bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Formation Evaluation (August 2018)
Authors: Ma Shouxiang (Mark) 
Published: October 2018

Technology Focus
The future is here; a machine can learn games and beat the world’s best players. What a fascinating time we are living in—Industrial Revolution 4.0.
In December 2017, news broke that AlphaZero decisively beat the world’s best players in chess after its older sibling, AlphaGo, defeated the world champions in the ancient game of go a couple of years earlier. These games have been won by machine learning and artificial intelligence.
What effects will Industrial Revolution 4.0 have on the upstream oil and gas business in general and petrophysics in particular? We should see more intelligence and automation in measurements, processes, work flows, and operations, which should result in more-consistent results, better-quality answer products, and less nonproductive time (i.e., improved quality, efficiency, and productivity with less cost).
Historically, petrophysics is based on physical principles or empirical relationships, as illustrated in paper SPE 191296 on predicting crude-oil viscosity. With Industrial Revolution 4.0, a new era in petrophysics has begun. The logging tools are smarter (as demonstrated in paper SPE 190062 dealing with environmental corrections to some of the deliverables of pulsed-neutron logs that can be performed automatically). And the operational and data-interpretation work flows are more automated (as shown in paper SPE 187040, which details formation testing and sampling jobs that can be done semiautomatically through standardizing terminologies, measurement uncertainties, and data quality-control criteria).
In playing games such as go and chess, machines learn on the basis of man-made game rules. In petrophysics, rules are often data-driven, so data quality becomes critically important. It is always true that having bad data is worse than having no data.
Density, representativeness, and coverage are other parameters of the data besides data quality that are required for data-driven petrophysics.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 189807 Characterization of Reservoir Quality in Tight Rocks Using Drill Cuttings: Examples From the Montney Formation, Alberta, Canada by A. Ghanizadeh, University of Calgary, et al.
SPE 188804 Low-Resistivity Pay Identification in Lower Cretaceous Carbonates, Onshore UAE by J.L. Ruiz, ADCO, et al.
SPE 187371 Saturation Mapping in the Interwell Reservoir Volume: A New Technology Breakthrough by Alberto F. Marsala, Saudi Aramco, et al.
Three Unconventional Startups Offer New Clues on Shale’s Biggest Well Spacing Mysteries
Authors: Jacobs Trent 
Published: October 2018

It can be fairly argued that the most important question being asked today by shale producers is: How close can horizontal wells be placed together? The right answer is worth billions of dollars to the sector.
Among the unsolved mysteries with well spacing are how and why hydraulic fractures from neighboring wells interact with each other. These events, described as frac hits, can be beneficial to oil production (as has been documented in the Bakken Shale) but the more pressing concern is focused on the cases where they harm production (often the case in the Permian Basin and Eagle Ford Shale).
Petroleum engineers know that production-depleted zones within their reservoirs play a big role, but predicting the effects this has on their well designs will require completely new diagnostic approaches.
To solve this grand challenge, an increasing number of industry startups have put their technologies, ones originally developed with a different purpose in mind, under the microscope. The clues they have discovered so far could reshape how the industry understands highly complex shale plays—where profits and losses can be decided by landing a well 100 ft in one direction or the other.
These young companies are among those coming up with some of the most compelling pieces to the puzzle. Fracture ID invented a measurement-while-drilling tool that can detect depleted reservoir sections; Reveal Energy Services has a monitoring system that may be able to diagnose interwell fracture activity; and ResFrac Corp. is using its new modeling software to help operators better estimate permeability, which ties right into well spacing and fracture cluster design.
Can You Measure Depletion While Drilling?
Founded in 2014, Fracture ID offers a new service called “drill bit geomechanics” that could become an early warning system for frac hits caused by pressure and hydrocarbon depletion from older producing wells.
The wellbore-focused service has been used by more than three dozen operators to improve on several different aspects of completion efficiency, including helping to make sure proppant effectively moves into perforations.
While a lot of its work is focused on what is happening around the wellbore, over the course of its 350-well track record the company has determined, “what we’re measuring in the near-field has some extension out into the farfield,” said Chris Neale, the chief executive officer and founder of Fracture ID.
He explained that the downhole data the firm gathers during drilling show correlations to the pressures that operators monitor during and after stimulating a fracture stage. This relationship is seen as one key to predicting which stages will most likely lead to fracture interference.
At the core of Fracture ID’s service is a foot-long accelerometer device that sits behind a drill bit and enables the Denver-based firm to translate drilling vibrations into critical rock descriptions, including stress and strain, two performance-driving factors for completions.
Getting to Zero and Beyond
Authors: Hinton Jack 
Published: October 2018

