bluuebunny/crossref_metadata_2025 huggingface dataset:
Non-Darcy Gas Flow Through Propped Fractures: Effects of Partial Saturation, Gel Damage, and Stress
Authors: Maloney Daniel R. , Gall Bonnie L. , Raible Clarence J.
Published: December 2007

The objective of this work was to identify and quantify important parameters affecting gas production through propped fractures under a non-Darcy gas flow regime. The gas flow capacity of a simulated propped fracture was studied systematically to determine the effects of partial saturation, gel damage, and stress conditions.

The flow-capacity response of the 20/40-mesh sand tested throughout this project was affected significantly by variations in the effective gas porosity of the proppant pack. Permeability and non-Darcy flow characteristics were correlated to effective gas porosity. Partial saturation was found to be a key parameter influencing the permeability and non-Darcy gas flow behavior of a proppant pack. Partially saturated fractures may result from incomplete removal of fracturing fluid, mobility of formation waters, or production of condensates. The partial saturation of the proppant pack, in effect, changes the open porosity available for gas flow, which adversely affects gas permeability and non-Darcy flow parameters. The results from this investigation demonstrate that non-Darcy gas flow behavior through propped fractures in which a saturation phase is present cannot be estimated from results using dry-proppant-pack tests.
Abnormally High Fracturing Pressures in Step-Rate Tests
Authors: Palmer Ian D. , Veatch Ralph W.
Published: December 2007

Step-rate tests (SRT's) are commonly used to infer formation parting pressure. The fluid injected is usually an incompressible Newtonian fluid, such as water. A theory was developed to describe the increase in wellbore pressure (i.e., fracturing pressure) once parting pressure is exceeded. The theory is based on a Perkins-Kern geometry (confined-height, elongated fracture) and assumes the limit of large leakoff coefficient and/or time. The theory applies for two different injection profiles. It was compared with measurements of wellbore pressure in eight field SRT's and one constant-rate injection test at the Nevada Test Site. Four tight gas sandstones, three liquid-saturated coals, one liquid-saturated sandstone, and one volcanic tuff are included. In most of the cases studied, the observed net wellbore pressure is two to nine times higher than predicted from conventional fracturing models. In seven cases, fracture geometry appears to be consistent with the Perkins-Kern model, a finding confirmed by modeling with a planar, fully 3D simulator. In the two cases that are inconsistent with the Perkins-Kern geometry, the theoretical prediction is based on fully 3D modeling. The statistical mean of discrepancy between observed and predicted net wellbore pressures is 3.9, with a one-standard-deviation range of 1.7 to 8.9.

The data set is used to discriminate between the hypotheses put forward to explain the discrepancy. Poroelastic effects, tip plugging by fines in sandstone formations, the multistranded nature of fractures, and fracture-surface roughness or waviness are not viable explanations. The explanations most consistent with the bulk of the data are high friction losses in constrictions within a fracture and apparent fracture-toughness effects. Of the two, we favor the first. The results presented here are further independent evidence for abnormally high pressures in induced fractures, such as previously reported in larger fracture stimulations in tight gas sands and in coalbed fracture stimulations.
Poroelasticity in Hydraulic Fracturing Simulators
Authors: Vandamme Luc M. , Roegiers Jean-Claude
Published: December 2007

This paper describes a 2D hydraulic fracturing simulator that relies on Blot's theory of poroelasticity. The simulator is based on a poroelastic extension of the displacement-discontinuity (DD) method: it uses time and space distributions of impulse-point DD's and impulse-point sources. Because both solutions satisfy Blot's equations, the model fully accounts for the coupling between fluid diffusion and rock deformation. Thus, this model yields a rigorous determination of the influences of fluid leakoff on fracture width and of opening distribution on reservoir pore pressures. Some preliminary results relevant to hydraulic fracturing are then presented.

Introduction

Models for predicting fluid leakoff, width, and length of hydraulic fractures can be divided into three classes, depending on the complexity of the interaction between diffusion of reservoir/fracturing fluids and deformation of the rock.

Class 1-Uncoupled Models. In most hydraulic fracturing models, the stress/ displacement analysis of the reservoir rock is based on the assumption that the rock is elastic. The fracture aperture can be computed from the elastic constants of the rock, in-situ stresses, and pressure distribution inside the fracture. Calculation of the fluid loss to the formation is generally based on Carter's ID diffusion solution, which predicts an instantaneous leakage inversely proportional to the square root of the wetting time. There is no direct interaction between the diffusion and deformation processes, except for a leakoff term in the mass-conservation equations of the fluid-flow analysis inside the fracture.

Class 2-Partially Coupled Models. In these models, the stress/displacement analysis is still based on the assumptions of elasticity. The fluid loss is calculated exactly, within the framework of the linear diffusion law, by distributing fluid sources along the fracture. The effect of pore-pressure gradient (caused by leakoff) on rock deformation and therefore on fracture width is accounted for with the concept of back stress.

