bluuebunny/crossref_metadata_2025_split huggingface dataset:
A/S-P Alternating Flooding, A Modified ASP Flooding Technology
Authors: Huang Wenqing , Dong Yeliang , Zhao Jinyi , Liu Xiaobo , Fan Yu , Bai Hongjun , Hao Jinsheng 
Published: October 2019

Abstract
A modified ASP flooding technology, in which polymer and alkali-surfactant solution are injected alternatively for several turns, rather than being injected simultaneously as the traditional way, is studied by both lab experiments and a field test.
Experimental results show that the viscosity of polymer solution will be reduced by 30% if alkalis and surfactants are added, while the dynamical interfacial tension is much higher in ASP-oil-water system than in AS-oil-water system. To give full play of these three chemicals on oil recovery, we alternatively inject polymer and alkali-surfactant slugs, and this modified ASP flooding is named A/S-P alternating flooding. A pilot test is then carried out in a water flooded reservoir since November 2008, which is employed in a block of 28 injection wells and 40 production wells.
In the pilot test, alkali-surfactant slugs and polymer slugs are alternatively injected for five turns after a leading polymer slug. Injecting pressure increases in each polymer slug and decreases in the following A/S slug. In the following polymer slug, the injecting pressure of test area is 1.5MPa lower than contrast area and the injection rate per well is 9m3/d higher, while the production is 18% more. Profile tests show that the proportion of injectable thickness to total effective thickness keeps 80% or higher during the whole flooding process of the test area, while the proportion of contrast area is only 70% in the late stage. The minimum water cut during A/S-P alternating flooding is 82.0%, which is 6.1% lower than ASP flooding. However, the water cut increases significantly when A/S slugs are injected, which is an important weakness of A/S-P flooding. When chemical flooding is over, 17.8% of the original oil in place (OOIP) has been exploited by A/S-P alternating flooding, which is more than 7% higher than the contrast area flooded by ASP, while the total chemical cost is 11.3% lower. Therefore, A/S-P alternating flooding can be a cost effective enhanced oil recovery technology.
A/S-P alternating flooding has more injection and production, displaces more zones, gets a higher oil recovery and uses fewer chemicals, which can be a cost effective technology.
Selection of Effective Surfactant Composition to Improve Oil Displacement Efficiency in Carbonate Reservoirs with High Salinity Formation Water
Authors: Kornilov Alexey , Zhirov Aleksey , Petrakov Andrey , Rogova Tatiana , Kurelenkova Yulia , Afanasiev Igor , Sansiev George , Fedorchenko Gennadiy , Fursov Grigory , Kubrak Mikhail , Altmann Thomas , Lichterfeld-Weber Nicole , Bittner Christian , Oetter Guenter , Helwig Ekaterina 
Published: October 2019

Abstract
The paper includes the scheme of surfactant composition selection and the approach to evaluate potential results of injection for Central-Khoreiver Uplift (CKU) fields with carbonate reservoirs. Several scenarios of surfactant composition injection were studied, using high salinity treated formation water (up to 210 g/l) without applying salinity gradient. The first step of surfactant composition selection included testing of water solution stability in formation water that is characteristic for CKU conditions. Then interfacial tension of surfactant water solution with oil was measured, as well as adsorption properties. The target values of interfacial tension were set in the range around 10-2, and not higher than 10-1 mN/m.
Filtration experiments on composite core model were conducted to evaluate the efficnency of selected composition. Development and tuning of linear model for the filtration experiment matched the laboratory results. Obtained parameters are included into the sector model of field development unit, considering the conversion of one of the wells to injection of chemicals. The paper presents preliminary evaluation of technological efficiency for the selected scheme of composition injection.
The approach presented in the current paper can be used to plan injection of surfactant-based compositions into carbonate formation with properties that are similar to investigated values. Applying surfactants that are compatible with high salinity formation water makes possible to use treated produced water as injection medium and it decreases the costs of mix water preparation.
Using Spectral Inversion to Build Acoustic Impedance Exemplified by an East Sibirian Field
Authors: Fagreeva Veronica , Butorin Alexander , Krasnov Fedor 
Published: October 2019

