bluuebunny/crossref_metadata_2025_split huggingface dataset:
Carbonate Reservoir Simulation Improvement on Base of Well-Test Data to Increase Forecast Reliability
Authors: Gulyaev D. , Chernoglazova N. , Fedoseev M. 
Published: October 2008

Abstract
Field development plans has been made on base of numerical reservoir models for many years in Russia. Nevertheless poor quality of lots of models makes them unable to provide reliable production forecast and optimize reservoir management. This is one of the reasons of relatively low recovery on fields in Russia. Numerical reservoir models quality can be significantly increased by wider usage of well-test and production-logging results for reservoir modeling.
JSC «Gazprom Neft» field example of carbonate reservoir shows that well-test and production-logging results can significantly decrease uncertainty in reservoir modeling and increase forecast reliability.
Breaking the Completions Paradigm: Delivering World Class Wells in Deepwater Angola
Authors: White Daniel , Whaley Kevin , Price-Smith Colin , Keatinge Patrick 
Published: October 2008

Abstract
The Greater Plutonio development, deepwater offshore Angola, is BP's largest subsea development. The "soft" rock reservoirs require sand-control completions that are some of the most complex and challenging in the world. A commonly accepted view is that effective sand-control can result in sacrificing well productivity; however, the 23 wells completed to date have broken that paradigm with world class results and the largest well potentials in the history of BP.
All twelve deepwater production wells employed Open Hole Gravel Pack completions, achieving outstanding results and technical limit productivity along with exceptional mechanical reliability and integrity. From the first well, they have all shown zero formation damage, resulting in individual well potentials up to 80 MBD. To support this prolific production capability, effective voidage replacement has been essential. Therefore, the injection well completions were designed to deliver equivalent well performance, while still providing robust sand-control. Based on this, Cased Hole Frac-Pack completions were selected for the initial gas and dual service injection wells with Stand-Alone Screen completions for the water injectors. The injector completions were as successfully deployed as their producer counterparts with technical limit injectivity on all the wells, setting a new standard for flow efficiency in high transmissibility reservoirs and delivering some of the largest water injector completions in BP's portfolio.
The Greater Plutonio completions excellence story is one of a truly performance driven and innovative team. Productivity indices are up to four times greater than prognosed and mechanical skins in production wells are all zero (compared with +5 to +20 in analogous fields). This is underpinned by comparable injection performance and furthermore, the over 99% mechanical reliability and full data acquisition uptimes have substantially reduced the probability of costly well interventions in the future.
This paper discusses the keys to the successful delivery of this world class completions performance and covers best practices and resultant well performance data of the first 23 wells from the planned initial 43 subsea well development.
Title Measurement of Component-Wise Gas Liquid Mixtures Flaw Rate
Authors: Akhmetzianov A. V. , Kasimov A. M. , Lunkin B. V. , Ermolaev A. I. 
Published: October 2008

Abstract
Here are examined measurement methods and instrumentation of two-phase multicomponent oiler production by using compensation method of volumetric flow measuring and resonance (radio wave) technique of composition measuring for technological control of the picked product directly in in the pipeline's flow area without separation of the phases.
Log Interpretation Methodology in Polygenetic Deposits of the Vikulovskaya Suite at the Kamennoye Field (Thin-Layer Storm Deposits and Incised Valley Fill Complex)
Authors: Lopatin A. Yu , Medvedev A. L. , Masalkin Yu. V , Valencia R. 
Published: October 2008

