bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development and Testing of Two-Phase Relative Permeability Predictors Using Artificial Neural Networks
Authors: Silpngarmlers N. , Guler B. , Ertekin T. , Grader A. S. 
Published: December 2007

Summary
In this paper, we report liquid/liquid and liquid/gas two-phase relative permeability predictors that are developed using artificial neural networks (ANNs). In the development stage, some of the relative permeability data from literature are used during the training stage while some other sets are preserved to test the prediction capabilities of the models. Various rock and fluid properties, including endpoint saturations, porosity, permeability, viscosity and interfacial tension, and some functional links (mathematical groups coupling various rock and fluid properties) constitute the input parameters of the models. The models are found to successfully predict the field and experimental relative permeability data.
Characterizing Disproportionate Permeability Reduction Using Synchrotron X-Ray Computed Microtomography
Authors: Seright R.S. , Liang J. , Lindquist W. Brent , Dunsmuir John H. 
Published: December 2007

Summary
X-ray computed microtomography was used to investigate why gels reduce permeability to water more than that to oil in strongly water-wet Berea sandstone and in an oil-wet porous polyethylene core. Although the two porous media had very different porosities (22% vs. 40%), the distributions of pore sizes and aspect ratios were similar. A Cr(III)-acetate-HPAM gel caused comparable oil and water permeability reductions in both porous media. In both cores, the gel reduced permeability to water by a factor 80 to 90 times more than that to oil. However, the distributions of water and oil saturations (vs. pore size) were substantially different before, during, and after gel placement. This paper examines the mechanism for the disproportionate permeability reduction in the two porous media.
Fine-Scale Simulation of Complex Water Encroachment in a Large Carbonate Reservoir in Saudi Arabia
Authors: Pavlas Emmerick Joe 
Published: December 2007

SummaryReservoir simulation has entered a new era with the advent of massively parallel processing (MPP) and its ability to handle millions of cells. In this study, a simulation model was constructed from a geologic model without scaleup, with the resulting model having 1.38 million cells. The majority of the effort in reservoir simulation was spent on reviewing geologic and engineering data. History-match changes were made at the well level and interpolated in kH and kV arrays with a deterministic mapping routine. Despite the complexity, the model size, and 30 years of history, a successful history match was achieved after 40 runs. The model has been used to identify well locations for bypassed oil recovery. To date, these locations have not been drilled.
A Field Comparison of Wet and Dry Combustion
Authors: Joseph C. , Pusch W.H. 
Published: December 2007

The injection of water during an in-situ combustion process has been shown with laboratory studies to be more efficient than dry combustion. This paper substantiates the superiority of wet combustion over dry burning with field data from the Bodcau in-situ combustion project in Bossier Parish, LA.

Introduction
Cities Service Co. operates an in-situ combustion project in the Bellevue field of Bossier Parish, LA (Fig. 1). The field was discovered in 1921 and covers approximately 900 acres (3.64 km2). Production is from the Upper Cretaceous Nacatoch sand occuring between 300 and 400 R (91 and 122 m). Porosity and permeability of the unconsolidated reservoir average 33.9% and 700 md, respectively. The 19 degrees API (931-kg/m3) gravity crude has a viscosity of 676 cp (0.68 Pas) at the reservoir temperature of 75 degrees F (24 degrees C). Due to the low reservoir pressure and high viscosity of the oil at reservoir temperature, typical producing rates are 1 or 2 BOPD (0.16 to 0.32 m3/d) per well. Reservoir properties are summarized in Table 1.Dry forward combustion was tested by Cities Service in a pilot started in 1971. Other production stimulation techniques had been tried in the field, but none were economically successful. Production from the four 2.5-acre (10 117-m2) inverted nine-spot patterns during the 3-year combustion phase was in excess of 167,000 bbl (26 550 m3). The pilot area is still under waterflood, and ultimate recovery will exceed 40% of the original oil in place. Although the pilot test demonstrated that dry combustion could recover the low-gravity crude economically, laboratory studies indicated that wet combustion would be superior to dry combustion in the Bellevue field. To compare the two combustion processes directly, a field test was begun in 1974.Successful results from the field test led to the development of eight additional patterns using wet combustion, including five operating under a contract with the U.S. DOE. The DOE project demonstrates the technical efficiency and economics of a commercial combustion project. Eight more patterns have been drilled and presently are being developed, while additional acreage is being prepared for future fireflooding operations (Fig. 2).

