bluuebunny/crossref_metadata_2025_split huggingface dataset:
Improved Material-Balance Regression Analysis for Waterdrive Oil and Gas Reservoirs
Authors: Sills S. R. 
Published: December 2007

Summary
An improved material-balance formulation is presented for determining original hydrocarbons-in-place (OHIP) in waterdrive oil and gas reservoirs. The improved formulation reduces the number of unknowns in the regression analysis through the definition of a combined aquifer/reservoir expansion term (CARET). Field examples analyzed with the CARET formulation are presented illustrating the nonunique nature of waterdrive material-balance solutions for OHIP. A method is presented for reality checking the best-fit aquifer parameters obtained from the regression analysis. The CARET material-balance formulation is shown to provide several advantages over existing regression analysis techniques.
Operational Limits of Synthetic Drilling Fluids
Authors: Growcock F. B. , Frederick T. P. 
Published: December 2007

Summary
In environmentally sensitive areas like the North Sea, synthetic-based drilling fluids are becoming increasingly popular as substitutes for conventional oil-based muds. In many cases, they appear to perform every bit as well as oil-based muds. As currently formulated, some synthetic-based muds are limited to lower temperatures and mud densities and higher oil/water (O/W) ratios than oil-based muds. Limits of these properties can be extended by using high concentrations of surfactants and low-shear rheology modifiers.
A Generalized Well-Management Scheme for Reservoir Simulation
Authors: Fang W. Y. , Lo K. K. 
Published: December 2007

SummaryA new generalized well-management scheme has been formulated to maximize oil production under multiple facility constraints. The scheme integrates reservoir performance, wellbore hydraulics, surface facility constraints, and lift-gas allocation to maximize oil production. It predicts well performance on the basis of up-to-date hydraulics and reservoir conditions. The scheme has been implemented in a black oil simulator by using separable programming and simplex algorithm. This production optimization scheme has been applied to two full-field models. The oil production of these two full-field models is limited by water, gas, and liquid handling limits at both field and flow-station levels. The gas production is limited by injectivity and gas handling limits. For a 12-year production forecast, the new scheme increased oil production by 3 to 9%.
Drilling Optimization—The Driller's Role
Authors: Reinhold W. B. , Close D. A. 
Published: December 2007

Summary
For any given drilling operation, several drilling technologies are available to optimize the process of producing a usable borehole. The intent of this process is to conduct the drilling safely and in the most cost-effective manner possible. Our industry has made significant progress in developing improved technologies such as realtime formation evaluation, directional control while drilling, improved bottomhole assembly (BHA) components, and drilling fluids. These and other new technologies have added the requirement for specialized staff at the wellsite and, at the same time, have often reduced the role of the driller. The challenge facing the industry for the foreseeable future is to find a more efficient method of utilizing these technologies while simultaneously reducing the need for certain specialized staff.
This paper analyzes the driller's role and emphasizes his role as the critical link in safely and efficiently drilling a borehole. As the industry moves toward the more cost-effective technologies of computer-based instrumentation, power-handling tools, and automated drilling, the driller's role will need to evolve from one of basic drilling mechanics into that of a real-time drilling supervisor. In this way, the driller (the only 100% real-time link with the drilling process) should become an active member of the wellsite management team, thereby reducing some need for specialized advisory staff.
Field Applications of Steam Foam for Mobility Improvement and Profile Control
Authors: Patzek Tad W. 
Published: December 2007

Summary
Foams are used to control and improve the injection profile in secondary or tertiary gas-injection processes and reduce gas mobility far from the injectors. Over the last decade, significant progress has been made in the understanding of the complex foam processes in porous rocks. The goal of this paper is to review consistently, albeit somewhat subjectively, several important field tests of foams, compare their performance, and critically evaluate the economic benefits from foam injection. It is shown that early, transient, and usually small oil production responses to surfactant injection are real, and depend critically on the reservoir architecture and gas flood implementation. These early production responses are related to the improvements of gas-injection profile by foam and are often quite profitable. The delayed, but bigger oil production responses are caused by foam propagation into the reservoir and could be very profitable, depending on the injection policy. An outline of an ideal future foam pilot is presented, and important advances in rigorous modeling of foam processes are discussed.
Performance of Multiple Horizontal Well Laterals in Low- to Medium-Permeability Reservoirs
Authors: Retnanto Albertus , Economides M. J. 
Published: December 2007

