bluuebunny/crossref_metadata_2025 huggingface dataset:
Development of Water Saturation Error Analysis Charts for Different Shaly Sand Models for Uncertainty Quantification of Volumetric In-Place Estimate
Authors: El-Sayed Samiha S. , Daoud Ahmed M. , El-Tayeb El-Sayed A.
Published: October 2008

Quantifying the uncertainty in the volumetric estimation of original oil in place (OOIP) is an important process in evaluating the field potential and hence in designing the proper and the most economical subsurface and surface facilities to produce the field reserves. This uncertainty in the OOIP estimate results from uncertainty in reservoir areal extent, net reservoir thickness, porosity, and hydrocarbon saturation. In this work, a methodology is presented to assess the uncertainty in the hydrocarbon saturation estimated from open hole logs using the commonly used empirical and theoretical shaly sand models.

This technique is based on development of water saturation error analysis charts for the commonly used water saturation models (Simandoux, Indonesian, Waxman & Smits, Dual Water, and Effective Medium) due to the uncertainty in the different input parameters to each model separately. Both analytical and numerical error analysis techniques were used to develop these charts and hence used as a forward tool to quantify the uncertainty in the hydrocarbon saturation due to the uncertainty in the petrophysical and electrical rock properties.

Fifteen wells with 1300 shaly sand points from Alam Bewab formation, in Western desert of Egypt, were used as our data base in generating these error analysis charts. The uncertainty in input data was assumed from ± 5 to ± 15%. The results showed a significant range of uncertainty in hydrocarbon saturation estimate from ± 0.3% reaching to ± 85% in some models.

General water saturation error analysis charts were developed, for each model, based on the above mentioned database and validated mathematically. These charts can be easily used to predict the uncertainty in hydrocarbon saturation estimate due to uncertainty in the input data. In addition, it can be considered as a useful screening tool to select the best saturation model to be used depending on the input data uncertainty.
An Innovative Acid Stimulation Technique for Reviving Dead Wells in the Ghawar Field of Saudi Arabia - A Holistic Approach
Authors: Haldar Surajit , Al-Jandal Ahmed A. , Al-Driweesh Saad M. , Al-Eid Mufeed H. , Ramanathan Venkateshwaran , Ovtchinnikov Kirrill
Published: October 2008

The Uthmaniyah field is one of the biggest sub fields and older producing sections in the giant Ghawar structure. A few wells have been dead for sometimes due to high water cut (60 to 80%). In all cases the target interval was only 5’-10’ at the top of the dominating water producing zones. There was no scope of water shut-off and artificial lifting. The pilot stimulation comprised of trials in a number of such wells with similar reservoir producing conditions. Isolation of bottom intervals by conventional gel-plug method was not very suitable here because of very marginal target interval. Even slightest inaccuracy of the coil tubing depth meter or depth correlation could be detrimental due to very close water producing interval.

The treatment involving the use of high viscous visco-elastic surfactant (VES) diverter technology and controlled bullheading placement was designed to achieve effective acid diversion during acid stimulation. Stages of high viscous VES was pumped as a diverter to temporarily plug the dominating water zones, followed by considerably low strength HCl acid to achieve shallow wormhole growth. All the wells responded to the treatment with sustained oil gain. Although water cut remained high, the well head pressure increased substantially to flow the well naturally.

This paper discusses the planning and design processes leading to the successful implementation of the technique, the experience during the stimulation treatment execution and the excellent post-stimulation results. Considering no cases of matrix acid stimulation in high water cut wells in the field, this technique promises to deliver in similar wells here and elsewhere. The significance of the new well stimulation technique is to revive dead wells with very high water cut and also to enhance oil recovery from these wells in a cheaper, easier and effective way.
Using Resistivity Log Invasion Profiles, Multiple Porosity Logs, Core and Test Data to Determine Lithology, Porosity and Permeability in Pre-Cambrian Sandstones of Eastern Siberia
Authors: Prasse Eric M. , Hornbrook J. W. , Tye R. S. , Putnam Timothy W.
Published: October 2008

The Verkhnechonskoye field was discovered and appraised during the late 1970s and early 1980s. One hundred legacy wells and three modern wells have been reevaluated and results used to construct a static model that matched test results and was used to forecast field potential. The Verkhnechonskoye field is currently operated by TNK-BP.

Cores in the three modern wells were studied to determine lithology, depositional facies, and mineralogy. Results were applied to crossplots of sonic and neutron log data. These crossplots showed six different lithofacies: basement, weathered-basement, high permeability sand, low permeability sand, salt/anhydrite-cemented sand, and carbonate. Sand was subdivided into relatively high and relatively low permeability sands using the laterolog and microlaterolog, based on the observation that sand with microlaterolog values less than 10 ohm-m were observed to be highly productive on test. To calculate porosity, the neutron, sonic, and core porosity were compared. Preliminary porosity was calculated using a field-wide solution from a combined crossplot of sonic log values and core data. Well by well analysis indicated that the sonic logs often underestimated porosity and that neutron logs tended to match core porosity better. Petrographic analysis confirmed that widespread secondary porosity was not detected by sonic logs. Single-well porosity solutions based on neutron logs were used together with sonic porosity calculations to finalize porosity estimates. For permeability, high and low trends were calculated for sands using the microlaterolog to define high permeability and low permeability sands. A relatively high permeability to porosity relationship was applied to sands with microlalaterolog values less than 10 ohm-m and a relatively low permeability to porosity relationship was applied to sand with microlaterlog values greather than 10 ohm-m.. A significant number of core permeability measurements were available and these points were honored after depth-shifting. Finally, log derived permeability was modified to match average permeability derived from well test results.

