bluuebunny/crossref_metadata_2025_split huggingface dataset:
Long-Term Comparison of Production Results from Open Hole and Cemented Multi-Stage Completions in the Barnett Shale
Authors: Lohoefer Darrell , Snyder Daniel J. , Seale Rocky 
Published: February 2011

Abstract
The Barnett Shale is considered to be a prototype for other shale plays in North America and throughout the world because it was the first shale play to be developed. This paper describes production results from two horizontal wells in the Barnett Shale completed with open hole, multi-stage fracturing systems (OHMS) compared to direct offset wells with conventional cemented liner, “plug and perf” completion.
Three years of monthly and cumulative production totals are analyzed and discussed. This paper also discusses the system details, the fracture methods used, as well as the operational efficiencies of OHMS compared to other horizontal completions methods.
These results demonstrate that OHMS technology provides a long-term option for the life of wells in shale plays. The estimated ultimate recovery (EUR) values for shale gas plays has been a hotly contested issue over the past year due to observed “catastrophic” production decline curves. This paper discusses how the choice of completion method can affect EUR by analyzing long-term production data from offset wells completed by cemented liner plug and perf versus OHMS. This knowledge can be applied to any unconventional shale reservoir.
Lithogeochemikal Features of the Jurassic Terrigeneous Sediments Formation Within Vat'-yegan Oil Field (West Siberia)
Authors: Kajachev N. F. , Kudamanov A. I. 
Published: February 2011

Abstract
We report here the results of lithogeochemical studies of silt-rich mudstones of the Tyumen, Vasyugan, Georievsk, and Bazhenov formations and sandstones and siltstones confined to the YuV11, YuV12, and YuV2 pay zones within the Vat-Yogan oil field. Chemical analysis was performed to define chemical composition of 370 core samples To detect major and trace elements an X-ray fluorescence method was used. To interpret the results of the study an R-mode factor analysis as well as nomenclatures, classifications and lithogeochemical techniques developed by F. J. Pettyjohn, M. M. Herron, and Ya. E. Yudovich were applied.
The Influence of Geological and Technological Factors on Enhanced Oil Recovery
Authors: Silin M. , Eliseev D. , Kulikov A. 
Published: February 2011

Abstract
The proposed report presents an analysis of the effectiveness of enhanced oil recovery (EOR), performed on the fields Western Siberian region in the period from 2002 to 2009. Analysis reached more than 1000 injection wells and processed about 5000 producing wells.
According to the analysis of the effectiveness of EOR determining geological parameters are partition factor and directional permeability of the reservoir, it is shown that the increase in efficiency with increasing partition factor is due to increased duration of effect.
It is noted that the decrease in the effectiveness of EOR occurs with increasing development of oil reserves. It is shown that the effectiveness of the EOR is the highest in the base water cutting wells about 80%. It was found that a decisive influence on the effectiveness of EOR provides value target intensity water cutting of well production, which expresses the anticipation of the current average water cutting of well production from the current development of initially recoverable oil reserves, shows the degree of backwardness of waterflooding processes from the processes of water cutting of well production. The analysis showed the benefits of integrated technology EOR, different injection gel-forming and stimulation chemical compositions. The advantages are the increase in injectability of injection wells with decreasing water cutting of well production. In order to optimize the flow of reagents for each field revealed the dependence of the efficiency of EOR from specific volume of the margin, whereby determine the optimum value of this parameter.
To confirm these results, we have conducted work on mathematical modeling of the EOR, which agree well with practically the results.
The practical value of the executed analysis of fishing activities is considerably improved the accuracy of selection of technologies EOR as a direct composition of chemical reagents, and the volume pumped into injection wells tracks.
Based on the analysis it was concluded that work on the runway injection wells on the fields of Western Siberia have led to increased oil recovery;
This work has significantly clarified the criteria for effective use of technology EOR; To a large extent optimized specific volumes of injected chemical compositions.
Fracture-Based Strategies for Carbonate Reservoir Development
Authors: Davletbaev Alfred , Baikov Vitaly , Doe Thomas , Emchenko Olga , Zainulin Aleksey , Igoshin Andrey , Fedorov Aleksey 
Published: February 2011

