bluuebunny/crossref_metadata_2025_split huggingface dataset:
Preventing Annular Water Flow in Primary Cement Jobs Utilizing Swellable Packers
Authors: Takhodinov S. F. , Ibragimov N. G. , Khisamov R. S. , Ibatullin R. R. , Mitchell R. K. , Davis T. W. 
Published: October 2012

Abstract
Cement has been the main form of annular zone isolation for oil well construction since the beginning of the industry. It is a science in its own right comprised of technical experts continually improving materials and processes. Often the failure of cement to achieve zonal isolation can be traced to the lack of best practices. When the cement does not provide required annular isolation, the result can be one of the following: Excessive water productionLost production from cross flowGas migration revealed as sustained casing pressure / sustained casing flowContamination of shallow water zones
Excessive water production diminishes the value of an asset and results in extra capex/opex for remedial operations. It can also result in delayed oil production. By concentrating on the zonal isolation process during the completion phase, many zonal isolation issues can be mitigated. A detailed evaluation of the cement program can highlight areas of improvement in both materials and operations. This is especially critical for areas where there are multiple stacked productive zones (oil on water) and varying reservoir pressures. An approach to improve annular integrity and the overall cementing process is the use of swellable packers. This practice has become more commonly accepted over the past few years.
This paper will discuss the best practices adopted to mitigate water production up to the time of implementing swellable packers followed by the additional improvement achieved by including swellable packers with the best practices.
Drilling Support Center -in its True Sense - A Russian Operator Experience
Authors: Bakici Ali M , Sarkisov Ivan I , Garifullin Azat A , Aker Gokhan H 
Published: October 2012

Abstract
Operators and service companies are considering alternative methods to remedy shortage of qualified and experienced staff to manage increasing activity and complexity. TNK-BP's approach has been creation of Drilling Support Center (DSC) as part of upstream peer review and technology center in Tyumen. The Company has eleven subsidiaries spread across Russia, and operations are managed by 6 regional drilling teams. DSC is centrally located to ensure geographical coverage of both eastern and western regions, with a mission to improve drilling performance, as well as support new technology implementation.
Main drivers for creating DSC were: –Increasing complexity of wells and wide geographical spread,–Limited drilling personnel with experience and expertise,–Commencing international operations requiring central support,
The center currently provides support in three main directions; firstly, monitoring complex and critical operations using realtime link from rigs by experienced staff with relevant expertise, including regular contact with operations teams to provide proactive feedback. Second direction is engineering support to well planning and new technology implementation by experienced specialists in directional drilling, cementing, drilling fluids, completions and drillbits. Third direction is Geosteering support of horizontal wells including real-time update of sector models. The center is active over a year now and subsidiaries regularly contact DSC for critical operations review.
Reducing the Loss of Energy in Transport Pipeline for Viscous Oil
Authors: Radulescu Renata , Sin Marius C. , Clain Bogdan M. 
Published: October 2012

Abstract
The variation of temperature over a pipeline has a major influence over viscous oil pumping.
Viscous oil transportation in non-isothermal regime, through buried pipelines, is a flow process in which intensive energy exchanges occur. Heated oil loses heat in the environment where the pipeline is assembled, but at the same time due to its friction with the pipeline's walls and to dissipated viscosity which produces in turbulent flow mechanical energy, this turns into heat.
Given such a context, the purpose of the paper is to assess the efficiency of oil transportation in non-isothermal state, and in order to achieve it we will make use of the entropic analysis of the process. Entropy is a state measurement of the process that enables the analysis of energy loss.
Entropy generation during a process is directly proportional to the available lost power.
We will show the dynamic variation of pressure and temperature in the transport process, the analysis of hydrodynamic and heat losses, as well as the entropic analysis.
Fracturing Completion System Optimization through Advanced Hydraulic Modeling
Authors: Deshpande K. M. , Simpkins D. , Gandikota R. , Ring L. 
Published: October 2012

