bluuebunny/crossref_metadata_2025_split huggingface dataset:
Value Assessment Using the Modified Black-Scholes Equation
Authors: Rasmussen M. L. , Civan F. 
Published: December 2007

Abstract
The Black-Scholes equation is frequently used and critical for assessment of the value of investments and projects, such as dealing with petroleum reservoir exploration, development, and production, involving significantly high capital-intensive investment and prospect values. This paper presents a functional analysis of the Black-Scholes equation and develops analytical solutions under various conditions. It is demonstrated that the analytical solutions besides the special Black and Scholes’ solutions can be derived by means of the method of Laplace transformation. The generic analytic solutions and the analytical solutions for two specific boundary conditions are presented. The functional behaviors of these analytic solutions are demonstrated by parametric studies and applications. The solutions presented here are expected to be instrumental in understanding and application of these solutions in future studies. The analyses and analytical solutions presented can be readily extended for valuation of forward contracts and commodity options.
Incorporating Mean-Reverting Price Forecasts into Exploration and Production Project Valuation
Authors: Hahn W. J. , Dyer J. S. 
Published: December 2007

Abstract
Modern asset pricing methods that account for managerial flexibility in project valuation require the specification of the stochastic processes followed by commodity prices and by other underlying uncertainties. Simplifying assumptions about these processes can be made to facilitate numerical analysis using binomial trees or lattices; however these assumptions are often untenable. An example is the assumption of a stochastic process for commodity price that is lognormally distributed with variance that grows linearly with time, commonly referred to as a Geometric Brownian Motion (GBM). Although GBM processes are convenient for modeling, they produce forecasts that do not match the empirical evidence of mean-reversion in commodity prices, and result in significant errors in valuation. Several methods have been introduced for modeling mean-reversion, but they complicate the numerical analysis of valuation problems.
In this paper we discuss a new method for modeling mean-reverting processes that enables straightforward binomial tree and lattice-based approaches to valuation. We provide an illustration by applying this method to model a one-factor mean-reverting price process, and then use this model in the valuation of an example oil and gas project with downstream managerial flexibility. We also solve the example using an alternative method, monte carlo simulation, and show that our results are identical to those obtained from this more computationally intensive approach.
First Applications of a Multiple Fracturing Method in Noncemented Horizontal Offshore Wells
Authors: Rodrigues V. F. , Fernandes P. D. , Rosolen M. A. , de Almeida Franco M. L. , Neumann L. F. , Lima C. B. C. , Surjaatmadja J. B. , Miranda C. G. , Carneiro F. 
Published: December 2007

Abstract
This paper presents the first offshore applications, both in platform and subsea wells, of a multiple fracture creation process in openhole horizontal wells, previously applied in onshore scenarios. The applications had to overcome many challenges typical of workovers on mature field offshore wells. The paper covers detailed workover planning, multiple fracturing designs, operations data, and the stimulation results. The campaign comprised three horizontal slotted liner wells offshore Brazil as part of a research project to evaluate selective stimulation methods for horizontal wells. It was proved that the method can be successfully applied in platform and subsea wells (a first). The economic results were very attractive, making the method an alternative for hundreds of noncemented offshore horizontal wells.
One-Step Acid Removal of an Invert Emulsion
Authors: Quintero L. , Jones T. , Clark D. E. 
Published: December 2007

Abstract
Removal of skin damage resulting from internal and external filter cake deposition during oil well reservoir drilling with invert emulsion drill-in fluid is desirable in order to maximize hydrocarbon recovery. Efficient filter cake cleanup is required for a number of open-hole completion operations, including the use of stand-alone and expandable sand screens, and conventional gravel pack applications for both production and water-injection wells.
Most of the currently used chemical methods to remove invert emulsion filter cake and internal formation damage are based on the use of acids, solvents and mutual solvents mixed in clear brine. Completing a well after drill-in with emulsion-based fluids is time-consuming and costly, and usually involves large volume multi-stage soak treatments.
Surfactant technology, when appropriately combined with conventional acid, allows a single-stage invert emulsion cleanup process. In this "one-step" cleanup method, the invert emulsion filter cake is incorporated into the organized surfactant in solution and the acid-soluble particles are then decomposed.
A number of injection permeability tests were performed on Berea sandstone cores and ceramic discs using various invert emulsion drilling fluids for filter cake deposition and organized surfactant in solution/acid blends for filter cake removal. This investigation demonstrated that, when using this technology to destroy the filter cake, (1) the invert emulsion is incorporated into the surfactant solution, (2) the solids become water-wet, (3) sludge formation between the acid and invert emulsion cake is prevented, and (4); and the majority of acid-soluble particles are removed.
This approach appears to be a credible method for removing formation skin damage and increasing hydrocarbon recovery and/or water injection rates.
Dynamics of Fluid Substitution While Drilling and Completing Long Horizontal-Section Wells
Authors: Dutra E. S. S. , Martins A. L. , Miranda C. R. , Aragão A. F. L. , Campos G. , Mendes P. R. S. , Naccache M. F. 
Published: December 2007

