bluuebunny/crossref_metadata_2025_split huggingface dataset:
Assessment of the Reservoir Monitoring System and Value of Real-Time Temperature and Pressure Profiles at a HASD Demonstration Project
Authors: Ficocelli Peter , Crecana Virgil , Legcevic Darko , Iordanescu Bogdan , Vincelette Andre , Hyland Connor 
Published: October 2015

Abstract
The Company is developing a heavy oil field in Romania with both in-situ combustion and steam stimulation methods. This paper describes the use of permanent fiber optics based array temperature sensing (ATS) technology in two (2) wells that utilize a horizontal alternating steam drive (HASD) process. The monitoring systems were installed in existing very shallow wells to capture temperature and pressure profiles for both the steam and production cycles of the HASD process and also provide some information about the combustion in-situ effects. During the cyclic steam stimulation (CSS) phase the reservoir's maximum temperature could reach up to 230°C. The steam is generated using mobile boilers which have been proven effective in minimizing steam loses. The ATS optical sensors are written in the core of the fiber and encapsulated within a 6.35 mm capillary using a six sigma qualified process. The ATS instrument string was deployed in the wells with a simplified capillary pump–in installation method and using proven and common well-services equipment. This slimline capillary deployment technique involves minimum wellbore intrusion to reduce deployment and retrieval risks. The wellhead located surface data acquisition and control system captures and stores the subsurface real-time temperature and pressure profiles and provides VPN access and updates to the Supervisory Control and Data Acquisition (SCADA) servers. Modbus over TCP/IP connectivity is used to gain real-time data from the PLC and for archiving the data at centralized location. The temperature and pressure data captured during the installation will be shown to validate the accuracy of the monitoring system and the thermal and pressure profiles of an HASD cycle. This data will be reviewed and analyzed with the emphasis on controlling the processes that have the greatest impact on optimizing production.
Results of Thermo-Hydrodynamic Modeling of Multiple Cyclic Steam Stimulations of Wells in the Permian-Carboniferous Reservoir of the Usinsk Field
Authors: Taraskin Evgenii , Ursegov Stanislav , Gerasimov Igor , Ruzin Leonid 
Published: October 2015

Abstract
The Permian-Carboniferous reservoir of the Usinsk field is one of the largest objects in the world with unconventional reserves of heavy oil. Despite the long history of the development of the reservoir (over 35 years), the cumulative oil recovery is less than 10.0 %. Difficulties in the development of the reservoir reserves due to non-Newtonian properties of the saturating oil with a viscosity of 700 mPa*s and a unique geological structure of a massive reservoir, which is represented by a 300 m carbonate strata of the Middle and Upper Carboniferous and Lower Permian age located at a depth of – 950 to −1500 m and underlained around the perimeter by the active aquifer. The prospects for increasing the oil production of the reservoir are associated with the introduction in the development with the help of innovative thermal technologies its poorly drilled edge area, in which almost one-third of all reservoir reserves is accomulated.
This article is devoted to a discussion of the results of thermo-hydrodynamic modeling performed on the sector models and aimed at selecting the most effective option of the further development of the edge area of the reservoir, for which it is advisable to consider the use of multiple cyclic treatments of wells with radial horizontal bores by dry superheated steam in combination with the central hot water flooding into injecting wells.
Evaluating Heterogeneity of Heavy Oil Viscosity According to NMR Core Analysis
Authors: Musin K. M. , Abdullin T. R. , Khisamov R. S. 
Published: October 2015

Abstract
The paper presents the results of laboratory nuclear magnetic resonance (NMR) studies of oil-saturated core samples of the Sheshminskian horizon of heavy oil fields in the Republic of Tatarstan. The analysis of the results showed that T2 spectra of oil recovered via centrifugation from the pre-heated core and oil remaining in the core are substantially different from each other. Magnetic relaxation rate of residual oil is much faster, and thus its viscosity is significantly higher than that of the recovered oil. The difference can be up to ten times. The spectrum of relaxation times T2 in the original oil-saturated core integrates information about all the fluid contained in the rock.
The results and findings underscore the ability of NMR logging tools to characterize the entire oil fluid in the rock in situ.
Stimulation of Unconventional Reservoirs using Graded Proppant Injection
Authors: Keshavarz A. , Badalyan A. , Johnson R. , Bedrikovetsky P. 
Published: October 2015

