bluuebunny/crossref_metadata_2025_split huggingface dataset:
Experimental Study on Applicability of Water-Alternating-CO2 Injection in the Secondary and Tertiary Recovery
Authors: Nezhad S. A. T. , Mojarad M. R. R. , Paitakhti S. J. , Moghadas J. S. , Farahmand D. R. 
Published: December 2007

Abstract
One of the problems that the world will face in the next future is the reduction of hydrocarbon reserves and the challenge in finding new resources. In recent decades, new ways to improve production methods and enhancing the recovery factor from reservoirs have been attempted.
Considering an increase in the different techniques of improving the recovery processes and the imperativeness of efficient recovery from existing reservoirs whose capacity for producing flow rates have been diminished, brings up the need for further studies and research for developing different methods to enhance oil recovery processes.
The goal of this paper is to investigate the profitability of immiscible water alternating CO2 injection in the secondary and tertiary recovery after water-flooding and continuous CO2 injection at laboratory scale. The experiments were performed in the sand packed model using dead oil sample taken from a southern Iranian reservoir at constant injection pressure (1500 psig) and constant temperature (the reservoir temperature, 190 °F) conditions.
The results indicate that the WAG process using CO2 can be efficient, especially when it is used a secondary recovery process rather than tertiary one.
Use of Amine/PHPA System To Drill High Reactive Shales in the Orito Field in Colombia
Authors: Guerrero X. , Guerrero M. , Warren B. 
Published: December 2007

Abstract
The use of water based fluids replacing oil based drilling fluids has been increasingly being applied in the Petroleum Industry in order to mainly accomplish environmental legislation.
A challenge when using water based drilling fluids in highly reactive shales is to overcome problems such as wellbore instability, torque and drag and environmental requirements. This was the case in the Orito oil field in Colombia.
The Orito field is located to the south of the country and has been operated by Petrominerales Colombia Ltd. During years of exploitation, the Orito wells were drilled with oil base muds in order to address wellbore instability problems related to the highly reactive shales of the Villeta formation, which is drilled in the 311 mm (12 ¼") hole and is about 300 m (1000 ft) long.
Some years ago, different water based mud systems have been used in the area; however, it has not achieved the high performance expected by the operator to successfully drill the troublesome Villeta formation. Thus, in order to drill the two last development wells in the Orito field, it was proposed that an Amine/PHPA system to be evaluated. The Amine/PHPA system has been developed by Q'Max Solutions in Canada and has also been used in Ecuador with very good results.
According to own experiences in the field, the Amine/PHPA system was formulated to achieve the right concentration of each mud product to satisfy the necessity of a system that provides at the same time good inhibition, adequate rheology properties and lubricantion during the angle build section.
Capillary Suction Test (CST) were carried out to determine the right concentration of amine and PHPA to provide inhibition for the highly reactive Villeta shales. Historical cases of hydraulics and operational performance were studied to find out xanthan gum concentrations to reach adequate yield point values that secure hole cleaning during the most critical deviated section of the interval and lubricant concentration was also determined to reduce torque and drag in the water based system.
This paper is intended to present the performance of the Amine/PHPA system and environmental achievements in an environmentally sensitive area. Laboratory and field data obtained during the project is also presented.
Conceptual Model Design Studies for a Self-Sustained and Complete Productive Utilization of High-Viscosity/Extraheavy-Oil Onshore Reservoir in Mexico
Authors: Ascencio-Cendejas F. , Reyes-Venegas O. 
Published: December 2007