Abstract
The present time is characterized by increased number of features with complex geology and poor exploration maturity where the target interval is represented by thin pays and heavy lithologic heterogeneity.
In most cases, seismic inversion is used to prospect such features; however, quality seismic inversion calculation is quite a labor-and-resource intensive process; given the increasing demand for the acceleration of exploration projects and fast provision of spud-in locations, the need arises for the development and provision of an inversion-building method whose quality would be no worse than that of syncronous inversion and which could be done faster.
This manuscript aims at the developing and benchmarking of a new approach to acoustic impedance forecast. The manuscript describes an acoustic impedance reconstruction algorithm built on wavefield spectral inversion and allowed for low-frequency model based on well logs. To prove its applicability, we tested it using model data, as well as based on an East Siberian field case as part of which the accuracy of reconstruction properties was benchmarked using standard and suggested approach.
Choosing Optimal Standoff for Horizontal Well Profile with High Cavernosity to Achieve Better Mud Removal
Authors: Tcibulskii Mikhail , Vavilov Mikhail , Afletunov Vladimir , Orlov Sergey 
Published: October 2019

Abstract
Cement bond logs in the Messoyakha field indicated only 65% achieved mud displacement, which resulted in poor zonal isolation, resulting in annular pressure and remediation. Casing standoff is the most important factor to achieving better mud displacement from the annular space. The wellbore profile and the presence of caverns have significant impact on casing standoff. At the same time, increased centralization, in some cases, has a critical impact on running the casing to planned depth.
Analysis in the use of different types of centralizers, their spacing patterns, and placement on the casing in the horizontal wells in this field are detailed in addition to the results of trial operations.
Application of Proportional, Integral, Derivative PID Control Loop Algorithm for Optimization of Equipment Operation Used for Decentralized Water Injection System at West Qurna 2 Oilfield
Authors: Letunov Dmitrii , Nepomiluev Dmitry 
Published: October 2019

Abstract
One of the key drivers in gaining the cost-effective, reliable and low-downtime Operation system for major Oil Fields is implementation of Water Injection System (WIS) with capability of online-automated regulation and control.
This Paper outlines an application of Proportional, Integral, Derivative (PID) control loop algorithm for Decentralized WIS (with direct injection from Water Source wells to Injection wells by means of high capacity ESP's) used in West Qurna-2 oilfield located in Iraq, operated by LUKOIL.
PID control loop algorithm has being used in the industry for the years, but not commonly applied as integral component of Water Injection System allowing to maintain optimal equipment modes. Such limited PID deployment is explained by complexity of operational parameters synchronizing for every Water Injection System component.
The decentralized Water Injection System at the West Qurna 2 project is common and united pipeline system for every WellPad that provides water transfer from Water source wells (3-5 wells per WellPad) to injection wells (3-6 wells per WellPad) with line pressure of 70-130 Barg by means of high-capacity ESP equipped with VSD.
Water injection process is regulated by controlling both the conventional ESP parameters (frequency, flow rate, motor current and load, Intake and discharge pressures), line pressure, required injection rate by means of flow control valves, and implemented PID control loop algorithm.
This paper discusses the techniques of PID control loop algorithm application as the tool for: –Pipeline protection against high pressure without full shutdown of water injection process and–ESP automated regulation to ensure operation inside Recommended Operated Range (ROR) and smoothening of ESP mode when any changes in the system happen (i.e. shutdown of other water source well ESP's at the same WellPad or shutdown of injection well) with immediate feedback to Operator Control Room. Implemented approach allows to decrease number of ESP shutdowns and avoid high jumping of ESP loads that consequently leads to maximizing of ESP run life.
Comparative examples and case studies of submersible equipment operation results before and after the application of PID regulation are specified.
Mainly by implementing PID regulation and control stable and smooth operation of equipment and ESP's used for WIS (direct injection from Water Source Well to Injection Well) has been achieved.
New approach for PID application as a tool for pipeline overpressure protection has been formed, which allowed to reduce Capital Expenses for the WIS construction works. Specified case can be used as example for further development and projects in the oil and gas industry.
Comparison of Various Tracer-Based Production Logging Technologies Application Results in One Well
Authors: Arefyev Sergey , Makienko Vladimir , Shestakov Dmitry , Galiev Marat , Ovchinnikov Kirill , Malyavko Evgeny , Novikov Igor 
Published: October 2019

