bluuebunny/crossref_metadata_2025_split huggingface dataset:
Computational Fluid Dynamics for Horizontal Well Plunger Lift System Design
Authors: Longfellow Neil , Green David 
Published: June 2014

Abstract
As the future of gas and oil well drilling lies largely in directional and horizontal wells, it is important to develop tools that allow for the optimum operation of these wells. A key issue in this matter is the challenge of deliquifying horizontal gas and gassy oil wells. This paper discusses the use of computational fluid dynamics (CFD) to design and evaluate tubing plungers to improve performance in horizontal well deliquification.
Previous use of CFD by the authors thus far has been in design and evaluation of plungers for vertical wells. A validation study was carried out in which the fall rate of a variety of plungers were predicted with CFD and then compared to measured field results acquired through an acoustic study. The study found that CFD predicts fall rates within 8% of observed fall rates, validating it as a capable tool to characterize plungers. The process of using CFD predicted characteristics of a plunger, such as drag coefficient, to determine whether a particular plunger is appropriate for a particular well based on its typical operating conditions is also discussed.
Two major issues with plungers in horizontal wells are uneven wear and gas blow-by. CFD modeling addresses these with quantitative results such as the torque induced on the plunger during rise and fall, the forces on particular surfaces in plungers with multiple parts such as padded plungers. Qualitative results such as the flow patterns can also be used to predict if a given plunger will perform properly in a horizontal well.
Despite its strengths and capabilities, CFD can be limited in capturing the unsteady multiphase flow physics in inclined or horizontal tubing. To address this we are developing an experimental apparatus in which to study the flow physics in horizontal and inclined plunger-tubing systems. The results of this will be used develop and validate appropriate engineering criteria in CFD modeling for plunger deliquification in horizontal and inclined wells.
A Production Performance Prediction and Field Development Tool for Coalbed Methane Reservoirs: A Proxy Modeling Approach
Authors: Rajput Vaibhav , Basel E. D. , Ertekin Turgay 
Published: June 2014

Abstract
Field-scale simulations for development optimization can be overly demanding in terms of their time and manpower requirements. Exploration of a full suite of different design scenarios and operational behavior of a given reservoir becomes impossible within a reasonable period of time. This paper develops a method that can be used to predict production performance of a given field and perform field development studies with nominal manpower and computational requirements. Artificial neural networks (ANN) are used for development of expert systems for prediction of instantaneous and cumulative gas and water production, as well as for reservoir property prediction. A commercial reservoir simulator is used for generation of database for training, validation and testing of these expert systems. Uncertainty in reservoir properties is taken into account by varying the reservoir parameters within an estimated range of values. The overall performance levels of expert systems are optimized by varying various network parameters, and monitoring the error values for testing datasets.
Networks used for prediction of gas and water production profiles perform at error bounds less than 3% (forward networks), while those that are developed for prediction of reservoir characteristics at error levels of 15-19% (inverse networks). Forward networks were then used for optimization of field development. In this case, net present value (NPV) of a given field was placed as the parameter to be maximized during the search for optimum design specifications. Several case studies were carried out and analyzed. Improper field development strategies can result in huge losses for operating companies. Arriving at a proper well/drainage area selection and operational well specifications requires large operational time and excessive amount of simulation runs. With accurate results being obtained in fraction of seconds, this paper provides a simple and computationally-efficient technique that can be used to predict various production profiles and carry out effective field development studies.
Impact of Fracture Closure on Productivity Decline of Unconventional Wells
Authors: Sarna A. , Xing Q. , Mork J. , Ershaghi I. 
Published: June 2014

