bluuebunny/crossref_metadata_2025_split huggingface dataset:
An Improved Complex Image Theory for Fast 3D Resistivity Modeling and Its Application to Geosteering in Unparallel Layers
Authors: Chen Jiefu , Yu Yao 
Published: October 2014

Abstract
Azimuthal resistivity logging-while-drilling (LWD) tools are widely used in geosteering because of their azimuthal sensitivity and depth of investigation compared to those of other LWD tools such as nuclear, acoustic, or gamma ray measurements. Compared to conventional resistivity tools, azimuthal resistivity LWD measurements can provide additional information including distance to bed interface, relative dip, and resistivity anisotropy. Because of the computing efficiency requirement, modeling and inversion of azimuthal resistivity LWD measurements are usually based on the 1D parallel layer model: i.e., all bed interfaces are infinitely large and parallel to each other. Clearly this 1D model assumption does not apply to some realistic situations such as when the tool is navigating in an unparallel layered formation, or approaching a fault.
3D full wave simulations such as finite difference or finite element methods can handle the complex cases, but they are generally too slow for real jobs, not to mention the inversion based on forward modeling. An approximation method called "complex image theory" was proposed for geophysical prospecting and recently introduced to well logging. This theory approximates electromagnetic wave reflection by an interface between local and adjacent beds as signal radiated from a virtual source with a complex distance from the observation point. The complex image theory can be several orders of magnitude more efficient than 3D simulations. However, it also has several limitations: This method only works in resistive beds with conductive shoulders, and measurement cannot be too close to bed interfaces. Those shortcomings greatly limit this method to more extensive applications.
An improved complex image theory is proposed here to tackle the aforementioned difficulties. This improved theory can handle finite-sized interfaces, any distance from the tool to a bed interface, and the scenarios where the source is in a conductive bed instead of a resistive one. An efficient and robust inversion scheme is also implemented based on the improved complex image theory. This proposed method can greatly facilitate formation evaluation and decision making of geosteering in complex scenarios. Synthetic data, laboratory experiments, and field jobs are shown here to demonstrate the effectiveness of this improved complex image theory.
Subsurface Capability Building
Authors: Kloosterman H. J. 
Published: October 2014

Abstract
Shell has implemented in the last few years a structured new approach for the capability building for its graduate recruits as well as its mature hires, with the objective to shorten the time to autonomy. Two structured programmes, the Shell Graduate Programme (SGP) and the Shell Advanced Technical Programme (SATP) have been specially designed for this purpose. These programmes form part of the overall talent pipeline in Shell for building technical Capability (Figure 1) and link to a simplified competence framework set-up, in which proof points are defined for each competence, allowing for consistent assessment of capability building progress. Both programmes follow a blended learning approach, integrating formal and informal learning through work-based activities.
The Subsurface Learning portfolio (covering Reservoir Engineering, Petrophysics & Geomechanics, Production Geology, Geophysics, Exploration Evaluation, Geomatics & Data Management) consists of some 100+ global as well as some 70+ regional courses (some 400+ learning events in 2013), delivered by 15 Full-time Learning Advisors, supported by some 100+ technical experts from the business. On average, some 10+ new subsurface courses are developed every year.
The latest developments in Subsurface Learning delivery focus on the integration of "Digital Geology" through augmented reality techniques with static and dynamic reservoir models, carried out at the relevant scale to support the associated business decision. These cross-discipline learning events will initially take place in Shell's 3D-visualisation centre in Rijswijk, the Netherlands (iScope), to be subsequently rolled-out to other Shell-locations. This paper will present an overview of the latest developments in Subsurface Learning in Shell, as described above.
Methodology To Estimate The Chance Of Success Of A Time-Lapse Seismic Project Using Reservoir Simulation
Authors: Ferreira Carla J , Schiozer Denis J. 
Published: October 2014