Abstract
The Vikulovskaya deposits of the Kamennoye field are marked by fine interbedding of sandstones and silts. The thickness of sandstone interbeds varies from a few millimeters to 50–60 centimeters. Well logging data interpretation in such a section often presents great difficulties. In the first place this is associated with the determination of the resistivity of oil-saturated sandstones which have a low resistivity without any correction for laminated shaliness and very often can be interpreted as water-saturated. The corruption of well logging porosity values as well as difficulties in net thicknesses delineation, add the complexity (qualitative indicators do not work, quantitative ones are corrupted). Certainly, up-to-date high-resolution geophysical logging tools help in some instances (3DEX - Baker Atlas, Multiarray Triaxial Induction Tool, FMI - Schlumberger). But they are expensive, and above issues need to be solved in a large amount of existing wells using conventional or even "clipped" well logging suite. Using various mathematical algorithms to obtain volumetric parameters is often ineffective due to the well logging data. The present paper shows how the profound understanding of Reservoir Geology helped to pass from lithotypes interpretation to geological facies interpretation and thus to solve some problems of well logging data interpretation.
The Development of an Intelligent Sensor for the Monitoring of Pipeline System Integrity
Authors: Umeadi Bonny B. N. , Jones K. G. 
Published: October 2008

Abstract
This paper presents experimental studies that integrate and develop a prototype sensor to monitor, analyse and communicate any changes in oil/gas/water pipeline performance in such a way that reduces pipeline failures and the associated disruption to supply, damage to the environment and cost to the company. In the oil steel pipeline systems industry alone, the financial implications of pipeline failures have been estimated at £2.5 billion year.
Further, current methods of detection rely on periodic inspection which misses more occurrences of failure than it identifies. What is needed is a semi-continuous monitoring system that not only recognises imminent pipeline failure characteristics but also automatically transmits a warning to a central control centre.
This paper reports the findings of a laboratory based test programme to evaluate the potential for vibration sound emission detection to form the basis of such an early warning system. Attenuation and waveform analysis were used to identify theoretical changes in the flow characteristics of a liquid medium as it passed along a damaged section of pipe.
The effectiveness of piezoelectric sensors to detect the changed flow characteristics were evaluated for a range of artificially induced defects. The flow characteristics were analysed (using spectrum analysis of the signal across a number of frequency bands) and compared to the theoretical predictions. The results show that a piezoelectric vibration sound emission sensor can detect changes in the flow characteristics of water and diesel oil to a level of accuracy that could form the basis of an integrated wireless sensor device. Further qualitative diagnosis theory can form the basis of an algorithm which could be used to associate the changed flow characteristics with underlying pipeline defects without third party intervention.
Particularities of Hydraulic Fracturing in Dome Type Reservoirs of Samara Area in the Volga-Urals Basin
Authors: Parfenov A. N. , Sitdikov S. S. , Evseev O. V. , Shashel V. A. , Butula K. K. 
Published: October 2008

Abstract
The majority of hydraulic fracturing work in Russia is being done in the Western Siberian basin where operators and service companies have gathered significant amount of experience and knowledge. The sweeping success of hydraulic fracturing in Western Siberia organically expanded to projects in Tymen-Pechora and Volga-Urals basin. Both basins are geologically, lithologically and stratigraphically vastly different from West Siberia. Adding the difference in the maturity of the fields, with significantly depleted reservoirs, high asphaltene and paraffin oil content varying the hydrocarbon properties, it is understandable that the extensive knowledge gained in Western Siberia can not be translated to the less frequent but well engineered and planned stimulation campaigns in the Volga-Urals basin.
This paper presents a summary of the knowledge gained in Samara fields of the Volga-Urals basin, with emphasis on the results obtained and highlighting the differences with the Western Siberian approach to hydraulic fracturing.
Samara area is characterized with relatively low temperature, high permeability, low pressure, laterally and vertically restrained dome type sandstone and carbonate reservoirs that are located in tectonically active, high stress environment. Although correct candidate selection and fracture design, the degree of the pre-stimulation formation damage has proven to be significantly different from the comparative formations in Western Siberia hydraulic fracturing has proven again to be a successful stimulation method.
Carbonate reservoirs that constitute some 50% of the oil bearing rock in the area have seen the first acid fracturing treatments performed, including the introduction of various diverter methods in the area. The success of the pilot project is addressed as it sets a milestone in carbonate stimulation in the Volga-Urals basin.
Foam Fracturing: New Stimulation Edge in Western Siberia
Authors: Oussoltsev D. , Fomin I. , Butula K. K. , Mullen K. , Gaifullin A. , Ivshin A. , Senchenko D. , Faizullin I. 
Published: October 2008