Abstract
With the rapid pace of drilling wells to tap unconventional oil and gas resources in the U. S., there is a need for further understanding of the fundamentals of reservoir mechanics that control well productivities. Wells with more than 5 years of data provide the opportunity to understand flow mechanisms affecting well productivity. What is particularly important is to test the validity and appropriateness of decline curve forecasting methods advocated in the literature over the last several years. To explain the unique and similar performance trends from unconventional wells, there are a number of issues that are gradually getting attention. Among these are the causes of rapid production decline seen after the initial peak. Certainly the physics of flow conditions causing the decline is not captured when regression analysis of production data is used with various decline models. Based on earlier studies, there is self-similarity among fractures formed during hydraulic fracturing. As discussed in the literature; the transient pressure behavior of complex self-similar fractures is equivalent to that for a single fracture. As such it is the flow capacity of the equivalent fracture that controls the behavior seen in actual performance of hydraulically fractured wells.
To test the applicability and weaknesses of commonly practiced regression models, we examined the performance of number of wells with production histories exceeding five years We used more than 40 examples from various shale plays all showing the loss of fracture quality resulting in lower flow capacity within the fracture network. The dynamic change in flow capacity is certainly not captured when decline curves are used that do not honor the flow regime's changes. As such, there can be major uncertainties associated with estimated EUR's from decline analysis techniques
Time-Domain Magnetic Defectoscopy for Tubing and Casing Corrosion Detection
Authors: Aslanyan A. , Aslanyan I. , Arbuzov A. , Zagidullin B. , Al-Rahawi T. A. , Prosvirkin S. , Al-Ajmi M. F. , Awad M. O. , Sharma S. S. , Das M. 
Published: June 2014

Abstract
The Magnetic Imaging Defectoscope (MID) is a tool designed to record the time response to high-energy electromagnetic pulses. Metal presence around the tool is evaluated by matching measured and numerically modelled magnetisation decays. The air response decays faster than if the tool is placed inside a metal pipe. If multiple pipes are present around the tool, the near pipe responds at earlier times and the more distant ones at later times. This phenomenon is key to detecting metal presence in each individual pipe. The MID tool features two sensors, short and long, to ensure reliable detection of responses from a wide range of multi-barrier completions and differentiate between defects in each barrier independently.
Despite this simple concept, the response detected by the tool has a complex time behaviour and cannot be modelled in a simple analytical way, which put time-domain technologies on hold for many years. The recent advances in computer speed and multicore parallel computing enable accurate numerical modelling of complex responses and determining metal presence in two metal barriers separately. In addition to thickness profiles for each barrier, the MID tool generates differential (DELTA) data panels, based on the difference between numerical models and actual responses, that visualise electromagnetic signatures of metal structures and can be used to locate and recognise various completion components, such as packers or SSD.
The paper describes the basics of the time-domain magnetic-pulse technology, specifications of the tool itself and laboratory test data. This technology has been tested in a dual-string producer of the Raudhatain field operated by the Kuwait Oil Company. The long and short strings were suspected to be communicating due to identical water cut trends. The MID tool was run once in memory mode on slickline through the long string and detected a 1.5-inch corrosion hole between packers that created communication with the short string. This communication flow left a footprint in a shut-in temperature log right across the corrosion hole. Another corrosion hole was located in the casing below the tubing shoe, immediately above the perforations. During a subsequent workover, the tubing was retrieved and a 1.5-inch corrosion hole was located in the exact place where it was identified by the MID tool.
Internal Corrosion Assessment of the Otter Oil Production Spool
Authors: Rodrigues Edgar , Akid Robert 
Published: June 2014

