bluuebunny/crossref_metadata_2025_split huggingface dataset:
Shale Gas Novel Technology: Is Coiled Tubing Undulating Completion Compatible in Substituting Multistage Hydraulic Fracturing in Shale Gas Production?
Authors: Gunawan William , Pratami Fatimah Larassaty , Angtony William , Chandra Steven , Lumban Gaol Ardhi Hakim 
Published: October 2018

Abstract
The most common technique of shale gas production is massive or multistage hydraulic fracturing. However, as massive multistage fracturing involves relatively higher capital and is of a negative impact to environment, this paper will discuss the application of undulating coiled tubing as a potential substitute for conventional multistage fracturing in shale production - of which is more economical and has proven to be effective in the production of conventional hydrocarbon from thin and low permeability reservoir.
This study utilizes reservoir data extracted from publicly available Haynesville Shale data. Haynesville is an organic-rich shale play which extends across northeast Texas and northwest Louisiana, US. Overlain by Bossier shale, Haynesville is a unique shale play compared to other plays in US as it is relatively deep; with true vertical depth (TVD) within the range of 11,000 to 14,500 ft, abnormally high-pressure gradient (0.72 to 0.91 psi/ft), and temperatures greater than 300 °F (Thompson, et al., 2011). Haynesville will be the target shale play in this study that will be assessed by production simulation using both massive hydraulic fracturing and undulated well completion. Each production method will then be assessed economically.
This paper shows the applicability of undulated well completion to substitute massive hydraulic fracturing in producing hydrocarbon from shale plays, in terms of technical deliverability as well as economic viability for final warranty of the profitability of the technique. Production performance of undulated well is comparable to that of hydraulically fractured well. Also, the application of undulating drilling proves to have significantly less negative impact on the environment – of which has been the major concern of multistage fracturing due to its pumping at high pressures and huge amount of water needed. Ultimately from economic perspective, the production of shale gas using undulating coiled tubing drilling is attractive as it requires less capital investment.
Undulated wells do not require high-pressure pumped water which makes the completion more environmentally friendly than hydraulic fracturing. The unprecedented shale production using undulating coiled tubing drilling will also be the main discussion to be further compared with the widely and commonly used multistage fracturing. Moreover, between multistage fracturing and undulating completion, both technical and economic comprehensive assessments are conducted to see the well deliverability and profitability in shale gas production before subsequent decision to determine more profitable method.
3D Petrophysical Interpretation of Horizontal Wells
Authors: Kolomytsev Alexander , Sazonova Ekaterina , Ageeva Ekaterina , Pronyaeva Yulia , Pashynsky Alexey , Kneller Ilya , Evdokimova Inna 
Published: October 2018

Abstract
Conventional interpretation of well logging data is done based on coaxial - cylinder model, which was initially developed and proved its reliability in vertical wells. But utilization of this model in horizontal wells may cause false interpretation results. The reason for it is the fact that properties change in vertical direction affect measurements in different way, due to their depth of investigation (DOI). In other words, tool measurements are influenced by formations at the distance with different properties. All this above adds the complexity into petrophysical interpretation - true formation properties evaluation (lithology, porosity, permeability etc.). Consequently, for correct well logging data interpretation in horizontal wells for wireline and logging-while-drilling (LWD) data, the new approach must be implemented, which should be based not only on tool measurements, but also on well trajectory and dip of rock layers; which means it must be in done in three-dimensional space.
This work explains the methodology of logging-while-drilling data interpretation in three-dimensional space. The results of several wells interpretation are compared with standard approach (coaxial – cylinder model) and with 3D. The difference in formation properties and net-to-gross (NTG) are shown for both methods with the recommendation of 3D approach.
Specificity of Flow Initiation at Unconsolidated Reservoir of East Messoyakhskoe Field
Authors: Zagrebelnyy Evgeniy , Martynov Mikhail , Konopelko Alexey , Demenev Roman 
Published: October 2018

