bluuebunny/crossref_metadata_2025_split huggingface dataset:
Small-Scale GTL, A Sustainable Alternative for Production of Transport Fuels in The U.S.
Authors: Ajagbe Oluwatobi , Moghanloo Rouzbeh Ghanbarnezahd 
Published: October 2018

Summary
This paper examines the utilization of small-scale gas to liquid (GTL) plants for the production of transport fuels using abundant gas production from shale plays in the U.S. It is well-documented that GTL technology can be successfully implemented to convert natural gas to transport fuels. However, our literature is lacking an economic feasibility study of utilizing small-scale GTL plants as an additional stream of income for shale gas producers.
This paper describes two different practical cases detailing field constraints a shale gas producer should overcome to successfully generate additional income through GTL technology in a reasonable time frame. Economic metrics such as Net Present Value (NPV), Internal Rate of Return (IRR), Cost-to-Profit ratio and Payback Period were used to assess the success of GTL technology at each given business case.
For strategic decision making, sensitivity was built into the market drivers such as CAPEX, OPEX, interest rate, efficiency feedstock price, etc., and their level of influence on each economic performance benchmarks were analyzed. Monte Carlo simulation was used to carry out sensitivity analysis in each case to assess the mean and standard deviation of each economic performance metric when the range of possible values of the market drivers were put into consideration.
It is expected that the outcome of this research would guide shale gas producers and private investors when considering a GTL investment to monetize their assets in the United States and beyond.
Inhouse Design of Innovative Completion Equipment as an Alternative to Technology Transfer
Authors: Riabov Mikhail , Pustovalov Mikhail 
Published: October 2018

Abstract
In recent years import substitution and a technology transfer are ones of the hottest topics in oil and gas industry and relate to both economic and political situation. Most import substitution projects in Russia are carried out using methodologies of transfer of foreign technologies or the reverse engineering. In the context of this discussions technology transfer usually means the process of transferring technology from the foreign developer to domestic manufacturer. At the same time conventional oil & gas reserves are being depleted. The development of unconventional oil and gas reserves requires increasingly complex technologies that have not yet been developed by domestic companies. At the same time, foreign developers are not interested in the transfer of the latest, most effective technologies. Thus, if an import substitution is conducted only in a form of technology transfer, then the dependence of the Russian oil and gas industry on foreign technologies could not be overcome. And while geopolitical situation remains a difficult one, the technological gap between domestic and foreign industries will persist. And such gap will lead to a drop of oil and gas production in the Russian Federation.
This paper discusses an experience in realization of a different method of an import substitution, the in-house development of innovative technology. The challenges arising from implementation of such an approach are analyzed and lessons learned are described.
Water Source Identification and Inflow Profile Determination in Horizontal Wells after Multistage Hydraulic Fracturing Using Passive Location Method and Temperature Modelling
Authors: Aslanyan Irina , Minakhmetova Roza , Salmin Sergey , Trusov Alexander , Lutfullin Azat , Ganiev Bulat , Khabipov Rishat , Khabibrahmanov Azat , Yakupov Aidar , Morozov Pavel 
Published: October 2018

Abstract
One of the most effective oil production stimulation techniques in low permeability and heterogeneous reservoirs is multistage hydraulic fracturing. The multistage hydraulic fracturing technique has multiple engineering solutions dependent on the specifics of a particular target and its performance parameters. Hydraulic fracturing in a horizontal well involves a risk of communications with over- and underlying water-bearing formations via the fractures developing as a result of the hydraulic fracturing job. As a consequence, water cut in the well increases, negatively affecting the overall well performance. Another cause of a higher water cut could be a leak in the downhole completion.
To identify water sources in horizontal wells, modern logging techniques are applied. To enhance the informative value of a standard logging suite focused on inflow profile evaluation and integrity assessment in a multistage hydraulic fracturing well, SNL locator and acoustic flowmeter were added.
This paper discusses some cases of locating water sources in horizontal producers using new well logging and interpretation techniques. The information obtained as a result of well investigation was used to detect the water source and assess the multistage hydraulic fracturing job effectiveness. It was also recommended to perform workovers for the purpose of shutting off the water-producing zones.
A New Radial-Azimuth Thermal Anemometer for Determining the Direction and Velocity of Fluid Flow in the Wellbore
Authors: Valiullin Rim , Sharafutdinov Ramil , Fedotov Vladimir , Ramazanov Ayrat , Vakhitova Guzel , Kosmylin Denis 
Published: October 2018