Abstract
The majority of oil exploited from Russian oilfields today comes from the Volga-Urals and Western Siberian basin, where large-scale fracturing and coiled tubing operations have been on-going for the past six years. In the mainly brown fields, tertiary recovery methods such as water-flooding are implemented to maintain financial viability of the well stock. In many areas, however, production wells do not benefit enough from the water flood, or the injection scheme is not optimized.
A consequence of reservoir pressure depletion is the increase in filtrate leak-off of drilling, completion as well as stimulation fluids. The sensitivity of the formation to wellbore fluids, the impact of the wettability changes and near wellbore damage is not fully evaluated on all formations and fields. It is though evident that the volumes of wellbore fluids lost to the reservoir impact final productivity. It equally affects the possibility to flow the well back after stimulation treatment. Hydraulic fracturing treatments have become the most popular completion method in Russia, and foam-based fracturing fluids seems to be a possible solution to the above problems. Foam, though, has evaded application in the region until recently.
Absence of foam to this point is mostly due to equipment requirements and logistic complexity. A hydraulic fracturing treatment based on foam as the main proppant carrier fluid effectively reduces the amount of liquid pumped overall, provides better fluid-loss control and aids in post-treatment flowback. Foam fracturing causes less damage to the formation and proppant pack, therefore improving the productivity of the well.
A variety of reservoirs and the impact of foam fracturing is described and analyzed in this paper, from typical shallow gas to challenging deep oil reservoirs, using numerous fluid systems such as foamed visco-elastic surfactants to stable- and superfoams.
Productivity Prediction for Fractured Wells in Tight Sand Gas Reservoirs Accounting for Non-Darcy Effects
Authors: Motiur Rahman M. 
Published: October 2008

Abstract
Reliable prediction of production profile for fractured wells is important for hydraulic fracturing optimization. Contribution of Russian researchers (Hristianovich, Zheltov, Goldstein, Entov) in hydraulic fracturing is worldwide recognized. The production profile includes early transient period that is followed by pseudo-steady-state production. Usually, the transition period for conventional reservoirs lasts for months while for tight sands with permeabilities far below millidarcy, it can exceed years. Therefore, two regimes are important for production profile prediction in tight sand reservoirs.
Drawdown values in tight sands significantly exceed those for conventional reservoirs, so gas velocity in well fractures is also exceedingly higher. At high Reynolds numbers, inertia effects have the same order of magnitude that the viscous (Darcy's) pressure losses. It results in well productivity decrease. Therefore, it is important to account for non-Darcy effects in fractured well modelling.
In the current paper, the inertia non-Darcy pressure losses are incorporated in the mathematical model for gas production via fractured well in tight sand reservoirs by including the quadratic term into momentum balance equation for gas flow in fracture. The model is based on matching of semi-analytical solutions for transient and pseudo-steady-state flows towards well and extends the previous research by considering non-Darcy effects. The iterative procedure allows predicting production profile up to 15 years in fields with permeability 0.005-0.2 md. The model developed aims optimization of hydraulic fracturing in tight sand gas fields.
Application of Outcrop Analogues to Optimize LWD Acquisition for More Confident Formation Evaluation in High Angle and Horizontal Wells
Authors: Tyurin E. , Benefield M. 
Published: October 2008

