bluuebunny/crossref_metadata_2025 huggingface dataset:
Incorporating Mean-Reverting Price Forecasts into Exploration and Production Project Valuation
Authors: Hahn W. J. , Dyer J. S.
Published: December 2007

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

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

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

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

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

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

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

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

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

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

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

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).
Enzyme Breakers for Chemically Modified Starches
Authors: Battistel E. , Bianchi D. , Fornaroli M. , Guglielmetti G. , Europa P. , Cobianco S.
Published: December 2007

The filter cake removal is still an important concern both for producers and injectors. Mainly in long horizontal completion sections, the cleanup of the filter cake does not always occur spontaneously because sometimes the drawdown in the production direction is not enough. For injection wells a chemical treatment is usually required for an efficient cleanup. Acids and oxidizers may not be applied in high sensitive and/or in low temperature formations but the use of a proper enzyme breaker may lead to an efficient degradation of the polymeric materials preventing great permeability impairment.

The use of linkage specific enzymes instead of mixture of generic hydrolytic enzymes has given in the last years a significant improvement to the breaker performance. Linkage specific enzymes give the possibility to select the specific chemical linkage to be broken within a well defined polymeric substrate. This means that the enzyme activity can be tailored according to the well conditions as well as to the drilling fluids properties and composition. Breaker efficiency is also related to the size distribution of generated polymeric fragments. However, previous studies suggested that although the filter cake degradation seems effective from a fluid loss point of view, the polymeric fragments produced by the filter cake degradation may contribute to formation damage. It is therefore important to gain information on the degradation reaction mechanism by studying not only the enzyme specificity on a particular polymeric substrate but also the chemical nature of the end point products.

The laboratory data presented in this study show that starch specific enzymes such as amylases, cellulases and glucosidases are highly efficient to degrade native and chemically modified (cross linked) starches. The specificity of the enzyme activity on the different polymeric substrates as well as the molecular weight distribution of the degradation fragments were studied and characterized. It was found that each enzyme is not only linkage specific but also regio-specific, that is, it is able to degrade chemically different regions of the starch polymeric chain. The effects of the activity of different enzyme breakers were investigated by filter cake treatment tests.
The Missing Link—Identification of Reservoir Compartmentalization Through Downhole Fluid Analysis
Authors: Elshahawi H. , Hashem M. , Mullins O. C. , Fujisawa G.
Published: December 2007

Reservoir compartmentalization is a major cause of production underperformance in the oilfield. A well drilled into a compartmentalized reservoir will see only part of the hydrocarbon in place over the production time scale. The obstruction to free flow can be sealing faults, fault baffles, pinching out layers, sand lenses or low permeability areas. Although it is recognized that a comprehensive approach to compartmentalization must make combined use of all available rock and fluid data, the case studies in this paper show Downhole Fluid Analysis (DFA) to be one of the most effective techniques in recognizing compartmentalization via fluid signature comparisons and fluid density inversions. Corroboration with geological, petrophysical, reservoir engineering and production data confirms the strength of the DFA technique

Fluid compositional variations must be considered in order to acquire fluid samples representative of the reservoir at large and to devise optimal production strategies. In addition, fluid compositional variations can be utilized as a tool to identify compartmentalization because different compartments are likely to be filled with different fluids. The limitation on use of such techniques in the past has been the need to rationalize the use of wireline sampling to collect and analyze only the necessary samples. In this paper, DFA is shown to be the "missing link." It provides the information necessary to optimize the sampling process and to decide in real time on where sampling is needed without necessarily having to bring all samples to surface.
Application of CHI Modelingsm Using Pulsed Neutron to Create Pseudo-Open Hole Logs
Authors: Reed S. , Quirein J. , Torne J. P. , Morales M. , Bernal J. , Perez M. , Casares M.
Published: December 2007

The Burgos Basin, located in Northeastern Mexico, has sometimes been very difficult to evaluate with openhole wireline tools because over-pressured formations present a problem when trying to reach a balanced borehole condition. This paper will discuss three problem wells, presenting both CHI Modeling results used to solve the problems as well as an alternative method of obtaining resistivity behind casing.

