bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Determination of Dynamic Proppant Concentration Field in Slot Flow in the FFCF
Authors: Beason Ronnie , Fagan John 
Published: December 2007

Abstract
This paper presents a methodology for the determination of dynamic proppant concentration mapping in slot flow in the Fracturing Fluid Characterization Facility (FFCF). The technique presented here is used in the FFCF for the purpose of monitoring and mapping proppant concentration as a function of time for clear slot flow and flow in the High Pressure Simulator (HPS) at the FFCF. The methodology allows the FFCF user, for the first time to determine the instantaneous spacial proppant concentration during slot flow of slurries.
The technique uses a method of measuring spacial light attenuation through the slot flow and a mapping of the light intensity using a calibrated standard to proppant concentration. The method makes use of video technology and the real time digitizing, quantifying, and mapping of the real time video. The paper will present the overall software and hardware scheme used to accomplish this visualization task, snapshots of the real time videos produced by the technique, and how the technique is used in the FFCF. The technique, for the first time, allows the researcher of proppant flow to study the dynamics of proppant flow in fracturing fluids as well as allows the quantification of the flow for the purpose of fluid dynamics modeling. The technique is currently available to researchers in the FFCF in the low pressure slot and will be available in production in the High Pressure Simulator in late 1995.
A New Microbial Plugging Process and Its Impact on Fracture Remediation
Authors: Zhong Lirong , Islam M. R. 
Published: December 2007

Abstract
Microbial mineral precipitation occurs constantly over the geological time. This process induces natural cementation or plugging in sediments or rock formations. Petroleum microbiologists employed the process as a reservoir selective plugging method to enhance the production of hydrocarbon resources.
Mineral precipitation is induced as a result of microbial activities. Bacteria can deposit minerals directly from the medium through their metabolic activities. They can also precipitate minerals indirectly from the medium by changing regional geological environmental conditions. Mineral precipitations and the dead bacteria bodies can persist as a part of the environment and result in plugging or cementing in pores in that environment. The process is optimized with bacteria Bacillus Pasteurii to precipitate CaCO3 so that the bacteriogenic cementation occurs in hours rather than in years. It is suggested that the process be used to plug fractures in water-producing zones to prevent excessive water production during oil recovery. The same technique can be used to consolidate sands in an unconsolidated fractures.
A series of experiments was conducted to investigate the possibility of using microbial plugging process to remediate fractures and to test factors affecting that process. The effects of pH, temperature and medium on mineral precipitation and bacteria growth are studied in detail. Also, the effect of fracture width and fracture fillings is studied. It is found that the microbial mineral plugging technique is effective in plugging fractures.
Application of Sequence Stratigraphic Modeling to Integrated Reservoir Management at Aneth Unit, Greater Aneth Field, Utah
Authors: Amateis L. J. 
Published: December 2007

Abstract
Infill drilling, workovers, and extremely low decline rates proved existing geological models were inadequate to explain reservoir performance. A three dimensional geological model was built using all available geological and reservoir data. The model combined with reservoir engineering analysis has been used to identify workover locations, horizontal well locations, and is being used in an ongoing study for CO2 flooding the reservoir.
Continuous Improvement In Well Design Optimises Development
Authors: Harrison P. F. , Mitchell A. W. 
Published: December 2007

Abstract
The Sherwood sandstone oil reservoir in the Wytch Farm field straddles the coastline of Southern England. The onshore reserves were developed from multiple well sites using limited step-out wells. After four years production, development of the offshore reserves began. Extended reach drilling was applied to drill wells with step-outs of up to 7km with 2.2km reservoir sections.
This paper describes how the extended reach well reservoir trajectories were designed to optimise oil production rate, maximise reserve recovery and limit water-cut development. The offshore development which uses 1990's technology is contrasted with the onshore development from the previous decade.
Surface Potential and Permeability of Rock Cores Under Asphaltenic Oil Flow Conditions
Authors: Alkafeef S. F. , Gochin R. J. , Smith A. L. 
Published: December 2007

Abstract
The surface properties, wetting behaviour and permeability of rock samples are central to understanding recovery behaviour in oil reservoirs. This paper will present a method new to petroleum engineering to show how area/length ratios for porous systems can be obtained by combining streaming potential and streaming current measurements on rock cores. This has allows streaming current measurements (independent of surface conductivity errors) to be made on rock samples using hydrocarbon solvents with increasing concentrations of asphaltene. Negative surface potentials for the rock became steadily more positive as asphaltene coated the pore surfaces, with permeability reduction agreeing well with petrographic analysis.
Steady-State Relative Permeability Measurements Corrected for Capillary Effects
Authors: Virnovsky G.A. , Skjaeveland S.M. , Surdal J. , Ingsoy P. 
Published: December 2007

Abstract
A new method is presented which enables to interpret steady-state flow experiments eliminating errors caused by the capillary end-effect. This is achieved by retaining the capillary term in the equations that are used to interpret the flow data.
The standard experimental procedure has to be extended to include variations in both total flowrate and the ratio of phase flowrates. Consistent values of saturation and relative permeability of each phase are then calculated at the inlet end.
Necessary modifications in laboratory procedures and influence of hysteresis are discussed and the theoretical development is exemplified by numerical simulation of coreflood experiments.

