bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas Drying Using a Pass-Through Hydrate Crystallizer
Authors: Tatro S. R. , Sheps K. M. , Brazel L. A. , Osegovic J. P. , Max M. D. 
Published: December 2007

Abstract
Unwanted hydrate (Clatrhrate) formation is a major flow assurance issue for exploitation of hydrocarbon resources, especially in the more remote and colder environment of offshore deep water. Unwanted hydrate may form as the temperature of extracted gas and oil falls following its removal from its reservoir and the pressure, temperature, and water concentration become suitable for hydrate formation. Preventing unwanted hydrate formation is presently accomplished mainly using inhibitors that retard the nucleation, growth, and agglomeration of hydrate or through the crystallization in petroleum of many crystallites (cold flow).
A new approach to preventing the formation of unwanted hydrate is described. In this method, the removal of water from the pipeline system, without which unwanted hydrate cannot form, is the objective. It is not necessary to remove all water; but only to keep the vapor pressure of dissolved water low enough so that unwanted hydrate will neither nucleate nor grow. Water is extracted through the controlled crystallization of hydrate, which extracts dissolved water from the hydrocarbons in an innovative manner.
In the proposed method, hydrate is formed on surfaces of a permeable heat exchanger through which the hydrate is dissociated and the water removed. Dynamically forming hydrate on the exterior (pipeline side) and dissociating on the interior side of the porous surface (in a low pressure chamber) allows for collection and removal of water from the pipeline. This eliminates the potential for unwanted hydrate formation of the mixture down stream. More than one water removal stage in a pipeline may be required. The method holds promise to achieve hydrate flow assurance on the seafloor without the use of chemicals or extensive industrial plants at a very low energy cost.
Characterization of the Chemical Properties of Crude Oils To Explain Observed Asphaltene Inhibitor Specificity
Authors: Squicciarini Michael , Yen Andrew , Smith Donald F. , Rodgers Ryan P. , Marshall Alan G. , Klein Geoffrey C. 
Published: December 2007

Abstract
Asphaltenes are typically defined by solubility as benzene soluble and pentane or heptane insoluble. The deposition and precipitation of flocculated asphaltenes in the oilfield can severely reduce the permeability of the reservoir, cause formation damage and can also plug-up the wellbore and tubing. Asphaltene inhibitors have been used with success in preventing these precipitation/deposition problems. Based on laboratory and field tests, it was found that asphaltene inhibitor performance is oil specific. We present results obtained by analyzing crude oil from two different geographic regions. The crude oil and asphaltene samples were characterized by a variety of analytical techniques including total acid number (TAN), elemental analysis, and Fourier transform infrared spectroscopy (FT-IR). Electrospray ionization Fourier transform ion cyclotron resonance mass spectrometry (ESI FT-ICR MS) was used to further characterize the two different crudes and their associated asphaltenes. Substantial differences between the relative abundance of heteroatom-containing compound classes were found for the two oils. The relationship between these findings and asphaltene inhibitor performance specificity is discussed. The results from this study provide a greater understanding on how different inhibitors interact with asphaltenes thus enhancing the ability to develop the next generation of asphaltene inhibitors.
Coupling Chemical Kinetics and Flashes in Reactive, Thermal and Compositional Reservoir Simulation
Authors: Kristensen M. R. , Gerritsen M. G. , Thomsen P. G. , Michelsen M. L. , Stenby E. H. 
Published: December 2007

Abstract
Phase changes are known to cause convergence problems for integration of stiff kinetics in thermal and compositional reservoir simulations. We propose an algorithm for detection and location of phase changes based on discrete event system theory. The algorithm provides a robust way for handling the switching of variables and equations required when the number of phases changes. We extend the method to handle full phase equilibrium described by an equation of state. Experiments show that the new algorithm improves the robustness of the integration process near phase boundaries by lowering the number of convergence and error test failures by more than 50% compared to direct integration without the new algorithm.
To facilitate the algorithmic development we construct a virtual kinetic cell model. We use implicit one-step ESDIRK (Explicit Singly Diagonal Implicit Runge-Kutta) methods for integration of the kinetics. The kinetic cell model serves both as a tool for the development and testing of tailored solvers as well as a testbed for studying the interactions between chemical kinetics and phase behavior. A comparison between a K-value correlation based approach and a more rigorous equation of state based approach to phase equilibrium shows that phase behavior may significantly impact the reaction paths.
Fluid-Loss Control Improves Performance of Viscoelastic Surfactant Fluids
Authors: Huang Tianping , Crews James B. 
Published: December 2007