The Society of Petroleum Engineers (SPE) technical report, Getting to Zero and Beyond: The Path Forward, sets the stage for continuing the discussion across the industry of the essential actions the industry must undertake to attain and sustain zero harm. The report is a compilation of discussions from various SPE sessions and expands on those discussions to identify and evaluate actions that may aid the industry by exploring current thinking and views; incorporating experiences and learnings from other industries that are mature in the application of human factors; and suggesting the next steps that will enable the oil and gas industry to meet an expectation of zero harm.
Introduction
The goal of health, safety, and environment (HSE) programs and departments is to eliminate incidents that produce harm whether to people, the environment, or property. But somehow the industry has settled into a comfort zone, a zone that tolerates incident occurrence and satisfaction with incremental improvement.
Phrases such as “you should have seen the way it was before” or “but we are better than we were” are heard and some-how enable us to accept that what we are doing is sufficient, good, and OK.
Industry safety statistics were the subject of an analysis conducted using International Association of Oil & Gas Producers (IOGP) member company annual safety data. The findings showed that in the period from 2014 to 2016, the lost-time injury frequency and total recordable injury frequency both posted an incremental decrease (Fig. 1). However, during the same period, the fatal accident rate showed an increase (Fig. 2).
In June, IOGP released its annual Safety Performance Indicators for 2017. Although the 2017 statistics illustrate an improvement in the number of fatalities, the number of fatal incidents increased in 2017 (IOGP 2018).
Most striking is the realization that the top three causes of fatal incidents that occur in the global upstream oil and gas industry have remained the same since IOGP first began collecting the data in 2010. Fundamentally, fatalities are occurring despite the industry implementing traditional HSE efforts such as IOGP’s Life-Saving Rules, management systems, training programs, and targeted injury campaigns. What needs to occur is to challenge the current mindset, the ingrained culture. What if we could reject this incremental mindset and make the leap to be satisfied only when we are attaining and sustaining zero harm?
That is exactly what a group of SPE members did. They united, starting in 2010, to change industry thinking—to challenge incremental HSE performance improvement, and to create “zero thinking,” not as the end or long game, but as the starting point to defining HSE performance. Their work and efforts have culminated into a recently issued SPE technical report titled Getting to Zero and Beyond: The Path Forward.
From the SPE President: Oil and Gas Industry: Bringing Prosperity and Happiness to the World
Authors: Alnuaim Sami 
Published: October 2018

President's column
I vividly recall a trip with my family when I was 10 years old from my hometown Hofuf to Dammam city on the east coast of Saudi Arabia. This was the early 1970s, and we passed through the northern part of Ghawar, the largest oil field in the world. We also drove through Abqaiq city, which was established by Aramco as a crude-handling facility. During that trip I was wondering what oil and gas would bring to me and to my country, Saudi Arabia. During that time, Saudi Arabia was at the initial stage of educational, industrial, and scientific evolution, trying to catch up with the more advanced West. I remember Saudi Aramco (Aramco back then) was the company where most of the people in Eastern Province of Saudi Arabia dreamt of working. Not only was Aramco a source of a reliable job with good pay, but also health, education, sport, food, and entertainment. To my generation in Saudi Arabia, the oil and gas industry was everything a young person dreamt of. During that trip, while gazing through the drilling rigs and flares on both sides of the highway at night, I created for myself a goal to be part of this great industry.
My thoughts back then were limited to myself and my family, hoping for more economic prosperity and happiness. Today, after 45 years, I can observe how oil and gas has brought economic prosperity not only to myself and my family, but to my country. I also see the positive impacts globally.
Saudi Arabia has evolved in a very short time to be one of the top developing countries, one of the top 20 global economies, primarily because of oil and gas. In a few decades, Saudi Arabia achieved extraordinary advancements in many areas—economy, health, education, manufacturing, agriculture, sport, and entertainment. It isn’t just exporting countries though. South Korea is an example of an importing country that has also developed due to oil and gas. Imported energy supplied the fuel for its development in advanced electronics, automobiles, and heavy industry. In mid-March, the SPE Board of Directors held a meeting in Ghana. Just days before, The New York Times published an article projecting that Ghana will be the world’s fastest-growing economy in 2018. This is primarily due to the recent offshore natural gas discoveries and the high potential for more oil and gas development in the region. Like many parts of Africa, Ghana does not have a countrywide electrical grid, and most current electric power comes from diesel major changes in the quality of the environment and the lives of people throughout Ghana. A number of other African countries have also had recent discoveries, meaning that even more people may benefit as these resources are developed.
Guest Editorial: Growth in Unconventional Resources Adds to Technical Literature
Authors: Teletzke Gary 
Published: October 2018

