bluuebunny/crossref_metadata_2025_split huggingface dataset:
Placement Using Viscosified Non-Newtonian Scale-Inhibitor Slugs: The Effect of Shear Thinning
Authors: Sorbie K. S. , Mackay E. J. , Collins I. R. , Wat R. 
Published: December 2007

Abstract
Reservoir formations are often very heterogeneous and fluid flow is strongly determined by their permeability structure. Thus, when a scale inhibitor (SI) slug is injected into the formation in a squeeze treatment, fluid placement is an important issue. To design successful squeeze treatments, we wish to control where the fluid package is placed in the nearwell reservoir formation. In recent work1, we went "back to basics" on the issue of viscous SI slug placement. That is, we re-derived the analytical expressions that describe placement in linear and radial layered systems for unit mobility and viscous fluids. Although these equations are quite well known, we applied them in a novel manner to describe scale inhibitor placement. We also demonstrated the implications of these equations on how we should analyse placement both in the laboratory and by numerical modelling before we apply a scale inhibitor squeeze. An analysis of viscosified SI applications for linear and radial systems was presented both with and without crossflow between the reservoir layers.
In this previous work, we assumed that the fluid being used to viscosity the SI slug was Newtonian1. However, the question has been raised concerning what the effect would be if a non-Newtonian fluid was used instead. We mainly consider the effect of shear thinning although our analysis is generally applicable if the non-Newtonian flow rate/effective viscosity function is known. We address the questions: (i) Does the shear thinning behaviour result in more placement into the higher or lower permeability layer (in addition to the effect of simple viscosification)? (ii) Can the shear thinning effect be used to design improved squeeze treatment?
Application of the SAGD to an Iranian Carbonate Heavy-Oil Reservoir
Authors: Sola B. Sedaee , Rashidi F. 
Published: December 2007

Abstract
Steam injection is the most important thermal enhanced oil recovery; while in this method Steam-Assisted Gravity Drainage (SAGD) is a very promising recovery process to produce heavy oils and bitumen. The method ensures both a stable displacement of steam and economical rates by using gravity as the driving force and a pair of horizontal wells for Injection/production.
SAGD in Sandstone heavy oil Reservoirs has been characterized quite well over the last years. However, there is huge carbonate heavy oil reserves in the world which their production can be enhanced by thermal recovery processes, especially by steam injection.
In this study, Application of SAGD to an Iranian heavy oil carbonate reservoir with low matrix permeability has been investigated. Field-Scale 3-D and simulation models were constructed by using commercial softwares and by thermal simulators to investigate SAGD performance in this reservoir.
The model was further applied to a fractured system and effects of fracture and matrix permeability, Vertical well spacing between producer and Injector and Length of the horizontal section of the injection well on the performance of SAGD process were studied. By comparison with other thermal methods results showed that SAGD can be used as a better EOR method for this heavy oil carbonate reservoir.
Simulating Chemical Placement in Complex Heterogeneous Wells
Authors: Stalker R. , Graham G. M. , Wahid F. 
Published: December 2007

