bluuebunny/crossref_metadata_2025_split huggingface dataset:
Bioremediation Evaluation of Surface Soils Contaminated with Organic Compounds
Authors: Tezak James , Miller Jeffrey A. , Lawrence Alonzo Wm , Keffer Ronald E. , Weightman Robin , Hayes Thomas D. 
Published: December 2007

Abstract
Potential environmental impacts of natural gas production have become the focus of increased regulatory activity. Cost effective environmental control strategies are needed for achieving environmental protection of operating and abandoned natural gas well sites and processing facilities. The Gas Research Institute (GRI) has an ongoing comprehensive research program to assist industry in developing cost effective technologies and strategies for attaining the required level of environmental protection associated with natural gas production activities. Bioremediation is hypothesized to be a key remediation strategy.
This paper presents background information on bioremediation; information on biotechnologies that have been proven in other industries and that may be applicable to the natural gas industry; a protocol for assessing the feasibility of bioremediation; and, some preliminary results on some soils that were evaluated using the protocol. Background information related to natural gas production and processing sites and chemicals that are typically used are presented because both are important preliminary feasibility screening criteria. Applications of bioremediation to sites with similar chemicals such as refineries, wood treating plants, and former manufactured gas plants (MGP's) have been used for approximately 30 years, however bioremediation is not widely used to treat wellhead sites or natural gas production and processing sites.
Examples of applications of bioremediation to nonnatural gas industry sites are presented and the similarities, primarily chemical, are presented. The GRI developed an Accelerated Biotreatability Protocol for former MGP sites and it is currently being modified for application to the Exploration and Production (E&P) industry. The Accelerated Treatability Protocol is a decision-making framework to evaluate the potential full-scale biological treatment options. Preliminary results from some soils collected and evaluated using the protocol are presented.
Applications of Exploration Technologies to Reservoir Prediction and Management—Field Examples of South-East Asia
Authors: Duval B. C. , Allen George , Madaoui Khaled , Gouadain Jacques , Kremer Yves 
Published: December 2007

Abstract
The paper describes how modem geoscience techniques, developed for a large part in intensive exploration programs, can be used at the field level to improve reservoir prediction and production planning and also to optimize recovery.
Detailed sedimentological studies have allowed to determine the environment of the reservoir formations and help define the likely shape and size of individual sands and refine the reservoir model. An illustration is given by fields located in the Mahakam delta area of Kalimantan (Handil, Tunu) and in the Gulf of Thailand (Bongkot).
Sequence stratigraphy assists in identifying efficient regional seals which, at field scale, lead to the recomposition of a great number of individual sands (several hundreds in some cases) into fewer flow units, making the system manageable from a reservoir standpoint. This technology was used extensively to delineate the giant Peciko gas field of Indonesia.
The geophysical approach of reservoir parameters and the use of seismic attributes are rapidly expanding. The Yadana gas field in the Gulf of Martaban (Myanmar) is a case in point to show how porosities can be determined from impedances obtained by seismic inversion techniques.
An example from the Bongkot field shows how 3D seismic and direct hydrocarbon indication technology (DHI) are used to deal with complex faulting to optimize deviated well profiles and improve recoveries.
Prediction of Minimum Principal In-Situ Stress by Comparison and Verification of Four Methods
Authors: Harikrishnan R. , Hareland G. 
Published: December 2007

ABSTRACT
This paper evaluates the correlation between values of minimum principal in-situ stress derived from four different models which use data obtained from triaxial core tests or sonic logs. The first method utlilizes a normalized form of the Mohr failure envelope equation fit different lithologies. The second method utilizes sonic log data to predict Poisson's ratio which is used to calculate the minimum principal in-situ stress. The third method uses a fit to the Mohr failure envelope as a function of average rock grain size, which was obtained from detailed microscopic analyses. The fourth method uses the Mohr-Coulomb failure criterion which uses an average angle of internal friction to predict the minimum principal in situ stress. The minimum principal in situ stress values obtained from the four different methods are then compared to actual field mini-frac test data which is known to be the most accurate method to determine the minimum principal in situ stress. The cores and the mini-frac stress tests were obtained from two wells, the Gas Research Institute's (GRI's) Staged Field Experiment (SFE) #1 well through the Travis Peak Formation in the East Texas Basin, and the Department of Energy's (DOE's) Multiwell Experiment (MWX) well located west-southwest of the town of Rifle, Colorado, near the Rulison gas field.
Results from this study indicate that the calculated minimum principal in situ stress values obtained by utilizing the rock failure envelope as a function of different lithologies are in better agreement with the measured stress values (from mini-frac tests) than those obtained from the other three approaches.
An Innovative Model for Drilling Fluid Hydraulics
Authors: Merlo Antonino , Maglione Roberto , Piatti Cesare 
Published: December 2007

