bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study on the Effect of Spiral Flow on Wax Deposition Thickness
Authors: Theyab Muhammad Ali , Diaz Pedro 
Published: October 2016

Abstract
Wax precipitation is one of the most important flow assurance problems, and a significant economic issue in the petroleum industry. Wax leading to increase fluid viscosity causing the blockage of filters, valves and even pipelines, increasing pumping costs, and reducing or even stopping oil production or transport. Wax can precipitate as a solid phase on the pipe wall when its temperature drops below the Wax Appearance Temperature (WAT).
The objective of this study is using spiral flow to mitigate wax deposition. An experimental flow loop system was built in the lab to study the variation of wax deposition thickness under the single phase transport. A series of experiments were carried out at different flow rates (2.7 and 4.8 L/min) to study wax deposition process and measure the wax thickness. The effects of factors on wax formation, such as spiral flow, inlet coolant temperature, temperature drop, flow rates and experimental time have been examined.
The spiral flow created inside the pipe by inserting a twisted metal along the pipe, which will create high shear stress affecting to wax deposition. The results show that the wax inhibition (reduction) percentage (WI) % by using the spiral flow at flow rate 2.7 L/min, inlet coolant temperature14 °C, was 65%. At flow rate 4.8 L/min, inlet coolant temperature 14 °C the wax inhibition percentage was 73%. Experimentally, it was found that the spiral flow more efficient than the chemical inhibitors. This percentage of reduction will increase rapidly by increasing the inlet coolant temperature and decreased by reducing the inlet coolant temperature.
This technique of creating spiral flow inside the test section of the pipe will provide a step forward in flow assurance technology to mitigate the deposition of wax.
Low-Volume Positive Displacement Pumps For Production of Viscous Fluids
Authors: Panachev Mikhail 
Published: October 2016

Abstract
A submersible system is provided for viscous fluids recovery making use of a newly designed rotary displacement sliding-vane pump. As opposed to sucker rod and surface-driven PCP pumps also used for viscous oil extraction, the system in question does not include elastomers (requiring selectin to match the fluid being extracted) and forgoes the line of rods, hence there are no limitations for lift it generates and it could be deployed even in horizontal wells.
The first sample has been in operation for almost a year with average flow about 10 m3/day and reservoir conditions of 70 CP.
Pore Structure of West Siberian Jurassic Clastic Reservoirs: Detailed Evaluation with Use of New Generation Wireline Technologies
Authors: Delia S. V. , Drandusov K. A. , Ezersky D. M. , Novikov S. V. , Weinheber P. , Vasilyev D. V. , Filimonov A. Y. 
Published: October 2016

Abstract
Highly heterogeneous rocks are known to provide significant challenges for the determination of permeability and other reservoir properties. Carbonates are known to be micro heterogeneous as well as macro laterally heterogeneous. However, the problem of accounting the structure of the pore space geometry is highly relevant in low-permeability shaly-sand rocks. Traditionally this problem is solved with extensive core analysis. In this article we present alternate methods with advanced logging tools and interpretation techniques to address the challenges.
Interference Test in Naturally Fractured Formation Gas Field Case Study
Authors: Vasilev I. , Aleksakhin Y. 
Published: October 2016

Abstract
Naturally fractured reservoirs present a production paradox. It is not an exaggeration to say that the big part of the world oil and gas reserves are concentrated in naturally fractured reservoirs (NFR). Naturally fractured formations may have different genesis. Igneous, metamorphic and sedimentary rocks undergo of fracturing and faulting as well while forming extensive and narrow system of highly conductive zones.
In this paper, we investigate and analyze core study results, interference test results conducted in naturally fractured formation on gas field, draw conclusions about the conducted test and analyze interpretation results.
At the end of this paper, we give recommendations for using the test for determinations of high permeable zone in naturally fractured reservoir.
Fracture Quantitative Characterization Using Tracer Flowback for Multistage Fracturing Horizontal Well in Tight Oil
Authors: Li Linkai , Jiang Hanqiao , Li Junjian , Zhao Lijun 
Published: October 2016

