bluuebunny/crossref_metadata_2025_split huggingface dataset:
High-Performance Freshwater Flocculating Drilling Fluid Helps to Increase Efficiency of Extended Reach Drilling Operations and Cut Costs on Uvat Oilfield
Authors: Samarskiy A. G. , Gasparov S. A. , Terentiev V. M. , Terentev A. G. , Samyshkin S. Y. 
Published: October 2008

Abstract
The traditional drilling fluid of choice in West Siberia is a potassium chloride (KCl) low-solids nondispersed polymer system. The use of KCl has been justified by the need to inhibit smectite-rich clays in the Tertiary and Cretaceous formations. KCl inhibits clay swelling and coagulates dispersive clays and does not impair the rheological and filtration characteristics of a polymer water-based drilling fluid. However, there are a number of concerns about the use of KCl in drilling operations. KCl is used in relatively high concentrations (up to 210 kg/m³), requiring significant logistical resources for delivery and handling of the material, especially on remote ice-road locations. High potassium and chloride ion concentrations can also be considered to be hazardous to the environment.
In recent years, regulators and operators have searched for a more environmentally, operationally, and logistically acceptable water-based mud (WBM). This has resulted in the introduction of a new generation of freshwater-based high-performance drilling fluids (Stawaisz et al. 2002). These fluids rely on polymers for clay flocculation instead of KCl. The use of a flocculating high-performance water-based fluid (HPWBF) in the Uvat Field has allowed significant reduction in fluid volumes, fluid cost, and drilling time, as well as helped to reduce logistical costs and control problems such as downhole losses, hole instability, and drilled solids contamination.
Application of Stochastic Prospect Analysis for Shale Gas Reservoirs
Authors: Harding Nathaniel R. 
Published: October 2008

Abstract
The principles of statistical analysis are well-established, but the development and practical application of scalable stochastic shale gas prospect analysis has remained elusive. Development of this integrated software package stemmed from a desire to quantify risk and uncertainty and create a universal program to easily do so for future prospects. An Excel model with Crystal Ball overlay was used for this design. This analysis is both easily implemented, and operates with the seamless addition of scalable Monte Carlo modeling.
Commercial production is a primary uncertainty in unconventional plays. Deterministic solutions do not reflect the uncertainty associated with input assumptions. This discussion presents a stochastic assessment program to evaluate the full range of commercial realization potential. The distinctive aspect is the use of stochastic simulation to calculate the risks of failure and the uncertainty of success for any or all project stages on the basis of subsurface and surface activity performance, cost and duration uncertainties. Land divestitures or acquisitions, monetization, seismic, etc may be modeled.
The results present economic, production, reserves and other performance indicators consistent with commercial software applications, with the additional insight of quantified statistical success uncertainty and failure risk, yielding probabilistic results with associated degrees of confidence. Further work is required to adapt this method for oil reservoirs, and to model tax structures outside of the US. Project-level application is illustrated using a case study from a US shale gas resource play.
This original analysis enables real-world, universal, repeatable application of well-established but theoretical stochastic prospect analysis. Practical application is now possible in-house, and is therefore user-friendly and customizable. Both inputs and outputs will be familiar to any engineer who uses commercial economic analysis software. Most of all, the ability to test the uncertainty of any input or output for any or all project stages grants unparalleled flexibility.
Evolution of Hydraulic Fracturing in Russia
Authors: Pongratz R. , Kuvshinov I. K. , Latkin K. E. 
Published: October 2008

