bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Effects of Non-Darcy Flow on the Behavior of Hydraulically Fractured Gas Wells (includes associated paper 6417 )
Authors: Holditch S.A. , Morse R.A. 
Published: December 2007

A reservoir simulator modified to include non-Darcy flow and fractureclosure was used to demonstrate the effects of non-Darcy gas flow in ahydraulic fracture on well performance. Results illustrate the effects onthe gas-well productivity index and on the analysis of pressure builduptests.

Introduction
Laminar flow of fluid through porous media can bedescribed using Darcy's law:(1)
This equation indicates that if the resistance (mu/k)remains constant, the pressure gradient (delta p/delta L) isproportional to the velocity of the fluid (v). However, when thevelocity is increased such that the flow is not laminar, thepressure drop will increase more than the proportional increase in velocity.
Fancher et al. recognized this behavior and publisheda paper in 1933 that gave an analogy between the flow offluids through porous media and the flow of fluidsthrough pipe. Several authors, including Brownell andKatz and Tek, have since published methods forpredicting the laminar and turbulent regions of flow inporous media based on correlations similar to the Reynoldsnumber for flow in pipe.
The generalized equation for flow through porousmedia may be represented by the following equationsuggested by Forchheimer.
(2)
If the constant (a) or velocity (i,) approaches zero. thenthe second term can be ignored and Eq. 2 is equal toDarcy's law (Eq. 1).
Cornell and Katz reformulated Eq. 2 as follows:
(3)
In Eq. 3, the constant (a) was replaced by the product ofthe fluid density (rho) and the beta factor, which is acharacteristic of the porous medium. Several authors havepublished empirical correlations of the beta factor with theporosity and permeability of the porous media.
Geertsma pointed out that the analogy betweenlaminar and turbulent flow of fluids in porous media to theflow of fluids in pipes could be misleading. Geertsmastated that turbulence does not actually occur in the smallpore systems of reservoir rock, and the cause of theincreased pressure gradients at high fluid velocities isinertial resistance. Consequently, Geertsma defined theparameter beta as the coefficient of inertial resistance. Geertsma's paper, therefore, has created a bit ofcontroversy concerning the terminology of the parameter betain the Forchheimer equation.
In reality, the excess pressure gradients at high fluidvelocities can be caused by either turbulence or inertialresistance, or by a combination of the two, depending onthe particular pore configuration of the reservoir rockbeing considered. In this paper, the parameter beta isreferred to as the beta factor. Regardless of its name, the beta factoris a value used to calculate the correct pressure gradientsunder nondarcy flow conditions.
Cooke investigated nondarcy flow in packed, hydraulically induced fractures. He noted that beta factors forfractures packed with multiple layers of sand had notbeen reported in the petroleum literature and suggested the following equation for calculating beta factors:
(4)
JPT
P. 1169^
Gel Systems for Controlling CO2 Mobility in Carbon Dioxide Miscible Flooding
Authors: Raje M. , Asghari K. , Vossoughi S. , Green D. W. , Willhite G. P. 
Published: December 2007

SummaryConformance control for carbon dioxide miscible flooding using gel has not been widely attempted. Laboratory research efforts at the University of Kansas have produced promising in-situ gelation techniques aimed at this application. Three in-situ gel systems were developed and tested in laboratory cores. Two systems are based on a new biopolymer, termed KUSP1, and the third gel system uses the reaction of sulfomethylated resorcinol and formaldehyde to form a gel.KUSP1 gel systems were studied using two different methods of inducing in-situ gelation. In the first method, gelation was accomplished by injecting CO2 at low pressure into the Berea sandstone core saturated by alkaline polymer solution. Permeability reduction to the brine and CO2 in the range of 80% was achieved. Stability of the gel was tested in the presence of supercritical CO2. When supercritical CO2 was used to induce in-situ gelation, the same degree of permeability reduction was achieved. The gel remained stable after the injection of many pore volumes of supercritical CO2. The second method of initiating in-situ gelation involved the use of an ester. Hydrolysis of the ester, monoethylphthalate, in the alkaline polymer solution caused the pH to drop to levels where in-situ gelation occurred. The permeability of the treated core to supercritical carbon dioxide was about 1 md which was equivalent to a permeability reduction of 95%–97% of the initial brine permeability.The third gel system, based on the reaction of sulfomethylated resorcinol and formaldehyde (SMRF), was gelled in situ and contacted with both brine and supercritical CO2. Permeabilities to carbon dioxide on the order of 1 md or less were observed. This permeability is equivalent to a reduction of about 99% in the initial brine permeability. Reduced permeabilities were maintained after injecting many pore volumes of supercritical CO2 and brine.
Applications of a New, Efficient Hydraulic Fracturing Fluid System
Authors: Powell R. J. , McCabe M. A. , Slabaugh B. F. , Terracina J. M. , Yaritz J. G. , Ferrer D. 
Published: December 2007