Class 3-Fully Coupled Models. These models include the full range of coupled diffusion/deformation effects predicted by Biot's theory of poroelasticity: sensitivity of the volumetric response of the rock to the rate of loading, pore-pressure change induced by the variation of mean stress, and back-stress effects already accounted for in the Class 2 models.

This paper presents the first phase of the implementation of an in-plane, 2D, fully coupled, poroelastic model that uses the boundary-element approach. The general problem is reduced to the investigation of a line fracture along which displacements and fluid flows are discontinuous. These discontinuities are modeled with impulse DD's and source discontinuities, respectively. The interest of the frilly coupled approach resides in the inclusion of the effects of the DD's (fracture aperture) on the stresses and fluid flow in the formation and the effect of the source discontinuities (fluid loss) on the fracture pressure and aperture profiles.
Hydraulic Rod-Pumping Units in Offshore Artificial-Lift Applications
Authors: Pickford K. H. , Morris B. J.
Published: December 2007

A declining gas supply and decreasing gas-lift performance necessitated the modification of the primary artificial-lift system on offshore production platforms in California. Although production characteristics of the field favored the use of the common rod-pump system, conventional beam-pumping units were deemed unsuitable for offshore applications. Hydraulic rod-pump units offer solutions to many of these problems. Since 1984, eight of these units have been installed offshore. The substantial benefits offered by hydraulic rod-pumping systems make them a viable alternative lift system in many offshore applications.
Effect of Vibration on Electric-Submersible Pump Failures
Authors: Durham M.O. , Williams J.H. , Goldman D.J.
Published: December 2007

Electric submersible pumps (ESP's) historically have had short run lives. Their failures usually were unexplained and accepted as the norm. Because the equipment has generally been downhole, finding all the influences that shorten equipment life expectancy has been difficult. Horizontal surface installations for water injection have been made where machine operating conditions could be monitored and equipment performance analyzed.

Unbalanced pump vibration has been identified as the cause of many seal problems and ultimately motor and pump failures. In fact, excessive vibration appears to be an inherent mechanical characteristic of ESP's. To illustrate the severity of this problem, this paper presents data gathered from field installations with monitoring equipment, from equipment tear-down analysis, and from statistics on ESP failure modes.

Introduction

ESP's have been used for more than 50 years, typically for moving large volumes of fluid where other means of artificial lift have not been feasible. Recently, the application of these pumps has expanded. It is not uncommon to use these pumps to move 500 bbl [80 m3] of fluid from less than 2,000 ft [600 m]. The industry has made great strides in improving ESP performance. Run times have improved significantly over those existing only 10 years ago. These pumps are now economically competitive with other pumping systems in many environments.

A unique application of ESP technology has been in water-injection systems. Water-injection pumps often must move large volumes at high pressures. Not surprisingly, ESP's fit this criterion. Although ESP's are not a panacea for all pumping applications, these examples demonstrate the applicability of ESP technology to an increasing number of applications.

Nevertheless, the significant problems that still exist with the technology must be addressed before the equipment can achieve adequately long run times for it to be widely applied. Current estimates are that ESP's are used in only about 5% of the lift applications in the petroleum industry. This leaves considerable room for further application.

History and Design

Before the problems with ESP's are addressed, the construction of the pumping system should be analyzed. This analysis will demonstrate the problems to be solved.

The design of today's ESP's remains basically unchanged from the first pumps. The pump assembly is a slender centrifugal pump of up to hundreds of stages. The stages consist of an impeller that "floats" on a shaft. The impeller is mated with a diffuser for directing the flow between stages. The impeller/diffuser assembly is stacked inside a small-diameter tubular.
A Laboratory Investigation of Cementing Horizontal Wells
Authors: Wilson M. A. , Sabins F. L.
Published: December 2007

Obtaining a successful cement job will remain one of the most important factors to the productive life of any well and will be especially critical for horizontal-well completions. Achieving a high mud-displacement efficiency under highly deviated or horizontal-well conditions requires that special attention be given to the many aspects of drilling/completion practices—e.g., drill-fluid systems and properties and casing and hole sizes—to obtain optimum mud displacement and cementing results.

A study of factors affecting mud-displacement efficiency focused on cementing an ultralow-permeability formation that is being evaluated as a subject for horizontal completion. Realistic laboratory testing was conducted on a large-scale test model that has been used for many years to evaluate factors influencing drilling-fluid-displacement efficiency. Factors evaluated for this study included influence of hole and pipe sizes, pipe centralization, displacement rates, and spacer systems. Findings from this study provided specific recommendations for low-permeability reservoirs that also can be applied to horizontally drilled wells. Various techniques for cementing horizontal wells will be discussed and general recommendations will be given.
Analyzing Injectivity off Polymer Solutions With the Hall Plot
Authors: Buell R. S. , Kazeml H. , Poettmann F. H.
Published: December 2007

