bluuebunny/crossref_metadata_2025_split huggingface dataset:
ANUMET: A Novel Wet Gas Flowmeter
Authors: Falcone G. , Hewitt G. F. , Lao L. , Richardson S. M. 
Published: December 2007

Abstract
Wet gas metering is rapidly establishing itself as a special problem area within the more general area of multiphase flow metering. In fact, while attempts are being made across the Oil and Gas Industry to define the boundaries between humid gas, gas-condensate and high GVF (gas volume fraction) multiphase systems, a few commercial wet gas meters are already available for specific field applications.
A major interest of Imperial College has been the development of metering schemes for three-phase (oil-gas-water) flows in oil-field production systems. Imperial College has already developed a flow meter (MIXMETER)1, which performs satisfactorily in the range of gas volume fractions of 0 to 90%. Imperial College has therefore been recently developing a new concept (ANUMET), which shows some promise for measuring two-phase flows at much higher gas volume fractions.
The technical description of the ANUMET wet gas meter is outlined in this paper. Preliminary experiments on this new metering concept have been carried out with air-water flows in a 32 mm diameter tube in the LOTUS (LongTUbeSystem) facility at Imperial College. Encouraging results have been obtained and they are presented here.
Job Change Practices Of Petroleum Engineers
Authors: Bragg Daniel M. 
Published: December 2007

Abstract
Labor turnover, or job change, of petroleum engineers has long been a vexing problem for managers in the oil and gas industry, especially in major firms, and no easy solution has yet been found. During the summer of 1979, a large sample of SPE members was surveyed to gather data related to career paths and job satisfaction. The goal of the study was to gain a better understanding of the importance of various intrinsic and extrinsic job factors and the role they play in keeping engineers with one company longer.

Introduction
During the past few years, especially since the OPEC oil embargo of 1973–1974, there has developed a new dynamism in the oil and gas industry as firms have shifted their business strategies in response to the new demands of the times. One effect of these new demands and shifts has been an increase in the rate of formation of small "independents" in the industry, who compete with the "majors" for the limited supply of petroleum engineers. This has resulted in an increase in the flow of engineers from the majors to the independents, prompting a growing concern on the part of the majors as to how to stop this "brain drain."In early March 1979, the Education and Professionalism Committee of SPE asked Texas A and M University if it would consider undertaking a study of the job change patterns or career paths of practicing petroleum engineers who were also members of the Society.
Compaction, Subsidence, and Associated Casing Damage and Well Failure Assessment for the Gulf of Mexico Shelf Matagorda Island 623 Field
Authors: Li X. , Mitchum F. L. , Bruno M. , Pattillo P. D. , Willson S. M. 
Published: December 2007

Abstract
This paper discusses analyses undertaken to address well failures at the Matagorda Island 623 field in the Gulf of Mexico shelf. All of the 17 development wells producing the main reservoir have experienced some form of well failure or casing damage during the past 16 years of production. A comprehensive review has been undertaken and a suite of studies conducted to determine the root cause of the failures, and to predict well life of existing wells and new in-fill wells. Based on the study, practical advice is presented that was applied in recent replacement wells. The particular merit of this paper is that it covers field problem case histories, advanced analytical approaches, and practical measures for implementing prediction results.
Producing Stress-Resistant High-Temperature / High-Pressure Cement Formulations through Microstructural Optimization
Authors: Mueller Dan T. 
Published: December 2007

Abstract
The economic success of a well construction is contingent upon establishing zonal isolation within the cemented wellbore. The concentration of stress within a wellbore produced by temperature/pressure fluctuations, hydraulic fracturing/perforating operations, dynamic forces imparted during drilling, formation compaction, etc. can result in the mechanical disruption of the cement sheath. These effects are amplified in a high-temperature high-pressure (HTHP) well environment. As such, managing, minimizing, and mitigating zonal isolation loss under HTHP conditions is the focus of considerable research efforts within the ranks of both operators and service companies.
This paper describes cement systems exhibiting very high tensile and flexural strength values in a HTHP curing environment. These stress-resistant systems are produced by simple addition of coarse (100-mesh) silica sand into the slurry design. The coarse silica serves to direct the fracture propagation along a tortuous path within the cement matrix, producing a non-linear fracture path compared to the essentially linear fracture pattern observed in conventional HTHP cement containing fine silica.
This paper introduces the general concept of mechanical property enhancement of a well cement by taking advantage of the interfacial transition zone (ITZ) produced within the set cement matrix. The ITZ serves to direct the fracture path in such a manner as to spend the applied fracture energy over a greater distance within the cement matrix. Such fractures are also wider than those produced in fine silica – cement matrices.
Analysis of Tensile Strength Test Methodologies For Evaluating Oil and Gas Well Cement Systems
Authors: Heinold Thomas , Dillenbeck Robert L. , Bray Windal S. , Rogers Murray J. 
Published: December 2007

