bluuebunny/crossref_metadata_2025_split huggingface dataset:
Imbibition Processes in Fractured Chalk Core Plugs with Connate Water Mobilization
Authors: Nielsen C. M. , Olsen D. , Bech N. 
Published: December 2007

Abstract
A displacement process in a chalk core plug with an induced axial fracture uses the fluid system H2O-D2O-n-decane. Initially the plug contains a mixture of D2O and n-decane with oil saturation equal to 88 %. The plug is flooded with H2O. The displacement process is monitored by NMR with a chemical shift technique enabling spatial resolution of the H2O and oil signals. The D2O component is not directly detected, but is calculated from the difference between the actual signal intensities and the signal intensities in a situation where the pore space is completely saturated with H2O and oil.
H2O-D2O-oil constitutes a partly miscible fluid system which is an analogy to the injection water-formation water-oil system of a hydrocarbon reservoir under waterflooding.
The injected H2O traverses the sample as a well-defined front together with capillary uptake from the fracture plane. Ahead of the H2O front the D2O of the sample is mobilized and travels as a bank in front of the H2O. Though the initial concentration of D2O is only 12% the D2O concentration reaches 50 % at the bank.
The experiment was simulated by means of ECLIPSE with a fair match of the displacement process.
The injected H2O has only made limited contact with the produced oil of the sample. In case of chemical EOR processes connected to waterflooding of hydrocarbon reservoirs a similar displacement situation could seriously affect the efficiency of the EOR process.
Reservoir Engineering Analysis of Microbial Enhanced Oil Recovery
Authors: Bryant Steven L. , Lockhart Thomas P. 
Published: December 2007

ABSTRACT
We assess processes for enhancing oil recovery by means of microbes (MEOR) from the perspective of reservoir and reaction engineering. In this work, MEOR implies recovering incremental oil by means of increased displacement and/or volumetric efficiency; it does not include well stimulation treatments. MEOR processes address the same physical parameters as chemical EOR processes such as surfactant flooding, polymer flooding, alkaline flooding, etc. They are hence subject to the same technical difficulties: identifying and locating the target oil; retention, dissipation and consumption of chemicals in the formation, etc. The essential difference between MEOR and chemical EOR resides in the method of introducing the recovery-enhancing chemicals into the reservoir.
An examination of the literature shows that MEOR generally does not recover as much remaining oil in place as other chemical EOR processes, either in the laboratory or the field. Efforts to explain this difference are severely limited by the lack of quantitative measures of microbial performance (reaction rates, stoichiometry, required product concentrations, etc.) It is possible, however, to demonstrate quantitative relationships between microbial performance, reservoir characteristics, and operating conditions (well spacing, injection rates, residual oil saturation, etc.).
We conclude that MEOR is potentially a "high risk, high reward" process, depending on whether it can use residual oil as an in situ carbon source for the production of recovery-enhancing chemicals. The reward in this case is that the difficulty and the logistical costs of implementing the process would approach those of implementing a waterflood. The high risk is associated with the many and severe performance constraints that a microbial system would have to satisfy in order to take advantage of an in situ carbon source. The current state of knowledge fails to provide satisfactory evidence that existing systems can meet the constraints identified in this study; thus an ambitious program of research and development would be required to determine MEOR feasibility.
Use of Highly Acid-Soluble Chelating Agents in Well Stimulation Services
Authors: Frenier Wayne W. , Wilson David , Crump Druce , Jones Ladell 
Published: December 2007

