bluuebunny/crossref_metadata_2025_split huggingface dataset:
Steam Allocation Optimization in Full Field Multi-Pad SAGD Reservoir
Authors: Kumar Anjani , Warren Gregory , Joslin Kevin , Abraham Anson , Close Jason 
Published: March 2020

Abstract
Computing hardware and reservoir simulation technologies continue to evolve in order to meet the ever-increasing requirement for improving computational performance and efficiency in the oil and gas industry. These improvements have enabled the simulation of larger and more complex reservoir models. When working with steam assisted gravity drainage (SAGD) operations, determining the optimal steam injection rates and allocation of steam among various multi-well pads is very important, especially given the high cost of steam generation and the current low oil price environment. As SAGD operations mature, steam chambers start to coalesce and interact with each other, forcing producers to face declining oil rates and increasing steam oil ratios (SOR). Operators must work to reduce injection rates on declining wells to maintain a low SOR and free up capacity for newer, more productive wells. Steam injection and allocation between wells and multiple pads then becomes an exercise of optimizing cost, and improving productivity and net present value (NPV).
A case study is performed on a full field SAGD model by optimizing steam delivery aided by Artificial Intelligence (AI) and machine learning enabled algorithms for automated numerical tuning, and dynamic gridding technologies. The model contains 15 pads, 96 well pairs (192 wells), 12.6 million active simulation grid blocks, and represents a typical Athabasca formation geology and fluid properties. The proposed steam delivery optimization considers two main scenarios. The first scenario considers the case in which steam generation capacity is limited, and the optimization process intelligently determines the optimal well and pad level steam injection rates dynamically during the life of the project. The second scenario assumes that steam generation availability is not constrained and the field development plan is optimized based on steam required for maximum recovery from the field as fast as possible. A full field optimized development plan is created for the 15 SAGD pads and 96 well pairs.
Following the optimization, an increase in NPV and reduction in SOR is achieved for the entire field due to the efficient utilization of total available steam. The optimization study required several full field SAGD simulations to be completed in a practical time period, demonstrating that workflows such as this can be carried out for full field thermal models. These models can also be used to evaluate production responses due to varying operating strategies in the field.
This paper presents the optimization of steam allocation for a full field, multi pad SAGD simulation model. It demonstrates that advances in computing and reservoir simulation technology have enabled the simulation of full field models within a reasonable timeframe, allowing engineers to tackle a new class of problems that were previously impractical.
Scale Up of Multi-Phase Flow Properties from Micro to Core Scale
Authors: Bashtani Farzad , Kantzas Apostolos 
Published: March 2020

Abstract
Multiphase relative permeability is a key parameter in reservoir simulation. Typically, end-point based correlations are employed in order to obtain such curves for reservoir simulation purposes. However, those correlations are not capable of capturing micro-scale physical phenomenon which can significantly affect flow pattern at larger scales. Consequently, it is necessary to obtain a scale-up methodology in order to transfer the micro-scale physics to reservoir-scale. The objective of this research is developing a scale up procedure which can be applied to multi-phase flow properties obtained by micro-scale flow simulation to compute the equivalent macro-scale and core-scale flow properties having the micro-scale flow properties. Two different sets of media are employed: media representing unconsolidated oil sands and media based on experimental data obtained from the Mesaverde formation located in the Poweder River Basin. The former is used for validating the scale up methodology since not all the required information is available in the experimental data set. Pore scale network modelling is used for calculating micro-scale multi-phase flow properties such as porosity, and absolute and relative permeability. Then the generated subsegments are populated in space to reconstruct the macro scale medium. Flow properties of such medium are then obtained by network modelling and the proposed scale-up methodology and the results are compared. Furthermore, macro-scale media are distributed in space in layers and stacks of increasing and decreasing permeability to form a core-level medium. Single and multi-phase flow properties are then calculated by applying a pressure drop across the core. Permeability and relative permeability curves are calculated using the combination of mass balance, equation of state, and Darcy equation assuming steady-state flow while capillary pressure curve is obtained using the modified Leverett-J function procedure used in micro-to-macro scale up section. Results show good agreement between the expected and calculated properties for both unconsolidated and consolidated media. Finally, physical behavior observed at micro and macro scale is transferred to the core scale.
Experimental Evaluation of a Hydraulically Actuated Double-Acting Positive Displacement Quad-Pump System for SAGD Oil Production Applications
Authors: Ding Yuchang Bob , Li Ming , Ding Xuefeng Kevin , Su Ze Kevin 
Published: March 2020

