bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Unified Approach to Asphaltene Precipitation: Laboratory Measurement and Modeling
Authors: MacMillan D.J. , Tackett J.E. , Jessee M.A. , Monger-McClure T.G. 
Published: December 2007

Summary
A unified approach to evaluating asphaltene precipitation based on laboratory measurement and modeling is presented. This approach used an organic deposition cell for measuring asphaltene drop out onset conditions. Asphaltene precipitation was detected by changes in optical fluorescence, electrical conductance, and visual observation. A series of experiments measured the effects of changing pressure, temperature and composition on asphaltene precipitation. A fully-compositional V-L-S mathematical model completed the analysis by matching the experimental results. The model was then used to forecast asphaltene precipitation under a variety of production scenarios including response to gas-lift operations, and to evaluate the possible location of a tar-mat.

Introduction
An organic deposition cell (ODC) was developed to experimentally detect asphaltene drop out onset. Two different detection techniques were incorporated into the cell. Fluorescence spectrometry has been used to study aromatic compounds. Fiber optics allowed application of this basic technique to asphaltene detection in the ODC. Conductance measurements were also incorporated into the ODC.
Thermodynamic models have been used to predict asphaltene precipitation from reservoir crudes under a variety of conditions. Burke et al and others applied polymer solution theory to the prediction of asphaltene precipitation. While this technique has been very successful, it is limited in its capability to predict the amount of asphaltene precipitate and varying precipitate composition. It was therefore decided to use the more rigorous approach presented by Thomas et al to model asphaltene precipitation. This method is based on an earlier wax deposition model which allows a fully compositional representation of the asphaltene phase.

EXPERIMENTAL TECHNIQUES
The high-pressure (6000 psig) I high-temperature (250 F) ODC employed a piston to allow sample or chemical introduction and pressure/volume control(Figure 1). The piston was designed to minimize dead volume so that flashing during sample introduction was reduced. Heating elements and cooling coils were installed for temperature control. The sapphire window allowed limited visual inspection and the use of a flexible fiber optics probe for luminescence detection. The cell was rocked to allow sample mixing and could be inverted so the window was on top. Electrical conductance was measured between the cellwall and the conducting probe. The conductance values obtained included a high background contribution from the equipment.
High-Throughput TVD-Based Simulation of Tracer Flow
Authors: Wattenbarger Robert C. , Aziz Khalid , Orr F. M. 
Published: December 2007

Abstract
High-throughput, total-variation-diminishing based, numerical techniques for simulating tracer flow are developed. High-throughput (HT) timestepping enables explicit differencing techniques to use timesteps that are larger than allowed by normal stability constraints. Total-variation-diminishing (TVD) based techniques are a means of controlling the solution oscillations associated with high-order differencing schemes. The concept of ‘upstream stability’ is introduced to help combine HT timestepping with TVD-based differencing. Additionally, an improved HT timestepping algorithm for solving physically dispersive flow problems is developed.
Numerical experiments indicate that HT timestepping is most beneficial for solving highly convective flows that have both a physical Peclet number and a diffusion-only numerical Peclet number greater than one. Experiments comparing standard and alternating direction TVD-based techniques with both the Superbee (SB) and third-order based (L3) limiters indicate that the TVD-SB scheme is the most accurate for purely convective problems. For physically dispersive problems, the TVD-SB scheme may be too compressive and the TVD-L3 is recommended. The alternating direction TVD scheme is the least sensitive to timestepping and the most sensitive to grid-orientation.
Simulation of a North Sea Field Experiencing Significant Compaction Drive
Authors: Cook C. C. , Jewell Stephen 
Published: December 2007

Summary
The Valhall field in the Norwegian North Sea is a high-porosity chalk reservoir undergoing primary pressure depletion. Over the last 10 years there have been a number of computer modeling studies of the field which have all assumed an original oil-in-place of approximately 2,000 MMSTB (318.0 × 106 m3). Despite this basic similarity, estimates of ultimate recoverable reserves have increased from an initial value of 200 MMSTB (31.8 × 106 m3) to the present estimate of 500 MMSTB (79.5 × 106 m3). This increase is partly due to the addition of wells and the optimization of completion techniques. However, the single most important and unique feature influencing Valhall long-term production performance is reservoir rock compaction.
Recent simulation studies indicate that over half of the oil produced from the Valhall reservoir is a direct result of the rock compaction recovery mechanism. In the reservoir crest area rock compressibilities can be as high as 150 × 10−6 psi−1 (21.75 × 10−6 kPa−1), and it is estimated that compaction contributes over 70% of hydrocarbon recoveries.
This paper describes the mathematical model used to simulate reservoir performance in a compacting reservoir with specific discussion regarding the proportion of oil produced by each physical recovery process. An understanding of the recovery mechanisms and their relative importance is critical for the successful management of the field. This paper also presents an alternative method for evaluating the various recovery processes using a simple solution to the material-balance equation. This is used to substantiate the magnitude of the various recovery mechanisms identified in the simulation model.
Effect of Rock Heterogeneity on Relative Permeability: Implications for Scale-up
Authors: Honarpour M.M. , Cullick A.S. , Saad Naji , Humphreys N.V. 
Published: December 2007

