bluuebunny/crossref_metadata_2025_split huggingface dataset:
Discovering Real Options in Oilfield Exploration and Development
Authors: Claeys Justin , Walkup Gardner 
Published: December 2007

Abstract
Techniques from the burgeoning area of real options are helping petroleum companies better value and manage their important assets. The real options perspective holds that typical discounted cash flow (DCF) techniques (including typical decision analysis or Monte-Carlo simulation) capture only part of an asset’s value; significant value also derives from the management options inherent in the asset. For example, owning an offshore lease not only gives the owner the right to develop the field, it also gives the owner the implicit option to build oversize facilities to process oil from nearby fields. This option may give the lease additional value. The question remains, however, how does one determine all of the real options embedded in an asset? What are the management flexibilities that give rise to real option value in an asset?
This paper will discuss a series of practical framing techniques that uncover the managerial flexibility and learning that are the hallmarks of real options. The techniques are fundamentally creative, rather than analytic, and focus on the entire value chain associated with the asset. By focusing on the future, the goal of the framing is to produce the set of key dynamic asset management decisions that must be made over time, and the evolving uncertainties that influence those decisions. Proper structuring of these decisions and uncertainties establishes a blueprint for calculating the value of the asset, providing a key advantage over typical valuation methods such as DCF or decision analysis. We will present examples from oil and gas projects that will illustrate how multi-disciplinary teams have used these techniques to uncover real options that contributed significant value to petroleum assets.
Valuation of International Oil and Gas Properties
Authors: Gustavson J. B. 
Published: December 2007

Abstract
The valuation of international concessions, prospects and producing fields varies greatly from country to country because of differences in fiscal and political regimes. The valuation of such properties must therefore include quantified adjustments for these differences in the light of comparative modes of sale of other international properties. The market for acquisitions and divestitures works by applying such adjustments also to the values derived for domestic analogues with comparable geological, engineering and economic risks.
This paper discusses the primary types of fiscal regimes found around the world, namely licenses with royalties and taxes, association agreements and production sharing contracts. Discounted cash flow models are shown readily applicable to proved reserves.
A review of a recent market transaction is presented to demonstrate these effects. Political risk in the international market is shown to be additive.
Indonesia-Predictability of Discontinuous Change
Authors: Proehl Thomas Strenger 
Published: December 2007

Abstract
Recent discontinuous political change in Indonesia has disrupted exploration and production operations of overseas investors. Disruption raises issues of uncertainty, risk, and pre-dictability. Political risk factors are calculated from economic and financial data. Background political risk in Indonesia is on the order of 15% and crisis political risk is on the order of 40%. The approach to political risk presented herein is consistent with the Neoclassical Liberal economic ideology that economics should determine politics.
A Proposed Standard Economic and Production Data Conversion File
Authors: Banks Richard B. 
Published: December 2007

Abstract
Although there are many programs, e.g., ARIES, OGRE, PEEP, PEP, FEGS, etc., etc., all of them use essentially the same data, e.g., economic and demographic parameters, plus historical oil, gas, water and P/Z data. A standard file for these data would facilitate the exchange of evaluation data among oil and gas companies, banks and consultants.
Risk Management for the Development of an Offshore Prospect
Authors: Fassihi M. R. , Blinten J. S. , Riis T. 
Published: December 2007

Abstract
Traditionally, deterministic evaluation of geologic prospects has been used to assess their economic potential. In this paper, a probabilistic method (Monte Carlo Simulation) is described for evaluation of an offshore prospect in the Former Soviet Union. In this technique, both the technical uncertainties (risks) and the variability of the fiscal terms were taken into account. Specifically, the uncertainties in the following parameters were included in our evaluation: Geologic (trap, seal, etc.), Reservoir (size, net pay, well rates, development pattern), Oil (gravity and GOR), Drilling (depth, radius of departure, fixed and variable costs), Platforms (numbers, construction time and cost), Gathering and Export Lines (size, costs), Operating Costs (fixed and variable), Capital Costs (cost index), Project (startup), Oil price, Tariff, Royalty, Cost Recovery, Profit Oil Split and Taxes. Then, the impact of the technical uncertainty on the project economics was compared with the uncertainty in the commercial terms. It was found that technical risks have more impact on project viability than the commercial risks.
Geochemistry in a Reservoir and Production Perspective
Authors: Huc A. -Y. , Carpentier B. , Guéhénneux G. , Magnier C. 
Published: December 2007

