bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comments: The Inevitable Price Cycle
Authors: Donnelly John 
Published: October 2018

Editor's column
Russian President Vladimir Putin and Saudi Crown Prince Mohammed bin Salman met in mid-June on the sidelines of a World Cup game in Moscow to discuss oil prices and diplomacy ahead of the recent OPEC meeting. It was the latest effort to wrest control of oil prices that began with the historic Vienna production cuts in 2016 that rescued the oil market, and the most recent in a long line of attempts to control the oil price cycle.
The production cuts worked. The OPEC members and several largest producers, including Russia and Mexico, agreed in late 2016 to curb oil production by 1.8 million B/D to reduce the supply glut that had sent prices plummeting and caused massive layoffs throughout the industry. Compliance was not only good, but better than expected. Some countries cut supply even more than they agreed, and Venezuelan output dropped sharply because of that country’s economic crisis, which brought the market back in balance. The production cuts totaled almost 2.5 million B/D, according to the International Energy Agency (IEA).
The extent of the cuts has led some, including the IEA, to fear that the market could soon be in short supply, sending prices sharply higher, and continuing the cycle of sharp shocks to the market. To them, oil prices in the $60–70 bbl range would be ideal, encouraging new production to replace declining reserves without disrupting demand growth. The oil market has tightened quickly, which should lead to output increases from major producers this year and next.
Common phrases in the industry this year are “cautious optimism” about prices and “capital discipline.” But oil price cyclicality appears inevitable. The long-term nature of the business that requires years to develop new production, along with reliance on lagging indicators and the relative price inelasticity of consumption, underlies the difficulty of balancing supply and demand. Since 2014, rebalancing the oil market has meant cutting production and reducing inventories; for the rest of this year and 2019, it will mean increasing supply to prevent prices from rising too quickly.
One source of supply that may help is the Permian Basin, which has seen remarkable growth during the downturn, and could act as a swing producer and a major oil exporter. A new report from IHS Markit forecasts that Permian production will rise by almost 3 million B/D to 5.4 million B/D by 2023. Production from the Permian by itself would be greater than any OPEC country except Saudi Arabia and the additional output would be more than the production of Kuwait, the report said. Permian output was less than 1 million B/D in 2010. One thing that could derail this predicted increase is strains on infrastructure. Already, logistical bottlenecks in pipelines and trucking have occurred, causing some production to be deferred to next year.
The UK North Sea: How To Manage an Aging Basin
Authors: Whitfield Stephen 
Published: October 2018

The words “UK North Sea” do not engender much more than cautious optimism these days when talking about oil and gas production, with dropping production and high decommissioning costs dominating the conversation.
The reality is more complicated. After 14 years straight of production declines, and particularly sharp production declines from 2010 to 2014, the UK continental shelf (UKCS) saw production increases from 2015 to 2017. While it is a mature basin in the midst of overall decline, the UKCS has shown potential. Production in recent years has been boosted by a number of large projects coming online such as BP’s Schiehallion and Chevron’s Rosebank. Future production numbers may see a boost from discoveries like BP’s Capercaillie and Achmelvich, and Hurricane Energy’s discoveries at Halifax and Lincoln in the West of Shetland area. Companies and government regulators also see opportunities.
Whether those opportunities will lead to anything beyond a temporary reprieve remains a question. Even if the decline resumes next year, as some have forecast, managing the assets still active in a way that avoids double digit losses will be a challenge for all the stakeholders in the area.
The Value of Infrastructure
In discussing decommissioning and abandonment’s place in the North Sea conversation, Oil and Gas UK economics and market intelligence manager Adam Davey said he has seen little evidence of a massive pickup in activity, with more stories coming about operators trying to extend field life and defer decommissioning.
However, the massive cost of decommissioning is still the most pressing issue facing companies operating in the region. The North Sea makes up the majority of global offshore decommissioning costs, and while the region is forecast to comprise a smaller share of the global total over the next 4 years, the overall costs of North Sea decommissioning should still rise from 2018 to 2021 (Fig. 1). Wood Mackenzie predicted that decommissioning spend will overtake capital expenditure by 2022.
In the UK, decommissioning costs are expected to remain consistent at $2.3 to $2.7 billion annually over the next 5 years, compared to $532 million to $1 billion on the Norwegian continental shelf and $864 million to $1 billion on the Dutch continental shelf. Oil and Gas UK said it is an indication that there is no need to rush decommissioning efforts.
While decommissioning activity on the UKCS is much greater than in the other sectors on the North Sea, the consultancy said this reflects the total amount of infrastructure in the basin, as well as the fact that an increasing number of mature assets are naturally reaching the end of their productive lives. Wood Mackenzie said it is not necessarily an indicator that the UKCS is entering a steep decline.
Integrated CO2-Foam Pilot in a Heterogeneous Carbonate Field
Authors: Carpenter Chris 
Published: October 2018