Abstract
The East Messoyakhskoye field is the northernmost developed oil field in Russia, located in the northern part of the West Siberian Lowgrounds, in the southwest of the Gydan Peninsula. His most studied object is the PK1-3 formation, the full-scale development of which was not economically viable ten years ago. The process of oilfield construction and pilot production in 2012-2014 was accompanied by the implementation of a large number of innovative technologies and approaches to its exploitation and development. However, it was not possible to completely solve all the problems related to the peculiarities of formation PK 1-3 bedding and structure, the physical and chemical petroleum composition.Reservoir characterization PK1-3:Average TVD reservoir top, m789High TVD reservoir top, m753Formation typemassive, fault-boundedReservoir typeporous, clastic rockAverage net thickness, m:   Oil-saturated16,8   Gas-saturated13,3Porosity0,29Permeability (core), 10-3 µm2387,7Net sand coefficient0,66Number of reservoir beds31Initial formation temperature, °C16Initial formation pressure, atm78
Located at shallow depth, the PK1-3 formation is mainly represented by unconsolidated heavy oil (viscosity 111 cP) sandstone, which characterized by low formation temperature (16°C), and resinous fractions in the reservoir fluid, which makes it possible to conclude that there are a lot of risks to reduce well productivity and increase the skin factor, up to the total or partial loss of the horizontal section.
Calibrating Global Uncertainties to Local Data: Is the Learning Being Over-Generalized?
Authors: He Jincong , Reynolds Albert C , Tanaka Shusei , Wen Xian-Huan , Kamath Jairam 
Published: October 2018

Abstract
A common pitfall in history matching is to falsely generalize the learning from local data to the entire field, which can lead to radical over-estimation of uncertainty reduction and bad reservoir management decisions. This problem is referred to as the local-global problem and in this paper a methodology is proposed to quantify and correct for the error arise from this problem.
Most performance metrics in an oil field, such as estimated ultimate recovery (EUR), are field-level ob jective functions that depend on properties (e.g., porosity) over the entire field. On the other hand, most measurement data (e.g., BHP) are sensitive only to a local area around the wells and are thus susceptible to local variation of geological properties. Calibrating field-level objective functions and multipliers of global properties (e.g., porosity) to local well data over-estimates the reduction of global uncertainties. In this paper, we derived the formula to quantify error in the calibrated posterior distribution (S-Curve) resulted from the local-global problem, as well as a correction factor to recover the true posterior S-Curve.
Through theoretical derivation, it is shown that the model error arise from the local-global problem is dependent on the magnitude of the global and local variation of the uncertain properties (e.g., porosity). The larger the local variation relative to the global variation, the larger the error is in the estimated posterior S-Curve. The error also depends on the variogram of the local variation, and the detection range of the data. The error is larger for case with long variogram for the local variation and short data detection range. In addition, this model error can be highly correlated for different measurement data points even when the measurement error for these data were independent. To address this local-global modeling error, a series of analytical and empirical formula is proposed, which has successfully corrected the error and greatly improve the posterior S-Curve for a series of cases.
To the best of our knowledge, this is the first time the error from the local-global problem is quantified and corrected. The methodology proposed could help improve the reliability of the result from probabilistic history matching.
Underreamer Block with Conical Diamond Elements – Concept, Design, Optimization, and Field Tests
Authors: Trunk Philip , Nasief Mary , Shi Kevin , Long Wiley , Terracina Dwayne , White Allen , Tocantins João Pedro , Costa Edson , Louback Leonardo , Hird Jonathan , Aguiar Romulo 
Published: October 2018