Abstract
Relative permeability and capillary pressure are important parameters in reservoir engineering calculations and numerical simulation of reservoir performance. Heterogeneities are often avoided during core plug screening and selection for relative permeability and capillary pressure measurements. However, sandstone rocks in many depositional environments show significant small-scale laminations that affect the measured relative permeability. This report demonstrates the length scale dependence of relative permeability data that results from cm to mm scale rock laminations and patterns of initial and final oil saturation distribution in a 108-cm long laminated core. It shows in a quantitative way the capillary, trapping of water in low-permeability lamina during primary drainage and of oil in high permeability lamina during water imbibition. Steady-state water-oil imbibition relative permeability data and unsteady-state drainage and imbibition data were collected using linear x-ray and x-ray CT scanning for in situ fluid saturation measurement. Numerical simulations of the core floods show that relative permeabilities and capillary pressures that are correlated with small-scale differences in porosity and permeability are necessary to reproduce the observed saturation distributions. Thus, the relative permeability length-scale dependence, combined with anisotropy data presented elsewhere (SPE 27968), imply that scaled-up effective relative permeability must account properly for heterogeneity. Assignment of core-plug relative permeability to simulator grid blocks may not capture the correct effective fluid flow performance in rocks that are heterogeneous with correlation length greater than the plug dimensions, and thus lead to erroneous fluid flow performance predictions.
Using numerical simulation, a number of papers have reported the importance of core-scale geologic heterogeneity to relative permeability and its ultimate impact to the prediction of reservoir-scale flow behavior. Jones et al. showed that within a channel environment the choice of relative permeability scale-up from small-scale to larger scales is very important to accurate prediction of water breakthrough and produced oil volume and is more important than are spatial arrangement of lithofacies within channel sandbodies.
An Analysis for Predicting the Performance of Cone-Shaped Reservoirs Receiving Gas or Water Injection
Authors: Welge H.J. , Johnson E.F. , Hicks A.L. , Brinkman F.H. 
Published: December 2007

Abstract
A method is presented for predicting the character of gas or water displacement in a radial system, which can be either horizontal or inclined. The latter case would comprise cone-shaped or dome-shaped symmetry. The method considers the one dimension of radial distance, taken parallel to the bedding planes. Approximate allowance can be made for segregation of the two fluids perpendicular to the bedding planes. A complete saturation history can be obtained in about a day's time with the use of a desk calculator. Results of an example calculation agree well with the performance of simulated gas drive in a large model representing a section of a cone. This pie-shaped, sand-packed model was 8-ft long and 4-in. thick. The method of solution is useful in handling other partial differential equations of first order and first degree.

Introduction
A new analytical method has been developed for predicting the performance of gas or water drive in a reservoir having radial or cone-shaped symmetry (see Fig. 1). In addition, this new development offers a general method of handling partial differential equations of first order and first degree. This work extends those methods developed previously for predicting the displacement of oil by gas or water in linear systems. The method of calculating oil recovery in a radial system involves two major parts. The first part is a calculation of the distribution of saturations at various times of depletion. The second part is the calculation of oil recovery and producing gas-oil or water-oil ratios through volumetric balance on the saturation distributions obtained in the first part. This second part differs only slightly in principle from similar calculations made with linear systems, for instance. The basic assumptions used in the calculations are as follows.One-dimensional radial flow. An approach is explained later for approximating a second vertical dimension. (Withdrawals of oil, and of the driving fluid after breakthrough, are assumed uniform around the periphery of the dome.)Constant-volume fluid flow. Thus, in a gas drive there is no change in gas solubility, or in oil or gas volume due to viscous and gravity pressure drops.Capillary forces are negligible.Constant rate of injection.
A program has been written for carrying out the calculations needed on a digital computer. However, a prediction can also be arrived at using a desk calculator; this latter method of work requires about a day's time for each prediction made.

