bluuebunny/crossref_metadata_2025 huggingface dataset:
E-Field Real Time Well Temperature Monitoring - Kharyaga Field Case
Authors: Semenov Andrey , Renaud Antoine , Allanic Christophe
Published: October 2012

Kharyaga field is a complex karstified carbonate reservoir located in a harsh arctic environment of Timan Pechora region on the North of Russia. The main Kharyaga reservoir, still under development, is subdivided on several layers and is characterized by an important heterogeneity (spacial distribution, fractures, karstified areas, etc …) leading to a very complex flow distribution in the reservoir (sweep efficiency) as well as in the well (water breakthrough, possibility of cross flow). In addition, the oil of this reservoir is waxy crude with high positive appearance pour point temperature.

High dynamic data quality and adequate real time follow up is mandatory for proper reservoir behavior understanding and characterization in order to be able to take effective operational decisions in due time and then maximize production level. Estimation of each layer contribution to the overall production allows proactive reservoir management including real time follow up and well intervention planning.

Fiber optic systems were installed as a part of the upper completion system below ESP in front of perforated interval. Each development pad is equipped with permanent DTS (Distributed Temperature System) to acquire temperature traces data in selected wells. An innovative system was implemented in order to ensure temperature traces acquisition, transfer and storage in real time to Moscow office, which allows reservoir engineer to interpret in real time and upon operational request any variation (well rate, watercut increase, Wax deposition evolution along the well, etc…) and take well-informed decision. This new procedure allowed to reduce drastically the time needed to integrate temperature information thanks to human interference reduction in the data transfer and data storage. Real time qualitative interpretation, thanks to real time data, allowed curative program and improving scrapping frequency leading to production gain.

In this paper, interpretation and action plan taken will be described in various conditions, such as: –Determining the contribution of main contributing layer in a single phase flow well - 90% of inflow was produced only from first 20 m out of 45 m perforated height–Identified a primary water-flooded zone after rapid water breakthrough. This zone was isolated leading to a 50% watercut decrease–Detecting water cross flow from a shallower water bearing reservoir into Kharyaga reservoir. A cross flow rate was estimated based on acquired temperature data and help designing remedial work-over. Cross-flow was successfully eliminated and the well was put on stream as producer with pure oil thanks to adequate remedial work over design

Obtained knowledge brings better understanding of the field behavior and revision of the object development strategy.
Invasion Modeling Assists in the Formation Permeability Evaluation from Resistivity Profiles and Mudcake Thickness
Authors: Makarov Alexander , Eltsov Igor
Published: October 2012

An invaded zone forms when mud filters into a permeable formation during and after drilling. The mud filtration process is affected by mudcake buildup, well pressure overbalance, and mud properties. Mud invasion changes the spatial distribution of resistivity in the near-wellbore zone – data that could be estimated from inverting the results of resistivity logging data. Invasion simulation can be used to predict invasion depth, mudcake thickness, distribution of resistivity, and formation permeability.

This paper presents an invasion simulation algorithm developed from the Buckley–Leverett filtration model, which takes into account mudcake buildup. This algorithm is used to calculate the near-wellbore water saturation and salinity distributions. These characteristics are used for resistivity profile calculations by an Archie-type equation.

The main goal of this paper is to propose a method of mudcake data interpretation based on a mud filtrate invasion simulation algorithm. This method yields the mud filtrate volume, water saturation and salinity distribution. To verify the results, the values obtained were compared with the results of the induction log and laterolog inversion from several vertical wells. This approach increases the significance of the mudcake thickness data and illustrates the practicality of the joint interpretation of resistivity log data and the mudcake thickness (the former being highly sensitive to resistivity changes within the invaded zone).