Abstract
Reservoir geochemistry has proved to be a valuable approach to constrain reservoir model and predict, or evaluate, potential production problems at an early stage in field development. The now classical reservoir geochemistry methodology is based on the interpretation of compositional variations detected in oil or in soluble bitumen from rock reservoir including gross composition and molecular distribution1,2.
These variations are usually related to long term geological processes (biodegradation, water-washing, gas solubilization, thermal sulfate reduction, and thermodynamic disequilibrium)3 which alter the original oil composition inherited from the source-rock. In the presence of efficient permeability barriers which prevent homogenization of the fluids by diffusion processes, the compositional variations can be eventually preserved over geological time.
Additionally, by the possibility of combining molecular information on test fluid samples and reservoir rock organic content, reservoir geochemistry can lead to a better evaluation of the reservoir fluid stability and detection of internal reservoir heterogeneity such as bitumen rich levels or pyrobitumen occurrence4–5.
Because such molecular information is available from the first obtained test oil or core samples, the occurrence of difference in fluid compositions across a field can be detected in advance of any production. Such information can be incorporated into the appraisal of the reservoir communicability and taken into account in the very first development scheme. Additionally, molecular fingerprints from production fluids can be used to calculate the relative contribution of individual reservoir in case of multi-reservoir single completion1 or oil mud contamination.
In parallel to this pragmatic methodology, a new reservoir organic geochemistry approach is emerging. The objective is to integrate the reservoir fluid in the geological dimension of the petroleum system. This is done through the understanding, the formalization and the modeling of the different geological processes which alter the original composition of the fluid. The aim is to calculate the effect, at the molecular level, of the mechanisms potentially responsible for the modifification of the fluid composition (thermodynamic equilibrium, thermal cracking, water-washing and biodegradation), in the context of the geological environment. Using these simulations, it becomes possible to identify the process(es) which is (are) responsible for the recognized fluid composition and eventual heterogeneity. In this respect, reservoir geochemistry becomes predictive in term of fluid distribution at the reservoir and regional scale.
New Instrumentation and Methods for Production Logging in Multiphase Horizontal Wells
Authors: Chace David , Trcka Darryl , Georgi Dan , Wang Jianrong , Atlas Baker , Bousché Olaf , van der Spek Alex , al Nasser Hassan 
Published: December 2007

Abstract
New hardware and interpretation methods are introduced that are designed specifically for production logging and inflow profiling in multiphase horizontal or deviated wells. The new method is intended to allow the measurement of three phase flow rates, water cut, and gas volume fraction in any flow regime. The new production logging instrumentation utilizes arrays of capacitance sensors to make across-the-borehole measurements of liquid level, holdup, and phase velocities while simultaneously making average borehole measurements of pressure, temperature, diameter and noise. Newly developed downhole flow modeling software helps pre-job planning and post-job evaluation of data consistency. Flow loop data for 500 downhole flow conditions representative of two and three-phase flow situations in a near-horizontal well are discussed. Log examples illustrate the accurate measurement of multiphase inflow profiles.
The Role of Sequential Welltesting in Improving Oil Recovery from a Closed Sand Lens
Authors: Zubari H. K. , Abdulwahab A. E. 
Published: December 2007

Abstract
Being a principal reservoir engineering tool, welltesting can yield very important information that can be integrated into models generated from other data sources to form more reliable models. It has been observed that welltests can be exceptionally useful when conducted in closed systems due to the significance of information that can be extracted with regard to boundaries and limits in addition to the other routinely calculated parameters; permeability and skin at one point in time. However, the concept of a sequence of welltests on the same well has been found even more important in improving the oil recovery from closed sandstone lenses in the Bahrain field. Conducted on a specific well situated within a sand lens, sequential welltesting yielded valuable information that assisted in understanding the drive mechanism and the deteriorating reservoir parameters, permeability and skin. Such method was found crucial in improving the recovery from the sand lens from a reservoir as well as single well treatment perspective. In this paper an example of how such technique aided in improving the oil recovery from a small sand lens is presented.
A New Thermodynamic-Hydrodynamic Model for Prediction of Downhole Corrosion in Oil Wells Based on Multiphase Flow Simulation
Authors: Al Hattab Mohammed I. 
Published: December 2007

Abstract
The findings of one downhole corrosion study for one oil field, to envisage reasons of downhole corrosion failures, and to recommend corrosion control procedures standing on an economical feasibility study are presented. The prevalent corrosion mechanisms are erosion corrosion due to excessive multiphase flow velocity of the produced fluids, under slug / transitional to annular flow regime, impingement corrosion in tubings at locations where flow changes direction, carbon dioxide sweet localized pitting corrosion (mesa), and ringworm corrosion at the upset of the tubings. Results of assessment models reflected a moderate corrosivity, that would not alone cause such severe corrosion failures, unless augmented by other influential factors as the hydrodynamics of production, and the geometry of the well. This study has developed one new realistic downhole corrosion predictive model to assess risks of downhole corrosion based on the correlation of the thermodynamic production conditions, and the chemical properties of the produced fluids to both of the well geometry, and the hydrodynamic production conditions as obtained by multiphase flow simulation of the wells. The model was verified through comparison to the results of the corrosion caliper surveys in same wells. The study recommended both of the long and short term corrosion mitigation methods and procedures to control downhole corrosion in this field based on the production optimization, sand control, and the establishment of effective corrosion monitoring, inspection and visual inspection programs.
Design of Action Plan and Monitoring Program: Secondary and Tertiary Gas Injection Pilots in a Limestone Reservoir
Authors: Al Hendi Ahmed , Boyd Douglas , Al-Riyami Ahmed 
Published: December 2007

