bluuebunny/crossref_metadata_2025_split huggingface dataset:
Pilot Testing Issues of Chemical EOR in Large Fractured Carbonate Reservoirs
Authors: Kiani Mojtaba , Kazemi Hossein , Ozkan Erdal , Wu Yu-Shu 
Published: October 2011

Abstract
Many world class large carbonate reservoirs leave behind at least half of the initial oil in place. Typically water injection is used to improve oil recovery while gas injection is used to maintain pressure or to promote oil gravity drainage. Immiscible gas injection, including injection of CO2, has been implemented on a large scale in only few fields for economic reasons. Furthermore, interest in using surfactants in large carbonate reservoirs has recently flourished. As a result, we began to investigate the viability of designing and conducting a manageable pilot test program in a large fractured carbonate reservoir using a single-well, dual-completion system to evaluate the efficacy of the surfactant oil mobilization and oil capture. However, pilot testing in large reservoirs is very expensive and requires a long time to complete. These issues are less problematic in pilot testing of small and thin reservoirs in onshore field.
In this paper we present the results of a conceptual model to simulate the performance of surfactant flooding in the above-mentioned pilot test configuration. Three different model formulations, having different approaches to gridding and grid-refinement, were used. These include the dual-porosity, dual-permeability, and conventional variable permeability-porosity formulations to simulate fracture-matrix interactions. Simulation of pilot tests using dual-porosity models shows that gravity is most effective during waterflood but not as effective during the surfactant injection while in the variable permeability-porosity fine-grid model the surfactant oil recovery is greater because both gravity and viscous displacement contribute. We also present a study using our in-house numerical simulator for dual-porosity, dual-porosity refined matrix, dual-porosity with adjustments for viscous displacement and variable permeability-porosity fine-grid models. Dual-porosity models with matrix refinement and viscous displacement give more incremental oil recoveries than the conventional formulation. Results are also compared with variable permeability-porosity fine-grid and coarse-grid models.
We will explain the reasons and will indicate which model is more reliable. In general the results of this study give an insight into the viability of using surfactant injection in thick carbonate reservoirs both in the pilot and production stage.
Viscous Fingering During Non-Thermal Heavy Oil Recovery
Authors: Doorwar Shashvat , Mohanty Kishore K. 
Published: October 2011

Abstract
Alkali-surfactant injection after a short waterflood can improve the recovery of very viscous oils of the order of 10,000 cp or above in corefloods. The goal of this research is to understand the pore-scale phenomenon behind these observations. Several secondary and tertiary floods using water, polymer, and alkali-surfactant slugs have been conducted in two-dimensional silicon micromodels to visualize the pore-scale displacement. The viscosity ratio controls the finger structure. As the viscosity ratio increases, the number of growing fingers (or branches) before breakthrough decreases. At large viscosity ratios of 103 or greater, the finger resembles DLA type fractal structures. Fractal dimensions of these structures vary from 1.4 to 1.6; that for DLA is 1.7. Injection of alkaline-surfactant solution after waterflood lowers the interfacial tension and forms oil-in-water emulsion at the sides of previously established water fingers. The tertiary oil recovery due to alkaline-surfactant flood increases with the surface area of the water fingers.
Discrete Modeling of Natural and Hydraulic Fractures in Shale-Gas Reservoirs
Authors: Gong Bin , Qin Guan , Towler Brian F. , Wang Hongyan 
Published: October 2011

Abstract
Interconnections of hydraulic fractures and pre-existing natural fractures provide key channels for shale gas to flow at economic rates. Micro-seismic mapping has proved that the resulting fracture system is much more complex compared to most conventional reservoirs due to the massive multistage, multi-cluster hydraulic fracturing stimulations. It becomes crucially important to develop advanced approaches to model such a complex system to better understand the recovery mechanisms and to optimize stimulation and development plans of shale gas reservoirs.
Recent advances in geological interpretations and micro-seismic mapping enable realistic modeling of hydraulic and pre-existing fracture network. Consequently, it is possible, to certain extent, to represent actual large-scale fracture distribution in reservoir modeling and simulation of shale gas development. In this paper, we apply the Discrete Fracture Modeling (DFM) approach to represent large-scale fractures individually and explicitly. This entails highly constrained unstructured gridding and construction of a connection (transmissibility) list of all neighboring cells. The geo-mechanical impact on micro-fracture system is modeled by "effective media", in which the rock permeability is sensitive to the stress change induced by hydraulic fracturing and pressure drawdown.
Simulations have been performed based on the detailed modeling of an actual shale gas reservoir with considering various mechanisms including adsorption/desorption, matrix-fracture transfer, and non-Darcy effects. Sensitivity studies by varying the production rate, pressure and hydraulic fracture parameters could be onducted to provide guidance on optimizing stimulation and production designs.
We have proposed and implemented an innovative simulation workflow that effectively captures multi-scale and multi-physics flow behavior caused by complex fracture system and geo-mechanical impact. A field-scale case study demonstrates that the proposed workflow certainly improves predictability in development of shale gas reservoirs.
B.A.R.T (Baseline Risk Assessment Tool): A Step Change in Traditional Risk Assessment Techniques for Process Safety and Asset Integrity Management
Authors: Petrone Annamaria , Scataglini Luciano , Fabio Francesco 
Published: October 2011

