bluuebunny/crossref_metadata_2025_split huggingface dataset:
Time-Lapse Seismic and Engineering Data Integration to Estimate Best Time for Seismic Acquisition Data
Authors: Ferreira Carla J. , Schiozer Denis J. 
Published: June 2013

Abstract
4D seismic is important information to optimize well planning, interventions and drainage strategy. It provides unique information regarding the properties of the reservoir between and beyond the wells; it can be used to locate bypassed oil, to identify not drained compartments or to mitigate risks such as an unexpectedly early breakthrough of injected fluids. The integration of geophysics and engineering information increase the predictive capability of reservoir simulations, and hence has positive impacts on field management. The estimation of the best time to acquire seismic data has a major impact on reservoir management since, depending on the acquisition period, seismic may not be able to identify important variations in the reservoir dynamic properties, important changes may no longer be detected, well history matching can be able to identify properties, and it can be too late for effective action in field management. 4D seismic reservoir monitoring has no value unless it impacts operations and its utility is related to the period of seismic data acquisition. The challenge is to use effectively the available information; the integration of geophysics and engineering information must be accomplished by performing the history matching process that incorporates both production and 4D seismic data. Changes in saturation and pressure, derived from 4D seismic, can be used to improve the quality of the reservoir model allowing a better understanding of the reservoir model and fluid flow. Given the importance in defining the time for seismic data acquisition, this paper evaluates the quality improvement of a synthetic reservoir model by incorporating seismic data over different production periods and identifies characteristics that impact on the best time estimation. It also, estimates the best time to the case studied considering a practical condition. The study evaluated two cases: a posteriori (Case 1) and a priori (Case 2) analysis. In Case 1 the true model is known; a history match process was performed to 2, 4 and 6 years of production using two methods considering: (1) only production data; (2) production and seismic data. By analyzing the reservoir model quality improvement it was possible to identify the main characteristics that determine the moment to acquire seismic data. As, in practice, the earth true model is unknown, in Case 2, a process flow considering a risk analysis associated with reservoir simulation was applied to estimate the best time to acquire 4D seismic information. Analyzing the reservoir model quality improvement it was possible to identify the main characteristics that determine the best moment to acquire seismic data, to a non-mature oil reservoir with water injection production mechanism. These characteristics include: saturation and pressure error maps, production data error and breakthrough distribution within production wells.
Injection Testing: Gas Storage Field Experience
Authors: Azzarone Eleonora , Beretta Enzo , Marzorati Daniele 
Published: June 2013

Abstract
This work presents the interpretation of the injection testing operations performed on two wells in a gas storage field, located onshore Italy.
These field applications were aimed at setting the most suitable injection rates to allow the reintegration of the reservoir working gas. The injection gas rates were established as a function of the existing surface facilities constraints.
A secondary target was to confirm the areal hydraulic communication between two injection wells. A third well was used as an observation well to assess whether the hydraulic communication could be confirmed within the reservoir.
Two injection tests were conducted injecting methane gas into a depleted gas sands reservoir. All the wells were completed with sand control techniques.
The bottomhole pressure and temperature data were acquired by permanent downhole gauges allowing real time transmission. Memory gauges were used in the observation well to account for interference effects.
Over the sequence of several injection/fall off cycles, the downhole pressure response, observed in both the injection wells, was found to change and evolve over time.
In fact, during the injection history the expansion of the gas in the sand layer was able to displace the reservoir aquifer away. This effect was clearly experienced in the longest fall off phase.
Such a complex dynamic phenomenon can be properly described using 3D numerical simulators. However, a clear understanding was achieved utilising the standard analytical solutions typical of pressure transient analysis.
Simulation Sensitivity Study and Design Parameters Optimization of SAGD Process
Authors: Munoz Ricardo 
Published: June 2013

Abstract
The process of Steam Assisted Gravity Drainage or better known by its English acronym as SAGD has been successfully tested and commercially implemented in the last decade. It has been particularly successful exploiting the Athabasca oil sands in Alberta. Some of the reservoir features that are frequently present in the oil sands include the presence of bottom water, top water and gas caps. All of them, representing potential thief zones and are inherent to the reservoir nature.
Characterize and understand how those features affect the SAGD process is a key element of early project planning. In the present study, a simulation work to asses the feasibility of SAGD process for a typical section of the McMurray Formation in Alberta was conducted to asses the impact of the mentioned reservoir features.
This study confirms that the presence of bottom water is harmful to the SAGD process; thicker bottom water will be more detrimental. A vertical separation of 5 m to the bottom water was determined as optimum for the production well in order to achieve better recovery and economics. Depleted gas pools associated, or in partial communication with bitumen reservoirs represent a potential risk to the effectiveness of SAGD. The connectivity of gas pools to bitumen reservoirs depends on the vertical permeability and thickness of the material that lay in between; this determines their potential to prevent steam to escape up to depleted gas caps. An optimal range of inter-well spacing among 50 m and 80 m was established for the average reservoir conditions evaluated in this study.
Control of Reservoir Heterogeneity in SAGD Bitumen Processes
Authors: Stone Terry W. , Law David Hin-Sum , Bailey William J. 
Published: June 2013