Abstract
Chemical Placement for scale inhibitor squeeze and other near wellbore chemical treatments is recognized as a significant challenge in today's ever more complex operating environments. For heterogeneous wells and long reach horizontal wells, various factors (including heterogeneity, crossflow and pressure gradients between non-communicating zones within the well) all contribute to uneven placement in the reservoir. Current methods to circumvent these problems often rely on extremely expensive coiled tubing operations, staged diversion (temporary shut-off) treatments or overdosing some zones to gain placement in other (e.g. low permeability) zones. For other very near wellbore treatments e.g. acid stimulation, a number of self-diverting strategies have been applied in field treatments with some success. Unfortunately, the properties which make such treatments applicable for acid stimulation may also make them inappropriate for scale squeeze treatments. Other modified lightly viscosified fluids have however been demonstrated to be of significant importance for improving chemical placement thereby reducing the potential for low permeability/high pressure zones being rapidly denuded of chemical during flowback.
Critical to our understanding of such a process is the ability to accurately simulate the effectiveness of such treatments in the laboratory and to use the data to build and validate more effective modelling tools to allow field treatments to be designed. The paper examines the potential benefits of using modified injection fluids, including lightly viscosified and shear thinning fluids to aid uniform scale inhibitor placement in complex wells. Laboratory data using dual linear core flood experiments coupled with mathematical modelling are used to describe cases where such fluids are shown to offer benefit for field application and also those where more minimal benefit would be anticipated, such that the risks associated with the use of modified fluids (e.g. potential formation damage and fines mobilization) would outlay the benefits. The paper therefore describes the effective use and interpretation of detailed laboratory core flood data, mathematical modelling and field evidence to describe the benefits associated with the application of modified lightly viscosified shear thinning fluids in scale inhibitor squeeze treatments.
Using Petrophysical Data to Differentiate A Separate Water Bearing Zone From A Water Level
Authors: Revett L. , Ayeni B. , Farshad F. , Hayatdavoudi A. 
Published: December 2007

ABSTRACT
Hydrocarbons, because of buoyancy, routinely accumulate in the upper portion of originally water-wet sands. Consequently, many petroleum engineers interpret any water bearing zone immediately below as the water level in that sand. However, petrophysical interpretation of the well data may reveal a more rapid water desaturation than is commensurate with the given permeability and pressure conditions of that interval. This condition is indicative of an apparent oil-water contact or pseudo water level rather than the true (free) water level. This can only exist when there is an interruption in the vertical permeability between the oil bearing zone and the water bearing zone.
Higher displacement pressures can be developed above a permeability barrier, which would cause a more rapid water desaturation of the sand than is physically possible for that distance above a true (free) water level. This paper outlines methods of determining whether continuous vertical permeability exists to the water level.
Corrosion Investigation and Prevention of Diesel Tail Gas Underbalanced Drilling
Authors: Wan L. , Meng Y. , Li Y. , Yang L. 
Published: December 2007

Abstract
Diesel tail gas drilling belongs to gas-based underbalanced drilling technology owning the advantages of protecting oil/gas reservoir and improving rate of penetration. Due to complex composition, especially containing carbon dioxide, oxygen, and erodible solid particles, diesel tail gas can give rise severe corrosion to drilling pipes and air compressor valve plates. The corrosion effect of temperature, total pressure and flow velocity on S135 drilling pipe steel and 13 chrome stainless steel were investigated simulating corrosion environment of diesel tail gas. The image and composition of the corrosion product were analyzed by the surface analysis means as scanning electron microscope, X-ray diffraction and so on. The results indicate corrosion rate of dynamic liquid phase exceeds that of dynamic gas phase, S135 steels corroded more badly than 13 chrome stainless steel, at the first the corrosion rate increasing and then decreasing while enhancing temperature, and improving with total pressure or flow velocity rise. Field experience and laboratory test indicate that hereinafter measures should be adopted to protect drilling tools and compressor valve plates from corrosion failure such as improving material quality, modifying tools structure, perfecting environment, also strengthening management and maintenance.
Underbalanced drilling technology on diesel tail gas is used successfully in Well Xing 24. The diesel tail gas drilling is unsuitable for watered gas well and high pressure gas well.
This paper is the first in a series of studies designed to investigate corrosion of diesel tail gas. The goal is to better understand the advantages and disadvantages of diesel tail gas drilling technology, to be able to select the proper corrosion control and extend diesel tail gas underbalanced drilling in suit region.
Our Water Chemistry Contains Organic Acids—So What Does It Mean?
Authors: Durnie W. , Harrop D. 
Published: December 2007

