bluuebunny/crossref_metadata_2025_split huggingface dataset:
Active Technologies of Production-Logging and Well-Testing in Injection Wells with Induced Fractures
Authors: Musaleev Kharis 
Published: October 2017

Abstract
This work is dedicated to the creation of complex methods of determining reservoir properties in injection wells with injection-induced fractures by production logging tests (PLT) and well testing.
During exploitation, injection wells are known to create uncontrolled fractures so called injection-induced fractures. They appear when the injection pressure exceeds formation tensile strength. They can spread both in height and length, depending on the injection rate.
The risks of fractures inducing during work are especially great in tight formations. They influence oil field development negatively because their growth in height can connect additional layers that change the distribution of water injection in layers.
Complex analysis of PLT and well testing during step-rate injection tests and shut in provides the opportunity not only to determine fracture properties, but also to estimate parameters of layers connected by injection-induced fracture. Series of different injection pressure tests and a fall-off are suggested to perform this task. Suggested interpretation method is based on the fact, that the size of fracture changes with different injection pressure, connecting more or less layers. Joint analysis of well tests and PLTs helps to diagnose and estimate the number of these changes.
Application of Special Well Logging Techniques for Geomechanical Model Imporvement in Naturally Fractured Reservoirs
Authors: Ezhov K. , Arsibekov A. , Dubinya N. 
Published: October 2017

Abstract
Geophysical Well Logging (GWL) is an important source of information about stress-strain state of the upper Earth's crust. Nowadays there are many methods of mechanical and stress properties estimation around the wellbore are developed and implemented. However, quantitative estimation of maximum horizontal stress (SH) is still quite problematic. This paper is dedicated to reduction of uncertainty on the stage of SH estimation by means of additional information of rock structure from special GWL: full-waveform logging (FWAL) and wellbore imagers (WBI). Straight consequence of this specification is geomechanical model reliability increasing and clearer understanding of naturally fractured reservoirs.
This paper was done for oilfield located on the south of Pannonian basin. Productive intervals are associated with crystalline schists of Paleozoic age. These rocks are very dense, have relatively high britlleness and many natural fractures, which are the main drivers for oil production. In this case, geomechanical parameters are closely related with petrophysical properties.
The work is based on complex interpretation of conventional and special GWL, which resulted in natural fractures identification and characterization. As one of the possible approaches of qualitative fracture permeability prediction Rock Physics was used. After classification of all fractures on induced and natural, permeable and impermeable it is possible to specify 2 important geomechanical parameters: azimuth of SH and its magnitude. The last parameter is one of the most complicated for quantitative analysis and there is still no direct or general method of estimation. At the same time, by minimization of error around this value, we can achieve several applied benefits: reduction of costs due to optimal well trajectory, mitigation of risks related to wellbore failure, increasing of hydraulic fracturing efficiency etc.
Analysis of relationship between stress state of the fracture and its flow properties allowed to estimate the possible range of SH values. Together with calibrated magnitude of minimum horizontal stress (Sh) this approach was used to prepare the complete analysis of main stresses on the examined field.
Prediction of Physical-Mechanical Properties and In-Situ Stress State of Hydrocarbon Reservoirs from Experimental Data and Theoretical Modeling
Authors: Dubinya N. , Tikhotsky S. , Bayuk I. , Beloborodov D. , Krasnova M. , Makarova A. , Rusina O. , Fokin I. 
Published: October 2017

Abstract
The study is devoted to preparing data for three- and four-dimensional geomechanical modeling. The main focus remains on the problem of predicting the physical and mechanical properties of the medium at the scale of the reservoir based on the logging data and laboratory studies. The predicted properties are further used to prepare a three-dimensional geomechanical model of the reservoir. The model is complemented by the boundary conditions for solving the poroelastisity problem formulated in terms of stresses. The question of obtaining these boundary conditions remains a distinctive point of investigation. The main approaches of estimating in-situ stress state from logging data are considered with further choice of the method of reconstructing stresses from special well-logging techniques’ data. The stress profiles are reconstructed for the wells added to the geomechanical model.
Practical Application of Geomechanics for Critical Depression Estimation in Sand Control Problem. Case Study for Kikinda Oilfield
Authors: Konstantin Lezhnev , Tatyana Timofeeva , Biluta Maksim 
Published: October 2017