Abstract
Openhole, multi-stage fracturing systems are commonly used today in many applications, including unconventional shale gas reservoirs. As many as forty stages have been successfully completed in a single horizontal well and the industry is aiming even higher. One problem that has a major impact on job success is the ability to accurately calculate maximum pump rates for a given surface pump pressure. When frac fluid is pumped through a downhole multi-stage fracturing system, each time a new stage is completed, the flow splits at different sleeves in the completion string.
To determine minimum surface pump pressure and maximum pump flow rate, predicting split flow rate and the resulting pressure loss at each stage is essential. Traditionally, laboratory tests and field experience are used to predict these values. However, these types of predictions are not possible for hydraulic fracturing jobs that use a multiple sliding sleeve system, as is commonly employed. To simulate the hydraulic fracturing process, the Computational Fluid Dynamics (CFD) approach has been used, as it is a proven methodology. However, extensive CFD analysis requires computational overhead and significant software and hardware costs.
This paper presents a methodology which combines CFD and theoretical approaches to calculate split flow rate and pressure loss for non-Newtonian frac fluids in a multiple sliding sleeve system. These methods are incorporated into the multiple sliding sleeve design process and hydraulic fracturing plan optimization. The method can also be extended as a general solution for calculating pressure loss due to split flow.
IT Governance and Organization in Smart Oil Fields
Authors: Guldemond Ewoud , Acda Léon , Andronov Mikhail 
Published: October 2012

Abstract
Several major oil companies have brought in specific Information Technology (IT) to implement the Smart Oil Fields concept in practice. They did so to reduce costs, to increase productivity and for recovery purposes. However, implementing IT for Smart Oil Fields does not automatically imply that you have actually implemented a Smart Oil Field with all its benefits. Alignment of the IT to the specific business needs is often lacking. In order to successfully operate Smart Oil Fields, and getting most of the value, oil companies need to have an adequate IT Governance and Organization framework in place, which bridges the gap between business and IT.
In order to develop such a framework, a PhD research was conducted at three different Operating Units of a major oil company. The research focused on the organizational structure of oil production locations, which had already implemented Smart Oil Fields. During our field research, interviews with staff & management were conducted, company documents were analyzed and observations were made.
We combined our research findings with our project experience on IT Governance and Organization in major oil companies in The Netherlands, Russia and South America. Our research findings combined with our project experience has resulted into an integrated, hands-on IT Governance and Organization framework for oil & gas companies who are implementing or planning to implement Smart Oil Fields operations.
Operational Performance Analysis of Mature Oilfields
Authors: Turchin Sergey 
Published: October 2012

Abstract
Analysis of field performance is a critical step in improving the production efficiency and optimizing the cost of operations. However, existing methodologies of analysis have limitations, particularly in the size of the analysis set and the inability to compare different types of assets. The new methodology was designed to overcome these limitations.
This paper explains the methodology of field performance assessment and shares some high-level results of the analysis. Operational performance is compared with results within a peer group. It allows the operator to obtain insightful information on how to improve the efficiency and reliability of production operations. The methodology is characterized by high quality performance indicators – the large amounts of data were collected from the operators and public sources, including cost, production, and technical field data. The detailed analysis is conducted for 12 standard operating cost classifications across seven oil and two gas peer groups, based on similar geological and operational characteristics. The methodology focuses on operations cost performance, production efficiency and production reliability performance, efficiency and cost driver analysis, and gives a suggested action plan. The paper also demonstrates how the results may be utilized to improve efforts by operators in the environment of mature oil fields with declining production levels.
The described methodology was applied to an analysis of the Permian Basin, which contains a large number of maturing oil fields. The study assessed 90 fields, including 35 waterfloods, 20 primary, 15 tertiary, and 20 gas fields for the period of mid-year 2010 to mid-year 2011. Trends and correlations between production efficiency and cost driver factors were found. This led to the issuing of recommendations to the producers.
The proposed methodology can be applied to an analysis of the operations performance of mature oilfields in Russia, which will result in low operating costs and higher production volumes.
E-Field Real Time Well Temperature Monitoring - Kharyaga Field Case
Authors: Semenov Andrey , Renaud Antoine , Allanic Christophe 
Published: October 2012

