bluuebunny/crossref_metadata_2025_split huggingface dataset:
Porous Media Flow of Oil Dispersions in Polymers
Authors: Darwish Mohamed I. M. , van Boven Pim , Hensens Hans C. , Zitha P. L. J. 
Published: December 2007

Abstract
Polymer and polymer gels are well suited for reducing water production during oil and gas production, but there exist a risk that they reduce oil flow appreciably, together with water. The risk is smaller when water is reduced by disproportionate permeability reduction (DPR), but may be sufficient to instill caution about using the chemicals. This explains largely the frequent use of mechanical means to isolate oil layers and ensure that polymer enters only in the water layers where it is needed.
The use of mechanical isolation or, alternatively, dual fluid injection, is impracticable in most wells. This is particularly true for deviated, horizontal, and multilateral wells, which are being increasingly used in different parts of the world. In those wells there is a need of polymers and gel treatments that can be injected without the mechanical isolation of the oil layers (i.e., treatments that can be bullheaded).
This paper concerns the use of oil dispersion in polymers (ODP) to achieve low penetration of polymer in oil layers and, thereby, to ensure the diversion of polymers towards water layers, during bullheading treatments. Core flow experiments were conducted using sandstone cores saturated either with brine or oil. Thus far the following observations have been made.
The mobility reduction for the flow of oil dispersion in polymers (ODP) is stronger in oil saturated cores than in the water saturated ones. On the contrary, the permeability reduction is smaller for the oil saturated cores. This effect can be interpreted by a stronger viscous dissipation occurring during ODP flow in the presence of oil. The viscous dissipation arises primarily from droplet trapping and polymer adsorption.
The results show that the presence of oil droplets in the polymer solution may reduce the penetration of the polymer in the oil layers, and divert it from oil to water layers.
An Approximate Model for the Productivity of Non-Conventional Wells in Heterogeneous Reservoirs
Authors: Wolfsteiner Christian , Durlofsky Louis J. , Aziz Khalid 
Published: December 2007

Abstract
A semi-analytical method is presented for the approximate modeling of the productivity of non-conventional wells in heterogeneous reservoirs. The approach is based on Green's functions and represents an extension of a previous model applicable for homogeneous systems. The new method, referred to as the s-k* approach, models permeability heterogeneity in terms of an effective skin that varies along the well trajectory and a constant background permeability k*. The skin is computed through local, weighted integrations of the permeability in the near-well region and is then incorporated into the semi-analytical solution method. The overall method, which can also model effects due to wellbore hydraulics, is quite efficient in comparison to detailed finite difference calculations.
Results for the performance of non-conventional wells in three dimensional heterogeneous reservoirs are computed using the s-k* approach and compared to finite difference calculations resolved on the geostatistical fine grid. The new method is shown to provide an accurate estimate of wellbore pressure and production rate, as a function of position along the wellbore, for various well configurations and heterogeneous permeability fields. The possible use of the overall approach in a simulation while drilling (SWD) tool, in which the well path and trajectory are "optimized" using real-time data, is also discussed.
Sonic-Magnetic Resonance Method: A Sourceless Porosity Evaluation in Gas-Bearing Reservoirs
Authors: Minh Chanh Cao , Gubelin Greg , Ramamoorthy Raghu , McGeoch Stuart 
Published: December 2007

Abstract
For environmental reasons, there are times when the use of radioactive chemical sources for density and neutron logging is not possible. The inability to use these logging tools seriously affects porosity determination in gas-bearing reservoirs. Several tools, such as the nuclear magnetic resonance (NMR) tool, the sonic tool or a minitron-based tool, determine porosity without using a radioactive source. These tools, however, are influenced by many effects and, when used alone, cannot deliver an accurate gas-independent porosity.
A new methodology that combines sonic and NMR logs for improved porosity evaluation in gas-bearing reservoirs is proposed. The first variant of the method uses the sonic compressional transit time and the total NMR porosity (TCMR) to determine the total porosity, corrected for the gas effect, and the flushed zone gas saturation. In this approach, a linear time-averaged equation corrected for compaction is applied to the sonic compressional log. The simplicity of the solution (much like the previously published DMR1 Density-Magnetic Resonance Interpretation Method) allows fast, easy computation and a complete error analysis to assess the quality of the results.
In the second variant of the method, we show that the rigorous Gassman equation has a very similar response to the Raymer-Hunt-Gardner (RHG) equation for a water-gas mixture. This allows substitution of the complex Gassman equation by the much simpler RHG equation in the combined sonic-NMR (SMR) technique to estimate total porosity and flushed zone gas saturation in gas-bearing formations.
The technique is successfully applied to an offshore gas well in Australia. In this well, the porosity in the well-compacted sands is in the 20–25 p.u. range and the compaction factor is around 0.77. The sonic-magnetic resonance results compared favorably to the established density-magnetic resonance results and also to core data. In another offshore gas well from the North Sea, the porosity in the highly uncompacted sands is in the 35–40 p.u. range and the compaction factor is around 1.85. The SMR technique was able to produce a very good porosity estimate comparable to that estimated from the density-neutron logs.
Limited-Entry Frac Applications on Long Intervals of Highly Deviated or Horizontal Wells
Authors: McDaniel B. W. , Willett R. M. , Underwood P. J. 
Published: December 2007