The Hall plot was originally used to analyze water-injection wells. This paper demonstrates that the Hall plot can also be used to analyze injection of polymer solutions. In particular, it is possible to determine the in-situ and residual resistance factors of a polymer solution from the Hall plot. The analysis methods developed are used to examine two field injection tests and one hypothetical example. The analytical results are verified with a reservoir simulator.
Extension of Stone's Method 1 and Conditions for Real Characteristics in Three-Phase Flow
Authors: Fayers F. J.
Published: December 2007

This paper presents extensions to Stone's Method 1 in the definition of the residual oil saturation (ROS) parameter, Sorm, in which linear, quadratic, and cubic forms are compared with measurements. The methods are also examined in terms of the system providing hyperbolic characteristics, and it is shown that small elliptic regions will usually occur in the saturation space. Some of the factors influencing the elliptic regions are analyzed and their significance is discussed.
Reservoir Performance Prediction Methods Based on Fractal Geostatistics
Authors: Emanuel A. S. , Alameda G. K. , Behrens R. A. , Hewett T. A.
Published: December 2007

This paper describes a method for blending fractal statistics, detailed geologic data, finite-difference simulation, and streamtube models into a systematic approach for prediction of reservoir performance. The objective is to make accurate predictions for large-scale projects by detailed accounting of reservoir heterogeneity with reduced history-matching effort at a low overall cost. The method has been tested for waterflood and miscible gas injection projects with balanced injection/production volumes. Example applications are shown for four field cases.
Interpretation of Wellblock Pressures in Numerical Reservoir Simulations Part 3—Off-Center and Multiple Wells Within a Wellblock
Authors: Peaceman Donald W.
Published: December 2007

In reservoir simulation by finite differences, well models are used to relate the wellblock pressure, the actual wellbore pressure, and the flow rate of the well. These well models are based on an "equivalent wellblock radius, " r0. Two methods for obtaining r0 exist: (1) by numerical experiments, and (2) by an approximate analytical approach that assumes that the pressures of the blocks surrounding the wellblock satisfy the exact radial solution. By definition, the numerical approach gives the correct r0. The more commonly used analytical approach frequently gives a good approximation but, in some cases, it does not. Hence, an analytically derived r0 should always be checked by a numerical calculation. In this paper, two important well geometries are investigated numerically: a single well arbitrarily located within an isolated wellblock and two or more wells within a single wellblock. The numerical r0 for a single well is found to be independent of location, a result that contradicts the prediction of the analytical approach.
Simulation of Gas/Oil Drainage and Water/Oil Imbibition in Naturally Fractured Reservoirs
Authors: Rossen R. H. , Shen E. I. C.
Published: December 2007

Much attention has been given to the simulation of naturally fractured reservoirs in the recent literature. The most prevalent approach is a dual-porosity (or dual-porosity/dual-permeability) formulation with computation blocks that may represent several individual matrix blocks. In models of this type, the processes of gas/oil drainage and water/oil imbibition have caused particular difficulties. Some authors have attempted to represent the correct behavior through a gravity term that assumes a simplified fluid distribution in the matrix. Others have used pseudo-capillary-pressure functions for the matrix, the fracture, or both. These functions also assume a simplified matrix fluid distribution or are obtained by "history matching" with a fine-grid model of a single matrix block. Still others have introduced refinement of the matrix into multiple blocks.

In this paper, the authors examine the mechanisms involved in gas/oil drainage and water/oil imbibition and propose a simple way to represent that behavior in a dual-porosity simulator. Basically, the formulation uses pseudo-capillary-pressure curves for both the matrix and fracture. The fracture curve can be determined directly from rock properties and matrix-block dimensions, while the matrix curve can be obtained from the results of a single simulation of a fine-grid model of a single matrix block. The approach is less costly than matrix subdomain and history-matching alternatives and is often more accurate than solutions that rely on a simplified gravity term.
Performance Predictions for Gas-Condensate Reservoirs
Authors: Vo Dyung T. , Jones Jack R. , Raghavan Rajagopal
Published: December 2007

This paper considers some reservoir engineering aspects of the performance of gas-condensate reservoirs that are important for commercial exploitation: calculation of producible fluids, material-balance computations, well deliverability predictions, estimates of the size of the two-phase zone, and saturation changes during the buildup period. Two production modes (constant pressure and constant rate) are considered. Both transient and boundary-dominated periods are examined. Extrapolation of results derived from data above the dewpoint pressure to conditions below the dewpoint pressure is discussed.
Gasflooding Experiments for the East Side of the Yates Field Unit
Authors: Christlansen Richard L.
Published: December 2007

In a series of immiscible gasflood experiments at current conditions for the east side of the Yates Field Unit (450 psi, 82°F [3.10 MPa, 301 K]), the oil recovery efficiency of CO2 was compared with that of gas-cap gas (GCG). Flooding rates in vertically mounted, preserved-state cores were near the critical velocities for gravity-stable displacement. Oil recoveries with CO2 were 6 to 11 % of original oil in place (OOIP) greater than those of GCG. Flooding results were interpreted with a modified Buckley-Leverett end-effect simulator. With this simulator, the gas/oil saturation profile that results from capillary end effects could be modeled. The modeling study showed that incremental oil recovery with CO2 resulted from oil swelling, oil-viscosity reduction, and gas/oil interfacial-tension (IFT) reduction.
Further Discussion of Application of Oil Muds
Authors: Grace Robert D.
Published: December 2007

