bluuebunny/crossref_metadata_2025_split huggingface dataset:
Viscoelastic System as an Alternative to UBD for Drilling a Severely Fractured Limestone Reservoir
Authors: Blanco J. , Ocando D. , Lanza A. , Rendon R. , Rodríguez F. , Caligiore A. , Acosta J. , Carrero N. 
Published: December 2007

Abstract
This document presents the drilling operations protocol designed to reach a depleted limestone carbonate reservoir, located in the Borburata Field in Southern Venezuela(Fig 1), with the use of a new viscoelastic fluid developed by PDVSA Intevep. This limestone reservoir has a very low pore pressure (about 3.0 ppg equivalent density) and it is characterized by vugular porosity and micro-fractures. Previously, when drilled with conventional fluid systems, severe fluid losses occurred; therefore, the best available alternative was Under Balanced Drilling (UBD)1. However, UBD service was a heavy burden on the drilling costs and represented a more complex and risky operation than using a conventional drilling fluid system. In order to have an alternative to UBD, a water-base viscoelastic fluid system was designed to avoid fluid losses in an adverse environment of very high overbalance (about 3,000 psi), very high temperature (about 300°F) and variable pore size due to the presence of vugs and microfractures. Viscoelastic drilling fluid systems have been used because they have excellent fluid loss control properties. However, for this application, the commercial viscoelastic fluids available did not comply with the extreme conditions found in this reservoir. A new formulation specifically designed for these severe conditions was proposed, tested in the laboratory, and evaluated in the field. It resulted in the elimination of fluid losses and allowed the access to this complex reservoir without requiring the UBD service. This result represents significant savings when compared with previous wells drilled in the same reservoir.
Downhole Fluid Analysis and Sampling Establishes Compositional Gradient in a Deep Water Gas-Condensate Reservoir
Authors: Seth G. , Zope D. , Deka B. , Ghosh B. , Joshi S. , Kundu D. 
Published: December 2007

Abstract
The paper demonstrates how to establish a compositional gradient in Dhirubhai-26 (MA) retrograde gas-condensate reservoir situated in a deep water territory of KG Basin, India, with the help of real-time Downhole Fluid Analysis (DFA).The reservoir consisted of an oil rim sandwiched by a large gas cap and bottom water. Very low contamination samples were captured downhole, using a Wireline Formation Tester (WFT), in Single Phase PVT bottles. This success was achieved through the combined use of DFA results, PVT data and a tuned Equation of State (EoS).
PR Peneloux (T) EoS was tuned to the PVT data and used to populate the PVT properties of the reservoir. The resultant fluid composition versus depth was correlated to the DFA results to verify the EoS simulated compositional gradation. Subsequently a reliable GOC was established using the combined result of WFT pretest derived gradients, PVT property derived gradients and saturation pressure curves. Establishing the existence or non-existence of compositional gradient and reservoir compartmentalization in this reservoir were key prerequisites for the formulation of an optimum Field Development Plan (FDP) and estimation of the associated financial implications.
The methodology adopted in this paper is applicable to any gas-condensate reservoir that exhibits similar PVT properties. It would help to evaluate a more accurate in-place reserve estimate and reduce the reservoir risk, which in turn would lead to an optimum FDP (that would maximize the oil recovery and returns).
The paper highlights the value of wireline conveyed DFA tools and latest wireline sampling methods coupled with a tuned EoS for an accurate PVT description of complex reservoir fluids. It can not only detect the presence of compositional gradients at an early time but also help refine the PVT model to establish the gradation in composition, thus providing a cost-effective solution for deep water ventures.
Conflicting Views: CO2 Corrosion Models, Corrosion Inhibitor Availability Philosophies, and the Effect on Subsea Systems and Pipeline Design
Authors: Marsh J. , Teh T. 
Published: December 2007

Abstract
This publication examines the influence of different corrosion models, corrosion availability philosophies, corrosion control philosophies and standards on materials selection and corrosion allowance design criteria for subsea systems and pipelines. These differ enormously from operator to operator and national authority to national authority. The result is that for the same nominal environmental conditions, pipeline and subsea systems designs can vary enormously, depending on who is the client and where the facility will be situated. Also, it results in designs that would be deemed as entirely acceptable for operation in one area of the world, but which would be considered as unsafe for operation in another.
This publication discusses the nature of these influences, and the effect on subsea system materials selection and corrosion allowance. It also discusses the conceptual conflict between what can be designed for in theory, and what experience tells us has actually been achieved in practice. Finally, it discusses the approach that Ionik Consulting would take in formulating solutions to these issues.
Integration of Pore Pressure/Fracture Gradient Prediction Methods and Real-Time Annulus Pressure Measurements Optimizes Drilling in Deltaic Environments
Authors: Greenwood Jeremy A. , Abdallah Mohamed 
Published: December 2007