Identification of multiple lithologies and calibration of porosity and permeability to core measurements and well test results signficantly reduced uncertainty in calculated results.
Appraisal of a Precambrian Oil and Gas Field: Verkhnechonskoye Field, East Siberia, Russian Federation
Authors: Tye R. S. , Hornbrook J. W. , Prasse E. M. , Robinson G. C. , Lowe D. R. , Morozov V. V.
Published: October 2008

To evaluate uncertainty in property distribution and reservoir connectivity, resource size, and development plans for Verkhnechonskoye, a large Precambrian oil field, three geologic models were built employing: 1) Sequential Indicator Simulation (SIS) and Sequential Gaussian Simulation (SGS); 2) Object Modeling; and 3) Seismic-Attribute Modeling. Reservoir models were based on seismic and wireline-log, core, and well-test data from over 100 wells.

The reservoir consists of sandstone, mudstone, and rare conglomerate deposited on a broad alluvial plain fringing an igneous and metamorphic continental island. Coarse-grained sediments were deposited in channels that prograded and aggraded the alluvial plain that terminated downdip into a lacustrine or epicontinental sea. In places, lagoons and poorly developed beaches fringed the alluvial plain. Relative base level created upward-coarsening and upward-fining successions that onlap the basement. Shale beds create flow barriers while, porosity and permeability are primarily controlled by evaporate, quartz, and calcium carbonate cements.

Buildup and interference tests were designed using estimated average reservoir properties. Test results discriminated among the three geologic models for use in field-development planning. Partial field-simulation models were upscaled from each geologic model and used to match the buildup and interference tests. The SIS model surpassed the Object and Seismic models in matching well performance. This better match of well performance from the SIS model occurred because sandstones are better connected and exhibit more homogeneous rock properties as compared to the Object or Seismic models. It was concluded that the SIS method of facies and property distribution is preferred for future modeling in the field.
Can Gas Hydrates Provide a Solution to Gas Utilisation Challenges in Russian Oil Fields?
Authors: Azarinezhad R. , Valko I. , Chapoy A. , Tohidi B.
Published: October 2008

The expanding demand for primary energy has pushed exploration and production activities towards more challenging environments, such as the north slope of Alaska, Siberia and deeper oceans. In many cases associated gas could be a limiting factor in the field developments. While stabilised oil could be transported by pipelines and/or tankers, the options for gas and associated gas is rather limited and/or not economical.

There are strict limitations on flaring due to environmental/economical concerns, and most of the available options for gas utilisation (e.g. gas to liquid, gas to wire, compressed natural gas…) require considerable CAPEX. Recently, we have proposed HYDRAFLOW, which is a Cold Flow solution for avoiding gas hydrate problems. This could provide a solution for gas transportation.

The concept of HYDRAFLOW is based on allowing/encouraging gas hydrate formation, but preventing their agglomeration and pipeline blockage by using chemicals and/or mechanical means. The aim is to eliminate/minimise the gas phase by converting it into hydrates and dispersing hydrates in oil and/or aqueous phase. Water could be added to maximise gas conversion into hydrates and/or adjusting the slurry viscosity. Furthermore, a loop concept has been developed where part of the liquid phase could be recycled, minimising chemical discharge to the environment.

As HYDRAFLOW basically converts gas into hydrates and transport it as slurry in a liquid phase, it could provide a solution for gas utilisation for fields where the ambient temperature and pipeline pressure are inside the hydrate stability zone. In this communication, after introducing the HYDRAFLOW concept, the latest results of laboratory tests at subzero conditions are presented as well as an economical evaluation and a pipeline transportation simulation on one of the West Siberian oil fields. These simulations demonstrate that the concept is viable, and suggest that HYDRAFLOW technology could offer significant benefits over existing flow assurance strategies, providing a novel low CAPEX/OPEX solution for gas utilisation.
"Pumping up the Life" of Electric Submersible Pump Systems, Russian Federation
Authors: Borling Daniel C. , Sviderskiy Sergey V. , Gorlanov Sergey F.
Published: October 2008

This paper is the first in a series describing results and lessons learned from longer run life across 13,176 Electric Submersible Pump (ESP) systems in TNK-BP. ESP artificial lift is the dominant method for producing approximately 90% of TNK-BP's oil volume, which averages more than 200,000 tons (1.5 million barrels) per day.

A sustainable economic benefit for TNK-BP was defined during 2006, and this benefit directly results from increased ESP run life. The 5-year value was estimated at $350 million and long-term forecast was $1 billion. An indirect benefit from longer run life was better HSE performance due to reduced exposure to oil field hazards from fewer rig days pulling ESPs.