Description of Test Area
Two 2.5-acre (10 117-m2) inverted nine-spot patterns were developed as shown in Fig. 3. Pattern 6 was to be processed by dry combustion, while Pattern 5 would make use of a type of wet combustion specifically designed for this reservoir. To monitor the progress of the combustion and water fronts, 18 temperature observation wells were drilled within two patterns.Producing wells were completed with 7-in. casing cemented to surface. The entire pay interval was perforated at a density of two hots per foot, and the wells were equipped for beam pumping. Injection wells also were completed with 7-in. (18-cm) casing, but only the bottom 15 ft (4.6 m) of pay were perforated for air injection.
JPT
P. 1523^
Advanced Slip-Crushing Considerations for Deepwater Drilling
Authors: Sathuvalli U. B. , Payne M. L. , Suryanarayana P. V. , Shepard J. 
Published: December 2007

Summary
This paper addresses a problem pertinent to the design of landing strings and drillstrings for deepwater operations. These landing strings are designed to run long and heavy casings, tiebacks, or liners (typically deep intermediate and production tubulars), and the total weight may approach or exceed 1,000 kilo lbf (klbf) at the mudline. Adding the weight of the landing string to the rotary results in a serious design problem regarding both the landing string itself and the handling equipment. Slip-based handling systems work well in most instances but lead to biaxial loading from the tensile and radial loads exerted by slip inserts. As a result of biaxial loads, the axial load rating of the landing string is reduced.
The current understanding of slip-crushing phenomena is based on testing and modeling work dating to 1959 by Reinhold and Spiri1 and Vreeland.2 This paper assembles all available data regarding slip crushing and places it in the perspective of current understanding. A secondary aim is to describe the physics of the slip-drillpipe interaction in some detail (i.e., extend the Reinhold-Spiri analysis1 to the next level).
The analysis presented in this paper shows variations between the historical Reinhold-Spiri model and test results, and it indicates an unconservative margin of ~20%. These trends can be accounted for with a more accurate model of slip-crushing mechanics. The improved model supports a nonlinear stress distribution in the pipe, and its prediction of peak stresses is consistent with general test observations. With better quantification of the friction factors between the slip and the bowl, load uniformity, and equipment tolerancing and fits, this new model and its underlying approach provide an appropriate framework for a more accurate tubular rating for slip-crushing performance. Until such time as these refinements are made and available, drilling personnel should consider and implement appropriate safety factors when dealing with marginal designs for slip-crushing scenarios.
Controlling Numerical Dispersion by Variably Timed Flux Updating in One Dimension
Authors: Larson R. G. 
Published: December 2007

Abstract
The one-dimensional (1D) material balance equations for multiphase, multicomponent transport in porous media can be cast into forms, analogous to characteristic equations, that express explicitly the velocities at which fixed values of concentration are propagated. Use of these concentration-velocity equations to control the frequency with which component fluxes from finite-difference gridblocks are updated leads to greatly reduced numerical dispersion, as demonstrated in miscible flooding, waterflooding, surfactant flooding, and other example problems.
Processing and Interpretation of Long-Term Data Acquired From Permanent Pressure Gauges
Authors: Athichanagorn Suwat , Horne Roland N. , Kikani Jitendra 
Published: December 2007

Summary
Long-term data from permanent gauges have the potential to provide more information about a reservoir than data from traditional pressure-transient tests that last for a relatively small duration. Besides reducing ambiguity and uncertainties in the interpretation, long-term data also provide an insight on how reservoir properties may change as the reservoir is produced. This study developed a multistep procedure for the processing and interpretation of long-term pressure data. The procedure was tested with several sets of simulated and actual field data. It was found to be an effective approach for the analysis of long-term pressure data from permanent gauges.
Analysis of Interference Test Data Influenced by Wellbore Storage and Skin at the Flowing Well
Authors: Chu Wei Chun , Garcia-Rivera J. , Rajagopoal Raghavan 
Published: December 2007

This paper presents new solutions for analyzing interference test data affected by wellbore storage and skin effects at the flowing well. Three parameters of interest - wellbore storage phenomenon, skin effects, and distance between two wells - are considered simultaneously. The new type curves should improve significantly the ability to analyze such data.

