bluuebunny/crossref_metadata_2025_split huggingface dataset:
Effect of Temperature on Gas/Oil Relative Permeability in Viscous Oil Reservoirs
Authors: Kumar Saket , Sarma Hemanta , Maini Brij 
Published: March 2022

AbstractOil displacement tests were carried out in a 45-cm long sand-pack at temperatures ranging from 64 to 217 °C using a viscous oil (PAO-100), deionized water and nitrogen gas. It was found that the unsteady-state method was susceptible to several experimental artifacts in viscous oil systems due to a very adverse mobility ratio. However, despite such experimental artifacts, a careful analysis of the displacement data led to obtaining meaningful two-phase gas/oil relative permeability curves. These curves were used to assess the effect of temperature on gas/oil relative permeability in viscous oil systems.We employed a new systematic algorithm to successfully implement a history matching scheme to infer the two-phase gas/heavy oil relative permeabilities from the core-flood data. We noted that at the end of the gas flooding, the "final" residual oil saturation still eluded us even after tens of pore volumes of gas injection. This rendered the experimentally determined endpoint gas relative permeability (krge) and Sor unreliable. In contrast, the irreducible water saturation (Swir) and the endpoint oil relative permeability (kroe) were experimentally achievable.A history-matching technique was used to determine the uncertain parameters of the oil/gas relative permeability curves, including the two exponents of the extended Corey equation (N° and Ng), Sor and krge. The history match showed that kroe and Swir were experimentally achievable and were reliably interpreted. The remaining four parameters (i.e., Corey exponents, true residual oil saturation and gas endpoint relative permeability) were obtained from history matched simulations rather than from experiments. Based on our findings, a new correlation has been proposed to model the effect of temperature on two-phase gas/heavy oil relative permeability.
Design of a Solar Parabolic Trough Capable of Producing Steam for Enhanced Oil Recovery in Trinidad and Tobago
Authors: Gajadhar Ahiliah , Hosein Raffie 
Published: March 2022

Abstract
Enhanced oil recovery by steam injection requires the burning of natural gas, a finite and expensive resource for steam production. However, solar energy can be harnessed for steam production via solar parabolic troughs. In this study, the design and application of a solar parabolic trough, in tandem with a heat exchanger for producing steam for Enhanced Oil Recovery (EOR) in Trinidad and Tobago is presented. Excel spreadsheets were developed to perform the calculations and to optimize the size and design of the parabolic trough collector for maximum heating efficiency. The parabolic trough designed was 36 m in length and consisted of a parabolic aluminum reflector, stainless steel receiver tube, and a glass envelope that surrounded the receiver tube. The heat transfer fluid used was Therminol VP-1, a synthetic oil, which was heated up to 403 °C. Once heated, the heat transfer fluid was then transferred to a heat exchanger whereby steam was produced at 300°C. Overall, 4 of the parabolic trough collector systems were required to heat enough fluid to fill the calculated 343 tubes of the heat exchanger, which were 0.091 m in diameter and 4.9m in length. The total cost of the parabolic troughs and the heat exchanger tubes was calculated to be USD 119,562. By having a mass flow rate of 46 kg/s for the water within the heat exchanger, approximately 1630 barrels of oil were economically produced at a maximum steam oil ratio of 4.5 after one day of steam injection. A cash flow projection was completed using both operational and capital expenditure of the parabolic trough collector. From this study, the parabolic trough system was shown to generate a profit of USD 1.8 MM after six months of steam injection. Profit calculation considered both capital and operating expenditure as well as the income gained from oil recovery due to the parabolic trough collector. The spreadsheet developed can be used to design similar systems of steam generation for enhanced oil recovery projects of different scales.
Fluor Solvent Offers Significantly Lower GHG Intensity CO2 Removal from Natural Gas Than MDEA for Horn River
Authors: Rodwell Morgan 
Published: March 2022