Since 2006, TNK-BP has gradually changed the way it thinks about ESP run life and lessons learned are provided in this paper as a case history.

ESP run life was about 300 days MTBF when the project started and the 5-year goal was set at 600 days MTBF by year end 2011. Elements for success included leadership structure, coordinated teamwork across multiple internal business segments and continuous equipment improvement using root cause failure analysis. Reducing frequent failures was a basic priority as was technical equipment innovation and pilot project expansions.

Results have been impressive with run life steadily increasing each month. Run life improved to 410 days MTBF during August 2008 from 296 days in January 2006. This 114 day run life increase has already prevented 550,000 tons (4 million barrels) of deferred oil, reduced $50 million of operating costs and saved rig time. The $350 million project value did not include redeployment of rigs to complete other oil enhancing work such as hydraulic fracturing and acid stimulations.

During 2004, TNK-BP joined the ESP-RIFTS Joint Industry Project. The ESP-RIFTS System allowed TNK-BP to further develop and implement a unified way to classify and analyze ESP data for a huge well stock. The result was strategic operating changes, one of which was stopping the purchase of the lowest reliability equipment. Failure analysis was fundamental in helping TNK-BP with its initiative to get the right equipment into the right well.
Development of Fields with Complex Environmental History – Key Engineering and Technological Solutions
Authors: Matevosov A. R. , Diyashev I. R. , Kruchkova T. V. , Maslennikova Yu. V. , Zubareva A. V.
Published: October 2008

This paper is dedicated to the key engineering solutions concerning development of the Kumzhinskoye field. The focus is put on the field development principles related to its complex environmental history.

The challenge we face in this field results from an accident that occurred while drilling well 9 in the crest of the structure due to failure to meet regulations on integrated gas and gas-condensate well testing procedures with regard to well production rates through orifices of certain size and duration of well production at those rates. Abnormally high gas flow rates amounted to 807 thousand m3 per day. The problem and severe pollution near the well resulted from a nuclear explosion 1500 m deep aimed at shearing the wellbore due to displacement of a rock mass. However, instead of the accident remediation the explosion increased the area of gas and condensate blowouts. As a result, a huge damage was inflicted to the environment and the Pechora river delta ecosystems. Exploratory wells are exposed to aggressive hydrogen-sulfur medium. Poor cementing creates the conditions for gas crossflows from natural reservoirs to overlying water bearing zones forming human-induced gas deposits. Accident remediation took almost 15 years.

It is important to realize that environmental challenges of this field are so huge that it is useless to handle them from the surface. Solution of environmental problems requires an integrated approach to the field development.

First, the primary reservoir is to be depleted to make its pressure drop below the pressure in the secondary induced deposits (200 Atm) and shut down the upward gas migration. Second, shallow slim holes are to be used to deplete induced deposits. To minimize the environmental damage, we are planning to ensure complete gas recovery using only 18 horizontal wells. We shall drill those wells from only 2 well pads minimizing land allotment for industrial purposes. In addition, these well pads are located in dry elevated areas outside the national reserve territory.
First results of Exploration Works in the West Ural Fold-and-Thrust zone of the Pre-Ural Foredeep
Authors: Danilov Vladimir N. , Ivanov Victor V.
Published: October 2008

The exploration area comprises the territory of the northernmost depression of the Pre-Ural Foredeep, called the Kosyu-Rogovskaya Depression, adjacent to the regions of the Circumpolar and Polar Urals (fig. 1).

The Pre-Ural Foredeep stretches from the south to the north from the Caspian Sea region to the Pechoromorsky shelf and covers approximately 3,000 square kilometers. Not all zones of this foredeep have sufficient geologic-geophysical data. The outer western zone which is adjacent to the East European Platform and the Pechora Plate is most explored; the central deepest part of the foredeep is less explored except for the largest anticlinal structures; and the inner eastern area characterized by the extensive development of the thrust dislocations has almost no geologic-geophysical data.

Taking into account the worldwide experience in performing works at foredeeps which proved high gas-and-oil presence of such tectonic elements, the fact that 5 subsidiary companies of "GAZPROM" OJSC are situated on the territory of the Pre-Ural Foredeep, considering also the availability of well-developed gas transport system (four gas-main pipelines pass through the foredeep, and the 5-th line is being constructed at present) and ultimate gas consumers the Geological Survey of "GAZPROM" OJSC is developing the Programme for the performance of exploration works on the territory of the Pre-Ural Foredeep.

According to this Programme exploration works including aero-space, geochemical and geophysical surveys and deep prospecting-and-appraisal drilling are performed in two license blocks located in the zone of juncture of the Kosyu-Rogovskaya Depression on the western slope of the Urals (fig.2).

In the first stage of works including remote sensing, geochemical and geophysical surveys the data confirming a great number of structures in the explored territory were obtained, also the traces of hydrocarbon migration were found out. The obtained data allowed to specify the tectonic zoning and determine first-priority objects to perform deep drilling works.