Abstract
Measurement of fluid flow, especially for small values of flow rate, is important and, at the same time, a difficult task [1, 8-11]. The need for reliable measurement of this parameter is especially important for operating well logging. There are many flow measurement methods that are based on measuring the flow rate when the cross-sectional area is known. A wide-spread thermo-anemometer method was obtained in the study of producing wells. Its operation is based on the dependence of the body heat transfer on the flow velocity of its cooling fluid flow [3-5]. Thermal anemometers are used to detect inflow and uptake intervals; determination of leakage of the column under low-rate conditions, when mechanical flow-meter is ineffective. The sensors are reliable, compact, have low inertness. But with all the advantages, thermal anemometers have their own limitations: Only the first inflow interval is well defined, then the sensitivity decreases sharply;The change in ambient temperature can be perceived as a change in the composition or velocity of the fluid, which reduces the efficiency of determining the radial flow;The instrument's readings are strongly influenced by the axial flow of the liquid
In this regard, the development of more effective thermal anemometer sensor remains an urgent task.
In this case, the development of an azimuthally-distributed thermal anemometer of indirect heating is one of the possible ways [6,7].
Reservoir Fluid Geodynamics for Characterization of Reservoir Connectivity: Case Study from Western Kazakhstan
Authors: Ramatullayev Samat , Charupa Mikhail , Blinov Vladislav , Valiakhmetov Rustem , Mendybayev Nurhat , Mukhametrakhimov Shaikhan , Saparova Saule 
Published: October 2018

Abstract
Various techniques are used in industry to determine the reservoir connectivity. The rock-based methods such as seismic mapping and well-to-well correlations present some challenges in subsalt and salt overhang deposits. While fluid based methods such as pressure gradients are traditionally used to infer the lack of connectivity and oftentimes cannot confirm the presence of it. Recent advances in asphaltene science have made it possible to clarify asphaltene distribution mechanism in reservoir allowing to address reservoir connectivity.
The asphaltene distribution in the reservoir is characterized by an equation-of-state (EoS) proposed by Flory, Huggins and Zuo. The classical approach of estimating an asphaltene gradient of the reservoir fluid involves acquiring downhole samples and performing laboratory analysis. However, since the asphaltene content is associated with the coloration of hydrocarbons, a method has been proposed to delineate the asphaltene gradient at reservoir conditions by measuring the color differences of formation fluid with depth using optical fluid analyzer. Integrating the color data from optical fluid analyzer with the proposed equation-of-state, it is possible to elucidate the connectivity of the individual layers.
This paper presents the results of the well logging campaign conducted in the field located in Western Kazakhstan, where new oil deposits were discovered below the salt overhang in Triassic and Permo-Triassic sandstone formations. Several exploration wells were drilled in different blocks of the field. Advanced open hole logging suite comprised of standard logging methods, nuclear magnetic resonance and wireline formation tester was run in all the wells to characterize the reservoir. The wireline formation tester toolstring included an optical fluid analyzer module, which allowed to measure optical density values of an oil at different depths in each of the wells. The study shows how the asphaltene gradient of an oil column constructed from optical density data in conjunction with geological and petrophysical data can be used to delineate reservoir attribute such as lateral connectivity. The analysis confirmed the hypothesis on the lack of reservoir connectivity between the two blocks separated by faults.
The prediction of the asphaltene gradient based on the previously acquired data offers a new way to optimize wireline logging by comparing the predicted with the actual color gradient in real-time during downhole fluid analysis stations, while the tool is still in the well, to uncover the unknown source of reservoir complexity.
Completions and Well Spacing Optimization by Dynamic SRV Modeling for Multi-Stage Hydraulic Fracturing
Authors: Sen Vikram , Min Kyoung Suk , Ji Lujun , Sullivan Richard 
Published: October 2018

