bluuebunny/crossref_metadata_2025_split huggingface dataset:
Insulated Coiled Tubing as a Tool for a Thermal EOR Process Through Non-thermal Well
Authors: Damour J. , Johannson D. 
Published: February 2017

Abstract
A thermally insulated coiled tubing is permanently inserted in a horizontal heavy oil producer well and used to circulate hot oil (or water) in the well to heat by conduction the vicinity of the liner, where the drawdown is the most important. This process can be used in non-thermal wells and improves heavy oil field production with a limited quantity of energy. This paper presents the typical completion applied for this EOR process, the well integrity concerns due to high temperature and the calculated oil production increase that is confirmed by field application.
The insulated coiled tubing is inserted into the horizontal well up to the well-toe. The production tubing is installed parallel to the insulated coiled tubing. The process is pumping hot oil at 230°C (or water) through the insulated coiled tubing. The heated oil is circulating from the well-toe back to the well-heel in the liner and heat the reservoir by conduction. This energy delivered to the reservoir will reduce the oil viscosity within a few meters from the liner and allow lower pressure drop.
A transient thermal model has been developed to model this EOR process. The equations on which the model has been built are Darcy's law, the continuity of the flow and the energy balance. Some assumptions were taken to simplify the model such as constant reservoir properties over space and time.
The model provides the temperature along the liner with max temperature at the toe and min temperature at the heel as well as the radial temperature in the reservoir. It models also the extra oil production allowed by the process. The temperature involved on the critical parts of the completion remain low and allow to apply this EOR on non-thermal wells. The field monitoring (temperature and net oil production) of the first pilots in Canada have confirmed the model results. The energy consumption requested is approx. 400kW, ten to twenty times lower than typical steam injection process. This process is not a competitor for steam injection but a good way to improve the production of heavy oil well with low CAPEX and low OPEX for specific fields where steam injection is not efficient like fields with thin reservoir.
In this tough period for the oil industry, this technology can be applied on existing producer wells without drilling injector wells. The combination of this process with waterflooding is a win-win association. Waterflooding brings the driven mechanism to the reservoir and the thermal process allows better oil flow at the well.
Performance Prediction of Solvent Enhanced Steam Flooding for Recovery of Thin Heavy Oil Reservoirs
Authors: Huang Shijun , Liu Hao , Xue Yongchao , Xiao Peng , Xiong Hao 
Published: February 2017

Abstract
More than half of heavy oil reservoirs in Western Canada are less than 5m thick and SAGD is generally not thought to be economically viable for such kind of reservoirs due to lack of Potential Energy of Gravity and significant heat losses to the overburden. Solvent enhanced steam flooding (SESF), a kind of enhanced steam flooding by co-injecting solvent with steam, has shown to be promising in enhancing oil rates in thin reservoirs. In this paper, a semi-analytical model is established for predicting production performance of SESF.
The model is mainly built based on Energy Conservation and Fick's Law to predict the steam front position as well as the solvent concentration profile in the reservoir. Besides, the blocking effects of steam condensate on solvent diffusion is modeled by introducing the oil-water two phase flow theory. Then, the model is divided into three parts corresponding to the three production stages of SESF, and they are semi-analytically solved successively. The proposed model is validated by comparing calculated oil production rate with the results of a numerical simulation method. The results indicate that the enhancement of oil production rate mainly happened in the early stage of the process which is achieved by the combining effects of heat and convection-enhanced mixing of solvent and heavy oil. On the basis of a sensitivity analysis for performance of SESF, it is realized that the operating thickness and solubility of a solvent are proportional to steam oil ratio reduction of SESF compared to conventional steam flooding. Besides, a relatively lower injection rate and a longer well spacing may result in higher thermal efficiency increment due to longer contacting time of solvent with crude oil.
Piloting SESF in a field has many challenges, especially when considering its main economic factors: production increase and solvent cost. Therefore, it is anticipated that considering the dynamic mass transfer and blocking effect of accumulated condensate on solvent diffusion in SESF process, which are important mechanisms of SESF with inadequate understanding in literatures, the newly developed model will help to better predict and design the future SESF heavy oil recovery projects in thin pay zones.
An Investigation into Temperature Distribution and Heat Loss Rate within the Steam Chamber in Expanding-Solvent SAGD Process
Authors: Liu Hao , Cheng Linsong , Li Chunlan , Xiong Hao , Xiao Peng 
Published: February 2017