Abstract
This paper shows the results of conceptual and feasibility studies for the design of a Self-Sustained and Complete Productive Utilization of High Viscosity-Extra Heavy Oil Onshore Reservoir in Mexico.
An onshore reservoir in Northern Mexico containing extra heavy oils (6-12 API) with extremely high viscosity (&gt;40,000 cp at 20°C) can be exploited in integral and efficient manner in a energy self-sufficient cycle by means of the proper coupling of several components or modules as: injection of CO2 – readily available in the region – into the artificial lift systems.
At the reservoir level the CO2 injection generates foamy Oil with much lower viscosity and density. On the surface the produced heavy oil can be hydrogenated to produce lighter oil with a better economic value and the residual heavy sub product can be feed to a power plant to generate the energy for the production artificial systems and the pumping or compressing equipment for pressure maintenance of the reservoir. Alternative analysis by in-situ enhancement of the oil - by hydrogenation process in the reservoir – is also included as to cover the economic aspects of this integral and energy self sustained extra heavy oil system
Thermally enhanced artificial systems and pressure maintenance of the reservoir (by fluid injection) achieved through novel and clever thermal design, operation and maintenance of the wells, pipelines and process equipment maintains the viscosity of the oil at acceptable level as to keep an efficient deliverability of the fluid to the surface as a foamy oil because CO2 injection. Hydrogenation of the oil in-situ or on surface facilities produce ultra heavy fraction that is feed to a power plant to produce all the energy required in the cycle to allow for self sustaining the field-production-processes.
A General Method for the Flow Diagnosis and Interpretation of Well Tests
Authors: Ascencio C. F. , Samaniego-V. F. , Ley H. C. , Feraud J.-P. 
Published: December 2007

Abstract
This paper presents a new technique for transient pressure analysis, based on a general diffusivity equation for any of the different coordinate systems. Essentially, this method consists in the identification of a flow exponent n for which the pressure resposne graphed in a log-log scale in terms of t1−n|p′(t)| versus t would show a horizontal behavior. It is demonstrated that the value of this exponent corresponds to the flow pattern (diagnosis; for example, linear, radial, spherical, etc., flows ), and the intercept is inversely related to the formation conductivity. For cases of highly heterogeneous formations of fractal propeties, the value of the n exponent could be different from any of the most well known exponenet values (linear;1/2; radial, 0; spherical: -1/2; bilinear: ¼; and pseudosteady state: 1).
Drilling Offshore HT/HP Wells in Environmentally Sensitive Area Using Water-Based Mud
Authors: Desai Harshit , Affes Sami , Rahman Mizan , Williams Gregg 
Published: December 2007

Abstract
Drilling an exploratory well in the lower cretaceous formation of the Krishna Godavari (KG) Basin on the East coast of India poses a host of technical, logistical and environmental challenges. The technical demands were particularly acute when designing a drilling fluid to address the ultra-HTHP environment, the lack of offset data making it difficult to predict pore pressure, low seismic resolution and the highly environmentally sensitive ecosystem. While the technical demands downhole made oil-base (OBM) drilling fluids the system of choice from an operational perspective, the location of the block near a wildlife sanctuary, posed a host of logistical problems, in addition to the exorbitant costs associated with modifying the rig to comply with zero discharge restrictions required when using invert-emulsion drilling fluids. Thus, the operator embarked on a fast-track campaign to design a water-base (WBM) drilling fluid system that would not only meet the technical demands, but also address the environmental limitations.
This paper describes the design, execution and evaluation of the water-base drilling fluids employed on two HTHP wells in the KG Basin. This authors will discuss the effective use of a specially engineered KCl/Glycol system to drill 2000m of clay stone section in the 12¼ hole and the use of a low-colloid and contaminant-resistant water-base drilling fluid to reduce HTHP fluid loss values, improve shale inhibition, increase lubricity and reduce differential sticking potential for the formation. The first HTHP well in the block was drilled to 5061m with BHP of 11,800 psi and BHST of 410°F and presented a host of well problems due to the severe drilling environment. The nature of the formation coupled with the use of WBM limited the ability to achieve the logging objectives of the discovery well.
The high performance required of the WBM was compounded dramatically when planning the second HTHP well, which was to be drilled deviated to 5710m. Based on the results of the second HTHP well, the low-colloidal HTHT water-base mud system has proved to be an ideal alternative solution to the OBM. In addition, the authors will discuss the successful application of a mechanical earth model in predicting the pore pressure and helping WBM in achieving the target of drilling the deepest and most extreme environment well ever in India.
Estimation of Average Reservoir Pressure and Drainage Area in Naturally Fractured Reservoirs—Tiab's Direct Synthesis
Authors: Igbokoyi A. O. , Tiab D. 
Published: December 2007

