bluuebunny/crossref_metadata_2025_split huggingface dataset:
Relative Permeability of Gas-Condensate Fluids: A General Correlation
Authors: Bang V. , Kumar V. , Ayyalasomayajula P. S. , Pope G. A. , Sharma M. M. 
Published: December 2007

Abstract
Predicting production from gas-condensate wells requires an accurate relative permeability model when a condensate bank forms. At high flow rates typical of many gas-condensate wells, the relative permeability is rate dependent. Such rate dependence can be modeled using a capillary number to calculate the decrease in residual saturations and the corresponding increase in relative permeability as viscous forces become dominant over the interfacial forces. New steady-state relative permeability data have been measured over a wide range of capillary numbers including very high values corresponding to the near-well region. These measurements have been made on several reservoir rocks as well as outcrop rocks and over a range of temperature, pressure, connate water saturation and hydrocarbon composition typical of gas-condensate reservoirs. PVT data of gas-condensate fluids can be used to predict the ratio of the gas to the condensate relative permeability and this simplifies the measurements and modeling since only data corresponding to the pressures near wells are needed. A relative permeability model developed at the University of Texas was tested using both new data and data from the literature. With only one parameter set, essentially all of the data for all rocks and conditions was fit within experimental uncertainty.
Using Downhole Real-Time Data To Estimate Zonal Production in a Commingled-Multiple-Zones Intelligent System
Authors: Sun K. , Konopczynski M. R. , Ajayi A. 
Published: December 2007

Abstract
Intelligent well technology provides the ability to monitor well bore data (e.g. down-hole pressure/temperature) in real time through down-hole sensors, and to control fluid flow into or out of the wellbore at each segment. However, integrating these real-time data into a reservoir management work flow and turning the data into measurable and tangible value is still an elusive and complex task.
This paper proposes a technique of integrating down-hole realtime pressure and temperature data to predict and allocate multiphase production in a multiple zone intelligent well system. The technique combines the known position of the installed zonal Interval Control Valves (ICV), measured realtime pressure and temperature data, available production data, and reservoir fluid properties, to estimate the production rate of each zone using customized ICV choke performance models.
In order to account for the impact of phase behavior on the prediction, fluid systems have to be corrected to the prevailing in-situ flow conditions. In light of this, an improved multiphase choke model for down-hole ICV is introduced in this study.
To demonstrate this technique, one example of a hypothetical two-zone intelligent well completion with multi-phase production is illustrated. The example shows how to use the surface production data, e.g., GOR, WOR, API, Gas S.G., and real-time gauge data with the multiphase choke model to predict production of each phase through the ICV.
4D Pressure Pilot to Steer Well Spacing in Tight Gas
Authors: Quint E. , Singh M. , Huckabee P. , Brown D. , Brake C. B. , Bickley J. , Johnston B. 
Published: December 2007

Abstract
Obtaining reliable and accurate formation pressures in micro-Darcy rock has been a formidable challenge for tight gas producers. However, it is these pressures that give the most unambiguous data to identify unique reserves. They help to determine the drainage areas as well as appropriate well spacing for tight gas reservoirs.
A 4D pressure pilot was designed and installed to measure pressure drop at two observation wells equipped with pressure gauges. The pressure gauges enable pressure monitoring along the wellbore (in space) and over time, hence the name 4D pressure pilot. Two wells were drilled with one in the maximum horizontal stress direction (aligned with the hydraulic fracture azimuth) and one perpendicular to this orientation. Each well was placed at approximately 660 ft from an existing producing well, corresponding to a conventional 10-acre pattern. Twenty pressure sensors were distributed over the 6,000 ft productive interval. One well showed significant depletion in the majority of the sands whereas the other displayed very little depletion.
This pressure data together with open-hole and production log data, core data, and geologic models was used to construct detailed static and dynamic models. The resulting history matched models were used to evaluate numerous well densities and patterns. This formed the basis for the two wells per quarter quarter section application for the center of the field, which was approved by the Wyoming Oil and Gas Conservation Commission. Similar data gathering activities have been initiated in other parts of the field to formulate a comprehensive, field-wide spacing plan.
Gauge configuration was designed to collect daily pressures in numerous sands without compromising future production. Combining existing systems offered by two contractors into an integrated package mounted external to the casing enabled us to acquire this data, while still allowing for hydraulic-fracture completion and normal production in the future when monitoring objectives were met.
Obtaining pressure data with dozens of permanent gauges is expensive, but we are convinced that given the significant impact on estimating gas in place, recoverable gas, drainage area and ultimately well spacing, it is cost effective.
Analytical Solutions for Compositional Three-Phase Four-Component Displacements
Authors: LaForce T. , Jessen K. , Orr F. M. 
Published: December 2007