Abstract
Viscoelastic surfactant (VES) fluids have been widely used as gravel-packing, frac-packing and fracturing fluids for more than a decade because the fluids exhibit excellent rheological properties and maintain low formation damage characteristics compared with crosslinked-polymer fluids. Due to its non-wall-building property, VES fluid has much higher fluid leak-off into the reservoir matrix than wall-building polymer fluid. For frac-packing this has limited VES use to reservoirs with permeability of less than 1000 md and, in most cases, less than 250 md. Excessive fluid leak-off also significantly increases the cost of treatment.
This paper will introduce new technology for controlling the fluid loss of VES fluids to about 300°F. New fluid loss control agents have been developed that, through chemisorption and surface charge attraction, associate with VES micelles to produce a pseudo-filtercake of viscous VES fluid that significantly reduces the rate of fluid loss. Use of this technology will reduce the VES fluid volume required for a given treatment by up to two-thirds and extends the permeability range of VES fluids to about 2000 md. The fluid loss control agents are slowly water-soluble particles that are used at relatively low concentrations. The particles will be dissolved and/or flowed back with the producing fluid. The rate of the pseudo-filtercake clean-up is enhanced by use of internal VES breakers. The results of rheology, leak-off, and core flow tests will be presented for the VES fluid systems at temperatures 150°F and 250°F.
Operator-Based Multiscale Method for Compressible Flow
Authors: Zhou H. , Tchelepi H. A. 
Published: December 2007

Abstract
Recently, multiscale methods have been developed for accurate and efficient numerical solution of large-scale heterogeneous reservoir problems. A scalable and extendible Operator Based Multiscale Method (OBMM) is described here. OBMM is cast as a general algebraic framework of the multiscale method. It is very natural and convenient to incorporate more physics in OBMM for multiscale computation.
In OBMM, two multiscale operators are constructed: prolongation and restriction. The prolongation operator can be constructed by assembling basis functions, and the specific form of the restriction operator depends on the coarse-scale dis-cretization formulation (e.g., finite-volume or finite-element). The coarse-scale pressure equation is obtained algebraically by applying the prolongation and restriction operators on the fine-scale flow equations. Solving the coarse-scale equation results in a high quality coarse-scale pressure. The fine scale pressure can be reconstructed by applying the prolongation operator to the coarse-scale pressure. A conservative fine-scale velocity field is then reconstructed to solve the transport equation.
As an application example, we study multiscale modeling of compressible flow. We show that the extension of modeling from incompressible to compressible flow is really straightforward for OBMM. No special treatment for compressibility is required. The efficiency of multiscale methods over stan dard fine-scale methods is retained by OBMM. The accuracy of OBMM is demonstrate by several challenging cases including highly compressible multiphase flow in a strongly heterogeneous permeability field (SPE 10).
The Method of Distributed Volumetric Sources for Calculating the Transient and Pseudosteady-State Productivity of Complex Well-Fracture Configurations
Authors: Valkó P. P. , Amini S. 
Published: December 2007

Abstract
The method of Distributed Volumetric Sources (DVS) is developed to solve problems of transient and pseudo steady state fluid flow. The basic building block of the method comprises calculation of the analytical response of a rectilinear reservoir with closed outer boundaries to an instantaneous volumetric source, also shaped as a rectilinear body. The solution also provides the well-testing derivative of the response to a continuous source in analytical form. This can be integrated over time to provide the pressure response to a continuous source. For production engineering applications, we cast the results into a transient/pseudo-steady productivity index form. The new method is validated through comparison to results of some of the well known well-testing solutions for simple configurations such as vertical wells with full and partial penetration, horizontal wells with unform flux and infinite conductivity, and fractured wells with uniform flux, finite or infinte conductivity. The results show a very good agreement with the existing models. The main advantage of the new solution is its applicability over the more complex fracture/well configurations, some of which is studied in the paper.
The new method has shown to provide a fast, robust, and reliable way to pressure transient analysis, and well performance prediction whenever complex well/fracture configuration is considered.
Predicting Productivity of Multiple-Fractured Horizontal Gas Wells
Authors: Zhu D. , Magalhaes F. , Valkó P. P. 
Published: December 2007

Abstract
In low-permeability gas reservoirs, horizontal wells have been used to increase the reservoir contact area, and hydraulic fracturing has been further extending the contact between wellbores and reservoirs. This paper presents an approach to evaluate horizontal well performance for fractured or unfractured gas wells, and a sensitivity study of gas well performance in low permeability formation. A newly-developed Distributed Volumetric Sources (DVS) method was used to calculate dimensionless productivity index for a defined source in a box-shaped domain. The unique features of the DVS method are that method can be applied to both transient flow and pseudo-steady state flow with a smooth transition between the boundary conditions. By describing the geometric dimensions of the sources, productivity index for a horizontal gas well or a longitudinal fracture along a horizontal well is readily calculated. For transverse fractures with infinite conductivity or uniform flux, the superposition principle is used for multiple sources in the system. Wellbore frictional pressure drop is coupled with the inflow calculation from fractures.
The study compares the productivity of horizontal wells versus horizontal well(s) with hydraulic fractures. The effects of parameters such as reservoir permeability and anisotropy ratio, horizontal well spacing and placement, and orientation of fractures along a horizontal wellbore are also presented in the paper. The objective is to optimize well design based on the maximum productivity and economic benefit. The results of the study show that the performance of horizontal wells can be very sensitive to the vertical permeability of the formation. In low vertical-permeability formation (high anisotropic ratio), fractures improve well performance significantly. In large drainage area, multiple-well placement, even with shorter wellbore length, increases productivity, compared with single-well placement. The study provides insight on optimization of production performance in low-permeability gas reservoirs.
Evaluation and Optimization of Low-Conductivity Fractures
Authors: Manrique J. F. , Poe B. D. 
Published: December 2007

