bluuebunny/crossref_metadata_2025_split huggingface dataset:
Technology Focus: Reservoir Performance and Monitoring (September 2018)
Authors: Livescu Silviu 
Published: October 2018

Technology Focus
Since the last Reservoir Performance and Monitoring feature in 2017, the industry has continued to advance with innovation in technology and business models to drive sustainable change. Operators around the world have continued lowering production costs aggressively, and oilfield service companies have continued to survive by making a low-margin profit in a greatly competitive market. If the industry until recently was lamenting an oversupply of oil and that a global upstream investment slump caused a focus on incremental technology improvements with fewer capital resources and personnel, now a looming oil-supply shortage has reignited discussions about how innovation, digital technologies, and collaborations can accelerate future major project development.
In the last 12 months, 157 technical papers were presented at various conferences and meetings with reservoir performance and monitoring programs and were reviewed for this feature. For comparison, 160 were reviewed for the 2017 feature. Interestingly, 62 papers had first authors from academia, 70 from operating companies, and 25 from oilfield services companies and consulting firms. Sixty-three papers had authors with different affiliations.
The six papers selected and recommended as additional reading are a representative sample of the papers reviewed for this feature. They are a geographically diverse mix of fundamental research, industrial research and development, and field-application studies, reporting the latest published advances in reservoir-performance monitoring, analysis, and optimization.
In considering the 157 technical papers reviewed for this feature, I am looking forward to seeing how our industry is going to react through innovation and digital technologies to the supply and demand changes of coming years. A new era of operational efficiency improvements, improved recovery factors, and lower production costs from continuous reservoir performance monitoring, analysis, and optimization is ready to begin.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 188890 Effect of Irreversible Retention on Tracer Deployments: Constraining Novel Material Deployments by Hsieh Chen, Aramco, et al.
SPE 189846 Applying Subsurface DNA Diagnostics and Data Science in the Delaware Basin by J. Silva, Anadarko, et al.
SPE 190480 Effect of Dilution on Acoustic and Transport Properties of Reservoir Fluid Systems by Ram R. Ratnakar, Shell, et al.
Technology Focus: Drilling Systems Automation and Management (September 2018)
Authors: Macpherson John 
Published: October 2018

Technology Focus
Signs of maturity in drilling systems automation are evident in the success stories filtering out of technical conferences and in the attraction of top university talent to an annual, international, drilling-systems-automation contest.
This international university competition is focused on designing an automated (push-the-button) drilling rig. It is sponsored by the SPE Drilling Systems Automation Technical Section and is referred to as Drillbotics (www.drillbotics.org). It is not only about automating equipment, however. The system must drill a quality hole in a block of unknown composition. The competition has raised aware-ness of drilling systems automation in academia and now shares space with an elite group of university competitions, among them Shell’s Eco-marathon and SpaceX’s Hyperloop.
Drilling-systems-automation products are now being released commercially. These are primarily focused on drilling optimization and wellbore positioning. Several approaches are being considered for the latter—automated placement of the wellbore in 3D space—including auto-mated slide drilling and automated use of rotary steerables. The benefit of these systems is becoming obvious as demanned and even unmanned directional-drilling operations are starting to take hold in the US land environment.
A couple of upcoming drilling-systems-automation sessions are of interest. The first is at the SPE Annual Technical Conference and Exhibition, 24–26 September, in Dallas addressing “The Automation of Well Placement.” The focus is on the successful integration of multiple technologies to allow the next steps in automated directional drilling: geosteering and reservoir navigation. The second is a session on the “Digital Twin for Drilling” at the SPE/IADC Drilling Conference and Exhibition, 5–7 March 2019, in The Hague. As described by the conference, “a digital twin integrates real-time data with both physics-based and data-driven models of a physical asset to create a dynamic understanding and optimization of its design, operation, performance, and maintenance.”
As you can see, significant progress is occurring in drilling systems automation, and I hope you can participate in both sessions guiding systems automation for drilling and as a Drillbotics volunteer guiding the talent for the future of the industry.
Recommended additional reading at OnePetro: www.onepetro.org.
IADC/SPE 189653 Reducing Stick/Slip by Avoiding Autodriller-Control Dysfunction by Derek Adam, Occidental, et al.
IADC/SPE 189691 Automated Directional Drilling Software and Remote Operations Centers Drive Rig Fleet Well Delivery Improvement by Colin Gillan, Nabors Industries, et al.
SPE 187447 Challenges and Lessons From Implementing a Real-Time Drilling Advisory System by Benjamin J. Spivey, ExxonMobil, et al.
New Geosteering Work Flow Integrates Real-Time Measurements With Geomodels
Authors: Wilson Adam 
Published: October 2018