Abstract
Long horizontal sections have been used increasingly in moderate-to low-permeability reservoirs. In these reservoirs, a successful program for applying fracture-stimulation treatments is a key component for commercial success. Historically, such wells have been stimulated with several separate fracture treatments, requiring expensive well operations between fracture stages. Successful zonal isolation for each fracture stage has been a primary reason for the success of this technique. This paper reports recent efforts by several operators to reduce completion costs by extending the application of limited-entry fracturing techniques to very long sections of highly deviated or horizontal wellbores, while ensuring effective fracture stimulation of each perforated section.
Many special innovations have been introduced recently for enhancing the applicability of limited-entry fracturing in long, openhole completions and in some uncemented liner applications. Some of these methods have been published; other unpublished methods are presented in this paper.
Case histories are presented for both sandstone and carbonate reservoir completions. Considerations that guided the wellbore azimuth, casing programs, perforating schemes, and fracturing program variables are presented. Known problems and unpredicted formation responses are also discussed.
Magnetic Resonance Relaxation-Tomography to Assess Fractures Induced in Vugular Carbonate Cores
Authors: Borgia G. C. , Bortolotti V. , Fantazzini P. 
Published: December 2007

Abstract
A method is presented to study fractures induced in full-size carbonate cores by means of Relaxation-Tomography (RT). This method combines nuclear magnetic resonance (NMR) relaxation and imaging techniques, and consists of obtaining, in addition to the usual 1H nuclei density (porosity) maps, images as relaxation time maps. By combining voxel-by-voxel signal intensity from the porosity map and relaxation time from the relaxation time map, one get the distribution of the signal intensity as a function of the relaxation time for selected internal regions of interest (ROI). The distribution of the signal intensity vs relaxation time gives information on the distribution of water in different structures inside the sample and therefore on the structure itself. One can compute the fraction of water in the ROI, relative to the total amount of water in the ROI, having relaxation time in a selected range. Also, average relaxation times, as the geometric mean, can be computed. In a previous paper (SPE 49294), we applied the method to quantify (following an operational NMR definition) matrix and vugular porosity in carbonate cores. In this paper we improve the computation of the relaxation time by introducing non-linear fitting of the data and extending the application to the study of fractures induced in carbonates. Several internal images from undisturbed vugular and microporous full-size carbonate cores saturated with water were obtained as porosity and longitudinal relaxation time (T1) maps. The T1 histograms from selected ROI's were obtained. Then, fractures were induced in the cores by repeated cycles of freezing and heating. The RT investigation was repeated on the treated cores after each step and the distributions of the relaxation times compared. The changes in the distributions suggest a twofold effect: the forming of new microfractures (increase of local surface-to-volume-ratio) and the expansion of pre-existing fractures (decrease of surface-to-volume ratio).
Determining Petrophysical Properties of Low Resistivity Reservoirs Using Nuclear Magnetic Resonance Logs
Authors: Hamada G. M. , Al-Blehed M. S. , Al-Awad M. N. J. 
Published: December 2007

