bluuebunny/crossref_metadata_2025_split huggingface dataset:
Prevention and Control of Gas Hydrates for Foam Combination Flooding
Authors: Zhang Jicheng , Song Kaoping , Dong Bo , Chen Donghui 
Published: December 2007

Abstract
Foam combination flooding is one of the most capable tertiary oil recovery techniques. For the pilot test of foam combination flooding performed in Sa-Nan, Daqing, gas hydrates affect the normal gas injection badly. The designed gas injection is 182 days, however, due to the influence of gas hydrates, only 59 days of gas injection is conducted. The injected gas is just about 36 days' work in the design. Based on the pilot test in Sa-Nan, this paper elucidates the structure, phase state and forming condition of gas hydrates and proposes a number of effective measures to prevent and remove the formation of gas hydrates in the process of foam combination flooding. Two models for predicting the forming condition of gas hydrates for foam combination flooding are presented in this paper. Phase-equilibrium-constant method is proved to be more accurate and reliable than empirical graphic method and is recommended for use in research work and field practice to determine the forming condition of gas hydrates in foam combination flooding. With this method, the forming condition of gas hydrates in Sa-Nan pilot is calculated. The result shows that gas hydrates will generate at temperature lower than 73.4°F. Three ways are proved effective to prevent the formation of gas hydrates for foam combination flooding, which are reducing the water content of natural gas, improving the injection technology to avoid the contact of water with gas and adding certain suitable inhibiting agent. Heating, lowering pressure and adding deicing agent are suggested as the three good measures to get rid of the plugging in injection pipelines caused by gas hydrates for foam combination flooding.
Abductive Networks: A New Modeling Tool for the Oil and Gas Industry
Authors: Osman E. A. , Abdel-Aal R. E. 
Published: December 2007

Abstract
Artificial neural networks have been proposed for solving many problems in the oil and gas industry, including seismic pattern recognition, permeability and porosity prediction, identification of lithofacies types, prediction of PVT properties, estimating pressure drop in pipes and wells, and optimization of well production. However, the technique suffers from a number of limitations. This paper introduces Abductive Networks as an alternative modeling tool that avoids many of the neural networks limitations. While the processing elements in neural networks are restricted by the neuron analogy, abductive networks use various types of more powerful polynomial functional elements based on prediction performance. Based on the self-organizing group method of data handling (GMDH), this technique uses well-proven optimization criteria for automatically determining the network size and connectivity, and element types and coefficients for the optimum model, thus reducing the modeling effort and the need for user intervention. The abductive network model automatically selects influential input parameters and the input-output relationship can be expressed in polynomial form. This enhances explanation capabilities and allows comparison of the resulting data-based machine learning models with existing first principles or empirical models.
The main objectives of this paper are to introduce abductive networks and outline their advantages over neural networks. Also, to put abductive networks into perspective from petroleum engineering point of view and encourage petroleum engineers and researchers to consider them as a valuable alternative modeling tool. The technique was successfully used in areas such as weather prediction, energy forecasting, spectrum analysis, and medical informatics, but has not been much utilized in the oil industry. To demonstrate the usefulness of the technique in this area, we describe the use of abductive networks for predicting the Pressure-Volume-Temperature (PVT) properties. Results indicate that abductive network models outperform other models and empirical correlations. Finally, some other potential applications in the oil and gas industry are briefly discussed.
Permeability Characterisation: A Novel Technique for Estimating Gas Recovery Factors
Authors: Kabir Mohammad I 
Published: December 2007

Abstract
A novel method is developed that allows estimation of gas recovery factor without permeability averaging. In this method recovery factor as a function of permeability is generated for each depth-interval (in a wireline log) utilising a one-dimensional (1-D) radial model. The 1-D recovery data over producing intervals is then volumetrically added to obtain recovery factor for the well. The reservoir average recovery factor is then calculated on the basis of permeability-thickness weighting of individual wells to account for lateral variations.
This is a simple technique based on a simple depletion model which allows a quick estimate of recovery from multizone, multi-well gas fields with variable permeability making recovery from different zones and different wells vary widely. This paper presents the basis of the technique and illustrates its application using several field examples.
The Multiphase Flowmeter, A Tool for Well Performance Diagnostics and Production Optimization
Authors: Kettle R. J. , Ross D. , Deznan D. 
Published: December 2007

