PRISM :: Browsing by Author "Chen, Shengnan"

Browsing by Author "Chen, Shengnan"

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Open Access
Acoustic Properties of Oil sands
(2017) Patel, Gaurav Jayeshbhai; Gates, Ian Donald; Chen, Shengnan; De la Hoz Siegler, Hector
A well-known, efficient and economical method to recover bitumen from oil sand reservoirs is the Steam-Assisted Gravity Drainage (SAGD) process. To monitor this recovery process, each year, operators conduct seismic shoots of the formation and from the interpretation of the data, they estimate the vertical and areal extents of the steam chambers around the SAGD well pairs within the reservoir. One of the important property that is required to process seismic data is the speed of sound in oil sands and bitumen. A lot of laboratory data is available on velocity in oil sands at different pressure and temperature but nearly all are measured at ultrasonic frequencies which is in the hundreds of thousands of Hz. However, seismic shoots are conducted at between 10 and 100 Hz and it has been shown that there is a significant difference of the speed of sound at ultrasonic and seismic frequencies. In the research, a novel large scale (2.3 m long, 2 5/8 inch diameter) high pressure core holder apparatus has been designed and constructed to measure the speed of sound versus pressure and temperature at seismic frequencies. The data obtained from the new experimental apparatus compares well with data from published literature. The same apparatus has been used to study the audible frequency effects on oil sand as a result of viscous dissipation and on bitumen viscosity.
Open Access
An Advanced Sand Control Technology for Heavy Oil Reservoirs
(2017) Zhang, Zhen; Chen, Shengnan; Dong, Mingzhe; Gates, Ian
It remains a challenge to control sand production from interfering in the production of oil and bitumen from unconsolidated formations in the upstream oil industry. The Wrapped Punch Screen (WPS), when applied under the conditions of open-hole and unconsolidated formations, can provide highly reliable sand control ability as well as lower costs, compared to the Wire Wrap Screen and the Premium Mesh Screen. It can also lead to a higher long term productivity compared to other open-hole completion methods. This is due to its stainless-steel construction that offers highly anti-corrosive and erosion-free advantages. This study has investigated and compared different types of sand control screens commonly used in heavy oil reservoirs, including the slotted liner screen, the wire wrapped screen and the WPS screen in terms of the sand control ability, performance under pressure and cost in the manufacturing process. Two experiments were conducted to compare the pressure performance and fluid productivity of the slotted liner and WPS. Key comparisons were based on six main evaluation points that are detailed Chapter 3, which addresses design, and in Chapter 4, which provides a dynamic fluid production analysis.
Open Access
Application of Dilation-Recompaction Model in Hydraulic Fracturing Simulation
(2015-04-30) Huang, Xuemin; Gates, Ian; Chen, Shengnan
Production of unconventional oil and gas resources has played a significant role on the global energy supply, of which tight oil and gas reservoirs are drawing greater focus. The key enabler behind tight oil and gas production has been multi-stage hydraulic fracturing along extended reach horizontal wells. Despite many advances in multistage fracturing, it still remains unclear how to model the hydraulic fracturing process to provide the basis to optimize and predict the properties of fracture networks and associated enhancement of fluid production. This is especially difficult since it is not possible to directly image the fracture network since the length scales of the network can be relatively small. In typical reservoir simulation practice, the conventional way to represent the hydraulic fracture is to place transverse plane around the horizontal well – this means that the user has prescribed the orientation and length scale of the fracture before the simulation has started. In the research documented here, we explore a dynamic fracturing approach that uses a dilation-recompaction model in a reservoir simulator to model hydraulic fracturing. The key strength of the approach is that the geometry and length scale of the fracture is not prescribed a priori. This means that the model can be relatively easily constructed and matched to field data. The results of the simulation show that dilation-recompaction model is capable of modeling the hydraulic fracturing process prior to the flow-back and production. The oil, gas, and water rates of the model are well matched to the field data and the extent of the fractured zone predicted by the model is reasonable. A sensitivity analysis using the history-matched model reveals that the design of hydraulic fracturing operation suggests that a larger number of stages and fracture fluid volume injected will raise oil and gas rates, but it remains unclear if the incremental oil and gas will provide enough revenues to offset the additional costs from increases of stages and fluid injection volume.
