bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of Simple-To-Use Predictive Tool for Rapid Prediction of n-Alkanes Surface Tension
Authors: Bahadori Alireza 
Published: December 2011

Summary
One of the most striking demonstrations of intermolecular forces is the tension at the surface of liquid n-alkanes. The prediction of surface tension is important in the design of distillation towers, extraction units, and tower internals such as bubble caps and trays because it has a considerable influence on the transfer of mass and energy across interfaces. Surface-tension data are needed wherever foaming emulsification, droplet formation, or wetting are involved. They are also required in a number of equations for two-phase-flow calculations and for determining the flow regime. Petroleum engineers are especially interested in the surface tension in the extraction of crude oil where adding surfactants to modify the interfacial properties between crude oil and the geological reservoir can improve production and increase oil yields. In this work, a simple predictive tool using Arrhenius-type asymptotic exponential function, the Vandermonde matrix, and Matlab (Matlab 2008) technical computing language is developed for the estimation of surface tension of paraffin hydrocarbons as a function of molecular weight and temperature. The surface tension is calculated for temperatures in the range of 250 to 440 K and paraffin hydrocarbon molecular weights between 30 and 250. Estimations are found to be in excellent agreement with the reliable data in the literature, with average absolute deviation being less than 2%.
Safety-Management Programs and Standardized Application Equipment Minimize Risks of Nonconventional Chemical Usage
Authors: Horaska D.D.. D. , San Juan C.M.. M. , Bonnivier B.M.. M. , Dickinson A.L.. L. , Conaway J.L.. L. 
Published: December 2011

Summary
Acrolein (2-propenal) is a highly effective microbiocide and sulfide scavenger that has been commercially available since 1960 and has been used widely in the oil- and gas-production industry. Acrolein is a liquid product supplied in and applied from specialized containers, eliminating potential releases from transfers between tanks. The acrolein containers are built to comply with international transportation regulations. This paper will cover the development of a safety-management program and standardization of application equipment that allow the usage of acrolein for applications with a risk comparable to, or in some cases lower than, that for conventional chemical products.
Standardized operating procedures, closed-system application equipment [verified by industrial hygiene (IH) monitoring], and redundant safety devices are built into the system to prevent chemical exposures or misapplications. Applications are performed by trained and certified personnel who have completed a specific competency evaluation under field conditions. A detailed and customized safety-management program is completed and implemented for each application with extensive client participation.
This paper will cover the core of the safety-management program, which focuses on developing site-specific elements, including process safety information, process hazard analysis, operating procedures, employee and contractor training, applicator competency and field evaluation, prestartup safety reviews, management of change, and emergency planning and response procedures. A safety audit program is also implemented to ensure that the completed safety management program complies with each element. Audits are conducted at the actual location during the course of the chemical application.
A strong safety-management program and standardized application system have been shown to reduce personnel and environmental risks by lowering the potential for misapplications or equipment failures. These systems have allowed successful treatment programs on numerous global production assets. To validate this, a series of case histories will be presented that highlight the best practices that enable the safe application of acrolein.
Managed Pressure Drilling Enables Drilling Beyond the Conventional Limit on an HP/HT Deepwater Well in the Mediterranean Sea
Authors: Kernche F. , Hannegan D. , Peña C. , Arnone M. 
Published: December 2011

Abstract
This paper describes the successful application of Managed Pressure Drilling on a deep exploration well drilled offshore Egypt in the Nile Delta. Building upon successful experience utilizing MPD on a HPHT jack-up well, the Operator transferred the experience across to a deepwater exploration project. This represented the first known use of MPD on a floating rig in this water depth and HPHT environment. Water depth was 1100 m, and the well was drilled to over 6000 m with BHP of 17,000 psi.
Extensive engineering, training and development of procedures were carried out prior to spud. MPD was utilized to drill four hole sections. Specific techniques were developed to handle floating drilling operations. The resulting benefits associated with MPD led to improvements in drilling performance, and eliminated many of the traditional problems faced on other HPHT wells in the area. MPD has now become an integral part of the well operating philosophy and has established new standards for drilling wells of this type.
The well was a rank wildcat with considerable pore pressure unknowns, coupled with narrow pore-fracture drilling window characteristic of HPHT conditions in the Nile Delta. MPD was able to minimize the problems faced on the well by enabling various techniques to be utilized. These techniques included the use of pressure build up analysis to quantify formation pressures, the application of dynamic flow checks, dynamic formation strength limits, and the application of constant bottom hole pressure during dynamic and static drilling fluid circulation conditions. The planning, development and execution phases of the MPD project are detailed in this technical paper.
Well Control When Drilling With a Partly-Evacuated Marine Drilling Riser
Authors: Falk K. , Fossli B. , Lagerberg C. , Handal A. , Sangesland S. 
Published: December 2011

