bluuebunny/crossref_metadata_2025_split huggingface dataset:
Mechanistic Modeling of Gravity Film Drainage Using Relative Permeability Equation of State
Authors: Khorsandi Saeid , Johns Russell 
Published: October 2018

Abstract
The double-displacement process (DDP) in dipping reservoirs has resulted in large oil recoveries with low operating costs. The large recoveries in the field result from high sweep efficiency and very low residual oil saturation, where very low saturation is obtained by oil flow through thin spreading films. Oil spreads to saturations near zero owing to competing interfacial tensions at contact points between three phases (oil, water, and gas). Experimental studies with micromodels and pore scale imaging support oil flow through films, where the rate of recovery and film drainage are controlled by parameters such as fluid compositions and topology of the water and gas interface within a give pore morphology. The interface topology is largely controlled by phase saturation, gas phase connectivity, pore structure and fluid wettability. Current relative permeability models, however, do not model spreading reliably as they do not include a mechanistic model for dynamics of film spreading on relative permeability.
We use the relative permeability equation of state (kr-EOS) to mechanistically model dynamics of film spreading and its effect on relative permeability. The reconnection of oil phase by spreading is modeled with a compositional evolution function for Euler characteristic. The IFTs and spreading coefficients are calculated based on phase compositions. Then, the physically based kr-EOS is implemented in our in-house fully compositional reservoir simulator. The simulation results are compared to published core flood and field data. We also performed a sensitivity analysis to determine the effects of gas and oil composition, miscibility, and reservoir heterogeneity on recovery rates and timing. These results show that saturation profiles from simulation are similar to those observed from CT-scanning of core floods, demonstrating good accuracy from the new mechanistic relative permeability model.
Geochemical Productivity Index, Igp: An Innovative Way to Identify Potential Zones with Moveable Oil in Shale Reservoirs
Authors: Piedrahita Jaime , Aguilera Roberto 
Published: October 2018

Abstract
A method is presented to identify intervals in shale oil reservoirs that contain moveable hydrocarbons with a novel geochemical productivity index, Igp. This index merges 3 important rock properties that always have to be considered for sound shale oil reservoir characterization: vitrinite reflectance (%R°), oil saturation index (OSI), and free water porosity (ϕFW). Integration of this index with other petrophysical properties and geomechanical parameters leads to define intervals with moveable oil.
Shale oil is both source and reservoir rock. Hence, it is critical to know both its organic matter maturity and oil/water flow capacity. The introduced Igp considers these features simultaneously; maturity is evaluated by discretizing %Ro from 0 to 1 depending whether the rock is immature or not; free oil flow capacity is modeled normalizing OSI between 0 and 1 based on results from Rock-Eval pyrolysis (REP) obtained in the laboratory or electric logs; and water flow capacity is estimated from ϕFW, obtained with the use of NMR log, which is transformed to an index between 0 and 1.
Use of the Igp is explained with real data from a vertical well that penetrates several stacked shale oil reservoirs. However, the same approach can be used in any other kind of wellbore architecture (deviated, horizontal, geosteered). Initially, a correlation between vertical depth and %R° is developed. This results in a continuous organic matter maturity curve along the well section. Next, OSI is simulated with the use of a bin porosity from NMR log, where T2 is between 33 and 80 ms and is correlated with OSI data from REP. As a result, a good match between simulated and real OSI data is achieved. Similar to OSI, ϕFW is also calculated from the NMR log but using a bin porosity when T2 is greater than 80 ms. All these 3 parameters are transformed to partial indexes, which are combined into a unique index, Igp. When the index is greater than 0.66 there is a good chance that the 3 conditions mentioned above will be met. For the example well considered in this study, it was found that almost 30% of total vertical section has good moveable oil potential. This corresponds to 10 intervals in the well.
The key novelty of the paper is that it develops a continuous curve of an index that is easy-to-use and is powerful for identifying intervals with moveable hydrocarbon potential. This is true even in those intervals without laboratory data due to the continuity of the Igp curve. In addition, the Igp integrates criteria that are usually applied independently.
Recently Announced Reforms in the Russian Domestic Gas Market: Impact on the Market Players' Value in New Realities of International Gas Trading
Authors: Talipova Amina 
Published: October 2018