Abstract
Chelating agents are materials that are used to control undesirable reactions of metal ions. In oilfield chemical treatments, chelating agents are frequently added to stimulation acids to prevent precipitation of solids as the acid spends on the formation being treated. These precipitates include iron hydroxide and iron sulfide. In addition, chelating agents are used as components in many scale removal/prevention formulations. Two different types of chelating agents are in use: polycarboxylic acids (including polyaminopolycarboxylic acids) and phosphonates. Chelating formulations based on ethylenediaminetetraacetic acid (EDTA) have been used extensively to control iron precipitation and to remove scale. Formulations based on nitrilotriacetic acid (NTA) and diethylenetriaminepentaacetic acids (DTPA) also are in use. Each of these materials has problems: 1) EDTA has low solubility in hydrochloric acid and is not readily biodegradable in standard laboratory tests. 2) NTA is acid soluble and biodegradable, but has a lower stability constant for iron than EDTA (or DTPA) and is considered to be an animal carcinogen. This report describes the search for the "universal" or "ideal" chelating agent for use in oilfield services. The materials evaluated include hydroxy-aminopolycarboxylic acids (HACA) such as hydroxyethylethylenediaminetriacetic acid (HEDTA) and hydroxyethyliminodiacetic acid (HEIDA) as well as other types of chelating agents.
Drilling of Multitarget Sinusoidal Wells to Manage Geological Uncertainty and Poor Reservoir Connectivity on the Njord Field, Offshore Norway
Authors: Tistel Jan Ivar , Andresen Svein , Lien Svein C. 
Published: December 2007

Abstract
The Njord field offshore Norway produces oil from a highly faulted and heterogeneous sandstone reservoir where both vertical and lateral communication is severely restricted. This paper describes how novel multitarget sinusoidal well designs have been successfully drilled and completed on Njord in order to increase production and reserves.
Determination of Hydrocarbon Properties by Optical Analysis During Wireline Fluid Sampling
Authors: Dusen Alexandra Van , Williams Stephen , Fadnes Finn Hallstein , Irvine-Fortescue Jamie 
Published: December 2007

Abstract
Recent innovations in wireline fluid sampling have allowed the expedient recovery of high quality oil samples. The use of the Optical Fluid Analyzer* (OFA), a part of the Modular Formation Dynamics Tester* (MDT), to predict sample fluid type and quality has now become an essential part of the sampling process. The ability to use the optical data from the OFA in a more quantitative manner has been under development for several years. This paper demonstrates that the analysis of the optical spectra measured downhole, can be used to give a quantitative indication of some hydrocarbon properties prior to or during sampling. Clearly, there are many potential benefits from using these optical spectra whilst sampling to assist in reservoir characterization and determination of oil type.
Optical data gathered while taking oil samples in 21 wells, drilled with water based mud, offshore Norway were correlated with the PVT properties of those samples. These samples were selected to ensure a wide range of oil types in order to establish correlations between the fluid and optical properties. Correlations have been found between the optical response and some fluid properties as determined from PVT laboratory measurements of the samples. Oil density, saturation pressure (Pb), oil compressibility (Co), formation volume factor (Bo) and gas oil ratio (GOR) gave good correlations. Weaker correlations were found with other properties. GOR as well as optical responses could become measured variables with the possible future addition of a GOR measurement sensor to the MDT. Improved correlations are demonstrated when this feature is simulated. The results of this study show that the optical data measured during wireline fluid sampling can help determine key in-situ hydrocarbon properties.
NMR Signal Pattern Classification for Estimation of Petrophysical Properties
Authors: Rodrigues Patricia , Alcocer Yuri , Matheus Justo 
Published: December 2007