Abstract
Carbonate reservoirs present both opportunities and challenges, especially in rocks that contain multiple, heterogeneous porosities. This study addresses a large carbonate reservoir with complex porosity types including porous matrix, fractures, faults, and vuggy zones. A fracture-focused strategy considers how these porosities behave in oil production, and uses this understanding to improve reservoir productivity.
The subject of this work is a major carbonate reservoir that was initially developed by conventional methods. These approaches emphasized matrix properties using petrophysically-interpreted wireline logs. The early stages of production, which did not include pressure maintenance, found anomalous behaviors that were inconsistent with a matrix-only reservoir. The existing petrophysical data, which are valid only for porous rock, could not address fracture-based hypotheses.
A program of fracture studies supported a re-analysis of the production strategies in light of reservoir's observed behaviors. The fracture-focused strategy employed FMI image logs along with production logs (PLT surveys) and temperature surveys. These well-based tools identified the locations of flow and their associated geologic features, which are appeared to be mainly fractured and vuggy horizons. Coring activities validated the FMI interpretations.
A reexamination of well tests using supported a single-porosity, fracture flow model. Pressure derivative interpretations using fracture-based conceptual models associated well performance with geologic features, including both the vuggy zones and faults.
The fracture-focused characterization program has developed improved conceptual models of the reservoir to support evolving production approaches including well acidizing, and other. The paper provides examples of successful well operations performed after appropriate field research.
Thermal Modeling for Characterization of Near Wellbore Zone and Zonal Allocation
Authors: Ramazanov A.Sh. , Valiullin R. A. , Sadretdinov A. A. , Shako V. V. , Pimenov V. P. , Fedorov V. N. , Belov K. V. 
Published: February 2011

Abstract
This paper describes a new method based on the analysis of non-steady state wellbore temperature distributions impacted by geothermal temperature profile, Joule-Thomson and adiabatic effects in reservoir flow to describe near wellbore parameters such as permeability distribution and to estimate flow rate distribution between producing layers.
The solution of the inverse problem with respect to parameters of near wellbore zone is based on the quantitative analysis of the transient baro-thermal effects resulting from the single-phase fluid flow from the reservoir into the wellbore. In the steady state case the reservoir thermal effect is the same as the throttling (Joule-Thomson) one. It is reduced to the adiabatic effect while the fluid is stagnant. In the general case for non-steady state flow the change of reservoir fluid temperature is a combination of frictional heating and cooling resulting from the expansion of the fluid. Non-isothermal well testing (NIT) relies on the analysis of these fluid temperature changes. The method discussed in this paper allows evaluating parameters of near wellbore region (permeability and radius of damaged zone) and could be complimentary to the conventional well testing practices for a single-layer reservoir and to estimate flow rate distribution among the pay zones in a multi-layer case (zonal allocation). The paper develops mathematical models and presents the results of numerical simulation for transient processes after the start of the production phase and during well test operations including multi-rate testing.
Limited to the particular cases of unsteady processes after specific wellbore operations (changes of production regimes and shut-ins), the transient analytical solutions assume that the fluid may be considered incompressible and that no conductive heat transfer occurs. In order to take into account compressibility and thermal conductivity, detailed numerical modeling has been performed. The paper compares the numerical results to experimental data and shows that the fluid heat capacity in wellbore perforated zone must be considered for appropriate interpretation of initial bottomhole temperature change versus time, in particular for small rates. Based on the analysis of the simulation results, an inverse model solution for the estimation of the near wellbore zone parameters from reservoir fluid temperature and wellbore pressure transients is proposed. The method comprises first-order estimation from analytical solution and their further numerical refinements by non-linear regression for the system "reservoir-wellbore". Example of interpretation of non-isothermal well testing field data is presented demonstrating the usefulness of this new methodology.
Development of Inflow Profiling Criteria for Low-Rate Horizontal Wells on the Basis of Physical Laboratory Experiments and Field Studies
Authors: Valiullin R. , Yarullin R. , Yarullin A. , Shako V. , Parshin A. 
Published: February 2011

Abstract
Russian experience with geophysical studies in horizontal wells producing under conditions of low rates and multiphase separated flow shows that traditional methods using mechanical flow rate measurements and temperature logging are not effective in identifying the producing intervals. Results of physical experiments conducted in a laboratory flow loop established that flow structure in horizontal wells producing at rates from 2 to 250 m3/d is mainly determined by the wellbore trajectories and phase rate ratios. In these horizontal wellbores there is a zone of stagnant fluids, as well as significant vertical gradients of fluid velocities and temperatures.
Taking into account actual values of total and phase rates typical for horizontal wells in the Russian Federation, experimental works were carried out in a flow loop at Bashkir State University to develop criteria for flow profiling and methodology for wellbore field measurements in low-rate wells.
Analyses of the laboratory experiments and field data established the need for precise data on wellbore trajectory, taking into account the phase distribution across the flow at the tool location; the need for local velocity measurements in the temperature field along the entire horizontal wellbore trajectory; and the need for different well operational regimes. Based on the results of the experiments, actual field data were reinterpreted. Recommendations were developed for methodical guidelines for field data interpretation, and criteria were formulated for identification of oil and water inflow intervals in low-rate horizontal wells.
Recompletion of a Horizontal Water Injector Well Purely on E-Line Made Feasible and Viable with Wireline Tractor Technology
Authors: Kueh P.T. , Lam F.S. , Lim E.C. 
Published: February 2011

