bluuebunny/crossref_metadata_2025_split huggingface dataset:
Cement Spacer Fluid
Authors: Carney Leroy 
Published: December 2007

Introduction
Completion problems during the cementing of casings or liners in wellbores have confronted the oil and gas industry for many years. Generally, after the borehole has been drilled, the drilling mud employed is displaced by the cement used in cementing the casing or liner. Compositions and properties of drilling muds and cement slurries vary widely. Such variation may result in detrimental physical and chemical reactions at the interfacial contact. For physical and chemical reactions at the interfacial contact. For example, when a high-viscosity, high-density drilling fluid is used, the incompatibility may contribute to channeling in the annulus and may prevent a satisfactory cement-to-formation bond. As a result, communication may occur between zones and possibly even to the surface.In view of the persistence of those problems, a serious need was recognized for a single type of spacer fluid that could be employed effectively between the cement slurry and any type of mud.

Criteria for Development
The following criteria were established as goals for research efforts in developing a universal spacer fluid:1. It should be compatible with all oil-base muds, invert-emulsion muds, and water-base muds, including chemical gel muds and polymer muds.2. It should not affect cement slurry viscosity, especially high-weighted cements at elevated temperature.3. It should not appreciably change the pumping time of cement slurries.4. It should allow for being weighted to any density required in the field.5. It should be able to tolerate high solids, as mud cake may be picked up, adding to what often is already a high solids content.6. It should tolerate the addition of wetting agents, dispersants, friction reducers, and retarders when needed.7. It should keep the calcium from cement slurries out of water-base muds and, especially, out of polymer muds.8. It should have low-fluid-loss properties.9. Its flow properties should permit turbulence at low pumping rates for better mud removal.10. It should be usable between various types of incompatible drilling fluids during displacement.11. It should be easy to mix and handle in the field.12. It should allow for the use of a variety of fluids in formulating the liquid phase so that specialty fluids are not necessary. In most cases the fluids are already on location.A field survey was conducted on several wells in South Texas and Mississippi to determine what cementing problems were being encountered with various drilling fluids and cements. The survey indicated that oil-base fluids and invert emulsions cause most of the problems. This is especially true when the oil-base mud contains a high-salinity internal phase composed of saturated sodium chloride or calcium chloride. As compatibility with oil-base muds and invert-emulsion muds as well as compatibility with aqueous slurries is necessary for an ideal spacer fluid, an emulsion was considered for development.
JPT
P. 856
Air and Gas Drilling
Authors: Moore C.L. , Lafave V.A. 
Published: December 2007

Abstract
The San Juan Basin of Northwestern New Mexico gave the impetus to the drilling industry to extend the use of gas drilling. This in turn brought about extended use of compressed air as a drilling medium, especially in wildcatting.
Many new drilling problems have developed with the advent of this type of drilling. Air drilling experiences have reached a point where problems such as water entry, crooked hole conditions, and the shortage of suitable air compressor equipment have at least partially been solved. Air drilling has opened an entirely new field for design and invention.

Introduction and Review of the San Juan Operations
The San Juan Basin of Northwestern New Mexico gave the oil and gas industry its first practical application for air drilling. This might be compared with the start the Rangely field in Colorado gave to the diamond bit.
Since 1951, the El Paso Natural Gas Co. has completed 400 wells in this Basin using gas as a circulating medium. It is estimated that there are between 800 and 1,000 wells that have been gas-completed in this area. These wells were completed principally in the Mesa Verde formation of Cretaceous Age, which consists of 800 ft of interbedded sand, shales, and coal at an average depth of 5,000 ft. This gas formation has a very low porosity, low permeability, and a reservoir pressure of approximately 1,250 psi.
This field would have been impossible to develop without gas drilling. Drilling mud completely blocked the producing formation and the only alternative, prior to gas drilling, had been cable tool operations. It often took five to eight weeks to drill the 800-ft Mesa Verde section.
After shooting this section with as much as 2,300 qt of solidified nitroglycerin, the cleaning out process further increased the hazards of cable tool operations. Cable tool drilling in this formation brought about seemingly endless fishing jobs. It was not uncommon to have as many as three strings of tools in the hole at one time, and in a number of cases from one to two of these were left in the hole. Rarely was a Mesa Verde well completed without at least one fishing job.
High-Accuracy Implicit Finite-Difference Simulations of Homogeneous and Heterogeneous Miscible-Porous-Medium Flows
Authors: Meiburg Eckart , Chen C.-Y. 
Published: December 2007