Abstract
Efforts to produce better annular isolation for oil and gas wells resulted in the development of methods to quantify the induced stresses that may occur within the cement sheath of a well. Along with the ability to calculate induced stresses in a cemented annulus, is the realization that typically, if there are sufficiently induced stresses to cause a mechanical failure of the set cement, failure will likely be of a tensile nature. While the ability to predict the compressive and the tensile stresses likely to be induced in a cemented annulus is certainly a step forward for the ability to provide better fit for purpose cementing designs, it also tends to highlight a larger challenge. Specifically, even though the American Petroleum Institute (API) and the International Organization for Standardization (ISO) established recommended methods for the testing of oil and gas well cement compressive strengths, no similar standards currently exist for the testing of the tensile strength of oil and gas well cements. Without the ability to test an oil or gas well cement tensile strength in an accurate and repeatable manner, it becomes very difficult for design engineers to utilize induced stress data to determine if a given cement system possesses sufficient tensile strength to resist the induced tensile stresses.
This lack of standardized tensile strength testing has led the oil and gas industry to adopt various tensile strength test methods that were originally developed for the construction concrete industry. The authors have used many of these different tensile strength test methods and devices in their own work. They discovered that very often, a cement system can yield widely different tensile strengths when tested with different procedures. In this paper, the authors review the basic construction concrete tensile tests most commonly used in the oil and gas cementing industry, and then analyze the tensile strength results obtained with the different testing methodologies. Correlations are developed between the tests that allow design engineers to better compare cement systems when the subject slurries have been tested with different tensile strength test methods.
Reconciling Time-Lapse Seismic and Production Data Using Streamline Models: The Bay Marchand Field, Gulf of Mexico
Authors: Vasco D. W. , Datta-Gupta Akhil , He Zhong , Behrens Ronald , Rickett James , Condon Patrick 
Published: December 2007

Abstract
One of the goals of reservoir characterization, particularly in mature reservoirs, is to identify unswept regions containing high oil or gas saturation for targeted infill drilling or enhanced recovery. Given the dense spatial sampling associated with time-lapse seismic surveys, there is a potential to map detailed interwell saturation changes in the reservoir. However, seismic attributes such as travel time and amplitude changes are indirectly related to reservoir saturation changes. Reservoir production data such as water-cut response at wells are related directly to saturation variations. An effective integration of the two forms of data is necessary to reliably characterize saturation distribution and still remains an important unresolved problem. A fundamental difficulty is the burden of reservoir simulation: use of conventional finite-difference reservoir simulators render coupled inversions of seismic and production data computationally challenging.
Recently streamline-based flow simulation models have demonstrated significant potential in integrating dynamic data into high-resolution reservoir models. The streamline approach has relied on computing and matching ‘travel time’ of fluid fronts at the wells and can be naturally extended to directly relate time-lapse images of a multiphase front to reservoir properties. In particular, saturation, porosity, and pressure variations in the reservoir will induce changes in seismic attributes such as ‘amplitude’ or the ‘travel time’. These changes can be incorporated into the streamline-based history matching using appropriate rock physics models. The result will be interwell saturation maps that are constrained by both production and seismic data. A key advantage of our approach will be its computational efficiency that makes it ideally suited for large-scale field applications.
At the Bay Marchand Field in the Gulf of Mexico both time-lapse seismic and water-cut observations are integrated to infer permeability variations within the reservoir. Some 40 years of historic production data are available at the Bay Marchand Field. In all, water-cut data from eight wells are used to constrain permeability variations in the reservoir. The streamline-based inversion is able to match the observations in 15 iterations, approximately four hours of computation for this 20,000 cell 3D model. The time-lapse seismic data are related to the reservoir saturation and pressure changes through Gassmann's equation and laboratory derived relationships. The time-lapse seismic data reveal large-scale amplitude variations that appear to correlate with saturation changes in the reservoir.
A Comparison of Travel-Time and Amplitude Matching for Field-Scale Production Data Integration: Sensitivity, Non-Linearity and Practical Implications
Authors: Cheng Hao , Datta-Gupta Akhil , He Zhong 
Published: December 2007