This article, written by Special Publications Editor Adam Wilson, contains highlights of paper SPE 191337, “An Interactive Decision Support System for Geosteering Operations,” by Sergey Alyaev, IRIS; Reidar Brumer Bratvold, SPE, University of Stavanger; and Xiaodong Luo, SPE, Erich Suter, SPE, and Erlend H. Vefring, SPE, IRIS, prepared for the 2018 SPE Norway One Day Seminar, Bergen, Norway, 18 April. The paper has not been peer reviewed.
To place a well in the best possible reservoir zone, operators use geosteering to support real-time well-trajectory adjustments. Geosteering refers to the process of making directional well adjustments on the basis of real-time information acquired while drilling. This work presents a systematic geosteering work flow that automatically integrates a priori information and real-time measurements to update geomodels with uncertainties and uses the latest model predictions in a decision-support system (DSS). The DSS supports geosteering decisions by evaluating production potential against drilling and completion risks.
Introduction
This paper presents a consistent, systematic, and transparent work flow for geosteering. The starting point is a priori information, for example a probabilistic geomodel representing a geological interpretation based on surface seismic and logs from offset wells, including relevant interpretation uncertainties. Multiple geomodel realizations of the possible geological scenarios span the space of interpretation uncertainties. The real-time measurements obtained while drilling are continually integrated by updating the realizations automatically using an ensemble-based filtering method. The real-time update of the realizations leads to a reduction in interpretation uncertainty, providing up-to-date predictions of the geology ahead of the bit consistently. The update work flow is linked to a DSS. The DSS applies the probabilistic up-to-date geomodel to support geosteering decisions under uncertainty by evaluating the chosen value function of the well. The value function commonly includes multiple objectives, including production potential, costs for drilling and completion, and risks associated with the operation. The DSS presented here is optimized specifically for use with ensemble-based update work flows that are increasingly popular in the oil industry.
The focus of this paper is the DSS. The DSS suggests steering correction or stopping, optimizing well trajectories over the ensemble of up-to-date geomodel realizations. A graphical user interface (GUI) enables geosteering experts to control the input to the DSS by means of interactive selection and adjustment of value functions and constraints (e.g., dogleg severity). The adjustments are applied in a matter of seconds using advanced dynamic programming algorithms that yield consistently updated decisions. The proposed steering decision is communicated through the GUI, which contains a visual representation of the current uncertainty and trajectory possibilities that give the best value for each realization.
BP and Startup Beyond Limits Try To Prove That Cognitive AI Is Ready for Oil and Gas
Authors: Jacobs Trent 
Published: October 2018