Guest editorial
Unconventional resources require technologies typically not used to produce conventional oil and gas reservoirs. In particular, starting in the late 1990s, the combination of horizontal wells and multistage hydraulic fracturing has been key to rapidly increasing success in exploiting unconventional resources. While the well completions in unconventional resources may be more expensive than those typically applied in conventional reservoirs, the advantage is access to the very large volumes of these resources, which include tight (low-permeability) gas in sandstone or carbonate rock, coalbed methane, and organic-rich source rocks classed as shale gas and tight oil.
The exploitation of shale gas, along with tight gas and coalbed methane, enabled a stunning increase in US natural gas production of approximately 4 Tcf/D from 2005 to 2010. A similar story followed a few years later for US crude oil production. Tight oil production ramped up nearly 5 million B/D over approximately 5 years, starting in 2008, and continues to rise. And it is not just the US that is benefiting—unconventional resource development is now beginning to spread to other countries around the world.
The technologies that accomplished these near miracles were developed, implemented, and continue to be improved largely by SPE members, and this has been reflected in an upsurge in conference presentations and journal publications related to unconventional resources over the past decade. This is illustrated by the chart (Fig. 1), which shows a dramatic increase in the percentage of peer-reviewed papers related to unconventional resources published in SPE Reservoir Evaluation & Engineering (SPEREE) beginning in 2011. Before 2011, there were only a handful of publications related to unconventional resources each year, primarily dealing with coal-bed methane and fundamentals of fluid flow in tight pore systems. Beginning in 2011, publications related to the analysis and prediction of shale gas reservoir production performance showed a sharp increase, followed a few years later by publications related to tight oil reservoir performance analysis and prediction. In addition, enhanced oil recovery from tight oil reservoirs has become an increasing area of focus. This year, over half of the publications in SPEREE will be related to unconventional resources. As further indication of the increasing importance of unconventional resources, in July SPE released Unconventional Gas and Tight Oil Exploitation, the first SPE monograph devoted exclusively to the topic.
A Study of Proppant Transport With Fluid Flow in a Hydraulic Fracture
Authors: Blyton Christopher A. , Gala Deepen P. , Sharma Mukul M. 
Published: October 2018

SummaryThe effective placement of proppant in a fracture has a dominant effect on well productivity. Existing hydraulic-fracture models simplify proppant-transport calculations to varying degrees. A common assumption applied is that the average proppant velocity caused by flow is equal to the average carrier-fluid velocity, while the settling-velocity calculation uses Stokes’ law. To more accurately determine the placement of proppant in a fracture, it is necessary to account for many effects not included in previous assumptions.In this study, the motion of particles flowing with a fluid between fracture walls is simulated with a coupled computational-fluid-dynamics/discrete-element method (CFD/DEM) code that uses both particle dynamics and CFD calculations to account for both particles and fluid. These simulations (presented in metric units) determine individual particle trajectories as particle-to-particle and particle-to-wall collisions occur, and include the effect of fluid flow. The results show that the ratio of proppant diameter to fracture width governs the relative average velocity of proppant and fluid.A proppant-transport model developed from the results of the direct numerical simulations and existing correlations for particle-settling velocity has been incorporated into a fully 3D hydraulic-fracturing simulator. This simulator couples fracture geomechanics with fluid-flow and proppant-transport considerations to enable the fracture geometry and proppant distribution in the main hydraulic fracture to be determined. For two typical shale-reservoir cases, the proppant placement and width distribution have been determined, allowing comparison at the hydraulic-fracture scale, including effects observed at the particle scale. This allows for optimization of the treatment to a specific application, and the results are presented in oilfield units, considered more familiar to our readers.
Thermodynamic Analysis of Phase Behavior at High Capillary Pressure
Authors: Rezaveisi Mohsen , Sepehrnoori Kamy , Pope Gary A. , Johns Russell T. 
Published: October 2018

Summary
High capillary pressure has a significant effect on the phase behavior of fluid mixtures. The capillary pressure is high in unconventional reservoirs because of the small pores in the rock, so understanding the effect of capillary pressure on phase behavior is necessary for reliable modeling of unconventional shale-gas and tight-oil reservoirs. As the main finding of this paper, first we show that the tangent-plane-distance method cannot be used to determine phase stability and present a rigorous thermodynamic analysis of the problem of phase stability with capillary pressure. Second, we demonstrate that there is a maximum capillary pressure (Pcmax) where calculation of capillary equilibrium using bulk-phase thermodynamics is possible and derive the necessary equations to obtain this maximum capillary pressure. We also briefly discuss the implementation of the capillary equilibrium in a general-purpose compositional reservoir simulator. Two simulation case studies for synthetic gas condensate reservoirs were performed to illustrate the influence of capillary pressure on production behavior for the fluids studied.
Novel Application of Cationic Surfactants for Foams With Wettability Alteration in Oil-Wet Low-Permeability Carbonate Rocks
Authors: Ghosh Pinaki , Mohanty Kishore K. 
Published: October 2018

