bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pre-Loads: Successful Mitigation of Damaging Frac Hits in the Eagle Ford
Authors: Whitfield Tom , Watkins M. Hunter , Dickinson L. James 
Published: October 2018

Abstract
Although infill drilling and tighter well spacing have improved the production and economic return for North American Shale leases, these practices have intensified a problematic side effect often referred to as Frac Hits (Jacobs 2017). Frac hits occur when a new ‘child’ well is completed near an already producing well and the frac treatment interacts with the older parent well, usually resulting in either total loss of production or diminished producing capacity (King et al. 2017). In some fields, such as the Haynesville, frac hits have been reported to improve parent well production (Esquivel & Blasingame 2017). However, as these wells produce longer in to their life cycle, that positive impact is less certain to result in a long-term recovery improvement. In the past, the loss of the parent well was not associated with a significant loss in production compared to the new wells. However, with increasingly larger completion designs executed on wells spaced ever closer together, the impact of frac hits has grown substantially in the past few years (Daneshy 2017; Rainbolt & Esco 2018).
Frac hits are not a new phenomenon in the development of North America's Shale fields. Usually first encountered by operators during the progression from Hold By Production (HBP) to infill drilling, they have been widely documented and studied over the past 6+ years. However, apart from avoiding frac hits entirely through a fully integrated field development plan, the existing industry literature does not provide a flexible, repeatable, cost effective solution to mitigating frac hits. Refracs have been discussed for parent wells next to the new infills, but economics have been difficult to justify on more recently completed wells with larger completion designs, and refracs do not address the challenge of third or higher generation infill activities where several wells are at risk of being frac hit.
This document will cover the development of the frac hit mitigation technique that the authors developed in their company's Eagle Ford acreage and which is now employed as standard practice for all infill completion campaigns in both the Eagle Ford and Permian.
Well Intervention Program Creation at the Novoportovskoye Field
Authors: Olender Oleg , Malyugin Andrey , Fedotov Vladimir , Korepanov Alexander , Asmandiyarov Rustam , Zulkarniev Rustem , Studinsky Roman , Sayfutdinov Elnar , Ivanov Anton 
Published: October 2018

Abstract
Novoportovskoye Field is classified as large and is characterized by complex geological structure, reservoir development is complicated by bottom water and gas caps.
The field is developed by horizontal wells with a horizontal section length of up to 2,000 m and various completion methods: Assemblies with extended screen sections isolated by packersAssemblies with sliding ball-activated hydraulic fracturing collarsInternal-flush assemblies with hydraulic fracturing collars (30pcs) activated by a special CT-conveyed device.
To estimate the efficiency of multi-stage hydraulic fracturing in horizontal wells, a module has been developed that allows estimating the effect of the primary and repeated fracturing. The module takes into account the increase in the number of frac stages, fracture half-length and width, it allows to estimate the risks of clay barriers breakthrough, evaluate reservoir properties, and select the stimulation option.
To select wells for Hz sidetracking and infill drilling, an algorithm for identifying undeveloped reservoir sections was applied to evaluate the efficiency of well interventions and assess the risks in each zone.
In the conditions of oil rims, to increase the efficiency of reservoir development using horizontal wells with screen completions, it is recommended to use casing packers in a liner assembly that divide the horizontal borehole into isolated sections. This solution will allow to perform targeted isolation / stimulation of a certain horizontal interval in the process of well operation in case of a decrease in productivity and water/gas breakthrough. As a result, the cost-effective life of a well will be extended and the oil recovery factor of the field will be increased.
A twin-packer technology for a targeted stimulation of a certain interval in a horizontal wellbore was tested and successfully implemented by Gazpromneft-Yamal.
An Investigation of Proppant Transport in Friction Reducer Fluid Systems Utilizing a Large Slot Flow Apparatus
Authors: Drylie Stephen , Duenckel Robert , Barree Robert , Hlidek Barry 
Published: October 2018

