bluuebunny/crossref_metadata_2025_split huggingface dataset:
An ICA Approach to Purify Components of Spatial Components of Seismic Recordings
Authors: Haghighi Arash Moaddel , Haghighi Iman Moaddel 
Published: September 2008

Abstract
Decomposing linear mixtures or superpositions into their components is a problem occurring in many different branches of science, such as telecommunications, Seismology, and biomedical signal analysis. Blind source separation (BSS) in particular, deals with the case where neither the sources, nor the mixing matrix or process of mixing are known, the only available data are the mixed signals. The standard approach to BSS is Independent Component Analysis (ICA).
In fact ICA is a statistical technique that represents a multidimensional random vector as a linear combination of nongaussian random variables - ‘independent components’-that are as independent as possible.
In 3D seismic surveys involved in exploration operations, recorded time series in each dimension are taken to be independent in nature and behavior, which is a direct result of physical response of materials into which seismic waves penetrate. But as an observation one dimension is sometimes contaminated up to one fifth by information from another dimension, resulting an increase in SNR.
Here we have applied FAST-ica algorithm to a 3D seismic record sample to extract least dependent recordings for all three spatial dimensions. In order to test the reliability of the decomposition we used mutual information (MI) transfer between signals to confirm the result of outputs from FAST-ica algorithm as, least dependent components, leading to more accurate interpretations of petrophysical parameters.
The Art of Mentoring As Told by Both Sides of the 3-Decade-Old Struggle in the Petroleum Industry
Authors: Edwards J. T. , Woo G. T. 
Published: September 2008

Abstract
Along with the dramatic price changes in the petroleum industry including gas and oil, there is one resource that has been seriously overlooked and undervalued: experienced personnel in the field, including engineers and other technical specialties. The real challenge is how this lack of experience is overcome in the short term, rather than just waiting for the passage of time. The petroleum industry can make significant gains quickly by investing in true, on the job mentoring. It could mean the difference between success and failure. Companies could be focusing less on headcount, and more on effective and well organized mentoring programs.
The shifts in supply and demand over the past three decades have at times left many within the technical side of the industry barely holding onto their jobs or looking at other vocations in order to maintain employment. Hoping to ride out the waves of boom and bust, those with valuable experience are not passing on their knowledge at a rate that can sustain our industry. These trends have led many colleges and universities to back away from true Petroleum degrees. Now that a demand is increasing again, how can the voids be filled quickly in the field with qualified and well-trained personnel, while the slow process of ramping up academic programs begins?
The only way to fill the void is through hiring from other engineering fields along with the inclusion of like-minded individuals with technical backgrounds. But now that they have been hired and are on the job, how can we maximize their success? The answer is mentoring. This paper will present the case with a personal perspective as told by mentors in the petroleum industry on both sides of the struggle, spanning three decades.
Improving Well Safety and Maximizing Reserves Using an Innovative Surface Controlled Subsurface Safety Valve (SC-SSSV)
Authors: MILLET François , PETIT Hervé , WALLEZ Gery , LALANNE Philippe , DUCASSE Alain , BARZU Emile 
Published: September 2008

Abstract
A common cause of failure with surface-controlled, subsurface safety valves (SC-SSSV) is a defect in the down-hole hydraulic line, which controls the valve from the surface. Such a failure generates production losses and requires the intervention of a costly workover rig - usually not immediately available. In order to alleviate this type of situation, a system has been developed where the physical control line has been replaced by a communication system based on electromagnetic waves. The surface emitter continuously sends a signal to the SC-SSSV. Both items are designed to be fail-safe. The normally-closed valve remains open while receiving the signal and closes as soon as the signal is lost. This innovative, control-line free, wireline-retrievable SC-SSSV can be set in any landing nipple profile or anywhere in the tubing using monobore lock technology without a workover or well head modification.
The primary application is to secure wells with a damaged or blocked control line, damaged landing nipple, or wells completed without an SC-SSSV. It provides an immediate cost-effective solution - allowing production to resume with a surface-controllable safety barrier while avoiding or postponing a costly workover. With the arrival of this technology, sub-standard and temporary solutions, such as the normally-open velocity and ambient valves, no longer need to be considered. Another application is to free up a hydraulic SC-SSSV landing nipple in order to install a device like a capillary string for chemical or gas injection at the bottom of the well safely.
A prototype has been built and successfully tested for six months in a flowing gas well with 15% H2S – the case history is presented. The tool has proven to be easy to install and reliable. Deployment will start in 2008. Thousands of wells are concerned around the world.
This breakthrough slickline product offers new possibilities for safely and efficiently managing the countless failures of hydraulic SC-SCSSVs. Its versatility brings a reduction in production losses and provides the user with a cost-effective and reliable solution.
Dynamic Buckling and Snaking Motion of Rotating Drilling Pipe in a Horizontal Well
Authors: Gao Guohua , Miska Stefan 
Published: September 2008