Abstract
Pore pressure and fracture pressure prediction represent one of the largest challenges in drilling in deltaic environments. They place constraints upon the design and ultimately on the cost of a well. They can also be a source of significant amounts of non-productive time in the drilling operation. Inaccurate estimates of formation pressure can significantly increase the costs of a well — from over-engineering the well design, taking kicks, differential sticking, and lost circulation, to losing hole sections.
The pore pressure and fracture gradient prediction model described in this paper has been applied in numerous wells drilled in deltaic environments, both on and off shore and in ultra deep water, with outstanding success.
Using a balanced stress strain algorithm not dependent on geologic age or burial environment, an accuracy that is better than ½ ppg can normally be achieved. Utilizing pressure while drilling (PWD) measurements alongside the pore pressure/fracture pressure prediction provides both a method of verifying the pore pressure and fracture pressure predictions and managing the drilling fluid static and dynamic pressures. Such information also provides an improved method of optimizing many aspects of the drilling process.
This paper will compare the pore pressure/fracture gradient methodology utilised here to other commonly used pore pressure methodologies and will illustrate the development and calibration of the model within an actual deltaic environment. The benefits achieved through the integration of these models with real-time PWD measurements, in optimizing the drilling process, will also be described. Finally, the latest developments in downhole sensor technology which may further improve this process will be discussed.
Effect of the Visco-elasticity of Displacing Fluids on the Relationship of Capillary Number and Displacement Efficiency in Weak Oil-Wet Cores
Authors: Wenxiang Wu , Demin Wang 
Published: December 2007

Abstract
In the past, the elasticity of the displacing solution was not considered when the influence of capillary number on displacement efficiency was studied. Recent years, the theory that the visco-elasticity of flooding fluid can increase displacement efficiency has been gradually accepted, but the present research level can not quantitatively describe the effect of elasticity on elasticity. In this paper, the first normal-stress difference was used to characterize the elasticity of polymer solutions, the influence of capillary number on displacement efficiency and residual oil saturation after flooding by different visco-elastic polymer solutions is studied through experiments on weak oil-wet artificial homogeneous cores. Also, at the same capillary number, the influence of the visco-elastic property of polymer solutions on displacement efficiency and residual oil saturation is studied. A set of curves of capillary number versus displacement efficiency after flooding by different visco-elastic polymer solutions is obtained. The results show that the capillary number and visco-elasticity both influence the displacement efficiency and residual oil saturation. Under conditions of same capillary number, the higher the visco-elasticity of the polymer solution, the higher the displacement efficiency, the lower the residual oil saturation, the visco-elasticity of polymer solution can significantly increase recover efficiency and lower residual oil saturation.
From "Forget It, It's Illegal," to "Yes, but…": The Saga of Carbon Underground Storage Regulatory Framework
Authors: Garland Emmanuel 
Published: December 2007

Abstract
Marine underground storage of Carbon dioxide (CO2) is now recognized as one of the techniques which could significantly reduce CO2 emissions. It has not always been the case. Five years ago it was uncertain whether a consensus could be reached or not on a realistic regulatory framework for offshore application.
Carbon capture and storage slowly emerged from other alternatives. Opponents moved from refusal to acceptance on conditions: having failed to have the proposal rejected on the grounds that marine underground storage of waste material was illegal, some opponents still use safety and environmental arguments against the concept, and require exorbitant characteristics and guarantees with a view to make that technique uneconomical or impracticable. Industry managed so far to pass the message to the regulators to ensure a favourable outcome, but there is still a long path to go.
In its second part, the paper describes current international legal status: it includes the London Convention on the Prevention of Marine Pollution by Dumping of Wastes and Other Matter (LC72) and its 1996 Protocol thereto (both instruments are valid, but in different countries), OSPAR, the regulating body for the North-East Atlantic (which includes the North Sea), and the European Union which is supporting several projects on this issue but has not yet taken a formal definitive position on it.
Integrated Property and Fracture Modeling Using 2D Seismic Data: Application to an Algerian Cambrian Field
Authors: Ouenes A. , Klepacki D. , Royer T. , Boufrioua A. , Mouhouche E. , Hamoud M. , Djermouni K. , Harhad H. 
Published: December 2007

