bluuebunny/crossref_metadata_2025 huggingface dataset:
The Analysis and Prediction of Electric Submersible Pump Failures in the Milne Point Field, Alaska
Authors: Sawaryn S. J. , Grames K. N. , Whelehan O. P.
Published: December 2007

Electric submersible pumps (ESPs) are the predominant lift method used in the Milne Point field, Alaska. Each year, approximately 50 ESP failures occur, adversely affecting lifting costs, rig utility, and production. Statistical methods based on the Weibull distribution and the bathtub reliability model have been used to analyze ESP reliability data collected over a 13-year period. This analysis differs from earlier works by treating a portion of the infant failures (the early part of the bathtub model) as a series of Bernoulli trials. Analysis shows that the three main factors affecting ESP reliability in the Milne Point field are reservoir, sand control, and whether the ESP is the first installed in a well or is a replacement. Further, the ESP failure rate is shown to be dynamic, influenced by the delivery of new wells and the time lag between failure and replacement. The results have been incorporated into a computer-based failure simulator that uses Monte Carlo techniques to simulate the failure rates. Numerical values for the statistical parameters are included with the details of the simulator.

The simulator is currently used within the Milne Point field asset as a planning tool to establish changes in rig utility, production loss, and ESP replacement strategies in a cash-constrained environment. It is also used to assess improvements in ESP performance and to secure commercial terms for ESP lease and purchase options. In the future, it is recommended that the simulator be used, with suitable analog data, to predict the economic impacts of ESP failures on development programs before sanction.
Wax Precipitation in Gas Condensate Mixtures
Authors: Nichita Dan Vladimir , Goual Lamia , Firoozabadi Abbas
Published: December 2007

Wax precipitation for gas condensate fluids was studied in detail with a thermodynamic model. It was found that the precipitated wax phase can exhibit retrograde phenomena similar to that in gas condensates. As a result of pressure decrease (at a constant temperature), the amount of precipitated wax may first increase, then decrease, then increase again.

The effect of pressure on wax precipitation from gas condensates was also studied. Pressure often shows an opposite effect in wax precipitation to that in liquids; however, the pressure effect is not universal.

The model used in this work accounts for both the Poynting correction term and the solid-state phase transitions. Incorporation of these effects reconfirms the suitability of the multisolid phase for wax-precipitation calculations (both the onset and the amount).
Experimental Study of Low-Liquid-Loading Gas-Liquid Flow in Near-Horizontal Pipes
Authors: Meng Weihong , Chen Xuanzheng T. , Kouba Gene E. , Sarica Cem , Brill James P.
Published: December 2007

Low-liquid-loading flow in wet-gas pipelines is a common occurrence in the transport of raw gas. The most important parameters governing the flow behavior are pipe geometry (inclination angle and diameter), operating conditions (flow rate, pressure, and temperature), and physical properties of the gas and liquid (density, viscosity, and surface tension). In this study, extensive experiments were conducted with a test loop made of 50.1 mm diameter acrylic pipe with inclination angles from the horizontal of −2°, −1°, 0°, 1°, and 2°. Gas and liquid superficial velocities ranged from 5 to 25 m/s and from 0.001 to 0.053 m/s, respectively. In-situ liquid loading ranged from 150 to 1800 m3. The flow patterns studied were stratified (smooth and wavy) and annular. Measured parameters included gas and liquid volumetric flow rates, liquid-film flow rate, pressure drop, temperature, liquid holdup, and droplet deposition rate.

The experimental results show that there is a broad gas velocity range for the transition from stratified to intermittent flow at low liquid loading. Entrainment can occur in the gas core at relatively low velocities, and droplet deposition occurs simultaneously with entrainment. An increase in gas velocity did not increase the liquid entrainment fraction over a relatively broad range of velocities. However, an increase in the liquid flow rate did increase the liquid entrainment fraction. In the annular flow region, a new phenomenon was observed at certain superficial gas velocities; an increase in the liquid flow rate decreased the liquid-film flow rate and liquid holdup and increased the entrainment flow rate. This phenomenon may have a significant impact on operations to sweep liquids from wet-gas pipelines. Seven correlations of the liquid entrainment onset point and the entrainment fraction in the gas core are evaluated. The interfacial friction-factor closure relationship should be different for upward flow when compared to horizontal and downward stratified flow, owing to the existence of counter-current flow in upward-inclined pipes.
Improved Production Forecasts and History Matching Using Approximate Fluid-Flow Simulators
Authors: Omre Henning , Lødøen Ole Petter
Published: December 2007

Forecasts of production with associated uncertainties must be based on a stochastic model of the reservoir variables and a fluid-flow simulator. The latter is usually very computationally demanding to activate. Approximate fluid-flow simulators based on upscaling of the reservoir variables are frequently used to assess the forecasts with uncertainties. The upscaling introduces biases and changes the error structures in the production forecasts, however. A production forecast model that accounts for these biases and changed error structures is defined, and estimators for the model parameters are specified. Forecasts both at the appraisal stage and the production stage including history matching are discussed. The so-called "ranking problem" is formalized and solved as a part of the study. The results are demonstrated and verified on a large case study inspired by the Troll field in the North Sea.
Pore Size Distribution of Porous Media and Displacement Experiments with Miscible Liquids
Authors: Klinkenberg L.J.
Published: December 2007

It is pointed out that the current concept of pore size distribution is not unequivocally defined and that different methods aiming at a determination of such a distribution therefore do not lead to the same results.

