bluuebunny/crossref_metadata_2025_split huggingface dataset:
Fiber-Based Fracture Fluid Technology a First for Oil Reservoirs in Western Siberia
Authors: Oussoltsev D. , Butula K. K. , Klyubin A. , Gayfullin Albert , Senchenko Dmitry , Fayzullin Ildar 
Published: February 2008

Abstract
Successful hydraulic fracturing in various "risky" oil reservoirs has been the biggest challenge for fracturing engineers in the Western Siberia basin, as a significant number of the oil-bearing formations in the basin are located near a water zone. These hydraulic fracturing difficulties created a niche for technologies that offer fracture-geometry control without sacrificing proppant-pack conductivity.
The conventional approach is based on net pressure control. This can be achieved using low-viscosity fluids, such as viscoelastic systems, oil-based systems or reduced polymer systems. The fluid systems can then further be pumped as linear gel pad stages with cross-linked proppant stages with or without the use of materials for fracture height-growth control (HGC). The Yaraynerskoe oilfield case study documents the fiber assisted fracturing fluid technology used with HGC materials as a significant improvement in HGC solution. This technology combination additionally enhances fracture placement success.
As the treatments significantly differ from the regular fiber assisted application in tight gas formations, a series of experiments had to be performed to ensure full compatibility with formation fluid, resin-coated proppants, and treating fluids.
Characteristics such as leakoff behavior, viscosity development, settling rate for large-sized proppants, and fiber degradation in static and dynamic conditions were determined in various laboratory tests. This engineering work allowed fiber based fluids technology to be extended to moderate permeable oil reservoirs (1-20 md) and relatively cool formations (76–95°C), where fracturing treatments are regularly designed for tip-screenout treatments requiring fracture geometry control maximizing proppant pack permeability by increasing mesh size and proppant concentration.
The first five treatments performed have pushed the limits of the technology in regard to proppant size, type, concentration, and fracture fluid gel loading. Combining this solution with the use of advanced HGC materials offers unprecedented results in regard to fracture-height containment, where positive net pressures were obtained the first time. These operational results were confirmed by production measurements where the average water cut is 50% lower compared to the conventional treatments. Increases in productivity allowed up to a 37% increase in oil flow rate.
Adopting Aphron Fluid Technology for Completion and Workover Applications
Authors: MacPhail W. F , Cooper R. C. , Brookey T. , Paradis J. 
Published: February 2008

Abstract
The literature describes several applications where Aphron fluid technology has been applied in both drilling and re-entry scenarios and includes an extensive description of how this fluid system works. A highly efficient leak-off prevention mechanism makes aphron based fluid systems beneficial for certain completion and workover applications as well, where formation damage could be avoided by the practical elimination of fluid-fluid or fluid-rock interaction or where simply the workover objectives can be achieved by obtaining efficient circulation of fluid to surface. Completion and workover applications for this fluid system have not been extensively reported.
This paper reviews three applications of Aphron fluid technology in different completion and workover scenarios. The selected cases were reviewed to present some of the technical and operational lessons learned and to some extent discuss the observed formation cleanup behavior. The following three applications were reviewed: completion of a dual string sour gas well, using an oil based aphron system for kill fluid, with practically no kill fluid loss to a hydraulically fractured formation; the completion of additional zones within a depleted dolomitic limestone formation on two wells where the method of Aphron fluid placement was found to significantly affect fluid losses; and finally, the enabling of the provision of annular pressure support at pressures which approached the hydraulic fracture opening pressure of a shallow zone while hydraulically fracturing a deeper zone through tubing with a packer.
Continuous Pumping, Multistage, Hydraulic Fracturing in Kitina Field, Offshore Congo, West Africa
Authors: Casero Alberto , Pace Giamberardino , Malone Brad , Cantaloube Francois , Tealdi Loris , Malonga Henri , Seale Rocky 
Published: February 2008

