bluuebunny/crossref_metadata_2025_split huggingface dataset:
Study of Skin Damage in Unconsolidated Sandstone by Computed Tomography
Authors: Sales E. S. , Bianco L. C. B. , Queiroz Neto J. C. , Campos E. F. , Lopes R. T. 
Published: December 2007

Abstract
It is well known that the porous media invasion by components of drilling fluids decreases near wellbore permeability and it is one of the factors that generate poor well productivity or injectivity. Permanent changes on the original permeability decrease well flow capacity and only can be evaluated after a well production test. The quantification of the difference, the damage, is defined as the mechanical skin. Among others, two particular factors contribute for mechanical skin during the drilling process: reduction on the oil or gas saturation by the drilling fluid filtrate and reduction on the effective porous throat size by bridging or aggregation of solids and other components.
The measure of the damage, its extent and remedial treatments has been studied since a long time using the API linear flow cell and filtration tests. However, the results obtained with this equipment do not allow an effective quantification that could be applied directly to the field mainly because of the test geometry.
In this study, a technique to quantify physically the damage has being evaluated, using a physical simulator composed by a X-ray transparent radial flow cell, hollow cylinder synthetic sand core sample saturated with mineral oil after full water saturation, the X-ray Computerized Tomography (CT) and a procedure to evaluate the permeability return. The invasion profile for water-base drilling fluid components were mapped after drilling simulation and the residual damage was quantified after an oil production period.
The results of this study showed that: permanent changes occurred on the porous media structure, which incorporated drilling fluids components at the grain and oil saturation was dramatically reduced. Both damages were not removed with the reverse flow of oil, generating a relative oil permeability reduction that was calculated in terms of mechanical skin associated.
Optimization of Stimulation Treatments in the Wamsutter (Almond) Formation by Means of Prefracture Impulse Diagnostic Tests
Authors: Rajappa Bharath , Maudgalya Saikrishna , Sullivan Richard B. 
Published: December 2007

Abstract
The Wamsutter (Almond) formation in southwest Wyoming is a tight gas reservoir in the eastern part of the Greater Green River Basin (GGRB). The Almond formation is generally encountered between depths of 8,500 and 10,500 feet with reservoir pressures varying from initial conditions (0.54-0.58 psi/ft) in the Lower Almond to varying stages of pressure depletion in the Upper Almond. The Almond interval is generally completed via massive hydraulic fracture stimulation down casing with a series of treatments targeting the Lower, Main and Upper Almond intervals. These zones are subsequently commingled for production.
In the absence of reservoir properties such as in-situ reservoir permeability, reservoir pressure, and closure stress, it has been difficult to optimize the stimulation treatments on a zonal basis. To identify these reservoir characteristics, pre-fracture impulse injection testing has been performed in each interval. These simple, easy to perform transient tests have aided in the interpretation of the key reservoir parameters.
This work presents data from eleven wells in the Wamsutter field and describes the methodology used to optimize the stimulation treatments. Reservoir properties obtained from the impulse tests helped eliminate the addition of nitrogen to the fracturing fluid, which had been routinely included to aid fracture clean-up after fracture stimulation. This design change has led to more effective fracture stimulation treatments yielding higher gas production rates while significantly reducing completion costs.
Production from wells stimulated with the modified design is compared to production from wells that were stimulated without the benefit of reservoir properties obtained from the pre-fracture impulse tests.
Field Studies of Drilling and Completion Fluids to Minimize Damage and Enhance Gas Production in Unconventional Reservoirs
Authors: Penny Glenn , Pursley John T. 
Published: December 2007

