bluuebunny/crossref_metadata_2025_split huggingface dataset:
A World-Wide Economic Analysis of the Non Conventional Supply Based on a Modelling Approach
Authors: Saniere Armeelle , Lantz Frederic 
Published: December 2007

Abstract
The global energy trend forecasts point out an increasing demand over the next decades, especially for electricity and automotive fuel. Over the next 25 years, the growing activity of the transport sector will involve increasing quantities of liquid fuels. On the supply side, the crude oil share in the total primary energy supply should remain to around 35% until 2030. Thus, the non conventional supply, coming from non-conventional oil (tar sands, extra-heavy oil and oil shale) as well as technologies transforming gas or coal to liquids should give a significant and necessary contribution to the global crude oil availability.
We have analysed the potential development of the non conventional supply in a worldwide model which aims to satisfy the oil products demand until 2030. In this analysis, several geographical areas have been distinguished, to take into account the regional dimension of the supply and the demand. This paper is organised as follow: section 1 concerns the resources availability, section 2 deals with the production technologies, ongoing and future known projects, section 3 gives an overview of the modelling approach and, finally, the results are given in the last section.
Heavy crude which often result from a bacterial oxidation of conventional oils inside the reservoir rock, have different physical and chemical properties, generally degraded: they have much higher viscosity, higher heavy metals and higher sulphur and nitrogen contents. Due to those specific properties, their exploitation implies specific methods to extract, transport and transform them into final products. Different categories of heavy crude are usually defined according to their density: -the heavy oils, the API° degree of which is between 10 and 22.3;-the extra-heavy oils and bitumen, the API° degree of which is less than 10. The « in situ » level of viscosity makes the distinction between extra-heavy oils and natural bitumen: -extra-heavy oils have a viscosity smaller than 10 000 centipoises (cP), which means that they are flowing at reservoir conditions;-natural bitumen, also called tar sands or oil sands, have a viscosity greater than 10 000 cP; they are not flowing at reservoir conditions.
A MultiParameter Methodology for Skin Factor Characterization: Applying Basic Statistics to Formation Damage Theory
Authors: Restrepo A. , Duarte J. , Sánchez Y. 
Published: December 2007

Abstract
The following paper describes a Skin Factor characterization methodology that has been developed and successfully applied in fields operated by BP in Colombia, South America. The method is based on basic statistic correlations that are applied for the ranking of different measured or estimated damage parameters; the primary purpose of the method is to weight the different formation damage mechanisms taking place in the complex reservoirs of the Colombian Foothills in such a way that multicomponent skin characterization maps can be estimated. The presence of compositional fluids, active tectonics environments, stacked reservoirs and well access issues all account for the above mentioned complexity.
By the application of this methodology, the design of chemical stimulations has become more efficient as the output of the method, which is a Multi-Parameter characterization of the skin, is available for all the wells; in this manner, stimulation packages include components for the control of the main skin mechanisms in the ratios estimated by the model. The model is being continuously updated through the incorporation of measured and estimated damage related variables such as physical chemical analysis of back flowed samples (after stimulations), output from mineral and organic scaling index estimation models, laboratory studies and well intervention records, among others; all of them taken into account for the entire life of a particular well.
Fed by the Multi-Parameter model, a skin characterization mapping tool has been developed and has become a key input in the periodically reviews of well productivity; stimulation and well intervention options are being efficiently ranked in terms of benefit leading also to a better planning of well work campaigns.
Well Clean up Issues in Field With Sand Coproduction Philosophy in Oman
Authors: Putra Rafliansyah A. , Azkawi Ahmed , Bharti Sanjay , Oyemade Stella 
Published: December 2007

Abstract
The case reservoir is a field in South Oman and produces high viscous oil from well sorted unconsolidated formation sand with a small average grain size (40 microns). Initially the wells were completed with downhole sand control but suffered from extreme plugging due to very fine nature of formation sand.
After performing some trials it was proved that, it is better to produce the wells without downhole sand control. A pre-drilled liner is used for downhole completion and Progressive Cavity Pump is for artificial lift as it is the most sand tolerable available pump.
Sand co-production (i.e. sand removal at surface) is the optimal development for this field. Sand fill up in the well bore however became an issue in the high producers that are impacted by nearby water injection wells. This phenomenon caused a reduction in well productivity. Few methods were trialed to remedy this issue. Sand clean out with a wash string by reverse circulating didn't work because the reservoir is sub-hydrostatic.
Coiled Tubing clean out with foam was trialed but somehow the result was not effective to bring the well back to previous productivity especially on long horizontal wells. The annular velocity was probably not high enough to lift up sand from the well bore.
Concentric Coil Tubing was trialed also which does not require foam or nitrogen for sand clean out. This unit and its special tool (i.e. jet pump) uses water to create a vacuum in the well bore to have fluid return while lifting loose sand or debris to surface. This method bring the well back to its actual productivity when no hard obstruction is encountered during clean out.
This paper presents WRM team experiences in dealing with sand clean out and sand co-production issues.
A Comparison of Methodologies for Handling Produced Sand and Solids to Achieve Sustainable Hydrocarbon Production
Authors: Rawlins C. H. , Hewett T. J. 
Published: December 2007