The second stage that provides for drilling of the two first-priority prospecting-and-appraisal wells (one at each license block) and the detailed seismic surveys is underway. One of the wells is already drilled while the second is being drilled. The interpretation of seismic data is being carried out.

The data obtained from the second still incomplete stage of works has already fundamentally changed the idea of: 1) geological structure of the explored territory; 2) mechanisms that form the fold-and-thrust zones of the whole region under consideration.
Research of Conditions and Scopes of Water-Gas Influence on the Layer with the Purpose of Increase in the Current and Final Oil Recovery Factor
Authors: Telkov V. P. , Egorov Yu. A.
Published: October 2008

On a background of the relative well-being connected to the high prices for oil insufficient attention it is given difficult-developing to stocks of oil which share in total amount of stocks constantly increases. In due course it can lead to full development of easy-developing stocks of oil, and the kept need for fuel and raw material for the chemical industry will lead to necessity of development difficult-developing stocks to which it is possible to relate oil in collectors with low permeability and essential heterogeneity, or to oil of the high viscosity.

Displacement of the oil by water, widely distributed in Russia, for fields with difficult-developing stocks it appears insufficiently effective. Therefore, oil recovery of developed deposits decreases.

In these conditions significant interest is shown to gas technologies of increase oil recovery, first of all to the water-gas influence (WGI) allowing not only to receive from a layer additional oil, but also it is useful to use the associated gas now aimlessly burnt on torches.
Critical Intra-Field Pipelines Inhibition Technology Using Batching Pigs
Authors: Sukhnat Yegor Yu.
Published: October 2008

Introduction:

Intra-field pipelines is the most critical constituent of pipeline network used by subsoil users in Khanty-Mansiisk Autonomous District–Yugra. Total length of pressure pipelines in TNK-BP spans 2,965 kilometers: 9% of the total web is corrosion-resistant whereas remaining 2,706 kilometers in operation are not protected against corrosion. Average life of a pipeline is 12 years. A pipeline break, if occurs, may not only drive to shut-down of a field but also have serious technogenic and environmental implications. The Company has developed and put in place a prioritization program, which classifies this group of pipelines as critical. According to the program, these pipelines require time and efforts to assure integrity and longer service life.

Goal:

The goal is to develop and implement a technology of intra-field pipeline inhibition with the use of batching pigs.

This goal sets the following objectives.

Objectives:

Assess operational and economic efficiency of the existing and proposed intra-field pipeline inhibition technologies; Select corrosion inhibitor with adequate properties; Develop Instruction Pigging and Inhibition of Pressure Oil Pipeline between DNS-24 and KSP-1 4 using Batching Pigs Develop an operational procedure for pressure oil pipeline DNS-24 – KSP-14; Run field trials of the proposed technology in the pressure oil pipeline between DNS-24 and KSP-14, OJSC TNK-Nizhnevartovsk.

Project description:

There are two (2) inhibition methods in use in the Company: continuous dozing and shock treatment. When inhibiting lengthy pipelines, these two technologies have shown their major week point – inhibitor is difficult to deliver to the cleaned metal surface that consequently leads to the small probability of generating a reliable protective film.

The proposed system ties together two existing technologies extending pipeline service life: pipeline pigging and inhibition. This technology represents a set of below successive operations:

launching of a solid pig; injection of calculated volume of corrosion inhibitor during specific time set in the Instruction; launching of a polyurethane foam pig to tail.

The proposed inhibition technology with the use of batching pigs allows coating of pigged metal surface with inhibition film (PД, 39-23-1082-84). As records state, cleaned metal surface coated with strong inhibitor solution increases inhibition effect by 15-20%.
Effect of Fluid Volume and Production Rate on Oil Recovery in Oil Field Development by Waterflooding Methods
Authors: Diyashev R. N. , Blinov A. F.
Published: October 2008

The five large oil fields found in the Russian Republic of Tatarstan have been producing from the Devonian sandstone reservoirs for more than fifty years. Currently all of them have entered the maturity stage. In all five fields waterflooding methods have been applied since the very start of production. And though the principal development approaches and strategy do not differ, development rate, volumes of fluid produced, actual and design oil recovery factor (ORF) do differ. The largest of the five fields, Romashkinskoye, has been developed in independent areas divided by injection wells’ rows. There are 21 such areas. Comparative analysis of these areas’ performance is of specific interest.

To make a generalized estimate of production performance of the five fields, we have ranked them by a number of geologic parameters. The same ranking has been performed for all areas of the Romashkinskoye oilfield. For the purpose of analysis these areas have been further divided into seven groups by a common integral geologic parameter.

The investigation method involves a correlation analysis of the fluid production and oil recovery profiles at different stages of development of both fields and areas; as well as evaluation of the present-day status of development, in that number with account for the tendency towards operating assets’ change.