Abstract
A water injector located in an offshore Sabah field, Malaysia was sidetracked and completed as a single string completion on 13 September 2006. This water injector was designed for 10,000 barrels per day of seawater injection. It was completed as open hole with swellable packers targeting H sand only. However, due to differential sticking while running completions, the completion string became stuck at 700 feet above the intended setting depth. Since then, the well had been closed to avoid the risk of nearby fault activation.
Due to the initial injection behavior of the new injector and the fear of fault reactivation, it was decided to re-complete an injection well by isolating the area near the fault it was intersecting. This was achieved by setting bridge plugs to isolate existing zones and re-perforate a new zone above the plugs. The original consideration to recomplete the well in 2008 was to use a conventional coiled tubing unit to access the horizontal section of the water injector. Due to the small size of the platform at this well, there was not sufficient space for placement of coiled tubing surface equipment, a dedicated barge equipped with catenary system had to be considered. Total cost and anticipated risks were high and as such, recompletion of this water injector well by way of a conventional coiled tubing unit had to be classified as low priority due to limited barge time allocated in the 2008 coiled tubing intervention campaign, which naturally became non-feasible and non-viable to execute.
An unconventional method of recompleting the horizontal water injector purely on electric wireline and wireline tractor was then considered and evaluated in 2009, in terms of technical do-ability, economics and risks involved. Recompletion of the water injector was then executed successfully in the same year purely on electric wireline on a shore-offshore-shore daily tripping arrangement at one fourth of the originally anticipated cost when compared to a barge involvement. Successful re- activation of the water injector well realized a significant increase in reservoir ultimate recovery as well as oil gain over the following years of production from the H sand.
This paper will describe the background of the project, recompletion concept selection and well delivery process, actual execution and result of operations. The identified key success factors are also discussed.
Calibration of Permeability Vertical Profile with Regard to Well Production Data
Authors: Khasanov M. M. , Toropov K. V. , Lubnin A. A. 
Published: February 2011

Abstract
A new method for determining permeability profile in producing wells is proposed in this study. The method is based on integration of log interpretation results with well test data and information on vertical reservoir heterogeneity, determined from core studies or production data. Mathematical problem which has been stated is in determining a relationship between true and log-based permeability assuming that the type of permeability distribution function is given. We propose to solve this problem using generalization of the well-known mathematical statistics tool — a quantile-quantile transformation. A new algorithm for determining the Dykstra-Parsons coefficient (as a measure of vertical reservoir heterogeneity) based on historical oil production data is presented as well. The key advantage of proposed technique is acceleration and improvement of history matching in dynamic modeling process. It has been shown that the results obtained after the first model initialization are in very good agreement with production data.
The Oil and Gas Bearing Potential of the North of the Siberian Platform According to the Results of Basin Modelling
Authors: Boldushevskaya Lyudmila N. 
Published: February 2011

Abstract
Two-dimensional modelling of oil-and gas generation history aimed at estimating oil-and gas potential of Paleozoic deposit have been carried out within understudied territory of the north-west of the Siberian platform. The structural imaging data and the results of the geochemical investigations of organic matter such as Rock-Eval pyrolysis, the analysis of the elemental composition of kerogen, the measurements of vitrinite reflectance in coaly inclusions of Upper Paleozoic rocks, the study of biomarker hydrocarbons distribution have been used in the research.
This report presents the results of stratigraphic formation thickness analysis with the use of geological survey, drilling, seismic prospecting data; the results of basin modelling and reservoir properties data analysis. The necessity of further detailed study of oil-and gas accumulation zone, adjoining to the Lama-Khantaika trough, has been founded.
The results achieved make it possible to carry out reconstruction of oil-and gas generation history, estimate resource base and justify the priority directions of licensing within the undistributed fund of the north-west of the Siberian platform.
Application and Optimization of Oil-Based Drilling Fluids for ERD Wells YNAO Area
Authors: Arslanbekov A. , Sevodin N. , Valuev D. , Mosin V. , Korolev A. 
Published: February 2011