Abstract
Uniform steam chamber growth (conformance) in a Steam Assisted Gravity Drainage (SAGD) process promotes enhanced bitumen recovery, project economics and environmental benefits. In the past, operators have implemented numerous alternative strategies to improve steam conformance in the SAGD process. Simultaneous injection in the inner tubing and annular space or use of dual-tubing completions are commonly used to provide some degree of injection control at the heel- and toe-regions of the horizontal well pair. However, this does not necessarily guarantee the uniformity and performance efficiencies sought. Distributed flow control devices (FCDs) can also contribute to more uniform production and injection. They can be incorporated in the horizontal production completion as restrictive elements to modify the pressure distribution along the length of the wellbore. A hybrid of these two technologies is proposed to provide superior (uniform and efficient) steam chamber development that benefits asset performance in highly heterogeneous bitumen reservoirs.
It has been shown that using Proportional-Integral-Derivative (PID) feedback to control the steam injection can be beneficial. The feedback control is applied to each steam injection point in the horizontal well pair. Injection at these control points is regulated by a PID feedback controller which monitors temperature differences between injected and produced fluids in order to both enforce a specified subcool and to achieve uniform production along the entire length of the producer.
This paper examines detailed wellbore simulations of a SAGD well pair with an FCD completion in the producer and PID controlled steam injection with dual tubing strings. A synthetic reservoir model, based on logs from the Athabasca region of Alberta, is employed and represents a highly heterogeneous formation with properties typical of a bitumen resource. Feedback controlled steam injection (FCSI) can be dynamically configured to target the worst-offending regions of the well pair in order to (i) start the PID control as early as possible after switchover, (ii) achieve a specified subcool target in those regions that would benefit most from the subcool and (iii) temporarily ignore regions which are bypassed and difficult to produce, but which may be dynamically included at a later time. Practical algorithms are presented to achieve these goals, based on existing technology.
Dielectric Properties of Synthetic Oil Sands
Authors: Swiech Weronika M. , Taylor Spencer E. , Zeng Huang 
Published: June 2013

Abstract
Dielectric logging tools have been used for some time in attempting to characterize oil reservoirs, and in particular to provide in-situ measurements of oil and water saturation. The particular sensitivity of basic electrical measurements, e.g. resistivity, to the presence of water made the original use of this approach most relevant to the determination of water-filled porosity.
In-depth dielectric spectroscopic analyses reveal contributions from underlying processes in materials, including electronic, ionic (electric double layer, EDL) and interfacial (Maxwell-Wagner, M-W) polarization, as well as molecular orientation. Our particular objective is the evaluation of dielectric spectroscopy as a means of characterizing the physico-chemical and structural characteristics of oil sands. Relatively recently, there has been a resurgence in interest in the application of dielectric techniques to unconsolidated heterogeneous systems. The present study builds on recent developments in the literature, and, specifically to determine the extent to which the potentially dominant effects of water can be overcome in order to access additional information, such as particle size and wettability.
This initial study has therefore involved investigating a range of synthetic oil sands systematically prepared from bitumen, water, sand and clay, to compare the behaviour with results obtained from a real core sample (obtained from a BP asset). The low-frequency dielectric spectroscopic analysis (10-2 to 107 Hz) yields complex properties (e.g. conductivity, permittivity, impedance) with frequency dependent in-phase and quadrature components. Within this frequency range, dielectric spectra are dominated by EDL and M-W polarization effects. By varying the sample preparation methods, it has been possible to observe structural differences with respect to water.
Phase Behavior and Viscosity Modeling of Athabasca Bitumen and Light Solvent Mixtures
Authors: Ghasemi M. , Whitson C. H. 
Published: June 2013

