bluuebunny/crossref_metadata_2025_split huggingface dataset:
Alternative Method to Determine Pore Volume Compressibility Attributable to Production-Induced Reservoir Compaction
Authors: Bai Mao , Shen Xinpu , Li Gang 
Published: July 2010

Abstract
In evaluating the process of rock deformation as a result of fluid withdrawal, two approaches prevail: macromechanical and micromechanical methods. In the oil and gas industry, the macromechanical method assesses the formation compaction arising from hydrocarbon production under reservoir field scales. The micromechanical method examines the origin of formation compaction arising from hydrocarbon production under micro-pore scale. The primary purpose of this micromechanical approach is to determine the critical pore strains subjected to the specified rock deformation and fluid drawdown that may lead to excessive reservoir compaction that is detrimental to the stability of subsurface structures (such as generating excessive sand production). This paper proposes the alternative conceptualization and formulation of pore volume reduction under both hydrostatic and uniaxial strain loading conditions. The result can be calibrated by the conventional pore volume compressibility (PVC)/compaction experiments. Furthermore, the proposed method considers the simplified concepts of pore volume reduction and solid volume reduction under the simple loading conditions amenable to laboratory testing techniques. The collective solutions yield the pore volume reduction in the form of reservoir porosity change that becomes a useful assessment to the planned reservoir production rate, and associated reservoir compaction, which is particularly important to the production in soft rock reservoirs where the reservoir compaction is often too significant to be manageable. The application of the developed critical pore strain in relation to bulk compressibility and PVC along with the variation of pore pressure and in-situ stress under the uniaxial strain testing conditions is illustrated in a simple case study.
Limitations in Numerical Well Rest Modelling of Fractured Carbonate Rocks
Authors: Corbett P. W. , Geiger S. , Borges L. , Garayev M. , Gonzalez J. G. , Valdez C. 
Published: July 2010

Abstract
Interpreting well-tests in (fractured) carbonate reservoirs poses significant challenges because these reservoirs often demonstrate triple porosity system (fracture-matrix-vugs) characteristics. However, there is no "unique" triple porosity system: The matrix can behave as a double porosity/dual permeability system whilst the fractures provide the third system; there may be two fracture systems and a single matrix; there may be vugs (macropores), mesopores and micropores to provide very large contrasts in matrix permeabilities. Modelling these systems is challenging because of the need to include heterogeneity for the matrix (or multiple matrices) and fracture(s) and determine the correct coupling between these systems.
The typical well test response in fractured systems – the classic double porosity "V" – can provide factors such as ω and λ as a description of fracture-matrix interaction (storativity ratio and the interporosity flow coefficient, respectively). Understanding how these two parameters relate to the description of matrix and fracture properties in triple porosity systems requires exploration of new scenarios in numerical well test modelling (sometimes called "geological well testing"). In this paper, we set out some of the reservoir description, modelling and simulation challenges to provide guidance on how to set up systematic models and determine the appropriate family of geotype (families of closely related pressure derivative response) curves for fractured carbonate systems in order to understand the interpretation of ω and λ.
History Matching with Differential Evolution Approach; a Look at New Search Strategies
Authors: Hajizadeh Yasin , Christie Mike , Demyanov Vasily 
Published: July 2010

Abstract
History matching and uncertainty quantification are two important aspects of modern reservoir engineering studies. Finding multiple history matched models for uncertainty quantification with fast and efficient optimization algorithms are the focus of research in assisted history matching methods. Recently a new approach for history matching has been proposed based on differential evolution optimization algorithm. Differential evolution is a very powerful optimization method with a simple structure and few tuning parameters which makes it easy to use in automatic history matching frameworks.
In this paper we are looking at three new search strategies as alternates to the proposed method in previous publication for obtaining multiple history-matched reservoir models. These strategies of differential evolution are different in the way that new models are generated during automatic history matching process. The comparative study presents the differences between performances of new search schemes for a simple reservoir simulation case in Gulf of Mexico. We compare the best history matching results and sensitivity of algorithms to starting conditions. Tradeoff between speed of convergence to good fitting regions and coverage of the search space is also demonstrated for different variants of differential evolution. We show that some variants of differential evolution exhibit global searching characteristics, while other ones quickly obtain good results, saving time and computational resources in reservoir engineering studies. Final part of this paper focuses on the uncertainty of production forecasts, discussing the prediction capability of applied differential evolution algorithms.
Advantages of Inflatable Packer Technology for Temporary or Permanent Well Abandonment in the Gulf of Mexico
Authors: Vaucher David , Brooks Robert 
Published: July 2010