Abstract
A novel positive displacement hydraulically actuated quad-pump system (Quad-Pump) has been developed to improve production in deviated and horizontal oil wells. This downhole pump technology can be used in high temperature environment with large volume production such as SAGD wells.
This paper describes the working principle of Quad-Pump downhole assembly and its hydraulic power system. Its operation advantages in SAGD environment are also presented.
Design details of a test apparatus (flow loop) used to test the newly developed Quad-Pump is provided in this paper. A series of experiment is designed to verify the pump working principle and evaluate pump performance. A 4.75" Quad-Pump was manufactured and tested with producing fluid temperature of 100 °C and 200 °C. Testing results show the pump can produce up to 3600 bbl/day of fluid when a 60 hp electric motor is used to power the hydraulic drive system.
Progress of the Artificial Lift Technology Suitable for Offshore Thermal Recovery in Bohai Bay, China
Authors: Liu Yigang , Shang Baobing , Bai Jianhua , Yu Fahao , Han Xiaodong , Gao Hao , Wu Xuanren 
Published: March 2020

Abstract
There is abundant heavy oil resource in Bohai Oilfield and thermal recovery is an effective method to realize the high-efficient development. Till now, several field pilots have been conducted. However, for the offshore thermal recovery well, the onshore common used rod pump artificial lift technology is not applicable. The ordinary electric submersible pump (ESP) system cannot be directly used either, because it cannot stand the high-temperature steam. Therefore, artificial lift technologies suitable for offshore thermal recovery well is developed in recent years.
For the ESP system, a high-temperature safety control system was developed, consisting of downhole safety valve, cable packer, and vent valve. The overall temperature and pressure resistance value could reach as high as 350°C and 21MPa, respectively. And the high temperature electric submersible pump could stand 250°C cyclic steam. This ESP system has been used in about 30 thermal recovery wells in Bohai Oilfild, satisfying the artificial lift requirements for the moment. With this ESP system, the overall process of each huff-and-puff cycle includes: lowering steam injection tubing, steam injecting, soaking, replacing production tubing, producing. That means two workover operations for tubing changes are required in each huff-and-puff cycle, which adds more cost to the oil production and has bad effect on the thermal recovery.
Considering the drawbacks of the current ESP system, a new concentric-tubing jet pump system suitable for offshore oilfield with function of both steam injection and oil production is developed. Besides, the matched surface equipment, such as oil-water-sand separator and power fluid pump, are designed. The temperature resistance of the designed jet pump system reaches 400°C. With this system, no workover for tubing replacement is needed any more during one huff-and-puff cycle. Till now, this new jet pump system has been put into field pilot in one thermal recovery well. Both the steam injection and oil production process completed successfully, indicating its applicability for the offshore thermal recovery wells. In this paper, the tubing string structure details of the jet pump system and the specific field operation process is introduced. This new artificial lift technology will be gradually applied in other wells to improve the thermal recovery effect because of its advantages comparing with ESP system.
Great progress and breakthrough of the artificial lift technologies suitable for offshore thermal recovery have been achieved in recent years in Bohai Oilfield, which will provide powerful technical support for the high efficiency development of the heavy oil resource in Bohai Bay.
Simulation of Non-Condensable Gases Co-Injection in Steam Assisted Gravity Drainage: The Role of Gas-Liquid Relative Permeability Curves
Authors: Mendoza Ana Maria , Kantzas Apostolos 
Published: March 2020

Abstract
The simulation of thermal recovery processes and their variations like non-condensable gases (NCG) co-injection with steam in SAGD require reliable gas-liquid relative permeability curves. In this work, three experiments were conducted to extract equivalent thermal relative permeability curves, and the experimental curves were used as an input in a numerical simulation model to evaluate the NCG co-injection with steam in SAGD. Heavy oil was diluted with toluene to mimic the viscosity of the oil at 165, 195, and 225°C. It was assumed that the viscosity variation was the main factor affecting the temperature-dependent gas-liquid relative permeability curves. Athabasca sand was packed, and after water and oil were flooded, gas was injected. Three sets of gas-liquid relative permeability curves were extracted through history match. The experimental curves were used as an input in a simulation model to evaluate the effect of the amount of NCG and time of NCG co-injection in SAGD using CMG STARS.
In contrast to previous simulation studies, the current simulation results showed that most of the injected gas leaked from the steam chamber and accumulated at the top of the reservoir. Part of the gas stayed at the top of the steam chamber insulating the steam chamber from the overburden rock. The gas that leaked from the steam chamber aided in additional recovery of oil. According to the simulation results, for a homogeneous reservoir, small amounts of NCG (about 1 mole %) can be co-injected with steam at any time of a SAGD project to reduce its energy requirements without a negative impact in the oil recovery. This amount can be progressively increased to further reduce the energy requirements and increase the ultimate oil recovery. With the introduction of the new experimental gas-liquid relative permeability curves, it would be possible to optimize NCG co-injection processes in SAGD with the use of numerical simulation, taking into account the flow behaviour of gases in the reservoir that usually is not considered.
Advances in Understanding the Scaling Potential for Thermal Wells: A Mechanistic Study
Authors: Habibi Ali , Fensky Charles , Roostaei Morteza , Mahmoudi Mahdi , Fattahpour Vahidoddin , Zeng Hongbo , Sadrzadeh Mohtada 
Published: March 2020