Abstract
All oil and gas wells produce sand or solids in varying types and amounts. The size and concentration of natural solids (i.e. formation sand) and artificial solids (i.e. workover debris) determine their net effect on production equipment and the resulting management of hydrocarbon production. Conventional exclusion methodology prevents solids from entering the wellbore but may adversely affect inflow production due to skin buildup. Inclusion methodology allows the solids to be produced with well fluids for surface separation and handling. A comparison of the performance, operability, cost impact, and effect on production rate is made for both methods through application examples. The goal is to show that the increased production resulting from allowing solids to be produced in some high sand rate wells allows more sustainable hydrocarbon production with a cost benefit compared to downhole exclusion for certain producing regions.
Economic Evaluation of the Afghanistan Natural Gas Sector
Authors: Cronshaw Mark 
Published: December 2007

Abstract
Gas fields were developed by the Soviets in Afghanistan in the 1960s and 1970s. Gas infrastructure has deteriorated since their departure. There are attractive business opportunities for developing the natural gas sector. This requires simultaneous development of the upstream fields and facilities, downstream markets, transmission and distribution infrastructure, and the legal/regulatory framework governing gas activity.
The 2007 SPE/AAPG/WPC/SPEE Reserves and Resources Classification, Definitions, and Guidelines: Defining the Standard!
Authors: Etherington John R. , Ritter John E. 
Published: December 2007

Abstract
In late 2004, a focused effort was begun to update the 1997 SPE/WPC Petroleum Reserves Definitions and the 2000 SPE/WPC/AAPG Petroleum Resources Classification and Definitions. The evolution of the industry, driven by advancements in technology, the international expansion of the E&P sector and the increasing role of unconventional resources in meeting global energy needs, drove the requirement to update what had served the industry well for the last 10 years.
The 2007 system builds on previous industry efforts to provide sufficient guidance to achieve a high level of consistency in estimating resource quantities; it incorporates best practices identified in other international petroleum and minerals classification systems. It recommends a rigorous approach based on applying a series of defined projects to hydrocarbon-bearing reservoirs. Resource classes are defined according to the maturity of the applied projects expressed as qualitatively or quantitatively as the chance of reach producing status. Within each resource class, the relative uncertainty in the estimated quantities that may be recovered by each project under those conditions forecast to exist during its implementation are denoted by assignment to categories. Assessments may be conducted using deterministic and/or probabilistic methods.
In order to satisfy requirements of the full range of industry stakeholders, the 2007 system introduces additional classification and categorization terminology. The resulting document is a set of technical guidelines that can be adapted by oil and gas companies to better manage their business; moreover, it forms a standard that can be referenced by government agencies in defining reporting requirements.
Computation of Sand Production in Water Injectors
Authors: Vaziri Hans , Nouri Alireza , Hovem Knut , Wang Xiuli 
Published: December 2007

Abstract
A significant proportion of the future oil production is expected to be driven by water injectors and in reservoirs that are sand prone. Achieving sweep efficiency and sand control in such formations is challenging. In many cases the ideal sand control is no sand control (e.g., a C&P completion) requiring rigorous sanding assessment. Sand production in injectors often go unnoticed until it is too late (sand covering the pay) making it difficult to ascertain the specific set of conditions resulting in sanding and the severity of the individual sanding episodes. Based on physics and mechanisms governing sanding, general factors can be postulated on the causes of sanding but not in a quantitative form. To provide a deeper insight into this matter, a numerical study has been undertaken to model sanding in injectors with due account of several inter-coupled factors including injection pressure, crossflow, waterhammer pressure pulses, degradation of the formation matrix resulting from repeated shut-downs and others.
This paper describes the concepts used for sand production modelling and shows application of the model to a field problem involving a C&P completion in a sand prone reservoir. The results show the mode and magnitude of sanding are influenced by the rock properties, injection operations and the equipment type and installation. The cases analyzed indicate a correspondence between the rate of shut-in and the onset of sanding. In cases involving unconsolidated sands, the waterhammer effects have a pronounced impact on sanding. Sand control can be omitted in even very weak rocks provided the injection pressure is optimized, frequency of hard shut-downs is controlled and hardware is positioned in such a manner to reduce the waterhammer pressure pulse magnitude. The proposed modeling can be used in determining the sand sump capacity required over the projected life of the well.
Engineering Evolution for an Effective Zonal-Isolation Process in Production Casings for the Antonio J. Bermúdez Basin in South Mexico
Authors: Cázares Robles Francisco , Corbalá Marco Antonio Corona , Monroy Rafael Rodríguez , Kulakofsky David , Caballero Carlos , Rivera Jorge 
Published: December 2007