Abstract
The use of 2D seismic lines to derive integrated 3D reservoir models remains a major challenge for the E&P industry. The use of 3D seismic in developing 3D reservoir models is well established, but there remain areas where 3D seismic is rare and 2D seismic lines are abundant. This paper describes a unique workflow that fully utilizes the data available in the 2D seismic lines. The first step in the workflow is to interpret key seismic horizons and use them in inversion and spectral imaging. The second step consists of interpolating the 2D seismic attributes over the entire field and creating pseudo-3D seismic cubes. The third step consists of using the various pseudo-3D seismic cubes to derive 3D geologic and fracture models. The fourth step is to use the derived models in a reservoir simulator to verify the validity of the models and to design reservoir management strategies to optimize recovery
This workflow was applied to a complex fractured field in Algeria which produces from a Cambro-Ordovician reservoir. Twenty-one 2D seismic lines were used in the project to derive a new structural interpretation and to create three pseudo 3D seismic attributes. These seismic attributes were used as input in REFRACT™, Prism Seismic fracture modeling software, to create geologic and fracture models. The resulting porosity and permeability models were input in the Eclipse™ reservoir simulator software. Ninety percent of the well performances were matched, confirming the reliability and accuracy of the derived geologic and fracture models and the usefulness of the workflow.
Dynamic Modeling of Multiple Regionally-Extensive Reservoirs Using a Unified Fluid Description
Authors: Dindoruk Birol , Al Kindi Azhar 
Published: December 2007

AbstractA novel approach to perform basin scale compositional simulations for a group of Gulf of Mexico reservoirs has been conducted. The main objective of such an effort has been to integrate reservoirs with potential dynamic communication through a single sensible initialization model in the simulator. In the past, some of these reservoirs were modeled stand alone, and the current information has forced us to connect multiple reservoirs that are connected laterally. Performance of three Gulf of Mexico (GOM) reservoirs was assessed using basin-wide compositional dynamic simulation approach. Like many reservoir simulation projects, at the initial phase of this project, "isolated" performance prediction of the subject reservoirs was considered, mainly due to unknown lateral connectivity and the differences in the discovery dates. In later years, there was a need to predict the unified system performance based on surveillance data, and to be able to test the possibility of the connectivity of the multiple reservoirs and reservoir segments.In addition to the surveillance production data, we have also gathered data based on basinwide analysis and geochemisty that focused on reservoir compartmentalization. Such data confirmed well responses and helped us to initialize the reservoir correctly. Along with the analysis of the particular case to be discussed here, the reasons behind the graded oil/gas reservoirs will also be discussed and will be provided to highlight the broader implications of field observations as well as some of the ideas presented in the literature.
Generation Y in the Oil Field: Are We Ready?
Authors: Rajan Surya 
Published: December 2007

Abstract
Often known as Net Generation, MyPod Generation, Millenials, etc., the latest crop of oilfield workers is characterized by a much higher level of technology simply growing up than earlier generations ever experienced in a lifetime of training and professional experience. Born in the 1980s through the end of the millennium, this generation grew up with cell phones and IMs, MySpace and iPods, and during their impressionable years bore witness to the first Gulf war, September 11th bombings, and then the second Gulf war.
Oilfield work culture is often described as "traditional". Early adoption of most technologies – particularly in terms of electronic communications – tends to be dampened by common oilfield factors such as anti-trust and anti-competitive concerns, financial controls, and general security practices.
We lag in terms of encapsulating field operational knowledge into computerized automation packages ready for handover to the thumbs seasoned on Nintendo controls. In the R&D centers we’re still not rich in 3-D visualizations and touch-screen control centers. External instant messaging is usually blocked. Technology aside, Generation Y workers are aggressive and result-focused, ready to step up as our peers. Our ability to attract and retain talent in the oilfield may very well be hampered by our stodgy image. Our approach towards adoption of technology has been pragmatic, heavily influenced by hard short-term economics. The drivers may be turning more strategic than ever before. As we face harder E&P challenges, technology development and adoption is becoming an imperative. Leaders and executives in the oilfield will have to understand the changing face of the workforce, and steer cultural shifts to not just open jobs for Generation Y, but embrace their potential and allow them to bring explosive productivity to the oil industry in partnership with expert veterans of the industry.
The analysis presented here explores shaping influences and determinant characteristics that distinguish Generation Y. Based on that, needs of that workforce segment are compared with the state of the oilfield and the remainder of its workforce, arriving at recommendations strongly rooted in partnering and relationships.
A CO2-Rich Gas Well Test and Analyses
Authors: Xu Q. , Weir G. , Paterson L. , Black I. , Sharma S. 
Published: December 2007