Introduction
During a steady-state procedure for measurement of relative permeability curves, the total flowrate of oil and water is usually kept constant while their ratio is changed at the inlet end of the core. After a change, it is necessary to wait until equilibrium in the core is re-established, i.e., when both the pressure drop and the effluent flowrate ratio do not change with time. The individual flowrates and the pressure drop is then used to calculate the individual phase relative permeability values by Darcy's law, relating them to the average saturation in the core, determined by material balance.
The main inaccuracies of this method stem from the basic assumption that the capillary pressure can be neglected. Actually, because of capillary effects, the saturation distribution along the core is non-uniform, and the pressure drop is different in each phase. The capillary effects are difficult to avoid even if the total flowrate is high and for some rocks high flowrate cannot be reached for reasons like limited equipment capacity or stress that may cause rock damage.
In this paper a new steady-state technique is described that includes capillary effects.
The proposed experimental setup is not very much different from that of the conventional steady-state method. For a fixed fractional flow at the inlet, a number of steady-state experiments is required with varying total flowrate to include the capillary effect in the analysis of the data. The capillary pressure curve has to be measured separately.

Theory
The following standard equations describe one-dimensional, two-phase flow of immiscible, incompressible fluids in a porous medium,
(1)
From Eqs. (1) it follows that the expression for the velocity of the first phase is
(2)
Conservation of mass gives
(3)
Let us consider steady-state flow only. Then the saturation in the core is solely a function of the x-coordinate.
P. 85
Application of Seismic-Guided Reservoir Property Mapping to the Dulang West Field, Offshore Peninsular Malaysia
Authors: Corbett Chip , Solomon G. J. , Sonrexa Kartikay , Ujang Salehudin , Ariffin Tajjul 
Published: December 2007

Abstract
A process is demonstrated for building a deterministic reservoir model, using 3D acoustic impedance inversion and seismic-guided log property distribution. The extraction of fluid and pore volumes at proposed drilling locations assists the qualification of reservoir development scenarios. Fluid flow simulation assists the field development.
Accurate Well Condition Estimates Under Multiphase Flow Conditions
Authors: Roadifer R. D. , Yeh N. S. , Jones J. R. 
Published: December 2007

Abstract
This work considers the analysis of pressure transient data obtained from wells produced under multiphase flow conditions. Both fully-penetrating and restricted=entry wells are considered. In particular, we examine methods for the calculation of the damage skin factor (and the pseudoskin factor caused by partial penetration) in reservoirs with multiple flowing phases. A new semi-theoretical method which accounts for the nonlinearities naturally arising from multiphase flow effects in the reservoir and at the well is presented for calculating these skin factors.
Numerical results for an extensive array of two-phase (oil-water, gas-water and oil-gas; including gas condensates) and three-phase (oil-gas-water) reservoir systems are presented and include the analysis of pressure transient data obtained from both fully-penetrating wells and restricted-entry wells. Our new semi-theoretical skin factor method is shown to provide extremely accurate estimates for both the damage skin factor and pseudoskin factor due to partial-penetration, even when the saturation and pressure dependent fluid properties vary substantially over the course of the well test.
Pressure analysis alone is considered in this work; i.e., we do not consider pseudopressure analysis, either single phase or multiphase. As such, the analysis methods presented are much simpler to use than corresponding pseudopressure analysis techniques and for the multiphase cases do not require a priori knowledge of relative permeabilities. This should result in a more general acceptance and usability by the petroleum engineering community.
Description of Heterogeneous Reservoir Using Tracer and Pressure Data Simultaneously
Authors: Deng Xianfa , Home Roland 
Published: December 2007

