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Steam generation for the purposes of thermal recovery includes facilities to treat the water (produced water or fresh water), generate the steam, and transport it to the injection wells. A steamflood uses high-quality steam injected into an oil reservoir. The quality of steam is defined as the weight percent of steam in the vapor phase to the total weight of steam. The higher the steam quality, the more heat is carried by this steam. High-quality steam provides heat to reduce oil viscosity, which mobilizes and sweeps the crude to the producing wells.
Summary Although the steam assisted gravity drainage (SAGD) process is still the preferred thermal-recovery process method for Athabascan deposits in Alberta, Canada, the interest in solvent-based techniques is growing due to reduce greenhouse-gas (GHG) emissions and water treatment concerns. In SAGD process, the thermodynamic trapping or subcool trapping is quite efficient due to strongly dependency of bitumen viscosity to temperature. As Irani (2018) discussed subcool trapping for solvent applications such Nsolv recovery process is inefficient due to week dependency of solvent viscosity to temperature. Other factor that effects the efficiency of the thermodynamic trapping is that the pure solvent injection recovery processes are operated at low pressure and it is not large temperature window for operators to apply large subcools. Such challenges make the pure solvent injection recovery processes a perfect case for deployment of Flow-Control-Devices (FCDs). FCDs have demonstrated significant potential for improving recovery in SAGD production wells. FCD experience in SAGD has been primarily positive and most producers performed better with FCDs. Application of FCDs are even more important in pure-solvent injection recovery processes due to large amount of solvent in the liquid pool and also low latent heat of solvent in comparison of water. With FCDs, the draw-down pressure is typically higher, resulting in flashing near the well bore, which is largely correlated to latent heat of the main fluid in the liquid pool. The flashing creates either steam or vapour breakthrough that causes the reduction in the relative permeability of the liquid phase. Such mobility reduction creates new equilibrium that stabilizes at lower rates. Such new equilibrium analysis is conducted by forcing a new temperature gradient to the model. Such condition creates an environment that leads into extensive solvent-breakthrough called solvent-coning in this study. The main output of such analysis is the produced solvent gas-fraction produced at the sand-face. The gas-fraction is an important input for the flow control devices (FCDs) especially at subcools close to the zero, as it controls its behavior. EoS model is also created and simplified to be possible to used in defining different equilibrium conditions. This type of analysis can help the operators evaluate the effectiveness of different type of FCDs, whether they are primarily momentum- or friction-style devices for application of the pure solvent injection recovery processes. This study is the first of its kind that couple the EoS and Darcy flow in the liquid pool. The model includes all the factors into a liquid-relative-permeability, and limitation of the liquid flow into producer is modeled by Darcy flow and reduction of such relative-permeability.
This paper presents performance, results, and learnings from the first solar enhanced-oil-recovery (EOR) project in the Middle East/North Africa region, including the motivation for solar EOR in Oman, a description of the enclosed-trough design used in the Amal field, and operations and performance data. The key objective for the pilot was to prove that the system is able to be deployed practically and economically at scale in the region. Thermal-EOR projects require a massive long-term thermal energy supply to heat the reservoir. Concentrating solar power (CSP) could provide this energy at a low cost after the initial capital investment; hence, the two processes are well-matched, especially in locations with high levels of solar radiation. The Sultanate of Oman, in common with many other countries in the region, has large heavy-oil reserves, which are best produced with thermal-EOR methods.
Javaheri, Mohammad (Chevron) | Tran, Minh (University of Southern California) | Buell, Richard Scot (Chevron) | Gorham, Timothy (Chevron) | Munoz, Juan David (Chevron) | Sims, Jack (Chevron) | Rivas, Stephen (Chevron)
Horizontal steam injectors can improve the efficiency of thermal operations relative to vertical injectors. However, effective in-well and reservoir surveillance are needed to understand steam conformance. Uniform steam-chest development improves the steam/oil ratio in continuous steam injection and accelerates recovery in cyclic steam injection. The conformance of the injected steam can be achieved by flow control devices (FCDs) deployed on either tubing or liner. A new liner-deployed FCD was used in a horizontal steam injector in the Kern River field. The liner-deployed FCD is intended to replace the tubing-deployed FCDs while reducing capital costs, surveillance costs, and well intervention costs for conformance control.