It has been demonstrated that the oil recovery factor and its behavior at different development stages depend to a large extent on reservoir geology. Besides, there is a close correlation between fluid and oil production rates. In mature fields very important factors are status of assets and producing wells’ density. Fields and areas have been identified which call for immediate rejuvenation operations.
Development of Effective Numerical Model for Heavy Oil Production Using Steam-Assisted Gravity Drainage
Authors: Klemin D. , Pimenov V. , Rudenko D.
Published: October 2008

One of the modem technologies for heavy oil and bitumen recovery is SAGD (Steam Assisted Gravity Drainage), which use two horizontal wells, one above the other with spacing 5-10m. Upper well is used for steam injection and creating the high-temperature steam chamber (SC). On the SC boundary the steam is condensing and water together with the heated oil flow downward into production well.

Pressure and temperature (P/T) measurements in injection and production well are used to control production process. This data contains only indirect information about the steam chamber parameters and oil inflow profile along the well length, therefore various mathematical models should be used to interpret measurement results.

P/T measurements interpretation, optimization of steam injection regime and analysis of reservoir heterogeneity influence on SAGD parameters are commonly performed on 3D models, which need tremendous computational resources and provide results within an inapplicable time (several days and even weeks) for field usage.

Present work is devoted to development of the effective SAGD numerical model. It is based on the well admitted in literature assumption, that horizontal steam flow along the injection well prevail over the horizontal steam flow along the reservoir. Thus 3D simulation can be substituted for by the 1D simulations for the injector/producer connected with N 2D cross section reservoir models which are connected only through injection and production boreholes (an example is in paper4). Injection well model provides steam pressure/temperature profiles for 2D cross section models. In turn these models calculate profile of steam injection rate which is an input data for injection well model. Developed 1D + N*2D SAGD model can be used for fast SAGD simulation and for injectivity profile inversion from P/T data recorded in injection well.

1D model of injection well with tubing inside the well for steam injection at the heel and/or at the toe was developed. It assumes two phase (water/vapor) flow with ‘drift flux’ and heat exchange between tubing and annulus flow. Nevertheless, analysis of field data recorded by DTS in injector shows that assumption of joint flow of the water and vapor along the injector, and hence simultaneous injection of the vapor and the water in reservoir can be violated in some cases. Modification of the 1D injection well model with separated distributed vapor/water injection in the reservoir was developed. Simulation results obtained obtained with modified model are able to reproduce qualitatively field data behavior.
Geological field classification of reservoir rocks of Ardat horizon, Rodnikovsky field, Orenburg Oblast
Authors: Nemirovich T.G. , Shakirov V.A. , Luzina L.A. , Virskiy D.A.
Published: October 2008

Major production zone on Rodnikovskoye field is Ardatov terrigenious deposit (D3 reservoir). At Brownfield stage when main reserves are recovered, more attention is paid to cross-section improvement. Typically, maximum oil is produced from reservoirs with good reservoir properties.

Many researches describe the relationship between SP relative amplitude and silty and clay material in the reservoir. V.S.Muromtsev sufficiently describes reservoir classification method based on grain size and aSP (Nedra 1984). The feature of spontaneous polarization method (SP) in terrigenious rocks allows to identify shale volyme and grain size effect, i.e. define two main lithological parameters. They help to determine terrigenious rock deposition settings and evaluate rock properties.

Table 1 shows rock type determined by authors vs. lithotype determined by V.S.Muromtsev. There is some discrepancy in prevailing sandy fraction. According to grain size analysis, the core samples are fine-grained sandstone which is due to insufficient quantity of samples taken in high aSP zones. Therefore, based on relative curve parameter aSP=0.75–1.0, coarse and fine-grained sandstone was associated with rock type I; based on V.S.Muromtsev classification, aSP=0.6–1.0 sandstone is divided into two types: coarse-grained and fine-grained. The range of aSP=0–0.25 corresponds to shales, aSP=0.25–0.5 corresponds to siltstone and argillaceous-silty rocks. Mixed rock type (sandy-siltyargillaceous) corresponds to average level of aSP=0.5–0.75. Thus, the grain size-typing study performed in TNNC does not contradict other investigators' data.
Modern Scientific and Technical Concepts for Oil Production and Processing
Authors: Muzipov Halim N. , Erka Boris A. , Savinykh Yury A. , Dvinin Anatoly A.
Published: October 2008

NEW PUMPING EQUIPMENT

B. A. Erka, A. A. Dvinin

VANE PUMP

In view of oil production restraints, such as high viscosity, high gas-oil ration, entrained solids, etc., current oil production methods are limited because low-pressure area is required at the submersible pump inlet for the subsequent compression and pumping of reservoir fluid into tubing.

The implication of this new artificial lift method is that vane pump is used instead of submersible pump (Fig.1) [1], as vane pump retrieves reservoir fluid without low-pressure area created at the pump inlet as the working elements (vanes) can operate directly in reservoir fluid.
INFORM Knowledge Hub
Authors: Muratov Fedor
Published: October 2008

In the modern world the development of informational technologies is going on at a breakneck pace. Often the company that starts implementing them in the business earlier surpasses its competitors by far in all key indicators. Based on this, the decision to develop and deploy the state-of-the-art information technology in OFS subsidiaries was taken. This system was named INFORM.