Outline
History of Underreamer Blocks and Problem Description
Conical Diamond Elements in Underreamer Blocks
Complementary Design Features
4D Simulation Software Introduction
4D Simulation and Design Approach
Vibration and Drilling Efficiency Lab Testing
18.125-in × 22-in HEWD Job and 4D Simulation Study
12.25-in × 14.75-in URO Job
8.5-in × 9.0-in HEWD Job
Conclusion
Excelling Asset Design: Performance and Operation Management Utilizing Reservoir-Production-Processing Facility Integrated Modeling Approach
Authors: Yengle Carlos , Kumar Hemant 
Published: October 2018

Abstract
Asset steady-state modeling is frequently done by separate teams of engineers working on asset subsystem, production, and processing facility design and asset operation management. Design criteria shared between the teams are based on a limited set of predefined discrete assumptions for each subsystem. Currently, the commonly used modeling approach fails to account for subsystem interdependencies and does not enable assessment of changing conditions across the asset life cycle. This gap often results in suboptimal facilities design for the asset and cost overruns and/or lost production. Overall asset management decision-making tools should be based on reinforcing the consistence of information used across the whole asset. Integrated modeling helps to make informed decisions by considering the combined effect of reservoir uncertainties, well placement, surface network, and process facility on overall asset design, production, and management. This paper describes how a full integrated asset model is built and used as an effective decision support tool to help optimize overall asset design and operational performance management.
A full integrated model is built using typical industry-known commercial simulator packages for each subsystem and field conditions. It includes steady-state models for reservoirs, wells, production and injection networks, and processing facilities. A platform, which orchestrates data connectivity and integration while allowing subsystem applications to maintain their dependency in thermodynamic properties and equations of state solving, is used for transferring data and controlling variables within the subsystems. Data from a major capital project in the early stages of development were used to pilot test the technique and stress test the consistency of forecast production across the subsystems for whole asset impact due to a change in an individual subsystem such as reservoir uncertainties, well placement and scheduling, surface network operating conditions, and individual subsystem constraints."
The integrated multifield network model provided realistic optimal operating conditions and long-term production forecasts of oil production, sales gas, and water injection requirements by incorporating the physics at appropriate levels to ensure higher accuracies than discrete models.
Integrated asset modeling uses information consistently across the entire asset and includes subsystem interdependencies on overall asset steady-state operating conditions. Integrated modeling provides the opportunity for independent teams of facilities engineers, production engineers, and reservoir engineers to collaborate as a unified team while maintaining specific expert's needs and resources.
The asset integrated model technique offers a novel and versatile capability of evaluating diverse operational scenarios to find optimal settings for short- and long-term asset production needs.
Recovery Drive Analysis in Respect of Tilted Oil Rims
Authors: Fedorov Konstantin Mikhaylovich , Samolovov Dmitry Alekseevich , Polkovnikov Fedor Igorevich 
Published: October 2018

Abstract
This paper is dedicated to the reservoir management and the recovery drive of oil rims – depletion, barrier water flooding and gas reinjection. First, the review of world experience in development of oil rims was carried out; the performance results of different drive regimes are described. Main dimensionless criteria that influence on the character of filtration flows in tilted oil rim were formulated. These criteria take into account gravity factor, anisotropy factor, geometrical configuration of reserves of oil and gas.
The methodology of choosing the best recovery drive was presented. It resides in varying key dimensionless parameters with finding the optimal well position and individual well controls at the same time. The criterion of efficiency is discounted oil recovery due to the same number of wells in all variations. Two-dimendional, three-phase, black oil simulator was used to get the "i-chart" that points out the best recovery drive and the best well control. Such graph will help to perform snap-analysis of development of oil rims what will be especially actual for greenfields when designing concepts of systems of development.
Improving ESP Production Through Compression
Authors: Munding Paul , Hudson John 
Published: October 2018

