bluuebunny/crossref_metadata_2025_split huggingface dataset:
Use of Pressure Transient Analysis for Monitoring SAGD Steam Chamber Development
Authors: Zamani Amir , James Bruce , Hite Robert 
Published: June 2013

Abstract
One of the major problems faced in steam assisted gravity drainage (SAGD) development is monitoring steam chamber growth and conformance in a cost-effective way. Currently, this is primarily done using 4D seismic. However, each survey costs several million dollars, can generally be taken once a year in winter, and is limited in resolution. This paper investigates the use of pressure transient analysis (PTA) to monitor steam chamber conformance as a low-cost and on-demand alternative. While PTA has been widely and successfully used in the conventional oil and gas industry, there has been little application to SAGD.
A range of cases were investigated using reservoir simulation including steam flooding in a vertical well, 2D homogeneous and 3D heterogeneous SAGD cases. The heterogeneous cases included variations in permeability and shale layers along the injector. Pressure responses from different pressure gauge configurations such as a single gauge and multiple gauges along the injector were analyzed.
Results indicate that PTA can estimate total chamber pore volume reasonably accurately, despite a number of non-ideal conditions such as heterogeneity in saturations and countercurrent flow. Results also indicate that PTA potentially can be used in a number of ways to monitor steam chamber growth. First, changes in total steam chamber volume potentially can be monitored by observing changes in pseudo-steady state behavior (PSS) over time. More importantly, the character of the derivative plot changes with the maturity/shape of the chamber, indicating that the derivative plot can be used as a qualitative tool for monitoring steam chamber growth. In particular, the derivative behavior at a pressure gauge is governed largely by local steam chamber conditions near the gauge so that multiple gauges down the horizontal section can be used to monitor how different parts of the steam chamber are growing. However, there are limitations on what can be discriminated; differences in chamber shape have to be major for the derivative responses to be significantly different.
Sanding Onset and Sand Rate Prediction in Heated Oil Reservoirs
Authors: Wang Yarlong , Lu Baoping 
Published: June 2013

Abstract
Sanding onset and sand production rate in non-isothermal conditions are of interest both for post-CHOPS and thermally EOR process for production enhancement and sand control purposes. Critical drawdowns by different criteria representing different types of formation and sanding mechanisms are presented based on a fully coupled geomechanics framework under an uniform in-situ stress and non-isothermal condition. Comparisons between a validated isothermal condition and those of heated/cooled formations are performed. Sand production rate after the onset of sand production is also calculated and two different formulations representing sanding zone and displacement changes, respectively, at the wellbore wall for an open hole case is also evaluated.
Slurrified Heavy Oil Reservoir Extraction (SHORE): A Non-Thermal, in situ Recovery Method
Authors: Yale David P , Wang Jianlin , Meier Steven W , Herbolzheimer Eric , Kushnick Arnold P , Adair Neal L , Leonardi Sergio A , Smith Richard J 
Published: June 2013

Abstract
The oil sands of Canada are a rich resource whose extraction faces many challenges. The most common processes for recovering in situ resources (i.e. too deep to mine) involve heating the reservoir to reduce the heavy oil or bitumen viscosity to allow it to flow to wellbores where it can be produced. This paper presents an alternate concept for recovery of these resources that does not require heat to mobilize the bitumen and that is especially well suited to reservoirs that are too thin or too geologically complex for economic thermal recovery.
The process utilizes water injection to "condition" a reservoir interval sufficiently to relieve the overburden stress on the oil sand and increase its porosity and permeability. Establishing a pressure gradient between a set of injector and producer wells allows the production of a bitumen-sand-water slurry as the pressure gradient established overcomes the friction holding the reservoir sand in place. This produced slurry is then processed at the surface to extract the bitumen and the cleaned tailings are re-injected back into the reservoir to aid in the sweep of the in situ sand, support the overburden, and dispose of the tails. We have developed a first principles numerical model of the process that fully accounts for fluid flow and sand flow under reservoir conditions to simulate and understand the process. We have also developed a large scale (2 meter diameter sand pack) laboratory system to demonstrate the technical feasibility of the process under reservoir conditions.
The technology is still in the early stages of development, but the laboratory and numerical modeling efforts demonstrate promising technical potential of the process at a field-scale. The ability of the process to work in thinner and more geologically complex reservoirs than other in situ processes, and with lower CO2 and surface footprints than thermal and mining processes, could make this an attractive alternative recovery process for shallow to intermediate depth, in situ bitumen resources.
Coupled Fluid Flow-Thermoplastic Deformation of Oil Sand and Shale in SAGD Process
Authors: Gong X. , Wan R. , Mohamadi M. 
Published: June 2013

