The article demonstrates the results of experimental and field studies of the thermal foam-acid treatment technology with the use of water solutions of heat and gas generating system. The potential temperature of the heat-generating reaction upon mixing of agents was estimated in laboratory conditions and the physical and chemical properties of acid solutions were determined. A series of filtration experiments was conducted on treating dolomitized core samples with a basic hydrochloric acid solution.The constant of the rate of reaction between the basic acid solution and dolomitized carbonate rock was determined based on the experiment results. The article provides a brief analytical overview of world experience of the thermochemical treatment of the bottomhole area. The technology selected for the tests called thermo-foam-acid and implies the step-by-step injection of water heat and gas generating solutions with an addition of surfactants and an initiator into the bottomhole area. The heat-generating reaction is accompanied by the generation of a large amount of heat, gases and hot foamed acid. Heating melts high molecular weight oil compounds, washes oil sheen from rock surface and increases the speed of its dissolution with hydrochloric acid. This foam acts as a diverter for the next portion of active acid and prevents undesired stimulation of high-permeability interlayers and fractures. Surfactants in the acid solution increase its ability to penetrate pores and microfractures. The physical modeling of a thermal foam-acid treatment has been performed. Arlanskoe (Kashirskian-Podolskian deposits) and Nadezhdinskoe (Famennian stage) fields where carbonate formations are characterized by high and increased oil viscosity, low reservoir temperature, fractured and dolomitized reservoirs were selected as a site to perform field tests. Well operation at these formations is complicated by the precipitation of asphaltenes, resins and paraffins in the bottomhole area. Solution injection parameters were recorded during treatments based on this technology. The technological efficiency of this treatment was confirmed based on bottomhole pressure and temperature changes during injection operations. Technology efficiency was analyzed and the well flow rate was monitored based on the field test results. The main stages of this work are shown in Figure 1. Figure. 1 Project stages

Kharyaginskoe field is located on the North part of Russia and produced by Zarubezhneft-Production Kharyaga company. The field is on the mature stage, so, it requires the special attention to drilling and production strategies optimization. The field is highly complicated by geological nonconformities (for example, faults), which has the crucial impact on the well productivity, recovery and reservoir management decision. So, the comprehensive understanding the zones complexities such as connectivity and compartmentalization is vital for optimal field development and has always been extremely challenging. The traditional method of using formation pressures for evaluation of reservoir connectivity does not perfectly work for the reservoirs under production as the fluid extraction disturbs the initial pressure equilibrium. This study shows another possible methodology of reservoir connectivity examination based on the analysis of hydrocarbon composition for three zones of Kharyaginskoe field.

A new method for assessing the stability of the asphaltene phase in reservoir fluids using a high-pressure microscope is presented. The new method is based on the observation of the asphaltene particles sedimentation in a vertically oriented sapphire cell. This determines the size of sedimentation particles, their number and sedimentation rate. Experimental results are used as input parameters for calculating solid particles sedimentation of using the Stokes law equation. It makes possible to calculate the density and weight percent of the solid phase, evaluate the aggregative and kinetic stability of the fluid with respect to solid particles depending on thermodynamic parameters (pressure, temperature, reagent concentration). The proposed method was tested in the single-contact study of high-viscosity reservoir oil and liquid carbon dioxide and was compared with the results of asphaltene precipitation gravimetric test. According to the results analysis, were conclusions about the applicability of the new method and the mechanism of asphaltenes precipitation in high-viscosity oil when it contact with carbon dioxide. It is shown that the combination of gravimetric and visual analyzes allows to investigate the asphaltenes precipitaion separately in two processes: reduction of pressure and vaporization of fluids. This makes it possible to assess the likelihood of formation and the effectiveness of reagents for combating solid deposits in the entire process chain of oil production. Concluded that the asphaltenes precipitation in the contact of carbon dioxide and high-viscosity oil occurs according to the complex mechanism and includes intensification due to a drop in oil viscosity and damping due to mass transfer between carbon dioxide and oil phases. From this, inhibitors selection criteria are derived and the using of deasphalted oil as a stabilizer of asphaltenes is proposed.

