bluuebunny/crossref_metadata_2025_split huggingface dataset:
Evaluation of Wireline Down-Log Information and Effects of Increased Log Speeds on Data Quality
Authors: Hartley Kevin B. 
Published: December 2007

Wireline logs run in deviated Gulf of Mexico wells using new logging techniques are studied. Formation density and other logs can be recorded logging in or out of a hole at very high speeds and often provide excellent evaluation information. Down logs can be very useful in the event the usual up log becomes impossible. Increased log speeds may be justified in some cases involving hole problems or high rig costs.

Introduction
A study has been made of openhole wireline logs run in deviated wells in the Gulf of Mexico. Some new logging techniques of interest have been made possible by the introduction of computerized digital possible by the introduction of computerized digital surface logging units. Many of these techniques could not have been used previously due to limitations of the conventional analog surface logging units.Logs run going in the hole (down logs) often can provide valuable formation evaluation information, provide valuable formation evaluation information, particularly porosity data. Sometimes hole conditions particularly porosity data. Sometimes hole conditions are severe enough that the logs run coming up from total depth are not obtainable. Down-log porosity data often can distinguish hydrocarbon-bearing from tight zones and even oil from gas.Of particular interest is the observation that the formation density tool often can provide very good average porosity values when logged going in a deviated hole at a speed of 10,000 ft/hr with the caliper arm closed (Figs. 1 and 2). Down logs using other types of logging tools also have provided critical evaluation information.The accuracy of depth information is a problem, but zone thicknesses often are correct and depth errors can be estimated.The repeatability of various log types when run at speeds higher than normal also has been studied. Formation density logs run in high-porosity formations at 3,000 and 5,000 ft/hr show only minor variations from logs run at the conventional speed of 1,800 - ft/hr (Figs. 3 and 4). This excellent repeatability is due to the high gamma-ray count rates of the density tool in the offshore low-density formations of Pleistocene age. In fact, the variations observable between density logs run over a common interval in these low-density formations may be primarily a function of wall contact effects, not the primarily a function of wall contact effects, not the random statistical count rate variations. Statistics for the compensated neutron and gamma-ray devices relative to logging speed also are studied.Induction-type devices have been run at speeds up to 15,000 ft/hr with excellent repeatability using the computerized surface units.This paper is not intended to be a recommendation for increases in log speeds, particularly for the porosity devices. Increased formation density log porosity devices. Increased formation density log speeds in complex lithologies, for example, could reduce the value of the data greatly.
JPT
P. 1151
Numerical Simulation of Water Injection in Fractured Media Using the Discrete-Fracture Model and the Galerkin Method
Authors: Karimi-Fard Mohammad , Firoozabadi Abbas 
Published: December 2007

Summary
Numerical simulation of water injection in discrete fractured media with capillary pressure is a challenge. Dual-porosity models, in view of their strength and simplicity, can be used mainly for sugar-cube representation of fractured media. In such a representation, the transfer function between the fracture and the matrix block can be calculated readily for water-wet media. For a mixed-wet system, the evaluation of the transfer function becomes complicated because of the effect of gravity.
In this work, we use a discrete-fracture model in which the fractures are discretized as ID entities to account for fracture thickness by an integral form of the flow equations. This simple step greatly improves the numerical solution. Then, the discrete-fracture model is implemented using a Galerkin finite-element method. The robustness and the accuracy of the approach are shown through several examples. First, we consider a single fracture in a rock matrix and compare the results of the discrete-fracture model with a single-porosity model. Then, we use the discrete-fracture model in more complex configurations. Numerical simulations are carried out in water-wet media as well as in mixed-wet media to study the effect of matrix and fracture capillary pressures.
Northstar Drilling—Delivering the First Arctic Offshore Development
Authors: Krieger Andrew G. , Kidd Gavin N. , Cocking David A. 
Published: December 2007

Summary
Northstar is the first arctic offshore development that is not accessible by road for most of the year and does not have fixed-wing air support. The implications of limited access to a 400×400-ft island are enormous. Successful completion of the first drilling season at Northstar is a significant milestone marked by detailed design and execution as well as pure determination. Many of the challenges were anticipated and accounted for, while many others were not. These challenges included environmental hurdles, logistical constraints, and commissioning the rig and the grind and inject (G&I) facility on an accelerated schedule. The first arctic offshore development delivered its first barrels of oil as per schedule on 2 November 2001. Now comes the next challenge—drilling to improve the profitability of this unique Alaskan project.
A Well-Test Analysis Method Accounting for Pre-Test Operations
Authors: Silin D. B. , Tsang C. -F. 
Published: December 2007