Abstract
Average reservoir pressure in a naturally fractured reservoir is usually computed in a similar way with that of a conventional homogeneous reservoir. However, because of the different flow regimes that exist in the pressure transient test of a naturally fractured reservoir, it is necessary to understand the implication of each flow regime on the estimation of average reservoir pressure. This work presents solution methodology for pseudo-steady state behavior of a naturally fractured reservoir under commonly identified flow regimes coupled with matrix flow behavior.
The matrix flow behaviors investigated are pseudo-steady state and transient flow in the matrix blocks. Different matrix block flow models are used to analyze the reservoir pseudo-steady state behavior. A new approach to pseudo-steady state sugar cube model is also presented and the result obtained using the new approach is compared with the Warren and Root model. Finally, Tiab's Direct Synthesis (TDS) technique is applied in the computation of the average reservoir pressure.
Drilling and Petroleum Engineering Program and Project Management at Santos Ltd.
Authors: Horton G. , Dedigama T. 
Published: December 2007

Abstract
PRISM (Plan Resource Implement Schedule Manage) is a project management toolkit developed to facilitate the field operations of the Petroleum Engineering department of Santos Ltd. for onshore Australia. It is believed that PRISM is unique in its functions when compared to other off-the-shelf project management applications. Currently PRISM enables the management of approximately 1200 projects (including in excess of 250 drill, complete and connect projects) being implemented by five major and four minor field resource types, comprising up to 20 major and 40 minor individual field resource packages that are deployed daily. These represent approximately A$450 million of activity planned for implementation in 2006.
PRISM allows real time reporting and updates to resource schedules during project implementation. It is used for near term schedule management, longer term forecasting and reporting, enabling the field resource schedules to be optimised as project scopes evolve. Unique interfaces have been developed to allow the inherent volatility of petroleum engineering operations to be managed and communicated to office and field based personnel on a daily basis.
The development of the PRISM application integrated and replaced a number of individual scheduling tools and reporting systems. It has allowed all stakeholders to better understand project requirements and status of implementation. The result has been better utilised field resources running more continuously, in conjunction with increasing work activity and complexity of downhole completions and the introduction of new technology. Scheduling performance has improved despite the increased number of projects, their scope and complexity.
A major part of the PRISM rollout process has been to gain user acceptance and encourage users to use the toolkit, both as a source of information on projects and to keep details updated. This paper also looks at the project implementation and rollout process, including barriers and lessons learned.
Superior Zonal Isolation Provided by Ultralightweight Cementing Technology Increases Profitability of Wells in Difficult-to-Cement Areas
Authors: Kulakofsky D. , Avalos A. , Hernandez R. 
Published: December 2007