Abstract
A method is proposed for enhancing conductivity of micro-fractures and cleats around the hydraulically induced fractures in coal bed methane reservoirs. In this technique, placing ultra-fine proppant particles in natural fractures and cleats around hydraulically induced fractures at leak-off conditions keeps coal cleats open during water-gas production and, consequently, increases the efficiency of hydraulic fracturing treatment.
Experimental and mathematical studies for stimulation of natural cleat system around the main hydraulic fracture are conducted. In the experimental part, core flooding tests are performed to inject suspended particles inside natural fractures of a coal sample. By placing different particle sizes and calculating concentration of placed particles, an experimental coefficient for optimum proppant placement is evaluated. This coefficient corresponds to the maximum permeability achieved after proppant placement. In the mathematical modelling study, a laboratory-based mathematical model for graded proppant placement in naturally fractured rocks around a hydraulically induced fracture is proposed. Derivations of the model include exponential form of the pressure-permeability dependence and accounts for permeability variation in the non-stimulated zone. The explicit formulae are derived for well productivity index by including the experimentally found coefficient for optimum proppant placement.
Particle placement tests result in almost three times increase in coal permeability. The laboratory-based mathematical modelling as performed for the field conditions shows that the proposed method yields around 6-times increase in well productivity index.
Implementation of Low-Residue Polysaccharide Fracturing Fluid System Aids Flowback Recovery at Chicontepec Basin: Field Experiences on Sandstone Tight-Oil Wells
Authors: Castro-Vera Erick , Chuc Edgar A. , Gutierrez Leonardo , Sanchez Alan 
Published: October 2015

Abstract
Low-energy and compartmentalized reservoirs make flowback more difficult than in conventional reservoirs following massive fracturing treatments. Conventional guar-based fracturing fluid systems can cause additional skin damage to the fracture because of fluid residues. Low-residue polysaccharide-based fracturing fluid systems, compared to conventional systems, provide a smaller residue percentage according to laboratory tests, and this result agrees with flowback data from wells discussed in this paper. Costs in primary treatments associated with operational events, such as flowback time, can be considerable for well completion operations. Guar-based fracturing fluid systems were used at the beginning of this basin study. After analyzing flowback and early production data, it was decided to change to a low-residue polysaccharide-based fracturing fluid system and to maintain other variables constant, such as injection rate, proppant concentrations, and treatment schedules, to compare fluid performances, cost benefits, and post-stimulation production rates.
This paper summarizes results for 70+ fracture stages in 30 wells, with an average of 150,000 gal of clean volume per stage and 250,000 lbm of proppant. Guar-based fluid fracturing systems comprise 25% of this study with an average flowback time of 231 hours with 30% (at most) fluid recovery. On the contrary, 75% of the treatments used a low-residue polysaccharide-based system, which required an average of 110 hours of flowback time, while only 10% of the volume was recovered to deliver to production facilities because of the lack of water percentage.
Metal-crosslinked low-residue polysaccharide-based fluids are more sensitive to shear stress than borate-crosslinked conventional systems, and they can become unstable at high injection rates and reduced pipe diameters (3 1/2-in. tubing). Increasing tubing friction requires more hydraulic power to apply the same amount of net pressure at the fracture. According to the diameter restriction, this study includes pumping through pipes with diameters larger than 5 1/2-in., therefore making sensitivity to shear stress a nonissue.
Low residue polysaccharide-based fracturing systems represent an early production alternative for massive fracturing treatments because of their low residue percentage. These fracturing systems can be used in both conventional and unconventional plays, and represent a low associated cost for the well completion.
More with Less: Channel Fracturing Delivers Improved and Sustainable Production with Less Resources in Low-temperature Reservoirs of Tsarichanskoe Field
Authors: Sukovatiy Vladimir , Titov Ivan , Konopelko Alexey , Ovsyannikov Dmitry , Yudin Alexey , Borisenko Alexey , Gromovenko Alexander , Pshenov Konstantin 
Published: October 2015

Abstract
Tsarichanskoe is one of the largest oil fields in the Volga-Ural region of Russia with proven reserves oven 25 million tons of oil equivalent. An ambitious goal to produce up to 2 million tons over the next 5 years was set to achieve. The target formation to produce from is a Devonian reservoir also known as DKT. It is represented by alternation of sandstone, mudstone and siltstone and has challenging properties to deal with such as low permeability and low temperature (60–70C). Economic production from these reservoirs requires an effective stimulation. Conventional hydraulic fracturing in vertical and horizontal wells has been intensively utilized in the field with varying success since the beginning of its development. In some cases, wells completed with conventional fracturing underperform expectations and demonstrate rapid production decline. In other, complex geological conditions restrict treatment size with fracture conductivity being compromised. Therefore, the need exists for a novel stimulation technique capable to perform in the given environment and unlock the reservoir to its full potential.
Channel fracturing technique has been successfully deployed in Russia with more than 170 treatments pumped in different fields. The channel fracturing technique creates highly conductive open pathways within the proppant pack by combining specific pumping protocols with fluid and fiber technologies. It is aimed at maximizing fracture conductivity and establishes unrestricted flow of fluids from the reservoir to the wellbore through the network for channels formed by heterogeneous proppant placement. To ensure stability of the channels network, the use of appropriate degradable fiber materials is imperative. The fiber additive has to be chosen based upon specific reservoir temperature. Several treatments were pumped with unique low-temperature fiber among the first trials worldwide. Successful application of low-temperature fiber enabled channel fracturing technology for Tsarichanskoe. Field campaign was supported by extensive laboratory analysis of the fiber to prove its mechanical properties and required functionality for channel fracturing in low temperature reservoirs.
Initial production analysis indicates that application of channel fracturing in conjunction with the unique degradable fiber resulted in a sustainable oil rate increase up to 30% in comparison with conventional fracturing. The step change in production was achieved with noticeable reduction in proppant and water consumption by 40% and 15% respectively. Successful deployment of the channel fracturing in Tsarichanskoe field offers new opportunities for effective stimulation of low temperature formations in Russia.
Combining Conformance Treatment with Mobility Control Improves Oil Sweep Efficiency in Non-Cross Flow Heterogeneous Reservoirs
Authors: Imqam Abdulmohsin , Bai Baojun , Wei Mingzhen 
Published: October 2015