I would like to commend J.W. Bloemendal on a very good paper, "Discussion of Application of Oil Muds" (Oct. 1986 SPEDE, Page 395). On the basis of my 22 years' experience in drilling and well control, I would like to offer some of my field experience as related to oil-based muds. First, oil-based muds do have specific applications; however, the recent universal use of oil-based muds is without economic justification. I am familiar with some instances in which freshwater muds were arbitrarily replaced by salt and polymer systems without engineering justification. Because of costs and operational problems, some operators reverted to freshwater muds and realized tremendous savings, while others opted for oil muds to solve operational problems at a significant increase in costs. Some operators elected to use "nontoxic" oil muds at even greater costs. So now we are drilling with "Crisco"!

As an experienced field engineer, I have witnessed the most severe and obvious cases of formation damage from the use of oil muds. These cases occurred in deep, high-pressure, low-permeability productive intervals. It is my opinion that the damage, which may not be reversible, is caused by the presence of the surface-active agents in the oil mud that permit the invert emulsion and the oil wetting of bentonite and barite. This change in surface tension could significantly affect the relative permeabilities and thus cause formation damage.

I have also been involved in well-control operations and training on a worldwide basis for more than 20 years. Well-control problems are complicated in the presence of oil muds and have resulted in disasters and dangers. In one instance, a well took a kick with an oil-based mud in the hole. After the well had been physically brought under control, the oil mud on the rig floor caught fire and burned through the rotary hose. The well blew out through the drillstring and destroyed the rig.
Use of Geochemistry To Improve Identification of Completion Intervals
Authors: Curtis J. B. , McBane R. A.
Published: December 2007

Geochemical analyses of cuttings samples have been performed at the wellsite during the drilling of 15 Devonian shale gas wells. The data were interpreted to provide information on the concentration of free gas and oil, the identification of potential hydrocarbon reservoirs, and the location of relative changes in shale matrix permeability over the entire drilled section.
A New Method for Analyzing Well Tests With Inadequate Early-Time Data
Authors: Harris Dan E. , Lee W. John
Published: December 2007

This paper presents a new technique, the cumulative-curvature method, for analyzing well tests with such limited early-time data that only nonunique type-curve matches are possible. The method is applied to buildup tests and single-rate drawdown tests that are distorted by wellbore storage and are run in infinite-acting reservoirs. The method was successfully applied to 16 of 22 field examples, two of which are presented here.
Application of a Pseudotime Function To Permit Better Decline-Curve Analysis
Authors: Chen H. Y. , Poston S. W.
Published: December 2007

A normalized pseudotime accounting for the effects of system mobility and compressibility is used to linearize the post-transient, semilog rate/time plot for a constant-bottomhole-flowing-pressure (BHFP) case. The improved matching technique permits better characterization of reservoir rock parameters, oil-in-place estimation, and prediction of future performance.
Compositional Multiphase Hydrodynamic Modeling off Gas/Gas-Condensate Dispersed Flow in Gas Pipelines
Authors: Adewuml Michael A. , Mucharam Leksono
Published: December 2007

A nonisothermal 1D steady-state compositional two-phase hydrodynamic model describes the formation and flow dynamics of gas condensate in horizontal natural gas pipelines. The two major constituents of the model, hydrodynamics and phase behavior, are coupled through the phase-generation/disappearance-related terms in the continuity and momentum equations. The model is demonstrably capable of predicting the amount, quantity, and distribution of condensate in the pipeline, in addition to the other commonly sought engineering design variables. Parametric studies show that the model is capable of predicting the phenomena associated with gas condensation in pipelines.
Gas Storage and Transport in Devonian Shales
Authors: Schettler P. D. , Parmely C. R. , Lee W. J.
Published: December 2007

Natural gas storage in Devonian shales occurs in part because of the adsorption of methane onto internal pore surfaces. Methane is released during production and is a significant fraction of the total gas produced. Thus, porosity, as a measure of gas storage capacity, must be supplemented with a term that will account for the condensed-phase methane. There are additional implications for gas transport in shale. These factors must be considered, for example, in the application of numerical simulators to production from shale wells.
Subsea Blowout-Preventer Systems: Reliability and Testing
Authors: Holand Per
Published: December 2007

A comprehensive study of subsea blowout-preventer (BOP) performance in the North Sea during 1978–89 was conducted to identify BOP reliability problems. Evaluations of the BOP as a barrier to blowouts, together with rig downtime caused by BOP failures and malfunctions, showed that BOP reliability has improved significantly during the last few years.
A Proposed Technique for Simulation of Viscous Fingering in One-Dimensional Immiscible Flow
Authors: Odeh Aziz S.
Published: December 2007