Case History #1 looks at the Fundador Field which has been a particular problem in this area, presenting both drilling and logging difficulties. Because of borehole problems associated with over-pressured formations encountered in this well, it was not possible to acquire openhole wireline logs across the intermediate drilling zone. After the well was completely drilled and cased, a pulsed neutron tool was run across the entire well to assist in the evaluation. By using the resistivity data acquired in the previous section of openhole along with the pulsed neutron data logged in cased hole across the same interval, the missing resistivity data was predicted over the entire intermediate zone. The pseudo resistivity log was created using only the pulsed neutron data obtained across the intermediate zone, processed with the CHI (Cased Hole Interpretation) Modeling program. The final resistivity is also compared to a second method of obtaining resistivity behind casing used by another service company.

Case History #2 uses CHI Modeling to create pseudo openhole logs that were subsequently used as inputs to a volumetric evaluation. The CHI Modeling results are compared to an alternate method of obtaining resistivity behind casing. Testing results are documented to confirm the validity of both the CHI Modeling and the volumetric evaluation.

Case History #3 documents where the CHI Modeling technique was successfully applied through two strings of casing where density data was not available. A comparison to the original openhole logs is presented confirming that this technique is a valid option when additional openhole information is required in a partially logged well.

This paper will discuss the procedures used to evaluate three case histories using CHI Modeling, and present two comparisons with a second cased hole resistivity measurement. Production data is also presented to validate this technique.

The use of pulsed neutron logs to acquire pseudo openhole data is shown to be a valid alternative when drilling conditions do not permit normal data acquisition in openhole; or when additional openhole information is required after the well has been cased.
3D Analysis for Wellbore Stability: Reducing Drilling Risks in Oriente Basin, Ecuador
Authors: Torres Villalobos M. E. , Frydman M. , Casalis D. , Ramirez A. , León M. F. , Villalba E.
Published: December 2007

This work describes a 3D approach that was used to reduce drilling risks and unscheduled events in Palo Azul field. The field is in the Oriente foreland basin (Figure 1), contiguous to the Ecuadorian Andean foothills. A portion of the field presented an unexpected igneous intrusion (laccolite) just above the reservoir formation. The 3D analysis combined 3D seismic information with the 3D structural and geological model to generate a 3D geomechanical model. The mechanical earth model (MEM), relied on onsite real-time monitoring, was used to support drilling decisions, providing predictions of well trajectory, casing points, and mud window.

The 3D velocity/amplitude cube, derived from one portion of the 3D seismic program, was used as the base to construct the MEM. To capture the uncommon structural characteristics associated with the complex geological structure, an innovative methodology was developed. Steps included special reprocessing of sequences of the seismic data; structural model reinterpretation; 3D seismic velocity analysis; population of the rock properties in the 3D domain (Geostatistical approach); integration with wireline logs; core measurements analysis; and drilling history review of the offset wells. The real-time geomechanics support allowed making important decisions in time when unplanned events occurred while drilling.

This new methodology created a systematic approach to well planning that reduces drilling risks in the development of a complex area. The value added by the integrated team's efforts was demonstrated by drilling the next two wells with significant reductions in costs and nonproductive time. A sensitivity analysis of different well trajectories across fractured zones was performed. Wellbore stability forecasts were compared with reference to the 3D model developed. The results obtained contribute to a better understanding of the mechanics of stress development around a magmatic intrusion and a faulted/folded zone.

The methodology developed allows better insight into the parameters that must be included in the 3D MEM creation and wellbore stability forecast for similar environments. This method also serves as a good basis for further development, such as sanding studies, completion design optimization, reservoir studies, and uncertainty analysis.
Rock-Drilling Fluid Interaction Studies on the Diffusion Cell
Authors: Muniz E. S. , da Fontoura S. A. B. , Lomba R. F. T.
Published: December 2007

This paper presents a new set of rock-drilling fluid interaction tests carried out in the diffusion cell using saline solutions and mineral oil on a Brazilian offshore shale. The diffusion cell was designed to apply hydraulic and chemical gradients through shale samples in order to evaluate shale-fluid interaction. The proposed test allows the determination of rock permeability, the coefficient of reflectivity (membrane efficiency) and the ionic diffusion coefficient. These parameters are essential to carry out proper wellbore stability analysis when taking shale-drilling fluid interaction into account. Shale characterization, testing methodology and test results are described. The results showed an average permeability of 46 nD and membrane efficiency less than 2 % for the tested shale.
Role of Asphaltene in Foamy Oil Flow
Authors: Adil I. , Maini B. B.
Published: December 2007

The role of foamy oil flow in cold production of heavy oil has attracted considerable attention in the literature. It has been suggested in several studies that there may be a link between the presence of high Asphaltenes content and the foamability of oil. However, a systematic examination of the impact of Asphaltenes on the performance of solution gas drive, in connection with foamy oil flow, has not been reported. This paper presents an experimental study that addresses this issue.