Abstract
NMR signals measurements are being widely used to estimate reservoir petrophysical properties, which directly impact calculations of recoverable oil. NMR T2 distribution curves have plenty of information about rock properties, however most of the work done on this matter has been concentrated in studying only few parameters of that curve (logarithmic and geometric averages). This work is focused on the use of the total T2 distribution curve for better prediction of petrophysical properties. This means using all information of the NMR T2 distribution spectra instead of an average of them. The approach consists in the use of data mining techniques for a NMR T2 curves pattern classification. The algorithm used identified several patterns, which correlated with rock "storage" properties, such as porosity, FFI, BVF and T2 cutoff, with no apparent correlation for permeability. Using only short times of the curves, it was possible to, obtain an excellent correlation with the "transport" property of the system (permeability), reducing significantly the correlation with "storage" properties. The same analysis was done using the long times of the curves, with no correlation. These findings showed that the use of the total T2 distribution curve relates to rock "storage" properties and the use of short times of the same curve relates to "transport" properties. This very important result indicates that a specific non-linear algorithm should be used to predict the different rock properties, "storage" (porosity, FFI, BVF and T2 cutoff) vs. "transport" (permeability), from NMR signals. This new approach can potentially improve reservoir characterization and estimation of oil reserves, improving reservoir characterization and exploitation management.
A Mechanistic Model Based Approach to Evaluate Oil/Water Slip at Horizontal or Highly-Deviated Wells
Authors: Ouyang Liang-Biao 
Published: December 2007

Abstract
Slip velocity between phases is an important factor in interpreting production logging survey, however, no much work has been done for determining the slip velocity when oil and water flow simultaneously in a horizontal or highly-deviated well.
There are several correlations and models that may be used to determine the slip velocity, nevertheless, they were developed for vertical wells and can not be applied for horizontal or highly-deviated wells due to the different mechanisms dominating the fluid flow.
An approach has been taken to develop a flow pattern-based method to evaluate the slip velocity for oil and water flow in horizontal or highly-deviated wells. More testing of the new approach will be conducted once experimental data is available.
Detection and Characterization of Fractures in Naturally Fractured Reservoirs
Authors: Verga F. M. , Carugo C. , Chelini V. , Maglione R. , Bacco G. De 
Published: December 2007

Abstract
Imaging log, sonic log, optical microscopy, NMR, MRI, and tomography have greatly enhanced the possibility of measuring fracture geometric characteristics. However, the fracture hydraulic width and permeability can only be evaluated from dynamic data revealing production or adsorption along the wellbore. Different analytical approaches accounting for mud rheology and their application to several field cases where mud losses were recorded with electromagnetic flowmeters are presented to evaluate the fracture hydraulic width from mud loss measurements. Observation of mud loss evolution in time also revealed whether a single fracture or an intensely fractured zone had been intercepted by the drilling bit. Results are discussed with respect to imaging log data, core analyses, and well test interpretation results. In general, a very good correspondence was found between mud loss occurrence, fracture detection from imaging log, core data, and productivity tests.
Well Testing in Ultra-High Permeability Formations
Authors: Cox D. O. , Stinson S. H. , Stellavato J. N. 
Published: December 2007

Abstract
Nye County, Nevada is the home of the Yucca Mountain Project, which is the proposed site for a high-level nuclear waste disposal facility. Over the last several years, Nye County has conducted an independent scientific program to evaluate the properties of the rock units around the proposed disposal site. This work has included drilling and testing several water monitor wells in clastic, valley-fill deposits. These tests indicated extraordinarily high permeability (up to 300 darcies) in some units. Well testing in reservoirs with such ultra-high permeabilities provides a unique opportunity to identify and evaluate reservoir heterogeneities. Analyses of three tests are presented.
The Nye County tests demonstrate the applicability of petroleum-industry well-test analysis methods even for ultrahigh permeability reservoirs. The tests show a large number of unusual effects (ultra-high permeability, extreme wellbore storage, linear flow, radial flow, hemispherical flow, multiple layers, multiple boundaries, wide range of compressibility, atmospheric corrections for a pumping well, etc.) in just a few tests. The test data and interpretations are publicly available and constitute an important database for well test analysis education and training.
Petrophysical Inversion of Resistivity Logging Data
Authors: Zhang Zhiyi , Chunduru Raghu , Frost Elton , Mezzatesta Alberto 
Published: December 2007