Abstract
This paper is focused theoretical and experimental study on the dynamic buckling and the snaking motion of rotating pipe in a horizontal well. Firstly, a comprehensive dynamic buckling model, a group of fourth order non-linear partial differential equations were derived and discussed. Then, a perturbation solution of the model was obtained, which represents the snaking motion of the rotating pipe. Based the perturbation solution, critical dynamic buckling load and dynamic behavior of rotating pipe were analyzed. It has been found that there are two different kinds of snaking motion. One type is that the pipe moves up and down around its static buckling configuration. The other is that the pipe moves from one to another side of wellbore.
The authors also conducted experimental study with a small scale experimental facility. Depending upon axial compressive load and rotating speed, different motion patterns of drilling pipe were observed. Measurements of axial load at both ends and axial displacement at the loaded-end are recorded. Theses observations and measurements provide us with very important information about the dynamic behavior of rotating pipe in a horizontal well. Observations also show that the pipe may take two different patterns of snaking motions. Both critical static buckling load and dynamic buckling load were measured with this facility. Both theoretical and experimental results showed that the pipe rotation does not affect the critical load of sinusoidal static buckling and snaking dynamic buckling. Experiment also showed that there exist two different snaking motions, which support the analytical solution of the dynamic model presented in this paper. The results are useful for practical design applications related to calculating buckling loads, selection of BHA elements and pipe rotational speeds.
Hydraulic Fracture Feasibility, Design, On-Site Supervision and Post Job Evaluation in Southeast Pakistan Gas Fields
Authors: Lolon E. P. , Quirk D. J. , Enzendorfer C. K. , Bregar U. B. , Shah S. Q. , Mayerhofer M. J. , Cipolla C. L. 
Published: September 2008

Abstract
This paper presents the results of a fracture feasibility and design study, treatment execution and post treatment evaluation for a hydraulic fracture campaign in the Sawan and Miano Gas fields, located in the Sindh Province, Pakistan. This first successful fracture campaign (in four wells) was conducted from December 2005 to July 2006. One well is located in the Miano and three wells in the Sawan gas field targeting the Lower Goru B and Lower Goru C sands at depths of about 3,300 m. Several injection tests and minifracs prior to the main treatment were performed to quantify closure stress, fluid leakoff, perforation friction, near-wellbore tortuosity, and fracture complexity. Issues such as formation water sensitivity and fines migration are discussed. High reservoir temperature, proppant flowback issues and risk of fracing into a water transition zone are some of the challenges faced during the fracture campaign. A variety of fracture design sensitivities were performed to evaluate the effects of pad size, treatment size, fluid and proppant types on fracture geometry, conductivity and gas production.
In the Sawan, fracturing was found to be simple as opposed to more complex fracturing in the Miano area. Permeability ranges from low 0.06 mD to moderate 8 mD in the four fractured wells. Treatment designs were adjusted accordingly to minimize screen-out risk and maximize fracture stimulation efficiency. To help reduce proppant flowback into the wellbore, partially cured, resin-coated proppant was pumped at the end of the treatments. A low-polymer loading, high-temperature, CMHPG fracturing fluid was used due to a high-temperature reservoir. This type of fluid provided high fluid viscosity for proppant transport while also minimizing polymer damage to the proppant pack. The fracture campaign has successfully increased the gas production by two to four folds.
Revised Big Bore Well Design Recovers Original Bayu-Undan Production Targets
Authors: Ledlow L. B. , Gilbert W. W. , Omsberg N. P. , Mencer G. J. , Jamieson D. P. 
Published: September 2008

Abstract
The Bayu-Undan gas recycling project is located north of Australia, in the East Timor Sea and is designed to produce 1,100 MMscf/D of wet gas, strip out 110,000 B/D of condensate/LPG, initially reinject 950 MMscf/D of lean gas, and later export up to 700 MMscf/D of lean gas to a LNG plant in Darwin. The initial development called for 16 North Sea-style, 7 in. monobore wells (11 producers and 5 gas injectors).
By May of 2003, it became apparent that the original well design would not achieve the 1.1 Bcf/D production target because of well construction problems. Three wells on the remotely located wellhead platform were abandoned because of wellbore instability. Without the production contribution from these wells, the first year's production target would not be met. To meet the production targets, a complete well redesign was undertaken. First, the tubing was upsized from 7 in. to 9-5/8 in. Then semi-openhole completions with pre-drilled liners and openhole packers were selected instead of the conventional cased and perforated design to reduce installation time. Finally, oil based drill-in fluid was selected to provide lubricity, temperature stability, and low liftoff pressure of the filter cake for rapid cleanup.
Utilizing the Big Bore design, the production capacity of +1.1 Bcf/D and injection capacity of 1.1 Bcf/D was achieved in June of 2004, ahead of schedule. The well count was also reduced from 16 to 12 wells (8 producers and 4 gas injectors.) Two producers had capacities in excess of 300 MMscf/D, and three gas injectors had injection capacities in excess of 350 MMscf/D. The increased production resulted in 19 MMstb of condensate/LPGs produced in the first year, some 7-8 MMstb more than would otherwise have been the case.
History Match and Reserve Evaluation of Hydraulically Fractured Wells: Low Permeability Field Case History
Authors: Colombo I. , Fanello G. , Valzania S. , Isella D. , Tealdi L. 
Published: September 2008