The objective of this study was to examine whether or not the presence of Asphaltenes has a strong influence on the performance of foamy solution gas drive. To this end, parallel solution gas drive experiments were conducted with a heavy crude oil from Lloydminster area and a de-asphalted version of the same oil. To eliminate the influence of oil viscosity, the original crude oil was diluted with a 50-50 mixture of heptanes and toluene to reduce viscosity to the same level as that of the de-asphalted oil. The experiments were carried out in a visual sand pack that permited observation of bubble formation in the sand.

The results show that the effect of asphaltene content varies with the depletion rate. At higher depletion rates, the oil recovery and production profile of crude oil with asphaltene is different from those without asphaltenes. The presence of asphaltenes, appears to facilitate bubble nucleation, decreases the critical super-saturation and helps in maintaining the dispersed gas flow by suppressing bubble coalescence. However, as the depletion rate declines, the incremental recovery due to asphaltenes diminishes. The two crude oil samples provided similar recovery and production profile when the depletion rate was the slowest one used in this work.
A Review of Matrix Acidizing Sandstones in Western Siberia, Russia
Authors: O'Driscoll K. , Stolyarov S. , Kalfayan L.
Published: December 2007

Matrix acidizing of sandstone formations in Western Siberia, Russia has been a technology application that has been largely ignored by operators in this area. Poor acidizing practices and difficult mineralogies have lead to poor results from matrix acidizing treatments applied in the past. With the relative success of skin bypass fracturing treatments and the development of a fracturing stimulation environment within Russia, matrix acidizing has been rendered essentially irrelevant. This paper reviews past and present practices and explores the reasons why matrix stimulation has been largely unsuccessful in Western Siberia. The paper also explores the developing need for matrix treatments, particularly in horizontal wells, and the application of modern acidizing systems and techniques in Western Siberia and the challenges associated with applying these "new" technologies
Gas Segregation in Turning Flows: Analogy with a Gas-Handler
Authors: de Matos A. , Franca F. A.
Published: December 2007

This paper presents experimental data and numerical results on the phase distribution of gas-liquid bubbly flows taking place inside a U-bend pipe curve of square cross-section. The main purpose was to contribute the understanding of analogous processes taking place in gas-handlers. The experimentation was performed with air-water superficial velocities in the range of 0.03 m/s to 0.14 m/s and 0.88 m/s to 2.12 m/s, respectively. The centrifugal force based Froude number (buoyancy/centrifugal force) varied from 0.15 to ~1. To measure the phase distribution, a conductive probe technique was used. The Two Fluid Model was applied to simulate the flow. The numerical algorithm was set-up to account for two turbulence models and other closure relations representing interfacial pressure term and the generalized interfacial force. Results and comparisons are commented.
Effective Reservoir Management of Thin Oil Rims
Authors: Samsundar K. , Moosai R. , Chung R.
Published: December 2007

Proposal

The Mahogany field in Trinidad and Tobago was developed as a dedicated gas field with reserves of 2.6 TCF to supply gas to the Atlantic LNG Plant in 1999. A major contributor to the gas in place is the 21 sand, which has reserves of 350 bcf. In addition however a thin oil rim (of 60ft) was discovered in this 21 sand. Initial recovery estimates for this thin oil rim was put at 18% with an estimated recoverable reserves of 18mmstb. At that time it was considered to be a marginal development. Approximately 30mmstb later, the development and management of the 21 sand thin oil rim have been a remarkable success story.