Abstract
Several fluid replacement operations take place during and after an oil well drilling operation, such as: the replacement of the drilling fluid by the completion fluid and the displacement of cleaning plugs or chemical treatment plugs. In such operations it is important to minimize the contamination of a fluid by the other to maintain the designed physical properties of the new fluid displaced.
This work presents a numerical simulation study of the operations related to the replacement of a fluid by another inside the well. The effects of density and rheology differences between the fluids are analyzed (Newtonian fluids displacing non-Newtonian fluids and vice-versa). The studies are based on the numerical solution of the governing equations for a two phase system and the subsequent evolution of the interface shape between the two fluids.
The present work details design criteria and fluid contamination predictions to some of the typical completion operations. Some displacement procedures are recommended to minimize contamination.
Ring Fence Provisions - How Important Are They in Determining the Value of Petroleum Projects and Portfolios?
Authors: Smith D. 
Published: December 2007

Abstract
Ring fence provisions are often ignored or greatly simplified when determining the value of a portfolio because of the complex modeling required. After reviewing the theoretical effects that ring fencing can have on both the value and expected value of portfolios, tests were run using actual fiscal terms and ring fence provisions in nine countries to determine the significance of the ring fence effects and whether or not the effects on portfolio value could be predicted prior to the complex modeling process by examination of the fiscal terms. While significance is a judgment that must be made by each analyst, the results otherwise indicate that prediction of the significance of proper ring fencing is virtually impossible in most situations because of the complex interactions among various fiscal components. The results seem to suggest, though, that proper ring fencing in fiscal systems with no sliding scales in any of their tax or production sharing contract terms will almost always enhance the value of the portfolio.
New Experimental and Modelling Approach for the Quantification of Internal Filtration
Authors: Al-Abduwani F. A. H. , Hime G. , Alvarez A. , Farajzadeh R. 
Published: December 2007

Abstract
A new experimental methodology using X-ray Computed Tomography for studying the filtration phenomenon that occurs during the injection of water with solid particles into porous media is presented. Previously unattainable deposition profiles are used to test for conformance the widely accepted classical deep-bed filtration model, proposed by Iwasaki in 1937. An equivalent system of linear ODEs is obtained using the method of characteristics and is used in the presented analysis. Results indicate that deposition profile measurements are more valuable than typically measured effluent concentration profiles. Furthermore, it is concluded from the presented analysis that the classical model is a valid approximation to the filtration phenomenon. However, clear discrepancies between model predictions and experimental results are observed. These discrepancies could be attributed to either the kinetics equation of the classical model or the extrapolation needed to compensate for data lost due to noise. Finally, a set of recommendations for improved experiments is suggested.
A Comparison of the Performance of Recent Sand Control Completions in the Mokoko Abana Field Offshore Cameroon
Authors: Mason D. , Ramos M. J. , Pena C. M. , Cameron J. , Jones C. 
Published: December 2007