Abstract
The Low Riser Return System (LRRS) is a method used for managing wellbore pressure during offshore drilling operations by adjusting the mud level in the marine riser by returning mud and cuttings to surface via a subsea pump in a separate conduit. It is a single mud gradient, open MPD system particularly designed for subsea drilling.
The LRRS can be used in two application modes. The first has a full riser during static conditions using conventional mud weights and the capability to lower the fluid level to compensate for the ECD effect during circulation and drilling as needed. With this technique, conventional well control procedures are used. The second technique involves using higher than conventional mud weights and lower fluid levels for both static and dynamic (circulating) operations. With this technique, modified well control procedures must be used. Both of these methods improve safety margins, allow for better pressure control, and increase efficiency for most well operations.
This paper focuses on the well control issues of drilling with a partially evacuated marine drilling riser. Two cases using data from deepwater US GoM wells illustrate how the LRRS gradient fits well inside the drilling window. Kick margins and kick detection are improved compared to conventional drilling operations, and riser margin can be achieved even for relatively deep water, which allows for safer disconnections. Improved cementing by compensating for density and ECD effects is another important result of applying this system.
We conclude that this technology can greatly improve safety in drilling of deepwater exploration and production wells as well as for infill drilling in depleted fields; enabling safe access to more reserves and improving recovery.
Offshore Underbalanced Drilling With a Closed-Loop Circulating System
Authors: Gough G. , Talbot S. , Moos H. 
Published: December 2011

Abstract
This paper reviews an offshore underbalanced drilling project in the Danish sector of the North Sea, undertaken during the summerof 2010. Two oil wells were drilled from a jack-up drilling rig, with produced oil and gas transferred to the accompanying production platform. A closed-loop circulating system was employed, to mitigate against the potential for release of gas vapours, completely bypassing the rig’s pits and shakers. Crude oil was initially selected as the drilling fluid for the reservoir section to reduce the baseline coefficient of friction and minimise the potential for emulsions. A bespoke disc-stack centrifuge was utilised to control the composition of drilling fluid injected into the standpipe by removing fine chalk solids and separating the oil from any produced water.
Underbalanced drilling was identified as an enabling technology to combat conventional drilling challenges due to variations in pressure profile along lengthy horizontal sections.
Experimental and Theoretical Study of Control Strategies for Constant Bottomhole Pressure While Drilling Oil Wells
Authors: Vega M. P. , Vieira F. R. , Folsta M. G. , Leibsohn A. M. , Gandelman R. A. 
Published: December 2011

Abstract
Well construction is a complex job in which annular pressures must be kept inside the operational window (limited by fracture and pore pressure). Monitoring bottomhole pressure to avoid fluctuations out of operational window limits is an extremely important job, in order to guarantee safe conditions during drilling job.
Several operational parameters have a direct impact on bottomhole pressure such as flow rate, rate of penetration, drilling fluid properties, etc. This way, due to the several parameters to be handled, bottomhole pressure control is a complex task and is (nowadays) a manual and very subjective job. Thus, control and automation of drilling operations is a required activity for future challenge of petroleum engineering.
This job presents the results of the implementation of a phenomenological model aiming the development of a classic PI (proportional - Integral) controller for bottomhole pressure during a drilling job. Some strategies were investigated by handling flow rate and a choke opening. An experimental unit was built to study pressure control, when the system is disturbed by an ROP steps or choke openings. Results show a non linear behavior, what requires the system investigation in different operational conditions in order to make a classic PI controller reliable. This fundamental study represents an important step in the understanding the requirements for the implementation of the drilling automation process.
Comparing the Results of a Full-Scale Buckling-Test Program to Actual Well Data: New Semiempirical Buckling Model and Methods of Reducing Buckling Effects
Authors: Mitchell S.. , Moore N.B.. B. , Franks J.. , Liu G.. , Xiang Y.. 
Published: December 2011