Abstract
The combination of conventional logs such as density, neutron and resistivity logs is proven to be very effective in the evaluation of normal reservoirs. An accurate determination of the petrophysical parameters with the conventional logs for low resistivity reservoirs is very difficult. This paper presents the two cases of low resistivity reservoirs and low contrast resistivity reservoirs. The problem of these reservoirs is that conventional logging interpretation shows water zones, but water free hydrocarbon would be produced. In the case of low resistivity contrast reservoirs it is very hard to determine water hydrocarbon contact with resistivity logs.
Nuclear magnetic resonance (NMR) has been only available as a supplement tool, to provide additional information on the producibility of the reservoir. The main limitation of NMR, however, has been the cost and time of acquiring data. This paper shows that in the case of low resistivity reservoirs NMR is very cost-effective tool and helps to accurately determine the reservoir rock petrophysical properties. In the analysis of NMR data, several aspects of NMR technique have been used; 1) T1/T2 ratio for fluid identification, 2) the difference between NMR derived porosity and total porosity to determine the types of clay minerals, 3) NMR relaxation properties to identify fluids nature and rock properties
This paper presents four examples of low resistivity reservoirs. Analysis of NMR data of low resistivity reservoirs has helped to identify the producibility of these zones, to determine lithology independent porosity and to distinguish between bound and free water. For the case of low contrast resistivity reservoir where there was little resistivity contrast between water bearing formation and oil bearing formation, NMR has been able to identify the fluid nature of the two formations and then accurately the height of the oil column. This was based mainly on high contrast of NMR relaxation parameters.
A New Method to Interpret Two-Phase Profiles From Temperature and Flowmeter Logs
Authors: Li H. , Zhu D. , Lake L. W. , Hill A. D. 
Published: December 2007

Abstract
The conventional method to measure two-phase flow rates downhole combines flowmeter and holdup measurements. This method requires assumptions about slip velocity to interpret the flow profile for both phases. Uncertainty about the slip velocity and errors in both holdup and velocity measurements often reduce the reliability of the method. As a consequence, there has been substantial effort concentrated on developing new tools for two-phase flow well measurements.
This paper presents a new way to use conventional tools, a temperature and a flowmeter log, to determine the flow rate of each phase for wells producing oil and water. The method is based on a simultaneous solution of mass and energy balances, which provides independent sets of information, if the oil/water heat capacities are different, to infer the flow rates of both phases with depth. The new method does not depend on slip velocity assumptions. This paper presents the mathematical model of the new method, and discusses the feasibility and reliability of the method. We illustrate the method with both synthetic and field cases with satisfactory results.
The Relation of Pore Size to NMR T2 Diffusional Relaxation in Porous Media
Authors: Xu Xinwei , Davis Lorne A. 
Published: December 2007

Abstract
A thorough understanding of the NMR relaxation mechanisms of fluids in rocks is of central importance to modern NMR log interpretation. The T1 and T2 bulk fluid response and surface relaxivity are currently better characterized than is the T2 diffusional relaxation. This latter T2 relaxation mechanism is a phasing incoherency which develops as the molecules that bear the proton spins diffuse across strong internal field gradients generated by the susceptibility contrast between rock and pore fluid when a sample is placed in a magnetic field. The CPMG T2 measurement pulse sequence is unable to refocus the spins effectively when they are subject to such a time-varying internal field, and the observable signal decays.
To characterize this diffusional loss mechanism, the proton T2 relaxation rate at 2 MHz in synthetic mono-disperse porous media was studied as a function of pore size, pore fluid and CPMG inter-pulse spacing τ. The results are compared to higher field data (85 MHz) and to relaxations in Berea sandstone and Bedford limestone. In addition, the effects of a static applied gradient G were investigated.
Over the entire range of τ, the T2 diffusional relaxation rate had a well-defined inverse dependence on pore radius. As expected, mono-disperse samples were adequately characterized by a single exponential decay. For small values of the refocusing time τ (the CPMG inter-pulse spacing), the T2 diffusional relaxation rate was proportional to τ. For large τ, this relaxation was independent of τ. The relationship of the effects of τ and G on T2 relaxation are developed to quantitatively explain how the CPMG T2 measurements in static field gradients of logging tools differ from the results done with lab spectrometers without gradients.
Enhanced Wellsite Technique for Oil Detection and Characterization
Authors: Delaune P. L. , Spilker K. K. , Hanson S. A. , Wright A. C. , Quagliaroli R. 
Published: December 2007