Abstract
With so many wells operated in the Gulf of Mexico, one would think that the process of eventually abandoning these wells temporarily (during hurricane season), or permanently plugging and abandoning (P&A) them is by now more routine. Certainly, there are years worth of procedures and case studies on the subject, yet there are always "special cases" that require more specialized planning and equipment. For instance, toppled rigs present the challenge of "kinked" tubing, while other wells have several tubing or casing strings through which a plug must pass before setting in a larger diameter opening. For these non-routine operations, inflatable packer technology presents several significant advantages: small restriction clearances and high expansion ratios as compared to traditional mechanical bridge plugs. Additionally, inflatable plugs are incredibly versatile in that they can be conveyed to depth using either coil tubing, threaded tubing, even slickline and wireline. Finally, inflatable plugs do cover a wide range of hole conditions (temperature, washouts, etc), and are therefore robust enough for most well decommissioning jobs.
This paper will present the unique advantages of inflatable packer technology in these decommissioning operations and will illustrate these advantages using job examples and case studies. The examples and cases used will be limited to the Gulf of Mexico, yet the advantages of these technologies can be applied to any well worldwide.
Scale Inhibitor Squeeze Treatments based on Modelling Studies
Authors: Raju Kris U. , Al-Buali Muhammad H. , Al-Saadoun Turki F. , Aramco Saudi , Mackay Eric J. 
Published: July 2010

Abstract
Scale inhibitor treatment programs for crude producers in Saudi Aramco have been exceptional in the oil industry. Development and application of various scale inhibitor treatment programs that incorporate the latest university industry-funded research findings improved the treatment lives over ten plus years for lowest possible cost. Phosphonate based scale inhibitor squeeze treatments provide the most effective means of preventing CaCO3 scale formation in our carbonate fields. Based on the mathematical scale inhibitor squeeze (SIS) model for horizontal wells, we applied a simple bullheaded squeeze treatment avoiding expensive coiled tubing application.
Conventional squeeze treatments with acidic scale inhibitors and an aqueous overflush generally resulted in initial high watercut and occasionally productivity decline. Recent research on phosphonate-carbonate interactions, and modelling of these interactions, and the impact of two-phase flow by the FAST group at Heriot-Watt University (HWU) - described in SPE 87448, SPE 100515 and SPE 114105 - led to improved squeeze treatment performance.
Based on the above studies, significant changes were introduced to the main scale inhibitor formulation and the overflush stages. These treatments were performed on both vertical and horizontal wells in our largest carbonate oilfield. The new modifications have resulted in better well response compared to earlier acidic scale inhibitor treatments. There was either a small drop in water-cut or else the wells maintained the same value, instead of the increase in water mobility observed with earlier treatments. Similarly, productivity changes are better with the modified treatment compared to the old program. This paper describes the theoretical background in selecting simple bullhead treatment for horizontal wells, partially neutralized phosphonate based scale inhibitor and the overflush formulations and the resulting field productivity changes after treatment.
Development of a New Corrosion Management Tool - Inhibitor Micelle Presence as an Indicator of Optimum Dose
Authors: Mackenzie C. , Magdalenic V. , Perfect E. , Achour M. , Blumer D. , Joosten M. , Rowe M. 
Published: July 2010