Summary
Buckling and its effects are topics of economic and technical interest as extended reach drilling (ERD) and horizontal wells become critical to maximizing recoverable reserves, particularly in the continental United States and Alaska. Previous work has resulted in important discoveries about drillstring buckling, but to date, little testing has been performed on actual drillpipe in a controlled manner, particularly in measuring drillstring whirl. As a result, there can be disparities between theoretical predictions of buckling effects vs. actual field results. These disparities can result in unrealistically high friction factors required to bring calculated values close to actual data, or in many cases, operational difficulties can result such as high torque, low rate of penetration (ROP), drillstring failures, inability to maintain directional control, or inability to reach the planned depth.
To learn more about drillstring behavior in buckling conditions, a full-scale buckling test fixture was developed to evaluate the effects of buckling on 2⅞-, 3½-, and 4-in. drillpipe while sliding and rotating inside 7-in. casing. The test fixture incorporated a variety of sensors and cameras to characterize torque, drag, vibration, and drillstring deformation under buckling loads. As part of the test program, low-friction nonrotating protectors were also tested to measure performance under buckling conditions.
The test results show that drillstring buckling occurs at far lower loads than predicted by current models, possibly caused by minor deformations inherent in real drillpipe. The results also show that for a given amount of torque or drag, protectors increased the available compressive load by 20 to 30% and substantially reduced vibration caused by drillstring whirl.
The test results were used to develop a new semiempirical buckling model that predicts contact forces resulting from drill-drag modeling software in which it was compared against actual data from a large number and variety of wells. The results show an ability to more accurately predict torque, drag, and vibration caused by buckling and whirl.
Petrophysics of Triple-Porosity Tight Gas Reservoirs With a Link to Gas Productivity
Authors: Deng Hui , Leguizamon Javier , Aguilera Roberto 
Published: December 2011

Summary
Petrographic work on thin sections from rock samples collected in tight gas sandstones of the western Canada sedimentary basin (WCSB) shows that the sandstones are composed of intergranular, microfracture and slot, and isolated noneffective porosities. The petrographic observations of these triple-porosity rocks have led to a petrophysical interpretation with the use of a triple-porosity model.
Tight gas reservoirs are very complex heterogeneous systems that have been evaluated in the past mostly with single-porosity models. We propose that these types of reservoirs can be represented better by triple-porosity models for more rigorous quantitative petrophysical characterization. The triple-porosity model discussed in this paper fits the petrographic observations very well, leading to a more rigorous characterization of effective and noneffective porosity.
The petrographic and core-calibrated triple-porosity model is then used for well-log interpretation of those wells when these data are not available. The result is a reasonable quantitative characterization of the tight gas reservoir that can be used for improving hydraulic-fracturing design, flow-units determination, reservoir engineering, and simulation studies. The data can be determined at room conditions and simulated conditions of net stress.
It is concluded that honoring with a triple-porosity model the different types of porosities observed in thin sections and cores leads to more-rigorous and -useful petrophysical interpretations that can be linked to gas productivity.
Coupled Facility and Reservoir Simulations to Optimize Strategies for a Mature Field
Authors: Hayder M Ehtesham , Putra Satya A. , Shammari Ahmad T. 
Published: December 2011

Abstract
It is important to employ a good production injection strategy to optimize hydrocarbon recovery from a field. Reservoir constraints on the surface facility change as the field matures. It may be economical to revise the surface facility configurations rather than retaining the initial design of the surface facility to maintain the target production level of the field as reservoir conditions change. If reservoir pressure is not sufficient to maintain natural flow, there may be need for artificial lift mechanisms to keep the well flowing. Careful analysis of interdependence of the surface facility constraints and reservoir conditions are important in designing good quality production injection strategies for these circumstances. Coupled facility and reservoir simulations allow production optimization and determination of the impact of injection or disposal policies on reservoir management. Sometimes there are oscillations in computed production rates, which may be as a result from inaccurate treatment of a coupling algorithm, well management rules, optimization techniques, etc. Excessive fluctuations make the solution impractical to implement. In this paper, we examine the cause of well rate fluctuations in coupled simulations. We were able to keep oscillation levels at a very low level in our simulations by using a small coupling interval and by revising well management rules. We made case studies with reconfiguration of surface facility designs in two large fields to examine if those designs were capable of meeting the required production targets as the reservoir conditions change with time. Surface facility models were built using a commercially available software, which were coupled to Saudi Aramco’s in-house reservoir simulator, POWERS. We examine scenarios where some facilities could be eliminated to reduce cost while maintaining required production target. We study the impact of reconfiguring the surface network and examine how surface constraints might change the overall production rate.
Three-phase Hydrocarbon Thermodynamic Liquid-Liquid-Vapour Equilibrium in CO2 Process
Authors: Lins Abel G. , Nghiem Long X. , Harding Thomas G. 
Published: December 2011

