bluuebunny/crossref_metadata_2025_split huggingface dataset:
Towards Effective Resolution of Borehole Stability Issues in Koshayskaya Suite while Drilling Horizontal Sidetracks in Samotlor
Authors: Kharitonov A. B. , Pogorelova S. , Tikhonov E. V. , Sergeev S. L. , Andriadi S. 
Published: October 2012

Abstract
The development of the AV1 (1–2) reservoir of the Samotlor field is a priority because it accounts for 37% of the recoverable reserves of the deposit. Horizontal wells were proposed for this reservoir to help ensure satisfactory production figures. The primary problem associated with the drilling of horizontal wells by sidetracking is the necessity of opening the interval of unstable mudstone in the Koshayskaya suite, which is the overlapping impermeable seam AV1 (1–2). In the recent past, successful sidetracking in an extended interval of Koshayskaya clay exposed at an angle of more than 70° was considered to be a difficult task, and despite many attempts, this has not been achieved. In 2011, while drilling one of the wells using standard KCL/Polymer, an attempt was made to drill such a well. Initially, an additional inhibitor, asphalthene (a stabilizer of shales), was also added to the existing drilling mud used in sidetracking, but because of a more complex profile of traversing the Koshayskaya shale, various complications developed during drilling, precluding a trouble-free drilling process. The goal was set to solve this problem. After in-depth laboratory studies involving cuttings and cores collected during the drilling, the use of an additional reagent, a shale stabilizer, which includes a mixture of asphaltenes, gilsonite, and polyglycols with various cloud points was proposed for the existing drilling solution system. This system enabled the drilling of 32 wells with a complex profile. It also significantly reduced the construction time required for each well.
A Drilling Fluid with High Inhibitory Characteristics, Based on Freshwater, Contributing to Increased Drilling Efficiency in More Than 600 Wells at the Salym Oil Fields
Authors: Vasiliev Michael , Afanasiev Oleg , Mekhdihanov Rustam , Rusanov Andrey , Kharitonov Andrey , Romanishin Constantine , Bulanov Denis 
Published: October 2012

Abstract
The drilling fluid solution system traditionally used in Russia is a Potassium Chloride (KCl) based, non-dispersive system with a low solid phase content. The use of KCl / polymer water based mud (WBM) is explained by the necessity to inhibit hydration of argillaceous rocks with a high content of smectite from Tertiary and Cretaceous sedimentations. Currently, the use of KC1 based WBM is limited because of their negative effect on the environment. Environmental restrictions pertain to the requirements for water and permafrost rock preservation. The limited used of KCl is also associated with the limited resources for the storage of freshwater for technical needs at the rig sites, and the luck of year-round road. The products delivery to the rig site is possible only once a year using winter roads.
For the first time, a freshwater-based drilling solution was used at the Salym Petroleum Development (SPD) project in 2006. The use of the new high performance freshwater-based fluid (HPFWF) ) at the Salym oil fields enabled a significant decrease in the volumes of prepared solution; it also reduced waste volumes, drilling cost, and duration, as well as the cost of delivering chemical reagents. The use of HPFWF enabled a decrease in the drilling solution price, which is one of the important factors when compared to traditional KCl / Polymer WBM. This reduction was achieved through a reduction of the volumes of prepared solution and through a decrease in dilution volumes. The selected system of drilling solution is also an optimal system that enabled us to reduce the time required for well construction. The most important characteristics of HPFWF include flexibility and an ability to easily achieve desirable parameters for the drilling solution, as well as for drilling wells with a complex profile.
This paper describes the main principles of HPFWF, as well as its advantages and limitations. This paper also addresses principles of the drilling fluid selection, and optimization. It also demonstrates the mile stones of a project's progression with HPFWF, and practices used at the SPD project.
Peculiarities of Thin Oil Rim Development
Authors: Kolbikov Sergey 
Published: October 2012

