bluuebunny/crossref_metadata_2025_split huggingface dataset:
Construction of a Stochastic Geological Model Constrained by High-Resolution 3D Seismic Data—Application to the Girassol Field, Offshore Angola
Authors: Lerat O. , Nivlet P. , Doligez B. , Lucet N. , Roggero F. , Berthet P. , Lefeuvre F. , Vittori J. 
Published: December 2007

Abstract
This paper presents a specific workflow developed to build a detailed geological model constrained by high-resolution 3D seismic data. The objective of the proposed approach was 1/ to integrate both geological and seismic information in a coherent fine-grid model at early stage of field production, 2/ to account for uncertainties in heterogeneity distribution, and 3/ to prepare the integration of 4D seismic data.
The first and critical step of this approach was the definition of a 3D grid of facies proportions from 3D HR seismic data to constrain the geological modeling process. A novel approach has been developed to account for scale differences between seismic and well data to obtain a detailed geological facies description.
In the second step, geological facies proportions derived from the seismic facies characterization have been optimized to minimize the differences between the seismic impedances of the average stochastic model and the real impedances.
In the last step, the truncated Gaussian algorithm has been used to generate stochastic realizations constrained by well data and geological facies distribution. Multiple realizations have been used to quantify uncertainty on facies spatial distribution.
This approach was applied successfully to the Girassol field, a complex and faulted turbidite field located offshore Angola. The objective was to build an initial geological model for an innovative history matching workflow integrating 4D seismic data (Roggero et al., [1]).
Thanks to the exceptionally high resolution of the seismic data, a 3D matrix of lithofacies proportions has been constructed with a resolution close to that of standard well logs (metric). Together with variograms, these geostatistical parameters have been used to generate equiprobable images of the geological model. Both well data and the seismic constraint are honored. Average sand proportions and volumes computed from ten realizations are in good agreement with the average values computed using the seismic constraint. Variability in the distribution of geological facies has been quantified and can be related to the uncertainty of the seismic constraint. This uncertainty has been reduced in the history matching process by introducing more deterministic geological information.
Field Implementation of Gravel Packing Horizontal Wells Using a Solids-Free Synthetic Fluid With Alpha/Beta Wave Technology
Authors: Aragão A. F. L. , Calderon A. , Lomba R. F. T. , Moreira J. N. V. C. , de Sá A. N. , Martins A. L. , Quintero L. , Moura E. 
Published: December 2007

Abstract
This article details the planning and execution phases of the first open hole gravel pack operation performed whith the alpha beta wave deposition technique using a non aqueous system as a carrier fluid. The operation was performed at Marlim Field, offshore Brazil, and constitutes the first field implementation of a research and engineering effort which started two years ago.
The idea in this first field operation was to avoid many changes in the original well design for the area and to concentrate novel steps in the fluid for gravel packing openhole design, friction loss evaluation, fluid substitution and rheology characterization are some of the new aspects detailed for the fluid design. Based on these results, optimized procedures were proposed for the operation. A broad description of the technical aspects, field pumping profiles and packing quality is also presented.
Stress-Dependent Permeabilities of Sandstones and Carbonates: Compression Experiments and Pore Network Modeling
Authors: Dautriat J. , Gland N. , Youssef S. , Rosenberg E. , Bekri S. 
Published: December 2007

Abstract
Mechanical effects are of great importance during reservoir production and induce sensible changes of the transport properties. This work focuses on the forecast of the change of porosity and permeabilities of reservoir rocks submitted to hydrostatic and deviatoric stress states representative of the field conditions. To predict these evolutions, we need to perform flow experiments with representative stress conditions. Our triaxial cell was designed to achieve this purpose and allows the measurement of permeabilities in the directions along and transverse to the principal direction of stresses. A good knowledge of the rock microstructures is also fundamental to choose the correct set of parameters for the simulation tools, and the input from our micro scanner facility is therefore of great importance. Using our directional permeability triaxial apparatus, we applied different stress paths to sandstones and carbonates samples and the evolutions of porosity and permeabilities were monitored during loading. We performed a microstructural analysis of these rocks using Mercury Porosimetry and Computed Micro Tomography imaging. From the 3D reconstructions, we extracted the poral network skeletons and the associated pore and throat size distributions. Then we performed two kinds of pore network modeling, one based on the real pore geometry and another based on a statistical description, to calculate the macroscopic transport properties. We included a model of pressure dependence of pore and throat sizes, based on deformation of porous inclusions in the framework of elasticity theory, to simulate the evolution of the transport properties with pressure. This model requires the knowledge of the elastic moduli of the rocks which were determined experimentally from the compression experiments. We show that the experimental determination of the evolution of directional permeabilities under hydrostatic and deviatoric stress conditions is feasible. The pressure dependences can be of valuable importance and therefore influence of mechanical effects should be investigated in experimental transport studies. Finally, we show that pore network modeling associated with CMT imaging can be used to forecast the pressure evolution of transport properties and therefore to understand the reservoir response to production.
Gas Bubble Nucleation of Extra-Heavy Oils in Porous Media: A New Computerized Tomography Technique and Physical Approach
Authors: Meyer V. , Pilliez J. , Creux P. , Graciaa A. , Luck F. , Franco F. , Mauduit D. , Montel F. 
Published: December 2007