Abstract
In order to save energy and to be more environmentally friendly, Expanding-Solvent SAGD (ES-SAGD) is proposed by adding solvents into the injection vapor. However, much heat may still be wasted due to early steam condensation, which is associated with heat transfer and phase behavior within the steam chamber during ES-SAGD process. The objectives of this paper are to study temperature distribution within the steam chamber and to evaluate the overall heat loss rate of ES-SAGD by using a semi-analytical model.
In the mathematical model, temperature and mass profiles within the chamber are implicitly represented rather than explicitly treated as beyond the edge of the chamber. By considering early steam condensation and phase change within the chamber, the model dynamically couples heat transfer equation and mass transfer equation. This approach allows us to clearly observe the heat loss rate within the chamber as well as to the overburden. The model is solved iteratively after the steam velocity at the chamber edge is determined by introducing theory of steam front stability. Finally, the proposed model is validated by comparing calculated temperature profile with the numerical simulation results.
The results of the analytical study reveal that, for solvents with smaller molecular mass, the temperature starts dropping deeper from chamber edge to the injection end, and the temperature gap between the two ends is larger than that of heavier solvents. Based on the calculated temperature profiles, it is considered that heavier solvents may not improve thermal efficiency, while lighter solvents can help to reduce heat loss rate to the overburden especially in the late stage of ES-SAGD. Moreover, although lighter solvents are always used to relieve the heat losses to the overburden, the heat wasted inside the steam chamber is severer than that of heavier solvents. Therefore, considering the total heat losses to the overburden and inside the steam chamber, the steam/oil ratio (SOR) of ES-SAGD in some ultra-thick reservoirs may be unfavorable even compared with that of SAGD.
On the basis of analysis for heat loss rate to the overburden and inside the chamber, several guidelines are presented to select solvent for ES-SAGD process. The proposed guidelines will help to better predict and design the future ES-SAGD heavy oil recovery projects.
Pore Network and Morphological Characterization of Pore-Level Structures
Authors: Mohammadmoradi Peyman , Bashtani Farzad , Goudarzi Banafsheh , Taheri Saeed , Kantzas Apostolos 
Published: February 2017

Abstract
Due to the computational simplicity and time efficiency, pore network and morphological techniques are two practical approaches for characterization of pore-scale microstructures. The methods are quasi-static and exploit pore space spatial statistics to simulate pore invasions. Here, both procedures are evaluated applying the workflows to pore-level micro-scale subdomains of Sandstone, Carbonate and Shale formations. A statistical approach is also utilized to improve the accuracy of Shale characterization by spatial restoration of fragmentary parts of organic matter. Post-processing results include relative permeability and capillary pressure curves, absolute permeability, formation factor, and thermal connectivity. The results appear to suggest that the accuracy of pore network modeling in the characterization of subdomains of micro-CT images is compromised by the presence of limited number of network elements, ignoring the resistance of pore elements, multi-scale structures, and tight/weak connections represented by an inadequate number of voxels. Pore network extraction negatively affects the accuracy of petrophysical predictions and ignores solid matrix and its thermal and electrical properties. The pore morphological approach accurately reproduces the fluid occupancies, efficiently deals with a variety of rock configurations and resolutions, and preserves connectivity and details of original images having more geometrical features than the pore network modeling. However, it predicts limited step-wised data points and realizations sourcing from its voxel-based nature. In addition, direct simulations confirm that stochastic conditional reconstruction of organic matter inside shale sub-volumes remarkably boosts the pore space connectivity and improves the accuracy of predictions.
Overcome Viscous Fingering Effect in Heavy Oil Reservoirs by an Optimized Smart Water Injection Scheme
Authors: Kadeethum T. , Sarma H. K. , Maini B. B. 
Published: February 2017