Open Access
The Application of Fishbone Wells in Steam-Assisted Gravity Drainage
(2022-09) Edafiaga, Benjamin; Gates, Ian; Gates, Ian; Wong, Ron; Chen, Shengnan; Haddad, Amin; Hejazi, Hossein; Chen, Zhangxing
Apart from cost, major challenges facing the recovery of bitumen from Canadian oil sands are the amount of energy utilized per volume of bitumen recovered as well as the amount of greenhouse gas (GHG) emitted to the environment. The situation is even worse in reservoirs that are considered to be challenging or difficult-to-produce due to the reservoir geology. Steam-assisted gravity drainage (SAGD) is the primary in-situ recovery technique for bitumen recovery in Northern Alberta, Western Canada. Within the reservoir, steam chamber conformance is a major control on the efficiency, economic performance, and GHG emissions intensity of the process. There is a search for ways to significantly reduce the costs and emissions of SAGD. Multilateral wells possess the potential to contribute towards this goal. To date, different theoretical designs of multilateral wells have been proposed in literature. One of the most common designs studied is the fishbone well configuration. This configuration has large reservoir contact and thus enhances the productivity of the well. While the merits of the application of multilateral wells are well documented in lighter oil systems, an understanding of the best operating conditions for the use in oil sands reservoirs is poorly understood. The research documented in this thesis examines in detail how fishbone multilateral wells can be used to improve the performance of SAGD. In summary, the results demonstrate that fishbone well are able to improve steam chamber conformance and ultimately minimize cumulative steam-oil ratio (cSOR), maximize ultimate bitumen recovery, improve net present value (NPV), and reduce GHG emissions. Therefore, fishbone multilateral wells should be considered for future SAGD operations.
Open Access
Artificial Neural Network Modeling of Well Performance in the Garrington Field, Cardium Formation
(2018-12-21) Kakar, Kushagra; Pedersen, Per Kent; Jensen, Jerry L.; Chen, Shengnan; Clarkson, Christopher R.
A number of studies have reported the use of artificial neural networks (ANNs) to predict tight formation well performance. ANNs are attractive because they do not require pre-conceived models (are “data-driven”), can accommodate numerous inputs, and allow for nonlinear relationships. There are reports of using ANNs in ‘factory mode’ to aid well and stimulation design where fast development of areas precludes devoting the time and effort to individually design each well. The analysis and experience of this study shows, however, that ANNs have limitations which can go unrecognized and lead to faulty predictions: 1) We find that investigators may not have adequately tested the ANN by overlooking the performance for the testing and validation tests, and only reporting the “R” values (correlation coefficients) for the training results. 2) There is a large variability between ANNs trained using the same dataset. We find that, even when we select only those ANNs which give R > 0.85, there can be significant discrepancies between predicted and actual performance. 3) ANN models which exclude the operator may give poor results and make some variables appear more important than they actually are. 4) Among other explanatory variables, the early time linear flow parameters are very important. This thesis illustrates this work using data from the tight oil Garrington Field (Cardium Formation). It makes recommendations to ANN workflows which will guide practitioners in the appropriate development, testing, and application of ANNs in this important topic.
Open Access
Asynchronous Injection-Production Process: A Method to Improve Water Flooding Recovery in Complex Fault Block Reservoirs
(2020-01-30) Yuan, Shibao; Wang, Rui; Jiang, Haiyan; Xie, Qing; Chen, Shengnan; Xu, Bo; Li, Lehong; Zhang, Yupeng
The complex fault block reservoir has the characteristics of small area and many layers in vertical. Due to the influence of formation heterogeneity and well pattern, the situation that “water fingering is serious with water injection, on the contrary, driving energy is low” frequently occurs in water flooding, which makes it difficult to enhance oil recovery. Asynchronous injection-production (AIP) process divides the conventional continuous injection-production process into two independent processes: injection stage and production stage. In order to study oil recovery in the fault block reservoir by AIP technology, a triangle closed block reservoir is divided into 7 subareas. The result of numerical simulation indicates that all subareas have the characteristic of fluid diverting and remaining oil in the central area is also affected by injected water at injection stage of AIP technology. Remaining oil in the central area is driven to the included angle and border area by injected water and then produced at the production stage. Finally, the oil recovery in the central area rises by 5.2% and in the noncentral area is also increased in different levels. The AIP process can realize the alternative change of reservoir pressure, change the distribution of flow field, and enlarge the swept area by injected water. To sum it up, the AIP process is an effective method to improve the oil recovery in complex fault-block reservoir by water flooding.