Summary
A novel computational algorithm for the direct numerical simulation of miscible-porous-media flows is developed and applied that offers multiple benefits. It is based on the streamfunction-vorticity formulation of Darcy's law and resolves all physically relevant length scales including diffusion. By employing an implicit discretization based on compact finite differences, it combines ease of implementation and the ability to handle nontrivial geometries with the superior computational accuracy usually reserved for spectral methods. The formal accuracy is O(Δx4,Δt2), although diffusion terms are discretized with O(Δx6). Test calculations are performed that provide a quantitative comparison with linear stability results for strong mobility contrasts in the practically relevant-quarter five-spot configuration. The excellent agreement, both with regard to the algebraic growth rate as well as the preferred wave number, demonstrates the very low levels of numerical diffusion, thereby eliminating grid orientation effects. The capabilities of the numerical method are furthermore demonstrated by means of representative calculations for both homogeneous and heterogeneous displacements. Among other findings, these simulations exhibit a minimal recovery efficiency for intermediate values of the correlation length of the permeability heterogeneities.
Pore-Level Network Modeling of Three-Phase Capillary Pressure and Relative Permeability Curves
Authors: Mani Vanita , Mohanty K. K. 
Published: December 2007

SummaryA three-dimensional (3D) pore-level network model is developed to calculate three-phase capillary pressure and relative permeability curves. The model combines a description of pore space morphological features and three-phase displacement physics to model capillarity-controlled gas invasion into a water-wet medium containing oil and water. The gas/water capillary pressure curves in three-phase systems depend on the fluid saturations, the spreading coefficient, and the oil/water capillary pressure. Water relative permeability, for the strongly water-wet system modeled, is a function of its saturation alone. Gas and oil relative permeability curves depend on the gas and oil saturation, respectively, the saturation history, and the spreading coefficient. The displacement of oil as a response to changing the capillary pressure in a three-phase system cannot be described by existing models for multiphase flow. A modification of Darcy's law is proposed to describe capillary pressure induced oil transport in three-phase systems.
The Use of Coiled Tubing During Matrix Acidizing of Carbonate Reservoirs Completed in Horizontal, Deviated, and Vertical Wells
Authors: Thomas R. L. , Saxon Alan , Milne A. W. 
Published: December 2007

SummaryA laboratory and field study directed at improved well performance of horizontal wells is discussed. During the study, several wells were matrix acidized by use of bullhead and coiled tubing (CT) placement techniques in carbonate reservoirs. The study indicates that acid placed with CT diverted with foam, or a temporarily crosslinked gelled acid (TCGA) system, provides excellent zone coverage and damage removal. Conventional bullhead techniques do not result in effective damage removal. The study emphasizes the evaluation of the treatment results and the development of improved acidizing techniques.Computer simulations of matrix acidizing indicate that proper placement techniques are essential. This observation is supported by field data in wells completed in carbonate reservoirs. The keys to successful damage removal are the placement of acid through CT and proper diversion. Production-logging and well-performance data support this claim. The proposed treatment is applicable in both horizontal and vertical wells completed in carbonate reservoirs.
Coiled-Tubing Deformation Mechanics: Diametral Growth and Elongation
Authors: Tipton S. M. 
Published: December 2007