At the final stage of gas field development, the reservoir pressure and the volume of produced gas are decreasing. At the same time, the moisture content of reservoir gas and the amount of produced formation water are increasing. It leads to the appearance of additional operation problems affecting on the stable operation of gas gathering and gas treatment systems. In particular, in the winter season there is primary risk of ice depositing in-field pipelines. In comparison, at the initial stage of field development the hydrate formation in-field pipelines took place. In any cases methanol is used both to ice and hydrate control. The analysis of the current operation parameters of the complex gas treatment plants (CGTP) of the Cenomanian deposit of the Yamburgskoye field shows that at dehydration units’ methanol vapors in addition to water vapors are extracted from the natural gas. This worsens the performance of CGTP. So, it is necessary to optimize the technological parameters of the absorption process to provide both the dew point specification and amount of extracted methanol vapors. To achieve the purpose under consideration, a technological model of absorption units is developed taking into account the extraction of methanol vapors from the gas. Model was adapted from the field data (by the analysis of water content in lean and rich diethylene glycol (DEG) as well as in reflux). Based on the results of the simulation the influence of the key parameters on dried gas dew point is estimated. Recommendations are proposed for adjusting the operating modes of the CGTP, taking into account the maximum possible reduction in operating costs. In particular, a significant reduction of the irrevocable losses of methanol is ensured. The specific rate of the lean DEG fed to the absorber is used as a regulated parameter for the operating mode of the CGTP. The centralization of production facilities takes place at the latest stage of gas field development. So, the possibility of preliminary gas dehydration before transportation to mother CGTP is considered. A criterion for reducing the operational costs for dehydration process is proposed. It allows to determine the optimal parameters of the operating modes of the absorption and to regulate the water dew point of the dried natural gas at the entrance to the main gas pipeline by changing the dehydrating depth for each of the CGTP. In case of centralization of production facilities, the stage of preliminary gas dehydration reduces the risks of ice deposit in the inter-field pipelines. As a result, the specific consumption of methanol is reduced.

Wax deposition contributes significantly and painfully to the deliverability of produced fluid along its journey from porous media through the wellbore to the production facilities. Solutions for wax fighting include, but not limited to, chemical, mechanical and/or thermal or a combination. Wax management has been always a key concern for Dragon Oil offshore Turkmenistan as per wax depositions in the wellbore of most producers has driven Dragon Oil to adopt different approaches to handle this critical issue. However, optimizing these approaches is of a paramount importance especially in today's industry situation and also to honor weather changes and logistical challenges while working on controlling wax related issues. Wide range of wax management strategies are practiced to prevent, mitigate and remediate wax deposition. Several studies have been conducted to investigate problem roots and to develop the most practical solution for wax management starting from downhole to the onshore facilities. Chemical injection and mechanical Slick Line (SLK) well interventions are the techniques most commonly practiced in Dragon Oil to manage the deposited wax in the wellbore (~ 100 jobs of wax cut/week and ~ 700 liters/day of wax inhibitor-optimized dosage). Compliance Sheets were designed and being optimized on daily basis to manage such intensive well intervention. Modifications to drilling Basis of Design (BoD) allowing chemicals injection at different depths/dosages and wellhead area thermal treatment are examples of precautions that being followed to secure wax free flow. Wells that are completed in "A-Sand" reservoir have severe wax challenges due to high wax appearance temperature (WAT). Having BHFP < BPP and WHT < WAT makes wax precipitation and deposition an imminent phenomenon. In addition, several studies showed that the above combination along with fluid properties and potentially low velocity contribute to more wax deposition in the tubing. Furthermore, harsh weather adds more challenges to the Company's efforts to manage flow assurance related issues. For example, delays in Slick Line operations due to difficulties in mobilizing SLK units allow more soft wax to build up and become harder at different depths. As a result, significant disturbance in the wells productivity and flowlines deliverability is observed causing losses in the field total production. Plugging of chemical injection systems (control lines and nipple), as first guard in some wells, adds another complication to deal with de-waxing management in the field. Dragon Oil has also successfully applied a few surface thermal means to manage wax deposition in surface facilities that will be discussed also in this study highlighting monitoring, surveillance and optimization efforts. It was observed that optimizing Wax Inhibitor (WI) dosage help in decreasing the frequency of mechanical de-waxing operations. Obviously higher WI dosage rate increases the operational costs and potential side effects (i.e., emulsion, foaming, etc.). Dragon Oil developed a practical approach to thoroughly monitor all wellhead related parameters and managed to add value through the comprehensive optimization cost/effect versus costs/risks of wax management by mechanical, chemical and thermal means.