Abstract
Due to the production decline of mature fields, the possibility to drain low permeability formations became recently of great interest in the Congo basin. Some of these reservoirs can produce at economic rates only if massive hydraulic fracturing jobs are performed. In the Congo off-shore environment, the capital expenditure associated to such kind of interventions can be critical. It follows the need to accurately identify the candidates, and then properly design and model such hydraulic fractures in order to have sound production profiles for economic evaluations.
Accurately modeling hydraulic fractures and mid-long term production profiles of slanted fractured wells can be extremely challenging.
Analytical methods can be misleading in estimating production profiles of hydraulically fractured wells due to multiphase flow and the reservoir heterogeneity.
The paper describes the successful history match process for highly deviated wells with pre and post frac production history in Kitina 3A oil field.
The static and dynamic 3D model is calibrated with dynamic data with a step by step approach, starting with the data gathered in the prefrac production history. Different criteria to establish cuf off are tested in order to properly describe the reservoir net pay.
The post frac data give insight into fracture properties. A huge effort has been made in order to properly modeling both hydraulic fractures geometry and conductivity in a consistent way with the data obtained with the treatment interpretation. The hydraulic fractures are described in a full field 3D model using refined grids around the wells and tuning the grid dimensions in order to have both production accuracy and acceptable run time. History match process gives indications that fracture conductivity may differs significantly compared with the value of the frac job interpretation. In addition post frac history match is improved greatly by the knowledge of formation permeability through for example well test interpretation. On the base of the experience gathered on the simulation of such wells, some general guidelines are drawn for a wider application.
Casing Ultradeep, Ultralong Salt Sections in Deep Water: A Case Study for Failure Diagnosis and Risk Mitigation in Record-Depth Well
Authors: Zhang Jincai , Standifird William , Lenamond Chris 
Published: September 2008

Abstract
The deepest well drilled to date in the Gulf of Mexico, the Well #1 discovery well in Green Canyon, required setting casing in a 15,000 ft thick section of tectonically active salt. After casing collapsed in the initial wellbore, a comprehensive model was developed to characterize wellbore stability, salt creep mechanism and implications for well design, and mitigation options for future well construction.
To facilitate the construction of models characterizing the interaction of casing and salt, the regional pore pressure and in-situ stress setting was analyzed. This analysis revealed that pore pressure in this area shows a significant regression in the subsalt formations. This pore pressure regression, if not accurately predicted, can lead to significant problems with the wellbore including wellbore breakouts and drilling fluid losses. The combined challenges of open-hole wellbore instability, salt creep, and casing damage made well design and construction very difficult.
In this paper, models are utilized to replicate wellbore instability, salt creep and the interaction of halokinesis, wellbore geometry, casing stress, and drilling fluid hydrodynamics. The modeling reveals that casing failure was caused primarily by non-uniform contact of salt on casing thereby generating stresses that exceeded the yield strength of the lightweight casing. The same model showed that heavier casing could withstand identical, non-uniform stresses if loading was diametric and not axial. The model was used to prepare an optimized drilling program that mitigates the risk of non-uniform application of stresses by salt and non-uniform application of slip loading. Recommendations included under-reaming in the slip zone, the use of drilling fluid of appropriate composition, and cementing practices that improve the stress distribution on the casing. Further, after setting casing through the salt, relatively high mud weights were required to avoid a large differential between internal and external loading on the casing. High mud weight had implications for wellbore stability in open-hole while drilling the subsalt sections to reach the reservoir. Modeling predicted accurate in-situ stresses and pore pressures that were utilized to drill a bypass well that successfully reached an unprecedented depth of 34,189 ft.
Both analytical and 3-D elasto-plastic finite element methods (FEM) were applied to analyze casing failure mechanisms, coupling the effects of in-situ stresses and mud pressures with the overburden. The methods were also applied to analyze mineralogic parameters that influence salt creep. The modeling process is applicable to essentially all Gulf of Mexico extended-reach wells to be drilled through salt sections.
Identification of Bypassed Pays in Low-Resistivity, Thinly-Bedded, Sand-Shale Sequences in the Ghdames Basin of North Africa Through Use of the Wireline Formation Tester
Authors: Chu Wei-Chun , Welch Paul M. 
Published: September 2008