Abstract
Kharyaga field is a complex karstified carbonate reservoir located in a harsh arctic environment of Timan Pechora region on the North of Russia. The main Kharyaga reservoir, still under development, is subdivided on several layers and is characterized by an important heterogeneity (spacial distribution, fractures, karstified areas, etc …) leading to a very complex flow distribution in the reservoir (sweep efficiency) as well as in the well (water breakthrough, possibility of cross flow). In addition, the oil of this reservoir is waxy crude with high positive appearance pour point temperature.
High dynamic data quality and adequate real time follow up is mandatory for proper reservoir behavior understanding and characterization in order to be able to take effective operational decisions in due time and then maximize production level. Estimation of each layer contribution to the overall production allows proactive reservoir management including real time follow up and well intervention planning.
Fiber optic systems were installed as a part of the upper completion system below ESP in front of perforated interval. Each development pad is equipped with permanent DTS (Distributed Temperature System) to acquire temperature traces data in selected wells. An innovative system was implemented in order to ensure temperature traces acquisition, transfer and storage in real time to Moscow office, which allows reservoir engineer to interpret in real time and upon operational request any variation (well rate, watercut increase, Wax deposition evolution along the well, etc…) and take well-informed decision. This new procedure allowed to reduce drastically the time needed to integrate temperature information thanks to human interference reduction in the data transfer and data storage. Real time qualitative interpretation, thanks to real time data, allowed curative program and improving scrapping frequency leading to production gain.
In this paper, interpretation and action plan taken will be described in various conditions, such as: –Determining the contribution of main contributing layer in a single phase flow well - 90% of inflow was produced only from first 20 m out of 45 m perforated height–Identified a primary water-flooded zone after rapid water breakthrough. This zone was isolated leading to a 50% watercut decrease–Detecting water cross flow from a shallower water bearing reservoir into Kharyaga reservoir. A cross flow rate was estimated based on acquired temperature data and help designing remedial work-over. Cross-flow was successfully eliminated and the well was put on stream as producer with pure oil thanks to adequate remedial work over design
Obtained knowledge brings better understanding of the field behavior and revision of the object development strategy.
Invasion Modeling Assists in the Formation Permeability Evaluation from Resistivity Profiles and Mudcake Thickness
Authors: Makarov Alexander , Eltsov Igor 
Published: October 2012

Abstract
An invaded zone forms when mud filters into a permeable formation during and after drilling. The mud filtration process is affected by mudcake buildup, well pressure overbalance, and mud properties. Mud invasion changes the spatial distribution of resistivity in the near-wellbore zone – data that could be estimated from inverting the results of resistivity logging data. Invasion simulation can be used to predict invasion depth, mudcake thickness, distribution of resistivity, and formation permeability.
This paper presents an invasion simulation algorithm developed from the Buckley–Leverett filtration model, which takes into account mudcake buildup. This algorithm is used to calculate the near-wellbore water saturation and salinity distributions. These characteristics are used for resistivity profile calculations by an Archie-type equation.
The main goal of this paper is to propose a method of mudcake data interpretation based on a mud filtrate invasion simulation algorithm. This method yields the mud filtrate volume, water saturation and salinity distribution. To verify the results, the values obtained were compared with the results of the induction log and laterolog inversion from several vertical wells. This approach increases the significance of the mudcake thickness data and illustrates the practicality of the joint interpretation of resistivity log data and the mudcake thickness (the former being highly sensitive to resistivity changes within the invaded zone).
In addition, this paper suggests a technique for evaluating formation permeability from mudcake thickness. This technique is applicable if the mudcake was not damaged during the drilling operation. The algorithm was tested and verified by the log and core data obtained at several vertical wells.
Simulation of Complex Carbonate Field: Double Media vs. Single Media Kharyaga Field Case
Authors: Khvatova Irina , Renaud Antoine , Malyutina Galia-Banu , Sansiev Georgiy , Kuzilov Igor 
Published: October 2012

Abstract
This paper presents the successive modeling solutions used to estimate the performance under primary and secondary recovery of the Kharyaga field. Kharyaga object 2 is characterized by different zones of heterogeneities and reservoir type: while platform margin is fractured and karstified, no karstic features are identified in the platform interior, transition zones seems the most complex.
To decide on further development of the field two dynamic models of the field were developed: –Double porosity-double permeability–Single porosity-single permeability.
The paper discusses advantages and disadvantages of these two approaches to predict a behavior of such a complex field. Forecast is run on these two models and the results are compared. Based on that, the conclusions and recommendations are made when it is reasonable to use one or another model for forecast.
Application of Dynamic Underbalance Perforating Technique on a Drillstem Test String in Combination with a Nondamaging Viscoelastic Surfactant-Based Fluid Loss Control Pill: Case Study from Western Siberia
Authors: Gobert K. , Pyatigorets Y. , Krunic N. , Amanov M. , Belov M. , Belova O. , Khabibullin T. , Levanyuk O. , Lungwitz B. 
Published: October 2012