Abstract
Unconsolidated reservoirs on Kikinda oil field cause sanding issues, which complicate exploiting of the wells. As a result, predicting critical depression above which intensive sand production commences becomes substantial problem to solve.
1D-geomechanical wellbore stability models were used as a tool to evaluate critical depressions on production wells. The fundamental complicacy in modeling was the poorly preserved core, so that it was impossible to conduct rock strength tests. Therefore, the approach to solve inverse problem approach was investigated. It allows determining formation strength from completions, historical production data and production initiating tests.
Input data for modeling included standard set of logs (resistivity, gamma, neutron, acoustic (compressional wave velocity)); shear wave velocity recovered by means of a neural network, mini-fracturing data was used in matching the value of minimum horizontal stress. The correlation between the strength of uniaxial compression and elastic modulus was derived from matching the modelled profile of cavities with caliper log in conjunction with historical data.
There were two ways to confirm the models. The first was by production initiation tests on pre-targeted depressions for new intervals along with sand production monitoring. The second was by calculating depression and comparing with predicted value for previously perforated intervals (where data was available), that is retrospective analysis.
According to historical data, the wells equipped with filters and gravel pack systems have 1000 days less mean time before failure (MTBF) than the wells that flow freely on subcritical depressions. Moreover, filters, presenting supplementary obstacle for fluid, often result in high skin values up to 40-80. At the same time, to reduce risks of needing the next workover gravel packs are being installed on the vast majority of the wells. It is possible to indentify relatively firm intervals with high critical depressions and design their completions excluding the installation of filtering equipment. As a result, well performance could be improved.
Conducted evaluations juxtaposed with production tests showed that solving the inverse problem approach allows utilizing geomechanical models in critical depression estimation for pay intervals. The main uncertainty of the technique is associated with low accuracy of forecasts for intensively flushed intervals. Supplementary studies on how high watercut influences rock strength was beyond the scope of the project.
To sum up, the approach of solving the inverse problem was introduced to predict sand production problems for the complex F on Kikinda oil field. The methodology incorporates rock strength determination based on caliper log and production history data. The advantage of the technique is the possibility to carry out evaluations even in the absence of core geomechanical tests data.
Methodology for Calibration of Geomechanical Field Model for Assymetric Hydraulic Fracture Design Based on Actual Data
Authors: Solovyev T. , Vishnivetskiy A. , Naumov Y. , Martynov D. , Kiselev V. , Naymushin A. , Frolov A. , Leontev I. , Abdrakhimov A. , Korovaychuk Y. , Bezikov A. 
Published: October 2017

Abstract
This paper discusses an approach to the static Young's modulus calibration on the basis of fracturing statistics from one of the West Siberian fields. The relevance of this work is due to the fact that there are many fields in the region where multi-stage fracturing is en masse carried out in horizontal wells, but laboratory tests of mechanical and strength properties are lacking. The procedure is based on reiterated matching of estimated fracture closure time to the actual values obtained during interpretation of data-frac test (or calibration or minifrac test) results in the course of the sequential search over the pairs of Young's modulus and leakage factor values. Then simulation of main fracturing is carried out, and simulation result is compared to the actual results of the works (whether fracture was successful or finished with emergency shutdown of pumps). From the entire set of experiments, the multiplier that satisfies all accidents and describes successful operations is chosen. Calibration of mechanical properties and stress model was successfully carried out in this field using the field data of more than hundred fracturing operations, which is evidenced by the similar values obtained in fracturing simulation and half-lengths of hydraulic fractures matched with field development data in one of the hydrodynamic model implementations.
This work is a continuation of research [1, 2] and includes comparison of field development parameters in both calibration methods, which led to the final decision on the repeated laboratory studies, because none of the calibration methods used allowed creating a single universal model of mechanical properties. One of the models more reliably describes the situation of fracture development within the rock mass, the other relates to fracture development along the fault. In addition, the geomechanical model analysis also revealed that in most cases where fracture intersects the fault it would develop along it.
Creation of the Strength Envelope for Rock Samples by the Multi-Cycle Loading Method
Authors: Skripkin A. G. , Polyakov D. A. , Toropetsky K. V. 
Published: October 2017

Abstract
The paper presents the results of a comparative analysis of strength envelopes plotted by two methods — in accordance with GOST 21153.8 and by the multi-stage loading method (ISRM [1]). The importance of this study is associated with a number of issues that arise during selection of core samples for analyzing elastic deformation, as well as during laboratory rock mechanics tests. The comparative analysis of the results shows that a curve that describes an elastic zone of rocks (the so called "strength envelope") can be generated promptly and with greater accuracy if samples are tested by the multi-stage loading method. This method can be recommended for situations where there is no sufficient number of conforming samples for laboratory deformation tests. The paper illustrates correlations for various parameters of the strength envelope plotted by the multi-stage loading method and demonstrates a wellbore stability log based on these correlations.
EOR by Smart Water Flooding in Sandstone Reservoirs - Effect of Sandstone Mineralogy on Initial Wetting and Oil Recovery
Authors: Mamonov Aleksandr , Puntervold Tina , Strand Skule 
Published: October 2017

