bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comments: Mexico Builds Momentum
Authors: Donnelly John 
Published: September 2017

Editor's column
In August, Mexico’s National Hydrocarbons Commission delayed the date of its next deepwater auction by a month to January 2018 to give companies more time to study the acreage on offer. Although postponing bid rounds is usually taken as a sign of lack of interest by private firms, the opposite is true in Mexico. Discoveries announced over the past few months have validated Mexico’s historic energy reform effort and may propel the oil industry there to reverse years of decline.
In a sector hampered by the downturn in oil prices, Mexico’s offshore has emerged as a bright spot. In July, US independent Talos Energy, Sierra Oil and Gas of Mexico, and Premier Oil of the UK announced one of the largest shallow-water finds of the past 20 years. The block, located off the coast of Tabasco state, holds an estimated 1.4 billion to 2.0 billion bbl of oil. The find, which came with Talos’ first exploration well, was the first since Mexico began auctioning off onshore and offshore properties in 2013. The block found up to 650 ft of oil-bearing reservoir of light crude around 28–30 °API. That same month, Italian major Eni announced the discovery of the shallowwater Amoca field in the bay of Campeche, which it said holds 1.3 billion BOE, of which 90% is oil. It is fast-tracking the development with hopes to produce from 30,000 to 50,000 B/D of 25–27 °API crude in early 2019. Consultancy PIRA Energy expects the discoveries to add up to 200,000 B/D of crude production, and believes they are economic at a $50/bbl oil price, but not for at least another decade.
Although deepwater and perhaps unconventional reserves hold the most promise for reviving Mexico’s oil sector, the country does not have a lot of time. Years of blocking the private sector out and underfunding the state oil company Pemex have taken their toll. The country’s oil and gas output is down 40% from its peak; oil production is 2.0 million B/D compared with its peak of 3.4 million B/D in 2004. That led the government to finally open the entire oil and gas sector to private money, but the reform launch could not have come at a worse time. Oil prices soon lost more than half their value, severely curtailing companies’ exploration budgets.
But the discoveries of Talos and Eni have breathed new life into Mexico’s upstream and attracted the interest of independents and supermajors. That is in contrast to the early bid rounds, which attracted only light participation. To date, seven auctions have been held—three covering onshore, three for shallow offshore, and one for deep water. Pemex has also negotiated farmout agreements with private firms. Another three are scheduled for next year. The key will be interest in the January auction. Thirty deepwater oil and gas blocks will be up for bid in areas thought to be potentially lucrative. Mexico’s deep water has been off limits to private firms and barely explored by Pemex. If resources there are anything like those found in the neighboring US Gulf of Mexico, the country’s upstream sector may become one of the globe’s offshore bright spots.
Technology Update: Tool Enables Complete Cased-Hole Formation Evaluation, Reservoir Saturation Modeling
Authors: Grover Rahul 
Published: September 2017

Technology Update
For more than 40 years, the industry has used pulsed neutron logging to determine hydrocarbon and water saturations behind casing for reservoir management. Multiphase saturation measurements over time are useful for tracking reservoir depletion, planning workover and enhanced recovery strategies, and diagnosing production problems such as water influx and injection fluid breakthrough. Cased-hole logs also serve as a contingency when openhole logs cannot be run or are not considered for reservoir characterization.
Although the cased-hole measurement suite has been greatly improved over many tool generations, the intrinsic physical measurements remained unchanged, which meant that operators could not obtain a complete picture of the rock and fluids behind casing. Input from openhole logs was required from a porosity or bulk density measurement for combination with the neutron porosity. Absent this input, primary formation evaluation in cased wellbores can be ambiguous. An additional challenge with cased-hole logging is correctly compensating for the effects of borehole fluids and the presence of completion hardware.
Next-Generation Logs
To meet the need for accurate surveillance in cased holes, Schlumberger recently introduced the Pulsar multifunction spectroscopy system. The system builds on innovative technologies originated by the company to provide the first complete cased-hole formation evaluation and reservoir saturation monitoring capability with openhole-equivalent measurements.
This next generation in pulsed neutron logging integrates multiple detectors and a high-output pulsed neutron generator (PNG) to significantly improve measurement precision, data acquisition accuracy, and logging speed. The measurements are complemented by powerful algorithms that compensate for variation in the borehole fluids and completion in delivering robust, representative answers in complex conditions.
The PNG and four detectors are housed in a 1.72-in.-outside-diameter (OD) tool that is designed for through-tubing access and logging through most completion restrictions.
The detector adjacent to the PNG is the compact neutron monitor, which is primarily sensitive to fast neutrons to provide accurate and precise output measurement. There are three scintillation gamma-ray detectors for near, far, and deep detection. The near and far detectors use cerium-doped lanthanum bromide (LaBr3:Ce) scintillators, and the deep detector, farthest spaced from the PNG, has an yttrium aluminum perovskite scintillator.
The three gamma-ray detectors are coupled to high-temperature-rated photomultiplier tubes, and their pulses are counted with specialized electronics matched to the high rate and resolution of the LaBr3:Ce scintillators.
Shale EOR Works, But Will It Make a Difference?
Authors: Rassenfoss Stephen 
Published: September 2017