Abstract
This paper documents the design issues and considerations of a miscible gas flood monitoring program planned in 1999. The objective of the monitoring program is to assess the efficiency of gas injection as a viable means to increasing oil recovery.
Based on simulation findings, it was decided to carry out three pilots; two secondary and one tertiary miscible gas injection in three sub-reservoirs.
The pilots were designed to provide information for a future Full-Field Development Plan (FFDP). Intensive data gathering and monitoring is planned to: 1) diagnose and rectify unforeseen events early in the life of the project, and 2) evaluate each individual pilot's performance. Monitoring is planned through the pilot's wells, nearby wells and two new dedicated observation wells.
Utilization of Associated Produced Gas to Improve Oil Recovery
Authors: Dehghani Kaveh , Ehrlich R. 
Published: December 2007

Abstract
Associated gas produced from oil fields in remote locations are costly to transport to market and if not utilized has been typically flared. Utilization of associated gas may justify some improved oil recovery processes (IOR), which would not be economic, if gas had to be purchased at world price. These IOR projects look especially more attractive if the available gas would otherwise be flared.
Gas re-injection for pressure maintenance, and injection of gas enriched with LPG's at high pressures for miscible flood are among the practiced gas IOR processes. These methods are best applied to certain geologic settings, and operational parameters. Utilizing the associated produced gas as fuel to generate steam for IOR is an alternative method.
In this paper, the overall criteria for applications of miscible gas floods and light oil steamflooding are compared and feasibility of steam injection process as a gas utilizing IOR method is examined. Application of steamflooding to three light oil reservoirs with different geologic settings is evaluated. These were a waterflooded vuggy dolomite, a deltaic sandstone structural trap with a gas cap, and a waterflooded deltaic sandstone. Optimization of steam injection to take advantage of individual reservoir characteristics is demonstrated.
Steam injection process is also qualitatively compared with other stranded gas utilization methods such as liquefied natural gas (LNG), and chemical conversion of gas to liquid. The results show that light oil steamflood projects can be designed to take advantage of post-secondary residual oil saturation distribution in a considerably different fashion than conventional heavy oil steamfloods. The results also show that light oil steamflood when applicable is a potential for utilizing the remote associated gas.
Scale Removal in Khuff Gas Wells
Authors: Mirza Mohamed S. , Prasad Vineet 
Published: December 2007

Abstract
The gas produced from Khuff wells in Bahrain field have exhibited severe down hole scaling problems. The scale deposits mainly consist of iron carbonate and iron sulfide. The Khuff gas contains about 6.5 % carbon dioxide (CO2) and between 500 to 2000 parts per million hydrogen sulfide (H2S). No formation water production has been observed in any of the wells and the only water produced is condensed water vapor. The hydrocarbon condensate yield from the Khuff wells is about 6 barrels per million standard cubic feet of gas produced. Twenty four out of twenty six wells have been completed with 5" C-75 or L-80 carbon steel tubing and only two wells are completed with Nickel-Chrome corrosion resistant alloy tubing.
Downhole scale deposits have been observed in most of the wells located in the periphery of the field. Scale deposits are limited to the lower sections of tubing below 7,000' and in the production casing all the way to the perforation intervals. Reduction in well deliverabilities, restricting well bore accessibility and erosion damage to surface production facilities by produced scale particles are the main problems encountered in these wells.
Acid descaling jobs have been conducted on most of the wells suffering from scale deposits with good results. In some wells caliper survey run after descaling has revealed severe metal loss in the lower tubing joints in areas where scale has been removed. Workovers have been performed to replace tubing in wells where excessive metal loss was observed.
Production Enhancement Efforts in the SPDC-W Land District-An Integrated Team Approach
Authors: Nnabuihe Larry , Orunta Ike , Boham Don , Ukpebor Isaac 
Published: December 2007