Fiber optics was used for surveillance, which is the most promising method in horizontal steam injectors considering reliability, accuracy, and cost. Fiber optic data enables monitoring the performance of liner-deployed FCDs as well as estimating the flow profile along the lateral length. Multimode distributed temperature sensing (DTS) optical fibers and single-mode distributed acoustic sensing (DAS) optical fibers were installed in the well for these objectives. Algorithms for interpreting DTS were improved to include a new technique, shape language modeling (SLM), and a probabilistic approach. The configuration of the FCDs was changed during the first well intervention, and it was monitored by DTS and DAS. Data from both DTS and DAS confirms the open/closed position of the sliding sleeve of FCDs initially and after the intervention. The probabilistic estimates of steam outflow in several FCD configurations match well with the theoretical outflow that is expected from the critical flow of steam through chokes installed in the FCDs.
Abstract In this paper, an assessment of a streaming dataset from all active steam injectors in a mature steamflood field is carried out to understand and identify data trends and patterns which indicate if a steam injector is out-of-design. The dataset utilized in this study comprises real-time data and data in motion available thanks to the newly instrumented asset. However, this high-frequency data, while available, was never analyzed before this study. This work showcases the first study of this kind that utilized high-frequency streaming data from steam injectors. As an exploratory study, it revealed powerful insights and patterns which explained not yet understood behaviors. The methodology employed involved management and analysis of large volumes of data and consideration of the steam distribution system network. The study revealed the root causes of out-of-design and questionable steam quality values, which led to a comprehensive report describing the events, recommendations, and remedial actions for 33 out of 111 active injectors. The business driver for this project relies on solving cases in which the real steam quality is unknown, or the injector is out-of-design, which affects the steam-flood delivery and, consequently, the oil production performance. The novelty of this study relies on the capability of identifying undesired events at very early stages. In similar oilfields under steam-flood operations, steam injectors performance is tested and analyzed every three to six months. Many undesirable events may occur and are ignored in the time window between tests. The study not only led to business value impact due to addressing un-optimized injectors but also started a new program for real-time monitoring. This research demonstrates the value of using high-frequency raw data for steam injectors diagnosis, management, and monitoring.
Qi, Zongyao (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Liu, Tong (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Xi, Changfeng (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Zhang, Yunjun (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Shen, Dehuang (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Mu, Hertaer (Xinjiang Oilfield, PetroChina) | Dong, Hong (Xinjiang Oilfield, PetroChina) | Zheng, Aiping (Xinjiang Oilfield, PetroChina) | Yu, Kequan (Xinjiang Oilfield, PetroChina) | Li, Xiuluan (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Jiang, Youwei (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Wang, Hongzhuang (State Key Laboratory of Enhanced Oil Recovery, PetroChina Research Institute of Exploration & Development, Research Institute of Petroleum Exploration & Development, PetroChina Co. Ltd) | Li, Huazhou (University of Alberta) | Babadagli, Tayfun (University of Alberta)
Abstract It is challenging to enhance heavy oil recovery in the late stages of steam flooding. This challenge is due to the reduced residual oil saturation, the high steam-oil ratio, and the lower profitability. A field test of CO2-assisted steam flooding technology was carried out in the steam-flooded heavy oil reservoir in the J6 block of Xinjiang oil field (China). The field test showed a positive response to the CO2-assisted steam flooding treatment including a gradually increasing heavy oil production, a rise in formation pressure, a decrease in water cut, etc. The production wells in the test area mainly exhibited four types of production dynamics, while some production wells showed production dynamics that were completely different from those during steam flooding. After being flooded by CO2-assisted steam flooding, these wells exhibited a gravity drainage pattern without steam channeling issues, and hence could yield a stable oil production. Meanwhile, emulsified oil, together with CO2-foam, was observed to be produced in the production well, which agreed well with what was observed in the lab-scale tests. The reservoir-simulation-based prediction in the test reservoir shows that the CO2-assisted steam flooding technology can reduce the steam-oil ratio from 12 m (CWE)/t to 6 m (CWE)/t and yield a final recovery factor of 70%.