Abstract
"Smart Water" is a modified injection brine specially designed for inducing wettability alteration to improve the oil recovery, and it can be injected in both secondary and tertiary (EOR) production phases. It is a low cost and environmentally friendly EOR technique, easily implementable in most oil reservoirs, both carbonates and sandstones. For an optimized Smart Water design, both initial reservoir wettability and the wettability alteration need to be understood. It includes surface mineralogy, brine composition and surface-active components in the crude oil. In sandstone reservoirs, the Smart Water EOR understanding is complex, involving several chemical liquid-solid interactions. The scope of this paper is to investigate how different sandstone minerals could affect initial rock wetting and wettability alteration during Smart Water injection.
A set of experiments was performed to study the influence of sandstone mineralogy on the Smart Water EOR processes. The chemical interactions between brine and rock minerals in sandstone cores were tested by evaluating the produced water chemistry. Crude oil-brine-rock interactions were also tested by static adsorption tests and core floods. Oil recovery tests were performed to compare the ability of the different injection brines to enhance oil recovery from sandstone core material.
Clay minerals contribute with most of the pore surface in sandstones. The experimental results have shown that adsorption of polar organic components onto the clay minerals are mostly dependent on brine pH, but also on brine composition/salinity, temperature, and type of clay minerals. For a wettability alteration to take place, initially adsorbed polar crude oil components must be desorbed from the mineral surface. Presence of feldspar minerals may affect the brine pH, and thereby affect the desorption of the polar organic components, and the reservoir wettability. Other minerals, such as evaporites, may also affect the wettability alteration process by Smart Water.
As a result, detailed knowledge of the rock mineralogy is needed to be able to predict the initial rock wettability, and to evaluate the Smart Water EOR potential in a sandstone reservoir.
Effective Use of Data-Driven Methods in Brown Fields
Authors: Temizel Cenk , Putra Dike , Anggraini Henny , Moreno Raul , Drozdov Oleg , Skiba Andrey 
Published: October 2017

Abstract
Several facets and uncretainties are present in petroleum oilfield operations, due to which decision making is a crucial process that ensures operational viability. For the purpose of decreasing risk and providing better insight, uncertainties must be reduced through a well-organized historical database. This is critical especially in the development of new fields.
An understanding of the cause-effect relationship between attributes and outcome of field operations can be gained through statistics. Through the use of statistical methods there is an opportunity to turn large amounts of data into knowledge for efficient decision making. Unfortunately, the lack of a well organized historical database limits the use of these data for improved results.
Reservoirs, being physically complex systems or having comple relations between the causes (attributes) and effects (outcomes), could use a multi-attribute based statistical model that will allow for improved results of future actions through better decision making. The first step in building a data driven model collection of relevant historical data pertaining to the phenomena to be modelled. Significance of each attribute of the historical data to the outcome is mapped through a multi-variate regression. From this analysis optimum range for each attribute that will give best results and maximize returns can be identified. It must be noted that relevant attributes must be those events and key parameters that largely influence the outcome.
In this study, performance of vertical and horizontal wells in tight reservoirs was selected as the outcome with the factors affecting it to be modeled. A numerical simulation model has been used for validating the data-driven model by determining the significance of each parameter and the optimum operating intervals.
Integrated Approach to Determination of Optimal Capacity and Configuration of Booster Compressor Station at Different Realization Stages
Authors: Poushev A. V. , Nerodenko D. G. , Kudrin P. A. , Yazkov A. V. 
Published: October 2017

Abstract
Development of a natural gas field by depletion drive is characterized by a decrease of average formation pressure, bottom hole and wellhead pressures of production wells over time. As a rule, during the initial field development period available formation pressure is sufficient for gas transportation from wellheads to a treatment facility and then to a tie-in to the trunk gas pipeline without using the compressor equipment. However, the formation pressure is decreasing gradually during the whole field life and this in turn leads to a decrease in the entire system "Reservoir - Well - Infield Gas Collection Networks - Gas Treatment Plant". There comes a point of time when the pressure of gas at the gas treatment plant (GTP) inlet becomes insufficient for its treatment and further supply into the trunk gas pipeline under the required pressure and flow rate.
Thus, from the point of view of infrastructure development and production technology the process of development of gas and gas condensate fields is divided into two periods: natural pressure and artificial lift production. The difference between these two periods lies in usage of a compressor unit designed for increase of the produced gas pressure to values required both at inlet of the treatment plant (in order to ensure the working parameters of the gas treatment process) and for further supply into the trunk gas pipeline. This unit is called a booster compressor station (BCS). As a rule, it is located at the site adjacent to the GTP site (Figure 1) and is used for the following purposes: Compression of gas for its downstream transportation;Maintaining of the required gas pressure at the GTP inlet.
Thus, BCSs are used for extension of the stable gas production period at gas and gas condensate fields where formation pressure is decreased to the point at which pressure in the field gathering main pipeline, at GTP and in trunk gas pipeline restricts flow rates of the wells. In other words, BCS allows to maintain the GTP capacity at the designed level and to increase gas recovery factors as decreased pressure at the BCS inlet may be used for wellhead pressures decrease and increase of flow rates.
Influence of Permeability Distribution on Gas Recovery from Massive Reservoir with Bottom Water
Authors: Indrupskiy I. M. , Arkhipov Yu. A. , Anikeyev D. P. , Zakirov E. S. , Mamedov E. A. , Zakirov S. N. , Mikhaylov V. N. , Volkov Yu. A. , Tsagan-Mandzhiyev T. N. , Klimov D. S. , Varyagova E. P. 
Published: October 2017