Abstract
Field data and lab data are presented for various fluids pumped in low perm shales, coalbed methane and tight sandstone reservoirs. Commonly used surfactants, alcohols as well as a microemulsion system (ME) are evaluated. Lab data is presented that illustrates the cleanup of injected fluids in tight gas cores. Damage mechanisms are shown to be phase trapping and high capillary pressures. The microemulsion additive results in lower pressures to displace injected fluids from low permeability core samples over conventional surfactant and methanol treatments. The observed enhanced relative permeability mechanism is the alteration of the rock-fluid interfacial tension or contact angle. It is demonstrated that this alteration effectively lowers the capillary pressure and capillary end effect associated with wellbores and fractures in low perm reservoirs by as much as 50%, thus mitigating phase trapping and therefore permitting an increased flow area to the wellbore following drilling and hydraulic fracturing.
Over 300 wells were evaluated that were drilled and/or fracture treated with various fluid combinations in the Barnett, Fayetteville and Appalachian basin shales. Some 200 wells are examined in the San Juan Basin and other low perm areas such as the Pieance Basin, Uinta, Vicksburg and Cotton Valley. Drilling examples are shown for several horizontal wells. The addition of the microemulsion to fracturing treatments has resulted in more than 50 to 100% increases in load recoveries and gas production. Production analysis of horizontal wells drilled and cleaned up with the microemulsion shows a doubling of production over offsets. Pressure analysis of fractured wells shows that the damage factor is reduced by a factor of 2 with the inclusion of ME.
This is a result of a combination of reduced depth of invasion, a higher relative perm in the invaded zone and/or longer effective frac lengths.
Modeling Non-Darcy Flow and Perforation Convergence for Vertically Fractured Wells
Authors: Huang H. , Ayoub J. A. 
Published: December 2007

Abstract
Non-Darcy flow reduces the productivity of fractured and frac and pack wells and causes erroneous results if ignored when analyzing well test data.1 Current practices to quantify the non-Darcy flow effect in a vertically fractured well are mostly based on the work of Guppy et al.,2-6 where simple empirical correlations were developed in the form of apparent dimensionless fracture conductivity as a function of the true dimensionless conductivity and the inertia resistance factor. However, based on the parameter matrices of their numerical analysis, restrictions were also imposed on the variables for the correlations to be valid. In this paper, the same problem of non-Darcy flow in a vertically fractured well is revisited for the cases of rate-controlled drawdown tests. We argue that the relationships between the apparent fracture conductivity and the true conductivity is a function of time and that the restrictions on variables can be relaxed. In addition, the issue of flow convergence near the perforation tunnels is also discussed. A comparative study of the relative effect of flow convergence vs. flow in the perforation tunnels is also presented to allow a quick assessment of the most dominant factor.
In-Situ Erosion of Damaged Formation During Injectivity Decline (PWRI and Seawater Flood)
Authors: Bedrikovetsky P. , Furtado C. A. , de Souza A. L. A. , Siqueira F. D. 
Published: December 2007

Abstract
Injectivity decline with further stabilisation was widely observed and reported in the literature. It can be explained by different physical mechanisms. The correct diagnosis of formation damage mechanism allows choosing the right damage removal technology during seawater injection and Produced Water Re-Injection (PWRI). Reliable prediction of injectivity decline is essential for planning of well stimulation, fracturing, etc.
Usually the stabilisation of well injectivity index after decline is explained by erosion of external filter cake, or by warm holes or even by fracture opening. Nevertheless, the stabilisation is observed in corefloods too, which evidences internal erosion. So, particle deposit erosion must be considered to interpret the injectivity stabilisation.
In the current paper, the particle erosion was described by introduction of a new particle storage capacity function which equals to maximum retained concentration versus dimensionless flow velocity. After the maximum is reached by the retained concentration, particle capture does not happen any more. The particle storage capacity function is a reological characteristic that closes system of governing equations.
The coreflood by suspension with permeability stabilisation was performed with a constant injection rate. The pressure drop on the core and the rate have been measured during the flooding. The analytical model developed allows to perfectly match the experimental impedance curve and calculate from it three injectivity damage parameters – filtration and formation damage coefficients, and also the maximum retention concentration. The obtained values of filtration and formation damage coefficients are in the usual variation range for these coefficients.
Introduction of just one new parameter – maximum retained concentration – into a classical suspension filtration model allows for significant enrichment of the physics schema for suspension transport and retention. An analytical model of suspension coreflood with piecewise constant rate shows that after changing the flow velocity from some value and coming back to the same value, the impedance returns to the initial constant velocity curve. It takes some time after an abrupt flux decrease to stabilise the resistance growth rate, while the resistance growth rate stabilises immediately after abrupt flux increase. If flow regime changes from low velocity to high velocity, there appears a short particle pulse at the outlet; it does not happen when velocity changes from high value to low value.
Applications of Organic Geochemistry in Rayoso Formation Characterization: Chihuido De La Sierra Negra, Lomita Field, Neuquina Basin, Argentina
Authors: Lovrincevich E. , Fasola M. , Labayen I. 
Published: December 2007