Abstract
Hydrocarbon phase behaviour must be rigorously represented when there is a need to properly account for mass transfer between phases in a porous medium. The overly simplified black-oil formulation, although appropriate for primary depletion and waterflooding, provides inadequate representation of miscible displacement processes. As a result, compositional simulation has evolved to provide thermodynamically consistent means to accurately describe the phases and compositions present within the porous reservoir rocks.
Compositional simulators have become essential modelling tools for CO2 processes in the Petroleum Industry. Advances in computational power have encouraged the development of meaningful improvements and refinements that were not possible until very recently.
CO2 injection into an oil reservoir at low temperatures causes the appearance of a three-phase hydrocarbon thermodynamic Liquid-Liquid-Vapour (LLV) equilibrium. The traditional use of a two-phase flash calculation in this three-phase region may lead to instability problems. Besides, commercial compositional simulators normally do not consider two-phase hydrocarbon Liquid-Liquid (LL) thermodynamic equilibrium that appears in oil reservoirs at low temperatures in the presence of CO2. Instead, it is treated as a Liquid-Vapour (LV) thermodynamic equilibrium and the fluid flux behaviour is not well represented. A compositional simulator must be able to represent adequately the LL hydrocarbon thermodynamic equilibrium when it is present in order to rigorously model the reservoir phase behaviour in the presence of CO2.
A novel procedure has been developed to overcome instabilities which may arise in calculation of multiphase liquid-liquid-vapour (LLV) hydrocarbon phase equilibrium. In addition, a new procedure has been developed for representing the thermodynamic liquid-liquid hydrocarbon equilibrium in a compositional simulator. This new procedure represents the real behaviour of the fluid flux. It is more rigorous than the traditional approach of lumping of the two liquid phases into a pseudo single liquid phase or as a liquid-vapour (LV) thermodynamic equilibrium. The results of this implementation are presented and analyzed in detail.
Shape Factors for Irregularly Shaped Matrix Blocks
Authors: Wuthicharn Katha , Zimmerman Robert W. 
Published: December 2011

Abstract
The shape factor that appears in dual-porosity models of single-phase flow in naturally fractured reservoirs is investigated. Previously derived analytical expressions for a few simple geometries (spheres, cubes, slabs, etc.) are first reviewed. A general numerical procedure is presented that allows the shape factor of an arbitrarily shaped block to be found using a fine-grid simulation of flow into a single matrix block with constant-pressure boundary conditions. From these various results, a scaling law is suggested that expresses the shape factor in terms of the block’s volume V, the block’s outer surface area S, and a diffusion length l. This expression is α = 5S/Vγ, where γ = V1/3 for a three-dimensional block, and γ = A1/2 for a two-dimensional prismatic block with cross-sectional area A. For all cases analyzed, this expression predicts the shape factor within an error of less than 10%. This seems to be the first accurate, general expression available for estimating the shape factors of irregularly shaped matrix blocks such as are formed by the intersection of realistic fracture networks.
Optimizing Development Strategy and Maximizing Field Economic Recovery through Simulation Opportunity Index
Authors: Abd Karim M. Ghazali. , Abd Raub M. Razib. 
Published: December 2011

Abstract
With the rapidly increasing costs of field development, one of the many challenges for any green or brown field development is to optimize the number and locations of development wells that would yield maximum sweep efficiency and recovery. A full field simulation model is generally constructed to assist in optimizing the development plans and in many occasions initial well planning is based on fixed well length, well orientation, well spacing, etc., before any iterative sensitivity runs are performed. It is recognized that in most cases, the decision was heavily influenced by a single reservoir property, such as permeability, without considering the effect of other inter-related parameters, such as movable oil volume, fluid viscosity, hydrocarbon pore volume, reservoir permeability-thickness and residual oil saturation. The need to analyze these variables in a structured and logical manner is therefore a challenge to ensure a technically sound decision making process. In this paper a modified approach, based on techniques already established (Molina et al., 2009), hereinafter called "Simulation Opportunity Index" (SOI) is introduced. It provides an innovative view on how a development strategy is addressed, and subsequently forms the basis of well placement optimization. All steps and equations to generate the desired indexes are discussed in this paper. We have successfully utilized industrial geological modeling software to perform the calculations and eventually generate the three main index properties in a 3D reservoir model. Using an in-house well planning tool, we can place new wells to optimize field development. This paper also presents a case study for a major oil field development in Saudi Arabia. Comparison between conventional approach and this modified technique clearly showed an improved field recovery performance.