A pore size distribution should not be based on the idea that a core should, under all circumstances, behave as a bundle of straight non-interconnected capillaries of the same pore size distribution. This is illustrated by calculations and experiments on the displacement of miscible liquids.

Introduction

The introduction of the concept of pore size distribution has been an attempt to characterize the intricate geometry of the flow channels in porous media. As pores in a porous medium are interconnected it is impossible to describe exactly what is meant by a "pore" and, therefore, the term pore size distribution requires further amplification.

In the visual method for the determination of pore size distribution "the pore" is considered to be the hole between the grains as observed on thin sections or on a polished surface of the rock under a microscope.

In all other presently known methods, a displacement process is studied and it is ascertained what assemblage of straight cylindrical capillaries would show the same behavior. The distribution of the capillary diameters of this assemblage is said to represent the size distribution of the pores of the actual porous medium.

From the foregoing it is already apparent that it is useless to try to decide which process or which method of investigation leads to a "correct" pore size distribution. To illustrate this further a displacement process in which a fluid is displaced by another miscible with it will be discussed and the results will be interpreted in terms of a pore size distribution.

Displacement Experiments With Miscible Liquids of Nearly Identical Viscosity and Density

Interpretation in the Form of a Pore Size Distribution

If distilled water is displaced from a homogeneous unconsolidated sand pack by, for instance, a dilute solution of NaCl, the breakthrough recovery i.e., the amount of distilled water produced at the moment the first trace of NaCl can be detected in the effluent water, is between 95 and 100 per cent of the pore volume of the pack.
Fast, Approximate Solutions for 1D Multicomponent Gas-Injection Problems
Authors: Jessen Kristian , Wang Yun , Ermakov Pavel , Zhu Jichun , Orr Franklin M.
Published: December 2007

This paper presents a new approach for constructing approximate analytical solutions for 1D, multicomponent gas displacement problems. The solution to mass conservation equations governing 1D dispersion-free flow in which components partition between two equilibrium phases is controlled by the geometry of key tie lines. It has previously been proven that for systems with an arbitrary number of components, the key tie lines can be approximated quite accurately by a sequence of intersecting tie lines. As a result, analytical solutions can be constructed efficiently for problems with constant initial and injection compositions (Riemann problems). For fully self-sharpening systems, in which all key tie lines are connected by shocks, the analytical solutions obtained are rigorously accurate, while for systems in which some key tie lines are connected by spreading waves, the analytical solutions are approximations, but accurate ones. Detailed comparison between analytical solutions with both coarse- and fine-grid compositional simulations indicates that even for systems with nontie-line rarefactions, approximate analytical solutions predict composition profiles far more accurately than coarse-grid numerical simulations. Because of the generality of the new approach, approximate analytical solutions can be obtained for any system having a phase behavior that can be modeled by an equation of state. The construction of approximate analytical solutions is shown to be orders of magnitude faster than the comparable finite difference compositional simulation. Therefore, the new approach is valuable in situations requiring fast compositional solutions to Riemann problems are required.
Scaling of Cocurrent and Countercurrent Capillary Imbibition for Surfactant and Polymer Injection in Naturally Fractured Reservoirs
Authors: Babadagli T.
Published: December 2007

This study tests the existing capillary imbibition scaling formulations in literature and proposes modifications to them for surfactant- and polymer-injection applications. Laboratory tests were performed using Berea Sandstone cores with different shapes, sizes, and boundary conditions. Kerosene, engine oil, mineral oil, and crude oil were selected as the oleic phase. Brine and two different concentrations of surfactant and polymer solutions were the aqueous phases. The capillary imbibition recovery curves were then used to test the existing scaling formulations.

It was observed that the scaling groups were applicable with certain modifications to the cocurrent flow of surfactant and polymer solution-oil pairs as well as the brine-oil cases. In case of cocurrent flow, the gravity forces dominate recovery for low-interfacial tension (IFT) experiments, and modification to the gravity-scaling group for the boundary conditions is required. For countercurrent flow, however, the scaling groups were observed to be inapplicable even after the modifications.
Support-Operators Method in the Identification of Permeability Tensor Orientation
Authors: Silin Dmitriy B. , Patzek Tad W.
Published: December 2007

The dependence of rock permeability on direction, or permeability anisotropy, is confirmed by numerous field examples. Therefore, the ability to carry out a numerical simulation of an anisotropic reservoir is very important. The support-operators method provides a conservative discretization scheme, allowing one to solve nonisotropic problems on a grid of practically arbitrary structure. Moreover, a discretization designed with the supportoperators method provides a natural and convenient way of deriving and solving the adjoint system for evaluation of the gradient and second-order differential in inverse problems.