Open Access
Characterization of tight and shale unconventional gas reservoirs using low field NMR
(2023-01-26) Solatpour, Razieh; Kantzas, Apostolos; Torabi, Farshid; Aguilera, Roberto; Clarkson, Christopher; Chen, Shengnan; Wong, Ron
Unconventional petroleum resources, especially tight and shale reserves, constitute an increasing frontier of reserves additions as conventional production declines. In these sources, reservoir characteristics have significant value in reserve estimation and flow modelling. These characteristics are challenging parameters to measure. On the other hand, oil and gas sectors are continually looking for ways to do more with less environmental impact and greater operational efficiency. Nuclear Magnetic Resonance (NMR) offers fast and non-disruptive detection of the reservoir samples properties. The purpose of this research is to investigate the interactions between tight and shale rocks with hydrocarbons using NMR technique. This thesis mainly presents routine and new experimental and numerical methods of measuring porosity, permeability, residual saturations, and excess and absolute adsorption isotherms. The experiments were conducted on different porous media such as shale cores, tight sand cores, activated carbon, and sandpacks at pressures up to 7 MPa. In this thesis, for 150 cores, permeability was estimated using all existing NMR permeability correlations. In addition, irreducible saturations were presented for these cores. A new method to obtain residual saturation using the area under the NMR relaxation distribution curves was introduced. Permeability and irreducible saturation models are compared based of their standard error deviation from the independently measured ones. For organic porous media, the NMR decay curve of hydrocarbons exhibited a logarithmic behaviour at early times. Based on this observation, a new method of obtaining absolute adsorption was developed. The time when the decay curve shifts from logarithmic to multi-exponential behaviour was defined as sorption cut-off time. Adsorption isotherm hysteresis of methane in Duvernay shale samples was demonstrated using the newly developed method. In this research, for the first-time Low-Field NMR relaxometry with a frequency close to logging tools directly and without the use of correlations is used for quantitative determination of adsorption isotherms of methane in shale reservoirs. Isotherms derived by the new method better described the physical behaviour of hydrocarbon in organic porous media as it captures the effect of phase transition and measures critical pressure in organic porous media, which is different than the ones in non-organic porous media. Moreover, with this new fractal model, total hydrocarbon in place, adsorbed, and free hydrocarbon can be estimated from a single NMR experiment. This thesis is beneficial in understanding existing tight and shale reservoir characterization methods and introduces more advanced and reliable techniques to measure the properties of these reservoirs. In chapter 3 to 7 of this study, currently available methods of tight and shale reservoir characterization are presented. Then a new approach is provided for each case which is less computationally demanding, and calculations are easier to perform. Moreover, in most scenarios only a single NMR measurement is needed.
Open Access
Comparative Simulation Study and Economic Analysis of Thermal Recovery Processes in Athabasca Reservoirs
(2018-04-30) Iyogun, Christopher Omokhowa; Chen, Zhangxing (John); Chen, Shengnan; Maini, B. B.
Simulation studies of three thermal recovery processes used in Athabasca reservoirs have been carried out for a 10-year production period. The recovery processes studied are Steam-Assisted Gravity Drainage (SAGD), Fast-SAGD, and Expanding Solvent-SAGD (ES-SAGD). Normal pentane (n-C5) was the solvent of choice used in ES-SAGD simulations with its molar concentration varied from 2% to 5.9%. The main objective of this study is to conduct an economic analysis of the three recovery processes with the goal of determining the most economically viable process. The economic indicator that will be assessed to ascertain the most viable recovery process is their Net Present Value (NPV.) 2D simulation studies based on homogeneous Athabasca reservoirs have been performed. Results obtained show that of the three recovery processes, Fast-SAGD had the lowest cumulative oil produced, followed by SAGD and ES-SAGD, the highest. The cumulative oil produced also increased with increasing molar concentration of n-C5. Furthermore, it was shown that as expected, the CSOR of ES-SAGD was the lowest of them while that of Fast-SAGD was the highest. The CSOR of the ES-SAGD processes reduced as the concentration of the n-C5 increased. The economic analysis showed that of the three recovery processes, ES-SAGD is the most economically viable process. Furthermore, the effect of solvent on the viability of ES-SAGD over the other recovery processes is dependent on the price regime of pentane. In this analysis, two extreme price regimes were chosen and the result showed that for a low price regime, varying the molar ratios of n-C5 had a significant effect on the NPV up to a point before its effect diminishes. In fact, increasing the molar concentration of n-C5 from 2% to 3.76% significantly increased the NPV while further increasing it from 3.76% to 4% and thereafter to 5.9% had no noticeable effect. However, it seems that increasing it from 3.76% to 5.9% had a diminishing effect especially after the 3-year period. Nevertheless, the significant NPV improvement ES-SAGD has over SAGD and Fast-SAGD diminishes once the price regime of pentane is more than 3 times that of oil. In fact, this high price regime showed that 5.9% molar concentration of n-C5 is no longer more viable than the SAGD counterpart. There is still some benefit up till about 4% molar concentration of n-C5 but this benefit is greatly diminished. In conclusion, ES-SAGD has been shown to be the best recovery process for Athabasca reservoirs based on economics but further research is needed to evaluate the molar concentration that will provide the most economic benefit for a real Athabasca reservoir.