Abstract
This paper describes a systematic approach to model the phase behavior and viscosity of Athabasca bitumen and light- solvent mixtures for a wide range of temperatures. A cubic equation of state (EOS) is first developed using Athabasca crude assay data. We use a modified Jacoby correlation to describe the relationship of specific gravity and molecular weight for the bitumen sample. A gamma molar distribution model is used to fit the Athabasca crude assay data, then single-carbon-number (SCN) fractions are defined out to C90+. The Twu correlation is used for estimating SCN critical properties, including C90+, resulting in an EOS with 89 components (EOSSCN).
Pure solvent-crude oil mixture PVT data were tuned to the EOSSCN model by adjusting a fixed set of BIPs (binary interaction parameters) between pure solvent components (N2, CO, CO2, C1, C2) and all C7+ components.
For viscosity modeling, the LBC (Lorenz-Bray-Clark) correlation is used, with SCN critical volumes modified individually to ensure that the LBC correlation estimates SCN viscosities as given by a modified Twu correlation, based on specific gravity and normal boiling point.
The EOSSCN model was lumped into five pseudo-fractions (EOS5), the heaviest being C90+. The resulting model reproduces accurately all phase and volumetric behavior of pure-solvent-crude mixtures.
Initial viscosity prediction of the Athabasca crude by the EOSSCN/LBC and EOS5/LBC models is satisfactory for dead- bitumen with viscosity only affected by temperature. However, for viscosities of pure-solvent-saturated bitumen at varying temperatures, the EOS5/LBC model did not perform well. Our solution was to split the heaviest fraction C90+ into two sub- fractions, where only critical volumes differ, resulting in "lower-viscous" and "higher-viscous" C90+ fractions (C90+L into C90+H). The fraction of C90+L (fL) was found to correlate with pure solvent solubility and temperature, resulting in a quite- accurate overall viscosity fit. This final model has, in reality, six components, even though the two heaviest fractions are identical for EOS calculations – we call this final model EOS6/LBC.
The final EOS6/LBC model was checked against measured PVT and viscosity data for mixtures of the same Athabasca bitumen using synthetic combustion gas solvents made up of C1, CO2, and N2.
3.5D + 4D Seismic Reservoir Surveillance in Case of no Baseline Survey
Authors: Ling Yun , Guo Xiangyu , Cai Yintao , Guo Jianming 
Published: June 2013

Abstract
Before ninetieth last century the major oilfield in China was discovered using low fold large cell size 3D seismic or even 2D seismic acquired by the several hundred channel equipment. Obviously these kinds of seismic data could neither satisfy the needs of reservoir monitoring nor be used as the baseline survey of the time lapse seismic. The reservoir monitoring and remaining oil prediction for these oilfields thus becomes a difficult subject.
The Role of the Phase Behavior Model within the Numerical Simulation of in Situ Combustion Processes
Authors: Palma J. M. , Rodriguez E. 
Published: June 2013

Abstract
In situ combustion is a method with a large potential for recovery of heavy oil reserves, worse yet has many complexities that make it difficult its field scale development. One of these difficulties is precisely understand the different kinds of reactions taking place once the process starts. One tool that helps the engineer to understand what is happening during the process is the numerical simulation and specifically, for the case of combustion, the kinetic model. This model has two essential parts: the reactions and kinetic parameters. The reactions are developed based on the pseudocomponents used to characterize the fluid and the kinetic parameters were obtained from measurements made in the laboratory tests: Ramped temperature oxidation (RTO) and Accelerating Rate Calorimeter (ARC). The initial characterization of a fluid throws several components, which are subsequently lumped to the least amount possible without losing crude representation. These pseudocomponents must correctly represent the PVT behavior of oil. This matching to the actual behavior is achieved using suitable software. Based on the set of tests, it stars to match the behavior of the main fluid properties, for this, have previously chosen the most relevant parameters that may require matching to obtain a more representative model. Within the main tuning parameters are the critical properties of the fluid, accentric factors, lumping and splitting schemes and viscosity coefficients.
This paper proposes a scheme that helps to build a model that represents the phase behavior when the fluid is subjected to various conditions during the development of the combustion process. Matched the fluid model, this can be used in different scale models: CTO(Combustion Tube Tests), RTO or field. In this case, the successful development of the reactions involved in the kinetic model for in situ combustion process is linked the phase behavior model and the molecular weight of the pseudocomponents.
Using Geochemistry to Address H2S Production Risk due to Steam Injection in Oil Sands
Authors: Lamoureux-Var Violaine , Barroux Claire 
Published: June 2013