When EOG Resources disclosed that it had found a way to get from 30 to 70% more oil from Eagle Ford shale wells, it set off a race among competitors looking for a low-cost way to add reserves by injecting natural gas.
It has been little noticed because few companies have said anything publicly about it. But university researchers and service companies are seeing widespread interest from companies that are trying to figure out how EOG uses gas injection to increase production and whether those gains can be sustained long enough to add reserves.
Research interest in gas injection enhanced oil recovery (EOR) persuaded David Schechter, a petroleum engineering professor at Texas A&M University, to equip his lab that has been used to test carbon dioxide (CO2) for EOR to safely observe how natural gas affects reservoir rock. “Basically everyone with a substantial acreage position is working on unconventional oil EOR now,” said Schechter.
“This is the name of the game. Everybody is talking about EOR and pumping money into trials of EOR,” said Deepak Devegowda, an associate engineering professor at the University of Oklahoma.
The question facing EOG and its competitors is, can they take a method that improves results from some of its best wells, and use it on a far larger scale to increase overall recoveries in unconventional formations where more than 90% of the resource is left behind.
Companies would like to understand and simulate it and, most importantly, they are looking for clues on how EOG did it. “A whole bunch of folks are watching what other people are doing,” Devegowda said.
Companies and researchers are using statistical analysis to determine patterns in production data filed with the Texas Railroad Commission to try to figure out how EOG is using natural gas injection.
Among those looking is Todd Hoffman, an associate professor from Montana State, who was initially skeptical of EOG’s claims. After studying the data, Hoffman said that EOG clearly is “seeing huge increases in added oil production.” He is now working on a paper based on the disclosures.
As for how he figured out which of EOG’s more than 7,000 Eagle Ford wells to study, he said, “I really had to dig around to find it. I talked to a number of companies planning pilots, doing pilots, in the planning stage, trying to do the same thing,” he said.
Talent & Technology: Drawing on Collective Engineering Sentiment To Improve Learning Outcomes
Authors: Lawrie-Munro Michele , Dalrymple Lori 
Published: September 2017

With many engineering disciplines projected to have a shortage of workers in the next 10 years and the impending retirement of many senior-level employees, there has been an emphasis on identifying job competencies and skills gaps. SPE, and others, have developed a variety of tools to identify and address these and help members ready themselves for the emerging realities of the future workplace, further their careers, and meet employers’ expectations.
As the SPE Soft Skills Committee reported in the February 2016 issue of JPT(Fig. 1), the American Association of Engineering Societies (AAES) released an Engineering Competency Model (CMT) in July 2015. The group engaged subject matter experts from its 17 member societies to develop the model in conjunction with the US Department of Labor Employment and Training Administration over a 2-year period. The administration partners with industries and professions to develop and maintain dynamic models of the foundational and technical competencies that are necessary in economically vital industries and sectors of the American economy. SPE’s parent organization, the American Institute of Mining, Metallurgical, and Petroleum Engineers (AIME) participated as a member society. AIME interfaced with SPE training staff during development of this model.
The creation of the competency model included an examination of existing bodies of knowledge, as well as the inclusion and involvement of the stakeholders within the engineering community, including associations, industry, and academia. The tool was vetted via a webinar, a survey, and an in-person review session. The team built the model to provide a universal standard for the knowledge, skills, and abilities necessary not only for entering the engineering profession but also for maintaining proficiency during one’s career. It is also helpful to employers, educators, associations, and economic developers.
While the Department of Labor has used this pyramidal template to develop models for 23 industries, engineering was the first profession for which this was used. Additional detail can be found at https://www.careeronestop. org/CompetencyModel/.
Bridging the Engineering Competency Model
With SPE’s Competency Work The ECM competencies are laid out in pyramidal fashion to display foundational skills typically learned earlier in life underneath those skills acquired in later stages of educational and workplace achievement. But it stops short of identifying competencies for specific engineering disciplines and jobs. This is where most of SPE’s technical competencies come in.
Fifty Years of TUDRP
Authors: Banzet-Ellis Gail 
Published: September 2017