Abstract
The study of multiphase flow pore level physic has scientific appeal as well as many applications, mainly in oil reservoir engineering. In this work, we show that micro-tomography is an effective tool to extract the structure of many solid systems in a non-destructive and classical manner. Recently, X-ray computed tomography tools have been extended to the ability to contrast fluids in the pore space of core samples.
As time required for collecting a CT image is much longer than almost flow time scales, CT imaging must occur at static flow conditions to accurate geometrical information on fluid-fluid and solid – fluid interaction.
Considering new decisive developments of the visualization cell we claim to have developed a new petrophysical tool which might permit to access experimentally to the visualization in quasi-static flow of the capillary phenomena and multiphase flows analysis in 3D form or in dynamic flow in 2D form. The in-situ measurements are realized in reservoir conditions of extra-heavy oils.
The aim of the measurements is first to contribute to a predictive bubble population balance which will then be integrated in a network flow model computation. This step is required to develop physical models to obtain a more efficient reservoir simulation. More precisely we focus our attention on a quasi static model of bubble nucleation which appears decisive and we demonstrate how to simulate the whole bubble nucleation and the corresponding experimental results to corroborate the experimental observations. We focus here on the influence of the gas availability in the porous media (diffusivity, GOR or porous media morphology).
World's First Metal PCP SAGD Field Test Shows Promising Artificial-Lift Technology for Heavy-Oil Hot Production: Joslyn Field Case
Authors: Beauquin Jean-Louis , Ndinemenu Felix , Chalier Gilles , Lemay Lionel , Seince Laurent , Damnjanovic Alex 
Published: December 2007

Abstract
Finding a reliable artificial lift pumping system for heavy oil thermal recovery has been a challenge mainly due to the high operating temperatures (&gt;150°C). Available options such as Rod Pumps and Electrical Submersible Pumps (ESP), which are well proven in the industry, are not particularly well suited to thermal production. While Rod Pumps offer high temperature service, they are limited in the flowrate they can deliver. ESPs on the other hand, can handle high volumes of low viscosity fluids, but are still limited in terms of maximum operating temperature.
Progressing Cavity Pumps (PCP), with elastomeric stator, is economic to run and have done well in heavy oil cold production. These elastomers are however limited in temperature (&lt;150°C). Through research work conducted by PCM and TOTAL, Metal PCP technology has been developed to meet the high temperature requirement of SAGD and other thermal recovery processes. Three models of the Metal PCP are now available to cover a wide range of flow rates for heavy oil production.
This paper presents an update on the Metal PCP development and the results of the world's first SAGD field trial of this type of pump currently on-going in Canada in the Joslyn field. Field performance data are discussed comparing high temperature ESP and metal PCP in actual LP-SAGD conditions.
Four SAGD well pairs were initially equipped with high temperature ESP. Another well pair was equipped with metal PCP. This well has been running since mid October 2006 without problems, in spite of low pressure at pump intake, close to steam flashing conditions. Production rate reached 200m3/d of liquid at 340rpm, giving a volumetric efficiency of 53%. Intake temperature is 160°C due to the LP-SAGD condition of the field. However, this pump is rated up to 350°C.
This first field trial shows the metal PCP as a promising artificial lift technology for hot production. Following this encouraging trial, a second metal PCP has been installed with success in the same field and more installations were decided eventually. Thus, all ESP initially installed were replaced by PCP and nine wells are producing with Metal PCPs currently.
Concept and Development of a Flow System for Handling and Exporting 600,000 bbl/day in Campos Basin, Brazil
Authors: Bordieri Eduardo , Vianna Cláudio Siqueira , Vidal José Oliveira 
Published: December 2007