Abstract
Steam injection for enhanced oil recovery induces chemical reactions within the reservoir, called aquathermolysis, which can lead to in-situ H2S generation and to H2S production at the wellhead. H2S production risk is particularly acute in oil sand reservoirs because they contain sulfur-rich bitumens. To forecast H2S production risk in these conditions, a workflow based on geochemical investigation and reservoir simulation has been developed. It relies on (1) a quick estimate, using a dedicated technique, of sulfur content and thermal reactivity of a large number of reservoir samples to map the H2S production risk over the field; (2) carrying out more time-consuming aquathermolysis experiments on oil sand samples selected from step 1, to define a kinetic model for H2S generation based on atomic sulfur thermal reactivity; (3) transforming this sulfur-based kinetic model into a molecular SARA components-based kinetic model, usable in a compositional and thermal reservoir simulator; (4) simulating the EOR process with the reservoir simulator to calculate H2S/oil ratio at the wellhead.
The geochemical methodology has been applied to four oil sand samples from Athabasca. The results have underlined that sulfur content and sulfur thermal reactivity of oil sands measured with the quick estimation technique are well correlated with the amount of H2S produced from the more lengthy aquathermolysis experiments. Moreover, it was shown that the sulfur in the oil sand, when distributed among Saturates, Aromatics, Resins, Asphaltenes, Solid matrix and H2S, as a function of time and temperature of aquathermolysis, can be interpreted in terms of sulfur-based kinetic model. This model can be used for a calculation of H2S generation upon aquathermolysis at field production temperature and time scale, thus for estimating the H2S production potential.
As detailed in another SPE paper (Barroux et al., 2013), reservoir simulation has been used to simulate a SAGD process in a generic 2D model of an Athabasca oil sand. One main finding of this study has been that the H2S/oil ratio at the wellhead appears to depend mainly on the stoichiometry of the kinetic model.
Integral Study of the Influence of Well Trajectory on the SAGD Performance
Authors: Wu Yongbin , Jiang Youwei , Guan Wenlong , He Wanjun , Qiu Min , Lv Bolin 
Published: June 2013

Abstract
Due to various operational realities including the precision of the guiding tools that navigate the wells, actual SAGD well pairs in the field are seldom drilled perfectly parallel. And different patterns of trajectory of SAGD wellpair have a significant impact on the steam chamber development and overall recovery factor [1-4].
In this work, the focus is on the quantification of well trajectory on the SAGD performance. Based on the typical in-situ oil viscosities and reservoir properties of 11 SAGD pairs located in the Fengcheng heavy-oil region in Xinjiang Oilfield, different non-parallel patterns of injection-production-well-trajectory combinations including non-parallel vertically (upward inclination, downward inclination), horizontally and both directions between injector and producer well trajectories have been evaluated by using a detailed, 3D, flexible-wellbore reservoir-simulation model.
TTthe vertical and plane offsets in the horizontal segment both cause the smaller regional distance between injector and producer, resulting in better heat communication during preheating phase, while after converting to SAGD production phase, the better communication segment will cause faster steam chamber growth, leaving steam chamber in other segment developing poorly, therefore the SAGD peak oil rate and ultimate oil recovery factor are also affected. Especially, the case of plane and vertical offsets simultaneously cause the plane and vertical unparalleled, which causes the ultimate oil recovery factor 26.2% less than that of the ideal case without offset.
Estimation of Three-Phase Relative Permeability Isoperms in Heavy Oil/Water/Carbon Dioxide and Heavy Oil/Water/Methane Systems
Authors: Torabi Farshid , Akhlaghinia Manoochehr , Chan Christine 
Published: June 2013

Abstract
Three-phase relative permeability data is an Achilles' heel in the field performance prediction of the enhanced heavy oil recovery processes with numerical simulation. Minor inaccuracy could lead to erroneous predictions and, in turn, considerable revenue losses. A technique is proposed to utilize two- and three-phase displacement experiments in order to estimate relative permeability isoperms for a fluid system of heavy oil/water/gas. Three-phase flow zone is determined in a ternary diagram with residual oil and irreducible water saturations obtained from two-phase heavy oil/water displacements experiments. A developed fully implicit three-phase simulator mimics three-phase displacement experiments in the form of gas (carbon dioxide and methane) injection into a consolidated Berea core saturated with heavy oil (1174cP at 28°C) and water. Three-phase relative permeability data corresponds to a saturation path, drawn across the three-phase flow zone, is tuned to match simulated pressure drop, oil and water production with three-phase displacement experiment. Results have indicated, due to high residual oil saturation, a small three-phase flow zone can exist in presence of heavy oils. Although different curvatures have been obtained with relative permeability isoperms of oil, water, and gas phases; however, repeating experinemts with different gases (methane and carbon dioxide) indicates that relative permeability isoperms does not change siginificantly in presence of different gases. Comparison of the proposed procedure with the unsteady state technique indicates that unsteady state technique fails to provide reliable relative permeability data for numerical simulation purposes since it calculates three-phase relative permeability data at saturations out of the three-phase flow zone. In addition, in the case of water, unsteady state technique gives relative permeability values for a short range of water saturations. Proposed technique takes advantage of practicability of displacement experiments to estimate three-phase relative permeabilities it and, also, eliminates uncertainties with unsteady state method such as inaccurate derivative calculations. Although proposed method indirectly estimates three-phase relative permeabilities; sensitivity analysis shows a good margin of confidence with the relative permeability isoperms.