Abstract
ESPs are a main type of artificial lift being used to unload current horizontal unconventional wells. Due to their high cost and high failure rate an operator must implement them in the most efficient manner possible. This paper addresses a way to create a solution to make ESPs more efficient by using compression at surface.
Current ways of handling gas through ESPs are insufficient utilizing variable speed drives (VSDs). Additional gas handling equipment installed in ESPs have also encountered mixed results as designs continue to be tinkered to improve gas handling. One area that has not been researched extensively is utilizing compression to drawdown the casing annulus of a well on ESP. A preferential path of less static head pressure allows the gas to be drawn up the annulus rather than handled through the pump. Thereby alleviating gas handling problems in the ESP and raising the FL over the pump.
The paper presents two case studies in Oklahoma involving ESP compression assistance up the annulus: one is a case study of an unconventional well of the Mississippi Lime with a low FL and moderate gas production, the second is an unconventional well in the Meramec formation with large amounts of gas production that was increased with the assistance of a compressor to the ESP. Data was collected over a six-week period and ESP performance is compared before and after the surface compressor installation for case 1. In case 2, well performance is compared for 3 different artificial lift setups: gas lift, ESP, and compression assisted ESP over a 3-month period.
Both case studies show benefits for utilizing surface compression with an ESP. The biggest benefits were found to be increased production and reduced operating cost by extending ESP longevity.
Asphaltene Gradient Analysis by DFA Coupled with Geochemical Analysis by GC and GCxGC Indicate Connectivity in Agreement with One Year of Production in a Norwegian Oilfield
Authors: Johansen Yngve Bolstad , Rinna Joachim , Betancourt Soraya S. , Forsythe Julia C. , Achourov Vladislav , Canas Jesus A. , Chen Li , Zuo Julian Y. , Mullins Oliver C. 
Published: October 2018

Abstract
Asphaltene gradient analysis in many wells in a large field match the Flory-Huggins-Zuo Equation of State (FHZ EoS) indicating equilibrated asphaltenes, thus reservoir connectivity. This analysis is consistent with data from over one year of production to date. Reservoir fluid samples were acquired with use of focused sampling techniques providing contamination free samples. Pressure measurements and many fluid properties are used to validate fluid equilibrium, including GOR and composition analyzed by the Cubic EoS, and a variety of markers in the condensate range, black oil range and the biomarker region. All analyses indicate equilibrium with the exception that the only two outliers in the asphaltene gradient curve are shown to be of different thermal maturity by utilizing the preferred biomarkers, the hopanes Ts and Tm. Moreover, the asphaltene abumdance in differently charged fluids varies by a factor of 6 while the maturity ratio Ts/(Ts+Tm) varies by 6% showing the sensitivity of asphaltene gradients for connectivity analysis. The modest levels of biodegradation (Peters- Moldovan rank=1) are used to constrain the petroleum system context of this reservoir considering that current reservoir temperatures significantly exceed biodegradation thresholds. There is evidence both that mildly biodegraded oil spilled into this reservoir and that some further biodegradation occurred in reservoir. Different gas-oil contacts in the field are associated with charge direction and show the limits of Cubic EoS for connectivity analysis in contrast to the good capability of the asphaltene gradients and FHZ EoS for this purpose. Moreover, the FHZ EoS analysis indicates that the asphaltenes are dispersed as a true molecular solution for this light oil in accord with the Yen-Mullins model of asphaltenes. Results from detailed whole-core and petrophysical analyses supports connectivity analysis. Core analysis shows the lack of any asphaltene deposition in the reservoir as expected from the fluid and asphaltene evaluations.
Advanced Well Positioning with Magnetic Interference Based on Passive Magnetic MWD Ranging: Case Study
Authors: Eatough Oliver , Alahmad Mohammad , Momot Fabien , Sikal AnaS , Reynaud Denis 
Published: October 2018