Abstract
Thin oil rims associated with gas-condensate field development have one common problem – low oil recovery. The main reasons are fast gas and water conning of the producers resulted in sharp oil rate decline and low cumulative oil production per well. One of the main reasons of low recovery efficiency is that with oil saturated thickness less than 10 m most of oil in place volumes allocated to transition zones.
Thin oil rim development was studied based on the 3D numerical simulation of one of the pay zones in Low Cretaceous formation of Western Siberian gas-condensate field. Several development scenarios (on depletion, with water injection, with and without simultaneous gas production from cap, different well completion) were analyzed.
Thin oil rim development was studied based on hydrodynamic modeling of West Siberian gas-condensate fields with oil rims at Low Cretaceous sands. Analysis of several scenarios of oil rim development with different well completion, and gas cap development at different timing are given.
Several factors were estimated with strong impact on the effectiveness of oil rim development (oil rates decline, water cut and gas-oil ratio growth, cumulative oil production per well): capillary pressure definition, well completion (horizontal vs. deviated), gas production from cap. Derived several conclusions: cumulative oil production from thin rims is very sensitive to the capillary pressure value, horizontal completion is most effective for rim development; limited production from the gas cap simultaneously with oil production could lead to a higher oil recovery at certain geological conditions.
Investigation of SWAG Injection and Prospects of Its Implementation with the Usage of Pump-Ejecting Systems at Existing Oil-Field Infrastructure
Authors: Drozdov A. N. , Drozdov N. A. , Malyavko E. A. , Alekseev Y. L. , Shayhutdinov I. K. , Zakharyan A. G. 
Published: October 2012

Abstract
The amount of unconventional oil resources in the world is increasing more and more up today, therefore the search for effective methods of layer stimulation is required. One of the methods of Enhanced Oil Recovery (EOR) is water-gas injection with a new approach - simultaneous injection of water and gas (SWAG - Simultaneous Water Alternating Gas) as a mixture with a bubble structure by means of multistage pump-ejecting systems. They allow to prepare a stable water-gas mixture on the surface and to inject it into the reservoir, using simple, reliable, and commonly used equipment.
The main effects of SWAG are enhanced oil recovery and utilization of low-pressure associated gas. Distinctive features of the pump-ejecting technology are a minimum of capital investment and the use of existing oil-field infrastructure.
For the conditions of Russkoye and Samodurovskoye oil fields laboratory filtration tests on sand-packed models were conducted, and also calculations of different process flowsheets based on the results of ejectors and ESP bench tests were carried out. Experiments have shown that SWAG significantly increases the oil-displacement efficiency, while the maximum effect is observed in the gas content 25% with the addition of surfactants in a water-gas mixture. Selected technical layouts of pump-ejecting systems allow injecting the water-gas mixture under a pressure up to 16 MPa at the lowest inlet pressures. Due to developed technical solutions the used equipment can operate in wide ranges of adjustment without significant reduction in the energy efficiency.
Thus, the generalized results have showed high efficiency and availability of this technology at a number of Russian oil fields.
The Use of Umbilicals as a New Technology of Artificial-Lift Operation of Oil and Gas Wells without Well Killing when Workover
Authors: Drozdov A. N. , Malyavko E. A. , Alekseev Y. L. , Robin A.V. , Alekseev A. I. , Stefomirov A. V. , Ageev S. R. 
Published: October 2012