Abstract
Today operators are forced to drill in increasingly challenging environments in an effort to meet a growing global demand for petroleum products. In Mexico, meeting this challenge requires more skills and innovative materials from oilwell cementing providers. Nowhere else in the world are the cementing requirements more difficult than those presented by Cantarell and other depleted zones and weaker formations present in Mexico. New ultra-light foamed cementing technology enables successful circulation and an effective seal, which can have a great impact on not only the cost of drilling a well, but on the productive life of the well. In addition to the easily quantified benefits from reduced water production, reduced remedial costs, decreased drilling days and increased hydrocarbon production, additional profitability stems from the more difficult to quantify areas such as delays in production delivery and early water production.
Traditionally, the lower limit for oilwell cementing has been 7.5 to 8.5 lb/gal. When the density of the cement slurry was reduced down to these light weights, it was still not low enough and the industry had to live with losses or attempt multi-stage cement jobs. In Cantarell, where a 7.3-lb/gal cement job was once attempted, these slurries were not light enough. Recent developments in ultra-light foam technologies have allowed the successful application of production quality foam cements delivered at downhole densities as low as 5 lb/gal.
This paper presents case histories from Mexican wells, which show how this ultra-lightweight foamed cement slurry technology was used to decrease costs and increase production, yielding more profitable wells for the operator.
Case Studies for Improving Completion Design Through Comprehensive Well-Performance Modeling
Authors: Ouyang Liang-Biao , Huang W. S. 
Published: December 2007

Abstract
Optimal completion design has been practiced over the past years through detailed well performance evaluation, and improved completion selection workflow. Six field case studies will be discussed in this paper to demonstrate the methodology to achieve the best completion design under different field and operating conditions. The focus of the field case studies covers well production prediction, well performance evaluation, optimum well length assessment, cost effective and production efficient completion strategy, skin estimate from well production history, water/gas control, impact of casing integrity, and sensitivity assessment on reservoir permeability, mechanical skin, non-Darcy skin, flowing bottomhole pressure (BHP), original oil saturation, and so on. The wells to be discussed include single, dual lateral horizontal wells, and highly deviated wells. The produced fluids include oil and/or gas and water. The most popular completion options, such as open hole, slotted liner, inflow control devices (ICD), intelligent well completions (DIACS), perforated cemented liner, wire wrapped screen or standalone screen, gravel pack, and frac pack, expandable sand screen, alternating standalone screen and blank pipe, etc, have been either applied and/or evaluated in the case studies.
Futures-Based Modeling of the Oil Price for Realistic E&P-Project Valuation
Authors: Staber Stephan 
Published: December 2007

Abstract
The net present value of an E&P-project is still the most important investment criteria in oil field acquisitions. Besides the discount rate assumption and the estimation of the strategic value of an E&P-project, the oil price assumption is the most important input parameter in E&P-project calculations. Even small variations in the oil price assumption can have large influence on the resulting project value. Therefore, for a realistic E&P-project valuation it is critical to use sophisticated methods for the estimation of the future oil price.
In the past, it was common practice to simply assume a fixed value for the long-term oil price (flat price); others use forward curves as a forecast (floating price). In probabilistic calculations (e.g. in Monte Carlo simulation) and in using the option pricing theory for valuing real options, stochastic processes are modeled. Here, the oil price is predominantly considered as to follow a Geometric Brownian Motion or a type of a Mean Reverting Process.
This paper presents an improved concept for modeling short- and long-term oil prices. The method is based on the premise that forward and future prices are the markets best guess of future oil prices. The future or forward curve is utilized as the expected value curve for the Mean Reverting Process. Thus, the oil price is modeled in a way that makes the resulting oil price assumption suitable for incorporating it in traditional net present value calculation as well as in sophisticated real option valuations. On the one hand for the discounted cash flow method it is critical to use reasonable short- and long-term values for the oil price, on the other hand for real options valuation it is necessary to model the oil price stochastically. The presented improved method fulfils both basic requirements and is therefore a strong improvement to common E&P-project valuations.
Dual Purpose Reversible Reservoir Drill-In Fluid Provides the Perfect Solution for Drilling and Completion Efficiency of a Reservoir
Authors: Ali Syed , Luyster Mark , Patel Arvind 
Published: December 2007

