bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling of a Large Gas-Capped Reservoir With Areal and Vertical Variation in Composition
Authors: Hamoodi A. N. , Abed A. F. , Grabenstetter Jim 
Published: December 2007

Abstract
Compositional modeling of one of the giant middle east reservoirs overlain by a primary gas cap is presented. The reservoir is 43 Km long and 23 Km wide and is noted for its large variation in composition in the areal extent. The H2S content varies from above 10 mole % in the North to less than 1% in the South.
Current technology in compositional reservoir simulators accounts for vertical variation in composition; however the problem presented for this reservoir includes significant areal variation in composition. This paper presents a successful attempt in addressing this challenge.
Reservoir Fluid sampling included 11 bottom hole and 5 recombined surface oil samples. 10 samples are considered representative of the virgin reservoir oil. Experimental data available include extended true boiling point analysis up to C20+ of two samples, constant composition expansion, differential liberation and oil viscosity measurements. One gas cap sample was recently collected. The sample experimental data include analysis up to C20+, constant composition expansion and constant volume depletion measurements. Additional experimental data available include a swelling test and two slim tube displacement tests.
An equation of state model, capable of accurately predicting the wide range of experimental data available, spanning the full compositional spectrum of the reservoir fluid, was developed. The methodology adopted in the development and validation of the equation of state characterization is presented.
An isobar map of the saturation pressure and areal compositional distribution maps based on reservoir fluid analysis were constructed and assumed representative of the mid-reservoir depth of the most productive layer. By applying the saturation pressure versus depth gradient, base saturation pressure maps for all reservoir layers were derived.
The compositional variation was correlated against mid-reservoir depth and saturation pressure. The total reservoir compositional distribution was then determined based on the average gradient of composition versus saturation pressure, and base saturation pressure and compositional distribution maps.
The model was successfully initialized in non-equilibrium mode by defining the composition for each grid block. Stability of the model was verified, and the calculated saturation pressure distribution per layer was validated against the established distribution based on collected samples and the saturation pressure versus depth correlation. Original in-place fluid volumes were compared to black-oil model initialization data, including the original oil in place, solution gas in place and free gas volumes.
The model size is 39,780 grid blocks, 7 components and includes 400 wells. The memory requirement is 380 Megabytes.
Theory and Measurements of Fates of H2S Scavengers
Authors: Elliott J. R. , Raymond M. B. , Kalpakci Bayram , Magri N. F. 
Published: December 2007

ABSTRACT
The partitioning of the H2S scavengers/biocides, glutaraldehyde and acrolein, between the oil and the aqueous phases has been determined. The effect of the presence of salt on the partition coefficients has also been studied for salt concentrations from 0 wt% to 10 wt%. Acrolein was found to partition 47% to 66%, and glutaraldehyde
2% to 0.3%, to the organic phase, in a heptane/brine system. The effect of aldehyde concentration has been evaluated, from 2-10 wt% for acrolein and 5-50 wt% for glutaraldehyde. Theoretical analysis has been achieved, correlating the acquired experimental data and available literature data using the Elliott, Suresh, Donahue, equation of state1 (ESD-EOS).
Characterization of High Molecular Weight Compounds —Implications for Advanced-recovery Technologies
Authors: Wavrek D. A. , Dahdah N. F. 
Published: December 2007

Abstract
The failure of traditional methods to predict the precipitation of solid phases can be partially attributed to an inaccurate understanding of the molecular composition of the high molecular weight (HMW) components. This paper reports our progress in developing analytical techniques for direct determination of compounds up to C90 with readily available instrumentation. We believe this technology will help lead to production strategies that are more efficient and allow better estimates of production costs by more accurate forecasting of production problems.
Asphaltene Dispersants as Demulsification Aids
Authors: Manek M. B. 
Published: December 2007