Abstract
Organic geochemistry has been widely used in oil exploration industry. However, only in the last decades, innovative applications of its methods have become known in field development activities and reservoir characterization. One powerful application is the lateral and vertical fluids continuity in reservoirs.
This study was made in Chihuido de la Sierra Negra-Lomita field, Neuquina Basin, which produces from three main reservoirs: Low Troncoso Formation, Avilé Formation and Rayoso Formation.
In the mature stage of field development, RepsolYpf developed an analytical technique based in organic geochemistry to discriminate the production from each reservoir in commingle produced oil samples.
The goal of the present paper is the integration of the geochemistry results and the geological model of the Rayoso Formation in order to establish the lateral and vertical continuity of the reservoir fluids, seal rock quality variations and support the field developments activities.
According to the obtained results, the following conclusions were reached: a) Rayoso Formation produces oils with different geochemistry characteristics and b) The geochemical characterizations of the oils produced in Rayoso Formation is going to be used as a powerful supporting technique for field development.
Analysis of Condensate Buildup and Flow Impairment of Retrograde Gases in Fissured Reservoirs
Authors: Ayala H. , Luis F. , Radespiel Eduardo , Turgay Ertekin 
Published: December 2007

Abstract
Reaching dew-point conditions upon depletion in a near-critical gas reservoir results in the precipitation of a liquid hydrocarbon phase or condensate dropout. Condensate dropout is usually immobile and impairs the flow of the other phases, adversely affecting reservoir productivity and ultimate recovery in this type of gas reservoirs. In the case of fissured reservoirs, the high-conductivity channels supplied by the fracture network will be prone to faster depletion upon fluid withdrawal. Condensate dropout would then occur in the fracture network first and then in the external edges of the matrix blocks. Even though condensate dropout in the fracture may have considerable mobility, this is not the case for the liquid formed at the external portions of the matrix. In this scenario, liquid buildup will hinder the flow of hydrocarbons from the inner portions of the matrix blocks and severely obstruct their recovery. This study aims at the numerical tracking of the liquid barrier, which requires a fine discretization of the inner portions of the matrix blocks, and the analysis of the interplay between the condensate barrier and hydrocarbon flow within the surrounding matrix/fracture system. While traditional wisdom dictates that reservoir condensate dropout is undesirable because this valuable condensate may be completely lost to the formation, this study analyzes if the situation is even worse for the case of fissured systems. In addition to low surface condensate recoveries, condensate appearance in fissured systems may also indicate that the inner-block gas stored in the matrices—where the bulk of the reservoir storage resides—might be also unrecoverable. In this study, guidelines for the development of this class of reservoirs are presented by identifying the controlling parameters of system behavior and ultimate recovery and analyzing the depletion characteristics of near critical fluids in fissured systems.
Pressure and PVT Uncertainty in Material Balance Calculations
Authors: Garcia Carlos A. , Villa Jose R. 
Published: December 2007