Abstract
The enhancement of brine corrosivity due to the presence of acetate (or anions of other weak acids) in CO2 containing waters has been discussed frequently in recent literature. It has been confirmed that the observed increase in corrosivity is related to the equilibrium concentration of undissociated acetic acid (HAc) in the water and this in turn can be determined via solution speciation calculations – providing the composition of the water is known.
As with all weak acids (and regardless of the in-situ pH), organic acids will be present in both their undissociated form and dissociated form (anions) and since propionic and butyric acids essentially share the same pKa as acetic acid, their molar concentrations can be typically summed under the generic name of the dominant species, i.e., acetate ions (Ac-) and acetic acid (HAc).
This paper discusses the implications of significant levels of organic acids in produced waters (&gt; 1mM) with regards fluid corrosivity. Specifically, how can we account for this in corrosion prediction modelling, as well as ensuring any testing programs conducted correctly reflect the water chemistry and speciation? Our approach to water speciation calculations and subsequent use of this will be discussed in relation to a specific example. The rate of corrosion is not determined solely by solution composition, however, we can’t understand or estimate the corrosion rate without considering the solution speciation.
Alternative Approach to Internal Pipeline Condition Assessment
Authors: Oliver K. E. , John D. G. , Crossland A. 
Published: December 2007

Abstract
Life extension of fields due to enhanced recovery methods and the development of increasingly remote resources has resulted in pipelines being used in very different circumstances to those for which they were designed. There are often large discrepancies between the current operating envelope and the original design conditions. Extension of field life has resulted in pipelines carrying changing fluids compositions beyond the original design life. In order to ensure future integrity of these pipelines, all of these changes in operation need to be assessed/reported and a full understanding of current condition of the pipeline defined. A good appreciation of current conditions, together with future operating conditions and therefore the likely internal corrosive condition of the pipeline can enable forward predictions on pipeline life to be estimated.
This paper give details of an uncertainty based probabilistic approach that enables the internal corrosivity of a pipeline to be assessed under varying operating conditions. This approach enables the risks associated with future maintenance options to be quantified.
Stringent Quality Control and Quality Assurance Process: Key to Successful Fracturing Treatments in Western Siberia
Authors: van Gijtenbeek Klaas , Pavlyuchenko Valentina , Rudnitsky Andrey , Pongratz Reinhard 
Published: December 2007

Abstract
Hydraulic fracturing has probably become the most attractive solution to enhance production in the oil fields of Russia and western Siberia in particular. Besides optimizing the fracturing design with the ultimate goal of increased production, it is equally important that optimized fracturing treatments be pumped successfully in the field. Only a high success rate with a limited number of screenouts can help guarantee that production optimization will be achieved. It is also important to reduce downtime, for operators to have earlier production, and for service providers to optimize equipment utilization.
In western Siberia, harsh conditions exist all year round. The winters are long with temperatures way below freezing for several months in a row. The summers are short, but can be quite warm. Logistics are difficult due to these weather conditions and because roads are rarely in good shape and worksites may be located very far away from equipment bases. To achieve success under these conditions, a lot of emphasis must be placed on quality control (QC) and quality assurance (QA). QC/QA must address many issues on the equipment side due to the harsh environment, but just as important is materials, in particular materials required for preparing the frac fluid and to a smaller extent the proppant used to hold the fractures open.
The frac fluid itself creates the biggest QC/QA challenge. Of special importance is the mixing water because the sources for mixing water vary and the quality of the water changes seasonally. Stringent QC/QA procedures must be in place, including fluid testing under actual reservoir conditions to check the performance of the frac fluid downhole.
This paper describes processes that have been developed and implemented in western Siberia. It includes equipment checks and maintenance as well as QC/QA procedures for frac fluids and their components and proppants. Specific issues related to the special location will be discussed and solutions presented regarding how a successful frac treatment can be provided every time.
Review of MEOR Technology Application in Dagang Oilfield for the Last Decade
Authors: Feng Qing-xian , Ni Fang-tian , Qin Bao-yan , Ma Xian-ping , Ji Chao-feng , Wang Xiao-lin 
Published: December 2007