Abstract
Inversion is a powerful tool for interpreting resistivity-logging data in complex situations, such as deep invasion, high conductive shoulders, thin beds, anisotropic formations, and highly deviated and horizontal wells. Inversion also provides a general means to interpret data from earlier, unfocused resistivity tools as well as the new generation of array-type instruments, allowing for accurate delineation of the resistivity structure. Although, in most cases, inversion produces solutions that are consistent with petrophysics and geology, there are occasions where consistency is not achieved. In order to address these inconsistencies, we have developed a petrophysical inversion algorithm that involves gamma ray, neutron, density, acoustic, and resistivity data in a single, unified interpretation process.
The steps in the interpretation process consist of estimating bed boundary positions from all available measurements, including gamma ray, neutron, density, and resistivity data, using a weighted inflection point method. Bed boundary positions are then adjusted using the tool response functions associated with the various instruments involved and integrated to produce a consistent set of bed boundaries, which best represents the subsurface geology and lithology. Next, upper and lower bounds for formation resistivity and flushed zone resistivity are estimated using an appropriate water saturation equation. Input for resistivity bound estimation includes shale volume, porosity, as well as the possible range of variation for water saturation, formation water resistivity, and shale resistivity. The resistivity bounds are incorporated into the inversion algorithm via an outside penalty function added to the original objective function of the optimization. The proposed inversion algorithm utilizes a generic objective function including a reference model and data weighting based on uncertainties. Furthermore, a first-order spatial-finite difference operator has been built into the objective function to eliminate unrealistic oscillations in the inversion results. A field case example shows that the proposed inversion process can effectively handle systematic noise in the data caused by borehole washouts and inappropriate bed boundary positioning, and generates petrophysically meaningful inversion results.
Reservoir Characterization for Naturally Fractured Reservoirs
Authors: Baker Richard O. , Kuppe Frank 
Published: December 2007

Abstract
Reservoir characterization and simulation modeling of naturally fractured reservoirs (NFRs) presents unique challenges that differentiate it from conventional, single porosity continuum reservoirs. Not only do the intrinsic characteristics of the fractures, as well as the matrix, have to be characterized, but the interaction between matrix and fractures must also be modeled accurately.
Three field case studies have been evaluated combining the "forward" modeling approach, typically used by geo-scientists, with "inverse" techniques, usually incorporated by reservoir engineers. The forward approach examines various causes of natural fractures and its' associated properties (e.g. fracture spacing, height, stress distribution, etc.) while the inverse approach focuses more on the effect created by the NFR (e.g. decline analysis, material balance, productivity, etc.).
This study shows how a more powerful methodology is created, for the evaluation of naturally fractured reservoirs, when combining two techniques that have, historically, been applied in relative isolation.

Introduction
The development of reservoir modeling and reservoir characterization for Naturally Fractured Reservoirs (NFRs) has lagged behind simpler matrix flow dominated rock systems due to the practical difficulty in quantifying both matrix and fracture parameters. The complexities of, numerical and mathematical calculations have historically constrained the development of NFR modeling1. This paper shows a number of integrated field studies, which have addressed the difficulties in characterizing NFRs, and presents a proven methodology to characterize and model them.
Reservoir characterization presents a unique challenge in NFRs because of:the need to characterize the fractures as well as the matrixthe need to characterize the matrix-fracture interaction.
Characterization of the fracture includes defining parameters such as inter-fracture spacing, length, orientation, porosity, connectivity, aperture and permeability. As well, it is important to include realistic areal and vertical heterogeneity in both the matrix and the fracture systems.
A fractured medium represents a highly heterogeneous system. Fluid transport and pressure dynamics cannot be fully replicated in a model using a homogeneous three-dimensional system.
Recent work has emphasized the need to better characterize heterogeneities in matrix properties. The same attention, if not more, needs to be given to the characterization of fracture heterogeneities. Reservoir characterization is highly dependent upon the integration of skills from geologists, geophysicists, petrophysicists and reservoir engineers to an even greater extent in NFRs than in conventional reservoirs.
The methodology presented ensures compatibility between the geological and engineering models. Specifically, this paper will show how NFR parameters were determined for the three fields in which this methodology has been applied.
Flood Evaluation by Log Analysis for Improved Recovery in Producing Wells
Authors: Smith Roger L. , Menzel R.M. 
Published: December 2007