Abstract
Original Oil In Place (OOIP) calculations based on material balance methods are strongly influenced by data uncertainty. Although some research is available in literature, usually the effects of data uncertainty on material balance calculations are rarely considered and quantified in most studies. This work presents an approach to properly quantify and account for the impact of reservoir pressure and PVT data uncertainty on material balance calculations under different drive mechanisms and using different material balance methods. This study allows reservoir engineers properly select the most suitable material balance method when uncertainty on reservoir pressure and PVT data is significant.
In this work, two different methodologies are proposed. First, a sensitivity analysis was conducted using generated realizations of reservoir pressure and PVT data to evaluate their effect on material balance calculations. Second, a more robust approach was proposed using experimental design and analysis of variance to systematically evaluate the influence of reservoir pressure and PVT data on material balance calculations in an optimal and integrated fashion. In both methodologies, different material balance methods were used and computed OOIP were compared to reference values from a conceptual reservoir model with known PVT data and simulated reservoir pressure. A MATLAB-based program, with graphical user interface, was coded for this purpose1.
Application of the proposed methodologies allowed to determine and quantify the most significant parameters that influence material balance calculations. Interestingly, the most important parameter was the selected material balance method used to compute the OOIP. More accurate results were obtained using the traditional graphical method (F -We vs. Et) for volumetric oil reservoirs with minimal pressure and PVT data uncertainty. In those cases with moderate to significant water influx and gas cap, and some uncertainty on pressure and PVT data, less accurate original oil in place was obtained when graphical methods were used. Reservoir pressure uncertainty was the most significant parameter on the material balance calculations. Gas-oil ratio uncertainty was also significant. Oil and gas gravity, and reservoir temperature were less significant.
Estimation of Permeability from Porosity, Specific Surface Area, and Irreducible Water Saturation Using an Artificial Neural Network
Authors: Basbug B. , Karpyn Z. 
Published: December 2007

Abstract
An Artificial Neural Network (ANN) was designed and tested in the present study to examine the correlation between permeability estimations and porous medium properties, such as porosity, specific surface area, and irreducible water saturation. The network developed in this work is a predictive tool that uses soft computing techniques to estimate absolute permeability of carbonate reservoirs. The Artificial Neural Network toolbox of MATLAB® R2006b and the Feed Forward Error Back Propagation methodology were used in the construction of the network. Carbonate reservoir field data presented in the literature were utilized in the training, testing, and validation of the proposed model. The present study indicates that ANN generated permeability values are consistent with those obtained from core analysis. Results from this study confirm the complex relationship among permeability, porosity, specific surface area and irreducible water saturation of carbonate reservoirs, and suggest that variations in specific surface area affect the magnitude of irreducible water saturations, thus creating an apparent dependence of permeability on irreducible water saturation. Additional observations support a direct relationship between porosity and permeability, and an inverse relationship between specific surface area and permeability.
Using Seismic Attributes in Petrophysical Resevoir Characterization
Authors: Costa Flaviana , Rodriguez Carlos , Sarzenski Darci , Guedes Carlos 
Published: December 2007

Abstract
The use of seismic attributes has increased, especially when extracted from interpreted horizons. The various available attributes are not independent from each other but represent, in fact, different ways of presenting and studying fundamental information from seismic data (time, amplitude, frequency and attenuation). However, statistical analysis using attributes must be based on geological knowledge and not only on mathematical correlation. Petrophysical studies and seismic modeling are sources of understanding. Such knowledge is necessary to improve confidence in observed correlations with reservoir parameters and must be part of all attribute analysis.
However, the use of seismic attributes leads to several questions, for example, what do they all mean? When to use one or another? How to use them on geologic modeling? How reliable those data are? The answers to these questions are not easy, but considering about petrophysical modeling (Porosity, NTG and permeability) what is the best approach: to consider only well data, that are punctual and need to be interpolated, or try to find correlation with physical measurements (seismic data)? Not to consider seismic attributes makes one feel coming back in time, when this important tool was not available.
On a giant oilfield offshore Brazil seismic attributes (‘conventional’, complex trace, polynomial decomposition, geometric and coherence) have been used to create geological models and to reduce uncertainties. The attribute choice must be performed by the geophysicist and the geologist working together, in order to check geological meaning of attribute maps, possible physical meaning of the attribute, etc. Plots of the highest correlation values should be visually inspected in order to choose the attribute with best correlation to the desired parameters.
The results show attributes have been favourable to porosity and NTG prediction, but regular (at maximum) to permeability. For permeability even if the results are not so good, the correlation are improving for the latest models (as long as new wells are used). Polynomial decomposion and complex trace attributes have shown better results.
Identifying Reservoir Potential in Shale-Dominated Thinly Bedded Clastic Reservoirs With a Near-Well-Bore Modeling Approach
Authors: Phillips Peter , Liwanag Janice 
Published: December 2007