Abstract
The main challenge of perforation completion is to provide communication between the wellbore and the undamaged reservoir through clean perforation tunnels. To achieve this, two key technologies were implemented for tubing-conveyed perforation (TCP) in workover wells in a mature field in Western Siberia. First, the application of dynamic underbalanced perforating achieved clean perforation tunnels, resulting in improved production. Second, the placement of a nondamaging viscoelastic surfactant-based (VES-based) pill after perforation avoided reservoir damage during the well kill operations through clean perforation tunnels.
Three wells in the mature Van-Egan oilfield were selected as candidates for the perforating project. Two wells were previously perforated with standard charges, and the third well was to be perforated across a new layer. Deep penetrating charges were used to bypass near-wellbore damage and maximize potential results. A customized TCP test string for 6 5/8-in. (168-mm) casing was implemented with two sets of gauges installed at different depths. The gauges included a downhole shut-in valve for a closed chamber test, a production valve for the inflow surge, and a fill-up valve for improved run-in-hole procedures. The TCP test string was designed to conduct a perforation inflow test to estimate post-perforation skin factor, productive zone permeability, and reservoir pressure. For the third well with 5 3/4-in. (146-mm) casing, a modified toolstring was used due to operational restrictions. After perforation, a novel, nondamaging solids-free VES-based fluid was used as a fluid loss control pill to protect open perforation tunnels during the subsequent workover operations. Several critical parameters such as permeability, bottomhole temperature, possible scale and emulsion formation, specific gravity, and stability time required were assessed to find the best pill formula for each well. This approach successfully protected clean perforating tunnels against damaging kill fluids for 3–5 days of workover operations.
Results showed negative skin values for reperforated intervals and slightly positive skin values for the new perforated interval. Improved loss control was reported after spotting the pill. Zero losses were achieved in a low-permeability reservoir; loss rate observed in the reservoir with high permeability was lowered by more than a factor of 4. Post-job production data showed an increase in oil rate of up to 2.5 fold compared with the preworkover rate.
Application of Targeted Bit Speed Technology to Directional Drilling in Buzuluk Russia
Authors: Maranuk Christopher A. , Bassarath Wendell , Abaltusov Nikolay , Groshev Vladimir F. , Zolotukhin Sergey P. , Kutlashov Anton 
Published: October 2012

Abstract
A new technology has been developed using a technique called Targeted Bit Speed (TBS) to improve drilling efficiency. Derived from a system that uses a conventional bent housing mud motor in conjunction with a measurement-while-drilling (MWD) tool, TBS technology provides advantages similar to a rotary-steerable tool, and allows for full 3D directional control, while continuously rotating the drill pipe. Steering is accomplished by modulating the fluid flow within the drillstring, creating slight oscillations in the flow rate through the mud motor. This technology takes advantage of these controlled undulations in flow rate to allow high-frequency variations in drilling parameters to control bit speed in order to steer the well in any targeted azimuth. If a planned objective cannot be achieved using TBS technology, then the motor can still be oriented in the desired direction and slid using standard mud motor-orienting techniques.
This paper will examine the field results of a multi-well project in the Buzuluk area, where the operator used TBS technology to drill S-shaped wells required to access the reservoir targets. S-shaped wells are typically the most challenging to drill with continuously rotating drill pipe and a mud motor-based bottomhole assembly (BHA) because the same tools are used to drill the curve, hold the tangent, and drop the angle. This single BHA concept was not feasible before the introduction of this technology. This paper will focus on the improvements achieved in not only directional control but also in the resultant rate of penetration (ROP) by using the new system.
This project constituted the first wells drilled in the Eastern hemisphere using TBS technology.
The Use of Artificial Bayesian Intelligence in Practical Well Control
Authors: Al-Yami Abdullah S. , Schubert Jerome 
Published: October 2012

Abstract
Many well control incidents have been analyzed, resulting in the optimum practices, as outlined in this paper. The objective of this paper is to propose a set of guidelines for the optimal well control operations, by integrating current best practices through a decision-making system based on Artificial Bayesian Intelligence.
Best well control practices collected from data, models, and experts' opinions, are integrated into a Bayesian Network to simulate likely scenarios of its use that will honor efficient practices. When dictated by varying operation, kick details, and kick severity. The proposed decision-making model follows a causal and an uncertainty-based approach capable of simulating realistic conditions on the use of well control operations. For instance, by varying the operation, the system will show the kick indicators for that particular operation. Also in the same model as the user vary the operation, rig and crew capabilities, kick details (such as slim hole, deviated or horizontal well), the system will show the optimum practices for circulation method and shut in method. The model also shows optimum practices for blowout control by varying the un-controlled kick type (surface, subsurface or underground blowouts). Recommended practices after controlling the well are shown by the same operation that caused the well control incident and by varying the potential reason for the incident.
Two well control experts' opinions were considered in building up the model in this paper. The advantage of the artificial Bayesian intelligence method is that it can be updated easily when dealing with different opinions. The outcome of this paper is user-friendly software, where you can easily find the specific subject of interest, and by the click of a button, get the related information you are seeking. Field cases will also be discussed to validate this work.