Abstract
Viscous fingering is a major obstacle to successful waterflooding in heavy oil reservoirs, as it results in water breakthrough and an undeveloped oil bank. To overcome viscous fingering, the composition of injected fluid can be tailored to a production scheme which optimally enhances oil recovery. Smart water can improve oil recovery through wettability alteration. However, wettability alteration also leads change in mobility ratio, which depending on value, may have either a negative or positive impact on oil recovery and water production and must therefore be carefully controlled.
In this study, smart waterflooding outperforms conventional waterflooding regarding oil recovery, with incremental recovery reaching as high as five percent. Moreover, smart waterflooding also significantly decelerates the water cut (WCUT) trend by subduing the effect of viscous fingering and decreasing the water relative permeability. Our results show that reducing a salinity of the injected fluid allows mineral dissolution reactions to raise effective permeability compared to that achieved by conventional waterflooding. Injection and production pressure affect mineral dissolution/precipitation and, consequently, effective porosity and permeability. Numerical simulation is used to analyze the potential of smart waterflooding as an enhanced oil recovery method in heavy oil reservoirs.
Sand Transport Modeling in Heavy Oil Gathering Network in Orinoco Oil Belt, Venezuela
Authors: Mendoza L. , Marin M. , Nascimento C. M. , Peraza R. 
Published: February 2017

Abstract
It is estimated that 70% of the world's oil and gas reserves are contained in reservoirs where sand production is or will become, a problem during the life of the field (Chen et al., 2010). Consequently, an effective sand management strategy may be critical to assure hydrocarbon production.
This study presents some results of a developed sand prediction model that has been used in Venezuela to understand sand transport characteristics in heavy oil and to estimate suspension and deposit critical velocities. In addition, results are presented of a sensitivity analysis of particle diameter and water cut carried out using a dynamic multiphase flow simulator to determine the accumulated solids content in some pipelines that helped to develop adequate cleanup procedures.
Pressure/volume/temperature (PVT) analyses were initially conducted in order to to reproduce the field characteristics of the produced fluid, including diluted fluid. Sensitivity studies were done to evaluate the effects of some parameters, such as grain size, flow rate, and water cut, to determine how they affect critical transport velocities. From these studies, the volume of particles deposited and the thicknesses of these deposits were determined, which helped the operator to define appropriate pigging program to remove sediments and to estimate the effect on the production system without an appropriate cleanup activity.
The initial result shows that the network gathering system operates below deposition critical velocity, however, a stationary sand bed is growing in pipelines near the wells.
In addition, the parametric studies revealed that when the particle sizes increase, the critical velocities increase. Besides that, critical velocity shows different behavior with water cut. Critical velocity increases when the water cut goes from 0% to 5%, but if this maximum value is overcome, the critical velocities decrease. Field data indicated that the amount of material received at the end of the system (CPF) during 500 days is 1600 tons of sand, but the maximum operation allowable pressure is reached 290 days after starting up the oil production. Dynamic flow simulations indicated that it is necessary to start the cleaning operation between 150 and 290 days after the start of production, depending on the available pressure to push the pig.
This paper summarizes the novel contribution of using dynamic flow simulations for sand prediction and a control model in one of the growing joint venture companies in FAJA PetroIndependencia in Venezuela.
Prediction of critical flow rate to prevent sand settling is important for flowlines that are in the design stage. This paper offers a valid approach to extend the predicted sand critical velocities to other fields in FAJA with similar crude conditions to aid in pipeline design.
A New Mathematical Model of Solvent-SAGD Process - Importance of Heat and Mass Transfer
Authors: Zargar Zeinab , Ali S. M. 
Published: February 2017