Abstract
This paper discusses the principle and proof of concept of a novel corrosion management tool based on maintaining optimum corrosion inhibitor dose in an inhibited environment. Film-forming corrosion inhibitors typically contain active ionic surfactant molecules which adsorb on surfaces and form a protective barrier against corrosion. Upon saturation of surfaces by the inhibitor, the molecules are found in the aqueous phase as micelles or in the oil phase as reverse micelles. The proposed technique is based on the hypothesis that the presence of these micelles in the water phase could be used to indicate the total surface coverage and therefore the optimum dose.
The technique has been applied in the laboratory simulating an actual inhibited multiphase production system. Fluorescent markers, that are extremely sensitive to micelle presence, have been developed and used during the lab testing. Results were compared to standard laboratory techniques, including interfacial tension (IFT) and particle size analyses (diffraction) in order to determine the efficacy for micelle detection. Corrosion bubble tests were also used to determine any link to inhibitor efficiency.
IFT results showed complex events occurring with increasing inhibitor concentration. The IFT vs. inhibitor concentration curve was non-classical, but suggested micelle formation at around 150ppm. Fluorescence analysis suggested that micelles formed starting at 150ppm dose. Particle size analysis was consistent with micelle presence beyond this concentration.
The analytical comparisons supported the underlying principles of this micelle detection technology. Further development is required to demonstrate the real-time link with corrosion protection, but other studies have already confirmed such correlation. Development of a portable device is underway and will provide an important new tool for proactive corrosion management in the oilfield, as well as a useful laboratory qualification method.
Discrete Fracture-Vug Network Model for Modeling Fluid Flow in Fractured Vuggy Porous Media
Authors: Yao Jun , Huang Zhaoqin , Li Yajun , Wang Chenchen , Lv Xinrui 
Published: July 2010

Abstract
Modeling and numerical simulations of fractured vuggy porous media is a challenging problem due to the presence of cavities called macro vugs which are connected via discrete fractures networks. The main difficulty is the co-existence of porous and free-flow region in such media on macro scale. In this study, a novel conceptual discontinuum model i.e. discrete fracture-vug network (DFVN) model has been proposed to this problem.
In DFVN conceptual model, naturally fractured vuggy porous rock masses are considered as a composite porous material, consisting of (1) macro fractures system, (2) porous rock matrix system, and (3) macro vugs system. Macro fractures and vugs are embedded in porous rock, and the isolated vugs are connected via discrete fracture network. We model the fractured vuggy media on macroscopic scale using Navier-Stokes equations within the vugular region, Darcy's law within the porous flow region including porous rock matrix system and macro fractures system, and a Beavers-Joseph-Saffman boundary on the interface between two regions.
A standard Galerkin finite element method is implemetated for the solution of DFVN model. A good match with analytical and numerical solutions for Poiseuille flow in a free/porous channel was achieved, which verified the accuracy of our finite element numerical scheme. Both 2D DFVN models with homogeneous isotropic rock matrix and heterogeneous anisotropic rock matrix are simulated and studied. The numerical results have shown that DFVN model provides a natural way of modeling realistic fluid flow in fractured vuggy porous media.
Control and Removal of Downhole Interfacial Solids
Authors: Smith J. Kevyn , Wahus Dale , Boyd Galyn , Fu Qiang , Boyce Greg , Firouzkouhi Fafa , Deichert Dominic 
Published: July 2010