One-dimensional (1D) oil/water displacement data for a very wide range of unfavorable mobility ratios obtained on three sandpacks show that for these sandpacks, the macroscopic effect of viscous fingering may be captured when its behavior is modeled with a reservoir simulator and one set of relative permeability values. This set may be calculated directly from the experimental data where viscous fingering occurred, or alternatively, it may be generated from relative permeability values obtained on systems with no frontal instabilities.
Physical Properties of Drilling Fluids at High Temperatures and Pressures
Authors: Fisk J. V. , Jamison D. E.
Published: December 2007

Rheological and dynamic filtration properties are presented for water- and oil-based drilling fluids. The physical properties were obtained by use of the DYNAMIC HPHT® test system at test temperatures to 400°F [478 K], system pressures to 15,000 psi [103 MPa], and differential pressures to 600 psi [4.1 MPa]. The data indicated that the de Guzman-Andrade law can be used to describe the temperature effects on the viscosity of oil muds. We also observed that dynamic filtration rates of drilling fluids are greatly affected by solids plugging the pore space in the formation. Temperature and pressure affect dynamic, filtration by changing the dispersion of the solids in the fluid.
Transient Stresses and Displacement Around a Wellbore Due to Fluid Flow in Transversely Isotropic, Porous Media: II. Finite Reservoirs
Authors: Seth M.S. , Gray K.E.
Published: December 2007

In Part 1 of this work,1 equations of elasticity were formulated for transversely isotropic, axisymmetric, homogeneous, porous media exhibiting pore fluid pressure. Equations of elasticity and the thermal analogy method were used to determine transient horizontal, tangential, and vertical stresses and radial displacement in a semi-infinite cylindrical region when either a constant rate of pressure or a constant rate of flow is maintained at the wellbore.

In this paper, the approach presented earlier is extended to finite reservoirs for the cases ofsteady-state flow,constant pressures at the well bore and outer boundary andconstant pressure at the wellbore and no flow at the outer boundary.

Results of this work show that radial and tangential stress gradients are high near the wellbore but diminish rapidly away from the well; the vertical stress gradient behaves in the same way but is less severe. Radial stresses are compressive or neutral, whereas tangential and vertical stresses may be tensile, neutral or compressive, depending upon the boundary conditions, the physical properties of the system and the radial distance involved (vertical stresses are always compressive in an unbounded system1).

For constant boundary pressures, both radial and tangential stresses increase with time whereas they both decrease for a closed outer boundary and constant pressure at the wellbore. The vertical stress decreases with time for both systems.

For steady-state systems, radial displacement may be positive or negative, depending upon the dimensions of the system, the pressure differential and the porosity. Radial displacement may be positive or negative for a closed outer boundary but is positive for constant pressures at both boundaries.

INTRODUCTION

The importance, utility and complexity of a realistic appraisal of the stress state at and local to a wellbore were indicated in Part 1. In this paper the analytical approach presented earlier is extended to finite, cylindrical reservoir geometry for the cases ofsteady-state flow,constant pressures at wellbore and outer boundary andconstant pressure at the wellbore and no flow at the outer boundary.

Other than the outer boundary of the reservoir being finite, the physical system and assumptions pertinent thereto are the same as before. The reader may wish to review the mathematical development through Eq. 49 of Part 1 before proceeding here.
Use of an Insulating Fluid f or Casing Protection During Steam Injection
Authors: Willhite Paul G. , Wilson J.H. , Martin William L.
Published: December 2007

Laboratory and field experiments are described which define casing temperatures when high-temperature steam or hot water is injected down tubing with a particular well completion fluid in the tubing-casing annulus. Also discussed is the method used to place and contain this completion material. Field results observed following stimulation of a production well with 646F steam verified laboratory data that indicated thermal deterioration of one well completion fluid. Thermal deterioration in the 15-day field test was sufficient to destroy insulating properties of the fluid tested. By using an insulating fluid in the tubing-casing annulus casing damage can be prevented in wells not adequately completed for thermal stimulation treatments.

Introduction

High-pressure steam injection frequently causes casing failure in wells completed with J-55 short-thread casing. Failures generally are identified by joint pullout or fracture occurring as the wellbore cools after steam injection. Tensile failures are the result of casing deformation when temperature- generated compressive forces exceed the yield strength of the casing steel. Preventing casing damage in injection or production wells completed with J-55 ST and C, 8-rd casing requires reducing the casing temperature and/or the thermally induced compressive forces. There are many ways to reduce casing temperature while steam is injected down the tubing. A common method is to set injection tubing on a packer to isolate the casing from the injected fluid. This technique has been used successfully to protect casing when injection temperatures are 500F or less. Few failures have occurred under these conditions because resulting casing temperatures did not exceed the temperature at which casing steel yields when fully constrained. At tubing temperatures above 500F the low-pressure annulus is not positive protection against casing failure. This is shown in Fig. 1, which compares the relative failure risk for J-55 ST and C wells when steam at temperatures of 400 to 650F is injected down tubing set on a packer in 7-in. casing. The risk of failure is high as injection temperatures approach 650F. Several instances of casing failure have been observed under these conditions. The alternatives to a low-pressure annulus can be divided into two categories: mechanical insulation attached to the injection tubing, and an insulating fluid to fill the entire annulus between the tubing and the casing. This article discusses the use of an insulating fluid for casing protection.
Nitrogen Miscible Displacement off Light Crude Oil: A Laboratory Study
Authors: Hudgins David A. , Llave Fellciano M. , Chung Frank T. H.
Published: December 2007