Open Access
Comprehensive Performance Optimization of a Water-Alternating-Carbon-Dioxide Reservoir
(2018-04-30) Li, Xiaoying; Chen, Shengnan; Hassanzadeh, Hassan; Dong, Mingzhe
An evolution-based algorithm is applied to comprehensively optimize a field scale reservoir developing process, spanning from the primary production to the waterflooding and then the miscible water-alternating-CO2 (CO2 WAG) process. Effects of 98 operational parameters on the net present value (NPV) are analyzed and quantified, including the primary production duration, water injection rates during the waterflooding process, process onset time, gas and water injection rates of CO2 WAG process and producer bottomhole pressure (BHP) during each production stage. The impacts of geological uncertainty are evaluated using multiple reservoir realizations. It has been found that durations of the primary production and waterflooding processes have the most pronounced impact on the final NPV. The oil recovery of the comprehensive optimization scenario has been enhanced by 23.37% compared to that of the conventional WAG optimization. This is mainly due to the shorter durations of the primary and waterflooding processes.
Open Access
Conversion of Petroleum Coke into Valuable Products using Catalytic and Non-Catalytic Oxy-Cracking Reaction
(2018-04-20) Manasrah, Abdallah Darweesh; Nassar, Nashaat N.; Chen, Shengnan; Kopyscinski, Jan; Pereira Almao, Pedro; Thurbide, Kevin B.
Every year millions of tons petroleum coke (petcoke) is generated as a by-product from bitumen and heavy oil upgrading due to the increasing demand in energy. Petcoke is a carbonaceous solid consisting of polycyclic aromatic hydrocarbons with low hydrogen content, derived from the processing of oil sands and oil refineries. The upgrading and treating of petcoke typically include thermal techniques such as gasification and combustion. However, several challenges limit the effectiveness of these conventional processes such as sulfur and CO2 emissions as well as high energy and costs associated with low efficiency. Therefore, finding an alternative, efficient, environmentally-friendly and cost-effective technology to treat these massive amounts of petcoke is needed. In this study, an oxy-cracking technique, which is a combination of oxidation and cracking reactions, is introduced as an alternative approach for petcoke utilization. This oxy-cracking takes place in basic aqueous media, at mild operation temperatures (170-230 oC) and pressures (500-600 psi). The oxy-cracking reaction mechanism was investigated using Quinolin-65 (Q-65) as a model molecule mimicking the residual feedstocks. Theoretical calaculations along with experimental reaction were carried out on Q-65 to explore the reaction pathways. Consequently, several operating conditions on petcoke oxy-cracking were investigated, such as temperature, oxygen pressure, reaction time, particle size and mixing rate to optimize the solubility and selectivity of oxy-cracked products. To enhance the oxy-cracking reaction conversion, an in-house prepared copper-silicate catalyst was introduced and characterized using BET, SEM, FTIR and XRD techniques. The oxy-cracking technique successfully converted the petcoke into valuable products, particularly humic acids analogs with other functional groups such as carboxylic, carbonyl, and sulfonic acids, as confirmed by FTIR, XPS and NMR analyses, in addition to minimal emission of CO2. Interestingly, based on the experimental findings, the metal contents in the obtained oxy-cracked products are significantly lower than that in the virgin petcoke. Consequently, the heating value and oxidation behaviour of the oxy-cracked products was investigated using TGA. These results showed that the oxy-cracked petcoke is easier and faster to oxidize compared to the virgin petcoke, suggesting that the oxy-cracked petcoke could be an alternative-clean fuel for power generation.
Open Access
Development of a Standalone Compositional Simulator for Modelling Multiphase Flow and Temperature Distribution Along Wellbore
(2019-12) Xiong, Wanqiang; Chen, Zhangxing; Azaiez, Jalel; Chen, Shengnan; Qin, Guan; Swishchuk, A. V.