Abstract
Unconventional reservoirs have emerged as significant hydrocarbon supplies all over the world. Although horizontal drilling combined with multistage hydraulic-fracturing techniques has enabled commercial hydrocarbon production from unconventional reservoirs, fracture characterization in such complex reservoirs remains challenging. In this study, we propose an analytical model to characterize fracture using the early-time post-stimulation tracer flowback profile.
The tracer flowback analysis is a quick method used to evaluate load recovery of hydraulic liquids, productivity of each stage and fracture characterization. However, tracer flowback analysis combined with microseismic data is still at qualitative appraisal stage and non-Newtonian effect of hydraulic fluids is not considered. Therefore, based on convection-diffusion transport theory, a tracer injection flowback model is developed and solved by Laplace transform and image reflection method, and then fracture parameters characterization is proposed considering the non-Newtonian hydraulic fluids flow.
The results demonstrate that the calculated tracer profile of the presented model can well explain the main part of tracer flowback profile except the long trail. That is because the model only considers the process of tracer transports in hydraulic fractures while the long tail of tracer flowback profile reflects the mass interchange between hydraulic fractures and tight matrix. Parameters sensitivity study shows that the peak of tracer flowback profile decrease with the increasing dispersion coefficient and retardation; tracer dispersion induces the increment of tracer slug extent. The differernce of tracer injection and flowback rate severly affects the shape of tracer flowback profile. Fracture parameters are characterized and validated with field data.
The presented model for describing the behavior the tracer profile during the flow back process provides an alternative approach for reservoir characterization. This study encourages the industry to manage the flowback operations carefully.
Investigation of Optical and Rheological Properties of Natural and Recombined Hydrocarbon Mixtures
Authors: Ramis Burkhanov , Ildar Ibragimov , Mars Khannanov , Azat Lutfullin 
Published: October 2016

Abstract
Currently, oil companies are actively using dual completion and production systems (DCPS/DS). In the case of using this technique fluids of two formations are mixed in the wellbore. Two formations are being operated simultaneously by one well. For better control on the oil recovery from both the formations a reliable and prompt product sharing technique is necessary nowadays. Rheological and optical properties of natural and recombined hydrocarbon mixtures have been investigated whithin the research. Recombined mixtures have been produced by mixing oil samples of different reservoirs. These studies are aimed at solving inverse problems, i.e. for product sharing problem.
Quantitative Inflow Profile Determination in Unsable Producers Transient Temperature Potential
Authors: Panarina E. P. , Kremenetskiy M. I. , Melnikov S. I. 
Published: October 2016

Abstract
A difficult condition of field development requires the search for new methods and techniques for more comercial production. There is active development and introduction of new technologies in the field of geophysical monitoring technologies in recent years. When the well inflow is a multi-phase one, or is low and unstable, the flow metering data tends to be of no particular value for evaluation of pay potential of a formation. Thus, some alternative evaluation methods become increasingly required. According to field data analysis, temperature log appears to be the most efficient geophysical survey in a setting discussed.
The report looks into capabilities of temperature log and the scope of its applicability to quantitative evaluation of production from formations that are only able to provide some low and unstable multi-phase inflow. The report describes the method of evaluating well production outside inflow intervals in case of a cycling operating pattern or when the well operating mode is changed, and thus geothermal temperature distribution can not be used as background data.
Examples include well test results obtained on fields of different types (terrigenous, carbonate) with different saturation of reservoirs when they were opened by a vertical well and by a horizontal well.
Multi-Zone Waterflood Top Seal Integrity Assurance: Insights from Advanced Pressure Fall Off Analysis Using Smart Well and DTS Technologies Offshore Sakhalin, Russia
Authors: Petrik Artyom , van den Hoek Paul 
Published: October 2016

Abstract
Assuring the topseal integrity during waterflood is important for petroleum field development. Several cases of failure to do so in the industry worldwide resulted in severe reservoir management and environmental problems, when either unwanted inter-zone communication, or even break all way up to the seafloor occurred.
Case history of applying topseal integrity assurance process with novel controlling approach in a stacked multi-reservoir environment, offshore field, is described in the article.
Approach applied within Sakhalin Energy includes definition of safe operating envelopes for water injection (injection rates, pressures, water quality), based on appropriate reservoir data collection, injection fracture propagation modelling, followed by model calibration and actual fracture height assessment with distributed temperature sensors. Multi-zone smart completions are being used to make zone-by-zone dedicated fracture calibration tests. Then, a proprietary technique to assess actual geometries of injection-induced fractures is applied for control.
The complete process to ensure topseal integrity assurance was developed and applied at the multi-reservoir oilfield offshore Sakhalin, Russia. Practical steps including unsuccessful initial trials with the lessons learnt analysis, and proven working algorithm are described. Based on the results, a simplified, cost-effective yet robust and fit for purpose topseal integrity assurance process is developed and field tested in an offshore multi-zone environment, applicable also to single zone wells and onshore.
A novel method of injection–induced fracture geometries determination from pressure falloff analysis in a smart well completion in a multi-zone well was applied for the first time in the industry, number of other steps were innovations in Russia or/and offshore environment.
Case history provides a practical approach to topseal integrity assurance proven to work and applicable elsewhere, as well as the lessons learnt and adjustments made based on experience.
Waterflooding Optimization in Case of Auto-Frac Naturally Fractured Reservoir
Authors: Maksimovskiy I. V. , Akimov A. G. , Yamaletdinov A. F. , Zhilina M. A. 
Published: October 2016