Abstract
Destabilization of petroleum asphaltenes may cause a multitude of problems in crude oil recovery and production. One major problem is their agglomeration at the water-oil interface of crude oil emulsions. Once agglomeration occurs, destabilized asphaltenes can form a thick pad in the dehydration equipment, which significantly reduces the demulsification rate.
Certain polymeric dispersants increase asphaltene solubilization in hydrocarbon media, and when used in conjunction with emulsion breakers, facilitate the demulsification process. Two case studies are presented that demonstrate how asphaltene dispersants can efficiently inhibit pad formation and help reduce demulsifier dosage. Criteria for dispersant application and selection are discussed, which include the application of a novel laboratory technique to assess asphaltene stabilization in the crude oil. The technique monitors asphaltene agglomeration while undergoing titration with an incompatible solvent (precipitant). The method was used to evaluate stabilization of asphaltenes in the crude oil and to screen asphaltene dispersants.
Education Needs of the Oil Industry's Engineering Staff
Authors: Smith Charles R. 
Published: December 2007

Abstract
From the humble beginning of the oil industry at Titusville, Pennsylvania, in 1859 to the giant that it is today, the use of the professionally educated individual has been a professionally educated individual has been a mainstay of the energy business—be this in companies, in governmental agencies, in consulting groups, or in the universities. The dominant role of the engineer dictates that he be current and be capable of adjusting to the evolving technology. Responsibility of continuing and renewal education lies with the individual, with needed support from the employer, the professional societies, from the universities, and from the various entities that provide educational services. There is reason to behave that an arbitrary two-week reeducation period per year, with a sabbatical leave of six months (minimum) every five years, should be the goal of the aggressive engineer, the requirement of each and every employer, and the personal goal of each self-employed engineer. Additional regional continuing education centers need to be established—similar to the Kellogg Center at the University of Oklahoma.
Introduction
Much has been said about the state of the engineering profession—especially after the launching of the first Sputnik. Since this historic date in 1957, the applied sciences have received much attention and considerable federal funding, though not necessarily in areas directly benefiting the oil industry. However, the United States' emphasis on space technology did culminate in the landing of two men on the moon in July of 1969. With less journalistic impact, but with more direct benefit to the man on the street, the oil industry has managed to provide the world with an economical energy source that has primarily changed lives for the better. Of the problems that have been created, pollution is now receiving the most attention. Much of the solving will be done by engineers of all ages but mainly by those who have remained mentally flexible and who have kept on top of, or at least current with, advancing technology. Where did it all begin?
Background
It may be speculated that education began with the drilling of the Drake well in Titusville, Pennsylvania, or possibly before this date. A sizeable patent literature existed prior to 1900. Uhl points out that by the prior to 1900. Uhl points out that by the early 1900's, engineers and geologists were transmitting to their apprentices, through articles and through informal courses and study groups, the knowledge gleaned from the actual drilling for and the production of oil and gas. Early AIME and USGS publications became the main recorder of such activities.
The Effect of Surface Active Agents on the Relative Permeability of Brine and Gas in Porous Media
Authors: Conway Michael W. , Smith Kevin , Thomas Todd , Schraufnagel Richard A. 
Published: December 2007

ABSTRACT
Surface active agents are included in most aqueous treating fluids to improve the compatibility of aqueous fluids with the hydrocarbon containing reservoir. A review of the literature indicates very little core flow data to describe the effects to be expected. Traditionally, it is believed that the reduced surface tension will reduce capillary pressure and enhance the recovery of water after the treatment. The reduced water saturation is then believed to result in higher effective gas saturation and higher relative permeability to gas after the treatment.
Scanning Probe Microscopy: Sulphate Minerals in Scales and Cements
Authors: Hall Christopher 
Published: December 2007