Abstract
In recent years, oil and gas producing companies have increasingly migrated towards using tracer-based methods to obtain data on horizontal wells operation. The interest in these technologies is largely due to their ability to obtain data over a long period of time with a radical decrease in the required resources, thereby providing new opportunities for well management and increasing cumulative production. The aim of this article is to compare the results of applying different tracer-based systems in one well.
Tracer-based technologies produced by different manufacturers vary in physical principles of operation, as well as in the methods of their injection into the well or reservoir. Tracers designed for long-term work are injected into the reservoir with marked proppant or lowered into the wells in the lower completion cassettes. For the first time, alternative tracer-based systems were applied in one well, ensuring the selectivity of work with oil and water. This allowed us to compare the results and evaluate the technology's advantages and disadvantages. The well was completed by multi-stage hydraulic fracturing with the possibility of subsequent port control using coiled tubing. Each of five well intervals were equipped with two tracer cartridges fixed on an MFrac sleeve on both sides. In addition, proppant with markers was pumped in 3 months. The unique signature of the marker was used for each fracturing stage (5 unique signatures for each of 5 fracturing stages).
As a result of this world-first field application of alternative tracer-based systems, valuable analytical material was obtained related to the quantitative analysis of various tracers, the performance of different polymers, and the stability of the tracers’ allocation in the formation fluid. The data obtained confirmed the character of the marked proppant pack washing out with the formation fluid in comparison with the tracer casings attached to MFrac port on both sides.
The following results were achieved upon completion: additional tools were obtained for the correlation of data on the tracers amount and concentration, and comparative indicators of different tracer technologies in terms of efficiency and work accuracy were identified. It was also confirmed that the marked proppant is not washed out into the well under these reservoir conditions. The authors of this article were the first to compare the technologies with different approaches to the tracers’ placement in a well within one project. Based on the project results, the obtained data allowed us to answer many pressing questions from oil and gas producing companies related to the comparison of tracer systems.
Estimation of the Largest Russian Oil Field Development Efficiency Using the Combination of Hydrodynamic Modeling and Horizontal Well Production Logging Methods Using Markers
Authors: Gurianov Andrei , Katashov Alexander , Ovchinnikov Kirill , Gilev Denis , Vasilyev Vladimir 
Published: October 2019

Abstract
Increasing the pace of oil production to achieve profitability in projects has increased significantly with the transition to the active development of deposits with low-permeable reservoirs throughout the West Siberian oil and gas province. The key to increasing production rates for objects with degraded reservoir properties is to increase the technical and technological effectiveness of the applied solutions. The purpose of the article is to evaluate the project using data obtained by the new, innovative tracer-based methods and contemporary types of well completion in well testing to increase the drainage area, flow rate and improve the operational parameters of the pressure maintenance system.
Greater reservoir filtration areas in reservoirs with abnormally low permeability is achieved by using horizontal drilling and fracturing. Modern modeling tools allow for the consideration of uneven development of the horizontal shaft length. Conventional logging methods cannot provide detailed information during the operation of hydraulic fracturing stages, but marker-based methods present a proper production logging alternative, especially given their widespread development in recent years. Using the data of marker diagnostics, it is possible to adapt hydrodynamic models to specify the hydrocarbon production profiles.
The present article brings to your attention sector hydrodynamic model (HDM) calculations that take into account the uneven development of depleting reserves based on marker diagnostics data. A comparison was made with HDM under the assumption of a uniform inflow into horizontal well with MFrac. The model showed several levels of inflow variability obtained through statistical data on the marker production logging of 60 wells performed at various fields.
Application of Time Lapse Gravity Measurements for Oil and Gas Field Development Monitoring
Authors: Kolesov Valentin , Gareev Kamil 
Published: October 2019

Abstract
Time lapse gravity (TLG) technology for producing oil and gas field control involves periodic high precision gravimetric and geodetic measurements at the area of a developed field.
The technology targets the following geological and technological challenges: improvement of field development control by adding independent information from gravimetric variations and finding its relationships with fluid saturation variations in the reservoir;prediction GOC or GWC shifting according to gravity data;precise surface elevation control in time (geodynamics).
TLG is considered as a significant part of the integrated field development control workflow and provides important independent information to be means added to time lapse well log measurements, production data and time lapse seismic where applicable.
The paper describes the methodological basics, provides some results of TLG implementation at a large gas field and estimates of gravity variations during production from a real oil field with a gas cap, which shows the feasibility of TLG application.
Enhancing Efficiency of High-Viscosity Oil Development with Using Autonomous Flow Control Devices. Case Study in Western Siberia.
Authors: Solovyev Timur 
Published: October 2019