Summary
This paper discusses low-temperature applications for an optimized low-gel borate fluid system that does not rely on a separate component to maintain system pH. This fluid system's viscosity, fluid loss, static proppant settling, and dynamic proppant transport were tested; experimental procedures and results are described. Case studies from Argentina, Ecuador, the Texas Panhandle, and Permian Basin are also included.
A new, borate-crosslinked hydraulic fracturing fluid system has been developed. This new, optimized fluid system provides higher viscosity with lower gelling-agent concentrations compared to conventional, borate-crosslinked fluids. Application of the optimized low-gel borate (OLGB) fluid system at low temperatures is discussed. Viscosity, proppant transport, and fluid-loss data of the OLGB fluid system are compared to conventional, borate- crosslinked fracturing fluids. Treatment designs are also presented.
Flow Heterogeneity in Reservoir Rocks
Authors: Rosman A. , Simon R. 
Published: December 2007

Introduction
Microscopic flow heterogeneity in reservoir rocks is related to pore size, pore shape, and location of the different pore sizes that determine flow paths of various permeabilities. In this paper, microscopic flow permeabilities. In this paper, microscopic flow heterogeneity is expressed by breakthrough recovery in a nitrogen/helium miscible displacement. Earlier nitrogen breakthrough indicates a higher degree of heterogeneity.
The following sections describe the experimental technique for measuring microscopic flow heterogeneity and give the results of some measurements in sandstones, limestones, and sand packs.

Experimental Technique
The technique involves using nitrogen to displace helium from a core, and measuring nitrogen breakthrough and effluent composition by frontal chromatography methods. These measurements agree well with measurements from liquid, equal-viscosity miscible displacements in the same cores (Table 1).
Nitrogen and helium were chosen because their viscosity ratio approaches unity at room temperature and because they have sufficiently different thermal conductivities for chromatographic detection. The nitrogen/ helium method is simple, rapid, and nondestructive.

Measuring Sequence
The core is mounted vertically (Fig. 1) to avoid gravity segregation effects caused by the density difference between helium and nitrogen. To insure repeatability, the core must be cleaned and dried before beginning the test. A typical run proceeds as follows:The core is saturated with helium.Nitrogen is injected into the bottom of the core. The emerging gas flows through the chromatograph so that nitrogen breakthrough can be detected and timed.Once nitrogen has replaced all helium in the core, the reverse operation can be performed to resaturate with helium injected from the top.

Output
Fig. 2 shows the output of a microscopic flow heterogeneity measurement, with the normal chromatographic output in millivolts and the corresponding percent of nitrogen in the effluent. The zero signal continues as long as only helium flows from the core.
In Fig. 2. nitrogen breakthrough occurs after 12.2 seconds. Increasing nitrogen concentration in the effluent changes the signal.
JPT
P. 1427
Formation-Rate-Analysis Technique: Combined Drawdown and Buildup Analysis for Wireline Formation Test Data
Authors: Kasap Ekrem , Huang Kun , Shwe Than , Georgi Dan 
Published: December 2007