Abstract
Steam-Assistant-Gravity-Drainage (SAGD) has become one of the most commonly used thermal recovery processes to extract heavy oil from oil sand reservoirs, especially in Northern Alberta, Canada. However, due to geological history, interbedded shales (IBS) in the reservoir act as barriers due to their low permeability and as such hinder the progression of the steam chamber. Cap-rock integrity also needs to be ensured to prevent steam breakthrough. Therefore, a comprehensive investigation of geomechanics is required in modeling SAGD processes to properly address the above issues.
The numerical simulation of SAGD typically solves classic multiphase fluid flow equations, but with seemingly less detailed reservoir thermo-hydro-mechanical (THM) deformation calculations. However, the latter play a major role in SAGD responses in that the injection of steam significantly alters both the pore fluid pressure and temperature fields in the reservoir, which in turn impact on effective (skeleton) stresses. The latter inevitably leads to plastic deformations which eventually cause geomechanical failure inside and above the reservoir. Relevant to this issue is the dilatancy of geomaterials under shearing that increases the pore volume, and thus permeability. Hence, a proper treatment of such effects requires the coupling of multiphase flow with geomechanics.
In this paper, the THM behavior of the reservoir was studied through a proper constitutive modeling of the porous media. Specifically, a generalized density-stress-fabric dependent elasto-plastic model with stress-dilatancy and plastic damage as main ingredients was implemented into COMSOL (2012), a commercial finite element programming environment, to model geomechanical behavior during SAGD process. The strength and deformation of oil sand and IBS were evaluated through the respective stress-strain relationships, including stress path analysis. As such, geomechnical effects would be highlighted in view of the global operation and performance of the SAGD process.
Influence of Clay Minerals and Water Film Properties on In-Situ Adsorption of Asphaltene
Authors: Hematfar V. , Maini B. B. , Chen Z. 
Published: June 2013

Abstract
Asphaltene is the heaviest and most polar fraction of crude oil that creates many problems in various sections of petroleum industry including reservoir development, well tubing, surface facilities and pipelines. There have been many investigations of the consequences of asphaltene precipitation but the adsorption of asphaltene on rock surfaces and its impact on multiphase flow are not yet well understood.
In this work, the effects of asphaltene adsorption on wettability, relative permeability, and displacement efficiency in porous media were evaluated using flow experiments in sand-packs. Clay content and water film residing between pore surface and the hydrocarbon phase are recognized as the governing factors on the level of adsorption. These experiments involved pre- and post-adsorption measurements of relative permeability and recovery in sand packs. Adsorption on sand particles was induced and measured by extended injection of asphaltene solution with known concentration into the sand pack and collection of effluent samples for analysis. A spectrophotometer was employed to measure the asphaltene concentration of each sample and the dynamic adsorption curves were obtained by the subsequent material balance calculations. Adsorption reversibility was examined by analyzing the sand samples at different sections of sand-pack and the wettability alternation was inferred from the displacement behavior. Observed improvement in the displacement behavior is explained by the combined effects of desorption due to brine injection in the post adsorption waterflood and by reduction of interfacial tension due to surface active properties of asphaltene particles.
The experimental results show the importance of the existence and properties of water film on the extent of asphaltene adsorption. Presence of clay intensifies the adsorption phenomenon but its impact on two phase flow behavior and recovery depends on the brine salinity. Maximum adsorption occurred under direct contact of sand surface and asphaltene solution when no water film was present, which resulted in more oil-wet conditions, thereby reducing the relative permeability to asphaltene solution and recovery.
Mechanism of Heavy Oil Recovery Driven by Electromagnetic Inductive Heating
Authors: Mustafina Daria , Koch Andreas , Danov Vladimir , Sotskiy Sergey 
Published: June 2013

Abstract
Electromagnetically driven heavy oil recovery is considered as an alternative or as a complementary technique to steam injection methods. Inductive electromagnetic heating (IH) of heavy oil reservoir represents a complicated multi-physics process affected by operating conditions, reservoir and fluid properties. The IH takes place at frequencies of 10-3 - 1 MHz and the principle is based on the eddy currents generation in the mineralized connate water and its Joule heating.
This work presents a numerical simulation study of IH assisted heavy oil recovery. Previously developed coupled electromagnetic and reservoir simulation workflow is applied for this analysis. The workflow incorporates coupling between ANSYS Emag and CMG STARS. The study is focused on the recovery drive mechanism and influence of the reservoir and operating parameters on the production.
The IH is realized via closed inductor loop through which alternating current is passed. In our current study we consider two-dimensional pay zone completely surrounded by impermeable barriers and two horizontal "SAGD – like" well pairs, a pair of producer (lower well) and inductor (upper one). Different well constraint cases and the sensitivity to fluid and reservoir properties (pay zone thickness, depth of a reservoir, distance between wells and electrical conductivity contrast between pay zone and under-, overburden) are evaluated.
Operating pressure plays a significant role for the production. It defines the water boiling temperature and controls underground steam generation and consequently the drive mechanism. The sensitivity to fluid and reservoir properties is estimated in terms of production efficiency and recovery factor.
Previous works on this topic did not consider particularly IH in much detail. The results obtained in this work provide a comprehensive understanding on IH assisted heavy oil or bitumen production process, drive mechanism behind it and the ways of improvement of this technology.
Revitalizing Indonesia's Potential for Oil Production: The Study of Electromagnetically Heated Gravel Packs for Steam-produced Heavy Oil Reservoirs
Authors: Gunadi Trianto A. , Bae Wisup , Suranto Suranto , Lee Jaehoon , Hidayat Fiki , Netzhanova Akmaral 
Published: June 2013