Abstract
The principles of scanning probe microscopy (SPM) are illustrated with examples from oilfield mineralogy, particularly emphasising sulphate minerals involved in scale formation and cement hydration chemistry. The topography of the (010) cleavage surface of gypsum observed by atomic force microscopy shows atomically flat terraces separated by shallow steps often only one unit cell high. SPM allows direct observation of processes on mineral surfaces while they are in contact with solutions. The dissolution etching and crystal growth of gypsum and barite are discussed and rates of step migration estimated. The orientation of steps is related to the crystallographic axes. The action of phosphonate crystal growth inhibitor on gypsum and of a chelating scale solvent on barite are also shown. The multiphase microstructure of an oilwell cement clinker is described in relation to its hydration chemistry in contact with water and its reaction with sulphate ions.
Examination of the Change in Returning Molecular Weight Obtained During Inhibitor Squeeze Treatments Using Polyacrylate Based Inhibitors
Authors: Graham G. M. , Sorbie K. S. 
Published: December 2007

Abstract
Scale inhibitors based on small polyelectrolytes are often employed in oilfield scale prevention treatments. These materials are injected into the near-well formation of producers in a scale inhibitor "squeeze" treatment. When the well is brought back on production, the objective is for the return concentration level of the inhibitor in the produced brine to be at or above a certain threshold level, Ct. This threshold level is the minimum inhibitor concentration required to prevent the formation of mineral carbonate or sulphate scales in that well. The squeeze lifetime depends strongly on the nature of the interaction between the inhibitor and the formation either through an adsorption or "precipitation" mechanism. Both adsorption and precipitation processes depend on the molecular weight of the scale inhibitor, as well as on a range of other factors. However, polymeric inhibitor species always display some degree of polydispersity (spread of molecular weight).
In this paper, we examine the effects of molecular weight on adsorption/desorption phenomena for polyacrylate based inhibitor species. This work shows that, in the inhibitor effluent after a squeeze treatment, the molecular weight of the returning inhibitor may be different from that which was injected. For commercially available polymeric inhibitor species, we demonstrate using core floods that preferential retention of higher molecular weight components occurs and preferential desorption of lower molecular weight components is observed. This leads to a gradation in molecular weight in the return profile, which can lead to increased molecular weight components returning as the inhibitor concentration approaches the threshold level. The significance of this observation to field application of polymeric inhibitor species is discussed.
Water-Soluble Hydrophobically Associating Polymers for Improved Oil Recovery: A Literature Review
Authors: Taylor K. C. , Nasr-EI-Din H. A. 
Published: December 2007

Abstract
Water-soluble hydrophobically associating polymers are reviewed with particular emphasis on their application in improved oil recovery (IOR). These polymers are very similar to conventional water-soluble polymers used in IOR, except that they have a small number of hydrophobic groups incorporated into the polymer backbone. At levels of incorporation of less than 1 mol%, these hydrophobic groups can significantly change polymer performance. These polymers have potential for use in mobility control, drilling fluids and profile modification. This review includes synthesis, characterization, stability, rheology and flow in porous media of associating polymers. Patents relating to the use of associating polymers in IOR are also examined.
Logically Rectangular Mixed Methods for Darcy Flow on General Geometry
Authors: Arbogast Todd , Keenan Philip T. , Wheeler Mary F. 
Published: December 2007

ABSTRACT
We consider an expanded mixed finite element formulation (cell centered finite differences) for Darcy flow with a tensor absolute permeability. The reservoir can be geometrically general with internal features, but. the computational domain is rectangular. The method is defined on a curvilinear grid that need not, be orthogonal, obtained by mapping the rectangular, computational grid. The original flow problem becomes a similar problem with a modified permeability on the computational grid. Quadrature rules turn the mixed method into a cell-centered finite difference method with a. 9 point stencil in 2-D and 19 in 3-D.
As shown by theory and experiment, if the modified permeability on the computational domain is smooth, then the convergence rate is optimal and both pressure and velocity are superconvergent at certain points. If not, Lagrange multiplier pressures can be introduced on boundaries of elements so that optimal convergence is retained. This modification presents only small changes in the solution process; in fact, the same parallel domain decomposition algorithms can be applied with little or no change to the code if the modified permeability is smooth over the subdomains.
This Lagrange multiplier procedure can be. used to extend the difference scheme to multi-block domains, and to give, a coupling with unstructured grids. In all cases, the mixed formulation is locally conservative. Computational results illustrate the advantage and convergence of this method.
Well Casing Corrosion and Cathodic Protection
Authors: Curry Elmer L. 
Published: December 2007