Abstract
This paper presents the new approach to production enhancement adopted in the land area of SPDC-West, Nigeria. SPDC's funding difficulties in 1995 shifted the emphasis from development drilling and well completion activities to low cost enhancement of production potential in existing wells and facilities in order to maintain availability. To make the production enhancement process more effective, problem areas were identified viz: ineffective communication between field and office based staff, an incomplete well surveillance data-base for identifying enhancement candidates, lack of focus and perceived lack of resources and funding. To remedy these problems, the following initiatives were taken in 1995: four cross-functional teams were set up with Petroleum Engineering, Production Programming, Maintenance Engineering and Field Operations staff, focused on particular fields;performance was monitored on a monthly basis by the area Production Superintendent and Chief Petroleum Engineer and quarterly by the Production and PE Managers. Resource problems that could not be resolved at a lower level were also addressed at these meetings;a quality Well Surveillance Report, addressing some 600 drainage points, is produced and published quarterly, incorporating validated data.
The team structure and targets forced team members to break through the functional barriers and feel responsible for the whole process from candidate identification to field implementation. The effort yielded 31,000 bopd net oil gain in 1995 (comparable to the production of a new flowstation), with similar results in 1996 and 1997.
Effects of Permeability contrast in the Near Wellbore Flow Patterns-Comparison Between Experimental and Numerical Studies
Authors: Al-Marhoon N. O. , Carter J. N. , Grattoni C. A. , Dawe R. A. 
Published: December 2007

Abstract
An understanding of the factors influencing formation damage in the near wellbore area will assist the development of drilling and production methods which minimize the creating of damage, as well as improve the treatments used to remedy any damage. In this paper, we compare our experimental work of the flow through different heterogeneous media with simulation and test different parameters (permeability, miscible flow and immiscible flow) to highlight the impact upon the flow patterns and recovery. Our experimental work demonstrates particularly differences in flow and displacement behaviour between heterogeneous and homogeneous porous media. The heterogeneity under investigation is permeability contrast. In our experiments we have used visual 5-spot models packed with Ballotini glass beads. The packings have been carried out with different sized beads in selected areas to represent the heterogeneities. Our simulations have been carried out using the Eclipse numerical simulator. The experimental flow patterns resulting from the distribution of heterogeneities were successfully simulated.
Further analysis is showing how these effects can be included in the characterisation of the reservoir and improve the accuracy of the reservoir simulation. This will in turn reduce the range of uncertainty when interpreting and integrating history match, well tests and well logs.
Analytical Modelling of Cyclic Steam Stimulation Using Pseudo-Relative Permeability Function
Authors: Tamim M. , Rahman M. H. 
Published: December 2007

Abstract
Cyclic Steam Stimulation (CSS) process is a proven commercial oil recovery method in heavy oil reservoirs. In many of the heavier reservoirs, steam is injected under high pressure to create fractures at the wellbore. The changes in mass and heat transfer properties created by high pressure steam injection in the deformed shear failure zone around the wellbore have been shown to influence recovery mechanism. This work presents an analytical model, which considers the shear failure zone permeability in reservoir simulation by means of pseudo-relative permeability functions.
The pseudo-relative permeability functions have been successfully applied to an analytical predictive model which considers flow into a circular wellbore at the center of an elliptical drainage system. The simulated results obtained from the new model shows excellent agreement with previously reported results in Cold Lake, Alberta oil sand.
Microbial Enhanced Oil Recovery Pilot Test in Piedras Coloradas Field, Argentina
Authors: Maure M. A. , Dietrich F. L. , Diaz V. A. , Argañaraz H. 
Published: December 2007

Abstract
Extensive feasibility tests involving Microbial Improvement Technology were conducted with the two main productive formations in Piedras Coloradas Oilfield, Mendoza Province, Argentina. The program started March 1997 and continued during twelve non-consecutive months. Six producer wells, two of them horizontals, were under a systematic program of inoculations using hydrocarbon-degrading anaerobic-facultative microorganisms. A complete set of rheology parameters, specific geochemical fingerprints and biomarkers comparison was used to evaluate pre- and post-trial compositional alterations in produced fluids.
Project performance in terms of fractional flow evolution was correlated with well completion configuration and reservoir petrophysics by the use of parametric models and compared on a well-by-well basis with corresponding decline and complementary baselines. Incremental Oil averages 66% over baseline with minimum values of 28.5% and maximum above 110%. Results are consistent and show a clear correlation between treatment design modifications and water cut reduction. This correlation proves that Microbial Enhanced Oil Recovery methods are controllable and predictable if team integration and proper engineering methods are observed during pilot design and well monitoring stages.
Cost per Incremental Barrel (CIB) was 5.1 $/barrel during pilot stage. On MEOR Expanded scales, this value is forecast to decrease to below 2 $/barrel. The project demonstrates that this technology is cost effective, easy to implement and complies very well with local environmental regulations and biosafety issues.
This pilot program is the first part of an integral mid-term strategy to use biotechnology in paraffinic oil bearing reservoirs. Further evaluations in course will be covering microbial influence mechanisms on waterflooding methods.