Abstract
Over the past two years, the Federal Antimonopoly Service of the Russian Federation (from now on referred to as FAS) raised the issue of the internal gas market's efficiency, as well as possible scenarios for its partial or complete deregulation. Previously several times settled task has been discussed in the context of the transition to market pricing of wholesale gas volumes and the preservation of state regulation regarding tariffs for the transportation of gas through the Unified Gas Supply System (from now referred to as UGSS). However, to date, the regulation of the domestic gas market, pricing rules and tariffs for transportation have not changed significantly, except for somehow development of the gas exchange trading (SPIMEX), which nevertheless also has some problems and constraints to the development of open market trade.
The main criticism in this issue is the currently applied pricing regime, which consists in the presence on the over-the-counter (OTC) market of monopolistically regulated prices and the so-called open pricing mechanism, and exchange prices on the Saint Petersburg International Mercantile Exchange (SPIMEX) gas exchange, respectively. Experts agree that such a system leads to an asymmetry of the market, and, as a consequence, its inefficiency, unequal position of players in the market, as well as risks of a serious shift of the balance towards one player in case of a significant change in gas market regulation. In this regard, each separate proposal of the FAS on reforming the domestic gas market, whether it relates to the division of the dominant seller into production and transportation or the abolition of price regulation, faces severe contradictions on the each player's side. Thus, the pilot project in three subjects of the Russian Federation (Tyumen Region, Yamal-Nenets, and Khanty-Mansiysk Regions) was discussed to be settled in 2016 on the abolition of the lower boundary of the monopolistic regulated gas price for industrial consumers. The project, however, has not been implemented due to the reason mentioned above for the disagreements of all interested parties.
Such aspects further exacerbate this problem as the share of the gas industry in exports, and, in particular, the export of liquefied natural gas (from now on LNG). The role of LNG in the transformation of global, regional gas markets has been noted over the past decade by the IEA and Russia, as one of the players in this industry, is also setting strengthening rules the positions of Russian gas companies in LNG markets as one of the country's developments priorities.
The paper briefly examines the proposed reforms on the abolition of the gas price lower limit for industrial consumers in the context of the impact on independent gas producers, their market position, market value and credit rating. Also, the work considers the development of exchange trade in natural gas, as an indicator of open pricing and related problems.
Ensemble-Based History Matching and Uncertainty Quantification for Reservoirs Exhibiting Complex Non-Gaussian Characteristics
Authors: Kumar Devesh , Srinivasan Sanjay 
Published: October 2018

Abstract
History matching is an integral part of field development planning for oil and gas reservoirs. It can be viewed as an inverse modeling technique which utilizes information contained in the observed flow response variables like flow rate, well bottom hole pressure etc. to better quantify the spatial distribution of reservoir model parameters like permeability or porosity. As the reservoir parameters and flow response variables are often related by non-linear relationships, the solution to the inverse problem of history matching is often non-unique. This makes it a problem that can be better handled by stochastic approaches than deterministic approaches. The proposed approach called ‘Indicator-based Data Assimilation’ (InDA) is suitable for such problems. To initiate the process, multiple realizations of the reservoir model parameters are generated based on the available information related to the reservoir description. The ensemble of realizations serves as a measure of initial uncertainty in the spatial distribution of model parameters. Next, flow simulations are run on the ensemble of models and the difference between the observed and simulated flow response variables are used to update the reservoir parameters using InDA. With successive updates, the uncertainty in the model parameters is reduced and the spatial distribution approaches the "true" distribution. Considering the residual uncertainty of the final updated models, reliable field development planning decisions can be made. The proposed method is validated using a realistic reservoir with complex channel-like features emulating a reservoir formed in a fluvial depositional environment. Liquid rate data from existing wells are used for updating reservoir parameters for several time steps using InDA. A comparison of the spatial distribution of final model parameters with the reference model used for validation shows a good match. After the history matching period, existing and new infill wells are run in a forecast mode where the observed and simulated flow responses show a good match. As majority of oil reservoirs comprise of high permeability oil-bearing zones in form of channels passing across low permeability zones, the statistical permeability distribution is bimodal making it non-Gaussian. It is shown that ‘Indicator Transformation’ of variables used in InDA preserves the non-Gaussian structure of the permeability field in comparison to methods like ‘Ensemble Kalman Filter’ (EnKF) that are sub-optimal in such cases.
Engineered Fracture Spacing Staging and Perforation Cluster Spacing Optimization for Multistage Fracturing Horizontal Wells
Authors: Salah Mohamed , Ibrahim Mazher 
Published: October 2018