CALCULATION OF SATURATION DISTRIBUTION
For definiteness, we describe the development of our method for the case of gas drive from the crest of the structure. The reader will note, however, that the method is just as applicable to an advancing radial water drive.
JPT
P. 894^
Successful Deployment of Thermal Simulation Technology to Field Office
Authors: Hong K. C. , Cook G. W. 
Published: December 2007

Summary
We successfully deployed thermal simulation technology to a field office to enable the staff responsible for operating steamfloods to conduct on-site studies of their projects. The success was attributed to a number of factors, including (1) placement of a simulation expert in the field office, (2) formation of a thermal modeling focus group, (3) introduction of simulation software on PC's, (4) increased speed and memory of desktop PC's, and (5) designation of reservoir heat management as a key job responsibility for thermal engineers. Field engineers now routinely use this technology to evaluate investment decisions and development alternatives, manage steamflood reservoirs, and optimize project operations.
Field engineers have carried out many simulation studies by use of the desktop technology. Examples include (1) optimizing slim-hole injector-injector spacing and injector-horizontal producer spacing in a dipping reservoir, (2) fine-tuning water and steam injection periods in a fieldwide application of the water-alternating-steam process, and (3) evaluating the economic potential of heavy oil, trough reservoirs. These studies have resulted in adding value to heavy oil assets by reducing operating costs or increasing reserves.
A Reservoir Study of the Friendswood Field
Authors: Blair E.A. , Enquist B.R. , Good L.W. , Walton E.C. 
Published: December 2007

To temporarily stop migration of oil into the original gas cap, the existing gas injection project in this Texas Gulf Coast field was expanded. For the purpose, water turned out to be a more efficient displacing medium than gas. By unitizing the field and then injecting 80,000 barrels of water a day, oil migration can be stopped and 55 million more barrels of oil will be recovered.

Introduction
The Friendswood field (sometimes referred to as Webster) was discovered by Humble in 1937. It is located on the upper Texas Gulf Coast immediately south of Houston (Fig. 1), and has productive sands originally encompassing more than 4,100 acres. Approximately 215 wells were required to fully develop the field to 20-acre spacing. The sands are very prolific and the average well exhibits a productivity index of approximately 29 B/D per psi productivity index of approximately 29 B/D per psi drawdown. Cumulative Frio sand oil production has been 310 million bbl, and reservoir pressure has dropped only 340 psi since discovery. Principal production has been from upper Frio sands of Miocene age. Although prorated together, these sands have been divided into 17 members for reservoir control purposes. A small amount of oil (2 million bbl) has been produced from the Marginulina sands, which lie just above the Frio. The field contains several fault systems, and, because of fault juxtaposition, communication occurs between some of the sand members. Several studies, resulting in MER hearings, workover programs, and a gas injection program, have been conducted in the past. For the study discussed here, those past programs were reviewed and additional necessary programs were determined. Current fluid contacts for each sand member were ascertained on the basis of conventional neutron logs, pulsed neutron logs, induction electric logs, and well production histories. Oil and gas volumes were then production histories. Oil and gas volumes were then mapped for original and current conditions. Material balance and unsteady-state water influx calculations were used to match past reservoir behavior and to predict future performance. predict future performance.
JPT
P. 685
Scaleup of Reservoir-Model Relative Permeability With a Global Method
Authors: Li Dachang , Cullick A. S. , Lake Larry W. 
Published: December 2007

Summary
Geoscientists and engineers commonly build geologic or geostatis-tical reservoir models that contain more than 106 grid cells. For flow simulation, the number of grid cells must be reduced by a factor of 10 or more. Such scaling up necessarily involves a loss of information that must be restored through the use of effective or pseudorelative permeabilities. This paper describes an approach to generate such functions that, when combined with global absolute permeability scaleup,1 offers a significant improvement over existing "dynamic pseudo" methods that require extensive fine-grid simulation and that are very sensitive to flow conditions.1
The method builds on previous work to scale up absolute permeability through a global technique that minimizes the loss of permeability variance and the spatial correlation in an unequally sized grid system. This paper shows that, when the residual permeability following global absolute permeability scaleup is spatially uncorrected, the velocity of a fluid-displacement shock front correlates with a well-defined universal heterogeneity number that is related to the permeability distribution. The paper presents an analytic computation of the pseudo as a superposition of the shock velocities for the residual field, found from a table look-up, and the fine-grid field when the fine-grid relative permeabilities (usually based on measured relative permeabilities) have the same normalized form. The method is then generalized to multiple functional forms of fine-grid-cell relative permeabilities with new relative permeability and capillary pressure averaging methods. The procedure eliminates the need for fine-scale simulation and is equally applicable to geologic deterministic or stochastic models.
The paper describes the technique in detail and demonstrates the procedure with one two-dimensional (2D) and one three-dimensional (3D) reservoir model waterflood simulation. In the latter case, the number of cells is reduced from 23,600 (fine scale) to 4,000 (coarse scale) with very little change in the water breakthrough and water-cut behavior.
Building Extensible Interactive Applications - A Case Study
Authors: Frost Robert , Diserens Michael , Williams Glyn 
Published: December 2007