The 21 sand is now set to deliver a recovery factor 34%, a best in class in the industry. Since first coming online in early 1999 the production and reservoir management philosophies have changed to respond to the depletion of this thin oil rim. Each phase of the field life, from first oil to mature asset, has provided its unique set of challenges. The Mahogany team has always risen to these challenges through the practical application of new technology and innovative thinking.

This paper will discuss how the production and reservoir management strategy for the 21 sand has evolved along this journey, highlighting the difficulties encountered, actions taken and the success of these interventions. This continuous reservoir management has clearly shown the economical viability of producing a thin oil rim with a large gas cap.
Production Control Through Main-Wells Telemetry
Authors: Distefano G. , Pioli A.
Published: December 2007

This work describe PETROBRAS ENERGIA experience settling a Control Production model based in telemetry on main wells, that impact in meaningful form in the production. Also, this work describe applications, advantages and disadvantages that they can be observed in the experiences accomplished in Puesto Hernandez Oilfield in Neuquen Province in the Argentinean Patagonia

Nowadays, the control of the production using instrumentation and control technology is very common over the oilfields around the world, but in mature fields where a low lifting cost is required, implementation of this technology can not be accomplished without take care in which wells are applied and which not.

In the Puesto Hernandez oilfield, the monitoring of the production is accomplished through the wells telemetry in those wells that are important in the production.

Due to Puesto Hernandez is a mature field with secondary recovery and great quantity of water, the telemetry and control is made on injector wells, wells with electro-submersible pumps (ESP) and in those wells of great quantity of associated net oil like well with Progresive Cavitation Pumps (PCP).

This model in addition to having a very good relationship cost - benefit, focusing the control in those principal vectors of production being an interesting alternative for mature fields, where an integrated control of all the wells can require a high important investment that it is not sustained by this type of fields
Streamline-Based Global History Matching for Geological Modeling Calibration. Application to a Giant Fluvio-lacustrine Sandstones Reservoir Field
Authors: Galacho M. , Vázquez P. , Paci V. , Fernández G. , Canosa C.
Published: December 2007

Proposal Abstract

The Dynamic Numerical Simulation in Flowlines (DNSFL) is an alternative tool adapted for handling Fine Scale Dynamic Models. DNSLF uncouples reservoir geometry and heterogeneity from transport equations, solving problems dominated by convective flows in a faster and computationally more efficient way. This allows to build Models of greater spatial discretization and, consequently, to better represent reservoir heterogeneity. This feature has been particularly relevant for studying the current case, that consists of great extension reservoirs with considerable facial and stratigraphical variations.

In this paper a workflow is presented, using the above DNSLF properties, in a Global History Matching to develop the "Fine" Scale Geologic Model Calibration and the Definition of a Preliminary Static-Dynamic Model of a giant field of Neuquén Basin, Argentina.

The analyzed field is constituted by fluvio-lacustrine deposits, nine sand-clay cycles (only six of them were modeled), partially connected reservoirs; with 380 actives wells in commingled production and water injection; and with a long and detailed history of simultaneous primary and secondary events.

CPU runtimes around 70 minutes were achieved using a 808860 grid cells Model, with 111 quarterly based timesteps in a Pentium 4 PC, 2.2GHz CPU and 2GB RAM. This showed that it was possible to work with a big Model in short processing time.

With this preliminary model, based on a well-groups-level global history matching, a clear conceptualization of the current primary and secondary production mechanisms, and its productive behavior, was obtained. This reservoir conceptualization was a strong guide for the Global History Matching process.

Geostatistical and Upscaling procedures applied for the definition of the Simulation Model could be evaluated by means of sensitivities analysis on some model parameters.

This preliminary model allowed sensitivities to make recommendations on future work stages, including Geological Model refinements and detailed History Matching.
PDC Bits Run on Turbodrills: The History, Facts and Current Developments
Authors: Seale R. , Conroy D.
Published: December 2007

Over time there has developed a perception that PDC bits are not typically run at high speeds. This perception has propagated from the perception belief that PDC cutters at high speeds will generate enough heat to thermally degrade the cutter or the impact damage at high speeds will destroy the cutter. However, twenty years ago when PDC bits were in their infancy, they were in fact run very successfully at high speeds. Many ROP records in these older fields were drilled with PDC bits on high speed drives. Over time however, PDC bit designs have transgressed to enable better performance when coupled with slower drive mechanisms, such as rotary and positive displacement motors (PDM).