SummaryIn recent work, we have extended the classical radial flow model used in a standard pressure drawdown or buildup well-test analysis by incorporating an additional parameter characterizing the pumping rate prior to the test. By this means, we develop an approach for estimating the formation hydraulic properties in the vicinity of the wellbore from regular pumping rate-pumping pressure data. In this paper, the approach is established as a well-test analysis method by accomplishing two steps. First, five parameters, including the reservoir transmissivity, storativity, skin factor, and pre-test pumping rate, are determined from analysis of measured data. Second, the average reservoir pressure and drainage radius are determined from a calculation using parameters obtained in the first part.
Application of Wavelet Transform to the Analysis of Pressure-Transient Data
Authors: Soliman M. Y. , Ansah J. , Stephenson S. , Mandal B. 
Published: December 2007

SummaryAlthough the mathematical concept of "wavelet transform" was developed in the early part of the 20th century, it did not receive practical application until the 1980s. Wavelet transform is now used in a wide variety of applications in the areas of medicine, biology, and data compression, among others. A significant benefit provided by wavelet transform is its capability to provide two functions:Smoothing of the basic signal. Retention or even enhancement of the details.In data analysis, these characteristics allow the user to recognize hidden signals quickly. In well testing, these capabilities can enhance signals that can be masked by other events or by the data frequency itself. Because the derivative techniques currently used in well testing tend to smooth data and conceal certain events, the use of the wavelet transform to analyze the raw data could prove to be very valuable as a major step in enhancing the techniques of modern data analysis.This paper briefly reviews the application of the wavelet transform methodology to data analysis in general and shows why its application to well-testing data in particular is important. It also provides guidelines for the application of this technology to well testing.Several field examples are provided to demonstrate the application of the wavelet transform to well testing and to show how the qualitative and quantitative uses of the method determine wellbore anomalies, boundary effects, and other well-testing phenomena.
Plunger-Lift Monitoring by Analyzing Wellbore High-Frequency Acoustic Signals and Tubing and Casing Pressures
Authors: McCoy Jim , Rowlan Lynn , Podio A. L. 
Published: December 2007

Summary
Plunger-lift operations are difficult to optimize owing to a lack of knowledge concerning tubing, casing, and bottomhole pressures; liquid accumulation in the tubing; and the location of the plunger. Monitoring plunger position in the tubing helps the operator understand the operation of the plunger system to optimize the removal of liquids and gas from the well. Plunger position can be tracked from the surface by monitoring the acoustic signals generated as it falls down the tubing. When the plunger passes a tubing collar recess, an acoustic pulse is generated that travels up the gas within the tubing and can be monitored at the surface by a microphone and/or a sensitive pressure transducer. The digitized signal is processed to display plunger depth and velocity and well pressures vs. time. Plunger arrival at the liquid level in and at the bottom of the tubing are identified on the time plots. A field case is presented to show how this information can be applied to optimize plunger-lift operations.
Damage Characterization of Deep Bed Filtration From Pressure Measurements
Authors: Bedrikovetsky P. , Tran T. K. , Van den Broek W. M. G. T. , Marchesin D. , Rezende E. , Siqueira A. , Souza A. L. , Shecaira F. 
Published: December 2007

SummaryPermeability decline occurs during injection of sea or produced water, resulting in well impairment. Solid and liquid particles dispersed in the injected water are trapped by the porous medium and may significantly increase hydraulic resistance to the flow.We discuss a mathematical model for deep bed filtration containing two empirical parameters - the filtration and the formation damage coefficients. These parameters should be determined from laboratory coreflood tests by forcing water with particles to flow through core samples. A routine laboratory method determines the filtration coefficient with expensive and difficult particle-concentration measurements of the core effluent, and then the formation damage coefficient is determined from inexpensive and simple pressure-drop measurements.An alternative method would be to use solely pressure difference between the core ends. However, we proved in an earlier work that given pressure-drop data in seawater coreflood laboratory experiments, solving for the filtration and formation damage coefficients is an inverse problem that determines only a combination of these two parameters rather than each of them.A new method for the simultaneous determination of both coefficients is developed here. The method's new feature is using pressure data at an intermediate core point, supplementing pressure measurements at the core inlet and outlet. The proposed method furnishes unique values for the two coefficients, and the solution is stable with respect to small perturbations of the pressure data.In this work, the proposed method is used for analysis of laboratory test data on deep bed filtration. The values of filtration and formation damage coefficients are obtained for flow of solid and liquid particle dispersions in a number of different cores. Effects of particle type and porous media wettability on permeability decline are analyzed.
Compositional Model Studies – CO2 Oil-Displacement Mechanisms
Authors: Leach M. P. , Yellig W. F. 
Published: December 2007