Abstract
Considering demands for internal Brazilian market and international crude oil trade, PETROBRAS has taken the decision to concentrate a significantly part of the future of crude oil production from three deep-water fields; Roncador, Marlim Sul and Marlim Leste, all of which are in Campos Basin, with one off-shore terminal. The name of this project is PDET.
This project comprises of a fixed central pumping station, PRA-1, a large FSO (2,1 million barrels storage capacity), and two calm buoys systems, at a depth of 100 m.
The start-up of this project involves the crude oil from three producing platform; P-52, P-51 and P-53, which are all currently under advanced construction. In the future PDET will receive the production of crude oil from two additional new platforms.
Each producing platform will have its own export pipeline, direct to PRA-1. The peak production of this system will achieve 600,000 bbl/day. PRA-1 will have special requirements to pump crude oil either to FSO or to the calm buoys systems. Based on a steel jacket structure the capacity of power generation will be 75 MW, up to 34 inches pigging capacity and many diverse pipings.
The FSO has special specifications such as the electrical power and optical swivels, both are at a high level of technology and capacity. To achieve system's targeted reliability extensive studies were done. Integrity protection system, leak detection system, offloading time, sub-sea layout and flow rates were taken into consideration. Environmental risks were fully mitigated. The final configuration, which achieved high standard integrity assurance, produced a valuable project.
This paper describes the logistics of this project focusing PRA-1 pumping, the export system through calm buyos, sub-sea facilities and the FSO. Also it will be highlighted some management programs used to implement this project. This work reviewed the major aspects of implementing this important infrastructure offshore facility to transport crude oil.
Several technical and managerial challenges were surpassed through introduction of new technologies, tools and techniques.
Challenges Associated With Subsalt Tar in the Mad Dog Field
Authors: Romo Louis A. , Prewett Harry , Shaughnessy John , Lisle Ed , Banerjee Sanjay , Willson Stephen 
Published: December 2007

Abstract
The Mad Dog field is located in Southern Green Canyon approximately 150-miles south of New Orleans, in 4400-ft to 6800-ft of water (Figure 1). Mad Dog wells are sub-salt and are drilled to the Lower Miocene at approximately 19000-ft true vertical depth (tvd). The discovery well for the field was drilled in 1998. Drilling in the field has been challenged by "mobile" tar. Tar has been encountered in other deepwater fields; however, other reported tar deposits have not had the mobility of the tar encountered in the Mad Dog area
Extensive work has been conducted in developing the Mad Dog tar mitigation plan and has included characterization of tar, laboratory plunger experiments with Mad Dog tar, tar shoe design optimization, investigation of solvents and catalysts to solidify tar, investigation of downhole pyrotechnic heating, investigation of coating agents and the review of drilling practices. This paper will document the theory on the origin of the tar deposits, steps taken to deal with the tar and experience with the tar.
The Intrinsic Reliability of Manometric Sorption Apparatus Using Supercritical Carbon Dioxide
Authors: van Hemert P. , Wolf K-H. A. A. , Bruining J. 
Published: December 2007

Abstract
The sorption of CO2 on coal is of great interest when investigating the possibility of CO2 Enhanced Coalbed Methane or sequestration of CO2 in coal. The measurement of accurate supercritical CO2 sorption isotherms has proven to be a complicated matter. Therefore, a high accuracy manometric apparatus has been constructed and the reliability of the setup itself is thoroughly investigated. Experimental errors are categorized according to the source of the error, instead of the classical categorization of random and systematic errors. These sources are: (1) Background theory fallacies, (2) effects of minor importance, (3) observational errors and (4) interpretational errors.
The reliability of the set-up is investigated by examining the errors of the volume ratio measurements. Volume ratio measurements are sorption measurements, but simplified by not using a sample and without the cumulative effect of errors in sorption measurements. The volume ratio stems from a material balance and the expansion of gas from one cell to another. The pressure and temperature of both cells are measured before and after expansion. The density is calculated from the pressure and temperature with an Equation of State, which also must be of high accuracy.
The accuracy of volume ratios measured with helium and carbon dioxide is investigated. Helium measurements are the base case that demonstrates optimal measurement accuracy. The observed errors in the experiments with helium correspond to the a priori error estimation (σ ≤ 0.2%). The difficulty with CO2 measurements is identified as the high sensitivity of the CO2 density for changes in pressure, temperature and impurities in the 80-120 bar region at 318 K. The high accuracy manometric apparatus can measure CO2 volume ratios with an uncertainty of less than 2%, except between 90 and 110 bar where the uncertainty is less than 10%. This larger uncertainty is caused by impurities in the CO2 of unknown origin. The influence of leakage, changes in the cell volumes, water desorption from steel and the influx of contaminants are shown to be of negligible influence. The error assessment in this paper will serve as the basis of uncertainty analysis of future high accuracy CO2 sorption measurements.
Impact of Self-Consistent Physically-Based Three-Phase Relative Permeability on Oil Recovery by Secondary Gas-flooding
Authors: Alamdari Baharak Barzegar , LaForce Tara , Piri Mohammad 
Published: December 2007