Abstract
This paper presents a workflow supported by field examples for modeling the Stimulated Reservoir Volume (SRV) as a Dynamic entity – constrained by validation or calibration against data from the frac treatment, flowback, production and pressure build-ups. The initial reservoir model of static properties is treated as a starting point and evolution of flow and storage are modeled as continuously variable properties using simultaneous modeling of flow and geomechanics – and hence the "dynamic" qualifier for SRV in the title of this paper. This workflow establishes the interaction between reservoir properties and completion parameters – and allows for program optimization. Emphasis is laid on (i) calibration with multiple types of independently measured field data points and (ii) construction of the simplest models which provide a useful degree of predictability, and we caution against over-parameterization through needless complexity of physical models. We first describe the calibration process – during which a model is perturbed to match various aspects of field data, and then explain the prediction process – where multiple hypothetical completion scenarios can be modeled. The results are then screened against economic metrics (e.g. completions costs vs. projected revenue from improved production) – reducing the number of hit-and-miss experiments in the field. While this paper is comprehensive and self-sufficient in its own coverage, it does focus on the physical modeling and calibration aspects, whereas a companion paper (Min et al. 2018), goes into greater detail about the predictive aspects and data analytics driven completion optimization.
Verification Technique of Technical Efficiency of Physical-Chemical EOR
Authors: Morozovskiy Nikita , Kanevskaya Regina , Ulmukhametov Dmitriy , Sergeychev Andrey , Demiyanov Andrey 
Published: October 2018

Abstract
The deterioration in the structure of stocks and the need to maintain the level of oil production leads to an ever-increasing use of tertiary methods of oil production. At present, the most popular of whom PJSC "NK Rosneft" is the physico-chemical methods for increasing oil recovery (PH-CH EOR).
The application of such methods has shown its effectiveness and is actively scaled at various reservoirs and stages of field development.
The variety of objects on which these technologies are applied required the creation of a uniform methodology for verifying the technological efficiency of the PH-CH EOR. This technique is considered in this paper.
The methodology was based on the generalization of the experience accumulated in the Company in the field of application of technologies of physicochemical methods of increasing oil recovery.
After summarizing the results, a transition was made to the estimation of dimensionless parameters that characterize the technological efficiency (TE) of PH-CH EOR measures. This approach allowed us to cluster implementation objects by the effectiveness of various methods.
The generalization of the results of the implementation of the PH-CH EOR also allowed the development of a unified methodology for the calculation of technological efficiency, which became possible to formalize and, accordingly, to automate. Automation of the process of calculating technological efficiency allowed it to unify the majority of the Company's subsidiaries and significantly accelerate, which in turn made it possible to concentrate on selecting candidates and more efficient technologies, rather than on mechanical calculations.
Delivering Drilling Automation II – Novel Automation Platform and Wired Drill Pipe Deployed on Arctic Drilling Operations
Authors: Israel Riaz , McCrae Doug , Sperry Nathan , Gorham Brad , Thompson Jacob , Raese Kyle , Pink Steven , Coit Andrew 
Published: October 2018

Abstract
This paper presents a case history of drilling automation system pilot deployment, inclusive of wired drill pipe on an Arctic drilling operation. This builds on the body of work that BP (the operator) previously presented in 2017 related to the deployment of an alternate drilling automation system. The focus will be on the challenges and lessons learned during this deployment over a series of development wells.
Two major aspects of technology were introduced during this pilot, the first being a drilling automation software platform that allowed secure access to the rig's drilling control system. This platform hosts applications that interpret the activity on the rig and issue control setpoints to drive the operation of the rig's top drive, mud pumps, auto driller, drawworks, and slips. The second component introduced was a wired drill string, which provides access to high speed delivery of downhole data from a series of distributed downhole sensors, providing an opportunity to improve both automated control and real-time interpretation of downhole phenomena.
The project team identified several key performance indicators both at the project level and for each well. The project level key performance indicators (KPIs) were designed to give the operator an understanding of the reliability and robustness of the hardware and software components of the automation system. The KPIs for the well were designed to assess the impact of the technology on drilling efficiency through aspects of invisible lost time reduction (connection and survey times). The well level KPIs also fed into the project KPIs by capturing uptime, reliability, and repeatability of the hardware and software components of the system.
The paper describes several specific examples of where the benefits of the technology were realized as related to the KPIs above and describes some of the technical challenges encountered and fixes employed during the pilot campaign.
The paper also gives an insight into some of the non-technical challenges related to deployment of this system, around human behavioral characteristics. It discusses how focused collaboration and communication from all the stakeholders was managed and directed towards a successful deployment.
The work delivered on this project incorporates several technological innovations that were deployed for the first time on an active drilling operation. Delivery of these were important milestones for both the operator and the automation technology provider as part of their collaboration to increase the capability and reliability of these systems. The operator believes that this effort is key to allowing its drilling operations to realize longer term and sustainable benefits from automation.
Valuation of Government Incentives for Hydrocarbon Asset Developments - A Real Option Approach
Authors: Aliaga Wilson 
Published: October 2018