Abstract
The nonlinear least square regression method is an indirect method to obtain reservoir properties from observed data. It has been applied widely in well test analysis, especially for interpreting transient pressure data. Based on the difference between observed and calculated pressure data, the estimates of the parameters are adjusted until the calculated response is sufficiently close to that of observations. This method works for limited observations and is most successful if the objective function is convex or has few local minima. However, as the number of observations increases, as in the case of data from multiple wells, the calculation in the indirect method becomes inefficient. Another disadvantage is that the optimization may converge to a local minimum and hence the estimated result will depend on the initial guess of the parameters. This paper presents an approach to interpret pressure data and tracer data from multiple wells simultaneously to characterize the areal permeability distribution in heterogeneous reservoirs. Since tracer data are more sensitive to heterogeneity than pressure data, integration of two kinds of data should give more information about the reservoir. A correlation between permeability and dispersivity was investigated, and used to reformulate the convection-dispersion equation and diffusion equation to a system of first-order equations in permeability. The system of equations was then solved to yield the permeability distribution for appropriate boundary conditions. Advantages and disadvantages of this new scheme are discussed. Though the work focused on isotropic heterogeneous reservoirs, there is no technical difficulty to extend it to anisotropic reservoirs provided that the dispersivity-permeability correlation is renewed. Moreover, this method can conveniently incorporate geological data as constraints.
Use of Inverse Modeling for Conditioning Geostatistical Models to Vertical Tracer Profiles
Authors: Maroongroge Vichai , Saad Naji , Pope Gary A. , Sepehrnoori Kamy 
Published: December 2007

Abstract
A new tracer test for estimating reservoir heterogeneity called vertical tracer profiling (VTP) is presented. This interwell tracer test is performed by injecting and/or collecting tracer samples at different locations along the wellbore. The problem in analyzing this and conventional interwell tracer data is finding the solution to an inverse problem, that is, the inference of the reservoir heterogeneity from the tracer production data. In this paper two inverse modeling techniques are presented and compared in terms of speed and quality of results. The first technique uses a tracer simulator as a forward model in a simulated annealing geostatistical algorithm for conditioning the generated model to tracer history. The second technique uses a least square history matching technique applied to the tracer history coupled with a geostatistical modeling method to solve the inverse problem. These techniques were used to investigate the effectiveness of vertical tracer profiling for determining reservoir zonation compared to traditional sampling of the tracer data. Both 2D and 3D models were used to test the efficiency of the inverse modeling algorithms, the use of tracer data for estimating horizontal correlation, and the advantages of the vertical tracer profiling. The 2D permeability field used in this study was measured on a sample of Antolini sandstone and the 3D permeability field was generated using a Gaussian simulation technique for a fining upwards geologic sequence. The geostatistically generated 2D models were tested by comparing model simulation results with experimental waterflood. The 3D models were also compared using waterflooding simulations.
Analysis Of Diversification In Certain Natural Gas Companies
Authors: Jessup F.M. 
Published: December 2007

Abstract
Ten major interstate natural gas pipe-line companies have been studied for the effect of diversification on net income. This comparison indicates that diversification has generally paid off for those so indulging. Diversification by acquisition would seem to be as successful as diversification by internal expansion; however, the greatest success was achieved by those companies who had good earnings in the beginning and were able to hold the line on costs as the new revenues increased.
This study proves the success of using public utility leverage to add unregulated public utility leverage to add unregulated industrial profits to the regulated profits of natural gas pipeline companies. By use of diversification, the industry can substantially improve its probabilities of maintaining its position in the economy while facing the crisis problems of gas supply, high cost of money and public confidence.

Introduction
Forecasting is the art of analyzing what is known about the past in terms of its meaning for the future. It is necessary to analyze the forces underlying current trends in order to be able to recognize the signals of change and make plans to capitalize on any variability in terms of profit, however, is the forecast of opportunity for it and this is the motivator of proposed activities.
In the natural gas industry, there have been two very depressive features that predict difficult times ahead. The features are the lack of understanding on the part of regulatory bodies and the growing supply crisis, also directly attributable to regulatory problems.
With the declining profit margin on natural gas, some companies have diversified to try to maintain their position in the economy. This diversification, it must be remembered that a profit can be determined only on the basis of a calculation showing the difference added to profit by undertaking the action decided upon, as against the probable result if that action had not been probable result if that action had not been taken.
Capillary Pressure Curves for Low Permeability Chalk Obtained by NMR Imaging of Core Saturation Profiles
Authors: Nørgaard Jens Vintner , Olsen Dan , Springer Niels , Reffstrup Jan 
Published: December 2007

Abstract
A new technique for obtaining water-oil capillary pressure curves, based on NMR imaging of the saturation distribution in flooded cores is presented.
In this technique, a steady state fluid saturation profile is developed by flooding the core at a constant flow rate. At the steady state situation where the saturation distribution no longer changes, the local pressure difference between the wetting and non-wetting phases represents the capillary pressure.
The saturation profile is measured using an NMR technique and for a drainage case, the pressure in the non-wetting phase is calculated numerically. The paper presents the NMR technique and the procedure for calculating the pressure distribution in the sample.
Inhomogeneous samples produce irregular saturation profiles, which may be interpreted in terms of variation in permeability, porosity, and capillary pressure.
Capillary pressure curves for North Sea chalk obtained by the new technique show good agreement with capillary pressure curves obtained by traditional techniques.
Do Electronic Pressure Gauges have 20/20 Vision?
Authors: Hailstone J. , Ovens J. 
Published: December 2007