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190204, “An Integrated CO2 Foam EOR Pilot Program With Combined CCUS in an Onshore Texas Heterogeneous Carbonate Field,” by Z.P. Alcorn, SPE, and S.B. Frederiksen, University of Bergen; M. Sharma, University of Stavanger; A.U. Rognmo, SPE, University of Bergen; T.L. Føyen, SPE, University of Bergen and SINTEF; and M.A. Fernø, SPE, and A. Graue, SPE, University of Bergen, prepared for the 2018 SPE Improved Oil Recovery Conference, Tulsa, 14–18 April. The paper has not been peer reviewed.
A carbon-dioxide (CO2) -foam enhanced-oil-recovery (EOR) pilot research program has been initiated to advance the technology of CO2 foam for mobility control in a heterogeneous carbonate reservoir. Previous field tests with CO2 foam report varying results because of injectivity problems and the difficulty of attributing fluid displacement specifically to CO2 foam. A more-integrated multiscale methodology was required for project design to further understand the connection between laboratory- and field-scale displacement mechanisms.
East Seminole Field
The East Seminole Field in the Permian Basin of West Texas was discovered in the early 1940s with an estimated 38 million barrels of original oil in place (OOIP). The field was developed throughout the 1960s, producing 12% OOIP through pressure depletion. Water floods began in the early 1970s and continued into the 1980s with strategic infill drilling, reducing the well spacing from 40 to 20 acres.
Tertiary CO2 floods began in inverted 40-acre, five-spot patterns in 2013 in the eastern portion of the field. Miscible CO2 injection initially increased oil production and reservoir pressure. However, rapid CO2 breakthrough, high producing gas/oil ratio (GOR), and CO2 channeling was soon observed in peripheral production wells. CO2 performance suffers because of reservoir heterogeneity and unfavorable mobility ratios between injected CO2 and reservoir fluids, resulting in poor areal sweep efficiency, high producing GOR, and CO2 channeling.
As seen in other areas of the Permian Basin, tilted fluid contacts, presumably resulting from basin activity or a breach of seal, have created a deeper residual oil zone (ROZ). These zones are thought to have been naturally waterflooded through hydrodynamic dis-placement and have been shown to contain considerable immobile oil (20 to 40% OOIP) that can be mobilized by CO2 flood. Thus, the residual oil saturation in the ROZ is similar to waterflooded zones and establishes it as an economically attractive target for tertiary CO2 recovery efforts.
Artificial Intelligence and Robotics Support Marine Mining
Authors: Carpenter Chris 
Published: October 2018