Abstract
One of the challenges facing the offshore oil and gas industry is the identification and quantification of internal corrosion for both topside and subsea process facilities. An increasing major cause of system failures and loss of production is that due to the presence of microorganisms that lead to the onset of Microbiologically Influenced Corrosion (MIC) in the offshore system [1]. Throughout the service life of the Otter oil production spool, internal corrosion was identified during the inspection programmes indicating severe metal loss of up to 1.7 mm/y for the Oil Topside Production spool. Internal corrosion and degradation were also detected in the subsea oil production pipeline during the 2010 and 2012 In-Line Inspection (ILI) programmes, where metal loss values of 12.5 mm depth were detected. Corrosion coupons and probes have confirmed that internal corrosion was active. The worst cumulative metal loss based on corrosion modelling indicated a corrosion rate of 0.22 mm/y. Furthermore, the microbial surveys performed using the most probable number (MPN) method has reported very low numbers of microorganism within the system.
Furthermore, the investigation of the spools when removed from topside, has confirmed severe internal corrosion aligned with inspection data. Samples of black deposits directly in contact with the carbon steel were taken for microbiological analysis and the novel DNA-based enumeration method quatitative Polymerase Chain Reaction (qPCR) has been used to assess whether or not MIC has occurred and to identify the key microorganisms responsible for this corrosion mechanism. High numbers of microorganisms were detected that could not be identified during service life indicating that MIC was in fact the primary mechanisms responsible for the damage found. Based on the results obtained, this paper discusses how the degree of internal corrosion was previously underestimated and how the microorganisms responsible for MIC that have been present were not properly identified and quantified. The paper also gives directions on how to strengthen MIC Threat Assesssment in the future.
Corrosion Inhibitors Squeeze Treatments-Misconceptions, Concepts and Potential Benefits
Authors: Graham Gordon M. , Bowering Deborah , MacKinnon Kirsty , McCall Matthew , Stalker Robert 
Published: June 2014

Abstract
While downhole chemical squeeze treatments are common practice for deploying scale inhibitors to protect wellbores and downhole production tubulars from inorganic deposits, their adoption for corrosion inhibitor treatments (CISQ) is much less commonplace. Historically they have often not been considered an option due to either anticipated poor lifetimes or the risk of formation damage in the form of emulsion blocks, wettability changes or relative permeability modification. However, in a number of carbonate reservoirs producing from different regions, corrosion inhibitor squeeze treatments have been shown to provide corrosion protection for downhole production tubulars when no alternative downhole chemical deployment technique is available.
This paper will present a technical review of the potential benefits of CISQ treatments. Different inhibitor retention/release mechanisms in sandstone and fractured carbonate reservoirs will be discussed, including classic adsorption/desorption and chemical imbibition/diffusion, as will the impact of these mechanisms and oil/water partitioning behaviour on squeeze lifetimes. Another factor limiting adoption of CISQ treatments is the misconception that residual assay techniques may be inadequate, and we demonstrate that this is not necessarily the case.
In addition to providing a mechanistic interpretation of the available retention and release mechanisms, the results of laboratory core flood studies will illustrate the different retention mechanisms and offer the potential to achieve considerably different lifetimes with different types of corrosion inhibitors. Field examples will also be cited in support of this. In these cases, the accuracy of the measured residual corrosion inhibitor return concentrations were confirmed by conventional electrochemical corrosion inhibitor performance measurements.
Corrosion Inhibition under FeCO3-forming Conditions at Elevated Temperatures
Authors: Palencsár Attila , Gulbrandsen Egil , Kosorú Katerina 
Published: June 2014