Abstract
One of the problems concerning the prevention of corrosion of oil and gas prevention of corrosion of oil and gas well casings is that of determining the current requirements for cathodic protection. protection. This paper discusses the causes of corrosion on well casings, suggests well completion practices that would minimize corrosion problems, and explains and discusses two methods of determining current requirements for cathodic protection. Graphs and drawings are included to describe and substantiate both methods.
The casing potential profile tool is the most used tool to locate and evaluate external casing corrosion. It can also be used to determine the current requirements for cathodic protection.
The E-Log-I survey (sometimes referred to as the log-current-potential method) cannot locate or evaluate external casing corrosion, but is a relatively inexpensive method of determining current requirements for cathodic protection. It's accuracy has been verified in tests with the casing profile tool and it's dependability has been substantiated through proven results with the successful application of cathodic protection.
A. CAUSES OF EXTERNAL CASING CORROSION ON OIL AND GAS WELLS
There are five (5) major items which are normally thought to be the cause of well casing corrosion. These are:
Dis-similar metals Dis-similar soil Differential aeration Bacteria "Stray current" interference
Dis-similar metals cause a form of corrosion brought about by the use of different metals electrically coupled together (such as steel pipe and brass gate valves); the use of metals unintentionally caused to be dissimilar by the manufacturing process in either the steel or the pipe; the use of "old" and "new" pipe in the same casing which can include pipe in the same casing which can include oxide scales, etc., and marks and scratches on the pipe left by tools.
Simulation of Independent Reservoirs Coupled by Global Production and Injection Constraints
Authors: Haugen E. D. , Holmes J. A. , Selvig Arild 
Published: December 2007

Abstract
An oil or gas field may comprise a number of isolated reservoir units, each of which may have been studied separately with their own simulation models. If these reservoirs are to be linked to common surface facilities, they are effectively coupled by global production (and perhaps injection) constraints. Their production and injection streams must be combined to obey these constraints. Two approaches are commonly applied to this problem: either amalgamating the simulation models into a single model of the whole field, or using production planning methods on pre-constructed production profiles of the individual reservoirs. The former requires a great deal of effort from the engineers, and may result in a large unwieldy model, while the latter may not be accurate because of rate-dependency effects which are ignored.
This paper introduces a third approach to the problem, which we call Reservoir Coupling. The individual simulation models are still run as separate processes, with minimal change to their data. But they are coupled to a master process which handles the global production and injection constraints and determines the flow rate targets to be applied to the individual reservoirs at each time step. Inter-process communication is handled by the PVM message passing system. This can spawn processes over a network of heterogeneous Unix computers, enabling the individual simulation models to be run in parallel on separate workstations.
The paper describes the Reservoir Coupling algorithm that has been implemented in a commercial black oil simulator, and discusses the advantages and disadvantages of the technique in comparison with the other two approaches. A simulation study is described which illustrates the application of Reservoir Coupling to three isolated reservoirs subject to global production and injection constraints.
Parallel Reservoir Automatic History Matching Using a Network of Workstations and PVM
Authors: Ouenes Ahmed , Weiss William , Sultan A. J. , Anwar Jabed 
Published: December 2007

