bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Optimization in the Provincia Field, Colombia
Authors: Blann Jack , Jacobson Laurie , Faber Christian 
Published: December 2007

Summary
Designing or redesigning production facilities for optimum operation usually results in the generation of maximum profit from an installation. But in older fields, or fields where a short life is expected, design changes may not be a viable option. In such cases, obtaining maximum production within the limits of existing facilities, thereby minimizing new investments, may be an attractive option.
This paper discusses application of the latter technique in the Provincia field, Colombia, to optimize oil and gas production within constraints imposed by periodic temporary gas-compression-capacity restrictions and by the configuration of existing oil and gas facilities. The multistep optimization program used at Provincia included improvement of individual well performance, optimization of individual well facilities, fieldwide optimization of surface facilities, and optimization of the field production scheme.
Perforating a High-Pressure Gas Well Overbalanced in Mud: Is It Really That Bad?
Authors: Bundy Thomas E. , Elmer Matthew J. 
Published: December 2007

Summary
This paper presents a case study of four high-pressure gas wells that were perforated overbalanced in heavyweight mud and then evaluated with pressure-transient tests. The surprising result of these tests was the minimal amount of completion damage. The average skin damage calculated from the test data was 2.6, which is much lower than the 12.6 predicted from data available in the literature. The information from this case study gives the completion engineer additional data on which to base decisions when designing perforation operations in high-pressure gas wells. This case study also raises the possibility that completion damage from overbalanced perforating practices decreases as reservoir pressure increases.
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

Summary
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

SummaryStep-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

Summary
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

Summary
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

Summary
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

SummaryObtaining 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

Summary
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

SummaryThis 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

Summary
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

SummaryIn 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

Summary
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

Summary
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

Summary
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

Abstract
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

Summary
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

Summary
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

Summary
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.