Summary
Carbonate rocks are typically heterogeneous at many scales, leading to low waterflood recoveries. Polymers and gels cannot be injected into nonfractured low-permeability carbonates (k &lt; 10 md) because pore throats are smaller than the polymers. Foams have the potential to improve both oil-displacement efficiency and sweep efficiency in such carbonate rocks. However, foams have to overcome two adverse conditions in carbonates: oil-wettability and low permeability. This study evaluates several cationic-foam formulations that combine wettability alteration and foaming in low-permeability oil-wet carbonate cores. Contact-angle experiments were performed on initially oil-wet media to evaluate the wettability-altering capabilities of the surfactant formulations. Static foam-stability tests were conducted to evaluate their foaming performance in bulk; foam-flow experiments (without crude oil) were performed in porous media to estimate the foam strength. Finally, oil-displacement experiments were performed with a crude oil after a secondary gasflood. Two different injection strategies were studied in this work: surfactant slug followed by gas injection and coinjection of surfactant with gas at a constant foam quality. Systematic study of oil-displacement experiments in porous media showed the importance of wettability alteration in increasing tertiary oil recovery for oil-wet media. Several blends of cationic, nonionic, and zwitterionic surfactants were used in the experiments. In-house-developed Gemini cationic surfactant GC 580 was able to alter the wettability from oil-wet to water-wet and also formed strong bulk foam. Static foam tests showed an increase in bulk foam stability with the addition of zwitterionic surfactants to GC 580. Oil-displacement experiments in oil-wet carbonate cores revealed that tertiary oil recovery with injection of a wettability-altering surfactant and foam can recover a significant amount of oil [approximately 25 to 52% original oil in place (OOIP)] over the secondary gasflood. The foam rheology in the presence of oil suggested propagation of only weak foam in oil-wet low-permeability carbonate cores.
Unlocking the Potential of the Monterey Shale Resource: An Analysis of Geological Characteristics, Completion Techniques, and Production Behaviors
Authors: Saini D.. , Wright J.. , Mantas M.. , Gomes C.. 
Published: October 2018

Summary
A critical analysis of the key geological characteristics, completion techniques, and production behaviors of the Monterey Shale wells and their comparisons with analogous major US shale plays—namely, the Bakken and the Eagle Ford—may provide insights that could eventually help the petroleum industry unlock its full potential. The present study reports on such efforts.
The Monterey Shale is very young and geologically heterogeneous compared with the Eagle Ford and the Bakken. Oil viscosity in the Monterey Shale is significantly higher, and one can also notice that Monterey oil production has declined over the years. The Monterey Shale has a field-dependent completion strategy (pattern spacing and fracturing stage), while a horizontal, uncemented wellbore completion is common in the Bakken and the Eagle Ford. In the Monterey, nonhydraulically fractured zones of horizontal and hydraulically fractured wells appear to be making approximately equal contributions to the well's cumulative production. The ongoing water-disposal operations in overlying injection zones, up to a certain extent, have affected the productivity of both types (long and short production histories) of wells. The geology also appears to have an effect on the production behaviors of horizontal and hydraulically fractured wells.
A preliminary economic analysis suggests that exploitation of the Monterey Shale is still a profitable venture. However, for sustainable development in a current price regime of USD 50/bbl of crude oil, it is necessary that production costs be reduced further. Also, compared with the Bakken and the Eagle Ford, the Monterey sits in regions of extremely high water stress (i.e., frequent occurrences of drought or drought-like conditions). However, oilfield-produced water associated with current steamflooding-based oil- and gas-production operations in the region as a base fluid suggests that it can potentially meet most of the water demand for future fracturing jobs. Also, combined use of a centralized water-management system; a less-costly, more energy-efficient, and high-capacity solar-powered desalination system; and a final sludge-management and/or residual-brine-disposal mechanism might assist the petroleum industry in managing flowback and produced waters while keeping water-handling costs low.
A combination of new enhanced-oil-recovery (EOR) methods for releasing the remaining oil from both nonfractured and fractured zones of horizontal wells and the use of oilfield-produced and recycled water for completing hydraulically fractured horizontal wells might prove to be a significant change for the future exploitation of California's Monterey Shale resource, which is subject to the toughest hydraulic-fracturing regulations in the nation and is in a region of extremely high water stress.