Abstract
The control of the formation, accumulation, and precipitation of downhole solids is critical to the efficient operation of placed equipment. Downhole solids formation can lead to premature sucker rod lift pump failure and subsequent lost production. Control of these solids is often complicated by the speciation, location and treatment availability. Well conditions, such as temperature and pressure, commonly have varying effects on the individual components of these complex solids mixtures thereby complicating the control of their formation, maturation and precipitation. Removal of these solids is generally accomplished by the application of batch treatment programs or continuous application of scale inhibitors, surfactants or iron chelators. However, there is another mode of control that is not common practice in the oil field, control of the particle size. In this paper, we seek to demonstrate the control of the particle size of a complex mixture of solids by the use of a highly surface active dispersant that is specific for FeS. In this study, removal and control of a complex scale mixture, which included FeS, FeCO3, ZnS and CaCO3 in several oil wells in North Dakota, was studied by applying the FeS dispersant and a FeCO3/CaCO3 scale inhibitor. Action against these solids present at the downhole interfacial pad, as well as those that are newly formed are inferred from observation of the suspended solids, as collected from Millipore filtration, pump friction, pump loading, and residual oil in water. Correlation of this data showed that control of the particle size, as well as, the removal of the downhole interfacial pad was achieved within a month of treatment with this highly surface active dispersant and scale inhibitor. After approximately 14 months of treatment, the long term analysis of this treatment has revealed that this approach has increased SRL pump life and decreased operational costs due to treater upsets, pump longevity and reduction of the instances of bad oil.
Scale Inhibitor Application In Northern Alberta: A Case History Of An Ultra High Temperature Scale Inhibition Solution In Fire Tube Heater Treaters
Authors: Wylde Jonathan J. , McMahon Jeff , Mayner Steve 
Published: July 2010

Abstract
This paper reports a challenging and unique scale forming environment in Northern Alberta, Canada. Calcite was forming on the fire tubes in a series of treaters. Bulk fluid temperature was 110°C but skin temperature of the fire tubes was in excess of 450°C. This created an incredibly high scaling potential.
The paper provides background on the field case history with a detailed description of the process and the scale forming environment. An in-depth scale modeling study characterizing the scaling up to 200°C is provided.
Further laboratory studies are reported including performance testing on candidate scale inhibitors and differential scanning calorimetry to determine their molecular stability. The testing looked at scale inhibitors and investigated the direct inhibition properties as well as any dispersion properties to prevent surface adsorption of scale on the fire tubes.
The testing found that the incumbent scale inhibitor (phosphonate based) was a good product for the bulk scale inhibition but was not stable at the temperature of the fire tubes. The most thermally stable scale inhibitors tested were polymaleic acid copolymers and polymeric acrylic acids of low to medium molecular weight. No scale inhibitors were tested to be fully stable up to 450°C but it was found in field application that the best product identified through laboratory testing was sufficient enough to delay the scale formation on the fire tubes. It is hypothesized that the product was stable at high temperature for the residence time of fluid in the treaters or imparted some degree of scale inhibition even after thermal molecular scission.
The paper concludes with data of the fire tube change out history highlighting the step change in performance when applying the polymeric inhibitor quantified by change out frequency and presence of hot spots.
DASS Well- A New Concept of Multiple Zone Well Completion
Authors: Dass Chanchal 
Published: July 2010

Abstract
Over the years, several techniques for multiple zone well completions were evolved in oil industry but due to some or other reasons the popularity of multiple zone well completions lost. Earlier attempts for multiple zone completions were to use multiple tubing or commingling large number reservoirs. Now a new concept of well completion is available in which all the advantages of multiple tubing completions and commingle production can be retained with a single tubing well completions.
The name of the concept well is DASS well. DASS well stands for Dynamically Activated Super Solution wells. The well architecture is radically different from existing well completions. The reservoir fluid enters the well bore through a production chamber. Production chamber is one device which is set over perforations. Multiple production chambers can be installed in a well depending upon the number of zones available for production. A multiphase flow meter and fluid flow control valve are fitted in the production chamber which is operated from surface control panel. The well fluid is flowed from production chamber through control valve to the well bore. The well depth depends upon the expected fluid production rate. A down hole pump is installed to pump the liquid through tubing and gas is produced through annulus in such a way that surface separation minimized/eliminated.
In this paper, the author introduces "DASS well" - the new concept of multiple zone well completion with detailed description and diagram with its advantages and disadvantages.
Deepwater development demands a simple and cheap well completion technology which can help in efficient production, handling, storage and transportation of oil and gas in addition enhancing oil production through advance processes. DASS WELL-the new concept for multiple zone well completion can prove helpful in this direction.
Non-Darcy Displacement in Linear Composite and Radial Flow Porous Media
Authors: Wu Yu-Shu , Fakcharoenphol Perapon , Zhang Ronglei 
Published: July 2010