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 29069, “How AI and Robotics Can Support Marine Mining,” by Peter Kampman, Leif Christensen, Martin Fritsche, Christopher Gaudig, Hendrik Hanff, and Marc Hildrebrandt, German Research Center for Artificial Intelligence (DFKI), and Frank Kirchner, DFKI and University of Bremen, prepared for the 2018 Offshore Technology Conference, Houston, 30 April–4 May. The paper has not been peer reviewed. Copyright 2018 Offshore Technology Conference. Reproduced by permission.
Marine mining initiatives open a new field of subsea operations. Offshore oil and gas sites are still located primarily in areas where divers can support maintenance and repair requirements, but future marine mining will take place in greater depths and with a complexity of machines that requires support from robotic systems equipped with a substantial amount of artificial intelligence (AI). Technologies are being developed that have the potential to support marine mining in all stages from prospection to decommissioning. These developments will likely have substantial influence in the oil and gas industry, itself searching for ways to maximize exploitation of assets.
Robotic Systems
Under Current Development Increasing Autonomous Underwater Vehicle (AUV) Intelligence. Commercial off-the-shelf AUVs rely mostly on acoustic and inertial sensors for their navigation. Speed measurements from a Doppler velocity log are combined with orientation values from gyroscopes and accelerometers to estimate current position. These updates are sometimes augmented by absolute-position fixes from an ultrashort baseline system. However, during such a mission, the inspection assets might not be located exactly at their expected positions. This might be because of incorrect positioning during installation, objects being dragged off location by fishermen, or sediments hiding a pipeline gradually from the view of standard sensors. Therefore, equipping modern AUVs with sensors and software that can search for, detect, track, and re acquire inspection targets is essential.
In addition, classical sensor suites consisting of cameras and sonars can be augmented with higher-resolution 3D sensing such as laser-line projectors (structured light). This enables an AUV’s onboard software to create a millimeter-precision 3D model of the asset, which can be compared with computer-aided-design models or previous-inspection-run data. By using a fully automated 3D-model cross-check, the AUV could detect asset deformations, defects, or marine growth, even while still submerged during the inspection run.
Seafloor AUV Support Infrastructure. Current AUVs have limited endurance, mostly because of limited battery capacity. Depending on the sensor suite, on-board data-storage space also can be a limiting factor. This causes AUV missions to run no longer than a few days at most, depending on AUV size and shape, propulsion, sensor efficiency, and environmental conditions in the deployment area.
Better Safety Performance Measures Can Lead to Change by Improving Conversations
Authors: Wilson Adam 
Published: October 2018

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.
Technology Update: New Instrumented Docking Gun System Maximizes Perforating Performance
Authors: Guedes Carlos Eduardo , Aboelnaga Sharif 
Published: October 2018

Technology Update
Accidental detonation of a perforating gun at surface can have catastrophic consequences. To decrease risks, layers of procedural controls have been implemented to reduce the inadvertent application of power caused by human error, stray voltage, or the presence of radio frequency (RF) energy. Explosives handling procedures and controls, such as locking out the firing panel and acquisition system, are used to mitigate the human error risk.
Mitigating RF risks requires establishing RF-free exclusion zones, with all RF transmissions shut down. Exclusion zones are effective, but adhering to them relies on strict procedural controls. With increased industry and personal reliance on RF transmitters, such as cellular phones, RF silence is becoming more difficult to achieve. Although RF-immune initiators were introduced more than 20 years ago to allow wellsite operations to continue without RF silence imposed, their complex initiation technologies require high power levels, which improve the safety margin to stray volt-age but significantly reduce overall system reliability.
Perforating has always been a hands-on operation that relies on supervisor experience. Over the last decade, perforating reliability has continued to improve as service companies and operators have implemented detailed training programs, procedural checklists, and advanced hardware. However, these reliability improvements have begun to plateau, acting as an impetus to develop new perforating systems that would be more effective than procedural controls in addressing the main causes of perforating misruns: damaged or improper wiring, mechanical seal failures, and initiator malfunctions.
Plug-In Design With Built-In Safety
With a focus on resolving these issues, Schlumberger developed the Tempo instrumented docking perforating gun system—the industry’s first perforating system that fully integrates a plug-in gun with real-time advanced downhole measurements for monitoring and confirming operations to mitigate risk while increasing safety, reliability, and efficiency (Fig. 1). Created for all environments, the system uses modularized initiators combined with RF filtering mechanisms and an addressable switch to provide an enhanced level of safety to operations.
Proprietary docking components are the key element of the gun system’s plug-in design. They streamline assembly and eliminate the major cause of perforating misfires: technique-sensitive crimping and wiring. The initiator can be plugged into a perforating gun by using simple mechanical and electrical connections without requiring complicated assembly. The new system eliminates all complex field wiring connections and crimping, which simplifies the arming process that has a direct impact on both wellsite efficiency and reliability.
An Update of the Global Standard in Reserves/Resources Classification and Definitions
Authors: DiLuzio Dan 
Published: October 2018