INFORM system is a multi-functional intranet portal that stores and processes important operational information of OFS subsidiaries. INFORM consists of key sections, such as Drilling, Workover, Technical Maintenance and Repair, Quality Management System, Operational Forum, and Training Programs. Thanks to INFORM, rig toolpushers can enter daily operations reports, and HQ managers can review operational performance at all wells based on these data. The portal has a great number of reference operational data, Field Operations Manuals, and the results of rig audits. The interactive map of Russia can show you the location of each rig and get the contact data of every toolpusher. All operational incidents in every subsidiary are stored in INFORM, so toolpushers have the opportunity to prevent them in their own crews. INFORM's Operational Forum has important operational issues discussed and information shared. The information contained in INFORM is Company's property: all TNK-BP users have the access to this site, while the operational data of INFORM is available only for the registered users.

So INFORM is the system we have designed to allow OFS to collect, organize and share knowledge which allowed for accelerating the process of decision making in OFS.

While implementing INFORM project team achieved next results:

– Evaluated the availability and quality of communication channels at the rigs, In case no communication channels are available, they were built with the optimum capacity using satellite technologies – Purchased and installed the required server and computer equipment in the subsidiaries and rigs. – Held a tender among IT companies on the development of System according to TNK-BP and OFS standards – Developed the interface of the future portal – Entered all data into INFORM. Obtain data from the services: HSE, HR, Quality, Technology department, etc.
Testing and Analysis of Wells Producing Commingled Layers in Priobskoye Field
Authors: Davletbaev Alfred , Ozkan Erdal , Slabetskiy Andrey , Nikishov Vyacheslav , Usmanov Timur
Published: October 2008

This paper discusses a Downhole Flow Control (DHFC) technology and describes its application for injection and fall-off testing of commingled layered reservoirs. The Simultaneous Separate Injection (SSI) technology has been successfully applied in over 150 injection wells by the Rosneft Oil Company in the Priobskoye Oil Field. The SSI assembly is a cable tool consisting of valves, packers, and pressure transducers and provides the ability to distribute the surface injection rate into individual layers in a controlled manner. The ability to control layer injection rates is intended for effective flooding of poor-injectivity layers. The concurrent measurement of layer pressures also provides the opportunity to simultaneously test multiple layers. Currently, the SSI assembly only regulates the distribution of the layer injection rates but does not measure the bottomhole injection rates. Valves on the SSI assembly are preset at the surface based on the spinner tests to determine the injection profile. The main advantage of this technique is the drastic reduction of test time and cost to obtain estimates of individual layer properties and injectivities. This paper focuses on the use of the SSI assembly in pressure-transient testing of commingled, multi-layer reservoirs. The application of the testing technology and the analysis of measured test responses are demonstrated on examples from the Priobskoye Field. Also presented are the results of the Single-Layer Steady-State Injection Tests. These tests are useful to understand the fracture development during injection and the resulting injectivity increases. This information is used to regulate the layer injection rates with the SSI technology and the in the design of the injection and fall-off tests.
Formation Hydrofracturing Experience on Horizontal Wells of Rosneft
Authors: Haidar Azat , Vafin Ilnur , Borisov Gleb , Dzhabrailov Ajndi , Nikitin Alexey
Published: October 2008

The available hydraulic fracturing (HF) techniques for horizontal wells (HW) allow stimulating one or several HW intervals, as well as creating fractures lying at various angles to the horizontal wellbore. The simplest of these methods available to operators is conventional HF; besides, operators may make use of different interval-wise HW stimulation techniques – both with and without packer systems.

During 2006-2007, Rosneft Oil Company performed over 20 HW HF operations. Two HF technologies have been tested: Conventional Frac and multiple-point Hydrajet stimulation. The obtained results demonstrate the efficiency of HF on Rosneft fields, in West Siberian geological conditions: HF has allowed reactivating a number of wells.

The considerable stock of horizontal wells has made it possible to analyze the influence of various factors affecting HF efficiency, such as completion, wellbore orientation, and formation permeability. Several operations were successfully carried out against weak water and gas barriers.

This paper presents Rosneft's experience of HF in horizontal wells and adaptation of conventional HW hydrofrac techniques to West Siberian geological conditions. The article features also some details of HF operations and the results arrived at; HW HF risks and limit conditions for different technologies are defined. Some criteria for HF candidate selection are given.
The Pilot Project: Application of Methods of Oil and Gas Geochemistry for Localization of Petroleum System of the Western Caucasus Basin
Authors: Jurevna Suslova Ellina
Published: October 2008

In 2007 our company has begun work above the East-Black Sea project. Its basic purpose - allocation and localization petroleum system of the Black Sea region for a gain of a raw-material base. In view of that within the limits of considered water area are not drilled wells, the forecast of petroleum system it is spent on the basis of studying regional oil and gas system of adjacent territory - Western Caucasus basin.