Abstract
Fluorescence has been used as a means of detecting oil while drilling since first introduced in the 1930s. The visual technique is recognized to be subjective, making it unreliable for consistent detection of oil in formation samples. The Quantitative Fluorescence Technique (QFT™) introduced in the early 1990s uses a portable fluorometer to measure the fluorescence of crude oil extracted from a formation sample. The intensity of the fluorescence is proportional to the amount of oil in the sample. QFT™ was a substantial improvement over the visual technique for detection of oil in drill cuttings or cores, but still provided only a relative measure of oil in the sample.
An enhanced technique called QFT2™ has been developed that provides improved estimates of oil quantity and character from measurements made on drill cuttings or core samples. QFT2™ involves a two-point fluorescence measurement that yields estimates of both quantity (Weight % Oil) and oil type (API gravity). While these estimates are not a substitute for laboratory analysis, the speed, accuracy and ease of application make QFT2™ a practical tool for the determination of oil concentration and API gravity at the well site. QFT2™ can be used effectively on fresh drill cuttings or cores, or older samples from wells previously drilled. Results can be combined with wire-line hydrocarbon porosity data to estimate volume percent oil in the formation, and resultant data can be further evaluated to estimate oil mobility.
QFT2™ was developed by Texaco and finalized in a joint development project with ENI-Agip Division. The project evaluated a world-wide suite of oils to determine relationships between surface measurements and in-situ conditions.
Optimal Locations and Performance Prediction of Horizontal Oil Wells in the Oil Rim at Mahogany Field, Offshore Trinidad
Authors: Ali-Nandalal J. , Staines M. , Bally Y. K. , Finneran J. M. 
Published: December 2007

Abstract
The 21 Sand reservoir in the Mahogany field has a 63-75 ft oil leg overlain by a gas cap and underlain by water. In order to utilize reservoir energy and efficiently develop the field, the oil reserves must be recovered prior to producing the gas which is dedicated to the Atlantic Liquified Natural Gas plant in Trinidad. A horizontal well program was planned to develop the oil leg. An in-house reservoir simulator was used to predict performance of the oil wells.
The 21 Sand is 400' thick and has been segregated into 7 stratigraphic intervals. One hundred and twenty feet (120 ft) of core was acquired through these intervals and the petrophysical properties were measured on representative plug samples. This data was then correlated to well log data. Porosity-permeability flow units were then derived for optimum well placement. Modified-Lorenz plots (Ref. 1) were used to identify the units that would contribute to the flow and those that would act as baffles. Three dimensional visualisation models were then used to place the horizontal wells in high quality reservoir rock. Additionally, placement of the development wells for the deep gas reservoirs was designed to provide vital structural and stratigraphic information for potential heel and toe points for horizontal drilling.
This paper describes how all this work was compiled into a simulation model which has successfully predicted the current well producing rates and pressure draw down.
Object-Based Modeling of Fluvial / Deepwater Reservoirs with Fast Data Conditioning: Methodology and Case Studies
Authors: Shmaryan L. E. , Deutsch C. V. 
Published: December 2007

Abstract
This paper presents a new method for fast fluvial and deepwater stochastic simulation. Sinusoidal channels and attached levees and crevasse splays are generated to honor global net-to-gross ratios, vertical and areal proportions and well data.
Fast conditioning to well data is achieved without resorting to time-consuming iterative procedures such as simulated annealing. The undulating channel centerline is created by 1-D conditional sequential Gaussian simulation. Direct conditioning is also used for the reproduction of 2-D areal proportions.
The method has been applied to a fluvial reservoir in the North Sea with 16 wells and to a braided channel reservoir with 110 wells in Mexico. The dependence of CPU time to a number of different factors was explored. The CPU time for the proposed method and annealing based algorithm are compared. The method with direct well conditioning is an order of magnitude faster than annealing based method.
New Insights into Proppant-Pack Damage Due to Infiltration of Formation Fines
Authors: Blauch Matt , Weaver Jim , Parker Mark , Todd Brad , Glover Mark 
Published: December 2007

Abstract
Many wells completed in soft, poorly consolidated formations tend to underperform because of drilling and completion prac-tices in which formation-incompatible fluids are lost to the formation, resulting in significant near-well permeability loss. Advances in soft-rock stimulation technology have made frac-packing the preferred method for bypassing this formation damage. Choosing a suitable proppant for frac-packing soft formations is often paramount to overall stimulation success because many soft formations produce fines that can plug screens or packs.
Numerous studies describe the optimization of proppant size as a way to minimize fines invasion into the proppant pack and maximize conductivity. A recent study suggests that the conventional proppant-sizing criteria can be increased to pro-vide increased conductivity while maintaining sufficient fines invasion properties by the simple application of a tackifier to the surface proppant grains. This work indicated that the formation of a stable proppant-pack formation interface is key in preventing formation fines invasion into the proppant pack.
The data presented in this paper show the long-term maintenance of permeability and conductivity for packs that are invaded by fines. The proppant-pack data compare packs treated with a tackifier to untreated packs. Laboratory model study results are provided for a variety of materials and flow regimes. In addition, this paper addresses finer-sized fines infiltration that can cause deep proppant-pack damage. It is generally believed that finer particles produce through the proppant pack without causing significant permeability reduction. The impact of adsorbing finer particles onto a tackified proppant surface is addressed.