Summary
We use the development of an interactive program, which analyzes the results of experiments on rock samples and uses these results realistically in reservoir simulation, to illustrate various software engineering techniques. These techniques promote portability, flexibility, and fast application development through the reuse of existing software components. We describe guidelines for achieving compiler and windowing system independence, along with the benefits of using an object-oriented software architecture.
A software module called the Calculator provides extendibility to the user by controlled exposure of internal program variables.
Factors Affecting Liquid-Liquid Relative Permeabilities of a Consolidated Porous Medium
Authors: Lefebvre du Prey E.J. 
Published: December 2007

Abstract
Many laboratory displacement tests have been performed to study factors affecting relative performed to study factors affecting relative permeability curves, residual saturations, and shape permeability curves, residual saturations, and shape of recovery curves. Three sintered artificial porous materials and pure fluid mixtures have been used for this systematic study.
The factors were interfacial tension, the viscosity and the velocity of the fluids (in the dimensionless group σ/µv), the wettability, and the viscosity ratio. The results can be used as guidelines for research on recovery processes.

Introduction
Waterflooding is by far the most common secondary recovery technique. Several processes (polymer injection, surfactant injection, hot water injection, etc.) attempt to improve sweep efficiency by affecting some of the factors involved in the displacement process. For orienting research on these processes, process. For orienting research on these processes, a good knowledge of how these parameters affect local displacement efficiency and over-all sweep efficiency in the reservoir is required.
We present here an attempt to understand the effects of such parameters:
(1) at the microscopic level on the shape of relative permeability curves and the values of final saturations obtained by flooding, and
(2) at the macroscopic level, on the behavior of one-dimensional displacement.
Effects of the morphology of the porous medium were not included in this study. We mainly examined the effects of fluid properties on fluid displacement in only three specific porous media. These three artificial sintered media were made of Teflon, stainless steel and alumina. For the following reasons they were very well suited to the systematic investigation undertaken:
(1) they are homogeneous and so the results are not subject to macroscopic heterogeneity effects;
(2) they are identical in the same series, thus permitting the results to be compared from one experiment to another
(3) their constant and well-defined chemical composition makes it possible to perform wettability measurements outside the porous medium;
(4) they are consolidated like most of reservoir rocks;
(5) they have good mechanical properties and so can be washed successively without being altered and
(6) the three media used correspond to three possible cases of wettability, i.e., Teflon is strongly oil-wet, alumina is strongly water wet, and stainless steel may have intermediate wettability depending on the fluids considered.
Some of our results reported here (concerning experiments with Teflon at a viscosity ratio of one) were presented earlier.
A Relationship Between Pore Structure and Residual Oil Saturation in Tertiary Surfactant Floods
Authors: Dullien F.A.L. , Dhawan G.K. , Gurak Nur , Babjak L. 
Published: December 2007

Abstract
Photomicrography and mercury porosimetry have been used jointly to determine the pore-size distributions of various sandstone samples. The two curves differed drastically from each other for all samples.
Two unconsolidated packs consisting of uniform 250u glass beads and mixed 44-250u beads, respectively, as well as the sinters prepared from them, were also investigated.
An index, D, measuring the difficulty of recovering waterflood residuals in tertiary surfactant floods has been constructed from the two different porosimetry curves. Reasonably good correlation porosimetry curves. Reasonably good correlation bas been obtained between D and residual oil saturations found in tertiary surfactant floods.

Introduction
This paper presents our first results in a continuing study of pore structure and oil recovery.
The problem of how pore structure might influence oil recovery has been discussed by several authors. There is, however, no known method whereby one could rank various porous media (e.g., different sandstones) on the basis of pore structure in the order of decreasing amounts of expected residual oil saturations assuming identical conditions of flooding (identical oil, water, wetting and pressure gradient for the various sands. In this pressure gradient for the various sands. In this work we have taken an initial step toward this ideal objective. The prime target of the treatment has been the problem of correlating the extent of recovery of waterflood residuals by tertiary surfactant floods with the pore structure. The degree of difficulty presented by the pore structure in the way of recovering the isolated oil masses left behind by a waterflood has been expressed in the form of an index that is calculated from a mercury porosimetry and a photomicrographic pore-size distribution curve obtained on the sample. pore-size distribution curve obtained on the sample. The degree of correlation obtained amounts to a promising start in the case of tertiary surfactant promising start in the case of tertiary surfactant floods, and there also appears to be some correlation between the residual oil saturations found in the waterfloods and the pore structure.
In this paper we are considering only the case of water-wet formations and moderate viscosity ratios.