SummaryCoiled tubing (CT) endures unique cyclic stress and strain histories. The loading imposed on pressurized CT can trigger deformation mechanisms resulting in incremental plastic diametral growth and elongation. This growth occurs despite the fact that both the hoop stress and net axial stress from tension are well below the material yield stress. The most dominant factors controlling the deformation behavior of CT are the bending/straightening cycles associated with the spool and gooseneck. The interaction of the bending stresses and strains with those from axial loading and pressure result in plastic elongation and diametral growth. Severe cyclic plasticity imposed by these events actually changes the structure of the CT material, causing a corresponding change in mechanical properties. The material properties in a section of CT along a string are thus dependent upon the localized service loading history.The operating parameters that control the loading on a section of CT are discussed in terms of the tubing geometry, the above-surface deployment equipment and the subsurface environment. With the load history characterized in terms of imposed stresses and strains, mechanisms that lead to diametral growth and elongation are demonstrated from the standpoint of simple material plasticity models. Refined models are described, based on more sophisticated plasticity relations, capable of characterizing transient behavior and multiaxial effects. Implications from these results for depth calculation are discussed.
Corrosion Problems in Below-Grade Wellhead Equipment and Surface Casings
Authors: Farooqui M. A. S. Z. , Bitar G. E. 
Published: December 2007

Summary
Inspection of the below-grade wellhead equipment has shown corrosion damage to the buried landing base, casing spools, and surface casing, especially in water injection and supply wells in onshore fields in Saudi Arabia. In this paper, we describe the problem and examine possible reasons for the occurrence of corrosion. Procedures and standards that have been developed to regularly inspect all wells, perform the required repair work, and provide durable protection with field-applied corrosion-resistant coating are also discussed in detail.
Quantifying Acid Placement: The Key to Understanding Damage Removal in Horizontal Wells
Authors: Jones A. T. , Davies D. R. 
Published: December 2007

Summary
The placement of acid over the entire wellbore interval can be the key to successful stimulation treatments in wells with long (often horizontal) completion intervals. In this paper, we discuss computer simulations performed to determine how fluids are distributed in the wellbore during acidizing treatments. One of the novel aspects of these simulations is the inclusion of wellbore effects arising from the transient flow of acid and diverter along the wellbore. The results suggest a possible cause of some of the poor stimulation performances observed in the field when acid was injected without diversion or selective-placement techniques. Such situations can result in the acid contacting only a small fraction of the treatment interval. The simulations also show how making the acid viscous could have improved the stimulation performance.
A Volumetric Analysis of Almond Formation (Cretaceous, Mesaverde Group) Gas Production in the Coal Gulch-Echo Springs Standard Draw Field Complex, Washakie Basin, Southwest Wyoming
Authors: Burch D. N. , Cluff R. M. 
Published: December 2007

Summary
The Coal Gulch-Echo Springs-Standard Draw field complex is one of the largest commercial gas accumulations in the Rocky Mountain region with over 1 Tcf of gas of recoverable reserves. Gas is produced from both the Upper Almond barrier bar and shoreline sandstones at the top of the Mesaverde Group (Upper Cretaceous) and from underlying Main Almond fluvial and marginal marine sandstones.
Some recently published models suggest that although the bulk of the produced gas in the fields is from the Upper Almond bar interval, simple volumetric calculations can only account for about 50% of the estimated ultimate recovery from this reservoir. These models imply that the depleting Upper Almond reservoir might be actively recharged by gas leakage from deeper Main Almond sandstones, with contributions from the deeper reservoirs of up to 10 to 30 Bcf of gas per well. This is in stark contrast to typical Main Almond-only producers outside the field area, which have mean reserves of less than 1 Bcf of gas and rarely produce more than 2 Bcf of gas per well. The implication is that the Upper Almond bar sand acts as a gas flow conduit, and its presence is required for efficient drainage of the Main Almond.
We determined the gas in place (GIP) for all field wells drilled before 1993. The GIP within the Upper Almond reservoir only was determined by detailed openhole log analysis and volumetric mapping to be 1,050 Bcf of gas. Total reserves from all producing intervals (Upper Almond and Main Almond combined) are estimated by decline curve analysis to be 1,003 Bcf of gas. The Main Almond lenticular reservoirs contribution to total production is then assumed to be statistically similar to Main Almond-only producers outside the field area, giving an estimated total contribution from Main Almond completions of 96 Bcf of gas; therefore, the recovery factor from the Upper Almond alone is estimated to be (1003 — 96)/1050 = 86%. We conclude that field volumetrics do not support a disproportionate contribution of Main Almond gas to the total field production, nor does the volumetric analysis support the active reservoir recharge hypothesis.
Applying Technical Limit Methodology for Step Change in Understanding and Performance
Authors: Bond D. F. , Scott P. W. , Page P. E. , Windham T. M. 
Published: December 2007