Abstract
Indonesia, like many other countries, is also a producer of heavy oil. An example is from Duri Field which has begun producing oil successfully by steam-injection since 1985. However, the relatively shallow and unconsolidated formations have been causing noticeable and sometimes significant sand problems (up to 500 cubic meters per day) resulting in excessive workover operations and loss in production. Delaying production due to workover in a steam-assisted production method is costly, because over time the viscosity of the movable oil will increase again due to the temperature drop. This condition will make the oil even harder to produce when the well is reopened. Thus, an inexpensive but effective solution is needed to remedy this problem.
This paper proposes a new and cost-effective method for improving the efficiency of the steam injection methods for fields similar to Duri by using EM-heated proppant as gravel pack/frac-pack material in the production well. Installing an EM field generator in the wellbore and using EM-heated proppant will have a dual advantage over the conventional method by being more resistant to flow and being able to heat the near-wellbore region of the production well. By heating the near-wellbore region of the production well, the lowered-viscosity of the steam-contacted oil will be maintained as it enters the wellbore.
From results of simple calculations, backed up with laboratory observation, heated-proppant is intended to transfer and sustain heat as well as other thermal stimulation methods. Production increment is predicted to be small due to smaller heated radius; however the increased well longevity before a workover schedule and hands-free operation should provide a more cost-efficient well for producing heavy oils, in-time covering the installation cost of the EM Generator.
Experimental investigation of heavy oil recovery from fractured-porous carbonate core samples by secondary surfactant-added injection
Authors: Roschin P. V. , Vasquez Cardenas L. C. , Petukhov A. V. , Mikheyev A. I. 
Published: June 2013

Abstract
In this study, the description of Enhance Oil Recovery effectivity (EOR) of surfactant denominated reagent A, at the secondary waterflooding process for heavy oil recovery from fractured-porous carbonate core samples were investigated experimentally. For this experiment have been selected two cores, 14,75 cm long and 3 cm diameter were stacked in a long 3D confining core holder. In the first step, cores have been saturated by brine. In the second step, cores have been saturated of heavy oil through the water-saturated core sample for two-phase saturation. In the third step, we provided the injecting of water through the core sample for measuring oil recovery factor (by cold water 20ºC) simulating the primary recovery at these conditions. In the fourth step, was injected of 2 pore volumes of Reagent A through the core sample for measuring oil recovery factor (by reagent A) and simulating the slug. In the fifth step and final, was injected water through the core sample for measuring full oil recovery factor (by cold water) after slug of Reagent A. In the course of experiments, oil and water productions, pressure and temperatures of system were monitored and regulated carefully.
In Situ Bitumen Viscosity and Saturation Estimation From Core Log Integration for Canadian Oil Sands
Authors: Chen Jiansheng (Jason) , Bryan Jonathan 
Published: June 2013

Abstract
Canadian oil sands contain bitumen with viscosity above 100,000 cP at in-situ conditions. Thermal recovery of this oil requires knowledge of both the oil and water saturation profile, and also the oil viscosity profile in the reservoir. A core-log integration program was conducted for in-situ viscosity and saturation estimation. Two wells were logged with NMR and other special petrophysical logs. Core samples on these wells were taken for lab NMR and other special core analyses, with the goal of calibrating the logging tool outputs against the laboratory core data.
Lab NMR measurements were conducted on both core and extracted bitumen samples at different temperatures (12, 20, 50, and 80 °C). Viscosities were also measured for the bitumen samples at these same temperatures. Results show that when viscosity is higher than 100,000 cP, oil viscosity is no longer sensitive to T2 geometric mean, but it still strongly correlates to a parameter defined as the relative hydrogen index (RHI) of the oil (Bryan et al., 2003). RHI is a convenient way of expressing how much of the signal is lost due to the rapidly relaxing components that are not fully captured by NMR equipment. This is also consistent with LaTorraca's (1999) findings, but in the Canadian oil sands the bitumen samples have viscosity values much higher than the heavy oil samples studied by LaTorraca. These results demonstrate that, while in heavy oils the oil mean relaxation time is a valuable parameter for predicting in-situ viscosity, in bitumen formations the RHI term will be the primary NMR parameter for predicting oil viscosity.
The results from the lab NMR have been integrated with NMR and other petrophysical logs for viscosity and saturation estimation. A workflow is developed for core-log integration. First, oil/water T2cutoff values were calibrated using Dean-Stark core saturation and lab NMR measurements to establish the separation between oil and water signals in the spectra. Then the water amplitude and oil apparent amplitude were calculated from the NMR log using the calibrated T2cutoff. Finally, water saturation and RHI were computed from the amplitude; while oil viscosity was computed from the RHI using the correlations developed from core-log integration. The output from this study is a combined calculation of fluid saturations, oil viscosity and an indication of variability in pore size distribution within the formation. This allows for an improved understanding of optimal locations for well placement and the expected growth of the steam chamber within the reservoir during thermal operations.
Prediction of Effective Diffusion and Dispersion Coefficients, Considering Different Flow and Heterogeneity Properties of Porous Media
Authors: Taheri S. , Abedi J. , Kantzas A. 
Published: June 2013