The resins of heavy sour crude oils with high vanadium and nickel contents have been investigated. Using original procedure, the concentrates of organonitrogen bases with various compositions and molecular masses have been recovered. The effect of the concentrates on the colloidal stability of the oil to asphaltene precipitation has been studied. Kinetic studies using UV spectroscopy have shown that organonitrogen bases, as well as natural amphiphiles in resins affect asphaltene aggregation and decrease the rate of their precipitation in the solvent/flocculant system.

At present, Russia's oil production in a number of large Eastern Siberia fields (Verkhnechonskoye, Talakanskoye, Yaraktinskoye) has reached or approached its maximum designed levels, therefore, the fields have progressed to the second stage of development or to the beginning of the third stage experiencing production declines. Thus, these fields can be categorized as brownfields. At the Verkhnechonskoye oil and gas condensate field, for the first time in the history of domestic oil and gas production the geologists came across a highly mineralized productive cross-section with the pore space partially or completely filled with salt. This determined the distinctive development features of the main target - the Verkhnechonsky horizon (Vch) (99.8% of the field's production). A distinctive feature of this paper is the description of the approaches to the development of the Verkhnechonsky horizon associated scaling formation and control using a wide range of geological and geophysical tools. The value of the work lies in the summary of lessons learned when managing reserves production and well operation processes at a large Eastern Siberia field, the development of which is complicated by the presence of salts in the pore space, which was the starting point of accumulating the knowledge on salt reservoir development. The experience based on a range of approaches and technical solutions can be applied to similar Eastern Siberia reservoirs with similar geological and physical characteristics.

This paper describes a new method for monitoring oil pipelines, as well as highly efficient and automated paraffin deposit monitoring method. When operating oil pipelines, there is an issue of paraffin, resin and salt deposits on the pipeline walls that come with the oil stream. It ultimately results in frequent transportation suspension to clean or even replace pipes and other equipment, thus shortening operation periods between repairs, creating emergency situations and increasing production expenses, badly affect environment, damaging ecology and spoil underground water, kill animals, birds etc. Oil spills contaminate rivers, lakes, and ground waters. oil transportation monitoring issues are still subject for further studying. Thus, there is the need to invent radically new automated process control and management system, together with measurement means intellectualization. The measurement principle is based on the Lambert-Beer law that describes the dependence between the gamma-radiation frequency and the density together with the linear attenuation coefficient for a substance. Using the measuring system with high accuracy (± 0,2%), one can measure the thickness of paraffin deposits with an absolute accuracy of ± 5 mm, which is sufficient to ensure reliable operation of the pipeline system. Safety is a key advantage, when using the proposed control system.