Abstract
This paper reports on the planning, operation, results and analysis of a carbon dioxide (CO2) well test performed on Buttress-1, a CO2-rich gas well located in the Otway basin, Victoria, Australia. A field-scale study of CO2 sequestration is planned by the Australian Cooperative Research Centre for Greenhouse Gas Technologies (CO2CRC) in this area, which will involve, inter alia, taking CO2 from the Buttress reservoir and injecting it into a nearby depleted gas field. Understanding the production characteristics of the well and gas initial in place of the field is important to the success of this project. Testing comprised of a multiple rate test and extended drawdown test in order to determine general well and reservoir characteristics, such as the well deliverability, the non-Darcy coefficient and the average reservoir permeability and volume.
The well test operations were challenging, as there have not been many instances where CO2 wells have been flow tested in the past. Hydrate formation, flow assurance, and environmental concerns, such as noise control, soil contamination, and safety level of CO2 were considered in the operation. Operations were completed successfully with no incidents and the required data were obtained successfully.
Compared to the wealth of experience developed over many years in testing oil and gas wells, the collective experience in CO2 well testing is limited. The distinguishing features between this test and those of a typical natural gas well test need to be emphasised. Although, in general, flow testing a CO2 well should be similar to testing a natural gas well, differences in the thermodynamic properties of CO2 affect the analysis of the well test considerably. In particular, the non-Darcy effect can be more pronounced and the wellbore and surface flow can involve dramatic phase changes, such as the formation of ice. In addition, since CO2 is more compressible than a typical natural gas, the accurate measurement of the flow rate becomes more challenging. It is also apparent that the use of pseudo pressure, as opposed to simpler methods of dealing with the pressure dependency of key properties, is essential to the successful analysis of the pressure response to the CO2 production.
Laboratory Testing of Downhole Gas Separators
Authors: Bohorquez R. , Ananaba V. , Podio A. L. , Lisigurski O. , Guzman M. 
Published: December 2007

Abstract
The objective of this paper is to provide insight on the design of downhole gas separators based on laboratory studies of various designs. A downhole gas separator, also known as a gas anchor, may be installed below the pump to separate free gas from the produced liquid. The gas that is separated downhole is produced through the casing-tubing annulus and the liquid is produced through the tubing. Unfortunately inefficient gas anchors are common and an acceptable guide for their optimum design does not exist.
Laboratory testing of downhole gas separators has been ongoing since January 2005 at the University of Texas at Austin using an instrumented full scale model of a wellbore and separator constructed with clear acrylic pipe to visualize the fluid mechanics of the separation process. An air and water mixture is injected through the well's perforations. The air and water flow rate measurements are used to measure and define a performance plot of each separator design. Both continuous and intermittent flow conditions were applied in the tests. The separator designs that were tested differ in entry port configuration, size of dip tube and relative position of the separator with respect to the well's perforations. Based on the results of the tests, a new separator design that includes the effect of centrifugal forces to separate the gas and liquid phases was developed.
The results show that, for the conditions in the laboratory, 100% separation was achieved whenever the entry ports were located 1 to 2 feet below the bottom-most casing perforation. The entry port geometry does not appear to have a significant impact on the separator efficiency as long as sufficient flow area is present. The efficiency of all gravity driven separators was limited by the liquid velocity inside the separator annulus. When the liquid velocity inside the separator averaged approximately 6 in/s or less, an almost to complete gas separation was achieved. On the other hand, the centrifugal separator had a liquid capacity 70% greater than any of the gravity driven static downhole gas separators.
Reservoir Management Challenges of the Terra Nova Offshore Field: Lessons Learned After Five Years of Production
Authors: Haugen E. , Costello J. , Wilcox L. , Albrechtsons E. , Kelly I. 
Published: December 2007

Abstract
The paper describes reservoir management challenges during the first 5 years of the production from the Terra Nova oil field, located offshore Newfoundland and Labrador, Canada. The purpose of the paper is to share lessons learned in the appraisal strategy, data monitoring, subsurface modeling and production management of this subsea/ floating, production, storage, offloading (FPSO) development. The material covers appraisal history, reservoir description, production history, reservoir monitoring, reservoir management, lessons learned and future challenges.
The paper will discuss the need for a balanced approach regarding development and delineation of the resources. Since there is no gas export from Terra Nova or any of the Grand Banks fields, surplus gas has to be re-injected. The Terra Nova depletion plan requires that the production from the water injection region and the gas flood regions be balanced for optimum pressure management. The relative richness of the injection gas from the Terra Nova production process has the potential to create miscible gas-oil conditions. We will discuss how slim tube experiments and compositional tracking of the fluids have demonstrated benefits to the oil recovery by operating the gasflood at a reasonable pressure. The Terra Nova field lies not only in a harsh environment but also in an immature, low infrastructure area. This has led to additional challenges regarding reservoir management and future development.
Production behavior and history matching have shown that seismically defined fault blocks are transmissible rather than sealing. The presence of leaky faults is beneficial for oil recovery, but presents challenges for precise reservoir simulation modeling and history matching. Terra Nova has extensive amount of data from bottom hole pressure gauges, wireline formation pressures (e.g. RFT/RCI), water cut trends GOR trends, gas tracers, etc. The paper discusses how these data have been integrated in the reservoir management process. Various history matching approaches will be discussed; both manual history matching and assisted techniques (experimental design).
This is to the best of our knowledge the first SPE paper from the Grand Banks oil province that describes integrated reservoir management challenges particular to this region.