Abstract
This paper presents an efficient application of Passive Magnetic Ranging (PMR) on the B3 well sidetrack drilled on the High Pressure/High Temperature (HP/HT) Elgin field in the UK Central-North Sea. The planning and execution of this sidetrack presented an escalated set of challenges beyond those encountered in standard well conditions due to the high temperature (HT), the potential for magnetic interference and collision avoidance constraints. The PMR method was deployed in order to mitigate the risk of, and ultimately resolve, magnetic interference. This resulted in minimised collision risk and safe achievement of the sidetrack in a HT environment.
Challenges were faced in the 12 ½″ section which resulted in the open-hole being plugged and abandoned below the 14″ casing shoe, with the drill-string cemented in place. A complex sidetrack was planned below the 14″ shoe. Reservoir target and collision avoidance constraints required the planned sidetrack well-path to be close to the abandoned branch, therefore magnetic interference was possible. PMR was planned in the case of interference. The aim was to make the preparation and operational deployment process as efficient as possible, while drilling this sensitive section. A work-flow was developed to manage the performance of ranging passes, specifically interfaces between all parties involved in operations. PMR was deployed to map the relative position of the well during periods of interference and develop ‘synthetic surveys’ to construct the well-path, allowing collision avoidance calculations by defining reliable projection ahead and thus permitting steering of the drilling assembly.
The PMR process was successfully deployed on B3 after experiencing high magnetic interference allowing drilling to continue to planned depth with limited impact on operations. This paper provides information on the application of independent PMR and processing aspects to be considered when defining relative wellbore position based on synthetic surveys. Understanding advantages and limitations of PMR opens up opportunities to benefit from this technique in similar challenging drilling applications and help to reduce operational risk and optimise cost. PMR can thus provide a viable alternative to Gyro While Drilling (GWD), where conditions do not allow or where the probability of magnetic interference is marginal and high tool costs could be incurred when potentially not required.
Adsorption Isotherms and Permeability of Tight Shales Using Magnetic Suspension Balance Experiments
Authors: Ratnakar Ram R. , Dindoruk Birol 
Published: October 2018

Abstract
Adsorption and flow characteristics of methane and other natural gases onto tight rock formations is of economic interest for the proper evaluation and production of the field. In this work, a novel technique to enable the determination of adsorption isotherms and permeability of a gas in such formations through the transient analysis of experimental data from magnetic suspension balance is presented. Adsorption of gases onto the tight shale samples were measured using the magnetic suspension balance (MSB) apparatus at a constant pressure and temperature conditions. The current work presents the experimental technique in sufficient detail to allow others to replicate and evaluate the results. MSB has been proved a very effective tool for evaluating the adsorbed amount of gases onto tight shales/coals, especially when the adsorbed amount is very small. A mathematical model based on volume averaging is developed to describe the transient behavior of the MSB-set up, which was utilized to obtain the permeability of shale sample from experimental data.
A simple methodology, developed with a theoretical framework, is presented to obtain adsorption isotherm of a gas onto tight shale/coal sample and permeability of the sample. The methodology can be utilized to any type of adsorbing gases and shale/coal samples. In particular,
Experimental data for adsorption of methane onto a shale sample is presented at 50C and in the pressure up to 25bar using the MSB apparatus. The density of methane was also measured with MSB which shows very good match with the data available in literature, demonstrating that MSB can be an excellent tool for density measurement of gases. A simple method is developed to decouple the buoyancy effect and obtain the absolute adsorption isotherms. Most-importantly, a low-dimensional mathematical model based on volume averaging is developed to describe the transient adsorption process in MSB experiments, which was used to regress the experimental data and obtain the permeability of the shale sample. The permeability versus pressure plot shows the Klinkenberg effect, as expected. Further, the validity and accuracy of the model was verified by comparing the absolute permeability obtained from our method with an independent measurement using pulse-decay experiments.
The novelty of the work includes the development of a mathematical model describing the transient adsorption process in MSB experiments that can be utilized to obtain permeability of tight shale samples. In addition, the current work presents how to decouple the buoyancy effects to determine absolute adsorption isotherm. The methodology was tested and verified against the experimental measurements and can be utilized for industrial applications.