Abstract
Oil reservoir depletion resulting from commercial exploitation of mature fields has increased the frequency of special drilling conditions caused by low formation pressures that can lead to massive drilling fluid losses. Several of these challenges have been addressed by cementation engineering, specifically applied to the production casing.
Because of these conditions, the Antonio J. Bermúdez basin has been constantly evolving with regard to cementing technology as well as drilling fluids concerns in an effort to effectively obtain long term zonal isolation.
Application of cementation engineering for production casing in development fields has resulted in the need for low-density slurries that can rapidly develop compressive strength. Furthermore, improvement in rock mechanics understanding using formation-evaluation technologies, has positioned cementation engineering as a technical discipline focused on application of solutions encompassing the entire life of the well. As a result, for example, the concepts of elasticity and durability have become important for cementation engineering, which is now moving far beyond the traditional application of hydraulic principles for slurry design.
This paper describes the evolution and maturing of the Antonio J. Bermúdez Basin during the past ten years and the changes in design and execution of cementing operations as a result of new challenges in oil-based and water-based mud environments as well as the introduction of under-balanced drilling methods.
Analysis of Longitudinal Vibration of Drillstring in Air and Gas Drilling
Authors: Li Zifeng , Guo Boyun 
Published: December 2007

Abstract
Vibration of drillstring has detrimental effects on drilling performance. This type of vibration is much more severe in air and gas drilling than in liquid drilling due to the low damping effect of air and gas. It is highly desirable for drilling engineers to have a reliable mathematical model to simulate the vibration and identify resonance conditions before and during the drilling operations. This paper fills the gap.
Traditionally drillstring vibrations have been analyzed using bit-force as a boundary condition. Accuracy of such analyses is often questionable as the discrepancies have been observed between model-predictions and field data. Mathematical models of longitudinal vibration of drill strings excited by both bit-force and bit-displacement have been established in this study. Equations are solved using the method of separation of variables. Calculations with the solutions indicate that the resonance rotary speeds of drillstring predicted by the bit-force model are non-resonance rotary speeds predicted by the bit-displacement model, and vice versa. A field case study is presented in this paper. Data from a field operation with drillstring failure seems to support the bit-displacement model, not the bit-force model. The models are presented to drilling engineers to further verify their accuracies. Once fully validated, the mathematical models will provide drilling engineers an effective tool for designing drill string for air and gas drilling operations against drillstring failure.
Decision and Risk Analysis Through the Life of the Field
Authors: Paul Hultzsch , Lake Larry W. , Gilbert Robert B. 
Published: December 2007

Abstract
Investing in an oil and gas field is capital intensive and usually involves many risks. Nevertheless, the economic evaluations of these types of investment opportunities often ignore risk or are based on subjective risk assessments that are frequently biased. Furthermore, as the life of the field progresses, well and seismic data become available and the risk level of the project changes. In this paper we demonstrate a decision and risk analysis (DRA) method that minimizes the subjectivity in the evaluation and that can be consistently updated as the life of the field progresses.
We use a tank production model and Monte Carlo (MC) methods to simulate the possible economic outcomes, and ensuing risk, of a primary oil recovery project as a function of the uncertainties associated with the reservoir properties. During the early stages of the field (i.e. pre-discovery) the uncertainty information comes from the analysis of analog fields. In the post-discovery stage, the initial uncertainties are updated with well and seismic data using an application of Bayes theorem.
The method demostrated here gives decision makers a consistent and relatively transparent way to evaluate E&P investment opportunities. It also allows them to track how the risk level of a project changes through the life of the field.
Beyond Portfolio Optimization
Authors: Faya L. C. , Lake L. W. , Lasdon L. S. 
Published: December 2007