AbstractTraditional approach to reconciling geologic models to production data involves an "amplitude matching", that is matching the production history directly. These include watercut, tracer concentration and pressure history at the wells. It is well-known that such amplitude matching results in a highly non-linear inverse problem and difficulties in convergence, often leading to an inadequate history match. The nonlinearity can also aggravate the problem of non-uniqueness and instability of the solution. Recently, production data integration via ‘travel-time matching’ has shown great promise for practical field applications. In this approach the observed data and model predictions are lined up at some reference time such as the breakthrough or ‘first arrival’ time. Further extensions have included amplitude information via a ‘generalized travel-time’ inversion. Although the travel-time inversion has been shown to be more robust compared to amplitude matching, no systematic study has been done to examine the relative merits of the methods in terms of the nonlinearities and convergence properties, particularly for field-scale applications.In this paper we quantitatively investigate the nonlinearities in the inverse problems related to travel-time, generalized travel-time and amplitude matching during production data integration. Our results show that the commonly used amplitude inversion can be orders of magnitude more non-linear compared to the travel-time inversion. The travel-time matching is extremely robust and the minimization proceeds rapidly even if the prior geologic model is not close to the solution. The travel-time sensitivities are more uniform between the wells compared to the amplitude sensitivities that tend to be localized near the wells. This prevents over-correction near the wells. Also, for field data characterized by multiple peaks, the travel-time inversion can prevent the solution from converging to secondary peaks, resulting in a better fit to the production response.We have demonstrated our results using a field application involving a multiwell, multitracer interwell tracer injection study in the McCleskey sandstone of the Ranger field, Texas. Starting with a prior geologic model, the traditional amplitude matching could not reproduce the field tracer response which was characterized by multiple peaks. Both travel time and generalized travel time exhibited better convergence properties and could match the tracer response at the wells with realistic changes to the geologic model. Our results appear to confirm the power and robustness of the travel-time matching for field scale production data integration.
Well Performance in a Previously Condemned Prospect: The J-Sand Formation in the Northeast Wattenberg Field
Authors: Khachatrian Mikael B. , Trippett Steve W. 
Published: December 2007

Abstract
The J Sand formation is a main pay zone in the extensively developed Wattenberg field of Colorado. Until recently, operators deemed the reservoir in the northeast part of this field uneconomical due to significant production of formation water in this low permeability and sub-pressured gas zone. By modifying the conventional completion techniques of the J-Sand, an operator relatively new to the area has been able to economically exploit this reservoir. Key factors that have contributed to the success include improvements in stimulation design and production techniques. Typically, hydraulic fracture stimulation treatments for the J-Sand utilize a low viscosity, guar based, zirconium crosslinked fluid pumped at injection rates up to 24 bbl/min. The above operator differs in stimulation design by incorporating a higher viscosity, low polymer carboxy methyl guar fluid pumped at a relatively low injection rate (e.g. 12 bbl/min). Well performance evaluations utilizing the Reciprocal Productivity Index (RPI) production analysis method in conjunction with log analysis quantify stimulation effectiveness. Treatment pressure history matching with 3D fracture simulators also identify advantages in achieved fracture geometry and proppant placement with the modified treatment design.
Asymptotic Dipping and Nonlinear Shoulder Correction of Resistivity Logs
Authors: Xiao J. , Bittar M. S. , Hu G. 
Published: December 2007

Abstract
The effect of dipping beds on resistivity logs has been well documented. Several correction methods have been developed and reported in the literature. However, many of them only work well within a limited range of formation and borehole conditions. Also, they commonly require heavy computation with long computation time and expert supervision.
The nonlinear shoulder effect of resistivity logs causes false curve separations in thin-bed formations and, distorts the curve shape and amplitude around high Rt/Rs contrast formation boundaries. This nonlinearity effect is often amplified by the linear processing of the array-type logging tools. In highly deviated wells, the dipping effect and the nonlinear shoulder effect tangle together, resulting in abnormal logs.
The method presented corrects for the dipping effect and the nonlinear shoulder effect simultaneously. It tackles the subject with a straight-forward methodology. A formation resistivity model is first estimated with raw measurements or pre-processed measurements. With the formation model, the tool responses of deviated borehole and of vertical borehole are then numerically simulated at the given relative dip angle and at a zero-degree relative dip angle as well. Comparing the simulated zero-dip response with the simulated non-zero-dip response yields the dip effect. Another response of vertical borehole is also calculated with a method of linear approximation, such as the Born approximation. Taking the difference between the two responses of vertical borehole, we obtain the nonlinear shoulder effect. Removing the dipping effect and the nonlinear shoulder effect from the raw measurements, we achieve an asymptotic correction for both the dipping effect and the nonlinear shoulder effect. The corrected measurements can be treated as if they were from a vertical well and processed with algorithms developed for vertical wells.
The asymptotic method can be applied to induction logs and other resistivity logs of low to moderate nonlinearity. So far, the method has been successfully applied to the high resolution array induction logging (HRAI) tool. The implementation takes a constant dip value or a log of dip angle as input
Leaky-Tube Permeability Model for Identification, Characterization, and Calibration of Reservoir Flow Units
Authors: Civan Faruk 
Published: December 2007