Abstract
Horizontal drilling and multistage hydraulic fracturing applied in tight reservoirs in North America over the past decade and economic productivity attained by creating large fracture surface area to contact the reservoir and create the conductive pathway for the flow of hydrocarbon into the wellbore. Perforation cluster spacing and fracture stagging are keys to successful hydraulic fracturing treatment for horizontal wells. The early focus of the industry was on the operational efficiency. A geometric spacing of perforation clusters adopted as the preferred completion method. Cipolla (2011) presented a case study on the interpretation of production logs from hundreds of horizontal wells. The results indicated that 60% of perforation clusters contribute to production when completed geometrically. Recently, numerous studies have been undertaken to understand this phenomenon. Increasing the stimulation effectiveness and maximizing the number of perforation clusters contributing to productivity was an obvious area for improvement to engineering the completion design. An area with a limited number of horizontally multistage fractured appraisal wells in the Western Desert of Egypt is targeted for this study. The developed workflow comprises integration of petrophysical, geomechanical and production data analysis to evaluate reservoir and completion qualities and quantify the heterogeneity and selectively place perforation clusters in "like-rock" thus promoting the chance of initiating all perforation clusters within a stage and ensuring uniform placement and distribution of the induced fractures and that every cluster in each zone is fracture stimulated and can contribute to the well's full potential. The hydraulic fracture attributes from the fracture simulator were exported to the reservoir simulator. The surface production measurement together with the production profile was used to calibrate the reservoir model.
The scope of this study is to present an integrated workflow to identify reservoir properties variation along the lateral section of horizontal to engineer completion design, improve stimulation effectiveness, and improve cluster efficiency. The methodology adopted in this study resulted in optimized fracture design that helped reduce-cost and increased well EUR. Optimal cluster spacing was determined based on long-term production performance. The final calibrated hydraulic fracture and reservoir models were used to optimize the cluster spacing and other completion parameters.
Efficiency Analysis of Massive Fracturing with Linear Gel Pad on the Achimov Formation of the Urengoyskoe Field
Authors: Shturn Dmitriy , Zavyalov Nikolay , Perfilyev Dmitriy , Kamenskiy Leonid , Tyurin Victor , Astafyev Vladimir , Osipov Ilya , Zolnikov Denis 
Published: October 2018

Abstract
The primary objective of large fracturing treatments (from 150 to 300 tons of proppant) in the Urengoyskoe (Urengoy) field is to increase the drained volume of the producing zone of the target reservoir by increasing the fracture length and placing a larger mass of proppant while maintaining similar fracture widths and heights.
The basic goal of fracturing is to increase production from the target reservoir. In this study, to increase the fracture length and propped fracture length in the target zone, linear gel fluid was used for the main fracture pad stage instead of the traditional cross-linked fluid pad. Because of the high filtration rate of linear fluids and their reduced efficiency, pads of larger volumes were used and were pumped at a higher rate. An additional goal of this strategy was to increase the formation coverage. The fracturing treatment proppant stages were pumped using crosslinked fracturing fluid, which helped to reduce the risk of screenout.
Large fracturing treatments using linear fluid pads increase risk because of the high possibility of screening out and because of undetermined economic efficiency. The initial strategy of the Achimov formation development for the given section of the field planned to complete wells using standard large fracturing treatments on S-type wells with crosslinked fracturing fluid throughout all of the main stages. Because of similar geological conditions across the field, the significant number of previous well stimulation operations performed, and the use of extensive logging by the operating company (including bottomhole pressure and temperature online monitoring during fracturing job, and production logging), it was possible to evaluate and compare the economic efficiency of large fracturing treatments using linear fluid pads and large fracturing treatments using crosslinked pads. The comparison of the results from geophysical studies after the fracturing and the subsequent well productivity analysis have been performed.
The described operations enabled fracturing risks and economic efficiency to be understood, both in the Achimov formations of the Urengoy field and in similar gas reservoirs with low permeability. Well productivity after fracturing with a linear pad increased in comparison with offset wells treated with crosslinked fracturing pad fluid.
Utilizing Drill Cuttings to Enhance Characterization and Description of Tight Carbonate Reservoirs
Authors: Salim Ahmed , Lagraba P. Javier Oscar 
Published: October 2018

