bluuebunny/crossref_metadata_2025_split huggingface dataset:
Investigation of Oil Swelling Packers
Authors: Al-Yami A. S. , Nasr-El-Din H. A. , Al-Saleh S. H. , Al-Humaidi A. S. , Al-Arfaj M. K. , Al Moajil A. M. , Awang M. Z. , Al-Mohanna K. S. 
Published: June 2014

Abstract
Achieving successful zonal isolation is critical to install smart completion tools. Currently, cementing and mechanical packers are the only conventional methods used in Saudi fields to provide zonal isolation. However, these techniques are difficult to apply and result in reduced inner casing string diameter. Another method to provide zonal isolation for smart completion tools and to complete them in a single stage is to use a rubber elastomer bonded onto a base pipe. The rubber swells in oil and provides a seal between the base pipe and the open hole. This paper will outline the step-by-step qualification testing that was carried out in Saudi Aramco facilities in an attempt to improve zonal isolation for smart completions.
In this study, we present lab evaluation of elastomers at 190°F using six different oil samples. These oils had different viscosities, API gravities, and compositional analyses. Also, the study investigated the effect of different acids and brines on the swelled elastomers.
The elastomer bonded in pipes was tested in autoclaves. The pressure drop across the pipe was measured as a function of time. The effects of other factors were investigated using elastomer samples and fluid characterization. The oil swelling elastomers withstood pressure up to 5,000 psi at 190°F after placing the elastomers in crude oils. In addition, the elastomers swelled rapidly in some oils and slowly in others. The oil swelling elastomers showed great resistance to different acids and brines.
From Real Time Data to Updated Models: The Challenge of Intelligent Fields Applied to Gas Storage Business
Authors: Tiani A. , Bartolotto G. , Strippoli P. D. , Latronico R. , Spitaleri G. 
Published: June 2014

Abstract
In recent years, Underground Gas Storage (UGS) has earned itself strategic importance as it guarantees energy sustainability in markets suffering from unpredictable supply. Storage management is a complex activity which faces the challenge of combining the variability of daily commercial client requests along with the capability of the reservoirs to deliver. Gas production and re-injection activity requires standard core competencies of the oil and gas industry, however the process is fast paced as compared to conventional hydrocarbon production activity as time scales from data analysis to decision making is reduced to hours.
Stogit Spa, an Italian gas storage company managing 8 depleted gas fields in Italy has implemented an integrated system that dynamically links databases, visualization tools and reservoir/well simulators in order to assist the management process. This system called PERSEO (PErformance Reservoir StoragE Optimization) is aimed at enhancing efficiency by utilising a piece of intelligent fields application.
The large amount of data from the 270+ wells of STOGIT equipped with SCADA systems monitoring real time gas rate and well head pressure, provides information for production/injection management. The challenge has been to extract the maximum information from the available database and computerize the process of updating well/reservoir performance automatically. This allows for faster monitoring, analysis and prediction of future well behaviour.
A workflow was realised to transform available real time data into calibrated models in the following two steps: ■Design an algorithm capable of filtering stabilised gas rates and wellhead pressures for every injection/production period to extract data representative of the well performance■Automatic updating of well performance (IPR/VLP) model and matching the algorithm filtered data with theoretical and practica1 models (back pressure C,n equation).
This paper describes the outline of the implemented PERSEO system, details of the computerized workflow along with sensitivities and the results obtained.
Modeling a Surfactant Preflush with Non-Aqueous and Aqueous Scale Inhibitor Squeeze Treatments
Authors: Vazquez O. , Mackay E. J. , Al Shuaili K. , Sorbie K. S. , Jordan M. M. 
Published: June 2014