Abstract
Time-lapse seismic technology has been successfully used in the petroleum industry. It provides important information regarding properties of the reservoir between and beyond the wells; 4D (time-lapse) seismic data is used as input for several processes, such as: well planning/completion; geological model constraining and reservoir simulation history matching. However, there are technical issues to be addressed before starting a 4D seismic project. Several geophysical studies use the chance of success concept to identify favorable cases; evaluating the seismic survey and the magnitude of seismic changes. However, from an engineering point of view it is important to evaluate the chances of business success, which relies on the use of the new information to identify infill well locations, increase the predictive capability of reservoir simulations, optimize the reservoir performance and develop well intervention programs. A 4D seismic project is considered an economic success if the impact on field operations generates more monetary benefit than the acquisition cost. The complex estimation should be based on field uncertainties and decision analysis. Given the importance and difficulty of predicting economic success, this paper presents a methodology to estimate the chance of success of a 4D seismic project from the engineering perspective applied to a synthetic model. The methodology was applied to a synthetic reservoir model to obtain a first estimate of the chance of success of a 4D seismic project for a specific production period. The process was performed in the developing phase and it comprises several methodologies such as: risk analysis, representative models selection, production strategy optimization and value of information concept. The presented methodology provides information of the chance of success of a 4D seismic project at a specific production period assisting the decision maker to evaluate the need for further analysis or to establish the acquisition or not of 4D seismic data. This decision is taken considering the acquisition cost, the increase of NPV due to new data and other influential factors. Thus, the main benefit derived from the acquisition of 4D seismic data was on the identification of remaining oil areas. Time-lapse seismic data has been successfully used in reservoir monitoring; several published cases report the success of its use in the improvement of production efficiency. But it is important to predict if acquiring new information will be profitable before the acquisition. This is a complex but essential part of time-lapse seismic reservoir management.
Dynamic vs. Static Ranking: Comparison and Contrast in Application to Geo-cellular Models
Authors: Kelkar M. G. , Pochampally S. , Bahar A. , Sharifi M. 
Published: October 2014

Abstract
With increasing computational power, large geo-cellular models are constructed comprising of multi-million cells. Using uncertainty work flows, large number of geo-cellular models (realizations and scenarios) are constructed which can incorporate uncertainties in static parameters. The typical number of geo-cellular models can range between as few as thirty to as high as hundreds or even thousands. Once these models are constructed, the geo-modeler as well as simulation engineer realizes that all these models cannot be flow simulated without significant upscaling. Therefore, a search begins to find a method which would cost effectively select just a few of these geo-cellular models which can bracket the uncertainties present in these models.
Static methodologies, which rank these realizations based on static properties such as Hydrocarbon Pore Volume (HPV) or STOIIP/GIP may not truly represent the ranking based on actual performance of the reservoirs. For example, a reservoir which contains large HPV but is not well connected will ultimately produce less oil/gas than a reservoir which is well connected but contains less HPV. We, therefore, need a ranking based on dynamic characterization of the reservoir.
We have developed methodology based on Eikonal equation which can rank multiple realizations extremely efficiently. The method determines the time it takes for a traveling of a pressure "wave" to reach a particular grid block from a given well and assumes that time it takes to "tag" a grid block will reflect how quickly that grid block can be drained from a given well. Unlike finite difference or streamline simulation, the method does not require solving any matrix; hence, it is unconditionally stable. In matter of few minutes, a geo-cellular model containing more than fifty million cells can be interrogated.
Using both synthetic and field examples, we demonstrate that the ranking based on our methodology is consistent with the ranking one would obtain using finite difference simulator. Further, ranking based on static properties does not correlate well with the dynamic response of the reservoir. By using the proposed methodology, limited number of geo-cellular realizations can be selected which can capture true dynamic uncertainty in reservoir performance.
A Combined Bottom-hole Pressure Calculation Procedure Using Multiphase Correlations and Artificial Neural Network Models
Authors: Li X. , Miskimins J. L. , Hoffman B. T. 
Published: October 2014

Abstract
The desire to have accurate bottom-hole pressure (BHP) data can come during different phases of a well's life, including well design, mini-frac test, well testing, and production analysis. But frequently, it is not practical, feasible, or economic to deploy a pressure gauge to measure the BHP directly. In most cases, however, the unknown flowing BHP is calculated from the known parameters and surface measurements using multiphase correlations or mechanistic modeling. Recently, artificial neural network (ANN) techniques have been adopted to predict BHP and proved to have better prediction performance than other conventional prediction methods. With the design applied in this study, the use of ANN techniques can be more fully utilized to solve complex multiphase flow problems, such as pressure gradient prediction and complex well trajectories.
Back-propagation (BP) neural network models have been modified to fit into the piece-wise calculation procedures of multiphase correlations to achieve higher prediction accuracy and broaden the prediction range. The model training requires well-segment-scale data sets, which contain pressure gradients as the model output and the model inputs, including inclination angle, liquid and gas superficial velocities, gas-liquid surface tension, liquid density, specific gravity of free gas, liquid and gas viscosities, average pressure and temperature. Different BP neural network model structures have been tested to find a suitable neuron number in the hidden-layer of the model. Two pressure gradient prediction models were trained for slug flow and annular mist flow.
Ultimately, a combined BHP calculation procedure was designed combining the multiphase correlations and trained ANN models. The statistical tests using the collected data showed that the combined procedure gave the best prediction performance against the eleven multiphase correlations studied in this work and had the lowest average absolute percent error of 3.1% and standard deviation of 0.034. Independent field data was used to test the extendibility of the combined procedure prediction range. Comparing to the multiphase correlations, the combined procedure gave fairly accurate predictions with an average absolute percent error of 23.0% and a standard deviation of 0.176. To facilitate field application, a multiphase flow BHP calculator with a user interface was developed.
Development of Improved Testing Procedure for Wells with Sustained Casing Pressure
Authors: Kazemi Mohammad , Wojtanowicz Andrew K. 
Published: October 2014