Abstract
This paper presents matches, using a fully compositional model, of the performances of seven laboratory CO2 displacements of a 10-component synthetic oil. The criteria for achieving a match of laboratory performance include (1) comparisons of predicted and experimentally determined oil recovery and (2) effluent compositional profiles for each component as functions of hydrocarbon pore volumes (HCPV) of CO2 injected.
An equation of state was tuned to predict single-contact (PVT) phase equilibria for CO2/synthetic-oil mixtures. The model incorporates this equation of state to predict the multiple-contact phase equilibria during a CO2 displacement test. Input to the model were independently determined gas/oil relative permeability characteristics and – for each laboratory displacement – injection rate, effluent pressure, pore volume, and temperature.
The experimental displacements were conducted in linear Berea core systems using a synthetic (C1-C14) oil at 120 and 150°F. Three displacements at 120°F have been published by Metcalfe and Yarborough.1 Previously, it was thought that these displacements were conducted at selected pressures so that oil displacements encompassed immiscible, multiple-contact miscible (MCM), and contact miscible mechanisms. However, the model results show that only contact miscible and MCM displacement mechanisms were involved. To confirm the mechanistic understanding at 120°F, three additional laboratory displacements were conducted at 150°F. These encompassed pressures such that the displacement was controlled by an immiscible, an MCM, and a contact miscible mechanism, respectively. The model results at 150°F match the ex-perimental data and confirm the mechanistic understanding. The experimental and numerical results are in agreement with the minimum miscibility pressure theory of Yellig and Metcalfe.2
The results of this study confirm the importance of experimentally determined effluent compositional profiles and fully compositional models for CO2 mechanism studies.
Use of Surfactant to Reduce CO2 Mobility in Oil Displacement
Authors: Bernard George G. , Holm L. W. , Harvey Craig P. 
Published: December 2007

Abstract
This paper presents results from a study designed to improve effectiveness of CO2 flooding by reducing CO2 mobility. In the course of reaching this objective we (1) screened surfactants for their ability to generate an effective and stable emulsion with CO2 under reservoir conditions, (2) determined the concentration range over which surfactants were effective, (3) examined chemical stability of the surfactants at reservoir conditions, (4) determined the extent to which emulsifying action alters gas and liquid mobilities in carbonate and sandstone cores, (5) determined that surfactant can enhance the production of residual oil from watered-out carbonate cores by CO2, and (6) showed that the permeability reduction caused by surfactant can be dissipated.
At reservoir conditions required for miscible displacement, carbon dioxide exists in its critical state as a very dense fluid whose viscosity is about one-eighth that of crude oil. Generally, this unfavorable viscosity and mobility ratio produces inefficient oil displacement. This study shows that surfactant reduces CO2 mobility and should improve oil displacement by CO2, presumably by reducing flow through the most permeable zones, thus increasing areal and vertical sweep efficiencies.
All three classes of surfactants (anionic, cationic, and nonionic) were found to be stable under conditions encountered during a CO2 flood in limestone formation; however, only a few surfactants had proper adsorption and emulsifying properties. Surfactant generated foams or emulsions with CO2 at reservoir conditions (1,000 to 3,000 psi and 135°F) dramatically reduced CO2 flow through sandstone and carbonate cores. Surfactant reduced the amount of CO2 used to recover a given volume of oil, especially from watered-out cores. The mechanism of tertiary oil production from linear cores appears to be limited to CO2 extraction. Approximately the same oil recovery was obtained either by continuous CO2 injection after a surfactant slug or by alternate slugs of CO2 and surfactant solution. It was found that oil recovery efficiency increased when surfactant was used with CO2 and that efficiency increased with flooding pressure.
One anionic surfactant was found to be superior for this purpose. This surfactant emulsified CO2 well, was least adsorbed on carbonate rocks, and greatly reduced CO2 mobility in linear cores at concentrations of 0.1 to 1%.
The study indicates that effectiveness of CO2 miscible flooding can be increased by alternate injection of CO2 and aqueous surfactant slugs into the reservoir.
Performance Improvement Techniques Used on Goodwyn A Platform, Northwest Shelf, Australia
Authors: Dolan S. P. , Williams G. J. , Barrows W. J. , Dickson J. W. , Torry D. , Drury R. F. 
Published: December 2007