On the basis of complex studying Jurassic and Cretaceous source rocks with use of modern methods of organic geochemistry (pyrolysis Rock-Evals and also were analyzed for aliphatic biomarker hydrocarbons (n-alkanes, i-alkanes and aliphatic isoprenoids) and cycloaliphatic hydrocarbons of sterane and terpane series using gas-liquid chromatography and chromatography/mass spectrometry) it is established:

the highest oil and gas potential are peculiar to locally widespread titon (J3) and senoman (K2) source rocks;

in overwhelming majority low Cretaceous source rocks are carried to a category petromaking, low and middle Jurassic to a category petromade, except for middle Jurassic source rocks of the East-Kuban hollow;

the generated petroleum and natural gas are expelled from the source rock can be take place on depth (from 20003000 - up to 6000 metres);

in a quantitative sense the greatest contribution to generation liquid hyqrocarbons have brought Jrassic and Cretaceous source rocks of axial parts of depressions.

Introduction

The Western Caucasus basin is administratively dated for Krasnodar region - large area with the developed infrastructure (Fig.1). At the present stage the most part of oil and gas pools have lost the profitability - they are considerably developed or are in a finishing stage of development. Objects of search can be deposits in less studied mesozoic source rocks, both within the limits of a continental part, and in the Azov and Black seas. Presence of oil fields and gas in Jurassic and Cretaceous petroleum system allow to consider them as perspective.
Gas/Oil Reservoir Pressure Maintenance by Way of Gas Injection
Authors: Romanov A. S. , Zolnikova E. F.
Published: October 2008

Of all available EOR methods deployed in thin oil rims and gas/oil reservoirs gas intervention techniques seem the most effective1,2,3,4,5. The study of practicability of this method was carried out at one of West Siberia gas/oil reservoirs. Natural pressure depletion is the chosen production method for the reservoir in question. Almost 150 wells were drilled within the limits of the reservoir. The dominant production mechanisms are free flow and gas-lift. By the beginning of 2008 average reservoir pressure dropped to 13.0 MPa from the original 28.0 MPa. Decline of formation pressure well below saturation pressure (19.0 MPa) resulted in wells’ shutting-in and curtailment of producing well stock. Prevailing causes of well problems are flooding and gas coning while in service. Mean water cut is 10%, GOR is 1600 CUM/MT, while oil production rate of available stock does not exceed 13 MT/D against start-up values of about 100 MT/D.

A well drilled next to one of the clusters of the reservoir in question exposed overpressured B4 stratum. Gas flowrates in the well reach up to 106-166 MCUMD with wellhead pressures of 25.0 to 30.0 MPa. This fact encouraged the studies of possibility of gas/oil reservoir pressure maintenance by way of injection of high-pressure natural gas.
Determination of Horizontal Borehole Geometry by Ultrasonic Pulse-Echo Method
Authors: Smirnov Nickolay A. , Varykhalov Aleksey S.
Published: October 2008

The information on the horizontal borehole geometry (size and shape) is needed in well logging interpretation and solving engineering tasks, for example, choosing a place for mounting a casing pipe seal. Direct application of mechanical driven logging devices such as used in a wire line caliper tool is impractical in horizontal boreholes. The borehole geometry can be determined by ultrasonic caliper operating in a pulse-echo pattern. Such techniques have been successfully used in wireline logging for borehole imaging and cement bond evaluation, but meet some obstacles in horizontal wells. A rugous borehole wall and low difference in acoustic impedances of formation and drill mud are the reasons of acoustic pulse high attenuation. In horizontal boreholes the logging tool is always decentralized and consequently the pulse travel time may be less than transducer ringing duration. These concerns with ultrasonic measurements lead to a task of finding a reflected signal amid overwhelming noise.

Using transducers similar to those of wireline scanners and applying robust algorithm to data processing can solve the task. The principal procedure of processing includes regular noise extraction by compiling waveforms of the neighboring depth steps in time domain. The search of reflected pulses in waveforms is provided by time windowing and finding the first reflections in frequency domain.

Application of described techniques in memory logging tool and data processing discovered a durable method of caliper measurements in horizontal boreholes. Field tests have demonstrated the capabilities of proposed logging method in borehole shape determination. Actually in more than a hundred boreholes average diameters were measured without discontinuities. The error of diameter determination was in the range of ±2 mm.

The results of field tests gave a hope for the ultrasonic caliper application to both borehole shape measurements and stress direction determination.
Pilot Project: Remote Monitoring Centre
Authors: Monakhov Vyacheslav V.
Published: October 2008

In September 2007 Remote Monitoring Centre (RMC) was established in NK Rosneft-Stavropolneftegaz, LLC, with the following functions:

Operation monitoring of «golden» well stock: Operation analysis of high-flow-rate well stock (Qoil ≥ 20 Tones/day) Organizing supply of supplementary information required – well flow testing, measuring data Spot data check (well flow testing, measuring data, data from ESP control stations) Failure analysis of wells and activities development: Daily cause analysis of failures Supervision of equipment disassembly (commission review), data base maintenance for failure causes due to configuration Activities development in order to increase time between failures for each failed well Designing ESP units Proposals on well operation business process reengineering, introduction of quality management system (TQM).

Reasons for establishing the Remote Monitoring Centre (RMC) are:

Geographical expansion; Declining production and cost escalation; Increasing staff shortage – competing for young people and limited number of experts; Highly feasible potential of production increase, cost reduction owing to both, innovative technologies and improvement of business processes; Inconsistency between organizational structures and production requirements for innovative technologies (reorganization is always late for application of new technologies).