Abstract
Modern well test analysis relies crucially on the ability of high precision, electronic gauges to accurately record changes in wellbore pressure and temperature in a pressure transient test. However, the gauges themselves may possess certain characteristics which cause a less than ideal response and hence result in the recorded pressure response being systematically different from the actual pressure in the wellbore. This may have an impact on the test interpretation. For instance, long term drift may be interpreted as artificial barriers, possibly leading to an erroneous geological interpretation of the data.
A gauge transfer function, which mathematically relates the input and output pressures and temperatures to each other, allows the non ideal behaviour of the gauge to be modelled. Inclusion of the transfer function in existing computer tools used to analyse Pressure Transient tests will improve the resulting analysis. Based on laboratory test data obtained from a European Joint Industry Project** (EJIP), gauge transfer functions have been determined for two high quality electronic gauges. Details of the transfer functions, analysis of the test results and illustrations of their application in improving a well test analysis are presented.
Conditional Simulation of Subseismic Faults
Authors: Godderij R. R. G. G. , Chessa A. G. , Bruining J. , Kreft E. 
Published: December 2007

Abstract
Extensive fault patterns occur in almost any reservoir. The importance of seismic faults is generally recognized. Subseismic faults, even if they are non-sealing, can also be important. For instance they can confine the flow to channels due to gravity effects.
Here we describe a simulation method, based on a marked point process, to construct realizations of subseismic fault maps that honor fault data obtained from well to well correlation.
We use an adapted version of the ellipsoidal model of Barnett et al.1 to characterize a single fault. The statistical fault properties which are necessary for the simulation are based on a field data-set.
A Hydraulic (Flow) Unit Based Model for the Determination of Petrophysical Properties from NMR Relaxation Measurements
Authors: Ohen Henry A. , Ajufo Austin , Curby Federica Manni 
Published: December 2007

Abstract
This paper presents preliminary results of a Hydraulic (flow) Units based research program aimed at defining more effective guidelines for the use of nuclear magnetic resonance tools (NMRT) for petrophysical evaluation. Successful application of the Hydraulic Units concept for predicting petrophysical properties from wireline logs has been demonstrated previously. In this paper, we show obvious but crucial relationships between the Hydraulic Units concept and nuclear magnetic resonance (NMR) relaxation data. The linkage between these two technologies is possible because the hydraulic unit zonation indicators referred to as flow zone indicators (FZI) and NMR relaxation data are related to the surface phenomenon which controls the microscopic attributes of the rock. It is shown that although NMR relaxation measurements respond to pore body size rather than pore throat size, an effective NMR based permeability model, which includes pore size to pore throat size ratios, can be developed. The phenomenological model presented herein consists of mathematical relationships between FZI and NMR relaxation data, specific surface area, tortuosity and relaxivity (ρ). Laboratory (NMR) relaxation time measurements on CORESPEC-1000 together with core analysis data of permeability, porosity, centrifuge capillary pressure and thin section petrography have been used to validate the model.
The results show that the observed variability in the relaxivity constant (ρ) is due to the existence of different hydraulic units in the reservoir rock. We also demonstrate that relaxation time cut-off (T1c) used for determining producible fluid from relaxation time distributions may vary slightly as a function of rock types.
Hydraulic units based predictive algorithms for the estimation of relaxivity (ρ) and T1c, using pore throat size distributions (mercury injection data), and centrifuge capillary pressure data are validated. A more effective permeability estimation algorithm is also presented.
Comparison of Nuclear Magnetic Resonance Techniques in the Delaware
Authors: Logan Dale , Morriss Chris , Williams Rick 
Published: December 2007

Abstract
The Delaware formation is a very fine grained sandstone, often 4000 feet thick, located in West Texas and SE New Mexico. Resistivity based log interpretation in the Delaware has proven to be ineffective in most circumstances. Deep invasion and high irreducible water volumes lead to water saturation calculations that rarely reflect future production. Recent work in this formation demonstrates that Nuclear Magnetic Resonance (NMR) is an effective evaluation tool.
Lab NMR measurements on core plugs accurately predict pore size distributions that have been used to estimate permeability and irreducible water volume (Bvirr). Lab NMR also demonstrates that water saturated rock has a distinctly different NMR response to partially oil saturated rock. This leads to an estimate of residual oil saturation from NMR.
This success is then duplicated using downhole measurements made by the Nuclear Magnetic Tool (NMT) and the Combinable Magnetic Resonance Tool (CMR). Downhole NMR estimates of porosity, pore size, permeability and residual oil saturation on five wells are then validated by comparison to mudlogs, sidewall cores and production results.