Abstract
Presently, the reservoir flow units are described by means of the Kozeny-Carman equation. Although, the Kozeny-Carman equation has been extensively used for relating permeability to other properties of porous materials, it has been shown to suffer from its inherent and long-forgotten assumptions and limitations. Therefore, the frequently used flow unit analysis based on this equation yields misleading results. Consequently, its modified forms and many other theoretical and empirical porosity-permeability equations have been proposed with limited success.
In this paper, a leaky-tube model is presented, which alleviates the limitations of the previous models. This paper presents theoretical improvements over the Kozeny-Carman equation by considering the fractal attributes of pores and realization of flow channels as a bundle of leaky and tortuous hydraulic flow tubes, which can interact with each other by means of the cross-flow between the capillary tubes. The leaky-tube model results in a power-law function of the pore-to-solid volume ratio, considering the cementation factor and the fractal parameters of porous media. The parameters of this model are correlated with respect to the interconnectivity parameter of the pore space.
The advantages of the leaky-tube model are demonstrated against the available porosity-permeability models by analyzing various core data. The leaky-tube model is applied for characterization of typical reservoir formations and correlation of their flow units. The validity of the present model is confirmed by comparison to experimental data. In contrast, the Kozeny-Carman equation and its modifications as well as the other available porosity-permeability correlations cannot represent the same data satisfactorily.
It is concluded that the leaky-tube model can accurately integrate the characteristic parameters of reservoir formations and therefore it is more appropriate for reservoir characterization. The leaky-tube model correctly determines the distribution of the reservoir flow units and allows for the calibration of the flow unit parameters.
Portfolio Development Planning for Operational and Strategic Decisions
Authors: Koosh Victor , Riis Torben , Blinten Jerry , Systems Caesar , Woodward Don 
Published: December 2007

Abstract
BP, a major shareholder of the Atlantic LNG Plant in Trinidad and Tobago, was in search of project modeling and economic forecasting tools to help meet the aggressive commercial gas demands of this asset. This asset consists of 7 production fields that supply oil & gas to the island, with gas being fed through the existing 1, 2 & 3 trains for the next 20 years and projected to feed future LNG trains and downstream gas projects and a proposed gas refinery.
The development & production team collaborated with the resident facilities engineers and the drilling & completions teams to procure facilities cost data, drilling data, and other similarly-structured project planning data. The team was then challenged to formulate a production constraint system that applied strategic and economic analysis of gas supply/demand options, deliverability forecasts, facility capacities, and rig availability.
The team met this challenge through a single decision support tool that accelerated project analysis cycle time by 30%, reduced risk with full-cycle economic options analysis and promoted interdisciplinary teamwork. This tool superseded the use of eight (8) linked Excel workbooks that occupied 17 MB and proved inadequate to meet the team's performance standards.
In this paper we present an overview of the challenges facing portfolio managers in their attempt to create a dynamic portfolio model for evaluation and optimization of portfolio value taking into account any relationships which may exist between portfolio projects and opportunities. Subsequently, it is demonstrated how the computational toolsuite "PetroVR" (Petroleum Ventures & Risk) managed the scope and complexity of modeling this BP asset. Features that helped search and define scenarios, provided graphic comparisons of model variations and finally helped the development and production team narrow their choice of real options will be discussed.
A Simplified Method to Predict and Prevent Asphaltene Deposition in Oilwell Tubings: Field Case
Authors: Alkafeef Saad F. , Al-Medhadi Fahad , AL-Shammari Ali D. 
Published: December 2007

Abstract
The natural state of asphaltene in petroleum fluids is described as a colloidal system stabilized to some extent by the resins that act as peptizing agents. Destabilization of colloidal asphaltene appears to happen as a result of changes in temperature, pressure, and composition. This can significantly affect the production efficiency of the reservoir during oil recovery.
The phenomena of asphaltene flocculation and deposition in oil well tubing appear to be influenced by two mechanisms, the fluid phase (gas/liquid/solid) separation and well flow regime respectively. The predictions of the onset of asphaltene flocculation determined by fluid phase laboratory studies do not necessarily imply that asphaltene deposition will occur during flow conditions. We believe that the deposition is due to the change in well flow regimes under the effect of reservoir drawdown pressure. This paper presents a method capable of predicting the onset of asphaltene deposition under well flow conditions. This allows us to take preventive actions before asphaltene problems occur by keeping the asphaltene dispersed in the oil phase.
A well monitoring technique was conducted in West Kuwait Marrat (Jurassic) deep wells to monitor the behavior of the well flowing pressure using programmable data logger. The data gathered from the logger have predicted the onset of the mechanism that influenced asphaltene deposition in well tubing. The deposition thickness of asphaltene in well tubing was estimated by the data and was found agreeable with the results obtained by the caliper test.