Well modeling of multiphase flow and temperature flow along a wellbore has wide applications in the petroleum industry especially in unconventional oil and gas recovery processes. Also, wellbore modeling can be applied in a geothermal well for optimizing production parameters. The main research works completed in this study include building mathematical equations for wellbore modeling and development of a standalone wellbore simulator. At first, a series of mathematical equations are built for wellbore modeling of fluid flow in tubing or annulus, heat loss to a surrounding formation and heat transfer in the formation. Then methods and workflows are determined for key steps in wellbore simulator development including discretization, a grid system, a solution method and a liner equation solver. A standalone compositional wellbore simulator is developed. Validation works against CMG SAM, CMG Flexwell and Eclipse Multi-Segment Well are conducted afterwards. Different scenarios have been modeled by the wellbore simulator that include hot water injection, steam injection, SAGD circulation, SAGD injection, multiphase well production, steam-solvent co-injection, liquid CO2 injection for a shale gas reservoir and geothermal well production. Different well trajectories and structures are handled such as vertical, deviated and horizontal wells, and the wells consisted of one or dual tubing strings. New correlations for more accurate heat loss calculations are regressed in this study based on CFD Fluent simulation and they can better estimate the convection heat transfer in annuli space with single tubing or dual-tubing strings. Also, a semi-numerical method and a fully numerical method for heat loss calculations are proposed. The semi-numerical method consists of heat loss through wellbore components calculated by correlations and heat loss in a surrounding formation numerically simulated, and the fully numerical method performs simulation for heat transfer both in wellbore components and the surrounding formation.
Open Access
Effect of Solvent Co-Injection on Residual Oil Saturation in SAGD Steam Chamber
(2019-09-11) Rengifo Barbosa, Fernando Javier; Maini, B. B.; Sarma, Helmanta Kumar; Chen, Shengnan
Steam Assisted Gravity Drainage (SAGD) process has been applied over wide area of the Province of Alberta, boosting the Canadian oil reserves to the position of third highest in the world. A key performance indicator of SAGD thermal efficiency is the steam-oil-ratio (SOR) that is the volume of water converted to steam and injected into the formation for each unit volume of produced oil. Even though several cost-saving advances have been made in this technology, SAGD remains expensive in terms of both the oil production cost and the environmental cost associated with greenhouse gases (GHG) emissions. Several kinds of additives have been proposed for improving the thermal efficiency of the process and decreasing the SOR while increasing the cumulative oil recovery. Solvent addition in SAGD is one alternative that improves the performance by decreasing the oil viscosity by dilution and thereby by decreasing the required amount of heat per produced oil barrel. In solvent enhanced SAGD, a part of steam volume is replaced by hydrocarbon solvent, in order to take advantage of not just heat but also of dilution for viscosity reduction. At the same time, solvent injection reduces heat losses by reducing the operating temperature. The combination of reservoir characteristics and operational constraints influence the choice of solvent as well as its concentration and timing. No systematic study of residual oil saturation (Sor) in solvent enhanced SAGD has been reported in the literature. This project tested four solvents (Pentane -C5H12, Hexane -C6H14, Cracked Naphtha and Natural Gas Condensate) at different concentrations using linear sand-packs that simulated SAGD gravity drainage to quantify their impact on the recovery performance during the injection process and on the residual oil saturation. The addition of all tested solvents to steam increased the rate of oil drainage and reduced the residual oil saturation. Amongst the single component solvents, 15 vol% hexane gave the fasted recovery and lowest residual oil saturation. However, the multicomponent solvents performed even better. Addition of 15 vol% cracked naphtha gave the lowest residual saturation and fastest oil recovery. The performance of gas condensate was also impressive. At 5 vol% concentration it was able to outperform 10 vol% cracked naphtha and 15 vol% hexane in terms of the rate of oil recovery and residual oil saturation.
Open Access
Effects of Nanoparticles on Thermal Conductivity Enhancement in Different Oils
(2018-12-11) Mustafin, Robert; Nassar, Nashaat N.; Hejazi, Seyed Hossein; Hassanzadeh, Hassan; Chen, Shengnan
In recent years, depleting amount of energy extracted from conventional oil reservoirs, together with an industrial shift towards heavy oil/bitumen recovery has become more pronounced. Today, steam injection heating methods are primary used by industry for heavy oil/bitumen recovery. However, these methods have a detrimental effect on the environment, high-energy consumption and limited application, especially for the deep reservoirs. Therefore, there is a high priority to investigate alternative approaches. To date, the most progressive alternative technique that has proven its potential during pilot-plant tests is “Nanocatalytic in-situ heavy oil/bitumen upgrading via hot-fluid injection,” developed by Catalysis and Adsorption for Fuels and Energy (CAFE) research group at the University of Calgary. Nevertheless, continual improvement of the technique is of utmost importance. Therefore, this study is intended for proposal of new nanofluid system suitable for high-temperature injection into the reservoir with consecutive heavy oil/bitumen upgrading. New nanofluid system posses enhanced thermal properties represented by thermal conductivity, which is one of the critical parameters that affects the performance of oil recovery. Experimental studies on the thermal conductivity of oil-based medias were conducted and the effects of particle type, solid mass fraction, particle size distribution and temperature augmentation were evaluated. The results showed that the thermal conductivity values of nanofluid systems is substantially higher than that of the base fluids. Thermal conductivity enhancement trend was found to increase with increase in particle dosage. The highest thermal conductivity enhancement was determined for nanofluids with smaller average hydrodynamic particle size. Moreover, presence of chemo-physical interactions between nanoparticles and base fluid led to additional intensification of thermal conductivity. Also, the temperature augmentation in a range from 80 to 110°C exhibited a positive effect on thermal conductivity enhancement of vacuum residue-based nanofluid system. The present study holds great promise for the application of nanoparticle technology in enhancing heavy oil upgrading and recovery.