Abstract
The paper summarizes application experience and optimization of oil-based drilling fluids for the development of oil and gas condensate fields in the north part of YaNAO area. Key requirements, application criteria, design decisions, advantages and limitations, main features and field application results are analyzed based on Yurkharovskoe oil/condensate field. Extensive computer modeling and hydraulic simulations were performed to take into account temperature and pressure conditions. Actual results are compared to that achieved in the field. The main features of proposed OBM formulation are discussed with respect to local field and reservoir specifics, including wellbore stability, ECD management, reservoir damage, drilling waste management. ERD specific features and benefits are highlighted.
Article demonstrates how extensive planning and preparation work has allowed to overcome many obstacles, typically associated with OBM application in remote areas with harsh climate conditions. Environmental regulations were thoroughly evaluated and proactive waste management was implemented to mitigate environmental risks.
Reservoir conditions and wettability were evaluated to ensure minimum OBM formation damage. Production data is included to demonstrate OBM applicability as reservoir drill-in fluid for oil-wet Yamal reservoirs.
The large scale implementation of oil-based drilling fluids in YaNAO is an ongoing unique project with the massive amount of lessons learned and “know how” technologies involved from all parties. The OBM application experience provided in the paper can assist other companies working in YaNAO with planning and execution of ERD projects and simplify OBM implementation. The experience gained on Yurkharovskoye oil/condensate field can also be applicable to other North Russia projects onshore and offshore.
Can Simulation Models Help in Oil and Gas Field Management? An Assessment Methodology for Reservoir Modeling
Authors: Larijani G.R. , Gallivan J.D. , Pepelyaev R.V. 
Published: February 2011

Abstract
The petroleum reservoir is a physical system defined by static and dynamic parameters. It is also an asset requiring investment. The reservoir model is a tool that we use in order to exercise control over the reservoir so that we can produce the reserves economically. By understanding the levels of confidence in our input reservoir parameters and by adopting a controlled approach to using the reservoir model we can strive to get a greater degree of control over the asset.
In this study each reservoir parameter in the model has been scored based on six criteria; Data used in parameter determinationMethodology for parameter computationIndependent verification of the computationEstimation of 90% confidence interval in the resultActions taken to make 90% confidence range smallerPercent decrease of the confidence interval
The Thistle field in the UK sector of the North Sea is used as a reference assessment in this paper.
The assessment methodology presented here can be used by senior technical staff and management to assess the degree of control given by the model before the predictions from the model are used for field development planning. The significance of this methodology is that it provides an objective measure of the quality of a reservoir model. It avoids reliance on intuition and gut feel in establishing trust in the reliability of production profiles and reserves estimates derived using reservoir simulation.
An Efficient Approach for Earth Model Updates
Authors: Suter E. , Cayeux E. , Vefring E. , Næsheim L. I. , Friis H. A. , Escalona A. , Kårstad T. 
Published: February 2011

Abstract
The increased amount of available measurements when drilling with wired pipe opens new possibilities for well placement optimisation. This requires effective interpretation, integration and utilisation of the new information within the timeframe set by the ongoing drilling operation. Earth models carry knowledge about geological structures and physical properties, and form part of the basis for geosteering applications. However, current earth modelling tools have limited capabilities for effective integration of newly acquired information. Model modifications are complex and labour intensive, and the time needed exceeds the time available during drilling. This is a large drawback for decision-making processes that require the most current and precise information.
The complexity of the earth model modification process in existing methodologies is partially a result of storing physical parameters in grids. The grids are controlled by a structural model composed of fault and horizon geometries obtained from geological and seismic interpretation.
We have developed a gridless strategy based on separation of structural information from physical parameters. The separation of the geometric and the parameter models enables modifications to be handled individually and more efficiently. It increases control with model resolution which allows improved management of large data sets, access to earth model information at any scale and efficient sharing over computer networks.
The main principles of our approach are demonstrated through geologically realistic test cases that imitate real drilling scenarios in a reservoir with normal faulting. The combination of new technologies may form a basis for closed loop control/automation of sub processes, required for future automation of the whole drilling process.
Integrated Geological and Engineering Uncertainty Analysis Workflow, Lower Permian Carbonate Reservoir, Timan-Pechora Basin, Russia
Authors: Shirazi A.F. , Solonitsyn S.V. , Kuvaev I.A. 
Published: February 2011

Abstract
This paper aims to show all the steps involved in a rigorous uncertainty analysis study, completed in 2008, in static and dynamic modeling as well as try to highlight some very key steps for a successful study.
Yuzhno Khylchuyu (YK) field is a Permian aged Carbonate reservoir in Timan Pechora basin in European part of Russia. It was discovered in 1981 and has since been appraised by 24 wells. The field is being developed on a regularized waterflood 5-spot pattern with 120-acre well spacing.
The productive reservoir is composed of three main zones, A, B, and C. These zones are not in communication based on geo-chemical data and dynamic well test results. Zone A, which is dominantly progradational has good continuity and best reservoir properties containing 90% of the original oil in place (OOIP). Dominantly aggraditional zones B and C are discontinuous, and have poor reservoir properties.
The motivation behind a rigorous uncertainty analysis on OOIP and Expected Ultimate Recovery (EUR) was due to the large capital investment required for full field development. Thus, the objective of this study was to quantify the range of uncertainty of OOIP and EUR, to identify the most influential parameters contributing to uncertainties in OOIP and EUR, and quantify the impact of those most influential parameters. Such rigorous uncertainty analysis would thus help mitigate the risks with the investment.