Abstract
The goal of this paper is to obtain by the method of characteristics (MOC) analytical solutions for compositional paths in one-dimensional, dispersion-free flow of four components, when up to three flowing phases may be present. The method is applied to an idealized quaternary system that exhibits a large region of three-phase behavior in order to study the effect of compositional four-component, three-phase flow on hydrocarbon recovery.
Injection of water and carbon dioxide (CO2) into a porous medium containing decane (C10) and methane (CH4) is considered. Two phases may be present in the initial reservoir composition or the injection mixture. The majority of each composition route remains in ternary subsystems defined by the initial and injection compositions, with a shock connecting the two ternary subsystems. As a consequence, a C10 bank is always produced prior to water or CO2 breakthrough.
Water, CH4, and C10 are produced for an extended time before CO2 breakthrough when less than 26% CO2 is injected for the parameters used. The delay in CO2 production is a promising result for both CO2 storage and enhanced oil recovery (EOR). Conversely, if more than 26% CO2 is injected then the hydrocarbons are pushed by a gas bank. Hydrocarbon recovery is studied for a variety of injection and initial oil mixtures. Finally, analytical solutions are compared to finite-difference simulations to study the sensitivity of these complex displacements to numerical dispersion.
How To Establish a Mathematical Model for the Electrostatic Desalting Process Based on Pilot Plant Studies
Authors: Alves R. P. , Oliveira R. C. 
Published: December 2007

Abstract
For the control of any process it is essential to establish a mathematical model capable to correlate the operational and free variables to the respond variables. Experimental studies conducted at a lab pilot plant with different Brazilian crude oil showed that the performance of the electrostatic desalting process can be simulated by using a semi-empiric mathematical model. After an intermediate validation step, the results obtained from this model were used to determine the proper treatment conditions of several offshore desalting plants installed in Campos Basin – Rio de Janeiro, Brazil. The present work shows how the proposed mathematical model was established and its correlation with the data taken from the pilot plant for different crude oils in the range of 15° API up to 30°API. Finally it is shown the correlation relating the data obtained from the proposed model and others collected from processing plants installed in different refineries and offshore production systems.
Scaling Analysis of the Migration of CO2 in Saline Aquifers
Authors: Hesse M. A. , Tchelepi H. A. , Orr F. M. 
Published: December 2007

Abstract
CO2 storage in saline aquifers may be used to reduce greenhouse gas emissions. After injection the CO2–plume migrates along the top of the aquifer for hundreds to thousands of years. An estimate of the area invaded by the CO2–plume is of interest for site selection. During plume migration, CO2 is trapped as residual gas in the wake of the plume. Reduction of the mobile CO2 volume by residual trapping would limit potential leakage.
Plume evolution can be divided into an early stage, where the CO2 has invaded the full thickness of the aquifer, and a late stage where the plume has spread enough to occupy only the top part of the aquifer. In the early regime we choose local variables for the dimensional analysis, to obtain a scaling law for the tip position xtip ∝ t1/2. At late time we choose global variables, obtaining a new scaling relation, xtip ∝ t1/3. Numerical simulations confirm the change in scaling for the tip position.
We also discuss the effect of residual trapping on plume migration. We present semi-analytic results for a plume spreading in a horizontal aquifer and numerical results for a plume in a sloping aquifer. In the horizontal aquifer plume volume decays as a power law, so that the efficiency of residual trapping decreases with time. In the sloping case initial power law decay is followed by ever faster decrease in volume.
The change in scaling for the CO2 front has not been discussed before. This change from t1/2 to t1/3 scaling shows that the plume will spread significantly slower at late times, suggesting that the plume will stay more confined than early measurements would indicate. Residual trapping will be very effective in sloping aquifers, and may be the dominant trapping mechanism.
Imaging Seismic Deformation Induced by Hydraulic Fracture Complexity
Authors: Maxwell S. C. , Waltman C. K. , Warpinski N. R. , Mayerhofer M. J. , Boroumand N. 
Published: December 2007

Abstract
Microseismic mapping is extensively utilized in the Barnett Shale, to map hydraulic fracture complexity associated with interactions of the stimulation with pre-existing fractures. Previous studies have indicated a fair correlation between the well performance and extent of the seismically active volume. However, in addition to this measure of the extent of the stimulated fracture network, the characteristics of this fracture network is also expected to impact the well performance. In particular, the fracture spacing is believed to be important factor controlling the potential gas flow. In this paper, we utilize the density of the total seismic moment release (a robust measure of the microseism strength) as an indication of the seismic deformation that may correlate to the fracture density. The study uses a set of microseismic maps of hydraulic fracture stimulations, including cases where the stimulated reservoir volume measured by the extent of the seismically active region poorly correlated with the well performance. Incorporating the seismic moment density to assess the fracture density with the network extent, an improved correlation with the well performance was observed.
Successful Application of Six Key Elements in Integrating People and Technology Toward Quality Achievements of Angsi Field Development Team
Authors: Abd. Karim Rahimah , Shaufi Dahlan M. , Noordin Khairul Annuar , Noor Harun M. 
Published: December 2007