After a theoretical introduction into the support-operators method, we consider an illustrative parameter-identification problem. More specifically, we evaluate the orientation angle of a nonisotropic permeability tensor in a horizontal reservoir. We assume that the principal permeabilities near a cored or otherwise logged well are already known. To accomplish this task, we need pressure measurements in monitoring wells. We consider both rectangular and curvilinear grids. In either case, the orientation angle has been recovered with a high accuracy.
Applications of 3D Streamline Simulation To Assist History Matching
Authors: Milliken W. J. , Emanuel A. S. , Chakravarty A.
Published: December 2007

The use of 3D streamline methodologies as an alternative to finite-difference (FD) simulation has become more common in the oil industry during the past few years. When the assumptions for its application are satisfied, results from streamline simulation compare very well with those from FD and typically require less than 10% of the central processing unit (CPU) resources. The speed of 3D streamline simulation (3DSM) lends itself not just to simulation, but also to other components of the reservoir simulation work process. This characteristic is particularly true of history matching.

History matching is frequently the most tedious and time-consuming part of a reservoir simulation study. In this paper, we describe a novel method that uses 3D streamline paths to assist in history matching either 3D streamline or FD models. We designated this technique Assisted History Matching (AHM) to distinguish it from automated history-matching techniques. In this manuscript, we describe this technique and its application to three reservoir simulation studies. The example models range in size from 105 to 106 gridblocks and contain as many as several hundred wells. These applications have led to refinements of the AHM methodology, the incorporation of several new algorithms, and some insights into the processes typically employed in history matching.
Mechanisms of Mudcake Removal During Flowback
Authors: Zain Zulkeffeli M. , Sharma Mukul M
Published: December 2007

External filter cakes are used to minimize fluid loss and solids invasion to a formation from drilling and completion fluids. Subsequently, the cake must be removed to increase the flow area and minimize skins, especially for openhole and gravel-packed completions in horizontal and deviated wells. Experimental data is presented to show that the pressure required to initiate flow into the wellbore after building up a filter cake is affected by rock permeability; mud properties, such as particle size and cake yield strength; flowback velocity; and overbalance pressure.

Mudcake liftoff tests, mud particle size, and rock pore-throat size distribution measurements were performed to understand the factors that contribute to cake removal. The mechanisms that control filter-cake removal are discussed.

In this study, it is clearly shown that the flow-initiation pressure during flowback is controlled by solids and filtrate invasion (i.e., internal formation damage rather than by the external mudcake). Flow-initiation pressures show a minimum with increasing rock permeability caused by two competing effects. Larger pore sizes result in smaller flow-initiation pressures, ΔPfi; however, more solids invasion increases ΔPfi. Higher overbalance pressures also increase the internal formation damage and flow-initiation pressure. A simple model to calculate the flow-initiation pressure during flowback is proposed. The model correctly predicts the experimentally observed trends with rock permeability, mud particle size distribution, extent of solids invasion, and yield strength of the mudcake. The model provides a systematic method for designing fluids with low flow-initiation pressures. It is also shown in this study that low flow-initiation pressures do not imply complete cake removal. Cake removal is primarily controlled by the permeability of the cake and its mechanical properties.
Simplified Graphical Method of Determining Gas Compressibility Factors
Authors: Rice Leon
Published: December 2007

Introduction

The composite gas compressibility graph was constructed by combining the data from the three graphs originally presented by Standing and Katz. In its original form, the following method was used to solve for compressibility factors.Graphically determine the pseudo-critical pressure and temperature for the gas in question.Calculate the pseudo-reduced pressure and temperature.Graphically solve for the compressibility (Z) factor.

By combining this original data, it was possible to construct a single composite graph which eliminates all intermediate calculations when solving for compressibility factors.

Basic Data and Equations

Fig. 1 is a plot of the pseudo-critical temperature vs specific gravity of natural gases, as originally presented by Standing and Katz. For a given specific gravity, the actual temperature in degrees Fahrenheit is related to the reduced temperature as follows.

or

.............................(1)

Fig. 1 also includes a plot of pseudo-critical pressure vs gas gravity. For all practical purposes, this can be considered a straight line defined by

.............................(2)

and the reduced pressure is, by definition,

............................(3)

or

............................(4)

Construction of Composite Compressibility Chart

The basic premise on which the chart was constructed is that, for any given pseudo-reduced pressure and temperature, all gases have the same compressibility (Z) factor regardless of gas gravity. To satisfy this condition, a basic graph was constructed with the left-hand portion being a group of straight-line plots of actual temperature vs pseudo-reduced temperature for various gas gravities ranging from 0.56 to 1.00 in 0.02 increments. The right-hand portion was then constructed as three straight-line plots of actual pressure vs pseudo-reduced pressure for gas gravities of 0.60, 0.70 and 1.00. Using Standing and Katz's "Compressibility of Natural Gases" graph, the basic graph was then completed by plotting and connecting equal values of Z, using a 0.70 gravity as a base.