SummaryThe formation-rate-analysis (FRASM) technique is introduced. The technique is based on the calculated formation rate by correcting the piston rate with fluid compressibility. A geometric factor is used to account for irregular flow geometry caused by probe drawdown. The technique focuses on the flow from formation, is applicable to both drawdown and buildup data simultaneously, does not require long buildup periods, and can be implemented with a multilinear regression, from which near-wellbore permeability, p*, and formation fluid compressibility are readily determined. The field data applications indicate that FRA is much less amenable to data quality because it utilizes the entire data set.
Moment-Equation Approach to Single Phase Fluid Flow in Heterogeneous Reservoirs
Authors: Zhang Dongxiao , Winter C. L. 
Published: December 2007

Summary
In this paper, we study single phase, steady-state flow in bounded, heterogeneous reservoirs. We derive general equations governing the statistical moments of flow quantities by perturbation expansions. These moments may be used to construct confidence intervals for the flow quantities. Due to their mathematical complexity, we solve the moment differential equations (MDEs) by the numerical technique of finite differences. The numerical MDE approach renders the flexibility in handling complex flow configurations, different boundary conditions, various covariance functions of the independent variables, and moderately irregular geometry, all of which are important factors to consider for real-world applications. The other method with these flexibilities is Monte Carlo simulation (MCS) which has been widely used in the industry. These two approaches are complementary, and each has its own advantages and disadvantages. The numerical MDE approach is compared with published results of MCS and analytical MDE approaches and is demonstrated with two examples involving injection/production wells.
Neural Network Model for Estimating the PVT Properties of Middle East Crude Oils
Authors: B.C. Gharbi Ridha , Elsharkawy Adel M. 
Published: December 2007

Summary
The importance of pressure/volume/temperature (PVT) properties, such as the bubblepoint pressure, solution gas-oil ratio, and oil formation volume factor, makes their accurate determination necessary for reservoir performance calculations. An enormous amount of PVT data has been collected and correlated over many years for different types of hydrocarbon systems. Almost all of these correlations were developed with linear or nonlinear multiple regression or graphical techniques. Artificial neural networks, once successfully trained, offer an alternative way to obtain reliable results for the determination of crude oil PVT properties.
In this study, we present neural-network-based models for the prediction of PVT properties of crude oils from the Middle East. The data on which the network was trained represent the largest data set ever collected to be used in developing PVT models for Middle East crude oils. The neural-network model is able to predict the bubblepoint pressure and the oil formation volume factor as a function of the solution gas-oil ratio, the gas specific gravity, the oil specific gravity, and the temperature. A detailed comparison between the results predicted by the neural-network models and those predicted by other correlations are presented for these Middle East crude-oil samples.
Comparative Effectiveness of CO2, Produced Gas, and Flue Gas for Enhanced Heavy-Oil Recovery
Authors: Srivastava Raj K. , Huang Sam S. , Dong Mingzhe 
Published: December 2007

Summary
A large number of heavy oil reservoirs in Canada and in other parts of the world are thin and marginal and thus unsuited for thermal recovery methods. Immiscible gas displacement appears to be a very promising enhanced oil recovery technique for these reservoirs. This paper discusses results of a laboratory investigation, including pressure/volume/temperature (PVT) studies and coreflood experiments, for assessing the suitability and effectiveness of three injection gases for heavy-oil recovery. The gases investigated were a flue gas (containing 15 mol % CO2 in N2),a produced gas (containing 15 mol % CO2 in CH4), and pure CO2. The test heavy-oil (14° API gravity) was collected from Senlac reservoir located in the Lloydminster area, Saskatchewan, Canada.
PVT studies indicated that the important mechanism for Senlac oil recovery by gas injection was mainly oil viscosity reduction. Pure CO2 appeared to be the best recovery agent, followed by the produced gas. The coreflood results confirmed these findings. Nevertheless, produced gas and flue gas could be sufficiently effective flooding agents. Comparable oil recoveries in flue gas or produced gas runs were believed to be a combined result of two competing mechanisms—a free-gas mechanism provided by N2 or CH4 and a solubilization mechanism provided by CO2. This latter predominates in CO2 floods.
General Method to Calculate the Permeability Weighting Function for Well Testing in Heterogeneous Media
Authors: Romeu R. K. , Lara A. Q. , Nœtinger Benoît , Renard Gérard 
Published: December 2007