Abstract
Declining output from conventional reservoirs has led to an increased interest in unconventional reservoirs, some of which are characterized by low permeability, shale-dominated, thinly bedded clastics. Historically, these reservoirs have not attracted attention as hydrocarbon exploration targets because of their inherent low deliverability and because it has been difficult to recognize net pay with conventional technology.
This paper presents a geological modeling and upscaling method that can help to identify net reservoir below the level of conventional petrophysical log resolution by modeling small-scale sedimentary details that can impact reservoir performance. The approach combines deterministic and stochastic modeling methods to generate 3-D near-well-bore models that capture laminar-scale, bedding-scale, and lithofacies-scale sedimentary structures. Using these geologically realistic models as a basis, we generate petrophysical models that honor input data derived from core plugs, core observations, and well log data. We then apply flow-simulation-based upscaling methods to derive effective properties for input to full-field reservoir simulations. The output includes pseudo-log curves of net-to-gross, porosity, directional permeability (kx, ky, kz), and the ratio of vertical to horizontal permeability (kv/kh) for a modeled well interval.
The modeling and upscaling approach was applied to a thin-bedded reservoir study to produce net-to-gross reservoir curves based on a geologically realistic distribution of sand and shale. The study identified a well interval where model-derived permeabilities were substantially higher than permeability estimates derived with the conventional phi-k transform. These results were consistent with core observations and core plug measurements, and accounted for original discrepancies between the static and dynamic reservoir model. The geomodel-based upscaling method provided more accurate permeability results and, hence, more appropriate cut-offs for estimating net-to-gross sand.
Geometric Models of Porosity Reduction Mechanisms in Tight Gas Sands
Authors: Mousavi Maryam A. , Bryant Steven L. 
Published: December 2007

Abstract
Pore volume reduction of sediments by plastic deformation during compaction and by cementation of grains has been evaluated for different proportions of ductile and hard grains. We attempted to produce the compaction behavior of grains with a purely geometric model, which uses the cooperative rearrangement algorithm to produce dense, random packings. To account for deformation of lithic grains, we used the soft-shell model, in which grains can interpenetrate until their inner rigid cores come into contact. We varied the fraction of grains assumed to be ductile and the radius of the rigid core of the ductile grains. By changing these two variables, we can have very small values of porosity after compaction of our packing, which is the character of tight sands. The predicted relation between the fraction of ductile grains in the sediment and the porosity after compaction agrees well with experimental data from Pittman and Larese (1991)1. The radius of the rigid core of the ductile grains proves to be a good proxy for different kinds of ductile material, ranging from brittle to extremely ductile. We simulated diagenesis in our compacted rock by considering quartz precipitation. The overgrowth or rim cement was modeled by uniformly increasing the radius of all the grains, while holding their centers fixed. These simulations yield detailed descriptions of pore scale geometry resulting from processes common in forming tight gas sandstones. Such models in turn can provide insight into two-phase flow properties of these reservoirs, particularly the sensitivity of gas permeability to water saturation2.