JPT

P. 1081^
Residual Gas Saturation Revisited
Authors: Kantzas Apostolos , Ding Minghua , Lee Jong
Published: December 2007

The determination of residual gas saturation in gas reservoirs from long spontaneous and forced-imbibition tests is addressed in this paper. It is customarily assumed that when a gas reservoir is overlaying an aquifer, water will imbibe into the gas-saturated zone with the onset of gas production. The process of gas displacement by water will lead to forced imbibition in areas of high drawdown and spontaneous imbibition in areas of low drawdown. It is further assumed that in the bulk of the reservoir, spontaneous imbibition will prevail and the reservoir will be water-wet. A final assumption is that the gas behaves as an incompressible fluid. All these assumptions are challenged in this paper. A series of experiments is presented in which it is demonstrated that the residual gas saturation obtained by a short imbibition test is not necessarily the correct residual gas saturation. Imbibition tests by different methods yield very different results, while saturation history and core cleaning also seem to have a strong effect on the determination of residual gas saturation. It was found, in some cases, that the residual gas by spontaneous imbibition was unreasonably high. This was attributed to weak wetting conditions of the core (no water pull by imbibition). It is expected that this work will shed some new light on an old, but not-so-well-understood, topic.
Well Index in Reservoir Simulation for Slanted and Slightly Curved Wells in 3D Grids
Authors: Aavatsmark I. , Klausen R. A.
Published: December 2007

A new, accurate method for computing the well index (WI) for a well that is oriented in an arbitrary direction in a 3D grid is presented. The method is simple and seminumerical and takes well direction and neighboring gridblocks into account. It is assumed that the medium is homogeneous. The method can be applied for any grid or discretization. However, only Cartesian grids with a seven-point stencil are used here. Properties of the seminumerical WI are investigated for both synthetic and field examples. The investigated properties are convergence rate and dependency on well direction, well location, grid geometry, and anisotropy. The new method shows the importance of taking the neighboring gridblocks into account.
A Coupled Model To Predict Interformation Flow Through an Abandoned Well
Authors: Striz Elise A. , Wiggins Michael L.
Published: December 2007

This paper presents a novel approach for predicting flow between two formations coupled by an abandoned well. A steady-state, abandoned-well model is derived analytically and applied with a "series of steady states" to create the transient flow response. The model is verified by comparison to the results of a transient, analytical, interformation well model for a single injector given by Avci. This model is the first to include true pressure losses in the abandoned wellbore calculated from established equations for turbulent or laminar pipe flow, plugs, and a casing perforation. The model can also predict flow behind pipe through an open or plugged annulus or a fracture in the annular plug. Finally, the model is the first to incorporate the effect of pressure variations on well flow caused by production or injection in the overlying formation.

Application of the model in a single-phase simulation demonstrates the impact of location and condition, rock and fluid properties, initial pressures, and well operations in the coupled formations on the abandoned-well flow. Evolving pressure distributions in the coupled formations may move flow up or down the hole. Pressure losses in the wellbore or behind pipe (through plugs) are shown to preclude flow. The model is also applied to a field case to demonstrate its use as a prediction tool for abandoned-well flow. As opposed to the limited analytical solutions or complex numerical-simulation methods currently available, the new abandoned-well model provides a simple means to determine flow for realistic field conditions.
A New NMR Method of Fluid Characterization in Reservoir Rocks: Experimental Confirmation and Simulation Results
Authors: Freedman R. , Lo S. , Flaum M. , Hirasaki G.J. , Matteson A. , Sezginer A.
Published: December 2007

This paper introduces a new magnetic resonance fluid (MRF) characterization method. The MRF method is based on two key ingredients—a new microscopic constituent viscosity model (CVM) and a new multifluid relaxation model. The CVM provides a link between nuclear magnetic resonance (NMR) relaxation times and molecular diffusion coefficients in hydrocarbon mixtures such as crude oils. The multifluid relaxation model accounts for the T2 decay of spin-echo signals that arises from intrinsic spin-spin interactions, surface relaxation, and attenuation due to molecular diffusion of fluid molecules in a magnetic field gradient. The MRF method exploits the fact that the molecular diffusion coefficients of brine, oil, and gas molecules typically have values that are well separated from one another. Thus, the diffusion attenuation of a suite of measured NMR signals contains sufficient information to allow differentiation of brine, oil, and gas. The method involves the simultaneous inversion of a suite of spin-echo measurements with the new MRF multifluid relaxation model.