Abstract
Angsi is an integrated oil and gas development project in offshore east coast of Peninsular Malaysia. It is one of the biggest oil producers in Malaysia, contributing one-sixth of the total national daily oil production. During its planning and execution stages, the project has had many successes and positive outcomes. It has been recognized as the model of success for all domestic and international operations in PETRONAS Carigali Sdn. Bhd. (PCSB).
The uniqueness of achievements in Angsi project relies on the successfulness of integrating its people and technology. With the recent skyrocketing oil price, the trend has been to chase for additional reserves and maximize crude production, and make it happen by whatever means possible (new technologies, joint ventures, aggressive recruitments etc). However, many projects failed to achieve these targets, despite being equipped with niche and advanced technologies.
Angsi project has successfully overcome these obstacles. The secret relies in the six key elements that have been nurtured in the working culture of every team member, which are; People, Focus, Integrated Approach, Planning, Communication and Feedback Loop. With this unique culture, it has allowed the team to achieve major successes over the past 5 years.
Among those is the successful implementation of the largest platform-based hydraulic fracturing program worldwide, and first in Malaysia. This allows the development of 0.5 Tscf gas from the otherwise uneconomic tight gas reservoir. The team also managed to increase its reserves level 2.5 times from its initial size. Consequently, it increases Angsi's daily production rate from 65 to 115 Mstb/d. Finally, Angsi project successfully reduces its unit development cost (UDC) by 67%, lowering it from 5.1 USD/boe to 1.7 USD/boe.
This paper discusses how the six key elements have contributed to the successes of Angsi Field Development Project.
Field Success in Carbonate Acid Diversion, Utilizing Laboratory Data Generated by Parallel Flow Testing
Authors: Nasr-El-Din H. A. , Chesson J. B. , Cawiezel K. E. , Devine C. S. 
Published: December 2007

Abstract
In order to treat the total interval in an anisotropic, heterogeneous carbonate formation, acid diversion is necessary. Many diverting agents are commercially available which will plug higher permeability portions of the formation and divert the acid treatment to lower permeability zones. For an oil-productive reservoir solid diverting agents such as wax beads, benzoic acid flakes, or polymers are used. Several problems may be associated with the use of these diverting agents: 1) too much additive may be used which may result in a severe reduction in acid injectivity and diverter may be very difficult to remove after the treatment; 2) flow may not be diverted from one zone to the other, but, rather, flow is equalized between the high permeability zone and the low permeability zone.
Recently, viscoelastic surfactants have been used in acid treatments for diversion.1-3 The viscoelastic surfactant contains neither solids nor polymer so clean up is of no concern. The appropriate concentration of surfactant is determined by laboratory flow testing of formation cores under reservoir temperature conditions.2
A parallel flow set up has been constructed which allows independent monitoring of flow parameters for a higher permeability and lower permeability formation core pair. Data demonstrate, through pressure analysis and effluent volumes, that flow is diverted from the higher permeability core to the lower permeability core, until acid break through occurs. Pressure data are confirmed by acid effluent volumes which are collected at regular time intervals throughout testing. In all cases, the effluent volume through the lower permeability core is greater than through the higher permeability core. Core plugs are photographed and imaged by the CT-scan technique before and after testing. Parallel flow testing has also been applied to stage treatments in which a stage of stable foam of viscoelastic surfactant in 2 wt% KCl is injected prior to the main acid stage. Appropriate surfactant concentrations in the foamed stage are determined by flow testing with formation cores.
The results of core diversion testing and fluid rheology testing of both the foamed and non-foamed viscoelastic surfactant diverting fluids are discussed. Field case histories of the application of acid treatments, which are designed on the basis of laboratory generated data, are reviewed.
Feasibility Study of Managed-Pressure Drilling with Automatic Choke Control in Depleted HP/HT Field
Authors: Iversen F. , Gravdal J. E. , Dvergsnes E. W. , Nygaard G. , Gjeraldstveit H. , Carlsen L. A. , Low E. , Munro C. , Torvund S. 
Published: December 2007