ABSTRACT
The hydraulic system plays an active role during drilling operations. Its proper design can accelerate the drilling effort and lower the overall well cost.
It is very important to predict the exact pressure distribution along the well and the circulating temperature distribution in the fluid.
This paper describes an innovative hydraulic computer program developed in Agip.
The program calculates the rheological parameters of drilling fluid based on the viscometer readings.
The rheological models of Newton, Bingham, Power law and Herschel-Bulkley are considered.
The program calculates also the temperature profile of drilling fluid and takes into account the temperature effect on the rheological parameters, when available viscometer readings at different temperatures.
The use of Herschel-Bulkley model and the temperature effect estimation improve the flow modelling capability during drilling fluid circulation and permits to better study and quantify the influence of hydraulic parameters, thus allowing better planning.
It will be also considered case histories with comparison of calculated and field data coming from Agip ultradeep wells experience.
Development of Coated Tubing for Oil/Gas Production in Sour Environment
Authors: Masamura Katsumi , Takeuchi Yuko , Nara Yoshihiro , Nagasaka Tetsuo , Miyagawa Tsuguo , Nakamura Arata 
Published: December 2007

ABSTRACT
To develop inside coated tubing for sour environments, a joint research program has been conducted by Japan Research and Development Center for Metals (JRCM) and Japan National Oil Corporation (JNOC). The aim of this project is to develop a cheap oil country tubular goods (OCTG) with high corrosion resistance in sour environment using new coating technology on carbon steel. Coating facilities by plasma transferred arc hard facing (PTH) process that was applied for tubing, was constructed. Developed coated tubing (5 m long x 89 mm O.D. x 76 mm I.D) and connection was manufactured and tested corrosion resistance and joint performance. Antigalling property and gas tightness is equivalent to conventional joint. Coated tubing and connection evaluated corrosion resistance in dynamic corrosion tester and field test. No corrosion damage was observed after tests. These results suggest that developed tubing and connection can be used in deep sour wells.
Stochastic and Deterministic Reserves Estimation in Uncertain Environments
Authors: Karra Sastry , Egbogah Emmanuel O. , Yang Foo Wah 
Published: December 2007

Abstract
This paper presents a comparison of stochastic and deterministic reserves estimation methods as related to the various stages of development of an oil or gas field, with emphasis on offshore environment. The current debate concerning stochastic and deterministic reserve estimates and definitions is framed with respect to the various stages of field development. Advances in technology in terms of three-dimensional seismic data and reservoir simulation appear to narrow the range of reserves estimates.
Field examples are presented to compare stochastic and deterministic reserves estimates. Stochastic methods are preferable during exploration and pre-development, while both methods can be used in practice to support the decision to proceed with development. In the later stages of development, deterministic methods become more practical as other data become available.
Advances in technology are leading to better deterministic estimates as well as stochastic estimates with narrower ranges. Practices in the industry vary from complete dedication to deterministic or stochastic to a choice of the method depending on the stage of development.
This paper offers recommendations as to which reserves estimation technique is more suitable at specific stages of field development based on data scope and availability.
Determination of the Original-Gas-in-Place and Aquifer Properties in a Water-Drive Reservoir by Optimization Technique
Authors: Chen Ta-Lin , Chen Yeong-Long , Lin Zsay-Shing 
Published: December 2007

Abstract
The purpose of this study was to estimate the original-gas-in-place (OGIP) of a water-drive reservoir using optimization algorithm for Port Arthur field, Texas, U.S.A. The properties of the associate aquifer were also obtained. The good agreement, between the results from this study and those from simulation study, would be demonstrated in this paper.
In this study, material balance equation for a gas reservoir and van Everdingen-Hurst model for an aquifer were solved simultaneously to calculate cumulative gas production. The result was then compared with cumulative gas production measured in the field that observed at each pressure. The following parameters were manually adjusted to obtain: OGIP, thickness of the aquifer, water encroachment angle, ratio of aquifer to reservoir radius, and aquifer's permeability. The procedure was then applied with simplex technique, an optimization algorithm, to adjust parameters automatically. When the difference between cumulative gas production calculated and observed was minimal, the parameters used in the model would be the results obtained.
A water-drive gas reservoir, "C" sand gas reservoir in Port Arthur field, which had produced for about 12 years, was analyzed successfully. The results showed that the OGIP of 60.6 BCF estimated in this study was favorably compared with 56.2 BCF obtained by a numerical simulator in other study. In addition, the aquifer properties that were unavailable from the conventional plotting method can be estimated from this study. The estimated aquifer properties from this study were compared favorably with the core data.
The Asia Pacific LNG Trade: Status and Technology Development
Authors: Hovdestad Wayne R. 
Published: December 2007