Abstract
The current in situ exploitation of oil sands in Alberta employs steam-based recovery methods, which are energy-intensive. A few companies are adding solvent to steam aiming to reduce steam requirements. The mechanism of oil recovery by steam with added solvent is not clear. Over the years, on several occasions- as at the present time- the oil industry has resorted to the use of solvents with steam in thermal recovery operations. The past trials with solvent were short-lived in view of the cost of solvents as well as the lack of success. Given the controversy regarding the use of solvents with steam, this work is intended to explain whether solvent injection with steam increases oil recovery or not.
In this work, a new analytical model is developed for describing the solvent-SAGD performance based on the combination of an overall solvent mass balance, heat balance and volumetric oil displacement and Darcy's oil rate using a mixture viscosity model as a function of temperature and solvent concentration ahead of front which satisfy the equilibrium in the system.
The objectives of this work are to predict: vapour-steam chamber growth, oil production rate, solvent production rate, solvent loss (or solvent retention) rate, and the effect of solvent type and concentration on the solvent-SAGD process. The results show that the rate of solvent retention increases over time, while the rate of solvent and bitumen production decreases.
The efficiency of this process is evaluated using cumulative steam-oil and solvent-oil ratio, which permits a comparison of the efficiency of SAGD and solvent-SAGD processes for different solvents. On the whole, the results of this approach give a better understanding of the mechanism of oil production during the solvent-SAGD process by interconnecting vapour chamber conditions and the conditions of heated and diluted oil ahead of the interface.
Water-Soluble Solvent as an Additive to Steam for Improved SAGD
Authors: Sheng Kai , Okuno Ryosuke , Wang Mingyuan 
Published: February 2017

Abstract
Coinjection of solvent with steam results in lower chamber-edge temperatures than those in steam-assisted gravity drainage (SAGD), which enable to decrease heat losses to the overlying formation rocks. However, use of highly volatile solvents, such as propane, can yield significantly slow bitumen production due to low chamber-edge temperatures. The objective of this research is to investigate the potential of water-soluble solvent as an additive to steam for reducing steam-oil ratio (SOR) while keeping SAGD-like rates of bitumen production.
The chamber-edge temperature for a given overall composition and operating pressure is defined as the temperature at which the vapor phase completely condenses with decreasing temperature. Thermodynamic predictions show that the chamber-edge temperature so defined will increase substantially if the solvent can partition into the aqueous phase at chamber-edge conditions. This is confirmedin numerical reservoir simulation for coinjection of steam with dimethyl ether (DME), as a water-soluble solvent, for Athabasca bitumen. In simulation case studies, coinjection of steam with DME (DME-SAGD) is compared with SAGD and coinjection of steam with C4 (C4-SAGD), in terms of SOR, bitumen production, local displacement efficiency, and solvent recovery. The steam-injection pressure is 35 bars for all cases, and 2 mol% of solvent is coinjected in solvent-SAGD simulations until the steam chamber reaches the side boundary of a 2-D homogeneous reservoir model.
DME is more volatile and less soluble in bitumen than C4 at their corresponding chamber-edge conditions. However, results show that DME-SAGD results in 35% lower SOR than SAGD while being able to increase bitumen-production rates of SAGD. Analysis of simulation results indicates that the solubility of DME in water not only makes the chamber-edge temperature higher than that of C4-SAGD, but also yields15% higher solvent-recovery factor than C4-SAGD. The main reason for the latter observation is that a much smaller fraction of the injected solvent is present in the vapor phase in DME-SAGD than in C4-SAGD. Also, DME dissolves in both water and bitumen, which results in the aqueous and oleic phases of nearly-equal density within the gravity-drainage zone near the edge of a steam chamber. This is the neutral regime of oil-water two-phase flow along the chamber edge between the two extreme cases: SAGD and C4-SAGD. Unlike in C4-SAGD, the reduced gravity segregation in DME-SAGD is expected to facilitate the mixing of condensed solvent with bitumen near the edge of a steam chamber.
An AI-Based Workflow for Estimating Shale Barrier Configurations from SAGD Production Histories
Authors: Zheng Jingwen , Leung Juliana Y. , Sawatzky Ronald P. , Alvarez Jose M. 
Published: February 2017