Abstract
The Dual-Energy Venturi Multiphase Flowmeter (MPFM), has gained acceptance within the Oil and Gas Industry as an accurate and cost-effective solution to multiphase metering. has now been implemented by the Australian Petroleum industry on the Apache Energy Simpson Alpha, Bravo and Gibson remote mini-wellhead platforms.
Eliminating the conventional test separator has led to wide-ranging improvements in engineering, financial and Operations areas. In addition, the field data are being used in a wide range of new and beneficial applications, including new field development, rapid deployment, artificial lift optimization and well-clean up optimization operations.
Integration of the MPFM packages into Customer supervisory control and data acquisition system (SCADA) and the connectivity achievable through these compact metering packages, has shown the benefits the customer may obtain by providing real-time data to operations and reservoir critical management functions. Connectivity for remote fault diagnosis and maintenance actions significantly reduces Field Service Operational Expenditure (OPEX) costs, and nonproductive time for field service personnel, which is particularly beneficial for installations in areas that lack infrastructure.
The applications, and commissioning of the MPFM packages and other low-cost technologies are illustrated in the paper. The straightforward nature of the Vx* multiphase well testing technology installation process brings distinct advantages to these applications, provided that methodical preparation is performed beforehand.
The key to the success of the multiphase flowmeter, as a tool for well performance diagnostics and production optimization, is its high availability and long-term performance stability, underpinned by the local and regional support network available to customers.
In the future, challenges remain in the interpretation of the new information being gathered, which document previously unrecorded inflow and outflow behaviors, with unmatched resolution and dynamics.
Applications of Permanent Downhole Pressure, Temperature, and Flow Rate Measurements for Reservoir Description and Production Optimization: a Taxonomy, Processes, and Benefits
Authors: Queipo Nestor V. , Verde Alexander , Goicochea Javier , Romero David , Zambrano Alexander , Bracho Annette 
Published: December 2007

AbstractThe resolution and accuracy provided by the existing technology for downhole (pressure and temperature) and rate measurements are unprecedented. However, while the potential benefits have been outlined, the models and processes required to reap these benefits (in particular the quantifiable ones) have not been sufficiently documented. In addition, considering the increasing number of reported work in this area, it is necessary to provided a framework for the analysis and discussion of existing and upcoming applications.This paper presents a: i) summary and classification of downhole and flow rate measurements applications, ii) a discussion of their benefits for reservoir description and production optimization, and iii) the models and processes required to obtain those benefits.The above-referenced applications are classified in three main areas: reservoir characterization, reservoir/well flow modeling, and process monitoring. The discussion of each application includes: benefits, previously reported work, required measurements and other relevant data, and a general description of the necessary models and processes.The paper is expected to be useful assessing the possible impact of investments (business cases) in permanent downhole and flow rate measurements, designing plans for the development or acquisition of applications, and establishing the knowledge requirements in the context of training programs.
An Analytical Model for Production Estimation from Hydraulically Fractured Tight-Gas Reservoirs
Authors: Rahman M. M. , Rahman M. K. , Rahman S. S. 
Published: December 2007

Abstract
In relatively high-permeability reservoirs, the pseudo-steady state (PSS) flow condition dominates the production life of a well, and therefore modeling of production profile considering this flow condition only is found adequate. In tight-gas reservoirs, however, the early production period is dominated by the transient flow condition whereas the later period by the PSS condition. Neither of these conditions alone can be used to adequately model the production profile during the entire production life of a tight-gas reservoir. The creation of hydraulic fracture also influences the flow conditions and thus the production profile. This paper presents an analytical method, which combines both the flow conditions and account for the effect of hydraulic fracture and non-Darcy components for computationally efficient estimation of production from tight-gas reservoirs. An algorithm is then presented to couple these two different models by a production rate matching technique, which has resulted in a hybridized transient-pseudo-steady-state (TPSS) model to predict the production profile during the whole production life. The production profiles and resulting pressure profiles for both TPSS and PSS models are verified by a reservoir simulator for a range of reservoir permeability. The TPSS model is found to be closer to the results from simulation for low-permeability reservoirs.
Completion, Perforating and Hydraulic Fracturing Design Changes Yield Success in an Area of Problematic Frac Placement— the Cooper Basin, Australia
Authors: Johnson Raymond L. , Aw Keong P. , Ball David , Willis Mike 
Published: December 2007