ABSTRACT
This paper describes a new computing environment for reservoir automatic history matching. A parallel simulated annealing algorithm is used to estimate geologic and reservoir engineering parameters by automatically matching production history of an actual oil reservoir. A complex computer set-up using two networks of workstations simultaneously, located at the New Mexico Petroleum Recovery Research Center (PRRC) and the Los Alamos National Laboratory (LANL), is used to test the concept of distributed optimization. A heterogeneous cluster of two workstations (HP and SUN) is used at the PRRC and a homogeneous cluster of six IBM RISC 6000 workstations is used at LANL. At each site (PRRC and LANL), a Parallel Virtual Machine is created by using the message passing software, PVM. Communication between the two parallel virtual machines located at the PRRC and LANL is achieved with a simple e-mail protocol. In this new environment, the total time required to complete a 22 well oil reservoir study lead to the following observation: two-thirds of the time was devoted to geologic, core, and well log analyses, and one-third of the time to history matching.
Ninth SPE Comparative Solution Project: A Reexamination of Black-Oil Simulation
Authors: Killough J. E. 
Published: December 2007

Abstract
The Ninth SPE Comparative Solution Project presented in the following paper provides a reexamination of black-oil simulation based on a model of moderate size (9,000 cells) and with a high degree of heterogeneity provided by a geostatistically-based permeability field. Nine participants provided data for the comparison which is based on a dipping reservoir with twenty-five somewhat randomly placed producers and a single water injector.
Results showed that significant agreement could be achieved for this problem on the basis of total production rates, saturations, and reservoir pressures. On the other hand, rates for some individual wells did show variations of as much as 30% due to differing treatments of well flowing bottomhole pressures. All participants were able to simulate the study in fewer than sixty time-steps with an average of 4-5 Newton iterations per step. In addition, the results showed that this moderate-sized problem could be simulated in only a few minutes in a workstation environment for the two plus years of data.
Petroleum Reservoir Simulation in a Virtual Environment
Authors: Jacobsen J. S. , Bethel E. W. , Datta-Gupta Akhil , Holland P. J. 
Published: December 2007

Abstract
In this paper, we describe an approach to combining a reservoir simulation with 3-D visualization and virtual reality technology. Our prototype VR/visualization system minimizes human-machine interface barriers and provides enhanced control over the simulation, thereby maximizing scientific judgment and use of intuition. We illustrate the practical advantage of using the VR/visualization prototype system in reservoir engineering by visualizing the results of a waterflood in an oil field with a three-dimensional, spatially correlated heterogeneous permeability field.
A Multiple Right Hand Side Iterative Solver for History Matching
Authors: Killough J. E. , Sharma Yogeshwar , Dupuy Alain , Bissell Robert , Wallis John 
Published: December 2007

Abstract
History matching of oil and gas reservoirs can be accelerated by directly calculating the gradients of observed quantities (e.g., well pressure) with respect to the adjustable reservoir parameters(e. g., permeability). This leads to a set of linear equations which add a significant overhead to the full simulation run without gradients. Direct Gauss elimination solvers can be used to address this problem by performing the factorization of the matrix only once and then reusing the factored matrix for the solution of the multiple right hand sides. This is a limited technique, however. Experience has shown that problems with greater than few thousand cells may not be practical for direct solvers because of computation time and memory limitations.
This paper discusses the implementation of a multiple right hand side iterative linear equation solver (MRHS) for a system of adjoint equations to significantly enhance the performance of a gradient simulator. This was accomplished by saving the inverse of the preconditioning matrix M from the first gradient solution and utilizing it in subsequent solutions. Reduced System/ILU(0) was chosen for the gradient solution since this preconditioner is one of the more robust. In this way, the significant computation time required to calculate the preconditioner is only needed for the first gradient solution, while all subsequent gradient calculations take only a fraction of the CPU time of the first solution.
Numerical experiments were conducted on models of up to 10000 cells and the new MRHS iterative solver was compared with standard red-black line successive overrelaxation (RBLSOR) and Direct(D4) solvers. For the problems which could be compared, overall speedups with the new MRHS solver varied from a factor of 3–6 over other solvers while gain in storage was about factor of 6 over the direct solver.