Abstract
Most of the new fields in Western Siberia have unfavorable conditions for the development of the field, such as the presence of an extensive gas cap, the low power of oil-saturated oil rim thicknesses, and the underlying water. The field is also characterized by weakly consolidated sandstone and high-viscosity oil. For the deposition of an early breakthrough of water or gas into the wellbore, it was decided to conduct a pilot stage of project on the use of various types of completion (autonomous inflow control devices), which allow controlling the inflow along the wellbore. Formation of completion strategy requires continuous monitoring of wells, evaluation of the effectiveness of cleaning intervals after drilling, interval flow along the wellbore, as well as the detection of water or gas breakthrough areas to identify the ineffective placement of AFCD.
This article presents the results of the use of autonomous flow control devices, an assessment of their effectiveness according to PLT and well logs interpretation and intellectual tracers, as well as analytical methods.
The article also describes general information about the inflow control devices technology, their characteristics and problems that the operators user may encounter when using one or another element of high-tech completion, gives reasons for the use of autonomous inflow control devices at the considered development object.
Analysis of field data and PLT and well logs results revealed that the devices actually work and help to limit water and gas compared to wells that are equipped only with wire filters without inflow control, and also begin to form a unified strategy and concept of well completion based on the data
The results of the work show that currently the use of AFCD for the project is favorable, and the completion of wells without flow control in these conditions is impractical.
Decision Making Process in the Gas Carbonate Reservoir Engineering Based on the Uncertainty Analysis at Various Stages of the Life Cycle
Authors: Ermilov Andrey , Volnov Ignatiy , Zhukov Alexandr 
Published: October 2019

Abstract
Usage of the uncertainty analysis in the carbonate gas reservoir is the most useful instrument for making decisions when changing the field development stages. And it is necessary to use the appropriate approach for each field development stage. The new systems that were used for the fields in Uzbekistan proved their usefulness for the complex reservoir conditions and were based on the deep understanding of the reservoir properties and geological issues as well as clear vison of the project management and criteria for the stage shifting. Carbonate reservoir inherent uncertainties lead to important issue – how to predict the production rate and properly manage the reservoir? Each stage of the field life cycle is characterized by the different approaches towards the uncertainties that must be properly managed.
The example of LUKOIL's reservoir modeling experience in Uzbekistan addresses the uniqueness of each stage by using the decision-making workflows driven by the model and uncertainty analysis. If the first stages are very uncertain, conceptual and need specific approach to define and manage uncertainties, the developed stages have very detailed and robust prediction calling for the usage of the more advanced uncertainty analysis methods. Usage of the specific approach for each stage for over 10 gas carbonate fields examples provides for the clear understanding of the uncertainty level as well as understanding of the main leading indexes requirement to ensure the shift from one stage to another. The paper reveals the peculiarities of the decision-making process for the reservoir engineering and uncertainty analysis for every field development stage. The novelty of the new decision-making system is based on generalization of the methods and approaches of the uncertainty analysis, clear understanding of the main valued indexes and parameters to estimate the criteria for reaching the right decision.
Understanding Well Events with Machine Learning
Authors: Elichev Vitaly , Bilogan Andriy , Litvinenko Konstantin , Khabibullin Rinat , Alferov Alexey , Vodopyan Alexey 
Published: October 2019

Abstract
The key to successful planning of well interventions and other well actions is to understand the current state and the history of the well. Due to the large spread of telemetry systems with high-frequency (up to 1 measurement per second) measurement of parameters, it is possible to use machine learning methods for well events recognition. In this paper we consider well analysis with, aim to identify equipment failures and other influences affecting the behavior of wells.
Typically, several parameters are recorded at the wellhead with high frequency: wellhead and bottom-hole pressure and temperature, flow line pressure and temperature. Also, readings of downhole measuring devices and well logs are periodically made and recorded. The readings of well parameters can be influenced by many factors: manual manipulations on the well, changes in the composition of the produced products, well integrity issues and others.
This work suggests an approach that allows to identify and classify events at the well. The approach is based on the results of constructed synthetic dynamic models of wells and observation of the real behavior of wells. It allows to identify the behavior of individual measured parameters and classify events using all measured parameters in aggregate.
The proposed algorithm allows retrospective analysis of data and identification of different events, such as well tests that occurred in the past. The algorithm also allows the analysis of incoming data and identification of well events in real time. Retrospective analysis of the data was useful not only for detecting anomalies and malfunctions, but also for building a real log of events at the well, monitoring well interventions and building reports on well performance. The analysis of event records demonstrates that only minor part of well events is normally captured in central databases.
The developed algorithm for natural flowing wells can be easily extended to wells equipped with mechanized oil production systems. For example, for wells with a gaslift or ESP installation. The algorithm can be easily integrated into corporate monitoring systems as an auxiliary tool.