bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparison of Techniques for Risk Analysis Applied to Petroleum-Field Development
Authors: Ligero E. L. , Madeira M. G. , Schiozer D. J. 
Published: December 2007

Proposal
Petroleum field decision-making process is associated to high risks due to geological, economic and technological uncertainties, and high investments, mainly in the appraisal and development phases of petroleum fields. In these phases, it is necessary to model the recovery process with higher precision increasing the computation time to represent all possible scenarios. The necessity to speedup the process demands simplification of the process. The use of Monte Carlo technique, for instance, is normally not viable when numerical flow simulation is used to model the recovery process due to the high number of simulations required. The use of the derivative tree technique can be an alternative in such a case but it also yields a high number of simulations when several attributes have to be considered. An alternative, in such cases, is to use fewer attributes or to use a lower number of discretization levels. Another alternative is to simplify the reservoir modeling process with faster models. Several works are being presented recently about these techniques but normally they show applications but not a comparison among alternatives. The objective of this work is to compare these techniques taking into account the reliability and precision of the results and speed up of the process due to the simplifications. Monte Carlo and derivative tree techniques are compared using reservoir simulation, sensitivity analysis, experimental design and response surface method as supporting tools. These techniques are applied to an offshore field to quantify the risk in economic and technical parameters. The results show that it is possible to reduce significantly the number of flow simulation runs maintaining the precision of the results.
Rigorous Approach for Viscous-Oil Productivity Forecast Before Well Completion
Authors: de Andre C. , Cañas J. A. , Low S. 
Published: December 2007

Abstract
This paper describes an integrated and rigorous approach for viscous and middle oil reservoir productivity evaluation using petrophysical models calibrated with permeability derived from mini tests (Dual Packer) and Vertical Interference Tests (VIT) from open hole wire line testers (MDT *). It describes the process from Dual Packer Test and VIT pre-job design, evaluation via analytical and inverse simulation modeling, calibration and up scaling of petrophysical data into a numerical model, history matching of Dual Packer Tests and VIT with numerical simulation modeling. Finally, after developing a dynamic calibrated model, we perform productivity forecasts of different well configurations (vertical, horizontal and multilateral wells) for several deep offshore oil reservoirs in order to support well testing activities and future development strategies.
The objective was to characterize formation static and dynamic properties early in the field development process to optimize well testing design, extended well test (EWT) and support the development strategies in deep offshore viscous oil reservoirs. This type of oil has limitations to flow naturally to surface and special lifting equipment is required for smooth optimum well testing / production.
The integrated analysis gave a good overall picture of the formation, including permeability anisotropy and fluid dynamics. Subsequent analysis of different well configurations and lifting schemes allows maximizing formation productivity.
The simulation and calibration results are compared to measured well test data. Results from this work shows that if the various petrophysical and fluid properties sources are integrated properly an accurate well productivity model can be achieved. If done early in the field development program, this time / knowledge gain could reduce the risk and maximize the development profitability of new blocks (value of the information1).
Development of an Optimization/Economic Model for Virtual Gas Pipelines
Authors: de Sa Neto A. , Filho V. J. M. F. , Moulin R. G. , Fiuza C. 
Published: December 2007

Abstract
This is the first of a series of papers describing the application of simulation-optimization methods coupled with an economic model to "Virtual Gas Pipelines". Virtual Gas Pipelines consist in transporting compressed (CNG) or liquefied natural gas (LNG) in tanks to remote locations.
In this paper we apply the use of a Virtual Gas Pipeline to a CNG system (compressed natural gas systems). This system is composed by a mother station (compression station with truck upload) with "n" satellite stations (delivery points). The results presented here illustrate the potential in cost-effectiveness that can be made by employing logistics simulation as the foundation for a wide-ranging search for solutions to gas transportation problems.
Two models are developed for a virtual CNG pipelines: a simulation model and an economic model to represent the process of transporting using of trucks. These models are integrated.
A field application case is detailed for CNG for vehicular use (NGV) with many NGV sale stations. Important optimization aspects are discussed such as mother station size, location, gas load distribution, number of loads, truck use and others. Economics aspects are also discussed specially presenting cutoff parameters for determining the application of Virtual Pipelines. Service level efficiency and also business profitability are two key elements of this integrated analysis
This methodology can be adapted for the use of other technologies to a Virtual Gas Pipeline System. These new technologies can be another gas transformation method such as liquefaction (LNG) or another gas transportation system such as shipping (barges).
Advanced Risk Analysis Approach for Optimization of a Water Injection Program -Illustration on a Brazilian Field Case
Authors: Manceau E. , Feraille M. , Zabalza-Mezghani I. , Portella R. C. M. , Reis L. C. 
Published: December 2007