Abstract
As natural gas demand increases through the energy transition, due to shifts away from coal-fired power generation and increased hydrogen utilization, production and processing of high CO2 natural gas sources, such as the Horn River Basin in Northern British Columbia will become more economic and important. The capture process should be energy efficient and provide the lowest GHG intensity possible to ensure the maximum decarbonization benefit. The propylene carbonate-based Fluor SolventSM process provides CO2 capture from natural gas sources at up to 97% lower GHG intensity when compared to the use of a formulated MDEA solvent which was used at the largest plant constructed to date in this field.
Coupling a Thermal Reservoir Simulator with a Dynamic, Multiphase Wellbore Flow Simulator to Rigorously Model Complex SAGD Well Geometries and Completions
Authors: Rivero Jose A. , Istchenko Christopher , Nascimento Carlos , Cao Jia-Ming , Aghabarati Hossein , Bergen Michael 
Published: March 2022

Abstract
In this paper, we propose a methodology to iteratively couple a wellbore simulator and a reservoir simulator in order to model the complex flow regimes that exist in a producing SAGD well while still taking into consideration the fluid movement and distribution within the reservoir. The process was successfully tested and implemented in two SAGD pads and the results were compared with those obtained using a commercial, fully-coupled reservoir-wellbore model. This method addresses the modeling limitations encountered in typical thermal reservoir simulators that use source/sink or discretized formulations to describe wellbore flow.
SAGD producers exhibit overly complex flow regimes caused by the presence of a steam phase that can condense within the wellbore and promote significant variations in temperatures and pressures along the tubulars. Therefore, standalone wellbore simulators are necessary to predict performance as accurately as possible; however, using a wellbore simulator alone will neglect the effects caused by varying inflow conditions from the reservoir. With these variations occurring both in time and in space (along the wellbore), it is necessary to include the dynamic input of a reservoir simulator, hence the rationale for coupling both models.
The algorithm devised to integrate the wellbore and reservoir simulators was coded into a standalone GUI-driven computer program called a coupler. The coupler was used to evaluate the performance of new SAGD pairs and new infill producers featuring flow devices and slanted trajectories.
In this work, we will present the results of field case studies with the proposed coupling approach to evaluate the effect on ultimate recovery of drilling new SAGD pairs and SAGD infills using toe-up or toe-down trajectories as well as fitting these wells with inflow control devices. When applying the coupling workflow to the case studies, we determined that despite challenging conditions, it is possible to have inclined SAGD wells properly transition from preheating to production as well as allowing access to previously untapped parts of the reservoir resources, which increased ultimate recovery.
The Effects of Asphaltene Precipitation on Bitumen Recovery during Non-Thermal Cyclic Solvent Injection in Cold Lake Oil Sands- An Experimental Study
Authors: Yuan Lin , Yousefi Mohammad , Dehghanpour Hassan 
Published: March 2022

Abstract
The non-thermal solvent-based processes for bitumen extraction consume less energy and water, and thus, have less impacts on the environment compared with the steam-based thermal processes. The objective of this paper is to investigate the mechanisms responsible for propane transport into and bitumen production from oil-sand core samples during the cyclic solvent injection (CSI). We use a state-of-the-art high-pressure and high-temperature (HPHT) visualization cell to investigate non-equilibrium propane-bitumen interactions during CSI. We inject propane into the cell containing a bitumen-saturated core plug representing in-situ reservoir conditions. Three sets of tests with different propane vapor (C3(v)) to liquid (C3(l)) ratio are conducted (set 1 with C3(l), set 2 with C3(l)-C3(v) mixture, and set 3 with C3(v)). After the CSI tests, the final bitumen recovery factor is calculated by the weight-balance method and the precipitated asphaltene content caused by propane-bitumen interactions is also measured using a distillation apparatus.
When the core is fully immersed in C3(l), the cell pressure rapidly declines during the early soaking process, and then, it declines gradually. However, no obvious pressure decline can be observed when C3(v) is present in the system. This can be explained by the higher compressibility of C3(v) compared to C3(l), leading to a less significant pressure decline during the soaking period. A light hydrocarbon phase is produced from the core at the end of the depletion process, indicating the extraction of light components of oil by propane even at low-temperature conditions. The bitumen recovery factor is the lowest (11.93%) in set 1 when the core is soaked in C3(l), while that is the highest (14.73%) in set 3 when the core is soaked in C3(v). Also, the bitumen production stops quickly at the early soaking period in set 1. This is because asphaltene precipitation is more significant when the C3(l) is present in the system. The propane density in liquid state is higher than that in vapor state, leading to more bitumen-propane interactions and more asphaltene precipitation. The precipitated asphaltene blocks the pore network and inhibits bitumen production. Our results show that increasing C3(v) to C3(v) ratio decreases the amount of asphaltene precipitation, and in turn, increases bitumen recovery factor.
CO2 Mineral Trapping in Basaltic Formation During CO2 Storage
Authors: Hamdi Zakaria , Raja Zainal Raffik Raja Zuhaili Aimran , Talabi Oluwole , Patel Urval , Mackay Eric , Bataee Mahmood 
Published: March 2022