Abstract
This paper presents the results of an investigation of the design and analysis of low conductivity fractures. The mathematical model used in this work is a practical alternative to estimate the degree of stimulation by means of a Stimulation Index (SD) and for evaluating the efficiency of wells with low conductivity hydraulically induced fractures. We utilize the dimensionless productivity index solution (JD) for finite-conductivity vertically fractured wells in closed rectangular bounded reservoirs and their corresponding pseudo-steady state shape factors under boundary-dominated flow conditions. Designing the optimum stimulation fracture treatment in this case is more heavily weighted on the achievable Stimulation Index (SD), for a given set of reservoir parameters and job sizes and on optimization of the flow rate and cumulative production.
We discuss the reasons for and alternatives to conductivity impairment within the fracture; fracture cleanup, width changes, conductivity degradation with time and stress effects are discussed. Field evidence indicates how these effects affect the fracture conductivity, affecting deliverability and inflow performance.
A practical performance criterion that focuses on conductivity improvement is used to improve performance of fractured wells. We use guidelines for choosing from the available fracture stimulation alternatives to focus on the technical merit of each technique and their application for improving fracture efficiency and deliverability, and include the use of higher breaker concentrations, lower polymer loads, and use of proppant with better resistance to stress (conductivity and permeability). Field examples and applications are provided for fracture stimulation evaluation and optimization.
This paper also introduces a way to evaluate and optimize the financial performance of fracture treatments. The financial criteria link the well deliverability or well potential (technical limits) to the fracture costs (or total well costs or OPEX).
Optimization is achieved by Net Present Value maximization and by generating an incremental return on investment due to the optimization steps. In this manner, we can financially quantify the engineered options for increasing well performance and optimization of the Stimulation Index (SD) while taking into account the associated costs into a financial model.
Sandstone Matrix Stimulation Can Improve Brownfield Oil Production When the Chemistry and Procedures Are Correct
Authors: Yong Yin-Chong , Shaikh Karim , Queiros Joao , Song Yan , Srisa-ard Surasak , Chan Keng Seng , Samuel Mathew 
Published: December 2007

Abstract
Improving oil and gas production from the Brown Fields is now more important than ever to the operating companies, as the oil price remains record high. Matrix stimulation is often preferred as it could generate additional production gain with relatively low level of investment.
In the recent acidizing campaign in Brunei, a particular challenge was the flowback of tubing pickling and spent acids, and neutralization of the spent acid on the surface. A series of effective methodologies for the stimulation of offshore multi-layer sandstone oil reservoirs was implemented. The chemistry and art of four different acidizing methods involving Tubing Pickling, Bullheading, Diversion and Coiled Tubing placement were used. Stimulation of over forty wells utilizing different acid systems and procedures resulted in noticeably different production gains. The short and long term results are correlated with the stimulation procedures and practices. The present paper describes a comparison of procedures and production gains during these acid stimulation treatments. The cost, logistics and operational constraints due to specific Brunei offshore environment and conditions will also be discussed. Post-treatment production gain is correlated with the efficiency and timing of the flowback process.
Use of computer-based virtual laboratory tool for the fluid selection, coreflow laboratory testing for the fluid optimization at downhole conditions and evaluation of fine migration tendencies were investigated before the treatment. The results were compared with the one from other operators in the same environment and reservoir conditions. Review of post acidizing results came up with recommendations and lesson learnt for future campaigns. This effort will certainly enhance the success ratio of the sandstone acidizing treatments.
Significance: Developed lessons learnt to increase the success ratio of sandstone stimulations.
Advanced Mud Logging: From Archie's Dream to Reality
Authors: Loermans Ton , Kanj Mazen , Bradford Charles 
Published: December 2007