Summary Over the last decade, steam assisted gravity drainage (SAGD) process has been successfully commercialized in Alberta and Saskatchewan thermal projects. Remediation of slotted liner wells in cases of erosion, or high gas/steam production later in life requires a different basis of design based on specific well challenges and will be challenged by the additional pressure drops due to poor or variable sand control productivity. Flow Control Devices (FCDs) have demonstrated significant potential for improving recovery in SAGD production wells. FCD experience in SAGD has been primarily positive and most producers performed better with FCDs. While for some operators the results are mixed or negative. The first generation of FCDs deployed in SAGD projects were not designed for such process and in some cases ill-suited. Furthermore, current modeling methods deployed have significant limitations that prevent appropriate FCD design or understanding, and although they can be history matched, typically do not provide useful insight into the pressure drops encountered or held understand the benefit of different devices. In order to design and optimize FCDs for SAGD, it is necessary to characterize different FCDs under the steam-breakthrough condition, and accurately model the flashing in the near wellbore area associated with low-subcool operation. The extensive chocking in FCDs, far greater than initial design, in many cases is due to near-wellbore flashing. This work is a continuation of three previous parts discussing the liquid pool modeling for SAGD producers (Irani, 2018, 2019 and Irani and Gates, 2018). The purpose of this work is to create a PI that fit for purpose of SAGD liquid pool pre- and post-flashing that mainly can be used for analysis and optimization of FCDs. With FCDs, the draw-down pressure is typically higher, resulting in flashing near the well bore. If there is flashing in the near wellbore area, the temperature gradient within liquid pool yields the saturation curve. The flashing causes the reduction in the relative permeability of the liquid phase, that creates new equilibrium that stabilizes at lower rates. Such new equilibrium analysis is conducted by forcing a new temperature gradient to the model. The main output of such analysis is the produced steam quality at the producer sand-face. The steam quality is an important input for the flow control devices (FCDs) especially at subcool close to the zero, as it controls its behavior. This type of analysis can help the operators evaluate the effectiveness of different type of FCDs, whether they are primarily momentum- or friction-style devices.
A novel Flow Control Device (FCD) for Steam Assisted Gravity Drainage (SAGD) production wells is presented. This device increases the thermal efficiency of the process and accelerates bitumen recovery by passively increasing its flow resistance as the produced fluid's subcool decreases.
Passive FCDs have been widely employed in SAGD applications to reduce the cumulative steam/oil ratio (C-SOR) and increase bitumen production. These passive devices react to density and/or viscosity changes of the produced fluid but do not select against steam. However, the novel FCD presented in this paper reacts specifically to the subcool of the produced fluid and offers a greater restriction as the produced fluid approaches the saturation curve and attains a steam component. Computational fluid dynamics (CFD) and experimental data have been used to minimize frictional pressure loss through the FCD while inducing subcool choking in pressures and flow rates typical of SAGD wells.
Selected test data clearly shows that the novel FCD increases its restistance sharply as the subcool approaches zero and as a steam component becomes present in the produced fluid. From initial hot water testing and extensive steam testing, a mechanistic model has been developed that uses physics and geometry to predict the performance of the device under a wide variety of thermodynamic conditions. The test data and this model were fed into numerical reservoir simulators to visualize the effects of this device in a typical SAGD completion. These simulations clearly show improved C-SOR and a more fully developed steam chamber for completions that utilize this novel FCD.
The novelty of this FCD is its proactive, yet passive, means of preventing steam production in SAGD wells. By preferring more subcooled fluid – either cooler or higher pressure – steam breakthrough and hot-spotting will be prevented or controlled, downhole equipment will be protected, and the SOR will be reduced. The thorough, mechanistic model for the new FCD allows for accurate interpolation and meaningful extrapolation, along with seamless integration with reservoir simulators to evaluate deployment strategy on a case-by-case basis.