SummaryA generalized semianalytical productivity model, accounting for any well and reservoir configuration has been constructed and presented recently. The model allows for the production or injection prediction of any well (vertical, horizontal, deviated) and reservoir configurations in both isotropic and anisotropic media. Partially completed wells can also be simulated. A concern in modern reservoir management is the potential desirability of multiple horizontal laterals, frequently emanating from the same vertical well. Once pseudosteady state is reached, the productivity index differences among various well configurations are diminished. Thus, multiple laterals in higher-permeability formations, draining an assigned "box," may not offer incremental benefits. However, at early time and under transient conditions in low- to medium-permeability reservoirs, the relative productivity improvements provided by multiple laterals may result in sufficient incremental benefits to warrant their drilling. This paper presents a series of parametric studies for a range of reservoir permeabilities and permeability anisotropies for various multiple well configurations. The desirability or lack thereof for these configurations is demonstrated.
The Impact of Corrosion on the Oil and Gas Industry
Authors: Kermani M. B. , Harrop Don 
Published: December 2007

SummaryThe impact of corrosion on the oil industry has been viewed in terms of its effect on both capital and operational expenditures (CAPEX and OPEX) and health, safety, and the environment (HSE). To fight against the high cost and the impact of corrosion within the oil industry, an overview of topical research and engineering activities is presented. This covers corrosion and metallurgy issues related to drilling, production, transportation, and refinery activities.
Egypt's First Subsea Completion: A Gulf of Suez Case History
Authors: El Hawary Ahmed , Hoffman John G. 
Published: December 2007

Summary
A case history of the Gulf of Suez Petroleum Company's (GUPCO) first remotely controlled subsea completion is provided. The first completion was for well GS 373-2, a previously drilled and tested exploration well located in the south portion of the Gulf of Suez. Subsea technology was utilized to economically justify development of this one well marginal field which was discovered in 1978. Traditional methods proved to be too costly for development, therefore application of a low cost subsea tree was utilized to capture the resources.
In the Gulf of Suez, many fields have been discovered but have not been developed due to low reserves. These marginal projects can have a profound impact on the revenue and shareholder value if an economic method is used to exploit these opportunities. Platform installation was not feasible due to reserve size, hence the well has remained abandoned until recently. Capturing the experience of Amoco in the Gulf of Mexico and in the Dutch North Sea, Gupco was able to build a low cost subsea system which would allow for the economic development of the marginal fields discovered in the past.
This paper presents a summarized look at subsea completion technology. The cost comparison of traditional development methods will be made, given the local cost structure in Egypt. The application of this technology has some limitations and constraints which will be discussed in the paper. Furthermore the actual field installation of Egypt's first remotely controlled subsea tree will be summarized. Also included is a discussion on simple remote controls, and offshore installation operations.
Asphaltene Adsorption Onto Formation Rock: An Approach to Asphaltene Formation Damage Prevention
Authors: Piro Giampietro , Canonico L. B. , Galbariggi Guido , Bertero Luigi , Carniani Carlo 
Published: December 2007

Summary
In this paper, through a comparative study on static vs. dynamic adsorption of asphaltene onto formation rock, we report how, for the particular asphaltene/formation rock system considered, the dynamic asphaltene adsorption onto formation rock is a continuous phenomenon by which the quantity of adsorbed asphaltene increases continuously. In our opinion, this rather remarkable adsorption behavior may contribute to asphaltene formation damage. In the hypothesis that "prevention" may represent a more economical approach than "removal," we also report a possible "prevention approach" based on formation rock treatment by means of specific chemicals more apt than asphaltenes to be adsorbed onto rock. As a preliminary demonstration, with the aim of assessing qualitatively the potential of our approach, we have pretreated the rock with commercially available asphaltene dispersant and flocculation inhibitors. Although the chosen additives are not commercialized on the basis of their specific adsorption feature, a modest prevention effect has been found. Experimental set-ups and procedures used as a base for a test to rank chemicals with respect to their "asphaltene adsorption" inhibitive effects are also reported.
Improving the Efficiency of Matrix Acidizing With a Succinoglycan Viscosifier
Authors: Jones A. T. , Døvle Marit , Davies D. R. 
Published: December 2007

Summary
The efficiency of matrix acidizing treatments is becoming more critical, especially as more wells are drilled with long, horizontal sections. Without some sort of selective placement or diversion technique, zones near the point of acid injection or with high injectivity will be preferentially treated. Yet hardware solutions are often prohibitively expensive, and many available diversion techniques are not readily applied in openhole horizontal sections. In this context, viscosified acids offer a potential solution.
An investigation into the placement of gelled acids over a treatment interval has shown that they can greatly improve the uniformity of acidizing. Other studies have revealed that a succinoglycan biopolymer in hydrochloric acid (HCl) exhibits nearly ideal gelled-acid properties over a certain temperature range. To design a gelled HCl treatment, the temperature- and time-dependent rheology of succinoglycan in HCl has been determined. The experimental data have been fit to a model that is used here in an example optimization procedure.
Permeability Prediction by Hydraulic Flow Units—Theory and Applications
Authors: Abbaszadeh Maghsood , Fujii Hikari , Fujimoto Fujio 
Published: December 2007