The application of the MRF method to magnetic resonance logging data can provide a detailed formation evaluation. The information provided includes total porosity, bulk volume of irreducible water, brine and hydrocarbon saturation, hydrocarbon-corrected permeability, and oil viscosity.

This paper discusses the theory underlying the CVM and validates the model by testing its predictions on hydrocarbon mixtures including live and dead crude oils. The robustness and accuracy of the multifluid inversion is demonstrated by a Monte Carlo simulation of a model carbonate rock that contains brine, oil, gas, and oil-base mud filtrate (OBMF). The MRF method is applied to suites of spin-echo measurements acquired in the laboratory on partially saturated rocks and shown to provide accurate fluid saturation and oil viscosity estimates.

Since the completion of this work, field test results have shown that the MRF method provides a powerful and unique new formation evaluation tool.
Openhole Stability and Sanding Predictions by 3D Extrapolation from Hole-Collapse Tests
Authors: Ewy R. T. , Ray P. , Bovberg C. A. , Norman P. D. , Goodman H. E.
Published: December 2007

Wellbore failure is best simulated in the laboratory by subjecting a model hole to simulated in-situ stresses. A jacketed, thick-walled, hollow cylinder is subjected to increasing pressure on the outer surface until hole collapse occurs. This provides a direct measure of the stress required to cause hole failure in that particular formation interval. To extrapolate to the downhole situation, a 3D analytic model is presented that is applicable to both stability and sanding of open wellbores. This model uses a Modified Lade failure criterion that properly accounts for the effect of the intermediate principal stress on rock failure. The Modified Lade rock-strength parameters are extracted from the measured hole-collapse strength (HCS) and are then combined with the in-situ stresses and formation pore pressure to determine the required mud weight for stability while drilling and the allowable drawdown pressure for prevention of sand production.
Restoration of Uranium In-Situ Leaching Sites
Authors: Hill A. D. , Silberberg I. H. , Walsh M. P. , Breland W. M. , Humenick M. J. , Schechter R. S.
Published: December 2007

In recent years in-situ leach mining has emerged as a new technology for the recovery of uranium from strata that cannot be mined economically by other means. Because the ore bodies lie within groundwater aquifers, a significant determinant in the process' viability is the requirement that such aquifers be protected from contamination. Since ammonia is one of the constituents of the leach solutions now being field tested, one environmental problem to be resolved is the removal of ammonia at the end of mining. A second related question is the fate of the ammonia that is not removed by the restoration procedure.

This paper considers the displacement and migration of ammonium cations in a flowing electrolyte with concomitant ion exchange. The ion exchange is an important feature since, during the solution mining phase, ammonium cations adsorb onto the mineral exchange sites and must be removed from these sites. A mathematical model is used to simulate this process, and the model is tested against the results of laboratory experiments. It is found that the simulations are adequate if an appropriate selection of parameters is made.

The model then is used to simulate restoration procedures and to determine the rate of migration of unrecovered ammonium in the groundwater. It is concluded that ammonium removal can be accomplished best using high concentrations of a cation that is exchanged selectively relative to ammonium cation.
Some Applications of Scanning Electron Microscopy to the Study of Reservoir Rock
Authors: Pittman E.D. , Thomas J.B.
Published: December 2007

The scanning electron microscope (SEM) provides qualitative information about pore geometry through direct observation of a rock or a pore cast of the rock. This aids in understanding reservoir productivity capabilities. The SEM is useful for locating and identifying minerals, particularly clay minerals -an aid when designing drilling and completion programs.

Introduction

This paper discusses some applications of the scanning electron microscope (SEM) to the study of reservoir rocks. The SEM is used extensively to provide qualitative information about the pore geometry of rocks, either directly or indirectly through the examination of pore casts. Many of these studies were concerned with relating pore geometry to various tests or rock properties; specific applications also are discussed.The basic principles of the SEM were known in 1935. Experimental instruments were built in Germany and the U.S. before World War II. After the war, the British started a research program that eventually developed a commercial instrument in the early 1960's. Since then, the SEM has become an indispensible scientific tool in all fields of science and industry. Presently, there are approximately 10 SEM manufacturers, with prices ranging from about $17,000 to well over $ 100,000.The SEM provides several unique advantages for the geologist or engineer when compared with other types of microscopes:magnification range of 15 x to a practical upper limit of about 40,000 x for rocks,great depth of field,ease of sample preparation - samples made conductive by a coating of metal applied under vacuum,nondestructive sample study, andthree-dimensional image analogous to reflected light requiring no special techniques for interpretation.

These features make the SEM ideal for studying irregular rock surfaces.An energy-dispersive X-ray attachment for the SEM provides qualitative information on chemical elements and aids in identifying minerals.