Abstract
High stress, high near-wellbore pressure losses (NWBPL) and pressure-dependent leakoff (PDL) contribute to premature screen outs during some fracturing treatments in the Cooper Basin of South Australia and Queensland. In one case, an unsuccessful attempt to hydraulically fracture a well occurred because of limitations raised by completion design, insufficient stress data forewarning high-stress observations, and inadequate ability to counter high NWBPL and PDL effects.
We reviewed the current completion, hydraulic fracturing design and treatment execution practices and concluded that changes should be made in these areas: stress modeling/layering, completion design, perforating practices, hydraulic fracture design strategy, management of PDL and on-site treatment execution strategy. The largest departure from current practices was the use of 0- and 180-degree oriented perforating; thus, we describe the methodology chosen for this case, discuss current means to orient perforations and review alternative methods available.
The specific changes in hydraulic fracturing design and execution included: developing and calibrating log-derived rock-mechanical properties; incorporating PDL characteristics in the hydraulic fracturing treatment design; and applying specific job steps to reduce PDL and NWBPL. Our evaluation presents our frac implementation strategy and describes field fracturing treatments applying all these changes. Wherever possible, we will discuss the considerations that lead to our choice of actions and must be made when evaluating the potential applications of these technologies.
Marine Transportation of Compressed Natural Gas a Viable Alternative to Pipeline or LNG
Authors: Wagner Jan V. , van Wagensveld Steven 
Published: December 2007

Abstract
The invention of the "Coselle" pressure vessel by Cran & Stenning of Calgary, Alberta, Canada and the development of the Coselle Compressed Natural Gas (CNG) Carrier promises to improve the economics of shipping natural gas over short sea routes, and from modest reserves. This invention also ignited renewed interest in CNG marine transportation and a few other concepts entered the scene: Enerseas' VOTRANS and TransCanada's GTM.
The general promise from all these CNG concepts is to economically explore modest reserves in moderate daily volumes over shorter transportation distances, thus unlocking reserves which would remain stranded where either pipeline or LNG are considered.
This paper provides an overview of current CNG technologies, compares those to pipeline and LNG and provides general insight regarding the commercialization of this concept.
Asphaltenes Characterization: A Key to Deepwater Developments
Authors: Jamaluddin A. K. M. , Nighswander J. , Joshi N. , Calder D. , Ross B. 
Published: December 2007

Abstract
The continuous pursuit to discover new hydrocarbon reserves is driving oil and gas exploration companies to explore in more challenging environments, such as in deep water. One of the major challenges in these environments is to understand the characteristics of hydrocarbon solids deposition and its potential for production disruption. Asphaltenes are one of the hydrocarbon solid materials that have the potential to form, flocculate, and deposit in the production circuits. This process can come about as a result of changes in pressure, temperature, and/or composition.
In this paper, we present a systematic approach to characterize asphaltene materials using state-of-the-art technologies. In summary, a fixed-wavelength near-infrared light-scattering technique (NIR) is used to prescreen the thermodynamic onset of asphaltene flocculation. Subsequently, a variable-wavelength spectral analysis system (SAS) is used to estimate the asphaltene particle size and the growth kinetics. Finally, a high-pressure microscopy (HPM) technique is used to better understand the morphological behavior of the asphaltene materials.
These laboratory techniques can greatly enhance the understanding of asphaltene flocculation and the risk of potential deposition at the beginning of field development. As a result, operators may have the option to proactively prevent deposition or design remediation methods during the planning phase of the deepwater development that will reduce the risk of flow disruption.
Stress Induced Changes in Two-Phase Permeability
Authors: Jones C. , Smart B. G. D. 
Published: December 2007

Abstract
An accurate knowledge of porosity and permeability is crucial to accurate simulation of reservoir performance and enhanced reservoir management. Porosity and single-phase permeability of reservoir rocks is dependent on the stress experienced by the rock mass, which in the simplest case is given by the overburden stress minus the pore pressure. Hydrocarbon production decreases the pore pressure causing an increase in stress. This causes coupled changes in permeability and porosity, which have a significant effect on production rates. The stress and permeability changes are particularly large in the near wellbore region.
The experimental programme was performed to examine the changes in two-phase permeability during deformation. This consisted of experiments where, starting from a given hydrostatic stress level, σ1 was increased until the rock failed and a shear fault was formed. In all experiments core flooding took place during the stress changes, either single-phase core flooding, oilflooding at Swi or waterflooding at Sor. The experiments were performed on a water-wet sandstone.
The deformation experiments were performed over a range of confining stress. Single phase, oilfloods and waterfloods, were performed at each stress. The stress strain behaviour, peak stress, residual sliding stress were independent of flooding type, but the variation of permeability was different depending on whether it was single or two phase flow. At low confining stress the single-phase experiments showed a smooth drop in permeability with strain, the oilflood showed first a decrease then a recovery then a steep drop at failure. The waterflood gave an intermediate behaviour between the other two. The results can be explained as an interplay between two mechanisms, compaction induced increase in tortuosity decreasing permeability and a dilatant increase in pore volume increasing permeability. At high confining stress the results showed the same effects except that the higher pressure inhibited dilatant cracking.
This work has applications in determining the effect of the stress path on the permeability of the reservoir. The differences between the single and two-phase permeability are of great importance when the reservoir stress changes are likely to cause failure. The single-phase data greatly underestimates the actual permeability change.
Continuous Scratch Testing on Core Allows Effective Calibration of Log-Derived Mechanical Properties for Use in Sanding Prediction Evaluation
Authors: Suárez-Rivera Roberto , Stenebråten Jørn , Dagrain Fabrice 
Published: December 2007