Abstract
The Asia Pacific Region is experiencing a period of sustained economic expansion. Economic growth has led to an increasing demand for energy that has spurred a rapid expansion of baseload liquefied natural gas (LNG) facilities in this region. This is illustrated by the fact that seven of the ten baseload facilities in existence provide LNG for markets in the Asia Pacific region. With the three exceptions having been initially commissioned in 1972 and earlier, it is fair to observe that most advances in LNG technology have been developed and applied for this market.
The paper presents the current status and identified future trends for the Asia Pacific LNG trade. Technology development in terms of application to onstream production, processing and transportation facilities, including LNG tankers, is presented. The potential of future advances to applied technology and operational practices to improve the cost-effectiveness of new and existing facilities is discussed. Current design data and methods as actually used are examined in terms of identifying where fundamental research and basic physical data are insufficient for optimisation purposes.
These findings are then summarised and presented in terms of the likely evolution of future and existing LNG projects in the Asia Pacific region.
Case Histories in the Europe/Africa Area Demonstrate Improved Capabilities of FiberOptic Video Camera Technology
Authors: Olsen J. E. , Kristensen R. , Taylor R. W. 
Published: December 2007

Abstract
Cost constraints in the oilfield restrict the performance of remedial services unless a high probability of success can be assured. Unfortunately, a method that could accurately diagnose wellbore problems in a broad scope of oilfield environments was not available, and until the 90's, accuracy of problem assessment was compromised to the point that estimates of remedial success could not be determined. During the 90's, however, a downhole video system that showed promise of providing the sought-after diagnostic accuracy for today's operational conditions was introduced to the oilfield. With the combined capabilities of fiber-optic signal transmission and downhole video camera technology, the system can now provide the oil and gas industry with a diagnostic tool that is rapidly becoming invaluable in oilfield services and is proving the worth of the old adage, "Seeing is believing."
This paper will present a brief overview of the use of the downhole video (DHV) camera technique from its first documented usage until early 1992. The enhancements that have been instrumental in enlarging the scope of its usage since that time will then be discussed. Case histories recorded by the video camera operation in the Europe/Africa area will be presented and analyzed to demonstrate usage and benefits of the system.
Horizontal Well Simulation in the Baram South Area, Offshore Sarawak, Malaysia
Authors: Raub Mohd. Razib Abd. 
Published: December 2007

ABSTRACT
The Baram ‘South’ area is a largely undeveloped fault block in the Baram Field which contains some 154 MMstb of oil.
Due to the elongated nature of the fault block, the moderately high in-situ oil viscosity of 6 cP. and the strong water drive, a horizontal well development has been identified to provide optimum reservoir development in the 14.0 sand. As a result, a horizontal well simulation study to support the requirement for horizontal wells has been carried out. The objectives of this study were to confirm the reserves and performance of the horizontal wells as compared to conventional wells and at the same time understand the key parameters that influence the horizontal well performance. Due to the lack of production history for this reservoir, in addition to no representative core and PVT data, the challenges lay in acquiring the most representative data to be used in the simulation study.
This paper describes the approach taken in the simulation; from utilising core and PVT data from neighbouring fields, establishing a geological layering based on well log correlations and finally the setting up of the simulation model and grid system. In addition, prediction runs and sensitivity studies are also discussed, which identified the key parameters that impact horizontal well recovery and performance.
The base case results confirmed the merits of a horizontal well development as compared to conventional wells. They also support the reserves, watercut and GOR performance of a horizontal well as derived from analytical calculations. However, the simulation gave new insight into the declining gross production. The sensitivity studies highlighted the need to obtain core data and fluid samples during development, for use in future simulation studies.
Structural Integrity of Typhoon Damaged Structures
Authors: Billington C. J. , Ward J. K. , Grimm David F. 
Published: December 2007

ABSTRACT
This paper concerns the integrity reassessment of offshore wellhead platforms damaged by a typhoon, the damage consisting of cracking at joints between the conductor support frames and the main jacket structures. These structures were reassessed to establish the stability and growth rates of the cracks, and the effect of the cracks on the overall stability of the conductor frames and the structures as a whole.
The structures were reanalysed using models that included joint flexibility which had a significant effect on load levels at the critical crack locations. Non-linear ultimate load analyses were carried out at selected joints in order to develop plastic collapse values for a fracture mechanics assessment of crack fracture criticality and growth rates. A series of analyses was carried out to investigate the potential progressive failure of the conductor frame supports and the effect of this on overall structural stability. Remedial measures were considered in detail including crack grinding, chord grouting, member removal and clamping.
The results of the reassessment showed that the analysis including joint flexibility predicted more accurately the crack growth rates. The flexibility considerably relieved member end moments albeit increasing mid span moments and deflections. The progressive collapse analysis showed that a rapid failure in the event of a complete member severance is unlikely and that therefore a planned programme of inspection and remedial grinding can be instituted.
This paper describes the overall assessment strategy and the detailed assessment methods used. It demonstrates the useful role of non-linear finite element analysis and fracture mechanics techniques in minimising the need for expensive underwater structural repairs.
New Findings in Low-Temperature Oxidation of Crude Oil
Authors: Mamora D. D. 
Published: December 2007