Abstract
MEOR, particularly indigenous MEOR technology, has been studied extensively in Dagang Oilfield, China, since early 1990s. Based on lab study results, pilot tests were conducted in four different reservoirs (in the Gangxi, Gangdong, Wang-guantun and Kongdian oilfields). In total 24 injection wells and 55 production wells were involved in tests with responses observed in 47 wells.
For MEOR, a series of microbial species, which were suitable to target reservoirs, were developed using produced fluids. The process included separation, culture, and special domestication, contributing to improved oil properties and producing surfactants, emulsion and gas. Core experiments in lab showed that, comparing to waterflooding, microbial flooding could increase the recovery rate by 6-8%. Field tests indicated the cumulative incremental oil production 28,000 tons from the reservoir at 54 to 73°C. One in the tested fields had already been flooded by polymer solution.
Considering the limitation of microbial species variability, match of culture with formation water, numerous of fermentation surface and injections, it was determined to develop indigenous MEOR. This process provided better effectiveness at 60°C. The test results showed improved ecosystem and increased oil production of over 31,000 tons with water cut decreased by 5% at average.
Our study and field tests for microbial flooding showed that reservoir temperature was the most important factor and then microbial nutrients and production pattern follow.
Analysis of Productivity Reduction Due to Non-Darcy Flow and True Skin in Gravel-Packed Wells
Authors: Himmatramka Alok K. 
Published: December 2007

Abstract
Low productivity in oil and gas completions may be attributed to mechanical causes as well as formation damage and/or low formation capacity. Various techniques are available in the industry literature which provide a means of distinguishing pressure losses due to non-darcy flow from pressure losses due to true skin. Jones, Blount, and Glaze1 have presented a procedure using production tests to determine the contribution made by turbulence and all other rate-dependent deviations from darcy flow in reducing a well's productivity. Analyses of transient pressure data measured in conjunction with production tests on a number of gravel-packed gas and oil wells in a field in the Gulf of Mexico support the usefulness of this analytical procedure as a significant means of pinpointing the reasons for low productivity. This enables the engineer to select the appropriate stimulation or remedial workover most likely to improve a well's reduced productivity.
Predicting the Distribution of Thin Bed Reservoir by Broad Frequency Band Seismic
Authors: Li Zishun , Cui Baowen , Guo Xuebin , Wei Xuerui , Mu Jiandong , Qiao Yanguo 
Published: December 2007

Abstract
Aiming at the problem of thin bed recognition in the thin interbed reservoir of the middle-shallow strata in the Songliao Basin, the broad frequency band and ultra high resolution seismic processing technique is studied. After the technique being applied in 3D seismic area of Zhaoyuan in the northern part of Songliao Basin, the seismic resolution increases 2-3 times compared with conventional seismic. It is known that characteristic of AVF is existed in seismic reflection through analyzing broad frequency band and high resolution seismic data and understanding characteristic of amplitude and frequency tuning effect of which originates from thin bed reservoir seismic reflection wave, two methods are given. One is that thickness of thin bed reservoir is calculated by AVF analysis, the other is that the distribution of thin bed reservoir is predicted by using proper broad frequency band and high resolution seismic. Through the fine contrast between seismic and wells data, the top and bottom interface of the F-2 pay zone are made sure. According to the results of seismic interpretation, the technique of seismic attributes extraction along stratum interface and 3D visualization technique are used to predict the horizontal distribution of reservoir on the F-2 pay zone. Taking the prediction result as basis, the applications on optimizing the location of the exploration wells, optimizing the zone of production test and analyzing the continuity of pay zone between the production wells are studied. They demonstrate the advantage of the high resolution seismic in the thin interbed reservoir prediction and the seismic recognition of lithologic reservoir.
Determination of the Zone of Maximum Probability of Asphaltenes Precipitation Utilising Experimental Data in an Iranian Carbonate Reservoir
Authors: Hamid K. 
Published: December 2007