Summary
This paper reviews the techniques that have generated a large improvement in drilling and completion performance on the Goodwyn A Platform, Northwest Shelf, Australia. The collective effort of well-construction professionals using these techniques has resulted in the drilling of a 6263-m (20,550-ft) total depth (TD) well with a horizontal stepout of 5200 m (17,060 ft) at a tangent angle of 67° in 39 days from spud to well handover. This was 31% under the P50 authorization-for-expenditure (AFE) time estimate.
This paper describes a method to produce systematic, steady, and sustainable improvements to well-construction operations. The methods described are a way of harnessing the collective brainpower of well-construction professionals and focusing that energy toward rigorous problem analysis or potential improvement areas, then systematically working through and implementing solutions.
The technical limit methodology and performance improvement groups (PIGs) are best suited for complex, high-cost drilling projects, typically extended reach drilling (ERD) developments, high-cost mobile offshore drilling units (MODU) exploration or subsea operations.
In addition, other tools, such as hazard management, learning system, and planning processes that contributed to success, are explained.
Application of the Theory of Multicomponent, Multiphase Displacement to Three-Component, Two-Phase Surfactant Flooding
Authors: Hirasaki George J. 
Published: December 2007

Abstract
The theory presented in a companion paper1 is illustrated for the case of three-component, two-phase (i.e., constant-salinity) surfactant flooding. The utility of this method is that, in addition to computation of specific cases, it provides a general qualitative understanding of the displacement behavior for different phase diagrams and different injection compositions. The phase behavior can be classified as to whether the partition coefficient is less than or greater than unity. The injection composition of the slug can be classified as to whether it is aqueous or oleic and whether it is inside or outside the region of tieline extensions.
The theory provides an understanding of the displacement mechanisms for the three-component, two-phase system as a function of phase behavior and injection composition. This understanding aids the interpretation of phenomena such as the effects of dispersion, salinity gradient, chromatographic separation, and polymer/surfactant interaction.
An Experimental Investigation of the Effect of Temperature on Recovery of Heavy Oil From Diatomite
Authors: Tang G.-Q. , Kovscek A. R. 
Published: December 2007

SummaryAn X-ray computed-tomography (CT) scanner, in combination with a novel high-temperature and high-pressure core holder, was used to investigate systematically heavy oil recovery from outcrop diatomite and field core. Temperatures ranged from 20 to 180°C, and all experiments are isothermal. Decane, two viscous white mineral oils, and heavy crude oil from the field were used as oil phases. In reservoir core filled with crude oil, oil recovery by spontaneous imbibition of water increased from 3% at 40°C (reservoir temperature) to 40% of oil in place at 180°C. Forced displacement brought total recovery to more than 50%. Thermal methods are effective at improving oil recovery from low-permeability, fractured oil-rock systems filled with moderate to viscous oil, whereas waterflood is not.Recovery increases with temperature because oil viscosity decreases and wettability is altered toward water wetness. Increased imbibition rate and oil recovery corresponded with production of oil-wet fines at elevated temperature. A mechanism for increase in water wettability is proposed whereby fines detachment from pore surfaces increases the water-wet surface area.
Experimental and Theoretical Studies on the Fluid Properties Required for Simulation of Thermal Processes
Authors: Lee S. T. , Jacoby R. H. , Chen W. H. , Culham W. E. 
Published: December 2007

Abstract
Experimental phase equilibrium data are presented for three reservoir oils at conditions approximating those encountered in in-situ thermal recovery processes. The fluid systems involved consist of three major groups of components: flue gas, water, and crude oil. Data were measured at temperatures from 204.4 to 371.1°C (400 to 700°F) and pressures from 6996.0 to 20 785.6 kPa (1,000 to 3,000 psia). Experimental phase equilibrium data were used to develop a correlation of binary interaction coefficients of crude-oil fractions required for the Peng-Robinson equation of state. Phase equilibrium data predicted using the Peng-Robinson equation of state, using our interaction coefficients, are compared with experimental data. Generally, the Peng-Robinson equation of state predictions were in close agreement with the experimental data. Effect of feed gas/oil ratio and water/oil ratio on the equilibrium coefficients was examined through the Peng-Robinson equation of state. A study on the feasibility of representing the crude oil by only two fractions was made also. This study includes a procedure for lumping the crude-oil fractions and examples showing the importance of mixing rules in determining the pseudocritical properties of lumped fractions.
Xanthan Biopolymer Semipilot Fermentation
Authors: Norton Charles J. , Falk David O. , Luetzelschwab Wayne E. 
Published: December 2007

Abstract
Using standard microbiological techniques in a semipilot plant-scalable fermenter, xanthan-specific culture techniques developed by the U.S. Dept of Agriculture's Northern Regional Research Laboratory (NRRL) were used at Marathon Oil Co.'s Denver Research Center (DRC) to obtain improved and reproducible high conversions and yields of xanthan biopolymer broth. Practical nutrients and fermenter parameters were studied to define and improve the viscosity performance and economics of xanthan broth production for thickening water in the Maraflood™ enhanced oil recovery process.