Abstract
Outcrop analogues are very helpful in generation of the reservoir depositional model but are restricted in their application to formation evaluation. They represent a missed opportunity, in particular in the interpretation of high angle and horizontal (HA/HZ) well log response. In our vision they give us access to the depositional controls on vertical and lateral petrophysical rock properties variations as well as actual geometry of the geological bodies; both matters are critical for confident formation evaluation in HA/HZ well setting.
The primary objective of this study is the integration of geological answers and petrophysical information to construct forward models of our high technology LWD datasets. We assign a major significance to the visual comparison of the rock picture and a simulated tool response, supported by a detailed petrophysical analysis.
We initially used the Ainsa 1 Pyrenean deepwater turbidite outcrop with the petrophysical properties of analogous offshore West Africa reservoirs. Across-channel geological complexity (thin layering and low NTG in marginal part; pinch-outs, amalgamations and rock property variation in the axial part) is valuable to demonstrate improved strategies of interpretation solutions in channel to lobe turbidite settings. Steps to forward model the LWD data include many of today's reservoir characterization procedures: sedimentological description, lithofacies to petrofacies associations, core and field scale 3D petrophysical properties simulation, upscaling, true resistivity matrix generation and resistivity anisotropy evaluation. Forward modeling of tool response accounts for different measurement natures, geometries and DOI's (from meters in resistivity to cm in radioactivity, images and magnetic resonance).
The range of the results acquired shows that basic LWD suites often do not provide an accurate result in a heterogeneous environment. For example, in our case water saturation is overestimated by around 30% total through improper use of the classical data. Our study highlights that reservoir parameterization in the presence of all scales of heterogeneities, sand mixtures and thin laminations is enhanced through proper application of gamma ray, resistivity, density, neutron and NMR for the pore volumetrics and imaging for the geobody shaping.
Using the approach to a contrasted West Siberian field case with inherent low resistivity contrast and invasion of WBM demonstrates further interpretational challenges. The work ultimately permits a more confident selection of logging suites and subsequent improvement in application of the acquired data to formation evaluation in high angle and horizontal well situations.
Development and Field Application of a Low pH, Efficient Fracturing Fluid for Western Siberian Oil and Gas Wells
Authors: Gupta D. V. S. , Le H. V. , Batrashkin A. , Nevsky P. 
Published: October 2008

Abstract
Hydraulic fracturing has proven to be one of the best technologies to improve productivity from oil and gas wells. Careful consideration must be given to fracturing fluid selection, particularly when the fluids have to be prepared with local waters. Siberian waters are particularly troublesome because of the presence of iron and bicarbonate and hardness, depending on the water source. Some hydrocarbon reservoirs are under-pressured and require the use of energized fluids, while others are sensitive to water-based fluids due to clay swelling and migration.
Proppant pack damage due to gel residue is one the primary causes of low production rates after hydraulic fracturing treatments. To minimize the damage and therefore maximize production, a new premium highly efficient fracturing fluid was developed. This premium system incorporates low polymer loading carboxymethyl guar polymer and a zirconium-based crosslinker. An adjustable crosslink delay makes the fluid ideal for deep well fracturing and coiled tubing treatment as frictional pressure losses can be minimized. The system can be energized or foamed with CO2 and N2 or may also be used in binary foam systems.
This paper will compare the new fracturing fluid system with alternative guar borate system used in Russia, in terms of proppant pack cleanup, rheological properties, proppant transport and fluid loss as well as other parameters. Various rheological evaluations using high-pressure, high-temperature rheometers as well as a foam loop; fluid leak-off testing; and proppant pack conductivity and regain permeability evaluations are presented.
Optimization of Coiled Tubing Interventions on Extended-Reach Openhole Completions in a Field in Saudi Arabia
Authors: Beheiri Faisal I. , Al-Mubairik Abdulrahman J. , Al-Mulhim Abdulrahman K. , Al-Meshal Fahad M. , Noguera Jose , Sierra Leopoldo 
Published: October 2008