Abstract
Advanced Mud Logging (AML) has been named "Archie's Dream" since AML will fulfil what must have been Archie's dream. That is: obtain high resolution rock parameters as quickly as (wireline) logs. Up until the recent past, the idea of obtaining quantitative petrophysical parameters from mudlogging seemed a dream. However, AML is moving towards continuous, real time determination of rock and fluid parameters from drill cuttings, drilling parameters and mud (gas) returns, in aid of well evaluation and reserves calculation.
The value of (to a large extent conventional) mudlogging for hydrocarbon productivity prediction is already significant, confirming that mud gas measurements, if properly analysed, provide very valuable information for production testing decisions.
Through application of rock typing techniques and rock catalogues, amongst others, reasonable electrical parameters, which normally require elaborate core measurements, can be obtained near real time from cuttings descriptions.
Tests on a method for direct permeability measurement on cuttings confirm the potential for this method for many circumstances.
Micro and nano indentation techniques are being tested to provide rock mechanical properties also from drill cuttings.
As the techniques to determine several of the key parameters are becoming more firmly established, AML is entering the stage of actually providing a significant input for a complete formation evaluation.
State of the Art – Natural Gases Viscosity under Reservoir Conditions
Authors: Gawish Ahmed , Al-Homadhi Emad 
Published: December 2007

Abstract
The influence of fluid viscosity on flow is especially important in petroleum reservoirs. Gas is now a highly desirable hydrocarbon resource. An accurate prediction of transport properties of natural gases is very important in the design and operation of fluid transportation, production, and processing. Viscosity is one of these properties. Many viscosity correlations are available but each has limitations in the range of applicability1–7. Only the Carr et al8–12. charts include the correction for gas impurities and reservoir pressure and temperature. Using Carr et al. charts you have to follow five steps to find the natural gas viscosity at any condition. As a results, some errors and inaccurated will occur and more time will be consumed. Standing13’14 proposed a convenient mathematical expressing for calculation the viscosity of the natural gas at atmospheric pressure and reservoir temperature, μ1. Standing also presented equations for describing the effects of impurities on μ1. Dempsey15 expressed the viscosity ratio (the viscosity at high pressure to the viscosity at 1 atm), by using reduced pressure and temperature.
Using the Standing equation and the slightly revised Dempsey equation, the natural gas viscosity at high pressure can be found by one step only. It includes all corrections for gas impurities. Its also includes any condition at the reservoir pressure and temperature.
On the Use of Acid and Proppant Fracturing Treatments to Develop Carbonate and Sandstone Reservoirs – Field Examples
Authors: Rahim Zillur , Bartko Kirk 
Published: December 2007

Abstract
For the past five years Saudi Aramco has implemented different stimulation techniques to develop its gas reservoirs.1,2 With the growing demand in gas and the need to meet the gas processing plant capacities' the stimulation treatments have provided excellent completion means for enhanced gas recovery. This paper provides an overview of the various stimulation methods used and presents the challenges encountered in different fields due to reservoir heterogeneity' low permeability, condensate dropout and banking, sanding of unconsolidated formations' high pressure and temperature, etc., and the systematic approach used to encounter such challenges to optimally develop the reservoirs. Several field examples are cited to show the success of stimulation technology.
A Fully-Implicit Fully-Coupled Well Model for Parallel Mega-Cell Reservoir Simulation
Authors: Fung Larry S. K. , Su HoJeen , Tan Cheng T. , Hemanthkumar Kesavalu , Pita Jorge A. 
Published: December 2007

Abstract
Various production and injection processes with the attendant well controls represent the most important boundary conditions for a reservoir simulator. Therefore, it is of significant interest that the modeling of wells be done in an accurate and robust manner. Recent development of horizontal wells, maximum reservoir contact (MRC) wells, and smart wells further increase the demand for more comprehensive numerical treatment of wells. In mega-cell simulation, wells can be perforated in more than one hundred computational layers known as well cells whose layer productivity indices (LPI) can vary widely. Contributions of inflow from each of the well cells make up the total target well rates. Collectively, the well cells communicate through the wellbore pressure boundary condition. A converged time step means the material balance is satisfied for all grid cells plus all the well constraint equations active at that particular time step.
In this paper, the fully-implicit fully-coupled treatment of well constraint equations in the context of parallel mega cell reservoir simulation is described. In parallel computation utilizing several processors, grid cells are partitioned roughly evenly into these processing units. A single well can traverse several grid cells residing in multiple processors where information pertaining to well inflow must be gathered to construct the well constraint equations. These well equations are unstructured and are solved simultaneously with the multi-million grid cell material balance equations. The paper describes the well modeling equations and the numerical procedures for solving these equations in a fully-implicit fully-coupled manner. Furthermore, methods for treating fully implicit wells in several special simulation features such as local grid refinement, dual porosity dual permeability, and complex MRC wells with flow hydraulic calculation are also included. A number of examples on the advantages of applying the implicit well model as compared to the less rigorous well treatments are also discussed. In addition, for some mega-cell simulation cases, we compare the field-scale performance and parallel scalability of the methods.