Abstract
The oil and gas industry has generally recognized, Process Safety and Asset Integrity Management as key drivers for ensuring, throughout Life Cycle of Oil or Gas plant, the ability of assets to perform their functions efficiently, preventing at the same time occurrence of Major Hazards such as fires, explosions and toxic gas releases thus protecting safety and environment and preserving asset value.
Several tools both qualitative and quantitative are available on the Market to support Process Safety and Asset Integrity Management. In early design phases, qualitative tools can be applied for preliminary evaluation of risk consequences while during subsequent project phases, Quantitative Risk Analysis (QRA) can be performed. However the above mentioned techniques have several shortcomings: QRA is a powerful design tool but can't give credit to operational controls, while qualitative risk analysis does not properly consider technical and process information.
This paper describes an innovative risk screening methodology for evaluating hazards and establishing priorities for risk reduction, supported by dedicated software: B.A.R.T (BAseline Risk assessment Tool) represents a step change in traditional techniques since combines simplified quantitative risk assessment methodology with bow-tie model to identify and assess potential hazards and risks, from upstream onshore/offshore process and activities. The sequence of any major incident is analyzed from identification of primary root causes up to determination of potential effects and impacts. Therefore, all existent safety barriers are identified and their prevention and mitigation risk reduction contributes included in the analysis. BART allows systematic monitoring of all major incident risks through prioritization and selection of effective control measures able to reduce likelihood and/or consequences of current risks.
In the paper methodology and rationale behind the tool are described through a real case application on an existing onshore Oil & Gas installation; main findings are highlighted and positively compared with alternative approaches.
Managing Large Enrollments: Plans to Ensure Students Receive a Quality Education
Authors: Schrader Susan , Todd Burt , Getty John 
Published: October 2011

Abstract
Much has been written about the current and future need for employees in the oil and gas industry. As the price of oil continues to climb again, prospects for a student graduating with a petroleum engineering degree look encouraging. This is helping to encourage high school students to consider studying petroleum engineering at the university level. However, the structure of many university systems and the lack of petroleum engineering programs make it difficult for the universities to ramp up to meet this surging enrollment. As a school experiencing record numbers, Montana Tech is experimenting with ways to manage enrollment, ensure quality and provide well trained students to enter the workforce.
A number of measures designed to manage enrollment and ensure quality have been either implemented or are in the proposal stage. The implemented measures include a new minimum GPA requirement on transfer students, the development of a pre-engineering program, the development of an anti-cheating policy, the enforcement of a 19 credit hour per semester rule, and a search for additional faculty. Proposed measures include allowing students only two attempts to pass courses in their major and establishing a common curriculum for incoming first year engineering students, after which they would apply to the petroleum department. An enrollment cap is proposed as a final measure to be considered after the effects of the above methods are evaluated.
Data currently being collected include class sizes, number of transfer students, class GPA's, and faculty student ratio. Preliminary observations show that some of the implemented measures are having an effect, as they indicate a stabilization of enrollment numbers and a better distribution of class grades.
Many of the institutions that offer a petroleum engineering degree are facing the same enrollment issues. The evaluation of these methods may lead to approaches that can be applied at other institutions, allowing for petroleum education to better able meet the needs of the industry.
Modeling of Multi-Component Flow in Porous Media with Arbitrary Phase Changes
Authors: Voskov D. V. 
Published: October 2011