Abstract
Scale deposition and its treatment are crucial part of any thermal recovery method. High temperature variation, phase change associated with steam condensation and flashing, and complex flow dynamics of the wells make the thermal wells more susceptible to scale deposition. Several studies evaluated the type of scales collected from plugged sand screens; however, more investigation is required to address the reservoir conditions and wellbore hydraulics affecting the scaling potential of minerals at downhole conditions.
A laboratory workflow combined with a predictive modeling toolbox to evaluate scaling tendency of minerals for different downhole conditions has been developed. First, saturation indices (SI) for different minerals were calculated at reservoir temperature and pressure using water chemistry analysis and the Pitzer theory. Then, the mineral composition of deposited materials collected from thermal wells in Athabasca and Cold Lake area were characterized using Scanning Electron Microscopy (SEM), Energy Dispersive X-Ray Spectrometry (EDS), Total Organic Carbon (TOC) and Inductively Coupled Plasma Mass Spectrometry (ICP-MS) analyses. Finally, a comparison analysis was performed between predictive and characterization results.
The results of SI calculations showed that Mg-based silicates and Fe-based minerals are positive (SI&gt;5) even at high temperatures (T&gt;430 K). This indicates that the possibility of deposition for these minerals is high. Carbonates (calcite and aragonite) minerals are the most common depositing minerals. However, the extent of scaling index of carbonates is controlled by the concentration of Ca, HCO3, and CO3 in the water sample. The characterization results confirm the results of modeling part. The results of SEM/EDS, ICP-MS analyses showed that carbonates, Mg-based silicates, and Fe-based corrosion products are the most common depositing materials among all minerals.
The workflow presented in this study will help the industry to evaluate the scaling potential for thermal wells at different downhole conditions to make a proper decision to prevent plugging of the completion tools.
Fiber Optics Application for Downhole Monitoring and Wellbore Surveillance; SAGD Monitoring, Flow Regime Determination and Flow Loop Design
Authors: Soroush Mohammad , Mohammadtabar Mohammad , Roostaei Morteza , Hosseini Seyed Abolhassan , Fattahpour Vahidoddin , Mahmoudi Mahdi , Keough Daniel , Tywoniuk Matthew , Cheng Li , Moez Kambiz 
Published: March 2020

Abstract
Effective Steam Assisted Gravity Drainage (SAGD) operation relies on subcool management to reduce the risk of steam breakthrough. Monitoring of several parameters is performed to assure uniform development of steam chamber and heating of reservoir. This paper discusses the application of Distributed Acoustic Sensing (DAS), a monitoring platform to achieve reliable reservoir and wellbore surveillance in SAGD projects.
In this study, a comprehensive review of DAS deployment in oil and gas industry was performed including vertical seismic profiling, hydraulic fracturing, well/pipe integrity and flow profiling applications. Then, SAGD flow monitoring was investigated in detail. To utilize DAS in SAGD projects, knowing completion designs are necessary. Therefore, various SAGD completion designs and corresponding flow regimes were discussed as well. Finally, four flow loop designs were proposed to accurately simulate the complex wellbore hydraulics of the SAGD producer using DAS recordings.
This work started with an overview of DAS systems in downhole monitoring including real time high resolution vertical seismic profiling, hydraulic fracturing characterization and optimization, well and pipe integrity, leak detection and assessing completion effectiveness. Then, flow profiling including flow rate, flow fractions and flow regimes determinations using DAS were discussed with focus on SAGD monitoring. Completion designs directly impact on SAGD monitoring and DAS recordings, more specifically on flow regimes inside the tubing and annulus. Therefore, various completion designs with their tubing and screen sizes were presented and corresponding flow regimes were determined in both tubing and annulus. It was observed that flow regimes vary with type of completion design, liquid flow rate, steam breakthrough locations and tubing/screen sizes. Eventually, four flow loop designs were proposed based on the discussions for future DAS application.
This paper discusses existing completion designs and possible flow regimes in SAGD projects. Consequently, novel designed flow loops are introduced for DAS deployment to better understand the complex wellbore hydraulic of the well and measure the key parameters in optimizing the production operation. This study is a design stage for future quantitative measuring of flow profiling using DAS systems.
A Novel Experimental Method CCEC and Modelling of Methane Dissolution and Exsolution in Heavy Oil
Authors: Dong Xiaomeng , Xi Zhiyu , Badamchi Zadeh Amin , Jia Na , Gates Ian D. 
Published: March 2020