Abstract
Heavy oil and bitumen are important hydrocarbon resources that are destined to play an increasingly significant role in the oil supply of the world. The total heavy oil resources are estimated to be about 10 trillion barrels, nearly three times the conventional oil in place in the world. The efficient and economic recovery of heavy oil and bitumen reserves is a crucial technical challenge. Most of these reserves lie deep inside the earth's crust and are not easily recoverable owing to their very high viscosity. Hydrocarbon solvent-based processes are thought to be effective EOR technologies for heavy oil and bitumen production.
An important feature of the miscible fluid displacement is the mixing of the solvent and oil. This mixing occurs on the microscopic scale and result from the diffusion and dispersion process. Mixing effect has positive and negative effects on the miscible process. It could exerts a considerable damping effect on the growth of viscous and gravity fingers as an advantage of the dispersion and diffusion and on the other hand mixing of the solvent with oil in a reservoir decreases the effective strength of the solvent, which can have annoying effect on the miscibility and recovery efficiency. So, correct treatment of this mixing effect within the simulation of the miscible recovery process is very important.
Mixing of the solvent and oil is governed by the diffusion and dispersion coefficients. For measuring these coefficients, we must depend largely on experimental measurements of them, because no universal theory permits their accurate a priori calculation. There are many influencing parameters on the mixing process during solvent injection into porous media. Designing an experiment to investigate all the effective parameters is extremely difficult (if not impossible) and time consuming. So, based on the sub-pore scale modeling method, a special program has been developed to investigate the mass transfer process in any porous medium, considering all medium properties. A realistic image of the porous medium without any simplification is directly used in the program.
Developed program used the porous medium image directly, so, heterogeneity effect could be investigated. Pore and throat size distributions, as an important heterogeneous parameter, has a unique effect on the diffusion and dispersion coefficients. A comprehensive study of the pore and throat size distribution effect on the mixing coefficients will be presented in this paper.
Advanced Numerical Simulation of Solvent Vapour Extraction (SVX) Processes
Authors: Imran Muhammad , Knorr Kelvin(Kelly) D , Jia Peng 
Published: June 2013

Abstract
This work presents advanced numerical simulation techniques that were developed to improve the history matching and predictive capability of both laboratory and field scale SVX processes. An algorithm was developed to incorporate the time dependence of SVX processes in the CMG STARS software; it incorporated a non-equilibrium solvent solubility method. A new methodology was developed to correct for excessive numerical dispersion effects at field scale gridblock sizes. Thermal effects due to solvent dissolution in heavy oil were also studied.
The advanced numerical simulation technique was constrained by PVT mixing experiments designed to generate mass transfer and non-equilibrium solvent solubility datasets for the solvent–oil system. The numerical models were tuned from the datasets obtained from three lab scale 3D SVX physical model experiments and by the use of a unique set of gas-liquid relative permeability curves (applicable to all three experiments) that employed the solvent mass transfer rate as the history matching parameter. The three physical model experiments varied in only model geometry and horizontal well placement. A relationship between reaction frequency factor (ra) and gridblock size was developed to correct for excessive numerical dispersion effects at field scale gridblock sizes. Thermal effects were incorporated in the numerical model by properly assigning the thermal parameters describing the fluid and porous media heat capacities and vaporization enthalpy coefficients.
The studies found that simulations conducted using a non-equilibrium solvent solubility method yielded more realistic relative permeability (kr) curves. The dissolved solvent concentrations and diluted oil viscosity profiles were also more realistic. The viscosity-reducing potential of the thermal effects of solvent dissolution were found to be negligible when compared with the viscosity-reducing effects of solvent dilution.