Abstract
The most common method for preventing downhole scale formation is by applying a scale inhibitor (SI) squeeze treatment. In this process, a SI solution is injected down a producer well into the near wellbore formation. Commonly, scale treatments comprise the following stages: a preflush (often involving a surfactant), the main scale inhibitor pill, an overflush and a shut-in, which is followed by back-production of the well. As noted, a surfactant preflush is often injected in order to "condition" the rock, potentially by altering the wettability resulting in enhanced SI retention. In these treatments, the main SI pill and overflush fluids may be aqueous or non-aqueous based fluids.
The main purpose of this paper is to present a near-well radial SI squeeze model that can simulate the impact of a surfactant preflush on both inhibitor return concentrations and on well clean-up time. Specifically, we model the effects of surfactant injection on the reduction of residual water and oil saturations and the results of these changes on enhanced SI adsorption, which may be modelled as either a reversible or an irreversible process. A sensitivity study is then presented of the effect of a surfactant preflush on reducing residual oil and water saturations, the impact of the surfactant volume injected, surfactant adsorption onto the rock surface, and enhanced SI adsorption. Of particular interest is that the SI adsorption enhancement shows a significant impact on the treatment lifetime. This study was performed using in-house scale treatment modelling software, developed over many years within the FAST group at Heriot-Watt University.
An example of modelling a specific field treatment with surfactant preflush is included, and the results are compared with the field return profiles, which clearly demonstrate the value such a model can bring to the interpretation and design of field squeeze treatments in terms of optimisation of chemical cost and treatment lifetimes.
Application of Deconvolution and Decline-Curve Analysis Methods for Transient Pressure Analysis
Authors: Zheng Shiyi , Fei Wang 
Published: June 2014

Abstract
Traditionally well testing is completed by analysing transient pressure due to constant production rate. However, in the oil industry practice, engineer often has to deal with the transient pressure resulted from variable flowing rate history. This is particularly true in the case, when transient pressure data is from a PDG over a relatively long period of production time.
Another well testing method is to analyse transient flowing rate as a result of the constant well bottom hole flowing pressure. The method is so-called decline curve analysis. However in reality, because of production constraints or changes in operating procedures, the down-hole flowing pressure seldom remains at a constant level over a long period of time.
Deconvolution is a technique, which can be used to convert measured transient pressure due to variable sand-face rate into the transient pressure response as a result of equivalent constant flowing rate. This technique can also be used to derive the transient flowing rate due to equivalent constant-pressure of a reservoir system from measured variable pressure. Once having these tasks completed, the traditional well test analysis methods including decline-curve analysis can be applied to analyse the field data.
This paper presents study results based on synthetic cases and numerical well testing. Deconvolution codes were developed for the study. It was proved that deconvolution algorithm works well in the case with single phase oil, but breaks down when dealing with cases having multi-phase flow and well interference effects in the data. These aspects need to be addressed in the future investigations.
Method to Preliminary Estimation of the Reserves and Production Forecast for Dual Porosity Fractured Reservoirs
Authors: Pirker B. , Heinemann Z. E. 
Published: June 2014

Abstract
When simulating naturally fractured reservoirs many uncertainties have to be accepted. These uncertainties do not only origin in the reservoir characterization but also in oversimplifying assumptions of the conventional dual continuum model. One of the shortcomings in this respect is the assumption of uniform matrix blocks within a simulation cell. The calculation of the matrix-fracture transfer term is done using one single value of the shape factor per simulation cell. This paper presents a new approach, which omits this simplifying assumption.
The method takes into consideration that the matrix blocks in a fractured reservoir are not of the same size, but follow a probabilistic distribution. The approach can be used in all levels of field investigation, starting with material balance calculations up to multimillion block full-field studies, with no or moderate supplementary CPU time. The method offers the possibility of a quick evaluation of an oil prospect with simultaneous assessment of the uncertainty.
Single porosity small scale simulations are used to model the matrix depletion processes. The results of these simulations are consolidated to recovery curves representing a simulation cell. The consolidation step considers the shape factor distribution and the depletion mechanism. The end-product is a set of recovery curves (recovery factor versus dimensionless time). The dual continuum calculation determines the local pressures and saturations changes during the depletion of the reservoir and so the timing of the depletion for every simulation cell, depending on the position within the model. The combination with the dimensionless recovery curves results in a more realistic production forecast. The single matrix calculations were already published, this paper concentrates on the recovery curve consolidation and the incorporation of these recovery curves in simulation calculations. Examples are presented to compare the results of the new approach with the conventional ones.
LWD Acoustic Measurements Enhancements for Varying Drilling Conditions
Authors: Moore John , Dubinsky Vladimir , Harrison Charles , Li Chen 
Published: June 2014