Abstract
Currently, the main part of oil in Russia and in the world is produced from low- and average-flow-rate wells. Comparing to high-yield well stock, artificial-lift production from these wells has its own complications associated with increased overheating of equipment, with more intensive process of salt and paraffin-asphalt deposition. This leads to the necessity of frequent round-trips and, as a consequence, well killing. As a result the costs and time for workover increase; also while killing low-flow-rate oil wells, filtration characteristics of the borehole zone are getting much worse. In addition, the technology of artificial-lift operation, based on pumping the liquid from the bottom to the surface, is becoming more promising for the flooded gas and gas-condensate well operation. Typically, these wells are operated at a late stage in a high water content and low reservoir pressure, when well killing is also related to a risk of significant gas productivity decline.
In this regard, we developed a new artificial-lift technology without well killing. A distinctive feature of the technology is the use of umbilical, which is made as one segment on the basis of steel-polymer pipe. Umbilical includes both hydraulic channels for the fluid flow and electrical conductors of different cross sections for the power of ESP that allows you to replace the commonly used steel tubing with an external installation of the power cable. Wellhead BOP provides the possibility of workover without well killing.
Bench tests of umbilical with a suspended ESP were successful and they confirmed the operability of the technology. Umbilical itself is favorably different from tubing as it reduces the probability of damage of the power conductors and leaks occurrence, reduces hydraulic friction losses, heat losses, physical and chemical inertness.
Thus, this technology reduces the time and maintenance costs of workover, increases the security of round-trips, and also increases the efficiency of artificial lift operation of oil and gas wells.
Modeling Uncertainties in Carbonate Karstic Reservoirs: Presentation of a Tool and its Application to a Real Field Case in Russia
Authors: Biver P. , Longis Ch. , Penna E. , Ovsyannikov A. 
Published: October 2012

Abstract
This paper is presenting a methodology to model karstic diagenesis with geometrical processes. This fast procedure is efficient to model karstic drainage zones in an uncertainty framework with multiple realizations. The technique is firstly depicted: from a set of simple parameters (paleo-aquifers, infiltration or dissolution zones, conduits characteristics: length, direction, density, and aperture) the incremental porosity and permeabilities associated to karstic processes are calculated directly on the reservoir grid; different typologies of karst can be addressed: "plateau" karst, hydrothermal karst and island sponge karst. Subsequently, an application to a real field case is addressed with multiple realizations of the fast procedure. The Object 2 reservoir of Kharyaga carbonate oil field, lying 60 km north of the Artic Polar Circle, in Nenets Autonomous Territory was modeled with a multi-phase island karst in agreement with the sedimentological interpretation from cores and borehole images. Several hundred realizations have been performed; each realization is scanned with connectivity computations in order to sort the models regarding relevant criteria (volumes connected to wells). Some recommendations and conclusions are suggested from several experiments on this topic.
Increased Turbo Compressor Reliability by Analysis of Fluid Structure Interaction
Authors: Smeulers J. P. , Díez N. González 
Published: October 2012

Abstract
The integrity of compressors and pumps is of paramount importance for the gas and oil industry. Failures may result in serious production losses that are in no proportion with the cost of the equipment involved. Besides, the equipment may be inaccessible for maintenance for a long period of time due to unfavourable weather conditions.
The requirements of compressors with respect to pressures, capacity, power and operating range, are increasing. The answer to this is innovative compressor concepts, advanced materials and manufacturing techniques. Unexpected phenomena, however, for instance due to fluid structure interactions, will occur that can lead to serious damage of the machine. In this paper such a phenomenon is discussed by presenting a case study.
On the NAM L9 platform, a centrifugal compressor was operated for the transport of gas to shore. The compressor showed serious vibrations at certain conditions that finally led to failure. An analysis of the vibration measurements showed that extremely large vibrations could occur at the blade passing frequency. By means of modeling, an analysis could be made of the acoustic resonances that could possibly occur in the compressor. It was found that a likely cause of the failure was a resonance mode in the shroud cavity of the 3rd and 4th stage. The acoustic resonance modes could be excited by pulsation sources present in the machine. Especially, the sources at the low solidity vanes were suspected to contribute to the excitation of the resonance. Vortex shedding at the impeller edge was also suspected to contribute. The resonance in the cavity may exert large dynamic forces near the trailing edge of the impeller shroud. Due to a structural vibration modes of the shroud, a fatigue failure occurred.
The paper describes the root cause analysis consisting of an analysis of the acoustic and structural vibration modes. The consequences for the design of similar compressors are subsequently reviewed. A future outlook is presented concerning dense gas compression systems for CO2 and high pressure reinjection.
In-depth Sweep Efficiency Improvement: Screening Criteria and Engineering Approach for Pattern Evaluation and Potential Field Implementation
Authors: Manrique E. , Garmeh G. , Izadi M. , Salehi M. , Romero J. , Aye N. , Thomas C. , Shevelev P. 
Published: October 2012