Abstract
I present a novel computational framework for simulating flow in porous media for mixtures having an arbitrary number of phases. This framework is designed to keep a unified computational structure for different nonlinear formulations and complex physical models. That includes generic phase appearance/disappearance treatment, efficient linear solver typical for mixed types of unknowns, finite volume discretization using flexible spatial stencil etc. The behavior of components in any phase is computed using mixed phase equilibrium assumptions. This type of simulation is very important for modeling of natural and industrial processes, such as development of natural hydrocarbon resources, including gas-hydrates, CO2 injection into hydrocarbon reservoirs and saline aquifers, and for modeling of thermal processes. In this framework I use a Fully Implicit (FI) time approximation with general extension to the Adaptive Implicit Method (AIM) using flexible algebraic reduction. The framework is built on top of an Automatic Differentiation with Expression Templates Library (ADETL) which generates the corresponding derivatives for any nonlinear relation and helps to construct Jacobian matrix for the nonlinear solver. Phase behavior for the new framework is calculated using Compositional Space Parameterization (CSP) approach, which helps to improve both efficiency and robustness of the standard Equation of State (EoS) computations. Within this simulation framework, the nonlinear behavior of different variable sets, including both natural and mass-type variables is investigated. The general extension of two-phase variable substitution is used to handle the phase appearance and disappearance for systems with arbitrary numbers of phases. Examples will be presented including different types of CO2 injection in a hydrocarbon reservoir, such as miscible and immiscible two-phase CO2 injection, thermal injection of CO2+steam (three-phase), and cold CO2 injection (three phase with the second liquid CO2-rich phase).
Fuel Formation During In-Situ Combustion of Heavy Oil
Authors: Hascakir B. , Ross C. M. , Castanier L. M. , Kovscek A. R. 
Published: October 2011

Abstract
In-situ combustion (ISC) is a successful method with great potential for the production of heavy oil. Application of ISC is limited, however, because the process is complex and not well understood. A significant open question for ISC is the formation of coke or "fuel" in correct quantities that is sufficiently reactive such that combustion is sustained. We study ISC from a laboratory perspective in one-meter long combustion tubes that allow monitoring of the progress of the combustion front using X-ray computed tomography (CT). Two crude oils with API gravities of 12 and 9 are studied. Images of oil movement and banking in situ are obtained through appropriate analysis of the spatially and temporally varying CT numbers. Combustion tube runs are quenched prior to front breakthrough at the production end thereby permitting a post mortem analysis of combustion products and in particular of the fuel (coke and coke-like residues) just downstream of the combustion front. Fuel is analyzed using both scanning electron microscopy (SEM) and X-ray photoelectron spectroscopy (XPS). XPS and SEM results are useful to identify the shape, texture, and elemental composition of fuel in the X-ray CT images. The SEM and XPS results aid in differentiation among combustion tube results with significant and negligible amounts of clay minerals. Initial results indicate that clays increase the surface area of fuel deposits formed and this aids combustion. Additionally, comparisons are made of coke-like residues formed during experiments under an inert nitrogen atmosphere and coke-like residues from in-situ combustion. Study results contribute to an improved mechanistic understanding of ISC, fuel formation, and the role of mineral substrates in aiding or impeding combustion. CT imaging permits inference of the width and movement of the fuel zone in situ.
Long and Stuck E-Line - Probable Root Cause Failure Analysis and Fishing Success Story
Authors: Abdul Razak M. Hairi , Azhar M. , Samsu M. 
Published: October 2011

Abstract
Angsi field is one of the major oil and gas producers in offshore Peninsular Malaysia. Highly deviated wells with average depth of 3500 meters represent of about 70% of total wells in Angsi. Perforation and mechanical water shut-off with bridge plug using E-line are common in this type of wells. E-line tractor will be used to run in hole whenever the operator faced difficulties to descend further into target depth. In one instance on such operation, a bridge plug was set at 4900m-MDTHF, while POOH, the E-line stucked. A signal was sent to disconnect the BHA electronically, but failed. Simultaneously, THP slowly built up to 800 psi, an indication that the bridge plug was either not properly set or unset. After exhausting all available options, the E-line cable was cut at BOP with 4860 meters of cable left in hole. Later, braided line open hole fishing operation was started using 3/16 in cable. Set of specially fabricated cable cutter, weight bar and fishing tool was used to compliment the complex work program. At the end, the entire 4860 meters of cable fish was successfully recovered. The E-line cable was sent to base to establish the root cause for the operation upset. This paper details the overall E-line post mortem and diagnostic, fishing work program, the special fishing tool that the field operator and braided line contractor fabricated specifically for this job, well control and project lessons learned.
Surface Area and Pore-Size Distribution in Clays and Shales
Authors: Kuila Utpalendu , Prasad Manika 
Published: October 2011