Abstract
This paper presents Buckley-Leverett type analytical solutions for non-Darcy displacement of two immiscible fluids in linear and radial composite porous media. High velocity or non-Darcy flow commonly occurs in the vicinity of wellbore because of smaller flowing cross-sectional area, however, the effect of such non-Darcy flow has been traditionally ignored. To examine physical behavior of multiphase immiscible fluid non-Darcy displacement, an extended Buckley-Leverett type of solution is discussed.
There exists a Buckley-Leverett type solution for describing non-Darcy displacement in a linear homogeneous reservoir. This work extends the solution to flow in linear and radial composite flow systems. We present several new Buckley-Leverett type analytical solutions for non-Darcy flow in more complicated flow geometry of linear and radial composite reservoirs, based on non-Darcy flow models of Forchheimer and Barree-Conway. As application examples, we use the analytical solutions to verify numerical simulation results as well as to discuss non-Darcy displacement behavior. The results show how non-Darcy displacement in linear and radial composite systems are controlled not only by relative permeability, but also non-Darcy coefficients, characteristic length, injection rates, and as well as discontinuities in saturation profile across the interfaces between adjacent composite flow domains.
Simple-to-Use Predictive Tool for an Accurate Estimation of the Water Content of CO2
Authors: Bahadori A. , Maddahi M. , Vuthaluru H. B. 
Published: July 2010

Abstract
CO2 emissions from burning fossil fuels have been identified as the major contributor to the increase in atmospheric CO2 levels that can potentially lead to global climate changes. In this work, an easy-to-use predictive tool which is simpler than existing approaches, less complicated with fewer computations, is formulated to arrive at an appropriate estimation of the water content of carbon dioxide-rich phase. The new developed method works for pressures ranging from 5 to 70 MPa (which covers the pressure that is widely considered in CO2 sequestration) and temperatures from 20 to 75°C. Comparison of predicted results with the reliable experimental data indicated excellent agreement with the average absolute deviations being less than 1.5%. This simple-to-use predictive tool can be of immense practical value for the environmental engineers and scientists to have a quick check on the water content of carbon dioxide-rich phase at various temperatures and pressures without performing any tedious experimental measurements. The proposed method is superior owing to its accuracy and clear numerical background, wherein the relevant coefficients can be retuned quickly for various cases. In particular, personnel dealing with regulatory bodies of greenhouse gas control and process industries would find the proposed approach to be user friendly involving transparent calculations with no complex expressions.
Preparation of Microgel Nanospheres and Their Application in EOR
Authors: Wang L. , Zhang G. C. , Ge J. J. , Li G. H. , Zhang J. Q. , Ding B. D. 
Published: July 2010

Abstract
Polyacrylamide microgel nanospheres were synthesized by inverse microemulsion polymerization with redox initiators on the basis of the preparation of water-in-oil (W/O) microemulsion with diesel oil, sorbitan monooleate, polyethylene glycol sorbitan monostearate, acrylamide, N,N′-methylenebisacrylamide and deionized water. By adopting a twice synthesis process, polymer content can be substantially lifted from 24.43 wt% to 35.04 wt%. Moreover, it's proved that nanospheres can expand from the initial 50nm or so to several microns after water absorption.
In this paper, synergy effects of the emulsifiers (sorbitan monooleate and polyethylene glycol sorbitan monostearate) separately with alkalis and surfactants are firstly proposed and verified via the achievement of ultra-low interfacial tension (IFT). Profile control and oil displacement tests by sandpacks further demonstrated the promising future of nanospheres in enhanced oil recovery (EOR) with incremental oil recovery over 20% OOIP after primary recovery.