Abstract
Before the mid-1990s, the main goal of hydraulic-fracturing operations in Russia was preventing near wellbore damage. Typical fracturing treatments used a crosslinked polymer-based gel as carrier fluid to place 5 to 20 MT of proppant into the formation. Because of the results, a new phase started, whereby "real" production enhancement treatments achieving skins of well beyond −4 were pumped with proppant volumes from 50 to over 100 MT. Because of Russian oil production practices at the time, it became apparent that the hydraulic fracturing technology combined with drilling horizontal wells increased production and was therefore beneficial to the Russian economy.
When the optimization process started, quality control in the field became mandatory in addition to an enhanced focus on health, safety and environment. Service companies focused on cleaner fluids with less polymer loadings and better breaker systems. Prejob, on-the-job, and postjob quality control procedures were developed specifically for the Russian environment and reached a standard unlike anywhere else in the world. The number of unwanted screenouts was reduced significantly by following proper perforating practices and optimizing the treatments designs in real time. The new goal was a skin of −5, and the design process was optimized to achieve this number by designing each job to achieve optimum production for the given reservoir parameters, especially permeability. Treatments of 300-400 MT are not uncommon these days for low permeability reservoirs with a large reservoir height sometimes covering several zones.
This lead to the optimization process that is currently practiced. Because many sandstone reservoirs, particularly in Siberia, are laminated, the vertical permeability is often an order of magnitude or more lower than compared to the horizontal permeability. Several times, horizontal wells did not yield the expected results. Hydraulic fracturing treatments placed in the horizontal wellbore can be the solution for further production optimization. This paper describes how this can be established through several techniques.
Hydraulic fracturing includes propped hydraulic fracturing in both oil and gas reservoirs, as well as carbonate fracture acidizing. This paper discusses propped hydraulic fracturing in oil reservoirs. Covering propped hydraulic fracturing in gas reservoirs, although still at the beginning stages, could reveal enough material for a paper on its own. However, carbonate fracture acidizing is not frequently used.
Testing and Design of Hydraulic Fractures in Tight Gas Formations
Authors: Soliman M. Y. , East Loyd , Ansah Joe , Wang Hong (Max) 
Published: October 2008

Abstract
Productivity of a tight gas formation is strongly tied to flow area. This fact dictates the creation of enhanced flow area through drilling of multi-lateral wells and/or fracturing.
In the case of fracturing, loss of fracture conductivity near the wellbore can have a drastic and negative effect on the productivity of a fractured well. This is especially true when creating a transverse fracture to intersect a horizontal well. In tight formations, loss of communication between the fracture and the formation could also have a devastating effect on productivity of the well, vertical or horizontal.
In this paper, the following will be discussed:
The effect of completion methodology on productivity of a tight gas formation The effect of near-wellbore damage of fracture conductivity on productivity of a fractured well in a tight gas formation The effect of creating multiple fractures on the productivity of wells Testing a previously fractured well using an injection falloff test, or a pressure buildup test to determine the degree of damage (DED) and depth of damage (DOD) of the fracture conductivity
A Field-Proven Methodology for Real-Time Drill Bit Condition Assessment and Drilling Performance Optimization
Authors: Salakhov Tagir R. , Yamaliev Vil U. , Dubinsky Vladimir 
Published: October 2008

Abstract
The primary objective of the proposed method is to evaluate the current conditions of the drilling system and suggest modifying values of main drilling control parameters to optimize the efficiency of the drilling in whole, while reducing the probability of premature wear of the drill bit.
The fundamental theory behind the proposed approach is based on some elements of fractal analysis as well as artificial neural networks (NN). Many different complicated multi-parameter systems, including drilling systems, frequently discover scale invariance, or "fractality" of spatial-time properties. On this basis, some common engineering approaches to modeling and diagnostic methods have been developed and used.
In our case, the "system" consists of the drilling components (e.g., surface equipment, drillstring, drill bit, mud, etc.), as well as the formation being drilled. Drilling control parameters include both the parameters adjustable in real-time, such as hook load, RPM, or mud flow rate, as well as those that can be modified with some delay (e.g., mud properties or configuration of the bottom-hole assembly).
We consider specific examples of operational situations accompanying the drilling process, in which the fractal performances’ application allows receiving important practical information during a standard operation, i.e., without carrying out a special controlled field experiment.
We present some field examples that we used for gathering required data, training our model, and making an assessment of the current state of the system (specifically, the drill bit conditions) by using the proposed methodology. We also present the results of monitoring the system's response to specific adjustments of control parameters’ values for these cases.
We believe that the proposed methodology opens new opportunities for real-time drilling optimization that can be efficiently implemented within the scope of the existing drilling practice.
Oil Production and Water-Cut in Naturally-Fractured Vuggy Reservoirs
Authors: Li Yangfan , Lin Tao , Li Xinyong , Liu Bo , Ren Xianghai , Li Kewen 
Published: October 2008