BP has invested more than $100 million into nine different startup companies in the past 2 years—but only one of them wants to turn your brain into a piece of its software.
The international major is working with the ambitiously named firm Beyond Limits on a set of artificial intelligence (AI) programs that will absorb the learnings of geologists and petroleum engineers, and then imitate their decision-making processes as they work on subsurface challenges together.
Before this partnership, Beyond Limits had never been involved in solving the complexities of oil and gas, which is something that might be counted against it by venture capital or prospective upstream clients. But after BP saw what the young company was working with in its office about 10 miles north of downtown Los Angeles, it decided to become both its largest client and its largest investor by injecting it with $20 million a year ago.
The attraction for BP came down to getting its hands on a strain of AI known as cognitive computing, or what Paul Stone refers to as “the pinnacle of the artificial intelligence pyramid.”
“We haven’t seen that elsewhere, so we wanted to be the first to engage and see where it might go in the oil and gas industry,” said Stone, who serves as a technology director in BP’s digital innovation group.
And where it lacks a prior track record in oil and gas, Beyond Limits compensates with a technology team that helped design most of the same intelligent software it is licensing from the Jet Propulsion Laboratory ( JPL), an institution run by the influential California Institute of Technology in cooperation with NASA. Similar to oil and gas explorers, at JPL immense uncertainty is the perpetual driver for emerging technologies.
AJ Abdallat has served as chief executive officer of Beyond Limits since its founding in 2014 and previously spear-headed several other startups that have been spun out of work first done at JPL. He believes that this firm’s pedigree gives it a big head start in pushing the envelope on cognitive computing because “the issues and challenges we are tackling today, JPL has been tackling for decades.”
And though there remains a lively debate about where cognitive computing really stands today in terms of its human-like reasoning capabilities, Abdallat said, “People tend to judge AI based on the last 2 or 3 decades—you really need to look at what has happened in the past 5 to 6 years.”
Some of the most notable recent advancements include the AI sector proving that intelligent programs can best human reasoning when it comes to complex games such as Go and Texas Hold’em Poker. Cognitive programs also demonstrate growing promise as a diagnostic tool in the healthcare industry—a vertical that Beyond Limits is positioning itself to break into along with oil and gas.
Shell, Bluware Team Up on Seismic With Video Game Tech
Authors: Jacobs Trent 
Published: October 2018

Looking for oil and gas is becoming a lot more like a video game.
This is the unique intersection where Houston-based Bluware stands. The software company is among a handful of first movers in the upstream industry that see the use of GPUs, or graphics processing units, as the way to eliminate all the wasted time spent waiting for seismic data to be visualized.
GPUs have been around for decades, but only in the past few years have they become one of the most talked-about pieces of computing hardware in the digital tech scene.
Their uptake was initially driven by the need to quickly render graphically rich video games, especially first-person shooters, and enable players sitting around the world to co-play online without lag. Others have since awoken to the potential of GPU technology, which is now accelerating the development of driverless cars and represents the computing muscle behind cryptocurrency markets.
In the modern video game setting, any significant latency in processing might mean game over. “Whereas in oil and gas, if you have to wait another half an hour to get a seismic line to load, you just go get a cup of coffee,” Bluware Chief Executive Officer Dan Piette said.
If that time is given back, those coffee breaks may be the thing put on hold as seismic processing ceases to be a major bottleneck. Bluware says on its website that it can shave several months off the typical seismic project.
Piette said this could translate into operators gaining the inside track on bidding for offshore blocks that their competitors might bypass simply because of using slower interpretation methods that rely on traditional hardware.
More Seismic, Fewer Eyeballs
And even though the industry downturn hit offshore exploration budgets as hard as any other part of the service business, Bluware sees plenty of opportunities for its cloud platform that also incorporates machine-learning tools to help automate key parts of subsurface characterization workflows.
The company estimates that global producers are sitting on at least 1.5 exabytes of seismic data sets that can be reprocessed with modern technology to find more oil and gas. To put the volume of this data into perspective, an exabyte is equal to more than 1,000 petabytes while a high-resolution offshore survey in the Gulf of Mexico might sail home with between 1–2 petabytes.
Piette argues that this inventory of data is only getting bigger in size, and that the lasting effects of the down-turn mean there are not enough technical professionals to interpret it all. “You can’t have 50 geophysicists looking at one petabyte of data and come up with the answer anymore—you need one geophysicist looking at 50 petabytes of data,” he said.
Technology Focus: Field Development Projects (October 2018)
Authors: Capello Maria A. 
Published: October 2018