Abstract
This paper discusses the use of continuous scratch testing for evaluation of rock heterogeneity and effective correction and calibration of mechanical properties predictions using wire line logging. Understanding the vertical variability of rock properties (strength and moduli) along the reservoir thickness is of primordial importance for sanding prediction analysis. Logging measurements (GR, Sonic, Density and Porosity) are traditionally used to identify troublesome intervals, to select sections for laboratory testing and for extrapolating laboratory data to untested reservoir sections. However, depending on the scale of the reservoir heterogeneity, the log measurements, by providing integrated values over their window of vertical resolution, can considerably underestimate the strong reservoir sections and overestimate the weak reservoir sections. This leads to misrepresentation of critical weak layers with high potential for sanding and potentially to large errors in the completion strategy with costly long-term consequences. Corrections are thus necessary and are traditionally based on simple unconfined compression (UCS) tests conducted sparsely or at high density, varying from operator to operator. This paper presents a method for log-correction based on continuous core scratching in the laboratory and shows that the methodology is effective in evaluating changes in properties with high accuracy and a resolution of at least 1 cm.
Shale-Fluid Interactions Measured Under Simulated Downhole Conditions
Authors: Ewy R. T. , Stankovich R. J. 
Published: December 2007

Abstract
Preserved shale samples, from four different shale cores, were exposed to various fluids while under simulated downhole stress conditions. Prior to fluid exposure, the samples were not contacted by any aqueous fluid, including simulated pore fluid. Time-dependent measurements of pore pressure, swelling and acoustic velocities were made. Pore pressures both less than and greater than the applied fluid pressure were observed, and apparent osmotic membrane efficiencies are calculated. Swelling was found to depend not only on the shale type and the fluid, but also on the level of confining stress. Swelling anisotropy was observed. Acoustic velocities were found to change as a result of fluid exposure, and the amount of change is dependent on the fluid type and on the existence of swelling.
Investigation of the Undrained Loading Effect and Chemical Effect on Shale Stability
Authors: Chen G. , Ewy R. T. 
Published: December 2007

AbstractAn investigation was performed to determine and compare pore pressure, stresses, and critical mud weights using poroelastic analyses with and without including the undrained loading effect. The undrained loading effect, which enables a fully-coupled poroelasticity analysis for wellbore stability, can be crucial to the stabilization of near-wellbore formations within the critical time even though it will diminish at long time. The critical time, or the duration, of the undrained loading effect is found to be inversely proportional to formation permeability and will vary considerably for formations with different permeabilities. It is also demonstrated in this paper that it is the dimensionless time, not the dimensional time, that controls the duration of the undrained loading effect.Chemical effects, caused by the imbalance between the water activity in the drilling mud and the shale water activity, are also found to affect shale stability by changing pore pressure and shale strength with exposure time. Including all effects (hydraulic diffusion, undrained loading, and chemical effects), one finds that the required mud weight can increase with time, decrease with time, or first decrease and then increase. Furthermore, the change in required mud weight with time is different at different radial positions. The chemical effect does not alter the undrained loading effect, but it may counterbalance the common destabilization of the undrained loading mode.
New Model for Predicting the Rate of Sand Production
Authors: Willson S. M. , Moschovidis Z. A. , Cameron J. R. , Palmer I. D. 
Published: December 2007

Abstract
A number of robust predictive methods for establishing sanding thresholds have been developed over the past decade. Having identified when the onset of sanding occurs, recent research efforts have focused on determining the rate at which sand will be produced once these thresholds are exceeded. In this paper a new analytic model for predicting the rate of continuous (steady-state) sand production is described. This sanding rate model is consistent with the threshold prediction model, and utilizes as its basis the non-dimensionalized concepts of loading factor (near-wellbore formation stress normalized by strength) and Reynold's number (a function of permeability, viscosity, density and flow velocity). Interpreted this way, the results of laboratory sand production experiments are used to derive an empirical relationship between loading factor, Reynold's number and the rate of sand production. A second empirical sand production ‘boost factor’ incorporates the effects of water production. The derived model is compared with field data from a total of six wells from two fields, for a wide range of flowing conditions. The predictions are a good match to the field data, typically overestimating the field-measured data by a factor of less than four. However, as the model is for continuous sanding only, this degree of overprediction is considered acceptable for field application, as it provides some compensation for short-lived transient sand production at rates higher than steady-state values.