A comprehensive laboratory study of N2 miscible flooding for enhanced recovery of light crude oil was performed. The minimum miscibility pressure (MMP) of N2 is a major constraint to its EOR application, so an empirical correlation for MMP estimation was developed and found to be reliable. Supporting work included many in-house slim-tube displacement determinations of MMP and the compilation and analysis of previously published data. The reservoir fluid composition, especially the amounts of the methane and ethane-through-pentane fractions, was found to be the major determining factor for miscibility. High-pressure core flooding tests with sandstone cores were performed to evaluate the effects of gravity stability and injection mode on the N2 miscible process. N2-gas miscible flooding successfully recovered most of the oil from laboratory cores. Gravity-stable and gravity-unstable displacements gave different oil recoveries, as did secondary and tertiary N2 displacements.
An Evaluation of Field Projects of Steam With Additives
Authors: Castanier L. M. , Brigham W. E.
Published: December 2007

The use of additives to improve both steamdrive and cyclic steam injection in field projects has been tested under a variety of conditions. This technique attempts to reduce gravity override and channeling of the steam by foam generation. Another mechanism appears to be "detergent" cleaning near wellbores by surface-active agents. When successful, this technology seems to be economic even at a low oil price. The results, however, have ranged from excellent to negative. In this paper, we attempt to evaluate the field projects published to date. The results of this study show that the use of additives with steam can provide significant benefits over the use of steam alone. Indeed, addition of surfactant to the steam has proved to be both technically and economically successful when the proper products and procedures were used. Caustics have given mixed results but seem to have been effective in at least one cyclic-steam project.
Evaluation of Jet-Bit Pressure Losses
Authors: Warren Tommy M.
Published: December 2007

An experimental and theoretical study was conducted to resolve discrepancies between observed and calculated pressure losses for fluids flowing through the nozzles of jet bits. The use of a nozzle discharge coefficient of 0.95, which is commonly used for roller-cone bits, results in the calculated pressure drop being up to 30% more than actually occurs, with the average error being 14.7% for 770 data points measured with nine different fluids. A relationship is presented to calculate the discharge coefficient as a function of borehole pressure, nozzle size, and mud density, which reduces the mean absolute error to 3% for these data points. Simply increasing the discharge coefficient to a constant value of 1.02 results in reducing the error to 4.1 % without using the more complicated relationship.
Organic Deposition During CO2 and Rich-Gas Flooding
Authors: Monger T. G. , Trujlllo D. E.
Published: December 2007

This paper provides a 17-stock-tank oil (STO) experimental data base on the effect of oil composition on CO2-induced organic deposition. This paper also compares CO2 to precipitating agents that are paraffinic and presents information on the topography of deposition. The results offer insights on evaluating organic deposition during CO2 and rich-gas flooding.
Depletion Performance of Layered Reservoirs Without Crossflow
Authors: Fetkovlch Michael J. , Bradley Mark D. , Works Adonna M. , Thrasher Thomas S.
Published: December 2007

This paper presents a study of the rate/time and pressure/cumulative-production depletion performance of a two-layered gas reservoir producing without crossflow. The gas reservoir has produced for more than 20 years at an effectively constant wellbore pressure, thus giving continuously declining rate/time and pressure/cumulative-production data for analysis. The field data demonstrate that Arps depletion-decline exponents between 0.5 and 1 can be obtained with a no-crossflow, layered reservoir description. Rate-vs.-time and pressure-vs.-cumulative-production predictions were developed from both 2D numerical and simplified tank models of a two-layered, no-crossflow system. These results demonstrate the effects of changes in reservoir layer volumes, permeability, and skin on the depletion performance.
Measurement and Modeling of Asphaltene Precipitation (includes associated paper 23831 )
Authors: Burke Nancy E. , Hobbs Ronald E. , Kashou Samir F.
Published: December 2007

Experimental asphaltene precipitation data on several live-oil/solvent mixtures at reservoir conditions were measured to study the effects of temperature, pressure, and composition on precipitate formation and the relationships between critical properties, PVT phase behavior, and precipitate formation. Data generated by the model can be used to identify operating conditions conducive to precipitate formation.