Technology Focus
Maximizing recovery and production used to be the main goal of field development plans, but that may be in the past. Extended periods of low oil prices and the incumbent use of data-driven work flows have triggered changes in the development of field development plans toward maximizing economic margins.
Recent advances in field development are not based on specific technical breakthroughs (although shale oil and gas and deep oil owe a lot to those) but on economic models and scenarios run at the very beginning, before any dollar is invested. This is true for companies large or small, public or private, and for national oil companies.
Major SPE conferences in 2017 and 2018 were hubs for numerous technical papers that portray the new trends in field development, such as basing decisions on the analysis of economic models and profitability elements. Certainly, operating companies are migrating from complex, lengthy, and bureaucratic approaches to capital-expenditure (CAPEX) decisions and approvals for field development plans to more data-driven decisions based on economic analysis using new tools.
Artificial intelligence, supervised/ guided machine learning, and massive and advanced data analytics play fundamental roles in the preparation of new field development plans, where well, field, and facilities information is shaped into high-resolution models that consider the micro and the macro elements. What previously was considered luxurious, such as high-resolution 3D seismic data and digital technologies, has become fundamental. Focusing on the maximization of margins using data-driven work flows enables better decisions at the field development stage and has yielded dramatic CAPEX/operational-expenditure optimizations and reductions, shrinking the time to first oil and triggering approvals of plans quicker.
I am confident you will enjoy reading these articles outlining the new trends in field development. The industry is evolving toward a data-driven approach to profitability, and we need to catch the wave.
Recommended additional reading at OnePetro: www.onepetro.org.
OTC 28791 Optimized Field Development Through Integrating Field Network With Dynamic Reservoir Model by Mahanaz Hatvik, TechnipFMC, et al.
SPE 190239 Machine-Learning-Based Optimization of Well Locations and WAG Parameters Under Geologic Uncertainty by Azor Nwachukwu, The University of Texas at Austin, et al.
OTC 28970 A Universal Field Development Approach for Advancing Stalled GOM Deepwater Projects by Richard D’Souza, Granherne, et al.
Technology Focus: New-Frontier Reservoirs II (October 2018)
Authors: Kalfayan Leonard 
Published: October 2018

Technology Focus
With the recent increase in new-well activity in unconventional reservoirs and the well-factory approach, a natural limitation exists in the capacity for implementing hydraulic-fracturing optimization. An even greater limitation exists with the consideration of stimulating production from existing wells in decline. Great strides have been made in drilling and completion efficiencies and well-cost reduction during the past several years. That focus has been most important in the lower-for-longer oil-price environment we have fought through.
Naturally, that focus has, to some extent, limited alteration of initial-stimulation design—for example, with respect to fracture-stage sizes, fracture-spacing optimization, and proppant types and volumes. Furthermore, restimulation of existing wells is not an area that has received as much attention as other areas, and, where it has, the focus has been on simply repeating refracturing with proppant. Remedial chemical-treatment options have not been explored to a significant extent, especially at the field level. Instead, greater attention has been placed on how to make the leap from primary production achieved from initial well completion to field-scale enhanced oil recovery (EOR). The in-between measure of remedial production enhancement in existing wells is largely being skipped.
With low primary-recovery rates in unconventional reservoirs and the longer-term development prospects for EOR applications on a fieldwide scale, the potential for accelerated completion optimization in new wells and production-enhancement treatments in existing wells is substantial and perhaps comes with more immediate returns.
Along those lines, the first of three papers featured this month addresses the optimization of fracture spacing and penetration ratio in unconventional reservoirs. The other two papers discuss studies related to remedial production and recovery improvement in existing wells—surfactant soak and flowback treatments in oil-bearing formations and solvent treatments for water and condensate blockage in tight formations, respectively.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 189805 Dual-Permeability Matrix-Fracture Corefloods for Studying Gasflooding in Tight Oil Reservoirs by Peng Luo, Saskatchewan Research Council, et al.
SPE 190214 Underlying Mechanisms of Tight Reservoir Wettability and Its Alteration by Peng Luo, Saskatchewan Research Council, et al.
SPE 187542 Limitation of EOR Applications in Tight Oil Formation by Ahmed Mansour, Texas Tech University, et al.
Technology Focus: Sand Management and Sand Control (October 2018)
Authors: Wang Xiuli 
Published: October 2018