Introduction
With the advent of sensitive pressure gauges and because of the need to obtain precise information on reservoir heterogeneity for implementation of tertiary recovery programs, interference tests have become popular. It is well-established that the results of a multiwell test are influenced more by reservoir heterogeneity than those of a single-well test. The line source solution presented first by Theis1 serves as a starting point for the analysis of interference test data. This solution assumes that the storage capacity of the flowing well and the skin region around the sand-face have a negligible effect on the observation-well response. This assumption is valid if the distance between the flowing well and the observation well is large. However, if the distance is small, then the effect of storage and skin on the observation-well response can be significant. The pressure response at any point in the reservoir will be damped and delayed as a result of the storage effect at the active well (with or without the skin effect), because the main effect of the storage capacity of the flowing well is to cause a lag in the time required for the surface rate to equal the sand-face rate. For given reservoir properties, the magnitude of the delay depends on the wellbore volume, the nature of the storage phenomenon, and the skin effect.
To our knowledge, the effect of wellbore storage on interference data was examined first in the groundwater hydrology literature.2,3 In petroleum engineering literature, Prats and Scott4 were the first to consider the effect of wellbore storage on the response of a pulse test. They concluded that the porosity-compressibility product, fct, of the formation would be overestimated and the hydraulic diffusivity, k/fctµ, would be underestimated if the wellbore storage effect was significant and not considered in the data analysis. Also, they noted that care should be taken in measuring pressure data if the wellbore storage effect was significant, because the magnitude of the actual pressure response would be lower than expected.
They did not quantify the effect of a skin region around the well but did discuss qualitatively the influence of the skin factor. However, Prats and Scott assumed that the storage effect existed at the observation well and not the flowing well. In a subsequent paper, we show that their results can be used to analyze pulse test data influenced by the storage effect at the active well.
Aconcagua, Camden Hills, and King's Peak Fields, Gulf of Mexico, Employ Intelligent Completion Technology in Unique Field-Development Scenario
Authors: Jackson Nielsen Victoria B. , Piedras Jose , Stimatz Gregory P. , Webb Tamara R. 
Published: December 2007

Summary
The economic success of deepwater and ultradeepwater developments often depends on the use of innovative technologies that can increase production and minimize workover needs to achieve the sought-after field efficiency during the productive life of the field. Intelligent completion technology, a new concept for the oil field, is one of the technologies that can support these needs. This well-completion concept allows the operator to obtain real-time or near-real-time reservoir data, then reconfig. the wellbore production/ injection architecture to adapt to the information obtained.
Along with pipeline, platform, and subsea system synergies, three fields in the Gulf of Mexico—Aconcagua, Camden Hills, and King's Peak—use intelligent completion technology to optimize a marginal reserve base. Located in Mississippi Canyon Blocks 173, 217, 305, and 348 and Desoto Canyon Blocks 133 and 177 in 6,200 to 7,200 ft of water, the three fields’ production will be tied to the Canyon Station host platform, 55 miles from the most distant well location.
Producing Viscous Fluids
Authors: Lebourgeois Guy 
Published: December 2007

Abstract
The discovery in March, 1946, of the Boscan low gravity-high viscosity crude oil accumulation presented the Richmond Exploration Co. with a multitude of problems almost unique in the industry.
Solution of these problems through experience and cut-and-try methods has resulted in the successful development of a large source of rod-building materials.

Introduction
Among the oil companies operating in Venezuela, to which heavy crude means some 14° to 15° API gravity oil, the name Boscan has practically become a synonym of "viscous fluid." Indeed, Boscan crude has an average 10° API gravity fluctuating from 9° to 12° and an average viscosity of 26,000 SSU at 122°F fluctuating from 17,000 to 50,000 SSU. This asphalt-looking oil has to be pumped out of the ground, shipped 25 miles away and loaded on tankers.
When the Boscan field was discovered, the technical obstacles brought up by the physical characteristics of its crude made questionable the commercial exploitation of a petroleum so difficult to produce. However, three years later, Richmond was shipping 14,000 B/D of Boscan crude. Even if the figure does not seem impressive, it means the practical answers to a large sequence of major production problems which had to be solved within the rates of the available equipment through constantly improving methods and designs. The drilling of a Boscan well is not a difficult task; it is when the rig is removed that obstacles start arising.

Geology
The Boscan field is located 26 miles southwest of Maracaibo in the State of Zulia in the western part of the Maracaibo basin.
The stratigraphic sequence encountered in and above the production section in the Boscan area includes Eocene, Oligocene, Miocene and Pliocene sediments. The Upper Eocene consists of the Las Flores formation with interbedded sands and dark gray carbonaceous shales. In the upper part, two zones of beach and bar sands (designated as Upper Boscan and Lower Boscan) produce heavy oil.
The Lower Oligocene overlies the Eocene and contains poor to well developed beach sands interbedded with light gray sandy claystone. Effectively permeable sands in this formation (designated Basal Icotea) locally are oil productive. The middle of Oligocene, principally claystone, contains thin sands which are oil productive in the eastern part of the field. This is Middle Icotea.
Reservoir Oil Resaturation with Gas During Pressure Build-up
Authors: Cheney M.G. 
Published: December 2007

Abstract
A sand-packed cell was used to determine the pressure-volume relationship of confined oil and gas by applying both increasing and decreasing pressures. Then the same hydrocarbon fluid was given a routine PV analysis over the same pressure and temperature ranges. The relationship between pressure and hydrocarbon volumes proved to be practically the same for all runs. Equilibrium conditions between phases were very rapidly established within the sand-packed cell.
A small, closed reservoir was produced until free gas developed in the oil leg; then the reservoir was gas-injected to restore a third of the pressure decline. By volumetric balance considerations it was indicated that as the pressure was raised the oil dissolved gas; and within experimental error, the gas maintained the oil saturated.
It was concluded that for both the laboratory and reservoir tests, the dispersed gas in the oil maintained the oil saturated during pressure increase.