Abstract
A common problem of waterflooded oil reservoirs is the premature water breakthrough bypassing high remaining oil saturation in unswept zones that are risky targets for infill and sidetrack drilling. Early water breakthrough can be caused by reservoir heterogeneity and unfavorable mobility ratios of oil and injected water. There are several IOR/EOR technologies that can be used to reduce water production and increase sweep efficiency. Polymer gels ("Conformance treatments"), polymer flooding and Colloidal Dispersion Gels (CDG) are some of the technologies most commonly used during the last few decades. However, the applicability of a given technology will depend on the problem (e.g., water channeling, adverse mobility, etc.) and its applicability under given reservoir conditions (e.g., temperature, salinity, lithology, and injection and fracturing pressures, among others).
The purpose of this paper is to describe screening criteria for thermally-activated polymer (TAP) flooding technology implementation before starting detailed project evaluations. Based on the suggested screening criteria and evaluation approach, it is possible to rank patterns or asset candidates for in-depth conformance treatments to improve sweep efficiency or delay premature water breakthrough. This is especially important for projects in remote areas or in offshore conditions where water handling is costly.
Based on field experiences, laboratory experiments, and new simulation approaches that are being continually improved, in-depth conformance treatments are carefully designed before pilot or asset implementation.
The proposed screening methodology was used to evaluate and rank temperature-triggered polymer applicability in more than 20 Russian oil fields. Results show how to identify good or poor candidates to evaluate the technology, which increases the probability for successful implementation. In some other instances the combination of technologies might be required to maximize ultimate recoveries.
Thirty Years of Experience in the Application of Thermal Recovery in the Permian-Carboniferous Reservoir of the Usinsk Oil Field
Authors: Taraskin Evgeniy , Ursegov Stanislav , Muliak Vladimir , Chertenkov Mikhail , Alabushin Andrey 
Published: October 2012

Abstract
The Permian-carboniferous reservoir of the Usinsk oil field is the largest one in the Northern European part of Russia considering the amount of original oil-in-place. Since live oil due its high content of asphaltic-resinous components has a very high viscosity (approximately 710.0 mPa*s) beginning from 1982 in several parts of the reservoir, different modifications of thermal enhanced oil recovery techniques (hot water and steam flooding, cyclic steam stimulations of producing wells) have been introduced. In recent years, in order to improve the efficiency of thermal technologies, their combinations with chemical agents are being tested, particularly, with the non-organic gel-forming compositions "GALKA" that increase the sweep efficiency of steam injection, and with the oil-displacing compositions "NINKA" that provide the additional oil displacement.
This article is dedicated to the discussion of the experience of the thermal oil recovery gained in the Permian-carboniferous reservoir of the Usinsk oil field during the last thirty years.
Successful Application of Foamed Acid Stimulation of Severely Damaged Perforations in a Horizontal Intelligent Well
Authors: Ruksanor W. , Webers J. , Vargas E. , Gdanski R. , Vickery S. 
Published: October 2012