Abstract
Current unconventional reservoir development depends on an assumed network of induced fractures created by hydraulic fracturing operations that facilitate production. In many cases natural fractures are linked to the created fractures and also contribute to production. Only in some fraction of the created and natural fracture network will proppant have been placed during the fracturing operation. In order to model the production from these fracture systems, reservoir and completion engineers often make optimistic assumptions about propped fracture half-lengths based on inaccurate expectations regarding proppant transport and proppant pack behavior. This work addresses proppant transport behavior by presenting results from large-scale lab testing of proppant transport with a range of fluid rheologies utilizing a slot flow apparatus.
Proppant transport tests were performed at multiple rates and proppant concentrations utilizing a 4-foot by 16-foot fracture slot. The primary testing objective was to compare proppant transport in friction reducer (FR)-based fluids against previously published results and other work that has been performed in this apparatus. Additional tests using guar based fluids of a similar nominal viscosity will be used for comparison and to demonstrate the need for other rheological properties for planning and predicting completion results.
The results of this testing will provide a more realistic description of proppant transport. Through this enhanced understanding, reservoir and completion engineers will be able to make improved assumptions about propped fracture dimensions that will drive better decisions regarding fracture design, improving recovery, optimizing spacing, and field development while reducing the need for costly future interventions and refracturing treatments. After an introductory review of important conclusions from previously published work performed in this and other slots, the results of this testing will be used to evaluate the validity of these conclusions. Additionally, relationships and interactions between viscosity, rate, proppant concentration, and other fluid properties will be established and reviewed to facilitate the development of improved models for proppant transport in unconventional reservoirs.
Much of the earlier lab work performed in slots of this scale was performed when crosslinked fluids were the preferred fluids in almost all applications. Since that time, the industry has shifted to a preference for slickwater fluids and other systems of much lower viscosity in the hope that increased velocity would make up for the loss in viscosity. This work will highlight where this hope is unrealized and when other fluid properties make the drop in viscosity less important than expected.
Hydraulic Fracturing Optimization for Regions with a Complex Tectonic Regime, High Temperature and Abnormal High Pore Pressure Conditions, in a Karatobe-Burbaital Well No. 101, The Caspian Depression
Authors: Nizametdinova Madina , Iskakov Askar , Zavarygin Sergey 
Published: October 2018

Abstract
This article is devoted to hydraulic fracturing justification, risks estimation and fracture optimization for ultra deep wells in regions with a complex tectonic regime, high temperature and Abnormal High Pore Pressure (AHPP) conditions, using the example of Karatobe-Burbaital well No. 101, The Caspian depression.
An approach was used to optimize well stimulation by hydraulic fracturing. Optimization is based on 1D Mechanical Earth Model and core tests results for petrophysical and mechanical rock properties. The model considers the thermal effects which influence on perforations and stress distribution around the borehole. The drilling and well development histories are used in the modeling.
Based on the geomechanical model results a complex tectonic regime has been identified involving the fracture propagation in both vertical and horizontal planes. The conducted complex analysis showed the presence of a hydrodynamic connection with the underlying water-saturated layer. Hydraulic fracture program was optimized accounting geological conditions, equipment technical limitations and multi-layer reservoir, with the risk that one fracture might be propagated into the underlying water-saturated formation. According to the stimulation program the fracture geometry was determined and starting rates were estimated. This allowed to determine the hydraulic fracture possibility and well stimulation feasibility underthese conditions.
Successful hydraulic fracturing in regions with a complex tectonic regime, high temperature and AHPP conditions requires a comprehensive optimization approach based on an accurate geomechanical model.
Employees Adaptation Mechanisms in Extractive Industries while Shift Work Organization at Far North and Arctic
Authors: Yurjeva Anna , Korneeva Yana 
Published: October 2018

Abstract
The study was carried out with the financial support of the grant of the President of the Russian Federation for state support of young Russian scientists - candidates of science (MK-6409.2018.6). The article is devoted to the description of the mechanisms of psychological adaptation of employees of oil and gas producing companies of various professional groups during shift work organization in the Arctic.
Mining industries are located in remote areas of the Far North and the Arctic, which is why the shift work method is used there. The professional activity of shift work specialists in the conditions of the Far North presents high demands for the creation of conditions for physiological, psychological and socio-psychological adaptation.
Despite the large number of works in medicine and psychology devoted to these issues of human adaptation to severe climatic and geographic conditions and shift work, the systematization and classification of the mechanisms of psychological, social and psychological adaptation of workers in extractive industries is not enough.
The research was carried out in oil and gas production with a shift work organization on the territory of the Nenets Autonomous Okrug (the duration of the rotation arrival is 30 days). The study involved 70 workers aged 24 to 60 years (mean age 38.7 ± 1.3). Methods of research: studying documentation, monitoring the work process, questioning, psychophysiological and psychological testing, statistical methods of data analysis.
As a result of the research, differences in self-regulation, regulatory processes, psychological protections and mechanisms of socio-psychological adaptation among workers in the oil and gas production of various professional groups were revealed.
Large Scale Field Development Optimization Using High Performance Parallel Simulation and Cloud Computing Technology
Authors: Tanaka Shusei , Wang Zhenzhen , Dehghani Kaveh , He Jincong , Velusamy Baskar , Wen Xian-Huan 
Published: October 2018