Abstract
The studied object is a part of a large field of the Uvat region (Western Siberia). The development process of the oil formation is conducted applying the waterflooding system. It is complicated by naturally fractured carbonate member and generation of auto-fractures at injection wells. The advancing rated of watercut and premature water breakthrough toward the production wells are observed. The studied reservoir has a complex geology, lithological intersection consists of clastic and carbonate members. Waterflooding system is not optimized: reservoir pressure falls and auto-fracs occur due to high repressions, that causes increase of watercut at production wells. Great amount of oil reserves is not withdrawn according to prevailing proceses. In this case, it was necessary to determine the reasons of noneffective development strategy and to optimize waterflooding system.
The algorithm for searching of a decision for optimization of reservoir development in case of auto-fracs generation is formed in this paper. The sequence of analysis and valid analytical methods for reasons determination of advancing watercut are defined during the work.
Complex analysis of geology, reservoir engineering, well testing and reservoir simulation forms the basis of the applied algorithm:
Analytical methods of advancing watercut determination are used during reservoir development analysis. As a result, the reasons of premature water breakthrough toward the production wells and volume of undrained oil reserves became obvious.
During the geology analysis main facies and features of the occurrence and spread are defined; created a distribution map of "superpermeable" facies. As a result, the map of wells interference is generated, in which zones of noneffective waterflooding and degree of reserves involvement in production are determined.
The presence of auto-fracs at injection wells is identified according to the well test analysis. As a result, dependency of auto-fracture generation pressure from injection rates and reservoir pressure is determine. Understanding of this dependency allowed to optimize technological regims of injection wells. Also, dual-porosity parameters of naturally fractured member are determined from these tests, after that simulation reservoir model was adjusted.
Because of the comprehensive analysis and understanding of all processes the large number of scenarios for reservoir development optimization appeared. To reduce the labor-intensive calculations and culling options the analytical model and the algorithm for choosing the best solution was formed. According to the algorithm several options were selected for more detailed calculation with reservoir simulation model.
Inflow Monitoring and Analysis Using Proprietary Intelligent Chemical Tracers in the Yuri Korchagina Field
Authors: Shtun S. , Senkov A. , Surmaev A. 
Published: October 2016

Abstract
The first installation of intelligent tracers system in extended reach horizontal well was deployed by LUKOIL-Nizhnevolzhskneft LLC in a thin oil rim reservoir with a large gas cap located in the North region of the Caspian sea. Putting in operation of the Yu. Korchagin field is challenging serious tasks during development:relative zone inflow estimation;identifying intervals of water breakthrough;long-term monitoring of oil extraction and water level;monitoring of completion equipment functionality.
Traditional technologies of production logging, considering complex well trajectory, are highly risky and expensive.
Fiber-optic system of monitoring of Distributed Temperature Sensors (DTS) would be an ideal instrument identifying the source of gas breakthrough, but such technology is not always feasible due to necessity of rotation of the completion during its running in extended reach horizontal well. Performance of periodic field research via cable is limited due to drilling operations on the platform. In addition to perform such survey it is required to use downhole tractors to transport logging tool. Practice of tractors usage in extended horizontal wells in the field has a negative statistics to reach the toe of the well, as for a project operator it's important to verify remote flow contribution (e.g. 7000 m) in total well flow rate.
To solve the above problem a relatively new monitoring technology has been applied.
At stage of equipment fabrication downhole intelligent chemical sensors were installed in sand screens. Sensors are placed in the drainage area in different intervals along the well to meet objectives by the engineers of LUKOIL Nizhnevolzhskneft LLC to provide flow profiles, identify the location of gas breakthrough and confirmation of the functional work of AICD in the course of time.
After selection of surface samples of hydrocarbons at the wellhead, a laboratory analysis is conducted for chemical tracers in the sample and interpretation of tracer signals during unsteady and steady state production is performed. Some period has passed related to operation of the well after its start. The first well equipped with intelligent chemical indicators has its history of production; the well performance can be evaluated both in whole, and for each zone equipped with chemical indicators.
This paper will review the experience of wireless monitoring for extend horizontal well on the shelf of the Caspian sea.
Problems of Modern Multiphase Flow Measurement: Properties of Two-Velocity, Water-Oil Mix Flows in the Presence of Surfactants
Authors: Dorovsky Vitaly , Perepechko Yury 
Published: October 2016