Technology Focus
Rig count and fracturing-crew activity are the pulse of the energy industry; as energy commodity prices increase, so do these vital numbers.
During the past year, crude oil prices jumped 36% from $49.59/bbl (WTI) at the beginning of August 2017 to $67.68/bbl on 1 August 2018, with a maximum price of approximately $74/bbl in late June 2018.
The price increase experienced during the past year has renewed investments in many plays. However, a long-term project, such as offshore deepwater field developments, would require a minimum sustainable oil price to be profitable. We, therefore, have not seen massive investment in developing challenging sand-prone fields that require large capital investment up front to complete wells with expensive and sophisticated sand-management and -control techniques. Perhaps the demand has not yet justified sustainable prices, leading some oil companies to rebalance capital allocation by increasing dividend payouts or stock repurchasing programs while waiting for the market forces to establish a price benchmark.
In this respect, in the energy industry, no news very often is the best news; any geopolitical instability and tensions could cause oil prices to fluctuate abruptly and make operators feel uneasy about investing in capital-intensive projects.
On the technology side, regardless of the oil price, demand persists for cost-saving and value-adding innovations and emerging technologies to bridge gaps in the existing technology portfolio for sand management and control.
To stay in the know of the latest projects trending in the energy industry, read the featured papers and recommended additional reading and attend the upcoming 2018 SPE Annual Technical Conference and Exhibition 24–27 September in Dallas and the Asian Pacific Oil and Gas Conference 23–25 October in Brisbane, Australia.
Recommended additional reading at OnePetro: www.onepetro.org.
SPE 187237 Self-Assembling Nanoparticles: A Unique Method for Downhole Sand Consolidation by Rajendra Kalgaonkar, Saudi Aramco, et al.
SPE 189491 Openhole Mechanical Packer With Eccentric Shunt-Tube Gravel-Pack Assembly Reduces CAPEX and Accelerates Production in Laombo Deepwater Development, Angola by J. Hernandez, Total, et al.
SPE 189557 A Large-Scale Sand-Retention Test Facility for Evaluation and Selection of Optimal Standalone Sand Screen for Injection Wells in Thermal Operations by M. Mahmoudi, RGL Reservoir Management, et al.
Stimulation of High-Temperature Steam-Assisted-Gravity-Drainage Production Wells Using a New Chelating Agent (GLDA) and Subsequent Geochemical Modeling Using PHREEQC
Authors: Ameur Z. Ouled , Kudrashou V. Y. , Nasr-El-Din H. A. , Forsyth J. P. , Mahoney J. J. , Daigle B. J. 
Published: October 2018

Summary
The acidizing of sour, heavy-oil, weakly consolidated sandstone formations under steam injection is challenging because of fines migration, sand production, inorganic-scale formation, corrosion issues, and damage caused by asphaltene precipitation associated with these sandstone formations. These and other similar problems cause decline in the productivity of the wells, and there is a recurring need to stimulate them to restore productivity. The complexity of sandstone formations requires a mixture of acids and several additives, especially at temperatures up to 360°F, to accomplish successful stimulation. Three treatments were tested on a horizontal well in the field: hydrochloric acid (HCl); Chelating Agent B, a high-pH chelant; and Chelating Agent A, or glutamic acid Ν,Ν-diacetic acid (GLDA). The first two treatments with 15 wt% HCl and high-pH (pH = 10) Chelating Agent B produced results below expectations. The third treatment using GLDA was successful, and the well productivity increased significantly. The field treatment with GLDA included pumping the treatment fluid, which was foamed to create proper rheological characteristics and a better-controlled pumping process. The treatment fluids were displaced into the formation by pumping produced water and were allowed to soak for 6 hours. In this paper, we evaluate the field applications of GLDA using geochemical modeling, production data, and analysis of well-flowback fluids after the field treatments.