Abstract
In the US, the Bureau of Safety and Environmental Enforcement (BSEE) regulations require pressure bleed-down/buildup (B/B) testing of wells with annular Sustained Casing Pressure (SCP) if the casing head pressure is greater than 100 psig. The test involves bleeding the pressure with a needle valve followed with up to 24-hour monitoring pressure return after the valve is closed. As the test description is limited to its principle, the way it is actually performed varies considerably among operators leading to different results.
Analysis of B/B tests described in the API standards is merely qualitative and limited to the finding if pressure could be bled to zero and if it would re-build to its initial value before the test. Needless to say, the two findings might depend upon the way needle valve has been operated and also they do not provide any quantitative information about gas migration in the leaking cement. Quantitative analyses methods and models have been already proposed, but – as shown in the paper – they either produce ambiguous results or they have oversimplifying assumptions that lead to widely-spread estimations of the cement leak size by orders of magnitude.
The presented work is a study of the B/B testing as a source of useful information for SCP problem assessment and remediation. Simulation software based on improved mathematical model of SCP well is used for theoretical parametric study of the testing process. Analysis of variance and multivariate regression method consider four unknown system parameters to be determined from the test (length and permeability of the leaking cement, and length and compressibility of the annular fluid above the cement). The study qualifies significant system parameters controlling each of the three stages of the B-B test: pressure bleed-down, stabilization and buildup. The results show that significance of these parameters varies between the stages. The finding indicates that B-B test should involve three stages – instead of two stages presently practiced. Also, the results show merit of a stage-by-stage analysis of the test instead of trying to find all system parameters by matching the whole test.
In addition, three operational parameters of the B-B test (bleeding rate and time, and pressure recording time step) are evaluated to see how they affect test results in view of possible improvements in the testing procedure. It is shown that the operational parameters have significant effect on well response and may cause misinterpretation of test results. Early closure the bleed valve prior to gas flow stabilization would not indicate the true bleed-down pressure and produce pressure buildup that misrepresents the cement leak size.
CFD Simulation of ESP Performance and Bubble Size Estimation under Gassy Conditions
Authors: Zhu Jianjun , Zhang Hong-Quan 
Published: October 2014

Abstract
As a high-efficiency tool to convert rotating kinetic energy to hydraulic pressure head, the electrical submersible pump (ESP) is widely used in the petroleum industry to increase hydrocarbon fluid production rates. Previous studies showed that the presence of gas would cause ESP hydraulic head degradation. Flow behaviors in ESPs under gassy conditions, such as gas pockets, further deteriorate ESP performance. It is important to investigate flow structure inside ESPs with gas involvement. In this paper, we use Computational Fluid Dynamics (CFD) to simulate fluid flows through an entire ESP stage, including impeller and diffuser. We also calculate the corresponding heads under both liquid and gas-liquid flow conditions. Additionally, the pressure field, velocity profile and gas distribution inside ESPs are analyzed. The commercially available CFD software was used for geometry editing, mesh generating, finite-volume-method solving and post-calculation. Sensitivity analysis of meshing was also conducted.
The CFD simulation results of ESP performance under single-phase water conditions matched manufacturer performance curves. For two-phase flow simulation, water and nitrogen were used as working fluids with different gas volume fractions (GVF) from 1.0% to nearly 20% and considerable degradation of pump performance was observed. In contrast to previous simulations in the literature using constant bubble sizes, our simulation results reveal that bubble size is a key factor related to an increase in GVFs. The CFD simulation results were compared with experimental measurements from the Tulsa University Artificial Lift Projects (TUALP) and good agreement was achieved under both single and two-phase conditions. The observed results using proper bubble size estimation indicated that CFD simulation is a reliable tool for analyzing ESP performance.
Characterization of Asphaltene Transport over Geologic Time Aids in Explaining the Distribution of Heavy Oils and Solid Hydrocarbons in Reservoirs
Authors: Mullins Oliver C. , Wang Kang , Chen Yi , Hernandez Diana , Pomerantz Andrew E. , Zuo Julian Y. , Hammond Paul S. , Dong Chengli , Elshahawi Hani , Seifert Douglas J. 
Published: October 2014