Abstract
The phase behavior and physical properties of heavy oil have been considered of great importance during cold production process. In this study, constant composition expansion and compression (CCEC) tests were performed to measure and evaluate the live oil expansion and compression under various temperatures and pressures conditions through a PVT apparatus. The live oil viscosity and density were also obtained from the the experiments. CCEC tests were conducted using the recombined live oil (with specified gas-oil ratio) in the PVT cell without mixing by utilizing three different constant volume change rates (i.e. "Fast Rate", 1.5 cc/min; "Moderate Rate", 0.015 cc/min; and "Slow Rate", 0.0003 cc/min) at 75°C and 15°C. During the expansion period, the total volume was monitored continuously until it reaches the cell maximum. Following the expansion process, the oil and gas were compressed back to the initial pressure following the same rates as the expansion stage. The P-V diagram has been plotted according to the PVT data, therefore pseudo-bubblepoint pressure was able to be determined based on the slope change of the P-V curve. It is found that pseudo-bubblepoint pressure determined at 75°C is higher than that of 15°C. For different volume expansion rates, a faster rate results in a lower determined pseudo-bubblepoint pressure, indicating a strong foamy oil behavior. On the other hand, however, the volume compression rate did not significantly affect the tendency of total volume reduction curve regarding the PVT experiments. The results obtained from the current study will facilitate industry to make better design for heavy oil reservoir development.
Enhanced Oil Recovery in Post-CHOPS Cold Heavy Oil Production with Sand Heavy Oil Reservoirs of Alberta and Saskatchewan Part 2 : Field Piloting of Cycling Solvent Injection
Authors: Coskuner Gokhan , Huang Haibo 
Published: March 2020

Abstract
Lloydminster area that straddles Alberta and Saskatchewan border contains vast amounts of heavy oil deposits in thin unconsolidated formations. It is believed that the heavy oil resource volume is in the 50 to 70 billion bbl range which makes it a world class resource. This work briefly summarizes the reservoir properties of these formations and provides an overview of the primary CHOPS recovery mechanism which only recovers on average 8% of the original oil in place. Therefore, the target for Enhanced Oil Recovery (EOR) processes are substantial. For instance, if an additional 2% (25% of the primary) oil can be recovered, this means an additional 1 to 1.5 billion bbls of oil production which can sustain the oil industry for many years in this area providing jobs and contributing significantly to government royalties.
A critical literature review of Cyclic Solvent Injection (CSI) as a post-CHOPS EOR technology is conducted. The key aspects of laboratory and theoretical studies of methane and propane mixtures, CO2 and propane mixtures and pure CO2 injection are summarized. A number of field pilots have been conducted using these solvents in post-CHOPS reservoirs in Lloydminster.
Implementation of field pilots is presented and results are discussed using publicly available data. It is shown that while CSI technology is technically successful, economic feasibility is more elusive. However, it appears that CO2 injection is more likely to be economically successful. Furthermore, the economic attractiveness of Cyclic CO2 Injection increases in an environment where greenhouse gas emissions are taxed and credits for disposal are available.
Development of a Rigorous Erosion Prediction Physical Model for Thermal Standalone Sand Control Screens
Authors: Hosseini Seyed Abolhassan , Roostaei Morteza , Velayati Arian , Soroush Mohammad , Mohammadtabar Mohammad , Mahmoudi Mahdi , Fattahpour Vahidoddin 
Published: March 2020

Abstract
Erosion of standalone screens in thermal wells can lead to significant damage and reduction in production. The dominant failure mechanism is the development of localized high-velocity hot spots in the screen due to steam breakthrough or flashing of the steam across the screen. This study provides methods to assess the erosion potential of screen material devices to determine the allowable production conditions which avoid erosion.
In this study the effects of impact angle, flow rate, sand concentration, particle size, and fluid viscosity on erosion are systematically investigated through a multivariable study. Experimental impingement testing is performed on screens in different orientations. Erosion is accessed by collecting weight loss data of the screen. Empirical erosion models are calibrated to provide predictions of functional relationships between erosion rate and varied parameters. Computational Fluid Dynamic (CFD) simulations are performed prior to the experimental work to visualize particle flow paths through the screen and determine local flow and impact velocities and wear patterns.
The performance of five existing erosion models is assessed through experimental testing of sand control screens. In order to translate short-term, high-velocity laboratory test results into field erosion predictions, an empirical erosion model is then developed and employed to provide well flow guidelines and minimize erosion potential. This suggests that the use of erosion prediction models in situations in which due to lack of time/data tuning is not possible, may still provide a reasonable estimate for the rate of material loss of the screen. The model is used to obtain threshold superficial velocity curves for several conditions.
The main concern associated with existing erosion models is that they do not consider sand production, nor do they account for many other factors that affect erosion process. An erosion model, coupled with CFD simulation, has been developed, that account for factors such as geometry, size, material, fluid properties and rate, sand size, shape, and density in downhole flow conditions.