Abstract
Accurate acoustic measurements performed while drilling present additional challenges as compared to wireline. In the logging-while-drilling (LWD) environment, the drilling operation will often adversely affect the quality of acoustic measurements in a number of ways, including substantial background noise during drilling caused by drilling dynamics and mud circulation. Also, the dynamic motion and fluctuating centralization of the transmitter and receivers can dramatically reduce the homogeneity of acquired signals.
To address these drilling-related issues, new approaches to data processing are proposed and evaluated. These approaches assume a certain configuration and features of the acoustic tool, such as an omni-directional transmitter and four columns of receivers to provide full acoustic coverage of the borehole. This provides the foundation for a new set of processing possibilities. The traditional approach used when multiple receivers per station are available is to perform simple summation to average-out local variances and improve the Signal-to-Noise (S/N) Ratio. However, in some cases, especially when the tool is off-center due to well-deviation, bending/compression, and/or bit whirl, simple summation provides little to no signal enhancement. This occurs more frequently in high frequency measurements, such as those that are commonly used for deriving compressional (P-wave) slowness of the formation. In order to achieve constructive summation and improved S/N ratios, special approaches are required.
New processing methodologies, such as using the multiple receiver columns and other data processing techniques are presented. Each method is illustrated with actual field data in varying drilling conditions. These methods, in conjunction with the unique tool features, provide a system that demonstrates enhancement of acoustic data in noisy drilling environments and or highly deviated wells.
Using Experimental Designs, Assisted History Matching Tools and Bayesian Framework to get Probabilistic Production Forecasts
Authors: Schaaf Thomas , Coureaud Bertrand , Labat Nicolas 
Published: June 2014

Abstract
One of the main concern in the O&G business is generating reliable production profile forecasts. Such profiles are the cornerstones of optimal technico-economical management decisions. A workflow combining different methodologies to integrate and reduce most of the subsurface uncertainties using multiple history matched models (explaining the past) to infer reasonably reliable production forecasts is proposed.
Using experimental design theory, a sensitivity study is first performed to scan the whole range of static and dynamic uncertain parameters using a proxy-model of the fluid flow simulator. Only the most sensitive ones with respect to an objective function (quantifying the mismatch between the simulation results and the observations) are retained for subsequent steps.
Assisted History Matching tools are then used to get multiple History matched models, an order of magnitude faster than traditional History Matching processes. Updated uncertain parameters (selected from the sensitivity studies) may be picked anywhere in the direct problem building workflow.
Using the Bayesian framework, a posterior distribution of the most sensitive parameters are derived from the a priori distributions and a non-linear proxy model of the likelihood function. The later is computed using experimental design, kriging and dynamic training techniques.
Multiple History Matched models together with a posteriori parameter distributions are finally used in a joint modeling approach to capture the main uncertainties and to obtain typical (P10-P90) probabilistic production profiles.
This workflow has been applied to a gas storage real case submitted to significant seasonal pressure variations. Probabilistic operational pressure profiles for a given period can then be compared to the actual gas storage dynamic behaviour to assess the added value of the proposed workflow.
Looking For Earlier Integration: An Application Example
Authors: Pampuri F. , Brignoli M. , Berto R. , Marzorati D. , Cairo E. 
Published: June 2014

Abstract
A "creative" approach to reservoir characterization is not always the best choice while integration should be the appropriate methodology, if properly planned and developed.
This paper describes the integrated sedimentology-petrophysics-geomechanics methodology used to characterize the reservoir and cap-rock that will be interested by gas storage activity at overpressure conditions. The determined data are then used in the modelling phase aiming at evaluating the safe injection/storage maximum operating pressure.
The analyzed sequence is located in Central Italy and is represented by sand-shale intervals.
The available data are: conventional and high last technology logs, mini-frac tests, laboratory core analysis, sedimentological and fracture description on cores.
The advantage of the approach relies in the use, during the different project tasks, of each provisional result to drive the work group for finding the solution which better honours the response of different disciplines, looking therefore for an ‘integration on the job'.
The two shales, bounding the reservoir, had similar geomechanical properties but different petrophysical ones (different sedimentological process). The overburden ("cap-rock") is mostly massive with maximum horizontal stress direction 155 N while acoustic logs showed also anisotropy surfaces. The underburden shales ("argille basali") show different sedimentological features and diffuse slumping surfaces. The stress direction is similar for both shales, therefore an unique stress profile was needed throughout the layers and the mini-frac/stress tests were used to constraint the minimum horizontal stress. The geomechanical data allowed to derive reliable mechanical and failure parameters. The sand reservoir shows laminations with few fractures. From a geomechanical standpoint, these results allowed a statistical analysis of the main parameters, for the use in the subsequent modelling activities.
An earlier integration approach was the key for the quality of a reservoir/sealing sequence characterization for the appropriate and safe storage operation.
A Global Gas Distribution Model with Transport Constraints: Methodology and Some Scenarios
Authors: van Berkel J. T. , Roodhart L. P. 
Published: June 2014