Abstract
On water flooding process, water preferential flow through high permeability, fractures, and large channels; cause a large amount of recycling of water without much benefit to oil production. Preformed particle gels (PPGs) have drawn more attention to reduce the fluid flow in these large opening features and to improve macroscopic oil efficiency. In spite of the successful applications of using PPGs in plugging such large features, there is still need to combine PPGs with other technology to produce more oil from the low permeable rich zones. The ultimate purpose of this study is to investigate the effectiveness of combining conformance control treatment using PPGs with mobility control using polymer to enhance oil recovery from both swept and un-swept oil zones. PPGs was injected into large permeability zones to reduce their permeability while polymer injected after gel to further increase oil recovery from the low permeability zones. Two separate parallel tubes packed with different sand grain sizes were designed to emulate the case when there is non-cross flow heterogenity between the low and the high permeability layers in the reservoir. Experiments were designed to examine the effect of permeability contrast ratio on the performance of coupling PPG and polymer to increase oil recovery. The results show a significant increase in oil recovery from both low and high permeability cores after performing polymer flooding right away after gel treatment. The oil recovery incremental was varied and strongly dependent on permeability contrast ratios. PPGs improved oil sweep efficiency significantly when the core permeability layers became more heterogeneous. Injection profile was improved after the PPG treatment, thus oil recovery from the low permeability cores was increased significantly.
Information and Analytical System for Prevention of Drilling Fluid Loss
Authors: Lind Yuliya B. , Samsykin Aleksei V. , Galeev Sergei R. 
Published: October 2015

Abstract
Drilling fluid losess seem to be the most widespread type of troubles during well construction on Bashkortostan oilfields. Elimination of a loss requires significant time and financial costs, so timely prevention of a loss by means of picking out appropriate drilling fluids for drilling perilous intervals is currently a promising task. And this is suggested to carry out on the base of field data on earlier drilled wells. The authors have developed an information and analytical system for prevention of drilling fluid losses, which includes a database on losses during wells construction at oilfields in Republic of Bashkortostan (RB), and a module of recommending drilling fluids basing on mathematical modeling and tracing of losses areas.
Geomechanical Model and Borehole Stability Prediction For One of the Fields of Perm Region
Authors: Predein Andrey , Klykov Pavel 
Published: October 2015

Abstract
Production of hard-to-recover reserves of Devonian system by drilling horizontal wells is one of the most promising areas of development of deposits in the Perm region. The main problems in the construction of wells with horizontal completion in the sediments of the Devonian system are related to the loss of stability of clay rocks ranging Timan terrigenous sediments. The destruction of clay rocks is a result of factors such as relieving current tectonic stresses and loss of stability of rocks due to the effect of propping microcracks under the influence of drilling mud. The paper presents the results of the determination of key parameters geomechanical model, calculated the wellbore stability, issued recommendations on the selection of the density of the drilling fluid and the most secure well path. Proposed component composition invert emulsion drilling fluids (IEF), designed to meet the real reservoir properties of unstable deposits of Devonian system. The mud is recommended for carrying out pilot projects for the construction of wells with horizontal completion in the sediments of the Devonian system.
Introduction of Gas Engines for Driving Gears of Pumping Machines
Authors: Yakin A. N. 
Published: October 2015