PDC technology has evolved dramatically over the last decade and it has become evident that further substantial developments based on the type of drive mechanism being used will lead to specific designs. This is vital, as different drive mechanisms behave differently, not only with regard to RPM, but also concerning tool plus bit generated vibration, depth of cut (DOC), blade count, cutter density, profile, etc. Analyzing the history of PDC bits run at high speeds and more recently the current designs which are primarily run at lower speeds proves this hypothesis.

The developmental process for further enhancements to PDC bit performance will be two fold. One, to make the PDC bit durable enough to last over long drilling intervals without sacrificing ROP, and two, to base the design on the specific run parameters a particular drive mechanism delivers. Discussions in this paper will detail the history of PDC bits run at high speeds, while addressing the particular design and characteristics required for successfully running PDC bits at high speeds, and finally addressing the research and development currently underway to optimize high speed PDC bit performance.
Effect of Compositional Grading on Reservoir Fluid Characterization: Case Study
Authors: Salehirad Y.
Published: December 2007

The variation of fluid composition with depth in a reservoir is called compositional grading. As depth increases, the mole fraction of light components decreases, density increases and GOR decreases1. In the case of these reservoirs prediction of phase behavior and accurate characterization of reservoir fluids becomes more critical. The reservoir under study is a saturated oil reservoir with a large initial gas cap and a tall column of oil. This fractured carbonate reservoir contains intermediate oil and is produced under natural depletion mechanism at the all of its life time2.

In this work several complete PVT reports from different depths of Asmari reservoir that show definite variations in composition and physical properties (especially saturation pressure), and some other reservoir/field data were used. Two fluid samples were chosen as the most representative samples, one for light samples and another for heavy samples. Also an optimum regression method was applied using a PVT package to characterize the reservoir fluid system. Finally results were prepared to use in Asmari reservoir simulation.
Evaluating Intelligent-Well System Requirement for an Offshore Field Development
Authors: Ajayi A. , Konopczynski M.
Published: December 2007

The paper describes the study conducted to evaluate the number of wells (producers and injectors) required to develop a small segment of an offshore field. The development plan consisted of both conventional and intelligent well completions. The main objective was to identify the best application of intelligent well technology in the field and quantify the gains from such applications. The technical performances of these cases are compared using the same base reservoir simulation model. Binary and multiple position downhole flow control valves are considered to determine the right level of "smartness" required for the field.

The study has shown that application of intelligent well completion (IWC) technology in selected wells will add value through control of produced water after breakthrough and manage subsurface uncertainty by mitigating unexpected well performance. We estimated incremental oil gain of 2.5% to 26% within the first two years after water breakthrough.

The results also demonstrated the capability of the IWC system to maximize asset productivity in cases where breakthrough occurred early and when it occurred somewhat later. In the former case, the non-offending intervals are able to easily complement the effect of choking back the offending zone resulting in significant gain.
Well Control Aspects Regarding Slender Well Drilling With Surface and Subsea BOP
Authors: Avelar C. S. , Santos O. L. A. , Ribeiro P. R.
Published: December 2007

The 2003 Brazilian deepwater drilling record (4th in the world) was achieved with a slender well in a 2887-meter water depth in Campos Basin (block BMC-10), Rio de Janeiro. Uncommon to the drilling practices throughout the world and, particularly, in the Brazilian coast, the well was safely drilled with a surface blowout preventer system (SBOP). Beyond the importance of a world record class, the result points out to an important paradigm shift in the current technical culture throughout the country, considering safety (human, environmental and material), economical and regulatory issues which surrounds such decision taking task. This work presents two discussions: the first one concerns the technical issues considering well control operations performed on the drilled well and on a hypothetical conventional well that could also be drilled under the same conditions. This discussion involves the calculation of pressures at the choke, at the casing and liner shoes, pit gain and produced gas rates at the surface using the driller's method. The results were obtained with an existing well control simulator for deep and ultradeep water drilling. The second discussion concerns important aspects of the surface BOP technology mainly related to well control. Thus, the main objective of the present work is to bring to light a broad discussion regarding the potential application of the SBOP concept to explore and develop deep and ultradeep-water reserves in Brazil, with emphasis on well control.