ABSTRACT
Drilling new generation wells with longer horizontal sections, to maximize the reservoir contact, has brought many challenges to well interventions using Coiled Tubing (CT). In most cases, the complexity has pushed CT interventions to the limits, driving the development of new solutions to extend the reach to total well depth.
The number of these extended-reach wells has grown significantly in recent years in Saudi Arabia, especially in this new development field where more than 120 extended reach water injection wells were placed in the reservoir flanks. The water injection wells in this study area are complex due to the combination of large bore tubular, lower reservoir pressure and horizontal openhole (OH) completion, with lengths from 3,000 ft to almost 5,000 ft.
During the initial CT i nterventions in this field, several challenges were encountered, e.g., stuck CT differentials, slack-off weight through severe doglegs, tight spots, and other obstructions. Extensive knowledge was gained by performing an extensive simulation, studying the horizontal section geometry and analyzing the operational data. Based on the findings, combinations of techniques were introduced to the procedure to extend the reach and minimize the operational problems and costs.
The key components of our new implemented strategy were buoyancy reduction by using nitrified fluids and new viscoelastic surfactant (VES) friction reducer or drag reduction agents. In addition, combinations of other techniques were employed, e.g., optimizing the pull tests frequency in the OH and improving CT movement practices.
This paper discusses the difficulties and challenges of the initial stage of the stimulation campaign, performed in horizontal OH water injector wells using CT. Also, it presents the results and analysis of the effect of buoyancy, CT pipe size and new friction reducer for the referenced wells. The study leads to a new cost effective and reliable technique, which once implemented, conduces to maximize the CT reach without using mechanical devices, e.g., agitators or tractors.
Productization of Data
Authors: Heggelund Dag G. , Andresen Vidar 
Published: October 2008

Abstract
An error in software, science, or data has an equal opportunity to yield incorrect results. Imagine using a computer or a software program that randomly gave the incorrect answer 30% of the time. Productization of hardware and software has given us products of much higher quality. This paper presents a methodology, DQM, for productizing the data.
Treating data as a product is a fundamental requirement in any data quality process. In this paper we apply productization to upstream E&P data and refer to it as making data suitable for a specific process. Treating data as a product forces the definition of data requirements, in a similar manner as we are accustomed to define requirements for other products. The degree that the data product meets these requirements defines the quality of the data product. Productization of data thereby yields a measurable definition of data quality.
This paper shows how productization of data yields a productivity centric definition of data quality. It further shows that Data Quality can be decomposed into five dimensions:
Completeness Consistency Content Uniqueness Validity
By applying an extended Design for Six Sigma (DFSS) approach, we show that data quality can be measured using the traditional sigma score. Our studies show that for organizations that do not utilize a data quality process the overall quality is less then three sigma, resulting in a resource waste of more than 30%. We further present findings regarding how organizations are adopting the new data product paradigm along with the overall impacts and lessons learned.
Analysis of Production Data with Elliptical Flow Regime in Tight Gas Reservoirs
Authors: Badazhkov D. , Ovsyannikov D. , Kovalenko A. 
Published: October 2008

Abstract
Analysis of production data for tight gas reservoirs is based on pressure transient (PT) analysis, which is now a conventional procedure for fractured tight gas reservoirs. Key parameters can be estimated during the analysis: fracture conductivity, fracture half-length and reservoir properties. Most PT analysis methods deal with bilinear, formation linear, and pseudo-radial flow regimes. It is well known that an elliptical flow regime can appear between formation linear and pseudo-linear flow regimes. Sometimes the period is very short and cannot be identified. But there are many cases when only formation linear and elliptical flow regimes are present in production data records and the time needed to reach the pseudo-radial period is more than decades. Most PT analysis methods substitute elliptical flow regime for pseudo-radial, which may lead to the incorrect calculation of key parameters of reservoirs and fractured wells.
In this study, we present the development of an approach for elliptical regime analysis in the production data record for calculation of key parameters of finite-conductivity fractured wells and reservoirs: fracture conductivity, fracture half-length, reservoir permeability, and effective drainage area. This method uses an analytical equation for elliptical flow period and estimation of parameters from the equation. The development is based on more stable deconvolution analysis of production data with variable rate/pressure and more reliable analysis of response function after deconvolution. We present here some synthetic and field cases to demonstrate the results of calculations.