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

Supercritical CO 2 flooding in unconventional tight sandstone reservoir is characterised as the complex changeable and irregular effects on the properties of crude oil and the system of pore-throat-fracture in formation. In the light of the above problems, being aimed at a typical unconventional tight sandstone reservoir, such a new thinking and methods as the methods of combining multiple experiment and test measurements, the methods from qualitative analysis to quantitative evaluation, the methods from phenomenon observation to essence revelation, and the methods from data statistics and analyzing to representation model setting up are putforwarded and used to study those problems comprehensively. In the CO 2 displacement process, asphaltene, resin, and paraffin are easily to be separated out from crude oil. Meanwhile, pore throats in rock formation can be blocked by the precipitate. In addition, when CO 2 was dissolved into formation water, PH value of the formation water was changed to be weakly acidic which has a certain dissolution for part of mineral composition of formation core, increasing the pore volume of reservoir. This article will launch the quantitative evaluation of the effects on these two factors on the pore throat system. By changing the experimental conditions to determine the amount of asphalt component in the core during whole experiment, then using the advanced and reasonable test technology to analysis the result after the experiment. The results showed that the recovery ratio of kerosene and oil increased with changing the experimental conditions. The recovery of kerosene raised with increasing pressure and volume. The increased range permeability of nature core rised the highest (6.7%) when the pressure was 26 MPa; The main reason for this phenomenon is acidification in the system of pore-throat-fracture. Less than 26 Mpa, the recovery of kerosene raised with increasing pressure. The amount of asphaltene deposition reached the greatest (51.3%) when the pressure was 29 Mpa. The decreased range of core permeability reduced the lowest (31%) when the pressure was 29 Mpa. The amount of asphaltene deposition and the decreased range of core permeability increased first and then reduced with increasing injection pressure and injection volume of CO 2 .

During reactive flows in porous media with precipitation of a solid chemical reaction product, the permeability reduction occurs. The mathematical model for reactive flow in porous media formulated contains two empirical parameters – the kinetics rate coefficient, determining the reaction rate along with reagent's concentrations, and the formation damage coefficient, reflecting the permeability reduction due to the solid precipitation. These parameters are determined from the laboratory coreflood tests with commingled injection of reacting fluids. A routine laboratory method determines the kinetics rate coefficient from expensive and cumbersome reagent concentration at the core effluent; then, the formation damage coefficient is calculated from inexpensive and simple pressure drop measurements. In the current paper, a laboratory method for determining both coefficients from pressure measurements only is developed. The method utilises pressure measurements at the core inlet, effluent and some intermediate core port during commingled quasi steady state flow of incompatible fluids. The data treatment is based on the analytical model for one-dimensional commingled flow of reacting fluids. The formulae for determining the model coefficients from pressure measurements are derived. The intervals for inverse solution existence, uniqueness and stability are established. Good agreement between the model constants as determined by the routine and three-point-pressure methods validates the proposed method.

Today, the oil industry faces a number of problems encountered in exploration and exploitation of oil and gas fields. At the same time, thanks to the joint efforts of experts in various fields of science and technology, there are new kinds of specialized research, which in combination with other methods of laboratory and field testing can improve the efficiency of existing technologies through an integrated approach to data acquisition and analysis. At present, increasing attention of researchers is drawn to a variety of nondestructive testing methods (research) associated with the use of various types of computer tomography (X-ray, magnetic resonance and others.). Application of research of this type in combination with other methods is wide enough and is only limited by the scientific training and applied knowledge as well as the scientists’ ability to invent. Particular attention is paid by the authors of this work to the following core areas of laboratory research: the study of the structure of the pore space of rock samples in order to evaluate the reservoir properties of the productive formation, complex filtration and tomographic studies to assess the extent of damage to the reservoir (as a result of the acid treatment, alkali treatment, hydraulic fracturing, killing operations on production and injection wells, evaluation of the depth of penetration of drilling mud filtrate into the formation, precipitation of resins, asphaltenes and paraffin in the bottomhole formation zone). Simulation of this process in a specially equipped laboratory allows for the assessment of the depth of penetration of the gelling agent into the formation or will help to establish the effectiveness of other ways to reduce water production, change the injectivity profile of injection wells, etc. This article presents the results of several types of special studies and a series of data to draw conclusions about the high significance of the research. The paper describes the standard type of study to assess the porosity of productive stratum rock (for example, collectors with hard to recover reserves of the Bazhenov Formation of Western Siberia), the method of evaluation of formation damage resulting from asphaltene deposits in the operation of wells with bottomhole pressure below the gas saturation pressure, and the results of the application of computer tomography in the evaluation of the results of classic acid treatment of bottom-hole zone of wells in carbonate hydrocarbon (oil and gas) bearing reservoirs. Studies have shown that the application of computer tomography in some cases, allows to obtain data on the processes of reduction or increase in permeability taking place in a core due to the introduction of any of compositions in the bottomhole formation zone. Construction of three-dimensional models can improve the degree of comprehensibility and effectively visualize data of models built (for example, models of porous space and the rock matrix). Ultimately, the results of X-ray computer tomography are very easy to understand, highly visual and can be presented in a variety of projects, from high-quality preparation of geological and technical measures in wells to inclusion of field development projects.