In addition, this paper suggests a technique for evaluating formation permeability from mudcake thickness. This technique is applicable if the mudcake was not damaged during the drilling operation. The algorithm was tested and verified by the log and core data obtained at several vertical wells.
Simulation of Complex Carbonate Field: Double Media vs. Single Media Kharyaga Field Case
Authors: Khvatova Irina , Renaud Antoine , Malyutina Galia-Banu , Sansiev Georgiy , Kuzilov Igor
Published: October 2012

This paper presents the successive modeling solutions used to estimate the performance under primary and secondary recovery of the Kharyaga field. Kharyaga object 2 is characterized by different zones of heterogeneities and reservoir type: while platform margin is fractured and karstified, no karstic features are identified in the platform interior, transition zones seems the most complex.

To decide on further development of the field two dynamic models of the field were developed: –Double porosity-double permeability–Single porosity-single permeability.

The paper discusses advantages and disadvantages of these two approaches to predict a behavior of such a complex field. Forecast is run on these two models and the results are compared. Based on that, the conclusions and recommendations are made when it is reasonable to use one or another model for forecast.
Application of Dynamic Underbalance Perforating Technique on a Drillstem Test String in Combination with a Nondamaging Viscoelastic Surfactant-Based Fluid Loss Control Pill: Case Study from Western Siberia
Authors: Gobert K. , Pyatigorets Y. , Krunic N. , Amanov M. , Belov M. , Belova O. , Khabibullin T. , Levanyuk O. , Lungwitz B.
Published: October 2012

The main challenge of perforation completion is to provide communication between the wellbore and the undamaged reservoir through clean perforation tunnels. To achieve this, two key technologies were implemented for tubing-conveyed perforation (TCP) in workover wells in a mature field in Western Siberia. First, the application of dynamic underbalanced perforating achieved clean perforation tunnels, resulting in improved production. Second, the placement of a nondamaging viscoelastic surfactant-based (VES-based) pill after perforation avoided reservoir damage during the well kill operations through clean perforation tunnels.

Three wells in the mature Van-Egan oilfield were selected as candidates for the perforating project. Two wells were previously perforated with standard charges, and the third well was to be perforated across a new layer. Deep penetrating charges were used to bypass near-wellbore damage and maximize potential results. A customized TCP test string for 6 5/8-in. (168-mm) casing was implemented with two sets of gauges installed at different depths. The gauges included a downhole shut-in valve for a closed chamber test, a production valve for the inflow surge, and a fill-up valve for improved run-in-hole procedures. The TCP test string was designed to conduct a perforation inflow test to estimate post-perforation skin factor, productive zone permeability, and reservoir pressure. For the third well with 5 3/4-in. (146-mm) casing, a modified toolstring was used due to operational restrictions. After perforation, a novel, nondamaging solids-free VES-based fluid was used as a fluid loss control pill to protect open perforation tunnels during the subsequent workover operations. Several critical parameters such as permeability, bottomhole temperature, possible scale and emulsion formation, specific gravity, and stability time required were assessed to find the best pill formula for each well. This approach successfully protected clean perforating tunnels against damaging kill fluids for 3–5 days of workover operations.

Results showed negative skin values for reperforated intervals and slightly positive skin values for the new perforated interval. Improved loss control was reported after spotting the pill. Zero losses were achieved in a low-permeability reservoir; loss rate observed in the reservoir with high permeability was lowered by more than a factor of 4. Post-job production data showed an increase in oil rate of up to 2.5 fold compared with the preworkover rate.
Application of Targeted Bit Speed Technology to Directional Drilling in Buzuluk Russia
Authors: Maranuk Christopher A. , Bassarath Wendell , Abaltusov Nikolay , Groshev Vladimir F. , Zolotukhin Sergey P. , Kutlashov Anton
Published: October 2012

A new technology has been developed using a technique called Targeted Bit Speed (TBS) to improve drilling efficiency. Derived from a system that uses a conventional bent housing mud motor in conjunction with a measurement-while-drilling (MWD) tool, TBS technology provides advantages similar to a rotary-steerable tool, and allows for full 3D directional control, while continuously rotating the drill pipe. Steering is accomplished by modulating the fluid flow within the drillstring, creating slight oscillations in the flow rate through the mud motor. This technology takes advantage of these controlled undulations in flow rate to allow high-frequency variations in drilling parameters to control bit speed in order to steer the well in any targeted azimuth. If a planned objective cannot be achieved using TBS technology, then the motor can still be oriented in the desired direction and slid using standard mud motor-orienting techniques.