Abstract
Field development optimization for oil and gas reservoirs is typically challenging due to large number of control parameters, model complexity, as well as subsurface uncertainties. In this study, we propose a joint field development and well control optimization workflow using robust parameterization technique and demonstrate its application through a offshore oil field development.
Traditionally, using simulation models for optimization of field development plan was considered time and cost prohibitive when incorporating models to cover range of uncertainties in reservoir properties. Consequently, the problem was simplified by reducing the number of control parameters through multi-disciplinary workflows. In this paper, we aim to optimize field development strategy by simultaneously controlling topside facility, number of wells, their trajectories, drilling sequence, and completion strategy etc., considering subsurface uncertainties and constraints. To achieve this, we used our next generation reservoir simulator and commercial cloud computing to explore the possibility of achieving an optimized development scenario within reasonable time and cost constraints.
We have applied the proposed workflow to the Olympus field case, which is an optimization benchmarking problem set up by Netherland Organization for Applied Scientific Research (TNO) using a synthetic North-sea type reservoir. Our objective is to improve the net present value (NPV) after 20 years of operation by controlling the number and location of platforms, number of injectors and producers as well as their trajectories and drilling sequence. The large number of control parameters and subsurface uncertainties make the optimization process challenging. Three optimization techniques, genetic algorithm (GA), particle swarm optimization (PSO) and ensemble-based optimization (EnOpt) were tested and their performances were compared. Best results in terms of NPV improvement was obtained by using the mixed-integer Genetic Algorithm method. More than ten thousand simulation runs were required by the method to reach to optimal development of well location, trajectory, drilling sequence etc. This was made possible by utilizing a high performance parallel simulator and cloud computing. The estimated cost of the commercial cloud service is almost negligible compared with the improvement in the economic value of the optimized asset development plan. The developed workflow and parameterization technique are flexible in well trajectory configuration and completion design allowing application to primary depletion as well as waterflooding.
Increasing of Operation Efficiency of Low Pressure Gas Wells by Using of Gas-Jet Device's
Authors: Fedorov Aleksei , Ibatulin Artur 
Published: October 2018

Abstract
One of the most important tasks in the development of multi-layered regions with a cluster layout of wells is to increase the low-pressure wells operation efficiency. A successful solution of this task can, in particular, help to increase the efficiency of developing multi-layer deposits by developing reserves of low-potential deposits, as well as reducing the time spent on producing reserves.
This task is relevant both in the development of oil and gas fields. And the situation is complicated at the late stage of field development. Inactivity of wells leads to loss of production, uneven development of productive layers and poor performance of fields development.
As a solution to the presented problem, in this paper, it is proposed to use gas-jet devices (GJD) to reduce the wellhead pressure of wells, which allows to jointly operate high-pressure and low-pressure wells in conditions of limited infrastructure.
This paper presents the results of the field trial of the developed method and the technological scheme for reducing the wellhead pressure of gas wells [5], [8], tested on gas wells at the Gubkinskoe field of LLC Rosneft-Purneftegaz. The tests were carried out with a positive result. An assessment was made of the further expediency of using GJD to improve the development efficiency of the Gubkinsky multi-layer field.
Based on the data obtained from the field trial, the prospects for further development of the technology for increasing the operation of gas condensate wells (in conditions of inefficient mechanization) and increasing the efficiency of oil wells (gushing and mechanized) are developed.
To solve these problems, the authors of the work used the results of theoretical and experimental studies of sonic GJD with the cylindrical throat conducted on special stands in laboratory of techniques and technology of oil production in Gubkin Russian State University of Oil and Gas (National Research University) [5].
Development of Surfactant-Polymer SP Processes for High Temperature and High Salinity Carbonate Reservoirs
Authors: Ghosh Pinaki , Sharma Himanshu , Mohanty Kishore K. 
Published: October 2018