Abstract
This paper presents an advanced risk analysis approach that has been applied on a Brazilian field case to manage and quantify the reservoir uncertainties during production forecasting and production scheme optimization.
The oil field (named PBR) is located offshore Brazil. The PBR reservoir consists of a complex lithology, including mainly turbiditic sandstones interbedded by shales and marls. The workflow of the PBR reservoir modeling from the geostatistical lithofacies model, built using the non-stationary truncated gaussian method, to the flow model (about 24000 active cells) has been implemented in a fully integrated chain. The field was considered in this hypothetical study at its appraisal stage. Main challenge consisted in selecting an optimal water injection scheme to maximize oil production while minimizing water production and maintaining pressure over the 15 years of production, taking into account the overall major sources of uncertainties in the reservoir.
Advanced risk analysis methods were used with the following objectives:
– Determine the impact of the main uncertainties on the field production forecasts versus time and versus geographical locations of production and injection wells – Optimize the water injection phase to maintain pressure over time, while producing maximum oil and minimum water in a 15-years period. – Quantify the impact of main uncontrollable reservoir uncertainties on production forecasts and fluid distribution maps versus time for the optimal water injection program selected in order to identify potential risks with non-drained zones and pressure drops.
At each step, either classical or optimal experimental designs were used to be able to perform an accurate analysis at a minimum cost in terms of reservoir simulation and interpretation.
Results show that this innovative methodology can be successfully applied on complex real cases to quantify the risk associated with the main reservoir uncertainties during production forecasts and to optimize the water injection. In particular, this example illustrates how some innovative interpretation tools can be combined with experimental design methodology to perform advanced risk analysis for reservoir management.
Compositional Modeling of Retrograde Gas-Condensate Reservoirs in Multi-Mechanistic Flow Domains
Authors: Ayala L. F. , Ertekin T. , Adewumi M. 
Published: December 2007

Abstract
A multi-mechanistic flow environment is the result of the combined action of a Darcian flow component (the macroscopic flow of the phase due to pressure gradients) and a Fickian-like or diffusive flow component (diffusive flow due to molecular concentration gradients) taking place in a hydrocarbon reservoir. The present work presents the framework needed for the assessment of the impact of multi-mechanistic flow on systems where complex fluid behavior-such as that of retrograde gas-condensate fluids-requires the implementation of compositional reservoir simulators. Due to the complex fluid behavior nature of gas-condensate fluids, a fully-implicit (IMPISC-type) compositional model is implemented and the model is used for the study of the isothermal depletion of naturally fractured retrograde gas reservoirs. In these systems, especially those tight systems with very low permeability (k &lt; 0.1 md), bulk fluid flow as predicted by Darcy's law might not take place despite the presence of large pressure gradients. The use of an effective diffusion coefficient in the gas phase—which accounts for the combined effect of the different diffusion mechanisms that could take place in a porous medium—and its relative contribution to fluid recovery is discussed. The compositional tracking capabilities of the model are tested and the conditions where Fickian flow can be the major player in recovery predictions and considerably overcome the flow impairment to gas flow posed by the eventual appearance of a condensate barrier—typical of gas-condensate systems—are investigated. Finally, a mapping that defines different domains where multi-mechanistic flow can be expected in compositional simulators of retrograde gas-condensate reservoirs is presented.
Decline-Curve Analysis for Solution-Gas-Drive Reservoirs
Authors: Frederick J. L. , Kelkar M. 
Published: December 2007

Abstract
This paper introduces a new method for analyzing solution-gas production to determine the ultimate recovery of a well or a field. The procedure developed and outlined in this paper requires very little input data and is easily implemented. By modifiying the equations for dimensionless rate and dimensionless cumulative production derived for the single phase model, a new set of equations is developed to approximate the ultimate recovery of a solution-gas well. Using the approximate material balance equation based on numerical results by Vogel1 and the equation for the production rate derived by Fetkovich et al.2,3,4, this new set of dimensionless rate and dimensionless cumulative production equations are derived. Using the relationship between these equations and an iterative calculation procedure, the ultimate recovery for the solution-gas well can be easily determined. All that is needed as input is the producing bottom-hole pressure, the initial pressure, and the oil production data. The method has been validated with twelve simulator cases, six under constant bottom hole pressure production constraint and six under variable bottom hole pressure production constraint. Furthermore, several field cases have been analyzed. The synthetic and field cases validate the procedure. Using the early pseudo-steady state production data in the analysis the results generated by the method are consistent with the actual ultimate recoveries.
Design and Implementation of a Computer-Based Tool for Risk and Impact Assessment of the Environmental Pollution in the Niger Delta Using Simulation Method
Authors: Igbokwe C. M. , Olofinlade A. V. , Ojegbile A. V. , Aroh A. O. 
Published: December 2007