Open Access
Effects of Nanopores on Carbon Dioxide Enhanced Oil Recovery in Tight Oil Reservoirs
(2017) Zhang, Kai; Chen, Zhangxing (John); Azaiez, Jalel; Chen, Shengnan; Eaton, David W. S.; Patil, Shirish L.
Horizontal well drilling with multi-stage hydraulic fracturing is mainly applied in tight oil exploitation. In some tight carbonate reservoirs like Pekisko, acidizing is applied. The primary recovery factor, however, remains below 10% even with advanced technologies. Water flooding has also been proposed for tight oil development, but water can form a membrane up to 43 nm, which tremendously hinders water injectivity. A CO2 miscible process seems a promising technique to enhance tight oil recovery. The mechanism of CO2-oil miscibility is the separation of oil molecules by the CO2 introduced; van der Waals forces that hold the oil molecules together need to be overcome. The process is similar to the vaporization of a liquid. The energy added into the liquid is used to overcome the van der Waals forces that hold the molecules of the liquid together, separate the liquid molecules and split them into the gas phase. In a nanoscale pore medium, variations in molecular orientation and molecules arrangement result in an alteration in the van der Waals forces, thereby creating unique thermal dynamic properties. These contribute to changes in CO2-oil miscibility compared to that in conventional reservoirs. At present, no systematical study addresses CO2-oil miscibility in nanopores. To unlock the mysteries of CO2 in enhanced oil recovery (EOR) in nanopores, the interactions between nanopores and molecules are studied using armchair, a zig-zag carbon nanotube, cubic shape smooth and rough nano-channels, and nano-channels with a functional group OH. The molecules trajectory and potential energy can be recorded by molecular dynamics simulations. The CO2-oil miscibility in nanopores is further presented including phase equilibrium, vaporizing and condensing drive, immiscible and miscible processes, and solubility parameters. The nanopore effect can be applied in screening candidate reservoirs for CO2 flooding and in selecting CO2 parameters by reservoir simulations. The thesis can be very revealing to researchers in the area of CO2-oil miscibility in nanopores.
Open Access
Energy Recovery from Oil Sands Reservoirs
(2021-01-04) Wang, Jingyi; Gates, Ian Donald; Chen, Shengnan; Hu, Jinguang; Hubbard, Stephen M.; Zeng, Fanhua
Alberta's oil sands are the third largest proven crude oil reserve in the world, after Saudi Arabia and Venezuela. The proven reserve is ~165.4 billion barrels. At original reservoir conditions, for in-situ methods, the bitumen is too viscous to extract directly with viscosities of the order of hundreds of thousands to millions of centipoise. To extract bitumen via in-situ recovery processes, the bitumen's viscosity must be lowered to less than 20 cP. In all current commercial oil sands recovery processes, this is done by injected high pressure and temperature saturated steam into the reservoir. One such process, Steam-Assisted Gravity Drainage (SAGD), has been proven to produce bitumen, but due to steam generation has high emissions intensity with large energy requirements. The research presented here studied the SAGD process from multiple angles. The first study is focused on the edge of steam chamber where both SAGD and Steam and Gas Push (SAGP) processes were compared to understand the impact of non-condensable gas on heat transport at the edge of the chamber. The second approach uses a detailed compositional model to exam the time scales for steam and bitumen flow within the depletion chamber. The approach used for multiple steam and multiple bitumen components is novel. The third study examined the instantaneous steam-to-oil ratio behavior when the steam chamber was exposed to different reservoir features. The last study explored the recovery of heat energy from post-SAGD chambers. The analysis reveals the following results. 1. non-condensable gas does improve the thermal efficiency of SAGD, but it changes the behaviour of the edge of the chamber by creating a more extensive depletion zone at the edge of the chamber. 2. the time scales for steam flow and bitumen mobilization, drainage, and production can be weeks to months to years depending on the stage of the process. This speaks to the 'thermal momentum' that is established in the reservoir during the process. 3. The SOR, in particular, the instantaneous SOR provides a signal that can be used to identify reservoir features. This could be used with multiple SAGD well pairs to determine reservoir features across pads. 4. A large fraction of the injected heat energy in the reservoir remains in the reservoir rock (sand grains) and the overburden and understrata. However, it is possible to extract a significant fraction of the energy remaining in the reservoir after SAGD operations have finished. This should be explored in the field since this provides a means to raise the overall energy efficiency of SAGD.