Abstract
Asphaltenes are a very important component of reservoir fluids. They have a huge impact on crude oil viscosity and are a Flow Assurance concern. They can undergo a phase transition, giving rise to tar mats that seal aquifers precluding aquifer sweep. Local tar deposits can act as a drilling hazard. Upstructure tar (or bitumen) deposition can occur which can flow with produced light hydrocarbons greatly reducing the productivity index. In EOR, miscible gas injection can also give rise to asphaltene deposition. Characterizing these disparate observations is now performed within a simple overarching framework. Here, we combine asphaltene nanoscience, thermodynamics, and fluid mechanics to model asphaltene-rich fluid flow and asphaltene deposition that occur in reservoirs in geologic (or even production) time. This analysis successfully accounts for extensive measurements in several reservoirs in different stages of similar processes. Reservoir black oils with a late, light hydrocarbon charge experience asphaltene instability. This instability does not necessarily cause precipitation; instead, weak instability can cause a change in the nanocolloidal character of asphaltenes without precipitation. Consequently, this less stable asphaltene remains in the crude oil and is thus mobile. This process can result in fluid density inversions and gravity currents that pump asphaltene ‘clusters’ in oil over reservoir length scales relatively quickly in geologic time. These asphaltene clusters then establish very large asphaltene and viscosity gradients at the base of the reservoir. If the light hydrocarbon instability event continues, a regional tar mat can form. In contrast, if the light hydrocarbon charge is sufficiently rapid, the displacement of the contact between the original and new reservoir fluids overtakes and precipitates asphaltenes locally producing deposition upstructure often near the crest of the field. In this paper, several reservoirs are examined. Two reservoirs have massive, current gas charge and have bitumen deposition upstructure. Another reservoir is shown to be midway through a slower gas charge, with the asphaltene instability causing migration of asphaltenes from the top to the base of the oil column in the form of clusters creating large asphaltene gravity gradients. Another reservoir is shown to have this process completed yielding a 50 meter column of heavy oil at the base of the oil column underlain by a 10 meter regional tar mat. This integrated analysis enables a much simpler understanding of many production issues associated with asphaltenes and provides a way forward for treating disparate asphaltene problems within a single framework.
Environmentally Friendly Fracturing Fluid as Utilized in a Western Canada Sedimentary Basin Case Study
Authors: Nixon Tara , Tomszak Jay , Lawrence Sally , Richardson Lee , Hepburn Krista 
Published: October 2014

Abstract
In recent years, the oil and gas industry has been highly focused on reducing the environmental footprint caused by hydraulic fracturing fluids. This parallels society's fixation on developing "greener" technologies and processes. Environmentally friendly or "green" is a vague term referring to processes and products that reduce or eliminate any impact to human health and the environment (US EPA, 2014). Although this is a common goal among those in the oil and gas industry, there is a lack of structure around what defines "green." The definition varies across continents, governing bodies, companies, departments, and individuals, with each employing a different set of criteria they deem relevant. Developing a process for environmentally responsible fracturing without a clear and accepted definition is a cumbersome undertaking.
This paper describes a process by which the concept of safer and "greener" hydraulic fracturing operation can be accomplished, with a strong focus on the chemical components of the fracturing fluid. The discussion will center around: health and safety of personnel, environmental impact of utilized chemistries, geographical applicability in conjunction with corresponding local regulatory policies, and an in-house developed chemical hazard rating system. The application of this process will be described through a case study which includes more than 100 pumped intervals in multiple geographic areas. The case study provides: stimulation job designs, treatment reports, and production results.
Once a specific set of criteria has been established, a system that meets the aforementioned criteria needs to be developed. This process entails evaluation of each system component for environmental applicability and system performance. Additionally, through collaboration with chemical manufacturers, toxicologists, and fluid experts, the technical accuracy and applicability of toxicological data can be determined. A cradle-to-grave development of a foamed linear fluid system will be the example illustrated in this paper to showcase the development and implementation of a "green" hydraulic fracturing fluid system. This specific system encompasses a significantly reduced environmental profile in comparison to similar systems, while maintaining equivalent performance and overall cost to customer. The fluid system has been optimized and continues to be pumped with great success.