Abstract
In over 300 expandable sand screen (ESS®) installations around the world it has proven exceedingly difficult to perform an equitable and rigorous comparison between the open-hole ESS system and an alternative completion technique. In this study, there is a marked apparent difference in completion performance between the systems and this is investigated in more detail in order to compare the techniques on an equal footing.
The Mokoko Abana field is situated offshore Cameroon. It is a mature heavy oil field initially developed in the 1980s. The sand is unconsolidated and all wells require sand control from start-up as evidenced by sand production if sand control is not effective. Several different types of sand control have been tried with varying degrees of success. This study is mainly focused on three different completions, all in similar configuration high angle wells in the same reservoir and sand.
The first type of completion studied was pre-packed stand alone screens (PPSAS). This showed excellent initial productivity, but was prone to a rapid decline in performance. The decline is attributed to hole collapse, either liberating fines plugging the screen, or creating a low permeability sand/shale mixture in the annular gap.
Open hole gravel packs (OHGP) were then used to support the borehole and immobilize any failed sand and fines in the annulus. The OHGP had a somewhat lower initial productivity than the PPSAS but has maintained a higher level of productivity over time.
Open hole expandable sand screens (ESS) are the most recent completion option, with the first being installed in Q4 2000. The main reasons for installing ESS were a number of reservoir simulation studies which showed better reserves recovery with a low skin completion, and hence ESS was selected in order to lower the overall skin.
As of 2005, the successful ESS wells show a high productivity that has been maintained over four years. An in-depth analysis of the productivity of the PPSAS, OHGP and ESS was undertaken. The analysis was complicated by variation in fluid and sand properties through the reservoir and masked by the different artificial lift methods used. This made an accurate assessment of the performance of each type difficult to achieve. However, even within the uncertainty in the analysis, the ESS completions have a significantly higher productivity and lower skin than the other two completion options.
The studies suggest there are production benefits in removing the annular gap. The range of sands controllable with an ESS is wide and supports the Ballard & Beare d5 criterion. ESS completions correctly applied can be successfully produced with high water cuts and draw-downs in excess of 500psi.
A Quantitative Method for Estimation of Volatility of Oil Production Projects
Authors: Lima G. A. C. , Suslick S. B. , Bordieri C. A. 
Published: December 2007

Abstract
The volatility is a key parameter that is difficult to estimate, but has a major influence in economic evaluation. Under the traditional investment view, volatility increases project risk, and the discount rate via a higher risk premium. In investment decision under the real option theory, volatility may aggregate value to the project, since the downside potential is limited whereas the upside is theoretically unbounded. In addition, volatility is an important indicator in oil project risk management, especially when oil prices present high levels of fluctuation. Volatility is hard to estimate. Oil price volatility can be estimated using historical data, but the procedure for estimating project volatility is more complex. This paper presents a framework to estimate the volatility of oil production projects employing a numerical technique based on project cash flows and the simulation of the evolution of oil prices using the Monte Carlo technique. Three stochastic processes to track oil price dynamics were used: Geometric Brownian Motion, Mean Reversion, and a pure Independent Lognormal Model. Since price is uncertain, NPV will also be an uncertain variable, so that its standard deviation is used as estimation of the true project volatility. This approach is applied to a portfolio composed of 12 deep-waters oil projects located in offshore Brazilian basins. These projects have different characteristics in terms of oil quality, water-depths, CAPEX, OPEX, infrastructure, etc. In order to reveal differences in results of project volatility, several correlations were evaluated regarding CAPEX, oil price and volatility of oil price. Preliminary results indicate that the project volatility is equal or higher than that of oil prices, especially in the case of high CAPEX and low price. In the simulations used in this study, project volatility ranged from 1 to 3 times oil price volatility. In case of oil volume of less than 300 MM bbl, the project volatility is around 1.8 times that of crude oil spot price. Therefore, this paper shows that the traditional assumption of using the oil price volatility, as a proxy for the project volatility may not give realistic results since most projects may not present a linear relationship between long-run average price and OPEX.
Maximizing Net Present Value in Mature Gas-lift Fields
Authors: Mora O. , Startzman R. A. , Saputelli L. 
Published: December 2007

Abstract
Advances in mathematical modeling and real-time monitoring have made it possible to more realistically and accurately model physics and economic performance of gas-lift oilfields. Mature fields, with installed gas-lift facilities (e.g. compressors, flowlines, and downhole valves) and reliably calibrated reservoir and facility flow models present a favorable opportunity to apply improved and more general optimization methods.
This paper describes a new approach for optimizing gas-lift operations in mature oilfields.
The new approach maximizes net present value by integrating mathematical models that describe the behavior of the reservoir, the behavior of the fluid gathering and gas-lift systems, and the future economic performance of the field operating under gas-lift. This integrated approach is in contrast to those in current use that typically seek to either maximize current oil production rate or to maximize the gas-lift efficiency of individual wells, and isolated from the ample economic picture.
To demonstrate the methodology, we tested it on case study for a mature offshore field in South America. Our results showed that the optimal operating conditions that maximize net present value do not necessarily occur at either the maximum production rate or at the maximum gas-lift efficiency. In fact, net present value improved 12% for the base oil price scenario, and up to 57% for the high oil price scenario, when applied the integrated approach of this paper.
Transverse Hydraulic Fractures From a Horizontal Well
Authors: Wei Y. , Economides M. J. 
Published: December 2007