Summary
This paper presents the design and implementation of risk and impact assessment of a tool that helps quantify and manage uncertainty to aid strategic decision-making over the life of an asset. The dynamic and iterative nature of the tool and the processes involved allows for rapid, quantitative systems analysis of the impact of a wide number of options with their associated uncertainty (risk). The result is a robust method to understand the risks and potential value of the prospective enterprise on an ongoing basis through development, operation, and expansion phases. Implementation of the tool over the entire life cycle of an asset is simulated, discussed and illustrated with two case studies.
Significant Results in Field Trials (Argentina) of an Electronically Controlled Automatic Drilling System
Authors: Fernández M. , Ibáñez D. , Storey G. 
Published: December 2007

Abstract
An Electronically Controlled Automatic Drilling System has shown significant results in improving drilling efficiencies in the Entre Lomas Field located in Neuquen province, Argentina. The new generation of electronic, automatic brake controllers available for land rigs and band brakes delivers increased drilling efficiencies and problem avoidance. An important reduction in total rotating hours has been obtained, by both increasing rates of penetration (ROP) and improving bit life.
Effect of Flue Gas Impurities on the Process of Injection and Storage of CO2 in Depleted Gas Reservoirs
Authors: Nogueira M. C. , Mamora D. D. 
Published: December 2007

Abstract
Our previous coreflood experiments - injecting pure CO2 into carbonate cores - showed that the process is a win-win technology, sequestrating CO2 while recovering a significant amount of hitherto unrecoverable natural gas that could help defray the cost of CO2 sequestration. In this paper, we report our findings on the effect of "impurities" in flue gas - N2, O2, H2O, SO2, NO2, and CO - on the displacement of natural gas during CO2 sequestration. Coreflood experiments were conducted at 1,500 psig and 70°C, in which a flue gas was injected into a carbonate core containing initially methane. Two types of flue gas were injected: dehydrated flue gas with 13.574 mole % CO2 (Gas A), and treated flue gas (N2, O2 and water removed) with 99.433 mole % CO2 (Gas B).
Main results of our study to-date are as follows. First, during displacement of methane, the dispersion coefficient increases with concentration of the "impurities". Gas A exhibits the largest dispersion coefficients, 0.18 - 0.25 cm2/min, compared to 0.13 - 0.15 cm2/min for Gas B, and 0.15 cm2/min for pure CO2. Second, for all cases, recovery of methane at breakthrough is relatively high, ranging from 86% OGIP for pure CO2, 74-90% OGIP for Gas B, and 79-81% for Gas A. Lastly, injection of Gas A would sequester the least amount of CO2 as it contains about 80 mole % nitrogen. From the view point of sequestration, Gas A would be least desirable (though the cheapest separation process). Gas B (flue gas with N2, O2 and water removed) appears to be the most desirable as separation cost would probably be cheaper than that for pure CO2 while natural gas recovery are similar in both cases.
Interface Management for Subsea Sand Control Completion
Authors: Crumrine T. , Nelson R. , Cordeiro C. , Loudermilk M. , Malbrel C. A. 
Published: December 2007

Abstract
Poor interface management can lead to time overruns and negatively impact the relationship between time, cost, scope, quality, and resources.The trend of streamlined organizations with reduced staffing often requires companies to rely on mul-tiple parties to complete a project.Even with the trend of streamlining, deepwater operators are challenging themselves to drill more complex wellbore architectures, and subsea sand control completions are becoming increasingly intricate.The development of such wells poses particular risks due to the completion complexity and requires a high degree of interface management to ensure operational success.
Interface management (IM) problems lead to scope creep in which the balance between project scope, time, cost, quality, and resources is upset.The objective of this paper is to pro-vide a roadmap in dealing with interface management issues early on in the project life cycle, so that potential problems can be mitigated and scope creep can be eliminated. The goal is to help provide a fit for purpose and high quality completion system delivered on time and within budget.
The objective is accomplished by first investigating Interface management, and second using proven project management techniques to solve common problems associated with poor IM.Third, three subsea sand control completion cases are reviewed in which proper IM was used to provide successful project results.An additional case review provides insight on IM outside of the oil and gas industry.Finally, an IM "road-map" is provided to assist the reader in developing their own IM philosophy.While the scope is limited to sand control completion systems, the IM techniques presented can be ap-plied to all aspects of the industry.
Well Succeeded Examples of Mature Waterflood Project Revitalization
Authors: Dõria M. A. F. S. , da Silva A. W. , Franco C. A. C. , do S. M. S Batista M. , De C. J. A. M. 
Published: December 2007

