics (Controls) were recruited for this study. Structured questionnaires were administered to the consented participants to obtain relevant data. Sera samples were assayed for antibodies to HCV using an enzyme linked immunosorbent assay [Inteco Diagnostic Limited]. ELISA technique.Result: Overall prevalence of HCV infection among diabetes patients assayed was 13.3%. Out of which 8(11.3%) was obtained from the male subjects compared to 16 (14.7%) seropositivity recorded for the female subjects (P = 0.511; P > 0.05). Considering age distribution, Subjects aged 41-50 years recorded, 9 (22.5%) positivity (P= 0.238; P>0.05).Considering educational status of subjects screened, 22 (14.9%) positivity was rescored among subjects who have attained tertiary status of education.( P = 0.574;P>0.05).Risk factors considered showed that, 7 (18.9%) seropositive subject were alcoholic consumers(P value = 0.2621;P>0.05) while 5 (8.9%) recorded history of sharing sharp objects P= 0.2427;P>0.05).Conclusion: Our study shows a slightly higher prevalence of hepatitis C infection in type 2 diabetics. This call for urgent routine screening exercise among diabetic patients for HCV infection. This study also emphasizes the need for public enlightenment on the association between HCV infection and T2DM, to avert possible complications among diabetic patients.
Association between levels of tumor-infiltrating lymphocytes in different subtypes of primary breast tumors and prognostic outcomes: A meta-analysis
Authors: He Lin , Wang Yaling , Wu Qian , Song Yuhua , Ma Xuezhen , Zhang Biyuan , Wang Haiji , Huang Yong
Published: August 2020

Background: To investigate the impact of the elevation of tumor-infiltrating lymphocytes (TILs) in different molecular subtypes of primary breast cancer, i.e. each 10% increment of TILs and high-level TILs (TILs≥50%) in tumor, on overall survival (OS) and pathological complete response (pCR) and to compare the presentation of high-level TILs across these molecular subtypes. Methods: Citation retrieval was performed in the PubMed, Cochrane Library, Embase and Web of Science databases. All statistical calculations were performed by the software of StataSE version 12.0. Results: Twenty-two eligible clinical trials including 15676 unique patients were included for meta-analysis. Each 10% increment of TILs significantly improved OS in human epidermal growth factor receptor 2 (HER2)-overexpression (pooled Hazard ratio (HR), 0.92; 95% CI, 0.89-0.95) and triple-negative (TN) (pooled HR, 0.90; 95% CI, 0.89-0.92) breast tumors but not in luminal tumor subtype (pooled HR, 1.06; 95% CI, 0.99-1.13). It was also associated with an increased pCR rate in breast cancers (pooled Odds ratio (OR), 1.27; 95% CI, 1.19-13.5). High-level TILs were significantly related with a higher pCR rate (pooled OR, 2.73; 95% CI, 2.40-3.01) than low-level TILs. The HER2-amplified (pooled OR, 3.14; 95% CI, 1.95-5.06) and TN (pooled OR, 4.09; 95% CI, 2.71-6.19) phenotypes of breast cancers expressed significantly more high-level TILs than the luminal tumor subtype, although the presentation of those between the former two subsets was not significantly different (pooled OR, 1.30; 95%CI, 0.83-2.04). Conclusions: The elevation of TILs in breast tumors predicts favorable prognostic outcomes, particularly in the HER2-overexpression and TN subtypes.
Community health worker motivation to perform systematic household contact tuberculosis investigation in a high burden metropolitan district in South Africa
Authors: Kigozi Gladys , Heunis Christo , Engelbrecht Michelle
Published: August 2020

Background South Africa faces a chronic shortage of professional health workers. Accordingly, community health workers (CHWs) are being employed to mitigate the ongoing health workforce deficiencies. As increased access to quality service delivery hinges upon their motivation, this study explored CHWs’ motivation to deliver systematic household contact tuberculosis (TB) investigation (SHCI). Methods In 2017, a cross-sectional survey was conducted among CHWs in the Mangaung Metropolitan District, Free State Province. Exploratory factor analysis was performed on a 30-item scale to determine the dimensions underlying CHW motivation. Items with factor loadings of 0.4 and above were retained. Descriptive and inferential analyses were used to determine CHW motivation levels. Multiple linear regression analysis was used to investigate the determinants of CHW motivation. Results Out of 235 participants, 89.2% were female. Participants’ median age was 39 (inter-quartile range: 33-45) years. CHW motivation was defined by 16 items across three dimensions — intrinsic job satisfaction, burnout and team commitment, together explaining 56.04% of the total variance. The derived scale showed satisfactory internal consistency (Cronbach’s alpha: 0.81), with a mean motivation score of 52.26 (standard deviation [sd]: 5.86) out of 64. Statistically significant differences were observed between formal CHWs — those with at least phase 1 standardised accredited training, and informal CHWs — those without such accredited training regarding team commitment scores (17.82 [sd: 2.48] vs. 17.07 [sd: 2.82]; t(233) = 2.157; p = 0.013). CHW age (β = 0.118, p = 0.029), location (β = 1.737, p = 0.041), length of service (β = -0.495, p <0.001), attendance of TB SHCI training (β = 1.809, p = 0.036), and TB SHCI competence (β = 0.706, p <0.001), contributed statistically significantly to CHW motivation. Conclusion CHW motivation to perform TB SHCI was both intrinsic and extrinsic. The high overall mean score implies that the CHWs were well-motivated to perform TB SHCI. To ensure sustained improved access to quality TB SHCI service provision, programme managers in the Free State and similar settings could potentially use the tool derived from this study to monitor and inform CHW motivation interventions. Interventions should pay close attention to the CHWs’ formalisation, competence and training.