Abstract
Many West Africa offshore fields are maturing and operators are completing secondary targets in their wells to maintain the economic operation of their valuable assets. Large quantities of reserves can be found in low permeability, consolidated, formations and new techniques are being investigated to improve the economic return of completing these formations.
The Kitina Field, offshore from Pointe Noire, Congo, is one such field. Deeper sands have been produced to economic depletion and the operator is looking for alternative production intervals.
The targeted reservoir is the 3A Sand at approximately 2200 meters TVD. The reservoir is a very heterogeneous lithology with varying quantities of siltstone, sandstone and calcite. The intervals of better porosity show a decrease in clay content, but the good "sands" can be either dominated by quartz or calcite with substantial variations with each meter of height.
Three candidate wells were selected for placing multiple propped fractures using a technique that has been used for six years in North America. This technique utilizes a series of mechanical packers and frac ports that are sequentially shifted "on the fly" allowing continuous placement of more than one hydraulic propped fracture without shutting down the pumping equipment.
During April to June of 2007, eight hydraulic propped fractures were placed in three re-completed, cased-hole wells in the Kitina Field with very encouraging production increases. During the first 90 days of post fracturing production, a production increase of 200% was achieved.
This paper will discuss the steps that were taken to place these propped fractures from an ocean going tender barge using skid equipment and recommendations for the future applications of this stimulation technique.
Effects of Crosslinker Type and Additives on the Performance of In-Situ Gelled Acids
Authors: Fatah W. Abdel , Nasr-El-Din H. A. , Moawad T. , Elgibaly A. 
Published: February 2008

Abstract
One of the most important factors that determine the outcome of matrix acidizing treatment is acid placement across the target zone. Chemical and mechanical means are used to enhance diversion during matrix acid treatment in various well completions; extended reach and multi-lateral wells. In-situ gelled acid that is based on polyacrylamide-based polymers has been used in the industry for several years.1,2 Previous studies highlighted that this acid can be used for diversion in formations with almost no hydrogen sulfide and permeability greater than 50 md.3
This acid consists of a polyacrylamide-based polymer, a cross linker, a buffer and a breaker. The cross-linker reacts with the polymer at a certain pH value and forms a gel, which helps in diverting the acid in tight or damaged zones. A breaker is used to reverse the gelation reaction at pH values that depend on the system. There are various cross-linkers available including those that are based on iron, aluminum and zirconium. The objective of this study is to examine the effect of type of cross linker and acid additives on the performance of in-situ gelled acids. Coreflood tests and rheological studies were conducted in this work.
The results obtained indicated that the gelation pH depends on the type of cross-linker used. Aluminum formed a gel at much higher pH values ((pH 4.3) compared the gel formed with iron (pH 2.6). Corrosion inhibitor reduced the pH of gelation in the case of iron, whereas an opposite effect was noted with the Al-based acid. Mutual solvent (ethylene glycol monobutylether) was very effective in reducing gel residue at pH values greater than 5.
Core tests indicated the in-situ gelled acid increased the permeability of tight cores from 35 to 2,000 md. Unlike previous studies, which showed damaged due to this system, no polymer residue was noted after flushing the core with mutual solvent solutions.
Effect of Droplet Size on the Reaction Kinetics of Emulsified Acid With Calcite
Authors: Al-Mutairi S. H. , Nasr-El-Din H. A. , Hill A. D. , Al-Aamri A. D. 
Published: February 2008

Abstract
Unlike other acid systems such as gelled and viscoelastic surfactant-based (VES) acids, where the mobility of hydrogen ion controls the overall rate of the reaction, emulsified acid/calcite reaction involves the transport of acid droplets in the diesel to the rock surface, breaking of acid droplets, and then the actual reaction on the surface. A limited number of papers have been published on the reaction kinetics of emulsified acid. However, none of the published work considered the effect of acid droplet size on the reaction of emulsified acid. The objective of this work is to examine the effect of acid droplet size on the reaction rate of emulsified acid with calcite.
The acid was 15 wt% HCl emulsified in diesel with 70 to 30 acid to diesel volume ratio. Emulsifier concentration was varied from 1 to 10 gpt. All emulsions were characterized by measuring the droplet size distribution, viscosity and thermal stability. Diffusivities were measured using the rotating disk device. Experiments were carried out at 25, 50 and 85°C, under 1,000 psi pressure, and disk rotational speeds from 100 to 1,000 rpm. Samples of the reacting acid were collected and analyzed for calcium concentration.
The effects of droplet size on the overall reaction rate were significant. Diffusion rate of acid droplets to the surface of the disk were found to decrease with increasing emulsifier concentration because of higher viscosities and smaller droplet sizes. Effective diffusion coefficient of emulsified acid was found to increase linearly with the average droplet size of the acid. Emulsions with low emulsifier concentrations (1 gpt) have average droplet sizes of nearly 13 µm. These emulsions were found to have high effective diffusion coeffeicents (5.093 ×10−9 cm2/s) and low retardation. On the other hand, emulsions with high emulsifier concentrations (10 gpt) have smaller average droplet sizes (nearly 6 µm) and found to have low effective diffusion coeffeicents (4.905 ×10−11 cm2/s) and high retardations.
The new sets of data can be used to determine the optimum emulsified acid formulation to yield deeper acid penetration in the formation. It is suggested that droplet size can be adjusted to produce the desired diffusion rate coefficients for acid fracturing treatments.
Sand Control Completion Failures: Can We Talk the Same Language?
Authors: Wagg Brian T. , Heseltine Jonathan L. , Faga Abraham T. , McKinzie Howard L. 
Published: February 2008