Abstract
Carmópolis, Siririzinho and Riachuelo oil fields, located onshore Northeast region of Brazil, were discovered in the sixties and quickly put into primary production. Waterflooding followed in the seventies, trying to restore reservoir pressure and well productivity.
For more than twenty years, oil production in these fields was maintainned under infill drilling and addition of new areas to the waterflood projects. Since production has reached its technical and profitable limits, oil rates has reversed to a deep decline.
A strategic IOR project conducted by PETROBRAS focused on improving waterflooding efficiency in Carmópolis field, led to significant changes on the management of that field and Siririzinho and Riachuelo fields as well, and supported the revitalization process of these fields.
The results were not only a total reversion but also an increasing in oil production profile that was declining for more than ten years. This work presents the results of the revitalization program in the mature waterflooding projects of Carmópolis, Siririzinho and Riachuelo fields, showing the importance and influence of each decision made during the project implementations.
A Case Study of Value Generation with Intelligent Well Technology in a High Productivity, Thin Oil Rim Reservoir
Authors: Elmsallati S. M. , Davies D. R. , Erlandsen S. M. 
Published: December 2007

Abstract
The Application of Intelligent (or Smart) Well Completion Technology (IWT) has not progressed as rapidly as originally expected. This is partly due to management's lack of confidence that the "added value" is sufficient to justify the extra investment. This concern can be addressed by publication of well-documented examples of IWT delivering value.
This paper describes the detrmination of the "added IWT value" from maximising oil production, within allowable gas constraints, for the Norwegian NH-field that produces from a thin oil-rim using high productivity, horizontal-wells. The well drawdown is similar, or lower, than the frictional pressure drop along the completion length. This generates a skewed production profile along the length of the completion; the bulk of the oil production - and early gas and water break-through - occurring at the heel of the well. This is further accentuated by the presence of a tilted, high-permeability sand that connects the heel of the well to the gas cap. A further complication is that the bubble point is close to the initial reservoir pressure (in fact at the gas-oil-contact, the saturation pressure and the reservoir pressure are identical) and 34% of the total Hydrocarbon Liquid is associated condensate in the gas cap.
This paper not only shows how the "added IWT value" was derived, but also the: Development of a well-performance management philosophy,Optimisation of the conventional well using a sector of the full-field model,Insertion of a detailed, Intelligent Well (I-well) completion model within this model,Development of an I-well design and operation philosophy,Illustration of the advantages, disadvantages and utility for well optimisation of available keywords within commercial simulation packages.
Finally, understanding how the I-well Completion "adds value" allows the development of guidelines for the choice of candidate wells in this type of reservoir where IWT is capable of delivering value.
Tube Pickling Procedures: Case Studies
Authors: Al-Mutairi S. H. , Nasr-El-Din H. A. 
Published: December 2007

Abstract
Tubing pickle treatments can eliminate formation damage that is caused by introducing millscale, pipe dope and other tubular contaminants into the formation. Two of acid pumping techniques implemented to perform the pickling treatments are bullheading and coiled tubing. In the bullheading method, the acid is pumped down the tubing, then the spent acid is lifted to the surface using reservoir pressure. Coiled tubing is another method where the acid is pumped down the coiled tubing, and flowed up through the tubing/coiled tubing annulus.
This paper examines the advantages and disadvantages of the two commonly used techniques for tubing pickling: bullheading and coiled tubing. The efficiency of each method is analyzed based on extensive analysis of field samples. In addition, the paper also addresses the effects of acid volume, concentration, and pumping flowrate on the efficiency of removing mill scale from the wellbore.
Field data indicated that tubing pickle is a must. Extremely high levels of total iron (up to 105,000 mg/l) were noted in the spent acid. The relationship between dissolved iron and acid concentration profile depended on the mode of acid pumping. In the case of bullheading, the iron peak coincides with the tail of the acid peak, whereas it coincided with the leading edge in the case of coiled tubing.
Getting a Clear Picture - Individual Zone Testing of the Khuff Reservoir Through First Application of a Zonal Isolation Completion and Nondamaging Drilling and Completion Fluids
Authors: Sorgard E. , Knox D. , Svoboda C. , Mason S. , McNeil B. 
Published: December 2007

Abstract
The North Field is a major gas field in the Khuff formation, offshore Qatar. Traditionally, this reservoir has been drilled with reduced solids drilling fluids and completed by heavily acidising the payzone in order to maximize production.
The purpose of appraisal well NFS 1-1 was to obtain high-quality representative formation fluid samples from each of the identified producing zones in the Khuff. The detailed gas analysis was required to determine the specifications of the Gas-To-Liquid (GTL) Plant to be constructed to process production from the field.
In order to achieve this, a new testing technique was developed using a ported liner, a high density, low solids reservoir drilling fluid, and a combination enzyme/chelating agent breaker to remove the filter cake prior to testing the individual zones. In order to ensure the success of this challenging operation, a high degree of collaboration between the operator and the supplier of drilling, completion and stimulation fluids was imperative.
The design and engineering of the fluids used during coring, logging, completion and well testing of NFS 1-1 is examined in this paper.