Abstract
Production logging encompasses profiling of flow velocities, holdup, pressure and temperature along the length of a horizontal well. Its advancement is determined by such factors as mathematical modeling, and development of new tools and software. These activities generalize the understanding of the multiphase flow meter, which requires a proper mathematical tool to calculate the parameters of multiphase flow. The natural water-oil flow always contains surfactants. The substances adsorbed on the surface of oil droplets affect the dynamics of the immiscible fluids; therefore, proper analysis of this effect is particularly important.
The paper presents the theory of two-velocity hydrodynamic continuum taking into account the surfactant effect to analyze the flow regimes of a two-phase system and develop the hydrodynamic grounds generalizing the understanding of the multiphase flow meter. Its two-velocity equations are derived only from the main physical laws. The equations are true for an arbitrary class of the state equations. Its difference scheme is based on the control volume method. The effect of a phase interaction force was demonstrated on the two-phase flow regimes, which is essential for accurate holdup measurements in modern hydrodynamic logging. The theory shows that the surface-tension gradient in a two-phase flow produces an additional drag force. The force is significant and can exceed both the viscous and Stokes friction forces. The theory demonstrates that, in a two-velocity medium, in the presence of surfactants, an additional reactive force is observed that is proportional to the gradient of the surfactant dissolved in water. In this case, the hydrodynamic velocity determines the surfactant spatial concentration. The gradient produces the reactive forces in moving subsystems that affect the rate of hydrodynamic transport. The interaction results in a consistent velocity profile of both water and oil. Having slowed the motion of oil, the surfactant increases the velocity of the water. At the relatively low velocities, the surfactant effects on the phase velocities, which is important for determining the holdups of phases in the cross-sections of production wells.
Compositional Simulator with Non-equilibrium Phase Transitions
Authors: Zubov V. R. , Indrupskiy I. M. , Bogachev K. Yu. 
Published: October 2016

Abstract
The paper presents efficient implementation of the non-equilibrium phase transitions model in compositional simulator. Reservoir non-equilibrium phase behavior effects are examined and simulated with the new approach.
Compositional simulators are widely used for modeling light oil reservoirs, gas injection projects, and gas-condensate reservoirs. Some features for modeling phase transition hysteresis are implemented in black oil simulators, but not in compositional simulators. Though some non-equilibrium phase transition models for compositional simulators were reported in the literature, they were not implemented in industrial simulators because of their complexity. A new physical-based approach is presented in this paper. Modifications for this model are required only to the thermodynamic block of a simulator. All equations and matrix structures for the hydrodynamic (flow) block are not modified.
The new approach is implemented as an extension block in a general purpose reservoir simulator. Implementation of the feature allows to model effects of phase transition hysteresis in compositional simulations. Criterion for determining phase transition type (equilibrium or non-equilibrium) is justified and also implemented.
The application of the new option requires minimum additional input data, which is good for history matching problems. The new approach is tested with numerical cases based on real reservoir data.
Peculiarities of Lihology and Petrophysical Parameters Calculation and Transfer from Epilogs to 3D Geomodel
Authors: Kolbikov Sergey 
Published: October 2016

Abstract
The method of averaging epilog parameters into the cell of 3D grid depends on the type of parameters and vertical cell size. The objective is to improve methods of calculating and transferring epilogs into the 3D grid of geological model. The paper presents the typical mistakes made by designers while reservoir parameters transfer into the 3D grid of geological and hydrodynamic models. The method of pseudo anisotropy factor (Kv / Kh) calculation from well epilogs had been proposed.
The model loses connectivity of the reservoir and understated HCIP when it cells are resulting to non-reservoir ones due to sufficiently high cutoff value of net-to-gross (up to 0.5) for the lithology parameter (reservoir / non-reservoir). To compensate for such imbalance reservoir engineers often neglect the NTG value for reservoir cells, calculating epilog parameters only for the reservoir intervals. Reducing the value for the NTG cutoff down to 0.1-0.2 and the introduction of NTG values for all reservoir cells allows more accurately reproduce the hydrodynamic connectivity of the model and the HCIP distribution.
It is shown that if the value of permeability in the reservoir cell of 3D grid calculate through the mean porosity for all epilog intervals of the cell, then the permeability value will correspond to the geometric mean, and will characterize the vertical permeability. To obtain a correct value for the lateral permeability of the cell it is necessary to calculate it as an arithmetic mean value for all reservoir intervals of the epilog within this cell. The ratio of vertical and lateral permeability will give us the value for the pseudo anisotropy of the cell. Guidelines for calculation and transfer of the epilogs into 3D grid shown in the work will result in the correct initial distribution of the lateral and vertical permeability in the geological and hydrodynamic models, differentiated values for the pseudo anisotropy factors of cells.
For the cases of geological models construction with hydrodynamic grid dimensions the upscaling is performed while transferring well epilogs into the 3D geological grid. The proposed method allows more correct averaging for the initial permeability distribution and calculate the vertical anisotropy for the reservoir cells as a function of their heterogeneity.