ABSTRACT
Clay and sand fines reduced the permeability of sand packs in combustion tube experiments and also provided a large reaction surface area. Consequently, residual oil saturation and hence fuel concentration increased, resulting in high-temperature oxidation (HTO). In contrast, low-temperature oxidation (LTO) resulted from low fuel concentration.
A combustion front temperature of 500°C (932°F) was obtained for HTO runs, compared to only 350°C (662°F) for the LTO run. During HTO, practically all injected oxygen was consumed, whereas during LTO, oxygen moved through the combustion front resulting in the formation of an oxygenated hydrocarbon fuel (atomic oxygen-carbon ratio of 0.3 was measured). As a result of distillation, the viscosity and specific gravity of the produced oil in HTO runs were reduced significantly. In contrast, LTO resulted in an increase in viscosity and specific gravity of the produced oil. A new method was developed to estimate the heat of reaction of oxygenated hydrocarbon fuels.
Kinetic tube experiments showed oxidation of crude oil to consist of two stages: low-temperature oxidation followed by high-temperature oxidation, with reaction peaks at about 250°C (482°F) and 400°C (725°F) respectively. Kinetic and combustion tube experimental results indicated that an oxygenated hydrocarbon fuel was formed during low-temperature oxidation. A new oxidation model for kinetic tube experiments was developed. Oxygen consumption based on the new model agreed well with experimental data.
Before implementing an in-situ combustion project, it is critical to carry out combustion tube experiments using actual crude oil, oil saturation and matrix found in the field to ascertain the type of oxidation reaction. Further, standard kinetic tube experiments may not yield the correct kinetic parameters, since fuel oxygenation is unavoidable in kinetic tube experiments. An alternative approach needs to be found to estimate the heat generated at the combustion front.
Cost Reduction Deriving From Integration of Services Thanks to Slim Hole Rig Design
Authors: Dupuis Dominique , Sagot Andre 
Published: December 2007

ABSTRACT
In respect of Slim Hole drilling, the savings deriving from the application of this technology have to be considered at the level of the well. The Slim Hole technology, thanks to the volumes of hole considered, the design requirements and the construction of a new dedicated rig, has permitted to integrate a cementation system (pumps and batch mixing tanks) an on-line waste treatment system and a comprehensive instrumentation from which are delivered the data to the different players on the rig i.e. mud-logger, driller, tool-pusher, company man. The services deriving from those components usually performed by third party's Contractor are implemented by the Drilling Contractor with its own crew. Futhermore other services like civil engineering (construction of site and roads) and transportation and mud monitoring are similarly performed by the Contractor.
Based on field experience this paper will in the first instance discuss why such globalisation is necessary by technical requirements, then will present the advantages and constraints for the contractor and the increase of risks. The analysis of cost reduction deriving from this scheme will be presented and discussed as well as the benefits for the Operator and the Contractor. The evolution in respect of competence and management of the services for the Drilling Contractor will also be outlined.
Gas Migration: Fast, Slow or Stopped
Authors: Johnson Ashley , Rezmer-Cooper Ian , Bailey Tim , McCann Dominic 
Published: December 2007

Abstract
We review the conflicting literature on gas migration velocities during kicks. We consider the laboratory and large scale test data that shows that for any local gas void fraction of more than 10%, the influx migrates at approximately 100 ft/min. We also review the evidence from field experience that shows that gas can migrate much more slowly (the typical rule of thumb suggests that gas bubbles move at approximately 15 ft/min) and in some cases remain stationary.
We show that the yield stress of the drilling mud which holds cuttings in suspension whilst making connections, can also hold gas bubbles in suspension, and report an experimental study of these gas suspension effects. Significant volumes of gas can be held in suspension during a gas kick, this trapped gas remaining stationary until the mud is circulated out of the well.
We consider the implications of this for well control operations, and present field data where gas was injected into a marine riser, it dispersed and remained stationary until circulated out. We show that a single bubble migration model, which neglects gas suspension, predicts that as the gas rises and expands it unloads the riser. By simulating the gas suspension characteristics we model the field data.
We conclude that gas in moderate concentrations (more than 10%) migrates quickly, typically at 100 ft/min. This migrating influx leaves a trail of suspended gas in the mud that remains stationary. For small kicks in deep wells the entire influx can be distributed, at a low concentration, and remain in suspension until the gas-cut mud is circulated out of the well.