Summary
The perturbation method provides approximate solutions of the well pressure for arbitrarily heterogeneous media. Although theoretically limited to small permeability variations, this approach has proved to be very useful, providing qualitative understanding and valuable quantitative results for many applications. The well pressure solution using this method is expressed by an integral equation where the permeability variations are weighted by a kernel, the permeability weighting function. As discussed in previous papers, deriving such permeability weighting functions appears to be a complicated calculation, available only for special cases. In this article we present simple and general method to calculate the permeability weighting function. In the Laplace domain, the permeability weighting function is easily related to the pressure solution of the background problem. Since Laplace pressure solutions are known for many situations (various boundary conditions, stratified and composite media etc.), the associated permeability weighting function can be derived immediately. Among other examples, we calculate and discuss the well pressure solution for a horizontal well that is producing from a heterogeneous reservoir.
Wellbore-Stability Predictions by Use of a Modified Lade Criterion
Authors: Ewy R. T. 
Published: December 2007

Summary
The two most commonly used rock failure criteria in wellbore stability analyses are the Mohr–Coulomb criterion and the Drucker–Prager criterion. Neither of these is compatible with three-dimensional rock strength measurements that have explored the influence of the intermediate principal stress. This paper presents a modified Lade criterion which has the following desirable qualities: 1. it correctly describes the influence of the intermediate stress on rock strength, and therefore on wellbore stability, 2. it can be rearranged to give a closed-form solution for critical mud weight, for any wellbore orientation, and 3. only two rock strength parameters are required, such as cohesion and friction angle. The modified Lade criterion predicts critical mud weight values that are less conservative than those predicted by the Mohr–Coulomb criterion yet are not as unconservative as those predicted by the Drucker–Prager criterion. It also reveals that the required increase in mud weight when going from low hole angle to high hole angle is not as great as predicted by either the Mohr–Coulomb or Drucker–Prager criteria.
Field-Scale and Wellbore Modeling of Compaction-Induced Casing Failures
Authors: Hilbert L. B. , Gwinn R. L. , Moroney T. A. , Deitrick G. L. 
Published: December 2007

Summary
Presented in this paper are the results and verification of field- and wellbore-scale large deformation, elasto-plastic, geomechanical finite element models of reservoir compaction and associated casing damage. The models were developed as part of a multidisciplinary team project to reduce the number of costly well failures in the diatomite reservoir of the South Belridge Field near Bakers-field, California. Reservoir compaction of high porosity diatomite rock induces localized shearing deformations on horizontal weak-rock layers and geologic unconformities. The localized shearing deformations result in casing damage or failure. Two-dimensional, field-scale finite element models were used to develop relationships between field operations, surface subsidence, and shear-induced casing damage. Pore pressures were computed for eighteen years of simulated production and water injection, using a three-dimensional reservoir simulator. The pore pressures were input to the two-dimensional geomechanical field-scale model. Frictional contact surfaces were used to model localized shear deformations. To capture the complex casing-cement-rock interaction that governs casing damage and failure, three-dimensional models of a wellbore were constructed, including a frictional sliding surface to model localized shear deformation. Calculations were compared to field data for verification of the models.
Pressure-Transient Analysis for Perforated Wells
Authors: Yildiz Turhan , Ozkan Erdal 
Published: December 2007

SummaryThis study presents a three-dimensional analytical model to analyze the transient flow into perforated vertical wells. The model considers arbitrary phasing angle, nonuniform perforation size and length, and formation damage around perforations. The characteristics of transient pressure and derivative responses of perforated wells are investigated. A sensitivity study is carried out to identify the impact of various reservoir and completion parameters on the transient pressure and derivative responses. It is observed that convergent flow into perforations significantly influences the early-time and intermediate-time pressure responses. A pseudoskin expression, which can be used to estimate the inflow performance, is also presented.
A Calculation Method for Carbonated Water Flooding
Authors: De Nevers Noel 
Published: December 2007