Many professionals in today’s drilling engineering industry can trace their careers back to a historic research facility in Tulsa. One of the oldest drilling consortia in the world, The University of Tulsa Drilling Research Project, TUDRP, is celebrating 50 years and is poised to continue its tradition for another 5 decades.
TUDRP is the concept of legendary TU professor Kermit Brown who initially established the consortium. A nonprofit cooperative between industry partners and university associates, TUDRP conducts basic and applied research to advance drilling technology. Students gain experience in the industry while partners benefit from the research developed. Professor B.J. Livesay was the group’s first director and welcomed a small group of industry partners. Livesay left the program in 1972, and John Day served as interim director until J.J. Azar accepted the permanent role. Azar arrived at TU in 1965 as an assistant professor in aerospace engineering. As director, he reached out to major oil corporations, independents, contractors, and suppliers.
“We were the only existing cooperative research program in petroleum engineering that specialized in drilling while also promoting academics,” Azar said.
TUDRP grew to more than a dozen members with worldwide recognition, and by the late 1980s, more than 25 companies were involved.
Azar led TUDRP for 22 years while teaching drilling courses to hundreds of students and helping them publish technical papers as a direct result of the research at TUDRP.
Professor Stefan Miska, who initially taught at New Mexico Tech, joined TU in 1992 and succeeded Azar as TUDRP director in 1996. Miska continued to focus on Azar’s priorities while also expanding the research. The development of a flow loop system by Azar provided a location for new experiments, and Miska was eager to implement additional applications.
“I wanted to do more for the drilling industry,” he said. “I wanted to develop something that would be unique and useful.”
TUDRP began looking at all aspects of drilling mechanics and introduced new tools such as the Rock Mechanics Facility to better understand factors affecting the drilling rate and ultimately drilling costs. Current TUDRP resources include a low-pressure flow loop, advanced cuttings transport facility, drillpipe/coiled tubing buckling facility, full-scale testing rig, drillpipe fatigue testing facility, fluids characterization laboratory, small and large indoor flow loops, shale-fluid interaction test cell, triaxial rock mechanics testing facility, and others. The consortium team includes eight TU faculty members as well as research technicians, several consultants, and research assistants. To date, 170 projects have been completed, and 14 are in progress.
Technology Focus: Field Development Projects (October 2017)
Authors: Capello Maria A. 
Published: September 2017