At the current stage of development the majority of oil fields operated by Bashneft-Dobycha are characterized by high water-cut of the produced fluids. When produced water is oversaturated with salt-forming ions scaling formation takes place not only in downhole pumping equipment of producing wells but also in the near-wellbore zone of the reservoir. Presently the main preventive techniques against scaling or salt precipitation in wells include cyclic adding of chemicals through the annulus, continuous batching of chemicals with dosing pumps into the annulus or through a capillary tube at the suction pipe of a pump. Less common are submersible downhole containers. These techniques have been field-proven as successfully protecting pumps and production tubings against scale formation however they are incapable of limiting salt precipitation in the interval from the near-wellbore zone in the reservoir to the suction pipe as inhibitors are injected after salt crystals start growing intensively. Squeezing of scale inhibitors into a productive reservoir is a good alternative to the techniques mentioned above as this treatment provides combined protection of the near-wellbore zone and downhole pumping equipment against scale formation.

The deposition of inorganic substances that accumulate in the Electric Submersible Pumps (ESP′s), tubing, and piping systems, equipment for the collection of oil is a significant complicating factor in oil production. The practical results of scale management was shows that the cost of prevention scale deposition is ten times less than the financial cost to remedy the effects of scaling. This paper presents the main provisions of the technical and economic management strategy scaling in the West Siberian oil fields Rosneft, are the criteria for selecting technologies to prevent scaling, implemented in the form of matrices and patterns, as applicable, developed an integrated approach based on the identification of “bottlenecks” in the full cycle of oil production: from the producing formation to the processes of the oil. Depending on the degree of salt saturation of formation water, oil sold technology, offers a range of technologies to combat scaling - from simple, traditional methods of protection to more complex integrated treatments. It is shown that the implementation of such an approach leads to a significant reduction in costs due to the problem of scaling.

Of late there is a sharp increase in the area of oil field development that contains the reserves due to several reasons referred to as hard-to-recover ones. In this connection there is expediency in conducting severe studies, both from the standpoint of geological conditions of their formation and from the standpoint of the reservoir and its fluids. One of the major objectives while performing viscous and wax field development program that are characterized by abnormally high temperature of solidification is the performance of studies related to rheological properties of water/oil emulsions during the process of their dehydration and their further transportation in a mixture with other types of recovered products. The recently published materials on rheology of water/oil emulsions are mainly based on system modeling that uses distilled water and what is more important, within the frames of negative oil solidification temperature range [1]. On the other hand, the requirements towards the quality of preliminary dehydration are usually governed inside a wide interval (up to 10-20 of %) of residual water contents and cannot serve as a benchmark to select the degree of well product dehydration in specific cases.