Since its publication in 2007, the SPE Petroleum Resources Management System (PRMS) has been broadly adopted by the petroleum industry as the international standard reference for reserves and resources classification and reporting. The SPE Oil and Gas Reserves Committee (OGRC) continues its commitment to periodically update the PRMS to accommodate changes in technology, commercial arrangements, and, as required, to address evolving industry needs. We are pleased to announce that the 2018 PRMS update has been approved by all sponsoring organizations and by the SPE Board of Directors in June.
How Did We Get There?
An OGRC Update Subcommittee was formed in 2014 to critically review the 2007 document based on industry feedback gathered during a series of workshops over the intervening 7 years. OGRC subgroups examined how the document should be improved and advanced to better support the full range of stakeholders using a standard project-based assessment process while maintaining the key principles. Numerous discussions were held between the sponsoring societies, OGRC members, and other industry experts to develop and refine the draft prior to public comment.
The document was posted for a 90-day public comment period beginning on 15 August 2017. At that time, over 250 personalized letters were distributed announcing the proposed update and requesting feedback from consulting and financial firms, government agencies, and E&P companies. The OGRC Update Subcommittee compiled and assimilated the public responses and made corrections, updates, and clarifications. This draft was submit-ted to the sponsoring societies and the other OGRC members for input and discussion leading to the final version.
The updated document was then approved by SPE and the six co-sponsoring organizations:
World Petroleum Council (WPC)
American Association of Petroleum Geologists (AAPG)
Society of Petroleum Evaluation Engineers (SPEE)
Society of Exploration Geophysicists (SEG)
Society of Petrophysicists and Well Log Analysts (SPWLA)
European Association of Engineers and Geoscientists (EAGE)
The PRMS also provides the commodity-specific specifications for petroleum under the United Nations Framework Classification for Resources (UNFC).
The updated PRMS is now posted at www.spe.org/industry/reserves.
Major Principles Retained
PRMS continues to utilize the same foundation principles contained in the PRMS 2007 document:
The system is “project-based”
Classification is based on a project’s chance of commerciality
Categorization is based on recoverable uncertainty
The base case uses evaluator’s forecast of future conditions
Provides more granularity for project management
Estimates based on deterministic and/or probabilistic methods
Applies to both conventional and unconventional resources
Reserves/resources are estimated in terms of the sales quantities and allowing for fuel consumed in operations (CiO) when reported separately
Net resources are allocated based on contractual entitlement
Lessons From 10 Years of Monitoring With Chemical Inflow Tracers
Authors: Carpenter Chris 
Published: October 2018

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 187677, “Ten Years of Reservoir Monitoring With Chemical Inflow Tracers—What Have We Learned and Applied Over the Past Decade?” by A.D. Dyrli and E. Leung, SPE, Resman, prepared for the 2017 SPE Kuwait Oil and Gas Show and Conference, 15–18 October. The paper has not been peer reviewed.
Initial development of inflow tracers was designed to provide qualitative information about the location of water breakthrough in production wells. The proof of concept and application for water detection initiated the development of oil tracers for oil-inflow monitoring. The evolution of inflow-tracer-signal interpretation also has provided valuable insight to inflow characterization. A model-based approach to match the measured signals with proprietary models also has been developed.
Unique Chemical Tracers for Reservoir Surveillance
During the past decade, many unique chemical tracers have been designed. The aim of this development has been to obtain many unique signatures with properties as similar as possible. The strategy involved finding families of chemical molecules that had the potential to provide a large number of unique tracers with a small change in the chemical structure. Today, more than 160 unique signatures exist. More than 80 are within one family of oil markers.
The chemical tracers and the polymer matrix need to be stable and inert at a wide range of well conditions. No applicable accelerated test methods exist for polymer materials, so long-term functionality must be tested in the laboratory with an environment as realistic as possible to estimate inflow-tracer longevities.
Another important feature of these tracers is the concept of the detection limit. To be able to mark production over decades with a limited amount of material placed in the well, the detection limit must be extremely low. The amount of material is limited because of space, cost, or environmental concern. In 2005, the detection limits were parts per billion, while the detection limit today is below parts per trillion and is expected to move toward parts per quadrillion.
Inflow-Tracer-System Design
Years of laboratory work and field experience have proved that designing systems from experience is crucial. The effect of nontarget fluids and treatment chemicals on different materials is tested over specific time periods according to time of exposure under actual conditions. The qualification tests include treatment chemicals, including solvents and strong acids or bases that may affect the tracer or polymer matrix in which the tracers are embedded. Temperature is one of the major parameters affecting release, and stability and functionality tests for the design will be performed at various temperatures. The use of permanent installed tracers to optimize oil production and reduce water production will reduce the need for water treatment and interventions, thereby reducing the overall environmental impact.