Abstract
Testing of inhibitors for CO2-corrosion at elevated temperatures is often performed so as to delay or avoid formation of a protective iron carbonate layer. Inhibitor performance in the presence of FeCO3 (partly or fully covering the steel surface), however, also deserves attention. This is relevant for parts of pipelines where rapid iron carbonate formation is expected, or when formation water breakthrough requires switching from pH stabilization to inhibition. From a methodological viewpoint such studies may indicate whether experiments in the presence of FeCO3 layers should be included in routine inhibitor performance testing. Investigating and comparing the behavior of corrosion inhibitors in the presence of iron carbonate layers of varying degrees of protectiveness was the objective of a series of experiments within the framework of a Joint Industry Project focusing on high temperature inhibition, carried out in our laboratories.
This contribution presents the results obtained with an imidazoline type generic inhibitor in high salinity brines with pH above 6, with 0.5 and 1 bar CO2 partial pressure. Inhibitor performance was studied by means of electrochemical measurements in glass cells at 80°C as well as in a pressurized jet impingement apparatus at 100°C and 120°C. Timing of the inhibitor injection was based on the development of the iron carbonate layer.
The inhibitor effectively reduced the corrosion rate when protective FeCO3 formation was not yet complete. Measurements of the Fe2+ concentration also revealed that the inhibiting effect hindered the increase of the supersaturation required for effective FeCO3 precipitation, slowing down or completely halting the film formation process. In contrast, once a fully protective iron carbonate layer has developed, no additional corrosion rate reduction can be observed upon inhibitor addition.
The results provide insight into how the inhibitor effect manifests itself when applied at various stages of iron carbonate formation on a steel surface. The experiments performed under enhanced convection illustrate the important role mass transport plays in the formation of iron carbonate layers and on inhibition. Both aspects are important for an improved understanding of inhibition of CO2-corrosion in oil and gas pipelines.
Multi-faceted Approaches for Controlling Top of Line Corrosion (TLC) in Pipelines
Authors: Frenier Wayne W. , Wint David 
Published: June 2014

Abstract
This paper reviews the mechanisms of initiation and the prevention of TLC. Practical multi-faceted techniques based on the most recent research and developments will be described and then illustrated using documented sources to arrive at best practices for control of this significant corrosion manifestation.
The application is in the complex corrosive environment in multi-phase and stratified flow pipelines (including gathering lines) that are frequently observed in new shale play production. The sizings of pipelines have become a critical factor to meet the current and future projected production rates. Especially where pipelines may be under-sized there is preferential attack in the top of the pipeline when water condenses and provides the electrolytes for acid gas and vapor attack on the steel surfaces.
Conventional corrosion inhibition methods (continuous or intermittent injection) are frequently not effective since physical contact of the inhibitors is difficult to achieve in multiphase flowing systems at the top of the line. In addition, the pipelines must be piggable to be properly cleaned and treated and traditional slug or continuous treatment methods have been found to not be adequate where conditions exist for TLC to occur.
Several innovative methods are being developed to provide effective and long lasting protection to the entire pipeline surface. Included are the use of pig trains with inhibitor slugs, inhibitor containing gels and foams and special pigs that provide a 360° spray of inhibitor chemicals. The newer methods will be compared with the other technologies.
The rapid expansion of the production of oil and gas from unconditional sources requires the annual construction of thousands of miles of new lines. These will experience a bewildering and changing range of conditions that will require the use of new and innovative internal corrosion protection methods described here that have been proven in field applications.
Application of Plant Extract for Inhibiting Corrosion in Acidic Environments
Authors: Belakshe Ravikant , Salgaonkar Lalit 
Published: June 2014

Abstract
Use of chemical corrosion inhibitors is quite common in production and processing operations. Depending on the type of acids used, different inhibitors have been developed to minimize corrosion and enhance the life of metal tubulars. Development of new chemicals and chemistries, which maintain good protection of materials under a variety of conditions while being environmentally acceptable, is an extremely challenging task.
This paper investigates the inhibitive properties of a new environmentally acceptable inhibitor toward corrosion of different steel alloys in the presence of mineral and organic acids. The inhibitor explored in this paper is a food grade chemical derived from a plant and commonly used in medicinal formulations. It is easily available, non-polluting, and biodegradable, being of plant origin. The inhibitor composition has several N, O, and S atoms containing alkaloid structures, which helps enhance the adsorption capacity of the chemical as well as imparts corrosion inhibition properties. The inhibitor can be used either in the form of a solid powder derived from the roots of the plant or in a liquid form derived by means of extraction.
Corrosion inhibition of oilfield alloys, such as N-80, 13Cr-L80, and QT-800, were studied in the presence of corrosive media, such as 7.5 and 15% HCl acid, and organic acid mixtures comprising acetic and formic acid. Weight-loss measurements were used to evaluate the inhibition efficiency and a corrosion loss of ≤ 0.05lb/ft2 was considered as a pass. Tests were conducted on the metallurgies mentioned over a temperature range of 150 to 275°F.
The results disclosed illustrate the potential of the inhibitor to serve as an effective environmentally acceptable inhibitor for the corrosion of steel alloys in the described temperature range. This single inhibitor composition can be applied for both HCl and organic acid media in fresh water and salt brine systems.
Accurate Tool for IOR/EOR Screening and Estimating Target Recovery Factors
Authors: Zijlstra Ellen , Wunnik John Van , Doren Jorn Van , Bimani Aisha Al , Wilson Ove , Shidhani Sultan Al 
Published: June 2014