Project Development Phases:

Source information quality improvement (statistics collection and processing) – 3rd quarter, 2007, – 2TB quarter, 2008. Visual problems representation by original software technology (RnWV) – 3rd quarter, 2008. Targeted activities aimed to operation efficiency improvement of artificial lift well stock (ideal equipment selection, abnormal wells, etc.) – 4th quarter, 2008.

Project's Novelty:

Integration of the Company's scientific and production potential; Creating optimum equipment design selection algorithm based on complicating downhole factors (detailed design of equipment components).
Development and Application of Innovation Technologies for Seal-Repair, Stimulation and Enhanced Oil Recovery
Authors: Zavolzhsky V.
Published: October 2008

The major activity of LLC "RITEK-ITC" is development, application, improvement and adaptation of innovative methods for seal repair, well stimulation, reservoir productivity increase, and production of chemical reagents.

In 2007 RITEK carried-out the following works on technologies:

integrated technology of selective water-restrain using invert emulsions stabilized by POLYSIL-DF with subsequent additional strengthening by plugging composition based on the material PLASTIK-KS; treatment of bottomhole formation zones (BFZ) in producing wells by invert water-oil emulsion using POLYSIL-DF for selective water-restrain; seal repair works (SRW) to eliminate untightness of production string and behind-the-casing flows, to shut off strata using plugging materials PLASTIK-KS; BFZ treatment by acid micro emulsion (AME) to increase reservoir permeability; BFZ treatment by the POLYSIL-P suspension to increase injectivity of intake wells; BFZ treatment by acid compositions (PC-9) to increase reservoir permeability; leveling of injectivity profile by PGS RITIN-10 to increase oil recovery.
Franchising -- a partnership model for efficient water services operation and maintenance
Authors: Wall Kevin , Bhagwan Jay , Ive Oliver
Published: October 2008

There is a need in South Africa for institutional innovations aimed at increasing the coverage and reliability of water services, and sustaining those services. The paper describes an alternative service delivery institutional concept, viz the franchising of the operation and maintenance of water services, and outlines the need to formulate a franchise model that could be developed and made available to emerging entrepreneurs as the basis of a viable business. The franchise would be in respect of components of the water services value chain that are suitable for small business in that they can be readily systematised.
Mapping Biopharmaceutical Innovation and Diffusion: How the Second Translational Block (T2) Shapes Drug Diffusion
Authors: Cohen Joshua , Faden Laura , Getz Kenneth
Published: October 2008

In the US, there is a vigorous public debate on the merits of biopharmaceutical innovations and their diffusion. There is virtual unanimity about the importance of maintaining a steady stream of biopharmaceutical innovations, to which patients should have timely access. However, the debate’s participants are cognizant that the effects of innovation and diffusion on health outcomes, health care spending, and incentives for future innovation, must be weighed against one another.

First, we performed a Medline literature review to map the innovation diffusion process, combining the search terms “innovation,” “diffusion,” and “pharmaceutical.” Second, we conducted a survey of 190 physicians to examine their valuation of the innovativeness and rate of diffusion of 20 new molecular entities (NMEs). Third, we collected data from the Centers for Medicare and Medicaid Services (CMS) Formulary Finder to assess payers’ valuation of the innovativeness of the 20 NMEs in question.

Based on our literature review, we identified the key stakeholders involved in the innovation diffusion process. Furthermore, we highlighted the changing landscape of translational movers and shakers, tracing the emergence of T2 barriers, emanating largely from third party payer formulary management. Our empirical analysis suggests payers are exerting influence on physicians’ prescribing decisions, while the role of patients and pharmaceutical firms has diminished somewhat. Payers directly affect prescribing decisions through the use of formularies, and indirectly by funding evidence-based continuing medical education.

On average, across the 20 drugs we sampled, the time from approval to first prescription was 33 months, which indicates a slow diffusion process. Our data analysis shows a gap in perception of innovativeness between physicians and payers, with physicians ranking drugs as more innovative on average than payers. And, our findings suggest the more innovative a drug is perceived by physicians and payers the higher market share it has.

Striking an appropriate balance on access to and cost of biopharmaceuticals will require policy adjustments on the part of payers. In cases in which there is a large degree of uncertainty or the fiscal impact is particularly high, coverage could be made subject to a policy of coverage with evidence development (CED). Here, coverage would be conditional on development and capture of outcome data. A CED policy could be combined with a risk-sharing arrangement in which financial risk is shared between payers and the biopharmaceutical industry.
Does 'Relationship Intelligence' Make Big Brains in Birds?
Authors: Scheiber Isabella B.R. , Weiβ Brigitte M. , Hirschenhauser Katharina , Wascher Claudia A.F. , Nedelcu Iulia T. , Kotrschal Kurt
Published: October 2008

Lately, Emery et al. developed a bird-specific modification of the “social brain hypothesis”, termed “relationship
intelligence hypothesis”. Although the idea may be valuable, we doubt that it is supported by sufficient evidence and
critically discuss some of the arguments raised by the authors in favour of their new idea.