Abstract
Naturally fractured oil reservoirs with vugs of size over 5 meters in diameter are few in the world. We developed a method to correlate the decrease in oil production and the increase in water cut. Production data from Tah oil reservoir (China) with big size vugs and high-density fractures were used to test the approach. It was found that the oil production decline and the water cut increase were coupled closely in many wells from this naturally fractured vuggy oil reservoir. The oil production was characteristic of rapid decline and the water cut was characteristic of sharp increase right after water breakthrough in many oil wells. An idea of shutting off water before water enters the production zone was proposed to reduce the decline rate of oil production and the increase in water cut. This approach of water shut off has many advantages compared to the routine measures which are usually taken after water cut is already great.
Technical, Economic and Risk Analysis for a Multilateral Well
Authors: Arcos D. , Zhu D. , Bickel E. 
Published: October 2008

Abstract
Multilateral well technology is considered a development strategy as the oil and gas industry is increasingly approaching more hostile environments. It remains attractive to maintain efficient exploration of oil and gas fields in order to maximize profitability with minimum uncertainty. Some of the non-conventional oil and gas reservoirs currently being drilled are characterized by significant heterogeneity, tight and naturally fractured, faulted/compartmentalized, heavy oil and, depleted reservoirs/mature development. However, sometimes the high risk involved accompanied by economic disadvantages have diminished the ability of multilateral wells to maximize access to reserves without incurring higher development costs.
The objective of this study is to develop a methodology to assist engineers in their decision making process of maximizing access to reserves. The process encompasses technical, economic and risk analysis of various alternatives in the completion of a well (vertical, horizontal or multilateral) by using a well performance model for technical evaluation, and a deterministic analysis for economic and risk assessment.
In the technical part of the decision making process, the flow rate for a defined reservoir is estimated by using a pseudo-steady state flow regime assumption. The economic analysis departs from the utilization of that flow rate data assuming certain pressure decline. Financial Cash Flows (FCF) are generated to measure the economic worth of investment proposals. Net Present Value (NPV), Internal Rate of Return, Profitability Index and payback period are the main economic yardsticks used in the analysis.
Last, a deterministic decision tree is used to represent the risks inherent in geological uncertainty, reservoir engineering, drilling, and completion for a particular well. The NPV generated from the economic analysis is used as the base economic indicator. In addition, the risk associated at each stage of the project is considered with an assigned probability. By selecting a type of well that maximizes the expected monetary value (EMV) in a decision tree, we can make the best decision based on a thorough understanding of the prospect.
The method introduced in the paper emphasizes the importance of a multi-discipline concept in drilling, completion and production technology. The examples presented in the paper will assist geologists, geoscientists, engineers, and managers in collaborating together in a development project.
Unique and Successful Recompletion of Well Kumkol South 1005, Kazakhstan
Authors: Yermakhanov U. , Louviere W. T. , Qingguang Q. , van Gijtenbeek K. 
Published: October 2008

Abstract
The Kumkol South 1005 well was originally drilled and completed in the Cretaceous formation at a depth just above 1100 meters with a 168-mm casing. After watering out, the Cretaceous perforations were squeezed off and the well was deepened to the Jurassic sands with an 89-mm liner set to isolate the upper formation. The well was then completed as a producer in the upper Jurassic formation.
The recompleted well was considered to be a good candidate for a hydraulic proppant fracturing treatment. However, although the liner overlap of the 89 mm into the 168-mm casing had been pressure tested after being cemented in, there was still concern that the applied pressure during a fracturing treatment could result in communication with the Cretaceous formation, which is a formation with a very high water-production rate.
The liner overlap was pressure isolated using a specially constructed mandrel with seal elements identical to what was being used at the end of a wellhead isolation tool. This assembly was run below a retrievable packer assembly. This unique pack-off allowed the Jurassic formation to be successfully treated by means of a hydraulic proppant frac without establishing any communication with the Cretaceous formation. This procedure has been successfully used on several other similar deepened wells in the same field.
Use of Representative Models to Improve the Decision Making Process of Chemical Flooding in a Mature Field
Authors: Costa Ana Paula A. , Schiozer Denis J. , Moczydlower Priscila , Bedrikovetsky Pavel 
Published: October 2008