Abstract
A calculation method has been developed for carbonated water flooding. This method takes into account the effects of oil viscosity reduction and oil swelling, due to carbon dioxide transferred to the reservoir oil from the carbonated flood water. It shows the effect of changes in carbonation pressure and carbonated water slug size. The method is based on a Buckley-Leverett- type linear flow model. The mathematical approach is similar to that developed by Welge, et al, for enriched gas drives. However, it contains a very important advance over the previous papers in its solution to the problem of injection of a "slug" of carbonated water rather than continuous injection of fluid of constant composition. The method also shows the chromatographic nature of the transport of CO2 in a carbonated water flood. Sample calculations indicate that viscosity reduction is the most important source of incremental oil recovery. Swelling contributes to a lesser extent. Raising the carbonation pressure increases recovery, but this effect diminishes as pressure is increased. Increasing the slug size also increases recovery, but again this effect diminishes as slug size is increased.

Introduction
In recent years there has been considerable interest in carbonated water flooding as a secondary recovery method. Several carbonated waterflood field tests are now in progress. Yet there is no published method for predicting the results of a carbonated water flood. This paper presents a method for predicting the oil recovery for a carbonated water flood.In a carbonated water flood, a carbonated water slug is injected into the reservoir. Then this slug is driven forward by injecting plain water behind it. The field operator must choose the carbonated water slug size and the CO2:water ratio in the slug. The calculation method presented here shows the effects of both slug size and CO2:water ratio on oil recovery.
Calculation of Wellbore Pressures and Rate Distribution in Multilayered Reservoirs
Authors: Prats Michael , Vogiatzis J. P. 
Published: December 2007

Summary
An analytic procedure in Laplace space is developed to calculate the wellbore pressure and rate distribution, and their time rate of change, in anisotropic multilayer formations with axial symmetry and interlayer crossflow, in the presence of skins and wellbore storage, for any number of layers, any number of intervals open to the formation, for wells of nonzero radius, for finite external radii, and for no flow at the outer boundaries. Numerically, the procedure appears to be robust and trouble free. A number of applications to which the procedure can meaningfully be used are identified, and some elements of the procedure are illustrated through two brief examples.
Investigating the Role of Crude-Oil Components on Wettability Alteration Using Atomic Force Microscopy
Authors: Basu Subhayu , M. Sharma Mukul 
Published: December 2007

Summary
The surface forces between a crude-oil and its components (oil, resin, and asphaltenes) and a glass substrate have been measured in brine of different salinity and pH using an atomic force microscope. The force vs. distance curves are used to measure the critical disjoining pressure for wettability alteration, i.e., departure from water-wet conditions. The measured data are compared with the classical DLVO theory to explore the nature of interaction of these components with mineral substrates.
The results indicate that the resins and asphaltenes obey the DLVO theory, i.e., the stability of the brine film decreases with increasing brine salinity and increases with increasing solution pH. The opposite trend is observed with increasing salinity for the nonpolar (pentane soluble) fraction and for the crude oil itself. The deviation from DLVO predictions indicates that for nonpolar oils, hydrophobic interactions may play an important role in the interaction of oils with minerals and, therefore, in wettability reversal.
Flow Simulation of Geologic Models
Authors: King M. J. , Mansfield Mark 
Published: December 2007

SummaryWe report upon our experience in performing flow simulation within detailed three dimensional geologic models. Such models have the potential to significantly improve mechanistic understanding of fluid flow through our reservoirs, especially those influenced by strong contrasts in permeability at multiple scales. We have found that utilizing these static models in a dynamic sense places new requirements upon the models, and forces a reevalua-tion of the theoretical foundations behind our flow simulators. We review a range of physical and numerical concepts, and provide the required conceptual extensions and new derivations.