Evaluation and Importance of Microporosity

Micropores occur in sandstone and carbonate reservoirs and affect fluid flow properties. These micropores are seen and evaluated best with an SEM. Microporosity, for convenience, has been defined as pore apertures with a radius of less than 0.5 mum.In sandstone reservoirs, clay with associated micropores may occur as detrital laminae, pellets (grains) of silt-sized or coarser material, or as authigenic (that is, newly formed or regenerated) material (Fig. 1). In a water-wet sandstone, the micropores and high surface area associated with the clay minerals are conducive to holding significant amounts of bound water that can affect log calculations for water saturation. Because of improved log-calculation techniques, which take into consideration cation-exchange capacities of clay minerals, this is less of a problem than in the past.Micropores in carbonate reservoirs occur among calcite or dolomite crystals that typically are less than 4 mu m in diameter.

JPT

P. 1375＾
Packer-to-Tubing Forces for Intermediate Packers
Authors: Hammerlindl D.J.
Published: December 2007

Changes in temperature and pressure during pump-in and production usually result in changes in tubing length or tubing and packer forces, depending on whether the tubing is free to move. Earlier papers presented means for calculating these effects for a completion containing one packer. This paper briefly summarizes those papers and generalize, the calculation to paper briefly summarizes those papers and generalize, the calculation to completions with more than one packer.

Introduction

This paper presents a means of calculating the forces that occur at intermediate packers as a result of changes in temperature and pressure. Intermediate packers are those within the tubing string, such as packers are those within the tubing string, such as dual packers or selective completion packers. The intermediate packer-to-tubing force is needed to design multi- and selective-well completions so that the well can be treated through the completion assembly. Without a proper design, it is possible to shear the release mechanism in the intermediate packer(s), which can result in a costly failure of the packer(s), which can result in a costly failure of the completion assembly.This paper is an extension of papers by Lubinski et al. and Hammerlindl. To eliminate much cross-referencing, the basic equations of Refs. 1 and 2 are presented with a brief review of the theory. presented with a brief review of the theory. This paper also develops the theory required to solve intermediate packer-to-tubing forces, illustrates solutions to typical problems, and develops the initial packer-to-tubing forces that result when the packer-to-tubing forces that result when the intermediate packer is set hydraulically.The calculation procedure requires working the problem from the lowest packer to the surface in problem from the lowest packer to the surface in stages. The first stage is the tubing between the first and second packers; the second stage is the tubing between the second and third packers (or the surface if there is no third packer), etc. The procedures are the standard ones used in Refs. 1 and 2. The only changes are in the procedures used to determine the actual and fictitious forces and the changes in length due to applied forces at the intermediate packers.The text pertains to uniform completions unless otherwise stated. A uniform completion is one with a single-size tubing string containing only one fluid and a constant-ID casing string where the annulus contains only one fluid, which may or may not be the same fluid as contained in the tubing.

Compendium of Movement and Forces Applied Forces With No Fluid

If a tubing string is suspended freely in a cased well containing no fluid and a tensile force is applied to the lower end in the axial direction, the tubing elongates. If a compressive force is applied, the tubing shortens and buckles.The elongation due to a tensile force is determined from Hooke's law. The e nation for Hooke's law in terms of length change is(1)

JPT

P. 515
Factors Affecting Water Blocking and Gas Flow From Hydraulically Fractured Gas Wells
Authors: Holditch Stephen A.
Published: December 2007

This paper demonstrates the combined effects of formation permeability damage and relative permeability damage in the invaded zone of a hydraulically fractured gas well. Study results indicate that the damaged zone permeability must be reduced by several orders of magnitude and the capillary pressure altered before a serious water block to gas flow will occur.

Introduction

To optimize profit from low-permeability gas reservoirs, well stimulation normally is required. In a majority of the cases, a long hydraulic fracture will provide the most efficient and economic means of stimulation. To create long hydraulic fractures, a large volume of fluid, mixed with additives and granular propping agents, must be pumped into the formation. Such treatments can be expensive and require extensive engineering effort.

The fluid injected during the fracturing treatment will leak off into the formation and will reduce the relative permeability to gas in the invaded region. Near the fracture, the permeability to gas will be reduced to zero. After injection has ceased, imbibition will begin to alter the fluid distribution, and when production begins, the fracturing fluid will flow from the formation into the fracture. As the fracturing fluid is produced, the relative permeability to gas in the invaded zone will increase and gas will begin to flow into the fracture. In some cases, the injected fracturing fluid may reduce the formation permeability in the invaded zone. Such damage can be caused by clay swelling, precipitation of solids, or migration of released fines.

In reality, all fracturing fluids, no matter how expensive, do some damage to the reservoir adjacent to the fracture. Using clean fracturing fluids that are compatible with the formation rock and the reservoir fluid helps minimize such damage. However, in some reservoirs, the injected fracturing fluid does not readily clean up and several months of production may be required before the maximum gas flow rate is achieved. In the most extreme cases, a complete water block to gas flow can occur.