Many oil producers in the Rocky Mountains region, USA, make use of electrical submersible pumps (ESP) to assist the lift of produced fluids. This region of the country is well known for its very harsh winters, with outside temperatures as low as −40 °F (−40 °C). ESP failures resulting in increased lifting costs due to workovers, lost oil, and logistics can be caused by many factors, including reservoir solids eroding the ESP or being trapped within the intake and pump stages, mechanical and electrical problems, and scale deposition. ESPs are particularly sensitive to calcium carbonate scale formation due to the extreme skin temperatures that can develop and often require continuous chemical injection to control this problem. Calcium carbonate scale formation in ESPs is a well known contributor to ESP failures. Large pressure drops combined with high temperatures increase the risk of calcium carbonate deposition even in mildly scaling systems. Scale formation on the motor housing acts as insulation, preventing heat transfer from the motor to the well fluids, causing the motor to be insufficiently cooled. Any scale deposition on the pump impellers can cause an imbalance and vibration, degrading pump performance. Continuous scale inhibitor treatment of ESPs to mitigate calcium carbonate scaling is a common practice. However, the choice of scale inhibitor requires careful consideration due to the high skin temperatures that can develop and can lead to inhibitor decomposition. Effective continuous treatment of ESPs during the winter months in regions where very low temperatures can be expected require product formulations capable of withstanding these harsh conditions without significant changes to their physical properties. This paper presents and discusses, with the aid of laboratory and field data, the development and deployment of a thermally stable scale inhibitor suitable for treatment of ESPs that can also be deployed in very cold climates, along with the monitoring tools used to ensure effective treatment.

MEG regeneration and injection unit regenerates aqueous MEG. The main goal of this unit is approaching desired MEG concentration whereas MEG loss via removed water is a big issue. Circulating glycol is polluted with Ca++ and Mg++ which forms carbonate scale and causes plugging of pipe lines, filters, lean/rich exchanger, still column packings and reboiler tube bundle and decreases their efficiency, consequently increases MEG loss via top product. Different alternatives exist according to similar experiences around the world. Using specific criteria and AHP (Analytical Hierarchy Process) method priority of these alternatives has been found. Results are as following: Increasing number of filters Using parallel filtration system Replacing charcoal filters in short periods Increasing flow rate in case of no operational problem Considering all constrains, final recommendation includes improvement of operational conditions, regular cleaning of equipments and enhancing filtration system.

The paper presents the description of an integrated approach, which is implemented in a program module and allows predicting scale deposition in well based on distributions of specific multiphase flow parameters (temperature, pressure, and gas content). Parameters are obtained from calculated pump operation regimes. The method's apparent advantages are presented, namely: - automatic input of reservoir water/gas chemical content data, - numerical estimation of scale deposition risk in different well sections by means of the saturation index, - built-in tips on selecting the optimal scale prevention technology specifying the inhibitor type and amount, - prediction of pump life cycle buildup, - estimation of the expected economic benefit caused by scale prevention. The prediction method of scale deposition and the algorithm of selection of the scale prevention technology can be successfully used during analysis of scale deposition risk and planning the activities for scale prevention for a group of oil wells or oilfield. The proposed algorithmic module has been tested in a number of active oil fields of Western Siberia, and has already garnered positive references from production professionals. This module is planned to serve as a basis for similar modules for forecasting risks of mechanical dashes, corrosion and paraffin buildup.