Abstract
Asphaltenes precipitation is one of the major operational problems affecting oil production in the Bangestan reservoir in south of Iranian fields. Precipitation of asphaltenes in reservoirs, wells and production facilities can have severe detrimental impact on the economics of oil production because of a reduction of well productivity and/ or clogging of production facilities. A field methodology based in the influence of pressure in asphaltenes precipitation has been designed and implemented to estimate the zone of maximum probability of asphaltenes precipitation. Nodal analysis is applied to determine pressure versus depth behavior at the well for different operational conditions. Knowing the saturation pressure and the flocculation onset pressure, the methodology allows the determination of the most probable range of depth at which asphaltenes precipitation will occur. The purpose of this methodology is determine the optimum operational conditions that maximize production at minimum risk of asphaltenes precipitation, as well as to select the better preventive measure for each particular case, thus maintaining overall control of the asphaltenes plugging problem. In this paper, field applications of the methodology are shown. Depending on the depth range of asphaltenes precipitation occurrence, reperforation of the producing interval, hydraulic fracture is recommended.
Studies on Less Expansive Environmentally Safe Polymers for Development of Water-Based Drilling Fluids
Authors: Sharma V. P. , Mahto V. 
Published: December 2007

Abstract
Recently there has been lot of interest and research activity started in the development of new products and combinations for the development of ecofriendly drilling fluids using chemicals, which are less toxic and biodegradable materials. In this work, an attempt has been made to develop water based drilling fluids using Indian bentonite clays and new ecofriendly polymers, which has been found to be cheaper than the conventional polymers used in oil well industry. The tamarind gum and tragacanth gum, which are not used in water based drilling fluids, had been found suitable. This has been confirmed by doing experiments using standard procedure adopted by oil industry. The temperature stability of drilling fluid additives was studied using Hot Air Rolling Oven and Aging Cells. The formation damage was carried out using oil field core samples on Ruska liquid permeameter. The laboratory investigation furnishes that combinations of these polymers and bentonite have favorable rheogical properties with less formation damage.
Fighting Against Non-Unique Solution Problems in Heterogeneous Reservoirs Through Numerical Well Testing
Authors: Shi-Yi Zheng 
Published: December 2007

Abstract
Numerical well testing started in about a decade ago. The technique was developed to tackle well testing problems in heterogeneous reservoirs. Integration of geoscience and well testing for improved fluvial reservoir characterisation was the first project of this kind supported by the oil industry that time. When approaching non-unique solution problems in heterogeneous reservoirs, the traditional analytical approach based on the ideal reservoir conditions failed. An option to get an approximate solution for the problem is to solve the non-linear pressure diffusivity equation through well test numerical modelling and simulation. Well test analysis and interpretation conducted on this basis is called numerical well testing. This technique has been proved, through study and research in the past few years, to be an effective way to solve the problems not only for single phase flow in heterogeneous formation, but also for multi-phase (heterogeneous fluid properties) flow in heterogeneous formation.
This paper will present study result and new development in numerical well testing in recent years. These are based on research and studies from a number of M.Sc. and M.Phil. projects at Heriot-Watt University. Due to the continuous support from the oil industry since the fluvial reservoir characterisation project, numerical well testing has been extensively conducted in the Institute of Petroleum Engineering at Heriot-Watt University. This technique has been used to tackle well testing practical problems as well as for academic research. There will be five aspects to be covered in this paper. These are: Numerical well testing forward modellingNumerical well testing for reservoir model calibrationNumerical well testing for future production forecast (well test design)Numerical well testing for reservoir monitoringNumerical well testing in heterogeneous reservoir saturated with heterogeneous fluids (multi-phase, e.g. gas-condensate reservoirs)
Case studies and filed examples selected for this paper will be used to demonstrate procedures; methods developed and illustrate field applications.