Abstract
Exploitation of oil sucker-rod pumps is one of the main mechanized methods of oil-mining. All machines are equipped with powerful electric engines, control stations, transformer substations, and overhead power lines. But we can do without this equipment, if in order to drive a pumping machine we use gas engine (GE) powered by associated petroleum gas (APG), obtained in the same well. It solves several problems at the same time. Firstly, associated petroleum gas is utilized.
APG is a mixture of hydrocarbon gas dissolved in oil and it's produced in the result of extraction and distillation. (20-500 m3 of gas per ton). In recent years, the public has paid close attention to the problem of utilization of associated gas, as well as increased penalties for inefficient use of valuable raw materials. From 60 billion m3 of associated gas, produced in the country each year, only half is utilized. The rest is simply flared, leading to half a million tons per year of harmful emissions into the atmosphere and tens of billions dollars of lost profit.
Secondly, at the same time it saves energy, because energy costs play a significant part in the cost of oil. Also it ensures uninterrupted oil production in small fields of remote single wells, where it's very expensive to form air lines. On some wells of "RITEK" the volume of associated gas is large enough. This makes the use of internal combustion engine for driving gears of pumping machines more cost-effective than the use of conventional electric drives.
The Algorithm of Integrated Productivity Forecast for Riphean Fractured Carbonate Reservoirs
Authors: Smolentcev Evgeniy , Kozyaev Andrew 
Published: October 2015

Abstract
This paper describes a method of predicting, riphean cavernous-fractured carbonate reservoir productivity integrating of seismic data, borehole imagers, well test survey and PLT. Apart from the description of the methodology itself, the paper contains some practical results of this implementing this approach based on a full-scale filtration model of one of East Siberia's oil fields.
Energy-efficient Natural and Associated Petroleum Gas Dehydration Technology with Composite Adsorbents
Authors: Akhtiamov A. , Konovalova K. , Kurochkin A. 
Published: October 2015

Abstract
Extracted natural and associated petroleum gases contain water vapor, amount of which is determined by pressure, temperature, gas composition and salinity degree of formation water.
The amount of water vapor in natural gas is regulated, because the moisture can condense in technological pipelines and vessels, forming liquid plugs, gas hydrates, as well as increase the corrosion rate of technological equipment, especially in the presence of acidic and corrosive substances (carbon dioxide, hydrogen sulfide, mercaptans, chlorine ions, salts).
There are several basic technologies used in oilfield conditions for natural gas dehydration: absorption dehydration, low temperature separation, membrane technology and adsorption dehydration.
Adsorption dehydration technology could be applied at all stages of gas production from the wellhead to the consumer: on the gas field and compressor stations treatment facilities, gas-processing on the gas processing plants and chemical complexes, as well as on the gas distribution stations and CNG stations. While technological scheme of gas dehydration unit fundamentally is not changed, differences relate only to layout solutions and auxiliary equipment.
In addition, in the oil and gas industry adsorption dehydration could be used for the gas field treatment of associated petroleum gas, for dehydration of fuel gases, as well as for dehydration of air and other process gases.
This paper presents new energy efficient technology of adsorption gas dehydration technology, which could be characterized by small weight and size of the final installation, small thermal energy and dehydrated gas consumption for regeneration of the adsorbent, and as a result, low capital and operating expenses, which allows to extend the limits of applicability of adsorption technology and to apply it for treatment of large volumes of gas.
Unit provides required degree of gas dehydration for the specified initial data and is characterized by a high level of industrial and environmental safety. Compared with the absorption dehydration, which is traditionally used for gas in fishing conditions developed installation is characterized by the decrease of capital expenses by 30%, operating expenses in 2-4 times, as well as decrease of the required area. Compared to other technologies (low temperature separation, membrane separation) reduced capital costs could reach 40%.
Introduction of Innovative Set for Real-Time Process Control Used for Watercut Prediction
Authors: Pirozhkov Maksim 
Published: October 2015

Abstract
Nowadays, the problem of enhanced oil recovery methods for already-run wells is literally a sticking point for oil and gas wells in Ugra region. Still the issue of development new oil and gas deposits, as well as the gradual replacement of routine labor with automatic systems and introduction of new innovative technologies is of great importance for oil companies throughout the country. Lets try to imagine how can possibly the abovementioned interdependent problems can be solved by using modern science and technology base. For all the oil companies the question on adequate water cut monitoring and control remains as the paramount one. The methods, using pre-separation of the product to gas and the water-oil emulsion, followed by measuring their flow through gauges are outdated. One of the latest technologies of measurement the oil, gas and water flow without phase separation is multiphase well testing. In many cases, they give a more accurate image of flow parameters under dynamic conditions, and are particularly useful for heavy oils and gas condensates where conventional measurement methods are not suitable because of the difficulty in the phase separation. For decades oil and gas industry tried numerous attempts to find a solution to devise a system that could measure the flow rates of well fluids, without dividing them into phases, without using moving parts and controlling the process. However no one has been able to propose a procedure of continuous monitoring, which among other things would make analysis parameters of the working system with well performance prediction and real-time information on well performance delivery.