Abstract
Several operators have recently launched a new industry-wide initiative on sand control reliability. The aim of the initiative is to gain a better understanding of Sand Control Completion (SCC) systems, equipment performance, and reliability in a variety of applications. It focuses on assisting the industry to improve SCC performance and service life through sharing of reliability and failure information, operational practices, and other pertinent data. One of the key challenges in this effort is how to achieve consistency in the data collected by several operators.
This paper presents an approach to establish consistent practices for collecting, tracking and sharing SCC reliability and failure information. The approach is based on two key elements: (1) common data set; and (2) a standard nomenclature for coding SCC failure information. The general data set contains basic information on operating conditions, SCC systems and equipment, and the observed failures. While this data set is not overly detailed, in that the information is typically already collected by most operators and relatively easy to obtain, it is comprehensive enough so that meaningful analyses can be performed. The nomenclature standard builds on the International Standard IS0 14224 that stipulates broad definitions and failure attributes related to collection and exchange of reliability and maintenance data for equipment used in the petroleum industry.
The paper also provides a review of past industry efforts to track SCC system reliability in terms of the types of data collected, and the main types of analyses performed with the data. Comments are included on difficult issues such as how to define failure of a sand control completion.
It is hoped that the paper will encourage discussion on the topic, and help the industry share SCC reliability and failure data in a more consistent manner. The ultimate goals of this work are to assist the industry in improving SCC service life; improving the basis for selecting sand control systems and equipment; and better realizing the full potential of SCC technologies.
Gelled Scale Inhibitor Treatment for Improved Placement in Long Horizontal Wells at Norne and Heidrun fields
Authors: Selle Olav Martin , Springer Martin , Auflem Inge H. , Chen Ping , Matheson Rozenn , Mebratu Amare , Glasbergen Gerard 
Published: February 2008

Abstract
The success of a scale inhibitor treatment depends on the placement efficiency. The scale inhibitor should be placed so that all water producing intervals accept a sufficient quantity of the total treatment volume. If significant permeability or pressure variations are present in the interval to be treated, treatment fluid will enter the zones with the higher permeability and lower pressure leaving little fluid to treat the other zones, which can be potentially the water producing zones. The challenge is even greater in long horizontal wells with significant permeability and pressure contrast.
To achieve a more uniform fluid coverage, the original flow distribution across interval often needs to be altered. The methods used to alter this are called "diversion" methods. The purpose is to divert the flow from one portion of the interval to another.
In response to this challenge, a joint study with the objective of improving the placement of treatment fluids was initiated by a major operator in the North Sea and two service companies in 2002.
As a result of this work a fully viscosified scale inhibitor system is developed. The system comprises a purified xanthan viscosifying agent, a standard scale inhibitor for downhole scale squeezing and a breaker to achieve controlled gel breaking down hole.
The system has been field tested at Norne field in two long horizontal wells at Heidrun field in one long deviated well, all with significant permeability variations and cross flow. The operations were successful and the scale treatments have protected the wells from scaling. The paper describes the product qualification process, placement simulation, temperature prediction and gel breaking characteristics, case histories and post job evaluation.
Inflow Control Device and Near-Wellbore Interaction
Authors: Moen T. , Asheim H. 
Published: February 2008

Abstract
The optimization of inflow performance in long horizontal open hole completions involves several challenges. One is the formation damage and well clean-up. Another is the heel – toe effect caused by flow friction in the pipe, resulting in risk of gas or water coning in the heel and limited drainage from the toe. Due to such effects, horizontal wells may suffer from reduced PI and reserves left behind.
The introduction of Inflow Control Device (ICD) technology has proved to significantly increase the recoverable reserves from many fields. The ICD provides a controlled pressure drop which is a function of the flow rate. This restricts high producing zones and thus stimulates low producing zones, resulting in:
Improved well clean-up reducing the effect of formation damage caused by the drilling of the well. Equalizing the flux along the well path, giving reduced coning effects. Reduced annular flow. This reduces the risk of sand production behind the screen and subsequent plugging or erosion.
This paper is discussing how an ICD interacts with the reservoir and near well bore region. The first step is the dynamic of the clean-up process. The optimal differential pressure can now be applied to remove near well bore damage.
A model illustrating the propagation of this process will be described. This will be correlated with experimental results from clean-up of core plugs and practical field experience. The purpose of this work is to illustrate how the use of the ICD technology both improves the well PI and increases the recoverable reserves.
Evaluation of Formation Damage/Completion Impairment Following Dynamic Filter-Cake Deposition on Unconsolidated Sand
Authors: Constien V. G. 
Published: February 2008