Abstract
Until recently, the only parameter that usually could be accurately determined from log analyses of wells that had been flooded for secondary recovery was porosity. Now, using new techniques, it is often possible to determine whether the primary fluid produced from a zone will be connate water, flood water, oil, or gas. Actual gas saturations can be calculated, and, in open hole, wireline formation-pressure tests can be made.
This paper will discuss several log-interpretation techniques which can be used to help define the zone-by-zone production of a producing well in a field being flooded. Their further implementation by wireline-formation-pressure tests in open hole will also be mentioned. All of these techniques have been used successfully in the Permian Basin. Their uses and limitations will be briefly outlined.

Introduction
A major problem in log evaluation of fields being flooded has been that, due to the encroachment of flood water, the waters in different zones frequently have different salinities. It has been impossible, therefore, to compute water saturations accurately with just a resistivity log or just a pulsed-neutron-capture (PNC) log, since such pulsed-neutron-capture (PNC) log, since such calculations require that the analyst know the water salinity in each zone. However, using the two tools together it is usually possible to differentiate oil-producing zones from flood-water-producing zones. Thus, flood-breakthrough zones may be identified and squeezed or plugged off.
In addition to producing unwanted flood water, the operator often finds that a secondary gas cap has developed in his reservoir, causing gas production to increase drastically. Using cased-hole logs, the gas-oil contact can be defined. Gas saturation can be determined through the use of PNC and porosity logs for either open-hole or cased-hole completions. Under some conditions, oil and water saturations may also be determined.
In the Permian Basin oil wells have commonly been completed open hole. In these wells, a Repeat Formation Tester (RFT*) can be used to take as many formation-pressure tests as desired on one trip in the hole.
A Family of Viscous Gelled Water Systems Featuring Moderate Polymer Loadings and Low Residue on Breaking
Authors: Hannah Robert R. , Matson Bill G. 
Published: December 2007

Abstract
It has been realized for a number of years that guar gum, the most commonly used polymer for thickening water-based fracturing fluids, has a significant amount of insoluble residue. This material has retained its popularity over the years because it has a high popularity over the years because it has a high viscosity yield per dollar spent compared to other suitable polymers. Repeated laboratory testing on productive cores has also proven that damage to matrix permeability is negligible and confined to the immediate fracture wall.
Attention has recently been focused on the potential damage that can be done to the sand potential damage that can be done to the sand pack or proppant pack by heavy residue guar pack or proppant pack by heavy residue guar gels and the subsequent reduction of fracture conductivity.
Extensive research has been done to develop fluids which retain the yield of high concentration quar gum gels while at the same time reduce the damage done by insoluble residue. Simple gels formed by high concentration synthetic polymers (H.E.C., C.M.C., etc.), while free of residue, are prohibitively expensive.
This paper will discuss a family of gels designed to meet or exceed the viscous yield furnished by guar gum gels that are low or free of residue and can be pumped at a price competitive with the high concentration guar gum gels.
In each case a base gel with a low to moderate polymer loading is crosslinked after sand addition with a consequent increase in viscosity.
Clean fracturing systems will be discussed with emphasis on fluid loss, rheology, and applications. A broad range of case histories will be presented to illustrate the application of these systems in the field under a variety of conditions. Criteria for the selection of individual gel systems to match particular well conditions will be presented.
The use of these moderate polymer concentration crosslinked systems is rapidly displacing the traditional gelled water fracturing systems. Their popularity is due not only to cleaner polymers but to their ability to furnish high viscosity systems without undue polymer loadings. The use of these and polymer loadings. The use of these and similar systems is desirable in all applications where the need for fracture conductivity dictates that damage be reduced to an absolute minimum.