Abstract
A non-fractured horizontal well is often not economically attractive in reservoirs where vertical wells are fractured. In many areas the latter are less expensive to complete and, with proper design, they provide at least as good and, usually, better well performance than horizontal wells. A considerable problem with horizontal wells is that they are rarely properly completed and/or stimulated.
One way, for a horizontal well to be potentially more attractive than a fractured vertical well, is for itself to be hydraulically fractured.
For almost all petroleum engineering applications, at depths where producing formations are found, the stress field leads to a hydraulic fracture that is vertical and normal to the minimum horizontal stress. Therefore the fracture direction and azimuth become important considerations in fracturing horizontal wells and they affect the well orientation. There are two limiting cases: the longitudinal and the transverse. For transverse fractures intersecting a horizontal well it is possible to generate multiple fractures with proper zone isolation.
The flow configuration in a transverse fracture intersecting a horizontal well generates an additional pressure drop which can be substantial. We provide a calculation procedure for this and relate the performance of each fracture with well-established methodologies, such as the dimensionless productivity index. Obviously, one transverse fracture intersecting a horizontal well cannot deliver the same performance as a fractured vertical well. Multiple transverse fractures are essential to make this configuration attractive. Thus, the question that we answer and quantify is the impact of multiple transverse fractures compared with the base case of a fractured vertical well.
What differentiate oil from gas reservoirs are the turbulence effects, often dominating the performance of a gas well but usually negligible in oil wells. This difference leads to a distinguishing performance between oil and gas wells. We present a comparative study of transverse fractures intersecting a horizontal well in oil and then in gas reservoirs, showing their significant differences.
Optimisation of Corrosion Inhibitors to Mitigate Localised Corrosion - A Proven Application of Online, Real-Time Corrosion Monitoring
Authors: Winning I. G. , Eden D. A. , Eden D. C. 
Published: December 2007

Abstract
This paper deals with the field use of a multi-technique electrochemical corrosion monitoring system, to differentiate between general and localized corrosion activity in a water injection system. The technology was used to identify the corrosion mechanism that resulted in failures in the system, showing benefit over and above 'conventional' corrosion monitoring techniques (e.g. Linear Polarisation Resistance, LPR, and coupons) that had failed to identify the corrosion risk.
Subsequent to identifying the type of corrosion in the system, the multi-technique approach aided the identification of a suitable corrosion inhibitor to mitigate the corrosion. The findings from the study have been confirmed by weight loss coupon data and 'conventional' monitoring techniques after implementation of a treatment program using the optimized corrosion inhibitor formulation.
Influence of Sodium/Potassium Formate-Based Drilling Fluids on Nuclear Logs
Authors: Al-Harbi A. , Ersoz H. , Abdrabalreda S. H. 
Published: December 2007

Abstract
Sodium, potassium formate (NaCOOH, KCOOH) based drilling fluids have provided improvement in many aspects of drilling and completing of HT/HP wells. These high density (up to 19 lb/gal), non-corrosive, environmentally friendly fluids can be mixed over a broad range of concentrations and/or temperatures without crystallization and solubility problems. Reservoir damage is minimized due to the low solids contents of formate based drilling fluids and they overcome shale and borehole stability issues. According to several projections, formate brines are like to be the most prominent drilling and completion fluid by 2010. Evaluation of wells drilled with formate brines requires special attention due to their unusual properties such as density, low Hydrogen Index and lower sonic travel time. Formate brines influence most logging tools somewhat differently than water or oil based mud systems.
Saudi Aramco has just started to drill with formate brines to overcome issues associated with HT/HP highly slanted/horizontal wells and initiated a study to measure the effects on nuclear logging tools. Nuclear logging tools are typically characterized in fresh water filled formation rocks, therefore it is essential that correction algorithms are developed for a broad range of hole sizes and mud weights for accurate formation analysis of reservoirs drilled with formate brines. Saudi Aramco and Halliburton Energy Services research center in Houston collaborated to study these effects on Neutron, Density, Natural and Spectral Gamma Ray logging tools. A series of experiments were conducted in various formation blocks of different borehole sizes immersed in many types of muds including the actual formate brine used to drill the initial well. The experimental data obtained and Monte Carlo Simulation models were combined to develop robust correction algorithms covering a range of hole sizes, temperatures and pressures (mud weights).