Abstract
Natural gas resources are unevenly distributed around the world. Will we be able to grow transport capacity sufficiently quickly to transfer ever-increasing volumes of conventional natural gas from locations where it is found to where it is consumed in the 21st century and for how long? On a world scale, the crucial question for now is not how much gas there is overall, but the transport capacity linking regions with high gas resources to regions with a high consumption but insufficient local gas resources like North America, Europe and East Asia.
To analyze the gas situation in the world, a gas distribution model was constructed. The model predicts the timing and amount of gas shortfall (the difference between demand and available supply) as well as depletion of recoverable gas resources for the various regions in the world for a 100-year period. To reduce the complexity of the problem, the world is split into only ten regions. In each region demand, supply and recoverable gas resources of the various countries are pooled. Transportation of gas by pipelines or LNG tankers is driven by the transport cost of gas between the regions and mainly depends on distance and topography.
Several scenarios were tested for demand and recoverable gas resources using public data. Supply and demand predictions are from USA Government Agencies. Gas transport capacities between the regions were modeled using total export capacity of gas exporting regions. In the low and mid case scenarios shortfall of gas starts early for North America, East Asia and Europe, in the period 2015 (low case) to 2035 (mid case), and is caused by the low indigenous gas resources and by insufficient imports. In the high case scenario, which includes large volumes of tight gas, shortfalls would be much later, i.e. past 2070.
North America has relatively large indigenous resources and imports relatively low amounts of gas but the local supply shortfall will be huge when its own resources are fully depleted. Both East Asia and Europe have low recoverable gas resources and high imports. Europe is strategically located to import gas from various regions but may find itself in competition with East Asia for pipeline gas.
Key uncertainties are recoverable gas resources, demand and transport capacities, causing a supply shortage. For North America, East Asia and Europe, the lack of recoverable gas resources is most sensitive and development of unconventional gas resources will be essential to satisfy future demands. Another option is an increase of supply from gas exporting regions with very large resources like the Former Soviet Union and the Middle East, but this also requires much higher inter-regional transport capacities.
An Integrated Methodology for Calibrating a Heterogeneous/Fractured Reservoir Model from Wellbore Flow Measurements: Case Study
Authors: Pourpak Hamid , Bourbiaux Bernard , Roggero Frédéric , Delay Frederick 
Published: June 2014

Abstract
Reliable flow modelling of highly-heterogeneous/fractured reservoirs necessarily goes through the calibration of poorly-determined geological and/or petrophysical parameters to field flow measurements. To that end, optimization procedures, based on gradient methods or on gradual deformation techniques, have been developed in the recent years.
This paper proposes a sequential methodology combining those two approaches. The case under consideration is a water-bearing reservoir constituted of heterogeneous, karstic and fractured limestones located near Poitiers city in France. In a preliminary step, drilling, core and log data acquired in about 30 wells were integrated into a geostatistical facies model used as the support for flow simulation.
Firstly, the facies petrophysical properties of this model were calibrated to well pumping and interference responses within a gradient-based inversion loop. Flow responses could be reproduced, except for a few "problematic" observation wells.
Secondly, the gradual deformation method was applied, globally then locally, to improve the distribution of facies while keeping the previously-optimized petrophysical properties. The "problematic" wells responses could be better reproduced without altering the other wells match. Furthermore, that good match of calibration wells was obtained on a simplified geostatistical model involving fewer facies as on the initial model. The gradual deformation method then appears as a robust and effective approach to find a model bestly matching a set of flow data among equi-probable geostatistical models.
To conclude, the sequential modelling methodology demonstrated herein is an effective way to actually integrate geological and flow data and to link geosciences and reservoir engineering skills, for setting up consistent models of hardly-tractable highly-heterogeneous reservoirs.