SummaryThis paper presents an alternative planning approach to the drilling and completion process, technical limit, which has resulted in a step change in Woodside's performance. Three new wells and six subsea completions were finished 20% under budget with this tool and with a simple philosophy characterized by the following questions.What is current performance? What is possible? What is needed to get there?The target was to drill a directional well in 20 days when the previous best time was 42 days. A target of 12 days was set on subsea completions, although a conventional approach had previously been 20+ days.The methodology was to ask what would be possible if everything went perfectly on every operation making up the well time. This is not the usual trouble free time but a well time built up of individual components, with each component representing its theoretical best performance.Details of how the approach was used to plan, and operational data that confirm that the technical limit can be approached are presented. As a result, the well construction performance delivered step change improvement when managed against the technical limit.
A Simple Model for Collapse and Post-Col apse Behavior of Tubulars With Application to Perforated and Slotted Liners
Authors: Abbassian Fereidoun , Parfitt S. H. L. 
Published: December 2007

Summary
This paper describes a simple method of evaluating the collapse strength and post-collapse behavior of oil field tubulars subjected to external pressure. The method is based on elastic ovalization and subsequent plastic collapse by formation of a four-hinge mechanism. The resulting predictions of collapse strength are compared with available collapse test data, and other existing collapse equations. For post-collapse behavior, model predictions are compared with available experimental and numerical data. The main attraction of the approach is its versatility, demonstrated through application to collapse of perforated and slotted liners, prepacked screens, and its extension to collapse under non-uniform loading.
Analytical Calculation of Coarse-Grid Corrections for Use in Pseudofunctions
Authors: Hewett Thomas A. , Suzuki Koichi , Christie Michael A. 
Published: December 2007

Summary
We present a new analytical approach for calculating the corrections to pseudofunctions required to account for discretization on a coarse grid. The approach is based on the method of characteristics and yields an expression for the average saturation in a cell as a function of the outlet face saturation similar to one presented by Welge.1 The method accounts for the appropriate averaging volumes for saturation and total mobility to be consistent with an underlying finite difference scheme that uses upstream mobility weighting for the interblock transport terms. The corrections required to account for coarse-grid effects depend only on the ratio of the distances from the injection boundary to the inlet and outlet faces of a discrete gridblock. A direct consequence of this conclusion is that the modifications of relative permeability for the discrete representation are independent of gridblock size and the total number of gridblocks used in the discretization. For a uniform discretization, they depend only on the number of the gridblock, with the first gridblock being that immediately downstream of the injection boundary. The consistent treatment of the averaging volumes for saturation and total mobility produces the unexpected result that the correct form for the discretized relative permeabilities does not converge to the rock curves, even for very large numbers of gridblocks along the flow path.
The results obtained reproduce exactly analytical solutions for fractional flow and pressure drop. The calculated relative permeabilities are frequently nonmonotonic, and may rise above their end point values. Although the results obtained so far are only one-dimensional (1D), the method offers a way of separating the effects of heterogeneity from coarse-grid effects, which may offer a significant improvement in the ability of current upscaling techniques to account for both heterogeneity and coarse-grid effects.
Injection-Well Testing To Optimize Waterflood Performance
Authors: Robertson D.C. , Kelm C.H. 
Published: December 2007

A method for injection-well testing is presented that is designed to optimize injection-well operating conditions and to maximize oil recovery from a waterflood without causing unnecessary, damage to the reservoir. This is accomplished by instituting a systematic program for data collection and testing on injection wells.