To effectively design a fracture treatment for a water-sensitive reservoir, it is essential to understand the basic reservoir mechanisms that govern flow between the fracture and the formation. Gas and water relative permeability, relative permeability hysteresis, capillary pressure, and reservoir damage all tend to complicate the analysis of reservoir flow in fractured formations. By considering the combined effects of the above parameters, it is possible to analyze a given reservoir and determine the cause of slow cleanup and reduced gas productivity.
Tall Oil Pitch in Chemical Recovery
Authors: Ying-Chech Chiu
Published: December 2007

This paper describes a laboratory investigation of tall oil pitch as a potential alternative to petroleum sulfonate as a surfactant for chemical recovery. Tall oil pitch is a bottom product of tall oil fractionation that is based on a major by-product of the paper industry. It is inexpensive, substantially available, and derived from a renewable resource. It is a complex solid consisting of fatty acids, rosin acids, and unsaponifiables. Oil recovery in Berea sandstone cores has shown that final residual oil can be lowered to several percent by injecting properly formulated tall oil pitch solutions in high-salinity field water at 158 and 195°F (70 and 90°C).

Tall oil pitch must be neutralized to achieve interfacial activity. Usual neutralization of tall oil pitch with sufficient alkali to balance the acid equivalence results in surfactant solutions unfavorable for chemical flooding. Alternative neutralization methods are shown to produce solutions that give better oil recovery and no plugging problem in core experiments.

Tall oil pitch has low salinity tolerance, and the additionof NEODOL® 25-3S does not provide satisfactory interfacial activity, salinity tolerance, and temperature stability. Alternative methods of increasing field water compatibility of tall oil pitch slugs have been investigated. Good oil recovery has been obtained with slugs containing as much as 26,280 ppm total dissolved solid.

Five different sources of tall oil pitch were studied. Oil recovery efficiency was shown to be parallel with the fatty-acid dimer content of the sample as determined by gel permeation chromatograph. Heat treatment of the pitch to increase the fatty-acid dimer content improves recovery performance. This finding is important not only in controlling the activity of tall oil pitch but also in providing new leads to what makes certain surfactant materials active.
Henry Darcy - Engineer and Benefactor of Mankind
Authors: Fancher George
Published: December 2007

Introduction

The petroleum industry, and particularly that part of it that is concerned with the production of oil and natural gas, depends upon the ability of these fluids to flow through the porous rocks of the subterranean reservoirs in which they are imprisoned. The ability of fluids to flow through porous rock is expressed in the language of mathematics by Darcy's law, and this mathematical statement is the basis of many petroleum engineering computations. Petroleum engineers have found it the most useful, fruitful, and dependable expression of the pertinent factors which govern the ability of reservoirs to produce oil, gas, and water and of wells to yield these fluids. Consequently, it is not too much to say that Darcy's law is the very basis of the modern petroleum industry.

Darcy's law was stated and published just 100 years ago, when Henri Philibert Gaspard Darcy published his classic paper on the flow of water through sand filter beds. It is fitting that this important anniversary be commemorated by the petroleum industry, although no one would be more surprised than Henry Darcy himself that the work to which he devoted his comparatively brief professional career should provide the basis for a gigantic industry which is the bulwark of modern civilization, an industry which began just three years after the first published statement of Darcy's law. Although petroleum engineers make use of Darcy's law daily in the preparation of professional analyses and reports, and executives of the oil industry, bankers and business men, public officials, politicians, and heads of state arrive at decisions on the basis of these analyses and reports the details of the life and work of this humble Frenchman and public servant, Henry Darcy, are known to few.

Early Life of Darcy

Henri Philibert Gaspard Darcy was born June 10, 1803, in the city of Dijon, chief town in the Department of Cote d'Or and former capital of the old Duchy of Burgundy. Dijon is situated at the confluence of the rivers Ouche and Saone, some 210 miles southeast of Paris by rail (about 160 miles by air line). It is a city of order and discipline, a city of old forts, palaces, bridges, public buildings and worksfactors no doubt of some importance in shaping and molding the lives of its citizens. Deprived at 14 of his father, who was Collector of the Registry and well thought of by his superiors and fellow citizens, Henry Darcy was reared by his mother, a woman of rare merit who, although left a widow at an early age, devoted her energy to the rearing of her two sons and who was responsible for their education.
Rate Effects in Tertiary Micellar Flooding of Bradford Crude Oil
Authors: Sayyouh M. H. M. , Ali S. M. Farouq , Stahl C. D.
Published: December 2007

Micellar flooding of the tight Pennsylvania oil reservoirs invariably is accompanied by low flood advance rates – on the order of a fraction of 1 ft/D. This investigation, therefore, was devoted to the effect of rate on tertiary oil recovery.

The experiments were conducted in 2- and 4-ft-long Berea sandstone cores at rates as low as 0.10 ft/D. All runs were tertiary in nature. The micellar solutions being used in the field tests in Pennsylvania also were used for this research. The majority of the runs were carried out in horizontally positioned cores (although a few runs used vertical cores) to determine if gravity was a factor in the observed effect.