Abstract
Evaluation of formation and completion (gravel pack and screen only) flow capacity damage in unconsolidated formation material has proven difficult in the laboratory because typical core flood equipment does not adequately confine the formation material to allow drilling and cleanup fluids to be circulated at representative shear rates and pressures over the formation face.
A testing protocol and equipment have been developed which allows dynamic flow and fluid loss across unconsolidated formation material at shear rates, temperatures, differential pressures, and times representative of mud circulation rates in the wellbore.
The dynamically prepared filtercakes grow to an equilibrium thickness depending on the shear rate, differential pressure, and temperature and are more representative in composition and mass to wellbore filtercakes so that their damage to formation, gravel packs and / or screens can be better evaluated. The effectiveness of cleanup systems can also be determined by circulating the fluids across the mud filtercakes at typical shear rates, differential pressures and temperatures before allowing static soak conditions.
At the end of the test, the screen and formation material or screen, gravel pack and formation material are stressed together simulating a wellbore collapse. The permeability of the formation plus gravel pack and screen or formation and screen only are then measured and compared to the initial values to determine flow capacity impairment.
Performance Evaluation of Ionic Liquids as a Clay Stabilizer and Shale Inhibitor
Authors: Berry Sandra L. , Boles Joel L. , Brannon Harold D. , Beall Brian B. 
Published: February 2008

Abstract
Most oil and gas producing formations contain clay minerals that were deposited during the sedimentation process, formed during the interaction of heat, pressure, and time on the naturally present minerals in the formation, or precipitated from fluids flowing from one area of the formation to others. The oil and gas industry has extensively investigated the role of these clay minerals during production and the potential permeability damage that can occur with swelling and migration of these clays. For many years, the effective use of salts such as KCl and NaCl in workover fluids for temporary clay stabilization has been well established. However, due to the potential environmental issues and the logistics of using large quantities of salts for this application, many operators have begun to search for alternative clay stabilizer products.
This project details the investigation and evaluation of ionic liquids as a clay stabilizer and shale inhibitor additive to prevent clay swelling and migration in comparison to the industry-standard clay stabilizers. Ionic liquids are compounds that are liquids at ambient temperatures and consist entirely of cations and anions, usually a organic cation and a inorganic anion.
Screening studies to determine the state of flocculation of clay-bearing fluids and to screen for shale inhibition were conducted with Capillary Suction Time tests (CST), Clay Pack Flow tests and core flow studies. This paper summarizes the results of the clay stabilizer screening studies conducted with ionic liquids and details the effectiveness of the ionic liquids as KCl substitutes, clay stabilizer additives, and shale inhibitors.
Long‐term seed bank dynamics in a temperate forest under conversion from coppice‐with‐standards to high forest management
Authors: van Calster Hans , Chevalier Richard , van Wyngene Bram , Archaux Frédéric , Verheyen Kris , Hermy Martin 
Published: February 2008

Questions:How do changes in forest management, i.e. in disturbance type and frequency, influence species diversity, abundance and composition of the seed bank? How does the relationship between seed bank and vegetation change? What are the implications for seed bank dynamics?Location:An ancientQuercus petraea — Carpinus betulusforest in conversion from coppice‐with‐standards to regularQuercushigh forest near Montargis, France.Methods:Seed bank and vegetation were sampled in six replicated stand types, forming a chronosequence along the conversion pathway. The stand types represented mid‐successional stages of stands in transition from coppice‐with‐standards (to high forest (16 plots) and early‐ and mid‐successional high forest stands (32 plots).Results:Seed bank density and species richness decreased with time since last disturbance. Adjusting for seed density effects obscured species richness differences between stand types, but species of later seres were nested subsets of earlier seres, implying concomitant shifts in species richness and composition with time since disturbance. Later seres were characterized by species with low seed weight and high seed longevity. Seed banks of early seres were more similar to vegetation than to later seres.Conclusions:Abandonment of the coppice‐with‐standards regime altered the seed bank characteristics, as well as its relationship with vegetation. Longer management cycles under high forest yield impoverished seed banks. For their persistence, seed bank species will increasingly rely on management of permanently open areas in the forest landscape. Thus, revegetation at the beginning of new high‐forest cycles may increasingly depend on inflow from seed sources.