Open Access
Enhancing Hydrocarbon Recovery and Sensitivity Studies in Tight Liquid-Rich Gas Resources
(2017) Wang, Min; Chen, Shengnan; Chen, Zhangxing; Maini, Brij
Unconventional tight reservoirs refer to the formations with a permeability ranges from 0.001 to 0.1 millidarcy. Horizontal drilling coupled with multistage hydraulic fracturing is required in these formations to achieve economic production rates. Recovery factor in tight gas formations is typically less than 25% of the original gas in-place. Such low recovery is a strong motivation to investigate the application of enhancing hydrocarbon recovery methods in these reservoirs. In this study, enhanced hydrocarbon recovery methods are investigated for a Montney liquid rich gas reservoir, located in the Western Canadian Sedimentary Basin. Firstly, a heterogeneous reservoir model is built and history-matched based on the production data collected from the field. Production performance of three EHR methods including cycling gas injection, CO2 flooding and water injection are then compared and their economic feasibility are evaluated. Sensitivity analysis of operational and geological factors including primary production duration, bottom hole pressures (BHP) during primary production and EHR process, pressure-dependent matrix permeability, non- Darcy effects and hydraulic fracture conductivity is conducted and their effects on the well production performance are studied. Experimental design is adopted to further study the mechanism and optimize the enhancing recovery process by cyclic gas injection and CO2 injection. Results show that both cumulative oil and gas production are increased with fluid injection compared to primary depletion methods. In addition, cyclic gas and CO2 flooding is more feasible for the ultra-low unconventional tight gas reservoir than water flooding due to the water injection difficulty and low sweep efficiency in the reservoir. Cycling gas injection leads to both a higher gas and oil recovery and lower injection cost due to the on-site available gas source and minimal transport/purchase costs, gaining more economic benefits than that of CO2 flooding. Thus, it can be concluded that cyclic gas flooding in tight liquid rich gas reservoirs with hydraulically stimulated fractures could be a good way to enhance oil and gas production. Optimization study results indicate that two injection wells, short primary production time, high primary BHP and injection BHP, short injection time and low later period BHP lead to an optimal scheme of cyclic gas flooding and CO2 flooding methods.
Open Access
Enhancing recovery and sensitivity studies in an unconventional tight gas condensate reservoir
(2018-03-27) Wang, Min; Chen, Shengnan; Lin, Menglu
Abstract The recovery factor from tight gas reservoirs is typically less than 15%, even with multistage hydraulic fracturing stimulation. Such low recovery is exacerbated in tight gas condensate reservoirs, where the depletion of gas leaves the valuable condensate behind. In this paper, three enhanced gas recovery (EGR) methods including produced gas injection, CO2 injection and water injection are investigated to increase the well productivity for a tight gas condensate reservoir in the Montney Formation, Canada. The production performance of the three EGR methods is compared and their economic feasibility is evaluated. Sensitivity analysis of the key factors such as primary production duration, bottom-hole pressures, and fracture conductivity is conducted and their effects on the well production performance are analyzed. Results show that, compared with the simple depletion method, both the cumulative gas and condensate production increase with fluids injected. Produced gas injection leads to both a higher gas and condensate production compared with those of the CO2 injection, while waterflooding suffers from injection difficulty and the corresponding low sweep efficiency. Meanwhile, the injection cost is lower for the produced gas injection due to the on-site available gas source and minimal transport costs, gaining more economic benefits than the other EGR methods.