Abstract
A semi-analytical method to calculate recovery factors is presented which is valid for recovery technologies that are based on flooding the reservoir with a liquid, such as Water, Polymer, Alkaline Surfactant Polymer and solvents including MGI and WAG. The method is based on describing the total Recovery Factor (RF) as the net result of a macroscopic displacement efficiency, essentially capturing the fraction of the reservoir that can be contacted by the injectant, and a microscopic displacement efficiency, capturing the extent to which the contacted rock can be swept clean. Given specific reservoir and fluid characteristics such as reservoir permeability distribution and relative permeability relations, these two components can each be described analytically and then merged together in the so-called PDO Tubes Model.
A comprehensive analysis of about 50 real IOR and EOR field cases with different geologies was done to validate the method. The PDO Tubes Model predictions of RF as a function of injected water in pore volumes were compared to full field simulation models showing a discrepancy of less than 5%. In this paper the tool and its validation will be discussed in detail and an example will be shown of an application of the tool for testing IOR and EOR implementation strategies for a very diverse set of fields.
Application of the PDO Tubes Model has resulted in a good understanding of the contributions of various EOR technologies to unlocking remaining oil in the Sultanate of Oman. Among others the tool can be used in any company for: IOR and EOR selection and target recovery factor setting, QC of simulation results, steering geological model building and analysis of a company's portfolio of fields for IOR and EOR potential and their implementation strategies including the resource requirements imposed by a specific strategy.
A Comparison of Asphaltene Deposition in Miscible and Immiscible Carbon Dioxide Flooding in Porous Media
Authors: Soroush Samaneh , Pourafshary Peyman , Vafaie-Sefti Mohsen 
Published: June 2014

Abstract
Carbon dioxide injection is used for tertiary oil recovery and can recover significant amount of residual oil. CO2 injection has been used successfully as an enhanced oil recovery (EOR) method for several decades. Recently, CO2 flooding method has gained popularity due to the growing concerns over the global warming issue. Hence, many light and medium reservoirs are subjected to Immiscible, miscible, and near-miscible CO2 flooding. In CO2 or hydrocarbon flooding, the asphaltene to resin ratio of crude oil is altered, causing asphaltene precipitation and thereby its deposition.
The deposition of asphaltene in an oil reservoir during production causes formation damage and productivity decline. The severity of this damage is different during miscible and immiscible flooding. In this study, asphaltene deposition due to miscible and immiscible carbon dioxide flooding and its effect on porous media damage are experimentally investigated. A high-pressure, high-temperature coreflood set-up is designed to work under reservoir conditions up to 6000 psia and 150 ºC.
Dynamic displacement experiments were carried out to study the process of asphaltene deposition and permeability reduction during CO2 injection in core samples. For this purpose, the pressures along the core were measured at 4 different points to study the damage distribution. Damage index were measured in different sections and compared during miscible and immiscible flooding and the effect of residual gas saturation in permeability reduction is studied as well.
The results showed that two parameters could change the permeability of the medium. At pressure lower than MMP trapped gas in the pores may also reduce the permeability and at pressure above the MMP asphaltene deposition is the main factor for the porosity and permeability reduction. The maximum damage index occurs in miscible flooding which was equal to 0.79.