Abstract
Drilling wells in depleted reservoirs is often characterised by a narrow operating window between formation pore pressure and fracture pressure. Drilling High Pressure High Temperature (HPHT) wells into a narrow margin reservoir is even more challenging, and Managed Pressure Drilling (MPD) techniques may be required in order to operate within safe limits.
Managing the annular pressure profile during MPD operations requires a robust and reliable drilling control system. The presented work treats some challenges and possibilities regarding a MPD choke control system under evaluation for a planned HPHT well in the Kvitebjørn Field in the North Sea. Here pressure management is to be achieved by regulating the choke opening and thereby compensating for downhole pressure variations.
Methodologies for automatic choke control during the drilling operation are assessed. A dynamic fluid flow model is used to calculate well pressures for application in the choke control algorithms, and to simulate pressure response in the well. The performance of choke control during drilling operations is evaluated and results from simulations are presented.
The Continuous Circulation System—From Prototype to Commercial Tool
Authors: Calderoni A. , Brugman J. D. , Vogel R. E. , Jenner J. W. 
Published: December 2007

Abstract
This paper follows the evolution of the Continuous Circulation System (CCS™) from the prototype to the first models available for commercial application. It reviews the mechanical and control system changes introduced following the prototype trials to make the CCS more user friendly and mechanically reliable. It also discusses the approach of the constructor to the introduction of the system to the drilling industry and its determination to provide reliable and fit for purpose equipment.
Utilisation of the CCS could significantly change the way that drilling operations are carried out in certain "difficult to drill" formations. The ability to maintain uninterrupted circulation while making connections with jointed drillpipe is of considerable benefit when drilling formations where there is a narrow margin between fracture pressure and pore pressure gradients. With continuous circulation a steady ECD can be maintained and the positive and negative pressure surges, associated with making a connection under normal drilling conditions, avoided. Improved hole cleaning and the elimination of connection gas kicks can also be achieved.
Performance Appraisals of Gas/Oil Separation Plants
Authors: Kokal S. , Al-Ghamdi A. 
Published: December 2007

Abstract
Produced crude oil is typically processed at wet crude handling facility (WCHF) or a gas oil separation plant (GOSP). Most of the crude is commingled with water and produced in the form of emulsions that are separated at the GOSP using demulsifiers. In general, the emulsions at the inlet of Saudi Aramco GOSPs are tight and no free water is observed in the feed stream. In spite of the tightness of the emulsions, the demulsifier costs per barrel of produced oil in Saudi Aramco are one of the lowest in the world.
This paper describes the performance appraisal of several Saudi Aramco GOSPs. It also discusses the evaluation of these facilities and the efforts undertaken to reduce and optimize the costs of oil-water separation. The most important effort was the characterization of emulsions from various fields. It shows the relative tightness of emulsions and the associated causes of tightness. It has become a diagnostic tool in the quest to understand the causes and treatment of emulsions. The inlet emulsions were characterized by conducting field tests at each of the GOSPs using fresh emulsion samples. The factors associated with the tightness of emulsions include the amount of fine solids such as asphaltenes and scales in the crude, watercuts, temperature, brine chemistry, and shear. Another aspect of oil-water separation investigated was the effect of processing equipment and vessel retrofitting. These included the conversion of two-phase (gas-liquid) separators into three phase (gas-oil-water) separators, installation of coalescer packs, demulsifier injection strategies and use of online analyzers. An innovative approach to optimizing oil-water separation is described. The paper provides invaluable operational experience and many ‘lessons learned’ are applicable to other crude oil treating facilities.
Technical Specialists or Business Managers: The Choice Being Made by Young Professionals at the Beginning of the New Millennium
Authors: Tealdi L. , Etkind J. , Bruni T. 
Published: December 2007

Abstract
Survey results indicate that the majority of todays young professionals (YP's) are keen to consider cross-disciplinary moves within their company and look forward to a future in management positions. They often perceive the "technical professional" career as second class with respect to the managerial one. This is a significant obstacle to the optimum functioning of any organization considering that a solid technical background is at the heart of any successful career in any technical business, especially in the E&P sector. New oil and gas reserves are becoming more and more challenging to discover and the basins in which the discoveries are occurring are geographically isolated, environmentally sensitive, and require technology that has yet to be developed. At the same time, the industry technical leaders who drive these projects forward against all odds are aging and are expected to retire within the next ten to fifteen years. As the next generation of E&P industry workers strive to maintain technical focus while harboring managerial aspirations, the industry itself is struggling to define its development expectations for them.
This paper reviews various historical efforts to equalize the technical and managerial career tracks such as the dual career ladder. Three surveys of young professionals working around the world are presented, analyzed and discussed. YP's aspirations are juxtaposed against corporate and industry needs to highlight their incongruity. This paper highlights the importance of greatly enhancing the attractiveness of the technical career track in order to bring the industry workforce goals back in line with corporate goals and provides the next generation of industry workers with some insightful career advice.
Finally, strategies will be proposed to restore balance and possibly erase the perceived distinction between managers and technical professionals with the final objective of maximizing companies' performance over the long term.