SummaryAn improved technique based on the concept of hydraulic flow units or hydraulic units (HU's) is presented to calculate permeability distribution in uncored wells. Graphical probability methods, nonlinear regression, and the Ward's analytical algorithm are presented to perform cluster analysis on core data and identify prevailing HU's in a formation. A Bayesian-based probabilistic approach is discussed next to estimate HU's and permeability distributions in logged wells. This is an inverse problem that requires constructing an a priori training database to capture implicit relationships between core-derived HU's and various well log measurements. Information from the database is drawn statistically to infer HU distributions at target logged wells. The method is applied to two heterogeneous reservoirs, a carbonate formation, and a laminated sandstone formation. Comparisons of permeabilities calculated by the HU approach and other conventional techniques are provided that demonstrate the usefulness of the HU method.
Modeling Coiled-Tubing Velocity Strings for Gas Wells
Authors: Martinez John , Martinez Alec 
Published: December 2007

Summary
Because of its ability to prolong well life, its relatively low expense, and the relative ease with which it is installed, coiled tubing has become a preferred remedial method of tubular completion for gas wells. Of course, the difficulty in procuring wireline-test data is a drawback to verifying the accuracy of the assumptions and predictions used for coiled-tubing selection. This increases the importance of the prediction-making process, and, as a result, places great emphasis on the modeling methods that are used. This paper focuses on the processes and methods for achieving sound multiphase-flow predictions by looking at the steps necessary to arrive at coiled-tubing selection.
Furthermore, this paper examines the variables that serve as indicators of the viability of each tubing size, especially liquid holdup. This means that in addition to methodology, emphasis is placed on the use of a good wellbore model. The computer model discussed is in use industry wide.
A New Analysis of Pressure Decline for Acid Fracturing
Authors: Gu Fagang , Ren Shuquan , Zhao Zhenfeng 
Published: December 2007

Summary
Conventional pressure-decline analysis has been used successfully to determine the in-situ fluid-loss coefficients and fracture geometries of minifracture tests or full-scale hydraulic fracturing. However, it fails to interpret the pressure-decline data of acid fracturing because it has a different fluid-loss mechanism and a short testing time. This paper presents a new pressure-decline analysis for full-scale acid fracturing or acid minifracturing to estimate fluid-loss coefficients and evaluate fracture geometries for the Perkins-Kern-Nordgren (PKN) model.1,2 The models established after shut-in have comprehensively taken into consideration the influences of compressibility and thermal expansion of fluids (waste acid and CO2 gas produced by reaction) and the rock volume etched away by acid. The effects of formation temperature and reaction heat are also taken into account in this analysis. The analytical solution derived by Nordgren2 for large fluid-loss is used to calculate the fracture-width distribution along a fracture. The short-test-time data for acid fracturing can be interpreted as a simulation technique used in analyzing.
The comparison of the results of conventional analysis and this new analysis for field test data shows that the conventional analysis causes a −56.2% error in the fluid-loss coefficient and underestimates the fluid-loss. The relative errors of the conventional analysis for estimating fluid efficiency and hydraulic-fracture length and width occur 186.2%, 220.8%, and 16.5% respectively.
Early Identification of Reservoir Compartmentalization by Combining a Range of Conventional and Novel Data Types
Authors: Smalley P. C. , Hale N. A. 
Published: December 2007

Summary
Reservoir compartmentalization (vertical and lateral) is often a major uncertainty at the field appraisal stage, impacting important investment decisions. Unfortunately, the most definitive compartmentalization data (dynamic production data) are not usually available so early in field life. This paper illustrates how early indications of compartmentalization can be achieved by integrating various types of conventional and novel data. Using an example from the Ross oilfield, U.K. Continental Shelf (UKCS), we demonstrate how integration of oil compositional data (molecular maturity parameters, gas chroma-tography [GC] fingerprinting, pressure-volume-temperature [PVT] data) with pressure, well test, and fault seal analysis revealed the presence of several sealing faults, and thus enabled the field to be described in terms of its likely segmentation. Vertical compartmental-ization was investigated using a combination of oil geochemistry (maturity, GC fingerprinting), water composition (residual salt analysis), and high-resolution stratigraphy, revealing a continuous shale that has a lateral extent of &gt; 5 km; it divides the reservoir into two main layers. The results of this study helped to decrease uncertainty in field development planning. The key message is that there are many tools available to aid in assessing compartmentalization, but individually they each only give part of the picture. It is therefore important to use several tools in combination.
Reparameterization Techniques for Generating Reservoir Descriptions Conditioned to Variograms and Well-Test Pressure Data
Authors: Reynolds A. C. , He Nanqun , Chu Lifu , Oliver D. S. 
Published: December 2007