Introduction
During the late 1950's and early 1960's, West Texas waterflood experiences, such as premature water breakthrough and poor sweep efficiency caused by improper injection-well operation, indicated the need for a systematic procedure for optimizing injection-well operation.
Many waterflood projects were initiated with peripheral or other dispersed patterns having a low ratio of injection wells to producing wells. During the 1960's, when allowables in prorated states started increasing, individual per-well injection rates often were increased to keep abreast of increased withdrawals. These increases sometimes resulted in performance problems that indicated the need for a better understanding of the reservoir and the factors that affect it during waterflood operations. Thus, there evolved a need for a systematic procedure for maximizing injection and producing rates, while allowing for adequate surveillance of reservoir and operating conditions to preclude any reservoir damage that might jeopardize waterflood recovery.
This paper presents a philosophy and method for injection-well testing for optimizing injection-well operation, thus maximizing recovery from a given waterflood pattern. Injectivity is optimized by instituting a planned series of step-rate tests, pressure falloff tests, profile surveys, and temperature surveys during an initial start-up period of about I year, and by continuously collecting and analyzing rate and pressure data, pressure transient data, and profile data throughout the remaining life of the injector.
Objectives and Basis for Injection-Well Testing
The first objective of the systematic injection-well testing approach is to allow maximum pressure differential between the injector and the producer within formation fracture pressure restraints. A simple application of Darcy's law to injection wells shows injection rate to be proportional to pressure differential. Consequently, higher injection rates should result in quicker response and higher production rates.
For several reasons it is imperative that this maximum pressure differential be attained below formation fracture pressure. First, the fracture caused by injecting above the formation fracture pressure is not necessarily limited to the oil pay. Fracturing can be to an aquifer or to a nonproductive interval. Thus, injecting above the formation fracture pressure can result in significant ineffective injection that, if carried to extremes, could result in less water effectively sweeping the oil pay. Second, when injecting above the formation fracture pressure, the direction of fracturing is not predictable.
JPT
P. 1337^
Least-Squares Finite-Element Method To Predict Areal Composition Variations in Large Hydrocarbon Reservoirs
Authors: Biswas Deepankar , Carey G. F. 
Published: December 2007

Summary
A method is proposed to calculate the areal compositional variations in large hydrocarbon reservoirs in the presence of thermal gradients. A model is developed from the fundamental equations of change for a multicomponent reservoir fluid mixture in a porous medium. The fluxes are obtained from nonequilibrium thermodynamics, and expressions are derived for mass diffusion coefficients. The thermodynamic properties are calculated by use of the Peng-Robinson equation of state (PR-EOS). Under the condition of stationary state, the governing equations are solved by use of the least-squares finite-element method (LSFEM) subject to specified sampling concentrations as data at several well sampling sites. The results are in good agreement with validation simulations based on a similar finite difference solution.
Inflow Performance and Transient Pressure Behavior of Selectively Completed Vertical Wells
Authors: Yildiz Turhan , Cinar Yildiray 
Published: December 2007

Summary
This paper presents new methods to estimate the inflow performance and transient pressure behavior of selectively completed vertical wells. In the first part, inflow performance of wells perforated at several intervals along the producing formation is investigated. It is observed that formation anisotropy, total perforated length/formation thickness ratio, and mechanical skin distribution caused by formation damage are the parameters controlling the well productivity.
In the second part, transient pressure and pressure-derivative response of selectively perforated wells are modeled and examined. A new interpretation technique, which combines the conventional semilog straightline analysis and type-curve matching method, is presented to determine reservoir parameters.