Abstract
An artificial intelligence (AI) based workflow is being deployed to develop and test procedures for estimating shale barrier configurations from SAGD production profiles. The data employed in this project is derived from a set of synthetic SAGD reservoir simulations based on petrophysical properties and operational constraints representative of Athabasca oil sands reservoirs.
Initially, a two-dimensional reservoir simulation model is being employed. The underlying model is homogeneous. Its petrophysical properties, such as the porosity, permeability, initial oil saturation and net pay thickness, have been taken from average values for several pads in Suncor's Firebag project. Reservoir heterogeneities are simulated by superimposing sets of idealized shale barrier configurations on the homogeneous model. The location and geometry of each shale barrier is parameterized by a unique set of indices. The resulting heterogeneous model is subjected to flow simulation to simulate SAGD production.
Next, a two-step workflow is followed: (1) a network model based on AI tools is constructed to match the output of the reservoir simulation (shale indices are inputs, while production rate and the steam-oil ratio are outputs) for a known training set of shale barrier configurations; (2) for a new SAGD production history generated via reservoir simulation with a shale barrier configuration that is unknown to the AI model generated in step 1, an optimization scheme based on a genetic algorithm approach is adopted to perturb the shale indices until the difference between the target production history and the production history predicted from the AI model is minimized.
A number of cases have been tested. The results show a good agreement between the shale barrier configurations predicted by the AI model with the configurations used to generate production histories in the reservoir simulation model (i.e., the "true" model). Thus, this optimization workflow offers potential to become an alternative tool for indirect inference of the uncertain distribution of shale barriers in SAGD reservoirs from data capturing field performance.
This works highlights the potential of an AI-based workflow to infer the presence and distribution of heterogeneous shale barriers from field SAGD production time-series data. It presents an innovative parameterization scheme suitable for representing heterogeneous characteristics of shale barriers. If this approach proves to be successful, it could allow the distribution of shale barriers to be inferred together with the impact of these barriers on SAGD performance. This would provide a basis for developing operating strategies to reduce the impact of the barriers.
2D Transient Simulation of Conjugate Natural Convection and Radiation within Thermal Wellbore Annuli
Authors: Lu Xueying , Xiong Wanqiang , Chen Zhangxin 
Published: February 2017

Abstract
In the petroleum industry, accurately estimating wellbore heat loss in thermal recovery processes remains a critical problem. One difficulty lies in simulating heat transfer and fluid dynamics within wellbore annuli. A literature survey shows that the state-of-the-art thermal wellbore simulators use empirical correlations to calculate the heat loss through wellbore annuli. As more sophisticated wells have been drilled, there is a growing need for a more detailed wellbore annulus heat transfer model. In this study, a 2D transient mathematical model is proposed for the conjugate natural convection and radiation within wellbore annuli. The governing equations consist of a continuity equation, a vorticity transfer equation, an energy transport equation and a radiative transfer equation (RTE). A finite volume approach with a second-order upwinding scheme is implemented for discretization. Newton-Raphson iterations are deployed for linearization. The algorithm is validated by consistence in simulation results compared with benchmark numerical solutions with the Rayleigh number up to 107. Parameters such as an aspect ratio, a radius ratio and a conduction-to-radiation coefficient are examined. A case study on vacuum insulated tubing heat transfer using Marlin Well A-6 data demonstrates the merits of the developed program by the consistence of simulation results compared with field measurements.