Abstract
Decision analysis applied to petroleum field development is always strongly related to risk due to uncertainties in the process. An important part of risk evaluation can be accomplished through the evaluation of the impact of uncertainties in the performance of the petroleum fields, yielding higher possibility of success, quantification of possible losses, minimization of sub-optimal development and identification of opportunities.
The objective of the present work is to use the quantification of the impact of uncertainties related to chemical flooding (injection of Alkali-surfactant-polymer) using the concept of Representative Models (RM) integrated with economic uncertainties to improve the production forecast in a Brazilian onshore field with 19 years of production history. The main advantage of this process is to provide a few adjusted models (RM) which are selected based on the integration of objective functions previously defined to the context to represent these uncertainties. These RM are selected to represent all combined models which compose the distribution curve (risk curve) of the process. The distribution curve is obtained through the concept of derivative tree technique, combining the possible scenarios using the numerical simulation to predict the reservoir behavior. The numerical simulation is used to give more reliability to the process and to give a detailed analysis for each model in order to provide integration with economic analysis which is used in the risk mitigation. The importance of this process is to provide a detailed analysis of the impact of the chemical injection in the decision making process. An automated tool and the utilization of a defined methodology to quantify the impact of uncertainties are used to speedup the process and to improve the viability of the procedure with a significant reduction of time and effort, yielding greater reliability of the production forecast with the improvement of the decision making process.
Field Validation Processes for Multiphase Wet Gas Surface Well Testing Solutions: Example from the Yamburgskoe Arctic Gas Condensate Field, Russia
Authors: Theuveny B. , Shumakov Y. , Zhandin A. , Zinchenko I. 
Published: October 2008

Abstract
Surface welltesting of Gas-Condensate with multiphase flowmeters is still considered a challenge for production metering. Traditional means of well testing have been deployed for years and used consistently for reservoir and production management. However, it can be difficult to compare data sets obtained with different measurement devices.
Multiphase flow meters have been proved for multiphase production metering by many operation companies worldwide. However, in artic environmental conditions like those of Yamburgskoe gas-condensate field, with low ambient temperature and production rate regulation restrictions, this process had to be revalidated and the operational capabilities confirmed with all of the logistical challenge of this environment. A number of recommendations to prevent and mitigate the impact of the hydrate and document major benefits of multiphase well testing are based on the accumulated operational experience from the operations of various multiphase flowmeters in the area.
Most of the gas condensate wells in the Yamburgskoe gas-condensate field are flowing with liquid unloading issues in a slug flow regime that can be observed and monitored accurately with multiphase flow meters. The importance of slug flow regime identification relates to the selection of stable flow intervals for surface sampling and further recombination factor determination. This information is also extremely important for well completion design. There is good agreement between the slug frequencies obtained with nodal simulations and the actual dynamic measurements from the meter - an impossible task for conventional measurements based on separator or batch processing of the liquid.
Surface well testing to control changes of reservoir parameters, PVT composition, and production back-allocation performance is one of the key parts of gas-condensate field development in Russia. A number of multiphase welltesting operations have been successfully performed recently that show acceptable performance capability and the benefits of this methodology compared to the parallel production measurement with a traditional gas separator. This novel comparison and qualification process of multiphase flow meters also provides a better understanding of the aptitude of conventional means to collect rate in the case of wet gas wells in Northern Siberia.
TELEMEDICINE in O&G Industry: Our Experience
Authors: Mortara S. , Uberti F. , Gomez G. 
Published: October 2008

ABSTRACT
The activities in Oil & gas industries have always been developed in remote and isolated locations especially in countries where health and hygiene conditions are very poor with difficult access to the advanced medical resources.
The constant development of communication systems allows the implementation of technological resources that maintain the communication between these remote locations with the most advanced hospitals, crossing the world in seconds and providing accurate diagnosis and guidelines for treatments.
Several solutions can be found on the market to help the physician to communicate with a colleague: all of them are valid in specific situations. We will firstly distinguish between vertical and horizontal solutions.
"Vertical" relates to platforms dedicated to medical tele-consultation in individual speciailties: teleradiology, tele-cardiology, tele-pathology, tele-dermatology.
"Horizontal" solutions: All systems that can manage any kind of medical data are grouped under this category: Telephone and fax; Videoconferencing (VC) systems and E-mail messages
The technological and organisational activation of the requesting health centres is a critical factor of success, from the technological viewpoint, a dominant element is connectivity.
Our tele consultation system has been utilised to date by Eni in remote places has provided:
– Support to the doctor with the diagnosis and treatment of routine complaints; – High quality medical assistance in more difficult remote sites, thereby contributing to improve the living conditions of expatriates and local employees; – New approach to handling emergencies, so as to reduce the number of assisted repatriations; – General improvement of healthcare in remote areas.