Abstract
We use a three-dimensional random pore-scale network model to simulate gas injection into oil and water after primary drainage. The model is based on the physics of multiphase flow observed in micromodel experiments. Important features of immiscible fluid flow at the pore scale, such as wetting and spreading layers and wettability alteration are implemented. The pore network simulator is utilized to model relative permeabilities, saturation paths, and capillary pressures. A random network that represents the pore space in Berea sandstone is used in this study. Three-phase relative permeabilities generated by the network model are dependent on the saturation path, which is not known a priori.
This paper includes numerical and analytical solutions for a series of secondary gas-floods with relative permeabilities generated using the network model. Analytical and simulated solutions such as these illuminate the large impact of correctly accounting for the effects of saturation history in relative permeabilities in gas injection. This knowledge is critical for the design of EOR schemes such as tertiary gas injection and WAG flooding. It is demonstrated that saturation history has a substantial impact on the relative permeabilities, and hence oil recovery. For the examples studied here, the physically-based relative permeabilities with correct saturation history exhibit an extremely rare solution structure. This is a strong indication that many of the complex solution structures frequently encountered in analytical solutions for three-phase flow may be the consequence of permeability models with little or no physical basis.
To the best of our knowledge, this is the first study to perform an analysis of the effect of physically-based relative permeabilities, using a description of the pore space and its connectivity that mimics real systems, on the saturation paths and secondary oil recovery by immiscible gas injection.
Advanced Formation Testing in OBM Using Focused Fluid Sampling for Producibility Evaluation in Mature Fields
Authors: Beaiji T. , Zeybek M. , Crowell A. , Akkurt R. , Al-Dossari S. , Amin A. , Crary S. 
Published: December 2007

Abstract
Wireline formation testing provides formation pressures, high quality samples and fluid identification/characterization. In addition, it can provide information for reserve assessment and producibility estimation.
In this paper, we present comprehensive formation evaluation case histories with formation testing utilizing a focused sampling probe in wells drilled with Oil Base Muds (OBM) in mature fields. Due to OBM and low mobility sections, a new focused sampling device was utilized for effective formation testing and sampling purity. One case history demonstrates confirming remaining oil saturation. Conventional open hole and Nuclear Magnetic Resonance (NMR) logs were run for formation evaluation, and fluid saturations. Gas and remaining oil saturation were obtained from 3D NMR analysis. Sampling lab results and real time analysis of gas compositions are also compared for verification and confidence.
Two field examples in low porosity/low mobility zones are presented showing the identification of mobile fluids. It is shown that the existence of mobile oil could have been missed without effective formation testing practices.
The third field example of formation testing with low porosity as well as low resistivity is provided for the identification of mobile oil. Flow was enabled from low mobility zones along with low rate pumpout that would not be possible with traditional probe and pumpout devices.
The final field example of water sweep evaluation in high permeabilitiy/mobility zones demonstrates using formation testing as a means of reservoir monitoring.
Forecasting Injector-Producer Relationships From Production and Injection Rates Using an Extended Kalman Filter
Authors: Liu Feilong , Mendel Jerry M. 
Published: December 2007

Abstract
This paper presents an adaptive method, using an Extended Kalman Filter (EKF), to forecast the injector-producer relationships (IPRs) between multiple injectors and a single producer based on measured production and injection rates.
For this method, we used a very simple parametric model, one with two parameters per injector, so that if a producer depends upon N injectors our model contains exactly 2N parameters. The EKF is used to adaptively estimate the 2N parameters, from which the IPR between each injector and a producer is then estimated.
This approach was tested on both synthetic and real data. The former used Monte-Carlo simulations, whereas the latter used data from one of Chevron's oil fields. Test results on synthetic data demonstrate the feasibility of the EKF method, and test results on the real data match other field indications about the IPRs between injectors and a producer. All results confirm that this EKF method may provide a good way to infer and track the IPRs, and may provide better insight about the IPRs.
The Effect of Volume Changes Due to Mixing on Diffusion Coefficient Determination in Heavy Oil and Hydrocarbon Solvent System
Authors: Luo H. , Salama D. , Kryuchkov S. , Kantzas A. 
Published: December 2007

Abstract
The diffusion coefficient is a key parameter to describe promising solvent - based technologies for heavy oil and bitumen recovery. In this work, an extended diffusion model considering the volume changes on mixing was used to calculate the mutual diffusion coefficients for the heavy oil -hydrocarbon solvent system. The approach requires not only concentration profiles, but also data on volume changes in the process of mixing. The concentration profiles were obtained from diffusion laboratory experiments in which X-ray Computer Assisted Tomography (CAT) was used to measure the density distributions at different times. In addition, the volume changes data was obtained by performing heavy oil and hydrocarbon solvent mixing experiments at different content of solvent in heavy oil.
By comparing the diffusion coefficient versus concentration curves based on the extended diffusion model and on the usual diffusion model (1), it was concluded that the volume changes due to mixing make significant differences to the diffusion coefficient determination in heavy oil – hydrocarbon solvent system, and the mutual diffusion coefficients are strong functions of concentration, which is consistent with previous literature.