Abstract
Oil recovery during waterflooding of carbonate reservoirs is often low due to their oil-wetness and heterogeneity. Surfactant-Polymer (SP) flooding can improve the oil recovery from these reservoirs through ultra-low interfacial tension (IFT), mobility control and wettability alteration. However, there are several challenges associated with this process in high salinity and high temperature carbonate reservoirs related to thermal stability of polymers at elevated temperatures, compatibility of surfactants with high concentration of divalent cations present in formation brines, and geochemical interactions with carbonate minerals. This paper addresses the following challenges: surfactant interaction with formation brine containing high concentration of divalent cations and thermal stability and transport of polymers in carbonate rocks at a high temperature (80 C). Surfactant phase behavior experiments were performed to identify promising surfactant candidates which showed ultralow IFT with crude oil and aqueous stability at high temperature in high salinity and high hardness brines. A systematic study was performed to understand the effect of surfactant hydrophobe length on phase behavior, oil recovery, and surfactant retention in coreflood experiments. Novel surfactants with very short hydrophobes and cosolvent-like properties were also included to further optimize the phase behavior. Surfactants of larger hydrophobe length, containing similar number of EO and PO groups, gave higher solubilization ratio (and lower IFT) and lower optimum salinity. Specialty synthetic polymers with good thermal stability and salinity tolerance (TDS &gt; 90,000 ppm) were investigated for their transport in single-phase corefloods. Results showed successful transport of polymer, without degradation in-situ, and improvement in mobility control. SP core floods were conducted using selected formulations in Indiana limestone cores. Coreflood experiments showed small increases in oil recovery over waterflood after the injection of the chemical formulation. Succesful polymer transport was observed in SP corefloods at high temperature.
Successful Adoption of New Technology: Implementation of a Global Drilling Bit Dysfunction and BHA Vibration Initiative
Authors: Willis John 
Published: October 2018

Abstract
Previously published technology that was not used in a company was implemented using a new approach based on marketing technology that resulted in widespread adoption and a lasting change. The drilling technology was available for years in SPE papers. Previous attempts to implement it failed to establish lasting application. The initiative took about two years and resulted in the use of the technology being well established. In addition to the process used to implement the initiative, the drilling technical process is also summarized.
The initiative drove implementation of the use mechanical specific energy (MSE) and other techniques to identify and minimize bit dysfunction and bit and bottomhole assembly vibrations. Full implementation of the techniques required drilling managers, superintendents, and engineers in the office, company drill site managers on rigs, and drilling contractor and service company personnel both on site and in the office all to understand the value of the technology, as well as know how to apply it.
The implementation process included an initial awareness phase of sharing successes by early adopters to create demand for the technology. Implementation included comprehensive training, management support, technical tools, and ongoing support.
The result of the initiative was a dramatic improvement in drilling performance. Significant increases in rates of penetration were achieved with virtually no added operational cost. Good results have been obtained in all business units, and the processes have evolved into routine practices.
The key conclusion is that proven marketing techniques can be adapted and applied to internal initiatives. The technology of marketing is effective and available, but adapting it to use internally is not trivial or obvious. On some previous initiatives, the approach was to deliver the technology, then create demand for it. The technique used this time was to create the demand first, then deliver the technology. This approach was successful in reducing opposition.
Early adopters must be identified and supported. Their initial successes are used to create demand for the technology and willingness to participate in training and learning. Training must be delivered to all of the people involved to enable application of the new process or technology.
Management support and technical support are both essential to get past difficulties. Patience and understanding are the best techniques to deal with resistance. Ultimately, successful results are the key to full adoption, but successful results cannot be achieved without the previous steps.
This case history includes both the principles and the application to a real case, with enough information on the drilling technology to understand the marketing process. The novel and additive information is how to adapt marketing technology for internal use, which is important for companies to adopt new technology faster.
A Diffusion-Corrected Sigma Algorithm for a Four-Detector Pulsed-Neutron Logging Tool
Authors: Schmid Gregory , Pemper Richard , Dolliver Darrell , Mekic Natasa , Musselman Jon 
Published: October 2018

Abstract
Sigma logging is a proven method for determining oil/water saturation behind casing. In this paper, we present a new, diffusion-corrected, sigma algorithm for a four-detector pulsed-neutron logging tool. Since the diffusion effect is inversely related to the distance between source and detector, there is an advantage in having multiple detectors at varying distances from the source. We will show how we use this advantage to design a diffusion-corrected sigma algorithm, and will verify the results using lab data, MCNP simulation, and field logs. Furthermore, we will discuss our use of a dual-exponential fit to cleanly separate the borehole decay from the formation decay. We will show that this approach works well, and can provide a certain advantage relative to the "moments method".