This paper will examine the field results of a multi-well project in the Buzuluk area, where the operator used TBS technology to drill S-shaped wells required to access the reservoir targets. S-shaped wells are typically the most challenging to drill with continuously rotating drill pipe and a mud motor-based bottomhole assembly (BHA) because the same tools are used to drill the curve, hold the tangent, and drop the angle. This single BHA concept was not feasible before the introduction of this technology. This paper will focus on the improvements achieved in not only directional control but also in the resultant rate of penetration (ROP) by using the new system.

This project constituted the first wells drilled in the Eastern hemisphere using TBS technology.
The Use of Artificial Bayesian Intelligence in Practical Well Control
Authors: Al-Yami Abdullah S. , Schubert Jerome
Published: October 2012

Many well control incidents have been analyzed, resulting in the optimum practices, as outlined in this paper. The objective of this paper is to propose a set of guidelines for the optimal well control operations, by integrating current best practices through a decision-making system based on Artificial Bayesian Intelligence.

Best well control practices collected from data, models, and experts' opinions, are integrated into a Bayesian Network to simulate likely scenarios of its use that will honor efficient practices. When dictated by varying operation, kick details, and kick severity. The proposed decision-making model follows a causal and an uncertainty-based approach capable of simulating realistic conditions on the use of well control operations. For instance, by varying the operation, the system will show the kick indicators for that particular operation. Also in the same model as the user vary the operation, rig and crew capabilities, kick details (such as slim hole, deviated or horizontal well), the system will show the optimum practices for circulation method and shut in method. The model also shows optimum practices for blowout control by varying the un-controlled kick type (surface, subsurface or underground blowouts). Recommended practices after controlling the well are shown by the same operation that caused the well control incident and by varying the potential reason for the incident.

Two well control experts' opinions were considered in building up the model in this paper. The advantage of the artificial Bayesian intelligence method is that it can be updated easily when dealing with different opinions. The outcome of this paper is user-friendly software, where you can easily find the specific subject of interest, and by the click of a button, get the related information you are seeking. Field cases will also be discussed to validate this work.
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

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

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

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

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

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

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

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

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

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

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

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: 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.
Waste Water Disposal Has Become Critical Strategic Focus Area
Authors: Macary Sameh , Tenizbaeva Biganum , Azhigaliyeva Aizada , Yessalieva Arailym , Seitim Malika , Iskakov Elrad
Published: October 2012

Tengizchevroil (TCO) has had up to 20 years of experience in industrial Waste Water Disposal (WWD) into the subsurface. TCO industrial waters cannot be recycled or utilized for any other purposes, hence, malfunction of any component of WWD system (especially wells) can lead to production curtailment. Therefore, TCO has identified the WWD wells as "critical" wells in the business unit.

Waste water is injected into three disposal wells; there are six monitoring wells that provide important information about reservoir pressure, the change in chemical composition of water samples, the fluid level and wellhead performance. Regular surveillance is a key to get data, such as reservoir pressure, temperature, downhole samples, reservoir connectivity, etc. This is important to build the correct reservoir model, both static and dynamic with immediate interest in identifying the water front movement and eventual water breakthrough wells.

In the light of expected operational activities, optimization projects and commercial oil growth, WWD activities are planned to be expanded. Drilling new wells is proposed to add spare injection and monitoring capacity to the project. Additional services, surveillance steps, well geometry and completion design optimization is considered for all new wells.