It was found that oil recovery decreased with a decrease in the flood advance rate up to a point. Thereafter, it showed a small increase with further decrease in rate. This effect has not been reported by other investigators.

The rate effect is discussed and analyzed in terms of the system phase behavior, sulfonate adsorption, dispersion, diffusion, and mobility control. The role of the rate effect on the formation of the stabilized bank also was developed for the experimental conditions involved. The implications of very low rates are discussed in the light of field results.
The Reciprocity Principle in Fluid Flow Through Porous Media
Authors: Falade G.K. , Brigham W.E.
Published: December 2007

The mathematical definition of the reciprocity principle is developed using the concept of the instantaneous Green's function. Investigation of the validity of the principle is extended to cases where pressure-sensitive principle is extended to cases where pressure-sensitive parameters of skin and storage are present at the parameters of skin and storage are present at the wellbores of the test wells. Generally, the reciprocity principle is not valid for wells with skin and storage principle is not valid for wells with skin and storage factors. However, for special cases where these pressure-sensitive parameters fulfill certain carefully laid out pressure-sensitive parameters fulfill certain carefully laid out conditions for the well pair of interest, the principle is perfectly valid. perfectly valid.

Introduction

The reciprocal relationship between two wells within a domain in a porous medium probably was reported first by McKinley et al. A similar observation also was reported by Bruggeman for hydrological systems. Also, recently Falade, in his study of pulse testing in slab reservoirs, reported the reciprocity behavior with the pulsing and responding well pair. pulsing and responding well pair. The reciprocity principle as applied to fluid flow through a porous medium can be stated as follows: the pressure change at an Observation Well A, due to a pressure change at an Observation Well A, due to a stimulus of Strength Q imposed on a Source Well B is identically equal to the pressure change at Well B if Well A were subjected to a stimulus of equal Strength Q for an equal length of time. Thus, in effect, the source well and the observation well can be interchanged readily with essentially the same result.Extension and applications of this generalized theory to well testing in a multiwell field and its intrinsic advantages are obvious. Valuable operational costs involved in a complete well-to-well testing of a field can be reduced significantly by applying the reciprocity principle. This paper tries to explore more in-depth principle. This paper tries to explore more in-depth implications of the reciprocity principle as it affects routine oilwell testing.

Theoretical Development

The mathematical proof of the reciprocity principle can be formulated on a general basis using the concept of instantaneous Green's function. Green's function as applied to the solution of a diffusivity equation recently was highlighted by Gringarten et al. and can be extended easily from the single-well case to that of a multiwell field situation.The generalized pressure response at Point R in an infinite porous medium described as a two-well (or two-domain system) is given as

(1)

If the boundary conditions given at the wellbores are the Neuman type as is usually the case (prescribed flow rate), the normal derivatives of the Green's function will vanish at these boundaries:

(2)

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The Reliability of Core Data as Input to Seismic Reservoir Monitoring Studies
Authors: Nes O. -M. , Holt R. M. , Fjær E.
Published: December 2007

There is a potential for improving the reliability of standard core tests for seismic monitoring studies. A primary concern is the ability to quantify and correct for core-damage effects, which significantly enhance the stress dependency of wave velocities. This problem is most relevant for relatively low-strength rocks cored in high-stress environments. We have used synthetic sandstones formed under stress to perform a systematic study of stress-release-induced core-damage effects. The results show that careful laboratory procedures and modeling efforts may reduce core damage effects. However, no simple procedure is currently available to eliminate the problem. The use of simplified laboratory test procedures, particularly the application of an inappropriate effective stress principle, may lead to erroneous interpretations.
The Operator Compact Implicit Method for Reservoir Simulation
Authors: Leventhal Stephen H.
Published: December 2007

This paper describes the application of the fourth-order operator compact implicit (OCI) method to multiphase flow through porous media. A conservative form of the method is developed and used to solve a one-dimensional, two-phase, immiscible waterflood problem.

The results of numerical experiments demonstrate the ability to track sharp fronts with relatively few mesh points. Comparisons with conventional finite-difference methods and variational methods are given.
Field Investigation of the Effects of Stick-Slip, Lateral, and Whirl Vibrations on Roller-Cone Bit Performance
Authors: Chen S. L. , Blackwood K. , Lamine E.
Published: December 2007

The effects of downhole vibrations on the performance of poly-crystalline diamond compact (PDC) bits have been well discussed in recent years. However, most studies on the downhole dynamics of roller-cone bits have focused on axial vibration and its effects. The questions that remain to be answered are what kinds of vibrations a roller-cone bit experiences and what the effects of these vibrations are on roller-cone bit performance.

To investigate these questions, a series of laboratory and field tests was conducted. Downhole vibration data were recorded by an advanced instrumented sub. Soft-to medium-hard formations were drilled with four 8½-in. roller-cone bits (IADC 517). Three kinds of harmful vibrations were observed, and their effects on bit performance in terms of rate of penetration, insert breakage, and bearing/seal life are discussed.