Abstract
Well LA-552 is the first Lunskoye horizontal oil rim appraisal/producer well targeting the oil rim underneath the Daghinsky gas reservoir. The well is a smart well completion having three zones (one gas zone for auto gas lift and two oil zones) remotely controlled by three inflow control valves (ICV's).
Pressure transient analysis on production data indicated a very high Darcy skin factor causing much lower production than expected. This was predominantly caused by overbalanced perforating with an oil-wet calcium carbonate (CaCO3) fluid-loss control pill used in the production liner.
Due to the well configuration, the damaged zones were not reliably accessible by wireline or coiled-tubing making re-perforation or acid jetting very difficult and risky. Without well recompletion, the only remaining option was to pump acid down the tubing through the ICV's to dissolve the pill across the long perforation intervals of both oil zones (approx. 200 meters long for each zone).
Zonal coverage (diversion) was expected to be a major challenge for an acid remediation treatment, since the perforations were behind tubing and accessible only through the ICV's. Various diversion methods were considered. Foam diversion in combination with a slow reacting acid system was selected to ensure zonal coverage.
An extensive series of lab tests were performed resulting in an acid blend of 9% formic acid containing 7% KCl (temporary clay stabilizer), 2.5% mutual solvent, 0.6% corrosion inhibitor, 15 lb/Mgal inhibitor aid, and 2% foamer being recommended for removal of damage believed to be oil-wet carbonate filter cake. The recommended acid was qualified as having passed oil-wet carbonate filter-cake dissolution tests, mud and oil compatibility tests, corrosion tests, and foam stability tests.
The acid stimulation was successfully performed in September 2011 with the following result: Net oil production increased 2.5 folds at 20% water cut (same as pre-stimulation)Major improvement of upper zone. Darcy skin reduced by 10 folds and productivity index (P.I.) increased by 4.3 folds.Limited success for the lower zone. P.I. increased by 54% but no significant improvement seen in Darcy skin. The limited success of the lower zone could be explained by a combination of low injectivity (0.5 bpm) and operational challenges causing sub-optimum foaming.
First Deployment of Oriented Perforation in Lunskoye
Authors: Lyapunova V. , Komolafe O. , Vargas E. 
Published: October 2012

Abstract
The development of the Lunskoye gas field is the core of the Sakhalin-2 project operated by Sakhalin Energy Investment Company Ltd. The existing gas wells in the Lunskoye field each has capacity to supply gas at rates of about 250–300 MMscf/day. At these rates, sand prevention, rather than control is critical.
The original wells were selectively perforated enabling these well to produce sand free to date (a period of over three years now). Selective perforation however cannot delay sand production later than 2028 without a significant reduction in gas rate. Selective perforation also avoided perforating the most permeable (and productive) zones as they are interpreted as "weak" and prone to sand production.
With state of the art oriented perforation technology and an improved understanding of the stress regime of the field, oriented perforating was selected for the latest gas well in Lunskoye with following potential benefits: Sand production is delayed to end of field life.Allowing perforation of weaker, more productive sands.
Significant Changes to Service Contracting and Execution are Required to Optimize the New Environments for Well Construction: Valuable Lessons from Russia
Authors: Whalley Robert , Aker Gokhan Haydar 
Published: October 2012

Abstract
Abstract: Significant changes to service contracting and execution are required to optimize the new environments for well construction. Valuable lessons from Russia.
Well construction challenges for Russian oil and gas producers can be broadly grouped into two categories. Firstly those fields in new frontiers ("NF") such as the arctic and offshore, in which risk management and technological solutions are paramount. And secondly, mature fields ("MF") in which cost management and efficiency are drivers. Drawn from experience of the re-emergence and transformation of the Russian oil and gas industry over the last 10 years, this paper reviews historic and current approaches, and recommends new models for partnership between operators and service companies to improve performance and encourage investment in technology.
Specifically, it is suggested how traditional Russian approaches, revised and revamped with new structures, processes and technologies, can provide a basis to exceed benchmark drilling efficiencies in mature fields. It also suggests how an improved approach to front end planning, engineering, and collaboration, can decrease project risks in "new frontiers". Some of the lessons learned are globally applicable.
Another key conclusion is that distinct organizational cultures are required in new frontiers compared with mature fields, and that these cultures are remarkably difficult to contain within one operational entity.