Open Access
Experimental and Numerical Studies of Foamy Oil Displacement Mechanisms in Heavy Oil Reservoirs
(2019-04-25) Wang, Danling; Chen, Zhangxin; Moore, Robert Gordon Gord; Chen, Shengnan
Foamy oil behavior has proven effective for heavy oil recovery and typically generates as pressure depletes in the first recovery stage. It possesses a low gas-oil ratio, maintains reservoir pressure and leads to high production recovery. Because the energy exhausts at the end of the first recovery stage, a significant amount of heavy oil remains underground. Therefore, the research objective is to develop a feasible gas injection process for foamy oil generation by understanding the generation mechanisms between gas and heavy oil. In the research, the mechanisms of foamy oil generation are experimentally investigated and the gas injection process is optimized. First, a vertical visible slab model is built, which can observe foamy oil generated in a gas flow channel. Gas injection tests are conducted afterwards. The strategy is optimized by identifying key parameters including gas injection type, gas injection rate, gas injection pressure and contact time. The model and our experiments reveal the mechanisms of foamy oil generation: the gas slowly reacts with the heavy oil at the contact surface and the generated foamy oil is stripped away with continuous gas injection. The highest oil recovery factor of 37.36% can be obtained by injecting gas at the rate of 2.0 ml/min, under 4.5 MPa, and using a contact time of 4 hours. The injected gas is mixed with 30% CH4 (methane) and 70% CO2 (carbon dioxide). Numerical simulation is also employed to validate the feasibility of the gas injection method for generating foamy oil and enhancing recovery in heavy oil reservoirs.
Open Access
Experimental Evaluation of Surfactant Assisted SAGD Process
(2019-11) Xie, Yun; Maini, B. B.; Dong, Mingzhe; Chen, Shengnan; Hejazi, Hossein
Using a surfactant as a steam additive for improving SAGD performance has been an intriguing idea for several decades. Some positive laboratory and field results on the Surfactant SAGD (S-SAGD) have been mentioned, yet very limited information has been revealed in the public domain literature. The primary mechanism responsible for improving the performance in S-SAGD also remains unclear. In this study, experiments under SAGD operating conditions were used to evaluate the adaptability of selected surfactants for S-SAGD. Oil recovery improvement was investigated using a one-dimensional sand-pack apparatus at SAGD conditions. Experimental results show that the majority of tested surfactants can achieve a higher initial recovery rate, but only three out of seven tested surfactants increased the final oil recovery factor. The surfactants reduce the interfacial tension (IFT) between the aqueous and oil phase at the steam temperature of 200°C. However, the impact of reduced IFT on recovery is limited, since ultralow IFT (0.001 mN/m) was not achieved. The improvement in oil recovery appears to be related to changes in wettability and relative permeability. The successful surfactants appear to increase the oil relative permeability and reduce the residual oil saturation. In view of considerably higher initial oil production rate and a 10.8% increase in the final recovery factor, the thermally stable Novel 6-2 is recommended for further evaluations as an additive for S-SAGD.
Open Access
Fracture Height Propagation in Tight Reservoirs Using the Finite Element Method
(2021-01-26) Cai, Jiujie; Chen, Shengnan; Chen, Zhangxin; Gates, Ian Donald; Wong, Ron Chik Kwong; Zhang, Yin
In recent years, multi-stage hydraulic fracturing technology is widely applied in oil/gas industry all over the world as a successful treatment, especially in tight and shale reservoirs. The induced fracture geometries directly affect the post-stimulation production and economic profitability of the project and accurately predicting the fracture properties is quite important. In addition to fracture length and conductivity, fracture height is another critical parameter of the hydraulic fracturing treatments in the unconventional tight/shale formations. Multiple transverse fractures are usually created along the horizontal wells, where the mechanisms of fracture-height-containment can be complicated under conditions such as interactions with the natural fractures, as well as adjacent hydraulic fractures. In addition, the directions of the bounding layers may not be parallel with that of horizontal wells. Traditional fracture propagation models applied in industry do not include all the aforementioned factors comprehensively. This research targets to study the mechanisms of hydraulic fracture propagation, focusing on the fracture-height-containment in the scenarios of multiple fractures along the horizontal wells. Firstly, a two-dimensional numerical model is proposed to analyze the methodology of single fracture height propagation via the finite element method. Then, an analytical model is built to understand the mechanisms of the fracture height containment considering inclined bounding layers. Modeling results suggested that for the closely spaced multiple fractures which are growing simultaneously, the critical fluid pressure becomes larger, implying that the fracture height propagation is more difficult under such scenario. Fracture height propagates more easily when bounding layer inclination angle increases. Thirdly, a three-dimensional numerical model with cohesive method on the fracture height propagation is used to analyze the multiple fracture interactions and the effective fracture height and width in tight reservoirs. The influence of stress shadow and stress difference on effective fracture height has been investigated and results show that the interaction from adjacent fracture becomes more significant when fracture spacing is small. Fluid injection rate is also an important influencing factor on the hydraulic fracture width especially when flow rate is low. When stress shadow effect is strong, the interior fractures can hardly propagate, and the majority of the fluid volume goes into the exterior fractures.