Abstract
Tight and complex carbonate reservoirs development requires placing horizontal lateral wells to maximize the reservoir contact across the zones with the best flow potential. Identification of the best permeable intervals and understanding their lateral and vertical continuity are key tasks faced during the field development. It is of critical importance to find means to identify all geological and petrophysical facies changes in such complex rocks. These changes could reveal variations in flowing capabilities of the reservoir.
Standard wireline and LWD logs during the appraisal phase do not always provide the necessary information to capture significant facies changes to identify conclusively permeability variations in the reservoir. Fonnation tester logs are expensive and have limitations in tight formations. Incorporating advance analyses of drill cuttings data into petrophysical and geological evaluations significantly improves the capabilities to recognize geological facies variations, even with minor changes in mineral composition, texture and grain sorting. Capturing these variations in the rock are critical to identify permeability and reservoir quality variations.
In this paper, a method to integrate drill cuttings analysis into standard formation evaluation program is presented as an alternative to enhance reservoir characterization and description.
Increasing the Efficiency of Gas Injection for Oil Recovery from Tight Reservoirs
Authors: Betekhtin Andrey , Glavnov Nikolay , Vershinina Maiia , Zobov Pavel , Khlebnikov Vadim 
Published: October 2018

Abstract
The paper describes the results of a series of slim tube experiments to study the miscibility properties of light West Siberian oil and associated petroleum gas (APG). The experimental MMP for the field's APG was found to be 26 MPa. To improve the degree of miscibility and facilitate the oil and gas miscibility, it is recommended to inject a slug of liquefied gas or other light hydrocarbons into a reservoir before injecting APG. To increase the accuracy and reliability of MMP, it is recommended to use the graphical function of gas breakthrough vs. pressure, rather than the usual function of oil displacement ratio (after injecting 1-1.2 pore volumes of APG) vs. pressure.
Study in Efficiency of Acid Compositions Application in the Clastic Reservoirs of Perm Region Based on Experimental Studies of Core Sample
Authors: Plotnikov Vladimir , Rekhachev Pavel , Barkovsky Nikolay , Amirov Aleksey , Mikhaylov Nikolay , Popov Sergey 
Published: October 2018

Summary
The paper considers results of laboratory experiments on the effect of an acid composition consisting of hydrochloric and hydrofluoric acids on core samples taken from clastic reservoirs in Perm Region. The research included determination of porosity and permeability properties of the samples before and after treatment with the composition, taking anisotropy of rock properties into account. The paper presents the research program and the experimental results obtained that showed a significant change in permeability after filtration of the acid composition and the influence of anisotropy on this parameter. The specific feature of the research carried out is the study of the combined effect of the acid reagent and varying effective stresses on permeability of core samples.
Natural Gamma Ray Tool Response Discrepancies: Not Always Due to the Calibration!
Authors: Allioli Françoise , Nicoletti Luisa , Stoller Christian , Xu Libai 
Published: October 2018

Abstract
It is not uncommon to note discrepancies in natural gamma ray (NGR) data from different designs of gamma ray (GR) tools run in the same well. These discrepancies are often blamed on inaccurate primary or secondary calibrations of the tools; however, it can be shown that in many cases, the different readings are inherent in the NGR measurement itself. Because the primary calibration is performed at the University of Houston (UH) in a reference formation with a specific mixture of thorium, uranium, and potassium, a change in the relative elemental concentrations results in a change of the energy spectrum of the gamma rays that reach the tool’s detector. The tool response to the different energies depends on a large number of factors; e.g., thickness and type of material traversed by the gamma rays, dimensions and type of the GR detector, as well as differences in threshold settings of the acquisition electronics. The standard environmental corrections for NGR tools correct for borehole effects (mud weight and composition, borehole size, and tool position in the borehole), so that the tool response to a given formation is independent of the borehole environment.
In this paper, we present a detailed Monte-Carlo modeling study quantifying the impact of the tool and detector design on the sensitivity to the three predominant naturally occurring radioactive materials (Th, U, and K). Also, the modeling study includes the impact the thickness and type of the materials have that is traversed by the gamma rays before reaching the detector. The modeling is benchmarked against the measured response in formations with a known Th, U, and K concentration, such as the UH Th and U pits, or internal calibration facilities.
The modeling results show that there can be significant discrepancies in the response of different tools to the same formation if the relative Th, U, and K concentrations deviate considerably from those in the UH reference pit. This condition will be illustrated by field cases with comparisons of the total NGR measurement and the spectral NGR measurement, which show that tool-to-tool differences can be attributed to a change of the composite energy spectrum of the emitters from the formation.
Finally, it can be shown that the tool calibration, as well as the interpretation of tool discrepancies, can be improved by using not only a 200-gAPI reference but also an independent Th, U, and K calibration associated with specific response functions for each tool design.