Abstract
This paper presents a discussion on the use of the Wireline Formation Tester (WFT) to identify oil-bearing intervals in a reservoir section that contains thinly-laminated, low-resistivity pay sections in the Ghadames Basin of southern Tunisia. Pay zones previously bypassed by conventional log analysis have been conclusively determined as oilbearing through use of the tool.
Three field examples are discussed on the use of the Downhole Fluid Analyzer (DFA) to determine hydrocarbon type and in-situ GOR for three different hydrocarbon phase environments.
The paper also discusses, again through use of field examples, how analysis of the post-DFA pressure response could be used to determine zonal producibility. This zonal producibility from the WFT is then compared to conventional well-test productivity. A close agreement exists between the WFT and conventional well-test productivity estimates. Thus, it eliminates the need for zones to be conventionally tested to determine productivity.
Finally, the paper provides a method to significantly reduce the time necessary to collect representative fluid samples through proper monitoring of the DFA data stream.
Scatter Search for Optimizing the Formation-Rate Analysis (FRA) Model
Authors: Li Baoyan , Georgi Dan , Wu Jianghui 
Published: September 2008

Abstract
The Formation Rate Analysis (FRA) method applies the multivariate linear regression method to invert pressure test data to estimate formation parameters. This method is simple and works well if the measured pressure transient noise is small. However, if the noise is large, errors in the estimated formation parameters are unacceptably large.
To solve this problem, we present a multi-scale scatter search optimization method. The basic idea of this optimization method is to iteratively generate sampling points using Hammersley random sequences in regions of various sizes in the parameter space. A reference data set is generated from the candidate optimal solutions and then used to filter the generated sampling points. The uncertainty of the calibrated formation parameters is quantified based on the searched valid optimal solutions.
We test this algorithm with formation test data from low permeability, high permeability, and tight formations. Its accuracy, efficiency, and reliability are validated. We also compare it with the original FRA method. The test results show that:
compared with the linear regression method, this algorithm more accurately estimates the formation parameters, particularly for the tight formation; compared with the direct Monte Carlo method, this new algorithm more efficiently provides calibrated formation parameters and quantifies more accurately the associated uncertainties; for high permeability formations, the estimated uncertainty of the calibrated formation pressure is very small; for tight formations, flow-line fluid compressibility can be effectively calibrated. However, the short length of the measured pressure transient results in a large uncertainty in the estimated formation pressure and mobility. Also, the mean value of the formation pressure is underestimated if the pressure transient is far from being stabilized.
Potential Microbial Enhanced Oil Recovery Processes: A Critical Analysis
Authors: Gray Murray R , Yeung Anthony , Foght Julia M , Yarranton Harvey W 
Published: September 2008

AbstractThis paper summarizes a critical review of possible microbially enhanced oil recovery (MEOR) methods and mechanisms to identify the most plausible utilization of microbial technology to enhance oil recovery. This paper is intended to stimulate discussion about broad applications of MEOR to field-wide improvement of oil displacement and recovery.The potential benefits of different MEOR mechanisms were examined for a representative North Sea reservoir of sandstone containing a light crude oil. In each case, the material input requirements for nutrients and inoculum were calculated in relation to the projected incremental oil production, assuming that the key components (bacteria, nutrients, or bacterial products) were uniformly distributed in the swept zone of the reservoir.The capillary number for the reservoir suggested that incremental oil recovery by biosurfactant production in situ would be modest under ideal conditions. The achievable yields would be lower because the Microbiol. in the reservoir would not be controllable to achieve sustained surfactant production. Losses of biosurfactants by adsorption to reservoir rocks and in situ biodegradation would further limit performance. The stimulation of surface active bacteria in the reservoir may affect the flow of fluids by producing emulsion droplets of oil coated with bacteria. The formation of a biofilm at the oil water interface changes the rheology of the interface, and may provide a useful mechanism to control mobility and areal sweep in reservoirs. Any mechanisms that required changes to large volumes of reservoir material, to produce gases, solvents, acids, or to significantly alter permeability, were not considered to be feasible. The limiting case of plugging fractures with bacteria and their polymeric byproducts does have considerable potential, but only for reservoirs which offer significant improvements in production with minimal injected volumes. The biological deposits must retain longer term resistance in situ to ensure that the anticipated production increase is achieved.This study provides a methodology for the systematic assessment of MEOR proposals using well-established reservoir engineering principles.