Abstract
One of the biggest challenges in estimating transport and storage properties of shales is a lack of understanding of their complete pore size distributions. Shale matrix has predominantly micro (pores less than 2 nm diameter) to meso-pores (pores with 2-50 nm diameter). These small pores in shale matrix are mainly associated with clay minerals and organic matter. Thus, comprehending the controls of clays and organic matter on the pore-size distribution is critical to understanding the shale pore network. Historically mercury intrusion techniques are used for pore-size analysis of conventional reservoirs. However, for unconventional shale reservoirs, very high pressures (&gt; 60,000 psi) would be required for mercury to access the full pore-structure which has potential pitfalls. Nitrogen gas adsorption techniques can be used to characterize materials dominated by micro and mesopores (2-50 nm). A limitation of this techniques is that it fails to measure large pores (diameter &gt;300 nm). In this study, we have used a combination of nitrogen gas adsorption and mercury intrusion to study the spectrum of pore-sizes in shales and clays.
Our results on pure clay minerals show that (i) clays have a mulit-scale pore-structure at different dimensions, (ii) Micropores are associated with montmorillonite clays but not with kaolinite, (iii) compaction results in decrease in pore volume and reduction of pore-size in the macropores of the clays while the micropores are shielded from the effect of compaction, and (iv) in natural shales, mineralogy controls the pore-size distributions for shales and presence of micropores in natural shales can be correlated with the dominance of illite-smectite type of clays in the rock.
New Algorithms and Integrated Workflow for Tight Gas and Shale Completions
Authors: Cipolla C. , Weng X. , Onda H. , Nadaraja T. , Ganguly U. , Malpani R. 
Published: October 2011

Abstract
Multi-stage stimulation has become the norm for unconventional reservoir development. How many fracture treatment stages and perforation clusters are optimal? What is the ideal spacing between perforation clusters? Where is the best location for each fracture treatment stage? These are critical and difficult questions to answer when designing completions for tight gas and shale reservoirs and the approach to answering these questions can differ considerably for vertical and horizontal wells in different lithologies. In the past, optimizing the number and location of fracture treatment stages has been primarily a manual, time intensive process, resulting in a "cookie cutter" approach that may not properly account for vertical and lateral heterogeneity. This paper details new algorithms and an integrated workflow that could improve fracture treatment staging in both vertical and horizontal wells.
The primary obstacles to optimizing completions in tight gas and shale reservoirs have been the absence of hydraulic fracture models that properly simulate complex fracture propagation which is common in many reservoirs, efficient methods to create discrete reservoir simulation grids to rigorously model the hydrocarbon production from complex hydraulic fractures, automated fracture treatment staging algorithms, and the ability to efficiently integrate microseismic mapping measurements with geological and geophysical data. One of these obstacles has been overcome with the recent development of complex hydraulic fracture models (Meyer and Bazan, 2011, Weng et al., 2011, Xu et al., 2010). However, the remaining obstacles are just now being addressed.
Algorithms for efficient and rigorous design of multi-stage completions are detailed in the paper. Separate staging algorithms have been developed for vertical and horizontal wells that utilize detailed stress, rock mechanical, and image measurements (i.e. - natural fracture identification) to select stage intervals and perforation locations. The staging algorithms incorporate "fit-for-purpose" hydraulic fracture models ranging from standard planar pseudo 3D models to newly developed complex fracture models, depending on the environment. The algorithms are seamlessly integrated with microseismic measurements, a common Earth Model, and automated routines to discretely grid the complex fracture geometry for reservoir simulation. A common software platform enables the efficient utilization of multiple data sources from multiple disciplines. The application of the newly developed algorithms and integrated workflow is illustrated using examples from tight gas and shale reservoirs.
Improved Precision Magnetic Resonance Acquisition: Application to Shale Evaluation
Authors: Hook Peter , Fairhurst David , Rylander Erik , Badry Rob , Bachman Nate , Crary Steve , Chatawanich Kirk , Taylor Tim 
Published: October 2011

Abstract
Traditional magnetic resonance (MR) acquisition modes tend to focus on the hydrocarbons found in high-porosity permeability rocks. This requires acquisition optimized for longer relaxation times (T1 and T2). Interest in shale resources (gas and oil) has resulted in a reexamination of MR acquisition sequences. Shale hydrocarbon resources are usually in rocks with very fast relaxation times for which traditional application schemes are not optimal.
MR acquisition sequences always involve tradeoffs. Modifying current acquisition schemes to improve precision involved increasing the number of short wait-time sequences. Analytical and Monte Carlo modeling were used to evaluate the tradeoffs between different options. The effect of the inversion parameters on the results was also studied to determine the optimal acquisition sequence and processing parameters for shale resources.
The improved precision from this acquisition is demonstrated with field data. Case studies demonstrate how the improved precision of the MR measurement, combined with other logs, provides a better estimate of the organic or kerogen content of the formation; this is particularly useful in areas where correlations to density or other logs have not yet been developed. High-precision MR pore size information in pilot wells is used to highlight the best layers for horizontal wellbore placement.
A Resident's View of Urban Operations
Authors: Fanchi John R. , Fanchi Christopher J. 
Published: October 2011

Abstract
Gas shales are an increasingly important source of natural gas found around the world. They can extend under population centers and require urban operations. The public perception of gas shale development operations can have an impact on the regulatory environment. The purpose of this paper is to report on the public perception of issues associated with urban operations in the Barnett Shale development area.