Introduction
In Eastern Venezuela, the question of resaturation of reservoir oil in the oil leg through pressure build-up has often arisen. Should oil leg resaturation take place, increased effective permeability will develop with increasing pressure. Decreased viscosity and increased oil formation volume factor from increased solution of gas in oil, would lead to reduced residual oil. These benefits would be reflected in increased ultimate recovery and improved well productivity. However, they could be limited, e.g., active water or solution gas drives. In the case of water drive, loss by backflow of oil into the water leg might result from pressure build-up. With an active solution gas drive that has led to a relatively high free gas saturation, to attain equal reservoir volumes of residual oil through gas injection, higher abandonment gas:oil ratios are necessary at higher pressures. The cost of handling greater volumes of gas could outweigh the advantages of an increased formation volume factor associated with a higher pressure. There are a number of conflicting articles (pro and con) in the literature concerning resaturation.
Streamline-Based Production Data Integration With Gravity and Changing Field Conditions
Authors: He Zhong , Yoon Seongsik , Datta-Gupta Akhil 
Published: December 2007

SummaryRecently, streamline-based flow simulation models have offered significant potential in integrating dynamic data into high-resolution reservoir models. A unique feature of the streamline-based production data integration has been the concept of a travel-time match that is analogous to seismic tomography, allowing the use of efficient and proven techniques from geophysics. In this paper, we propose a generalized travel-time inversion method for production data integration that is particularly well-suited for large-scale field applications with gravity and changing conditions. Instead of matching the production data directly, we minimize a travel-time shift derived by maximizing a cross-correlation between the observed and computed production response at each well. There are several advantages of our proposed method. First, it is general and extremely computationally efficient. The travel-time sensitivities can be computed analytically with a single forward streamline simulation that can be much faster than a conventional reservoir simulator. Second, it is robust and the minimization is relatively insensitive to the choice of the initial model. Finally, it is field-proven because we utilize established techniques from geophysical inverse theory.We demonstrate the power and utility of our proposed method using synthetic and field examples. The synthetic examples include a large-scale 3D example with a quarter-million grid cells involving infill drilling and pattern conversions. The field example is from the Goldsmith San Andres Unit (GSAU) in West Texas and includes multiple patterns with 11 injectors and 31 producers. Starting with a reservoir model based on well-log and seismic data, we integrate water-cut history for 20 years in less than 2 hours on a PC.
Application of Statistics to the Analysis of Production Decline Data
Authors: Chatas A.T. , Yankie W.W. 
Published: December 2007

Introduction
The appraisal of an oil lease may often be made through production decline analysis, which requires description of the functional relationship between the oil production rate and either cumulative production or time. Heretofore, attempts to define the function appropriate to a given set of production data have depended to some extent on subjective procedures. The purpose here is to introduce an objective solution, obtained by combining the principle of least squares with the theory of equations.
Cupiagua: Modeling of a Complex Fractured Reservoir Using Compositional Upscaling
Authors: Ballin P. R. , Clifford P. J. , Christie M. A. 
Published: December 2007

SummaryThe first application of compositional upscaling to the routine modeling of a major reservoir is described. The reservoir— Cupiagua, in Colombia—is a rich gas condensate field. Given that Cupiagua falls rapidly below dewpoint and produced gas is recycled, the main recovery process is the vaporization of liquid components into the gas phase, in which they are transported to producers. Therefore, the process is compositional, but flow is dominantly in one phase.Cupiagua is a heterogeneous reservoir dominated by natural fracture corridors that provide more than 80% of the permeability in some areas. It is not possible to represent these features explicitly within the full-field model (FFM), nor do they fit a conventional dual-porosity representation. Therefore, an upscaling process is required.The process described is the use of alpha-factor compositional upscaling functions, which modify the velocities of individual pseudocomponents. We show how fine-grid cross-section modeling, with a range of sensitivities, may be used to generate an appropriate set of alpha-factor functions, which are validated against detailed sector models and may then be used as the principal history-match parameter in the FFM.