Abstract
In recent years, the Oil & Gas industry has struggled due to the low hydrocarbon prices. In this context, E&P firms have responded by optimizing their asset portfolio with focus on prospects with the lowest possible financial and technical risks. Since this process has seriously affected countries with emerging hydrocarbon plays and/or relatively low explored geology, government incentives play a pivotal role to mitigate this pessimistic trend. To understand their benefits, this paper presents a methodology to value hydrocarbon prospects using a real option formulation that properly incorporates government incentives such as royalty relief and royalty rate structures that vary with production volumes and prices.
This work links valuation and incentives by using functions that depends linearly on relieved and produced volumes and non-linearly on price. These variable royalty schemes behave similar to bull spreads (financial derivative tool), limiting the upside and downside risk of both government and company take due to hydrocarbon prices and production volumes. Then, we incorporate these functions into the general real option formulation and numerically solve the yielded equations using finite differences methods.
For illustration purposes, the proposed approach is applied to a hypothetical field with an exponential decay production curve. We compare the impact of government incentives for both the prospect value and the optimal investment rule. As observed, these incentives have two merits: to positively influence the economic attractiveness of future developments by compensating investors for their high-risk exposure and to allow an optimal government take in an unfavorable price environment.
We observed that before lease expiration, the real option approach assesses the timing option. Consequently, this approach yields higher values than the NPV analysis since delaying the project execution can be more valuable than the immediate option exercise. Moreover, depending on the financial and volume parameters, intermediate waiting areas might appear between exercise regions. Hence, the methodology proposed captures not only the flexibilities available for an E&P firm that holds a lease, but also the economic benefit of the incentives and their impact on the investment rule.
In summary, the novelty of this work is to propose a general methodology that includes government incentives in the economic analysis of hydrocarbon asset developments using real options. This methodology captures the flexibilities available for managers to respond to hydrocarbon price uncertainty. Moreover, we also propose a new royalty rate scheme that resembles bull spreads. This scheme allows investors to capture the upside of production and prices, and optimizes the government take.
Sweep Efficiency Increasing of Fractured Oil-Wet Reservoirs: Case Study of Central Khoreyver Uplift Fields
Authors: Yudin Evgenii Viktorovich , Chorniy Aleksei Vadimovich , Churanova Nina Yurevna , Soloviev Aleksei Vitalevich , Khairullin Marsel Mansurovich , Sadreev Ernest Anvarovich , Yushmanov Aleksei Igorevich 
Published: October 2018

Abstract
Reserves decline of oil fields with fractured carbonate reservoir is crucially complicated due to formation vertical heterogeneity, occurrence of separate filtration pathways and as a consequence poor sweep efficiency of reservoir development both in vertical and lateral direction. As a result – there is a failure to achieve expected level of recovery factor.
To its simplest extent there is no clear understanding of mechanism of reserves recovery, quite how the process of oil displacement happens: either in vertical direction or in a layered way. More uncertainties in the research process are brought by active aquifer, reservoir pressure maintenance system directly below the OWC and nonuniform recovery at vertical scale.
The results of systematic survey of sweep efficiency increasing of oil-wet fractured carbonates are reviewed on the article using the case study of Central Khoreyver Uplift fields (CKU) of LLC «JC «RUSVIETPETRO» company.
Application of Machine Learning Methods for Modeling the Current Indicators of Operating Wells Stock of PJSC Gazprom Neft
Authors: Teplyakov Nikolay , Slabetskiy Andrey , Sarapulov Nikolay , Simonov Maksim , Perets Dmitriy , Kotezhekov Viktor , Andrianova Alla 
Published: October 2018

Abstract
The main goal of the work is to review and describe the algorithms currently being developed in order to obtain reliable well operation parameters using machine learning (ML) methods, existing constraints and results achieved. The work covers a number of ML applications. The methodology of bottomhole pressure modeling is described, which, in the absence or in case of failure of pressure sensors at an ESP inlet, allows more reliably, in comparison with a conventional approach, to determine the bottomhole pressure in wells and thereby improve the efficiency of selecting well candidates for well interventions. To assess well flow rates, another key indicator, an ESP instant flow ate simulator has been developed that allows obtaining information about the instantaneous production rate at any time, thus increasing the accuracy of cyclic wells measurements, and promptly implementing the necessary corrective measures. Approaches to modeling the impact of injection on the production well rates have also been considered.