Abstract
A significant contribution to the natural gas production is delivered from massive reservoirs with bottom water of several unique fields of Western Siberia, confined to highly productive Cenomanian formation. Most of them are brownfields at low reservoir pressures.
Despite the high permeability of the reservoirs, a strong heterogeneity in the distribution of reservoir pressure and elevation of the gas-water contact (GWC) is observed, which is not reproduced by full-scale flow simulation models.
The purpose of this study was a comprehensive analysis of permeability data from various sources for one of such objects to explain the observed features of field development. The analysis of areal and vertical permeability distribution includes the results of well log interpretation (WLIR) by three methods in 81 wells over more than 250 m of reservoir thickness, and several tens of pressure build-up curves (PBU). The analysis made it possible to identify the main causes of the uneven distribution of pressure, GWC elevation, drainage of gas volumes associated with a multi-fold difference in the average permeability between the drilled central (dome) part of the site and on its periphery.
As the gas is produced and the GWC shifts upward, the contrast in permeability of the drilled and un-drilled zones increases, and the most permeable intervals pass to the area below the GWC. It is for the first time for the long-developed highly productive gas reservoirs with bottom water in the Cenomanian formation that complex analysis of well logging data, field development control data, and 3D reservoir models has been used to justify interrelation between the inhomogeneity of gas drainage, reservoir pressure distribution and GWC advance and the distribution of permeability within the reservoir. The need for detailed geological analysis is shown for constructing a model of the reservoir properties distribution in the inter-well space to help localizing and activating the remaining gas volumes, which are greater than 440 billion m3 for the Medvezhye field alone.
Perspective View on Gas Well Stimulations in Case of Complex Carbonate Reservoir
Authors: Zhukov A. , Volnov I. , Ermilov A. , Sidikhodzhaev R. 
Published: October 2017

Abstract
Most modern challenges of gas field development are caused by an increase in complexity of geological structure, mainly associated with carbonate reservoirs. The studied field is characterized by the reservoir complexity, heterogeneity of reservoir properties both laterally and in section, the high impact of stratification factor and variability of rocks at micro scale. It significantly affects reliability of well productivity and field gas production prediction.
For such fields, in order to reduce risks, it is necessary to identify the best technology for well stimulation, which allows achieving high gas recovery and economic efficiency. In this article, the five main criteria for the efficiency of such well operations are formulated.
The authors present the results of application of basic well stimulation technology for carbonate reservoirs. It is acid treatment (acidizing) with various chemical compositions. The results of work on selective acidizing, both with the use of packer systems and with the use of chemical deviators, are described.
On the next step a review of existing methods of well stimulation and selection of a new perspective technology, alternative to acid treatment, is performed. As an untested technology, the acid fracturing with flow deflectors is considered. Polymer spheres or complex polymer systems based on glass fibers and resins may be used as the deflectors.
The purpose of acid fracturing is production enhancement by increasing of reservoir conductivity in the bottom-hole area, activation of non-flowing reservoir zones and reducing skin factor and D-factor values. An important task is to involve low permeable zones containing significant volume of gas in the production and preserve high productivity of high permeable zones.
The selectivity effect is provided by flow deflectors. This technology is advisable to conduct on reservoirs that have several separated productive layers, when it is necessary to treat each layer.
The authors identified main criteria for application of acid frac and selected appropriate wells. The design of acid fracturing was made with the use of a specialized software package. The impact of the reservoir features on fracture geometric parameters was studied. The final forecast of gas production increased. Economic efficiency was estimated with a use of the full-scale reservoir simulation model.
The practical significance of the work is to generalize the experience of pilot projects carried out at the field, and to select a perspective technology for well stimulation in conditions of complex low permeable carbonates.