Introduction

Asphaltene precipitation in the reservoir has proved to be a difficult problem to define and study. Field conditions conducive to precipitation include normal depletion, acid stimulation, gas-lift operations, and miscible flooding. Asphaltene precipitation is generally believed to be an irreversible process, which is the main reason it can have a profound impact on production operations. Investigations into asphaltene precipitation have been impeded by a shortage of experimental data and information on precipitation mechanisms. Our investigation included performance of experimental tests to induce and measure precipitation, selection of a thermodynamic model to describe and predict precipitate formation, and performance testing of the model with a variety of reservoir fluids. This paper summarizes the experimental testing, the theory behind the model, and applications of the model to field operations. Relationships observed between the reservoir-fluid phase behavior and the performance of the model are also discussed.

Theoretical Basis

Several theories have been proposed to explain why asphaltenes precipitate. For our work, we defined asphaltenes as the portion of the crude oil that is insoluble in heptane yet soluble in benzene or toluene. We selected a model that describes the precipitation mechanism by polymer solution theory. The large asphaltene molecules are similar in structure and behavior to polymer molecules. The remaining components in the rude oil act as a solvent in which the asphaltenes are dissolved or suspended. Hirschberg et al. used this approach in studies conducted by Koninklijke Shell E and P.

The overall model depends on two types of fluid equilibria: a vapor/liquid equilibriim (VLE) of the total reservoir fluid and liquid/liquid equilibrium(LLE) between he liquid oil and pseudoliquid asphaltene phases. The VLE of the reservoir fluid is modeled first to obtain the composition and fluid properties of the liquid phase. In the LLE segment of the model, the oil is considered to consist of two liquid phases-an oil-rich phase that acts as the solvent and an asphaltene-rich phase that behaves as the polymer. The term "asphaltenes" actually defines a solubility class of components within the crude oil. Precipitates from a crude oil are classified by the solvent used to induce precipitate formation. For this work, n-heptane was used as the precipitating solvent for asphaltene measurements performed on stock-tank oils.
Productivity of a Horizontal Well
Authors: Babu D. K. , Odeh Aziz S.
Published: December 2007

An equation for calculating the pseudosteady-state flow—i.e., the productivity—of a horizontal well is presented that is easy to use and identical in form to the well-known productivity equation for a vertical well. The equation was extracted from a very complex general solution. Application of the equation requires the determination of two parameters: (1) a geometric factor that accounts for the effect of permeability anisotropy, well location, and the relative dimensions of the drainage volume and (2) the skin caused by restricted entry, which accounts for the effect of well length. The paper gives simple equations for calculating these two parameters. The equation is used to study the effects on well productivity of well length, location, and degree of penetration; vertical and horizontal permeabilities; and the horizontal dimensions of the drainage volume. It is concluded that, though each of these variables has a significant effect, the well length and degree of penetration have the strongest.
A Parametric Comparison of Horizontal and Vertical Well Performance
Authors: Mukherjee Hemanta , Economides Michael J.
Published: December 2007

This paper presents screening criteria for vertical and horizontal wells with or without induced fractures. The parametric basis of such screening makes the decision on either type of well more objective. A simple procedure to calculate the optimum number of orthogonal transverse fractures in horizontal wells and their sizes is also presented. Two important comparisons have not appeared in the literature: (1) the performance of a fully completed horizontal well with that of a hydraulically fractured well and (2) the performance of a hydraulically fractured horizontal well with that of a hydraulically fractured vertical well. In addition, previous work does not take into account the effect of the plumbing system on well performance. This paper is intended to fill these gaps.
Transient Flow Characteristics of Low Permeability Gas Reservoirs and Improvement of Deliverability by Nuclear Explosion
Authors: Eilerts C. Kenneth , Sumner Eudora F.
Published: December 2007

A program for computing the transient radial flow of natural gas, taking into account significant variable properties of the fluid and of the porous medium was used in an investigation of flow characteristics of formations for which the permeability-thickness product kh is 1 to 100 md-ft. A graphic summary of the results obtained may be used with well flow-test data to estimate kh for the formation in which the well is completed.

Assuming that a nuclear explosion in a gas-containing formation would create a rubble-filled chimney with a diameter of 170 ft and fissures radiating from the chimney wall out to a distance of 255 ft, formation pressure gradients were computed for the recovery of gas with a well drilled into the chimney. These computations for 640-and 160-acre spacing indicate that diminution of the radius segment re - rf over which flow occurs in unaltered formation provides for markedly greater ultimate recovery of gas in place than is possible with conventional well completions. A formation drilled with conventional wells 1.0 mile apart must have a productivity product of kh = 197 md-ft to deliver for 20 years 1.0 MMscf/D of gas into a pipeline operated at 300 psi. Aided by nuclear stimulation, one well can meet the same performance requirements with a kh of only 49 md-ft for the native formation. With a spacing of 160 acres and nuclear stimulation, kh need be only 9 md-ft.