Abstract
Recently, we have shown that reservoir descriptions conditioned to multiwell pressure data and univariate and bivariate statistics for permeability and porosity can be obtained by techniques developed from inverse problem theory. The techniques yield estimates of well skin factors and porosity and permeability fields which honor both the spatial statistics and the pressure data. Imbedded in the methodology is the application of the Gauss-Newton method to construct the maximum a posteriori estimate of the reservoir parameters. If one wishes to determine permeability and porosity values at thousands of gridblocks for use in a reservoir simulator, then inversion of the Hessian matrix at each iteration of the Gauss-Newton procedure becomes computationally expensive. In this work, we present two methods to reparameterize the reservoir model to improve the computational efficiency. The first method uses spectral (eigenvalue/eigenvector) decomposition of the prior covariance matrix. The second method uses a subspace method to reduce the' size of the matrix problem that must be solved at each iteration of the Gauss-Newton method. It is shown that proper implementation of the reparameterization techniques may significantly reduce the computational time required to generate realizations of the reservoir model, i.e., the porosity and permeability fields and well skin factors, conditioned to prior information on porosity and permeability and multiwell pressure data.
Errors and Uncertainties in Reservoir Performance Predictions
Authors: Bu Tor , Damsleth Eivind 
Published: December 2007

Summary
While the uncertainty related to mapping/quantification of hydrocarbons initially in place is well understood, there are problems regarding the sources and propagation of errors/uncertainties in reservoir simulation. Because reservoir models use measured data from only a small fraction of the total reservoir volume, the challenge is to construct a reservoir model that uses the available data and minimizes errors in simulation results.
Several recent studies have aimed at performing a total uncertainty analysis of reservoir simulation results. Underlying such work is usually a number of hypotheses/assumptions that are not always clearly expressed.
In this paper, we will discuss implications of some of the statistical methods that are commonly applied in uncertainty analysis and construction of a geological model. The Bayesian approach, where additional data can reduce uncertainties, is emphasized.
Several papers have demonstrated large variations in parameters obtained from routine and special core analysis on samples originating from the same geological building block (lithofacies). This variation, which sometimes may be difficult to dissolve from uncertainty in the measurements, must be accounted for in models that describe small scale variation.
Trials of Threshold Hydrate Inhibitors in the Ravenspurn to Cleeton Line
Authors: Corrigan A. , Duncum S. N. , Edwards A. R. , Osborne C. G. 
Published: December 2007

Summary
A series of field trials to test threshold hydrate inhibitors (THI's) has been carried out in the wet gas line connecting the Ravenspurn and Cleeton fields. These BP-operated assets are located in the U.K. sector of the southern North Sea, approximately 50 miles offshore of the Dimlington gas terminal. The flow line is 13 miles long, 16 in. in diameter with a normal production rate of 195 MMscf/D. During the trial, the line pressure was maintained at 75 barg (1,088 psig) for a throughput of 90 MMscf/D. When methanol injection into the line was stopped, hydrates readily formed. Conditions in the line were 8 to 9°C inside the equilibrium hydrate curve. This resulted in an estimated 50 tonnes of hydrate accumulating in the line over a 4-day period. At these same conditions, THI injected at a dose rate of 3,000 to 5,000 ppm (parts per million on the basis of total water production) prevented hydrate formation. After 6 days, the chemical supply was exhausted, and after a delay during which chemical was flushed from the system, hydrates formed as before. The robustness of the chemical to line shut-in conditions was also confirmed. These trials conclusively show that a low dosage chemical can be used for hydrate suppression in a wet gas pipeline system.
Application of Streamtube Techniques to Full-Field Waterflood Simulation
Authors: Emanuel A. S. , Milliken W. J. 
Published: December 2007

Summary
A comparison between streamtube and finite-difference (FD) modeling for waterfloods is presented to show the utility of streamtubes as a reservoir modeling technique. The streamtube formulation follows most of the classic techniques presented in the literature. Areal sweep in the model is determined by streamlines developed on the basis of unit mobility ratio and corrected for changing mobility ratio by the method of Martin and Wegner.1 Displacement along the streamtubes is calculated by a Welge2 construction with vertical heterogeneity represented by Dykstra-Parsons3 (DP) layering. This work differs from previous efforts because wells are individually history matched by assignment of DP coefficients on a well-by-well basis. Suggestions are made for the further application of the saturation distribution resulting from the model.
Two applications of the technique are described. The first is a comparison between FD and streamtube modeling for a waterflood based on the Ninth SPE Comparative Solution Project.4 This application is designed to describe the basis of the streamtube technique in the context of a standardized industry problem. The second application is for a study of the Kaybob North reservoir that shows model development and history matching for a 100 + -well field with a 30-year history and a number of realignments.