Abstract
Methods to obtain optimal portfolios have been used extensively in the financial community for several decades. The first methods were published by Markowitz in the 50's and the literature has been vastly expanded since these days. Most discussions and publications to date have been centered on the methods to perform portfolio optimization. However, the greatest value added by portfolio optimization is not in the optimization itself, but on the use of the results as an aid to decision making. Unfortunately, little research has been done on this behalf. This paper proposes a new approach, and intends to bridge this gap showing concrete portfolio management applications.
Portfolio optimization is not a single event, on the contrary, it is an iterative procedure where the results gathered from each iteration are used to feed the decision making process. After some decisions are made, or company policies established, the process must be repeated to observe the results of the simulation and to provide feedback to the decision making process. This paper describes three portfolio applications that aid corporate decision makers. The first application deals with the effect that production and capital constraints have on the portfolio optimization process. These constraints assist management in the setting of realistic company goals. The second application explains how acquisitions and divestures can be evaluated in the portfolio context, and the effect that those projects have on the company objectives. The third application explains the use of portfolio optimization to manage and drive the company strategy. Using these methods, management could manage acquisitions and divestures in a proactive way, set realistic goals and objectives. As a result, management gain more control and insight over the company future.
Inevitable Disappointment in Projects Selected Based on Forecasts
Authors: Chen M. , Dyer J. 
Published: December 2007

Abstract
Investors often select project whose estimated performance meets or exceeds a hurdle value. At the time of decision making, the true performance of a project is unknown but uncertain forecasts are available. Decision makers (DM) often ignore the prediction errors when they use these forecasts to choose projects. To the disappointment of the DM, many selected projects result in smaller actual yields than the ones that were forecasted.
Some have attributed the cause of this to the optimistic bias of the predictions. This paper shows that this disappointment can occur even if the prediction is unbiased. In this case, a bias can be introduced by the selection process that will allow more unattractive (over-estimated) projects to be accepted than attractive (under-estimated) ones. Although a similar phenomenon has been noted in statistics and finance research, it is not well understood in the context of project selection by decision analysts.
We present a solution method based on Bayesian updating, and demonstrate its effectiveness in eliminating the disappointment in project selection with realistic data from oil E&P projects.
Geosteering Horizontal Coalbed Methane Reservoirs: A Case Study
Authors: Meszaros G. 
Published: December 2007

Abstract
It is well known that horizontal wells provide maximum reservoir contact to optimize production rates and recovery. This holds true for Coalbed Methane (CBM) drilling as well. The direction and position of a horizontal CBM well can be controlled to intersect face cleats and take advantage of directional permeability. In this manner one can stay in zone in CBM drilling just as in other horizontal applications.
The use of at-bit gamma ray and inclination measurements in a Logging-While-Drilling (LWD) tool string greatly enhances the geosteering capabilities of the Bottom Hole Assembly (BHA). The measurements are made in a short sub positioned immediately above the drill bit. At-bit measurements improve directional control in geosteering complex sections. These tools are routinely used in CBM drilling, and other horizontal applictions, to extend the horizontal section within a particular coal seam.
Geosteering requires a software package capable of pre-well modeling, displaying the measured information and interactively adapting the model to the real-time data. Offset well data are used with the well plan for a horizontal well to predict the log response of the different logging tools. Different models can be generated to predict what the log response will be when drilling out of zone either at the top or the bottom, or when dramatic facies changes occur. While drilling, the models are continuously updated and compared to the real-time data to improve the formation model and structure. This allows real-time decisions to modify the well path and stay in the intended zone.
This paper describes the results of drilling horizontal CBM wells. The horizontal drilling includes combining at-bit measurements, LWD resistivity, and forward-modeling software.
Single Point of Initiation, Dual-Fracture Placement for Maximizing Well Production
Authors: Surjaatmadja Jim B. 
Published: December 2007

Abstract
Placement of a fracture in a formation has become a well-understood process in the industry. Recently, this practice was improved by the introduction of a method to properly initiate the fracture into a specific direction using super-high-energy jetting. A drawback of this jetting method though is not knowing exactly where the far-field fracture has gone. Although we know that the fracture will extend in the local minimum-stress direction, it is not known where that direction might be. In all probability, the fracture has gone into a less-than-desired area in the formation, and will result in only an "acceptable" improvement of production.
It was once thought that refracturing merely reopened existing fractures. Recently, however, it has been shown that refracturing can actually create new fractures. In addition, when refracturing causes older fractures to reopen, the results generally show that some new area has been reached by the fracture. It is the opinion of this paper that these new areas are not substantially different from the one reached by the first fracture because local depletion enhances the effects of the original stress regime.
This paper discusses a process whereby fractures are generated in a formation using at least two different fracturing techniques to reach formations in a manner not reached by conventional fracturing alone. In this process, the first fracture may achieve "acceptable" production goals, although the cost may be high. A second fracture is then quickly created to take advantage of the stress modification resulting from the first fracture. This rapid followup fracture is thus able to reach more productive rock not accessible to the initial fracture. Field data supporting the feasibility of this concept will be presented. Various situations where this approach could reap substantial benefits are also described.