Introduction

Project Gasbuggy of the El Paso Natural Gas Co. and government agencies is concerned with the creation by nuclear explosion of a chimney and radiating fissures in a low-permeability formation containing natural gas. A well is to be drilled and completed in this chimney and tests will be made on this well and other wells in the vicinity to determine the economic feasibility of nuclear stimulation for recovery of the gas. Engineering studies of the Bureau of Mines pertaining to parts of this project have been in progress since 1963. Because of the complexity of the experiment, its cost, and possible economic significance, it is desirable to define the reservoir flow problem, determine by computing the relative importance of the parameters involved, and obtain a measure of the benefits that may be expected. The results should be generalized for application to other projects.

Two parts of this problem have been investigated:

- determination of average properties of the native formation from flow tests of wells, and

- evaluation of the transient flow performance of a low-permeability formation in which a relatively high-permeability area has been created to receive a recovery well.

BASIC EQUATIONS

The partial differential equation for transient radial flow of a gas phase,

(1)

was integrated in the range rd r re. With rd/re = 0.005 and 640-acre spacing rd = 14.9 ft, so that flow over most of the radius is computed by means of Eq. 1. A program previously described by the authors was used for this purpose.
The Skin Effect in Producing Wells
Authors: Hurst William , Clark J. Donald , Brauer E. Bernard
Published: December 2007

In calculating negative skin, treating the skin as a zone of infinitesimal thickness leads to mathematical difficulties. These can be overcome by assuming an enlarged wellbore radius and using the same equations that apply for positive skin.

Introduction

Because of drilling, completion, and workover practices, the permeability around a wellbore generally is different from the permeability of the formation. The zone with the altered permeability is called "skin" and its effect on the pressure or flow behavior of the well is called "skin effect". Hawkins has shown that the radius and the permeability of this zone are related to the skin by:

(1)

If the permeability in the skin zone is less than that of the formation, the skin is positive; if it is more than that of the formation, the skin is negative. If the two permeabilities are equal, s is zero; that is, there is no skin.

Van Everdingen and Hurst, have given mathematical solutions to the case of a zone of reduced permeability around the wellbore. This skin effect is illustrated in Fig. 1. They treat the positive skin as a zone of reduced permeability of infinitesimal thickness around the wellbore. When applied to a well with negative skin, however, their solutions lead to the calculated flowing well pressure, which is smaller than the formation pressure, i.e., an injection situation. This is a physical contradiction. In this paper, it is shown that this mathematical difficulty can be overcome by assuming an effective wellbore radius larger than the actual wellbore. Existing solutions are modified to include the effect of an enlarged wellbore radius, and thus enable the engineer to deal with negative as well as positive skins.

Theoretical Development

Van Everdingen and Hurst, through the use of Laplace transformation, obtained the following expression for transient fluid influx into a wellbore:

(2)

where tD, dimensionless time, is given by:

(3)

By use of the superposition technique, Eq. 2 can be expressed as

(4)

The values for QtD, reported extensively by van Everdingen and Hurst, are obtained from the following integral:(5)

JPT

P. 1483ˆ
Engineering Design of Gas-Condensate Pipelines With a Compositional Hydrodynamic Model
Authors: Vincent Patrick A. , Adewumi Michael A.
Published: December 2007

Gas condensation in pipelines designed to transport natural gas is common. The radical difference in the engineering design required for this system, compared with that required of "dry gas" pipelines, makes the problem of significant interest to the gas industry. Because the point and quantity of condensation is not usually known a priori, any attempt to develop a predictive capability for such a system must have an inherent means of providing this information. This requires a good coupling of the gas-phase behavior model with the appropriate hydrodynamic model. This work attempts to develop such a model. With a two-parameter equation of state (EOS) to describe the phase behavior of the natural-gas system, a multiphase hydrodynamic model developed from fundamental fluid dynamics is used to describe the hydrodynamic behavior of the resulting two phases. The model, which consists of a system of nonlinear algebraic and ordinary differential equations (ODE's), was solved numerically. Output from the model solution includes quantity of condensate at any point in the pipeline, pressure drop, and other hydrodynamic variables. The model can predict the various engineering parameters of interest in the design of such pipelines and could be used for feasibility studies and for optimal location of fluid-handling equipment.
Comparison of Pressure-Transient Response in Intensely and Sparsely Fractured Reservoirs
Authors: Johns R. T. , Jalali Younes
Published: December 2007

A comprehensive analytical model is presented to quantify the pressure-transient behavior of a naturally fractured reservoir with a continuous matrix-block-size distribution and interporosity skin. Geologically realistic probability density functions of matrix block size are used to represent reservoirs of varying fracture intensity and uniformity. Drawdown and interference type curves are developed with rectangular probability density functions.

The results obtained extend previous dual-porosity models by incorporating fracture spacing variability. In the absence of interporosity skin, intensely and sparsely fractured reservoirs show distinctions in the pressure response. Uniformity of a fractured reservoir also significantly affects pressure responses, irrespective of the degree of fracture intensity. The pressure response in a nonuniformly fractured reservoir with large block-size variability, for example, can exhibit a nonfractured (homogeneous) reservoir response. The results may be used to estimate matrix-block-size variability and the degree of fracture intensity from drawdown and interference well tests.