Cross-functional efforts of subsurface earth scientists and petroleum engineers, lab technicians/facility engineers/environmental specialists/regulatory teams are critical to achieve technical excellence, and hence to fulfil regulatory requirements. Third party involvement in lab analyses and results interpretation strengthens confidence in the operator's efforts to maintain and protect the environment according to official agencies vision.
Self Consistent Approach to Construct Inflow Performance Relationship for Oil Well
Authors: Khasanov Mars , Krasnov Vitaly , Khabibullin Rinat , Musabirov Timur
Published: October 2012

This paper offers a new correlation to construct inflow performance relationship (IPR) for vertical oil well operated under solution gas drive with bottomhole pressure below the bubble poinr pressure. In this case an area with liberated free gas is created in the near-wellbore part of the reservoir. For this case a new functional equation (correlation) for IPR curve in the form of power law is suggested based on the analytical derivation and using pseudopressure function approach. In contrast to the other studies where a parametric IPR equation (usually in the polynomial form) with subsequent selection of coefficients (e.g. Vogel's methodology) was a priory used the new correlation is consistent with the fact of similarity between the oil wells IPR curves built in dimensionless coordinates. In particular case the IPR correlation considered is approximately close to the Vogel's IPR curve which allows using it as Vogel's simple alternative. A modification of the method is suggested. This modification corrects IPR curve behavior in the case of the presence of a transition zone where oil mobility decrease for the pressure values closed to the bubble-point pressure. The paper introduces the justification of the n exponent suggested by Fetkovich IPR and shows how application of new IPR correlation eliminates the contradictions associated with variation range of this parameter. Relations are also proposed to predict the future form of IPR curve and future values of the absolute open flow rate. Based on the large set of numerical calculations the expected values of exponent n for new IPR curve are presented thus they can be applied in the case studies when the experimental data are not available.
Improvement of the efficiency of remaining oil reserves recovery at mature field
Authors: Manapov T. F. , Ruchkin A. A. , Ustyugova E. V. , Levanov A. N.
Published: October 2012

This paper presents the results and the concept of increasing the efficiency of recovering remaining strongly watered hard-to-recover oil reserves based on the example of developing Upper Jurassic reservoirs of a typical field of TNK-BP in Western Siberia, Russia, that has entered the final stage of development. In particular, the paper describes the positive outcome of implementing such technologies as hydraulic fracturing at extremely watered wells, forced liquid withdrawal coupled with targeted focal waterflooding supplemented by flow diverting technologies in injection wells and water shutdown in producers, optimization of perforation intervals, with sidetracks targeting blind unrecovered zones.

The work is different from previous projects in provisioning a comprehensive integrated flow production and injection regulation with low-cost technologies with an emphasis on reducing injection costs and producing liquids to the surface to optimize cash flows. As a result, the accepted recovery concept is described, which provides increased energy efficiency and production profitability, together with targeted production of remaining oil reserves.
Differential Approach to Determination of Compartmentalized Reservoir Properties
Authors: Yudin Evgeniy , Lubnin Alexander , Krasnov Vitaly , Musabirov Timur , Khasanov Mars
Published: October 2012

In this paper a semi-analytical approach for well productivity calculation in low-permeability and highly heterogeneous reservoir is proposed. Model considered allows explaining a high production rate decline for the wells operating in such conditions. Method of different interlayers flow capacity determination is considered based on identification of connected and isolated parts of the reservoir during waterflooding. Integration of rate transient analysis and steady-state production rate evaluation is used. Technique described can be used for the prediction of new wells production rate.
Monitoring Technology for Co-Mingled Tight Play Development with Hydraulic Fractures
Authors: Kokurina V. V. , Kremenetsky M. I. , Melmikov S. I.
Published: October 2012

At present, low-permeability formations become increasingly important in global hydrocarbon production. Simultaneous development of several reservoir zones with single well pattern - along with hydraulic fracturing became the most common for the today's upstream.

At the same time, less attention has been paid so long-term monitoring of such comingled pay zone development with hydraulic fractures. Traditional monitoring methods offer minor benefits in such conditions.