Abstract Rosneft has oil fields in Western Siberia producing fluids from a number of wells via Electric Submersible Pumps (ESP's). While production rates are increased using ESP's, run time can be compromised by the formation of scale within the inner workings of the pump. The deposition of scale can be detected by the pumps requiring increasing amounts of current to maintain the flow rates. Eventually the pumps fail (either mechanically or electrically) and have to be replaced. Typically examination of these pumps indicated the main failure mechanism to be the deposition of Calcium Carbonate scale within the pump. The actual run times achieved tend to be dependant on the severity of the scaling produced water, but were typically in the order of weeks. However in some extreme cases, pump failures had occurred in a matter of days from replacement and start up. It was proposed that one treatment strategy to increase the pump run time by inhibiting scale formation was via a Scale Inhibitor Squeeze application treatment. The Squeeze process and inhibitor application is very well understood, but to get successful squeeze treatment you need to perform adequate laboratory selection tests, including inhibition efficiency testing and core flood evaluations. This data, together with the Heriot Watt University Squeeze VI modeling can get an approximation to the potential squeeze life. This paper presents the testwork performed to identify and develop successful Scale Inhibitor Squeeze Chemistries suitable for application in Western Siberia. It details the laboratory testing, the coreflood evaluation and Squeeze VI modeling. The Squeeze application and performance of the first well squeezed is reviewed together with a summary of the current status of the wells squeezed. An economic evaluation of the squeeze is also performed together with a summary of all the wells treated which demonstrates that the squeeze application provided a very cost effective method of scale control to maximize pump run time and increase the net well value. Introduction Yuganskneftegaz is Rosneft's largest oil-producing enterprise. It holds licenses to develop 26 oilfields located in the Khanty-Mansiysk Autonomous District of Western Siberia. Yuganskneftegaz was established in 1977, and in early 2005, it was fully integrated into Rosneft's core production base. Yuganskneftegaz is responsible for fields that contain approximately 16% of Western Siberia's recoverable oil reserves. Nearly 80% of them are concentrated in the Priobskoye, Mamontovskoye, Malobalykskoye and Prirazlomnoye fields. Production of oil and associated gas at Yuganskneftegaz in 2006 amounted to 56 million tonnes, and 1.5 billion cubic meters, respectively, which is 70.1% and 11% of Rosneft's total production. Yuganskneftygaz Primary fields are: Priobskoye, Prirazlomnoye, Mamontovskoye, Malobalykskoye The number of wells in production in 2006 was 7,707. The average production per well is 21.3 t/day (2006).

Abstract Wax deposition in pipelines is a constant concern in Flow Assurance studies. When the temperature along a pipeline falls below the so-called Wax Appearance Temperature (WAT) of the oil, various problems due to wax precipitation and deposition may happen: wax can deposit on pipewalls, wax particles can increase the viscosity, and, due to plant shut-down, wax can cause the crude oil to gel. To counter-act wax problems, two approaches are possible: prevention (like e.g. insulating the pipe or adding chemicals to the oil) or removal (like e.g. pigging the line). In order to correctly design pipelines and to implement proper strategies for prevention and removal, a reliable description of the phenomenon plays a key role: without such a model, every intervention has to be oversized, dramatically increasing costs and risks. A number of commercial codes have been developed to describe the deposition process based on a number of mechanisms (molecular diffusion, shear dispersion, Brownian diffusion, gravity settling …) that have been proposed to elucidate the evolution of wax deposits on cold pipe walls. The comparison of these different commercial codes to each other, and with field data, represents a first result of this study. The models still present limits, many of which relate to the practical reliability of model predictions and their impact on operations: – The relative importance of the different and/or concomitant mechanisms proposed for wax deposition modelling is still not completely clarified. – The models present a number of arbitrary or not well defined values of parameters that are often used to adjust predictions with respect to a specific experimental result. – The models have been developed using gel deposition rates observed in the laboratory flow loops and the scale-up of the deposition usually leads to an over-prediction of the wax deposition in field pipelines, due to the unavailability of a reliable upscale criterion. In addition, the lack of detailed field data makes the qualification of the different models difficult. Due to the failure of available models, the consolidated proposed mechanisms of wax deposition have been critically analysed. It resulted that there is need for alternatives: molecular diffusion controls wax radial transport, but this is not the only process that counts. Convective axial transport brings enough waxes to form a gel on the wall, and this gel formation is the fast process responsible of the deposit geometry. On these bases, a new approach has been developed founded on this physical picture of the process; the comparison of its results with field data is by far better than the other ones.