Dong, Xiaohu (China University of Petroleum (Beijing)) | Liu, Huiqing (China University of Petroleum (Beijing)) | Lu, Ning (China University of Petroleum (Beijing)) | Wu, Keliu (China University of Petroleum (Beijing)) | Wang, Kun (University of Calgary) | Chen, Zhangxin (University of Calgary)
Summary Dual‐pipe steam injection technique has currently demonstrated technical potential for improving heavy oil recovery. It can effectively delay the occurrence of steam fingering and homogenize the steam injection profile along the horizontal wellbore. In this paper, first, we built a cylindrical wellbore physical model to experimentally study the steam injection profiles of a single‐pipe horizontal well and a concentric dual‐pipe horizontal well. Thus, the heat and mass transfer behavior of steam along the horizontal wellbore with a single‐pipe well configuration and a dual‐pipe well configuration was addressed. Subsequently, considering the effect of pressure drops and heat loss, a semianalytical model for the gas/liquid two‐phase flow in the horizontal wellbore was developed to numerically match the experimental observation. Next, a sensitivity analysis on the physical parameters and operation properties of a steam injection process was conducted. The effect of the injection fluid type was also investigated. Experimental results indicated that under the same steam injection condition, an application of dual‐pipe well configuration can significantly enhance the oil drainage volume by approximately 35% than the single‐pipe well configuration. During the experiments, both a temperature distribution and liquid production along the horizontal wellbore were obtained. A bimodal temperature distribution can be observed for the dual‐pipe well configuration. From this proposed model, an excellent agreement can be found between the simulation results and the experimental data. Because of the effect of variable mass flowing behavior and pressure drops, the wellbore segment close to the steam outflow point can have a higher heating radius than that far from the steam outflow point. From the results of sensitivity analysis, permeability heterogeneity and steam injection parameters have a tremendous impact on the steam injection profile along the wellbore. Compared with a pure steam injection process, the coinjection of steam and noncondensable gas (NCG) can improve the effective heating wellbore length by more than 25%. This model is also applied to predict the steam conformance of an actual horizontal well in Liaohe Oilfield. This paper presents some information regarding the heat and mass transfer of a dual‐pipe horizontal well, as well as imparts some of the lessons learned from its field operation.
Steam-foam has been used extensively in field trials to improve steam conformance, both for cyclic steam injection and steam flood. It is a proven process and very useful lessons can be drawn from these field trials to plan new projects. However, foam has not yet been used to improve SAGD (Steam-Assisted Gravity Drainage) performances. The aim of this paper is to examine the reasons for this situation and discuss the practical aspects of Foam-Assisted SAGD (FA-SAGD).
After a thorough description of the main mechanisms involved in these processes (steam-foam for cyclic steam injection and steam flood, as well as foam for SAGD), this paper proposes to review the differences between the various processes and their implications for the design and implementation of FA-SAGD. Finally, based on the lessons drawn from all the documented steam-foam trials, potential and drawbacks of FA-SAGD are presented together with suggested roadmaps to address these remaining and newly identified challenges to make this technology come true.
By definition, the driving mechanism of SAGD relies on gravity and involves the use of a pair of horizontal wells drilled a few meters apart, one on top of the other. This is completely different from foam applications with both cyclic steam injection and steam flood, which are typically conducted with vertical wells; in addition, cyclic steam relies on single wells only whereas steam flood is essentially a lateral displacement process. Steam quality, injection velocity, proximity of the injection and production wells and the risks associated with the formation of emulsions in the surface facilities are some of the issues that are typically not problematic for foam with conventional steam processes, but which need to be considered before FA-SAGD can be implemented in the field. This work concludes that FA-SAGD is feasible but that ignoring any of these aspects would very likely cause the process to fail in the field.
This study will provide useful physical considerations on the steam-foam process along with detailed guidelines for the implementation of the Foam-Assisted SAGD process in the field. It will be useful for engineers that are considering foam to improve the performances of SAGD by targeting a reduction of the steam consumption or the Steam Oil Ratio.