Technology Focus
The new dynamics and strategies of field development are marked more than ever by the profitability considerations imposed by an extended period of low oil prices. The new market scenario has apparently cornered producers from the Organization of the Petroleum Exporting Countries to maintain their production volumes because reducing production to raise oil prices would trigger profitability levels for shale oil and nonconventional producers. Interweaved forces of precarious equilibrium affect field development and redevelopment plans.
The papers presented at main SPE conferences are grounded in this reality, and I found that a staggering number of articles by researchers and service and producing companies are related to theoretical and real-data economic modeling, with approaches rarely seen before, where the long-term profitability has acquired prime weight. Early assessments of the future reservoir response to enhanced-recovery systems need more-detailed, -reliable, and -precise fore-casts to enable decisions of ever-more-demanding investors and stakeholders in international and national oil companies. Development/redevelopment plans for new and established oil fields of any kind undergo a detailed screening of future performance in low-price scenarios, and further challenges to cost arise when producing from frontier areas or from reservoirs with different maturity levels at the same time or with environmentally challenged production systems.
The papers selected typify this new trend and exemplify several of the challenges experienced in new and mature oil fields. Paper SPE 181598 showcases challenges for offshore redevelopment in the Middle East to extend production for 25 years. Paper IPTC 18984 accounts for an incipient shale development in China, and paper SPE 182269 departs from the conventional net-present-value maximization and capital-expenditure minimization to explore alternative options for subsea-production-systems design.
The industry is evolving to a more factual approach to profitability, with emphasis in modeling the long-term scenarios with detail. And this applies for developments in both mature and new fields.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 182632 Model-Based Well-Location Optimization—A Robust Approach by B.A. Ramirez, Shell, et al.
OTC 27592 Johan Sverdrup—Creating a Unique Environment for Successful Drilling Operations in an Accelerating Spotlight Project by JÁkup øregaard, Statoil, et al.
SPE 184848 Optimizing Well Spacing and Well Performance in the Piceance Basin Niobrara Formation by N. Li, Black Hills Exploration and Production, et al.
Field Life Extension in Abu Dhabi Through Hybrid Development Concept
Authors: Wilson Adam 
Published: September 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181598, “Prospective Unlocking of Future Reserves in Offshore Abu Dhabi: Field-Life Extension Through Hybrid Development Concept,” by T. Nakashima, SPE, D. Ouzzane, SPE, G. Dudley, SPE, and M. Al-Marzouqi, ADMA-OPCO, prepared for the 2016 SPE Annual Technical Conference and Exhibition, Dubai, 26–28 September. The paper has not been peer reviewed.
Field A, a giant field consisting of many subreservoirs, is offshore Abu Dhabi and has produced for 50 years, mainly through peripheral water injection. A long-term development plan (LDP) for the field aims to extend the production plateau by 25 years through infill drilling and waterfloods. This paper describes an approach for optimizing the number and type of drilling centers required to enable the development plan to be flexible in design to accommodate infrastructure, facilities, drilling, and subsurface constraints.
Introduction
Field A, a giant carbonate field, has been developed for 50 years. As the field reaches maturity, it moves to another phase of development. Design of the next development phase, the LDP, began in the early 2010s. The LDP assessment stage, which screened the surface and subsurface development concept, was recently completed, and the development planning team is preparing for the selection stage. The assessment-stage conclusion was for drilling from artificial islands (AIs), wellhead towers (WHTs), or a combination of both and leaves a degree of freedom. This paper describes the optimization approach of the drilling-center options.
The LDP is just the first phase of a large-scale long-span offshore reservoir redevelopment that aims for a further 50 years of production. The complexity of the field is significant because of limited seabed space, the age of the existing surface facilities and pipelines, and challenging drilling circumstances.
These complexities differentiate the development project from other offshore projects, and an appropriate selection of drilling centers is one of the more important keys to project success.
Field and Development History
The field of carbonate reservoirs is in shallow water. The field is 40×20 km, and different reservoirs have been developed by two different operators. The stack of reservoirs is divided into shallower reservoirs (U Reservoirs) and deeper reservoirs (L Reservoirs).
The L Reservoirs are geologically divided into two major reservoirs, L1 and L2, which have been developed similarly. The development began with natural production with original reservoir energy. Beginning in the 1970s, pressure maintenance through dump flood-water injection by connecting the target reservoirs with a shallow aquifer was conducted for 10 years. For further reservoir-pressure maintenance, powered peripheral water injection was started, and the development scheme has been continuous, with reinforced pressure maintenance through immiscible gas injection from the top structure.
Natural-Language-Processing Techniques for Oil and Gas Drilling Data
Authors: Wilson Adam 
Published: September 2017

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 181015, “Natural-Language-Processing Techniques on Oil and Gas Drilling Data,” by M. Antoniak, J. Dalgliesh, SPE, and M. Verkruyse, Maana, and J. Lo, Chevron, prepared for the 2016 SPE Intelligent Energy International Conference and Exhibition, Aberdeen, 6–8 September. The paper has not been peer reviewed.
Recent advances in search, machine learning, and natural-language processing have made it possible to extract structured information from free text, providing a new and largely untapped source of insight for well and reservoir planning. However, major challenges are involved in applying these techniques to data that are messy or that lack a labeled training set. This paper presents a method to compare the distribution of hypothesized and realized risks to oil wells described in two data sets that contain free-text descriptions of risks.
Introduction
In the oil and gas industry, risk identification and risk assessment are critical. This holds particularly true during the drilling stages, which cannot begin before a risk assessment is conducted. While these risk assessments are typically conducted in a group setting, the project drilling engineer usually has a predetermined list of risks and likelihood scores that are the focus of the conversation.
One problem with this approach is that drilling engineers are inherently biased by personal experiences, which can affect their view on how likely an event is to happen. For example, if a project drilling engineer recently encountered well-control issues, the engineer will likely overestimate the chance of future well-control issues. On the other hand, if the engineer has never encountered a well-control issue, it may be unintentionally omitted altogether from the risk assessments.
Using historical data as a barometer could help the drilling engineer overcome these issues, though doing so requires a unified view of both prior risk assessments and prior issues encountered. Chevron maintains both data sets in disparate systems. The Risk Assessment database contains descriptions of risks from historical risk assessments, and the Well Operations database contains descriptions of unexpected events and associated unexpected-event codes, which categorize the unexpected events.
Leveraging both, a system has been created that allows a project drilling engineer to enter a risk in natural language, return drilling codes related to this risk, produce statistics showing how often these types of events have happened in the past, and predict the likelihood of the problem occurring in certain fields.