Based on theoretical considerations and numerical modeling of velocity, pressure, and temperature fields in tight formations tapped by hydrofracs (Eclipse 300), the authors proposed a new production monitoring technology. This technology is based on comprehensive production logging and well testing methods and involves the following innovations: It was found that in case of hydraulically fractured pay-zone the fracture will affect spinner logging showing homogeneous flow (injection) profile even in heterogeneous formation. Analysis of transient temperature survey in the assumption of linear geometry of temperature field is proposed as an alternative method.The authors assessed existing capabilities of long-term monitoring of downhole pressure and flow rates under conditions of comingled fractured tight reservoirs development, with individual zone real-time estimation of formation pressure, permeability, and skin factor. To avoid uncertainties of these parameters, the authors justified, in addition to this monitoring technology, the alternating well off take and shutdown cycles.A new methodology for estimation of permeability and skin-factor of individual layers (including the hydrofrac-related ones) based on well monitoring data using permanent downhole monitoring systems.The authors justify a comprehensive approach to tight reservoir development monitoring with hydraulic fractures, based on continuous acquisition, storage, and analysis of long-term, multifaceted survey which is critical for numerical modeling information support.
Do no harm – or when there is an advantage from the oil production equipment failures prediction
Authors: Khabibullin R. , Krasnov V.
Published: October 2012

Mean-time-to-failure (MTTF) enhancement is key task for oil production operator. To achieve this goal they increasingly engage remote well stock performance monitoring systems. Regular acquisition of the detailed information on the well performance and the downhole equipment condition facilitate routine well control for the production engineers as well as enables to predict some well performance deviations before they actually arise, for example, oil production declines. Such predictions might initialize actions on the well performance optimization before a failure occurs or operation conditions change. In many cases it could prove to be economically feasible due to less well shutdown period while waiting for the repair teams to arrive.

This report specifies criteria which are crucial for practical implementation of the downhole equipment failure prediction system. The main criterion is the failure time prediction accuracy. In this report "prediction accuracy" notion is described based on the statistical figures reflecting the number of successful predictions. A comparison of economical effectiveness of the various accuracy prediction systems application and existing practical approaches such as "change broken" application is provided as well.

There are applicability maps for the failure prediction systems compiled in terms of Rosneft well stock example. It is shown that the range of application of such systems exists, but is significantly limited.
Oil Production Process Optimization Resultant from Intelligent Field Technologies Implementation in Samotlorskoe Field
Authors: Shevchenko S. D. , Navozov V. A. , Mironov D. V. , Pchelnikov R. L. , Muslimov E. Ya.
Published: October 2012

Nowadays the "Intelligent Field" concept is being actively implemented in TNK-BP, with Samotlorskoe field (OJSC "Samotlorneftegas") at the forefront in this conceptual area.

The term "intelligent field" means arrangement of additional value of oil and gas asset by forming a cycle of gathering of qualitative data, treatment, modeling, decision making and their prompt performance. The concept is implemented step by step. At the first stage of implementation in 2009 – 2010 the main focus was on its technical constituent, the following technologies were reviewed and implemented: –use of different primary transducers for real-time data receiving;–upgrading SCADA, including use of remote control;–use of different real-time expert and simulating systems.

Implementation of such technologies on a large scale adds value to the process of decision-making and oil production control. It has become evident that efficient implementation of technologies is impossible without changing production control processes both at the technological and organizational level. It also becomes essential to organize the process of implementation of such changes.

In 2011 – 2012, in addition to the technical phase, the organizational phase was started in parallel. The issues related to technology influence on the current business processes and organizational changes required for efficient use of the technology were addressed to, the personnel's objectives were reconsidered and the team for implementation of changes was formed.

The paper outlines technical aspects of technologies implementation and evaluates their influence on oil production process. The issues related to changes in organizational structure and business processes relevant to implementation of "intelligent field" technologies are presented. The effect resultant from technology implementation is evaluated.