AbstractIdeally, a reservoir drill-in fluid (RDF) possessing both an oil external phase for drilling and a water external phase for completion would provide the ideal solution for drilling and completing a well. Through the manipulation of surfactant chemistry, a novel reversible invert emulsion drilling system, which provides both attributes, has been developed. During drilling, an operator can utilize the reversible oil-based mud to take advantage of the commonly accepted properties that enhance the drilling efficiency and then convert this system to a water-based fluid to improve the completion efficiency.The amine-based surfactants used in the reversible invert system are strong emulsifiers in an alkaline medium; however these same emulsifiers become more common direct oil-in-water emulsifiers in the presence of protonating agents such as acid. This process of protonation and deprotonation of emulsifiers controls the emulsion phase of this drilling system and thereby, the oil-wetting and water-wetting characteristics of the subsequent filtercake and entrained solids. As the bridging agents in filtercake are commonly calcium carbonate, once water-wet (in presence of acid) promote clean-up and thus, are readily consumed by common acids that may be utilized during the completion phase.This system was field trialed with success for drilling and completing an injector in the first quarter of 2000. Since this initial application, numerous completions have utilized this reversible invert RDF system. This system has been successfully applied to a variety of completions, in particular: injectors and producers, openhole gravel-packs (OHGP), expandables and standalone as well as various environments and reservoirs. Theoretically, this system also provides advantages with respect to common cementing and environmental issues.This paper presents the development of this multi-purpose drilling and completion system and discusses the application of this technology to adapt to the challenges of evolving global completion complexity.Several case history examples are presented from selected completions. The paper includes the laboratory pre-planning and field data illustrating the concerns and the development of a solution with respect to drilling and clean-up.
Developing Heavy-Oil Field by Well Placement-A Case Study
Authors: li Pan You , Hong Luo Hui , Sharara Abdel Mageed , Naganathan Sivaraman 
Published: December 2007

Abstract
Fula is a heavy oil field located in Muglad basin in Sudan. Aradéiba reservoir in the field consists of highly heterogeneous sandstone that is thinly bedded, unconsolidated, bearing typical heavy oil. Bentiu reservoir is composed of massive sandstone, unconsolidated and traped very high viscous oil. Production performance of vertical wells indicates that the reservoirs are facing problems of low productivity, bottom water conning and sand production. In his circumstance CNPCIS set itself a daunting task of tripling the production in less than a year.
Horizontal wells were considered as best option for improving the productivity in this small to medium sized heavy oil field, and controlling the sand production due to low drawdown pressure and increased exposure the reservoir.
This paper discusses about comprehensive geological study, identification of target oil pools, well design, selection of fit for purpose technologies and the complete well placement cycle including detailed analysis on the drilling and steering challenges while placing horizontal well through reactive shales and channel sand environmentThe paper also discusses about various completion strategies, the results of well placement, value of using new technology, lessons learnt and cost/production analysis.
Team work, communication, knowledge sharing and deployment of fit for purpose technologies has resulted in a five fold increase in production through horizontal wells compared to vertical wells with no sand production. The paper illustrates how integration of different disciplines led to successful well placement, enhanced production with sand and water management in heavy oil environment.
Auto, Natural or In-Situ Gas Lift Systems Explained
Authors: Vasper Adam 
Published: December 2007

Abstract
The terms auto, natural or in-situ gas-lift all refer to artificial lift systems that use gas from a gas bearing formation to gas-lift a well. The gas-lift gas is produced downhole and bled into the production tubing via an auto gas-lift valve designed for gas operations.
The value of auto gas-lift is probably easier to demonstrate than for other types of intelligent well because it provides a direct replacement for conventional gas-lift equipment, compressors, pipelines and the ancillary equipment they require.
An estimated 60 auto gas-lift systems have been installed at the time of writing this paper, most of them in the Scandinavian sector of the North Sea. Several papers have discussed this technology but, so far, none have presented a rigorous analysis or solution of the wells’ production from a gas-lift perspective.
This paper presents the basic theory behind auto gas-lift and how to apply it. The components of the theory are well known and commonly used in Nodal analysis and conventional gas-lift design. Properly combining these components allows an auto gas-lifted well's performance to be calculated and downhole equipment to be correctly sized and located.