Abstract
The rise in global warming is due to the high emissions of greenhouse gases (GHG) around the world. Carbon dioxide (CO2) gas emissions, a by-product from the petroleum industry, is contributors to climate change. One technology that may help curb CO2 gas emissions is injecting the gas into the subsurface reservoir. In this study, CO2 mineral trapping behaviour and its reactions within a wet basaltic rock containing Olivine mineral are captured and simulated in a full field numerical simulation model. A 2-stage approach was planned to develop the full field numerical model. In the first stage, a single cell model was developed, assessed and matched to the literature experiments with several assumptions considered and applied. Following this, the second stage involved developing a full field model to observe and analyse the distribution and concentration of CO2 during injection, as well as its sequestration as a solid phase (i.e., mineral trapping). The overall volume ratio of injected CO2 versus water was also assessed to ensure enough CO2 were injected into the basalt rock ensuring clear distribution of CO2 in the rock either in dissolved, trapped, or mobile state. In this study, the injected volume covered 4% of the total water volume. Results show that mineralization occurs faster than expected when CO2 gas was introduced to the wet basaltic rock especially near the CO2 injector wellbore. The mineralization speed depends on the reaction rate, modelling (cell) surface area and volume as well as the reaction rate coefficient where it was tuned to match the experimental results. The time required for the CO2 component to travel within the rock was also assessed to give a clear picture of the CO2 distribution where it took 10 years to reach 1000 ft away from the injector wellbore within a 440 ft thick reservoir.
Study of Carbon Capture in Oilsands Production and Upgrading
Authors: Isley Jon , Gutscher Matthew , Henezi Benjamin 
Published: March 2022

Abstract
Canada's oilsands production and upgrading industry has plans for a regional CO2 pipeline, enabling carbon capture and sequestration (CCS) solutions for reducing industry CO2 emissions. In order to evaluate the relative merits of carbon capture solutions, a case study is developed of three hypothetical carbon capture facilities: one post-combustion from a SAGD facility, a second post-combustion from an upgrader hydrogen plant, and a third pre-combustion from an upgrader hydrogen plant. All cases are based on process configurations of commercially proven technologies. Capital costs are developed for each of the cases based on Fluor process expertise and historical cost data for the oilsands region. Process and utility balances are developed to inform net carbon intensity reductions along with operating costs. The study includes a discussion of the influencing factors to CCS economics, including looking at the carbon footprint balance of production and upgrading operations, the existing utility profile, economies of scale, and carbon lifecycle impacts of choices. In addition to net carbon avoidance from a $CAD/ton CO2 perspective, the results also inform on relative merits of carbon intensity reduction of produced liquid fuels which generate carbon credits and revenue under the Canadian Clean Fuel Standard (CFS). Consideration of both carbon tax avoidance and fuel carbon intensity need to be considered to justify capital investment.
Steam-Solvent Process: A Gamechanger in Cutting Emissions in In-Situ Recovery of Oil Sands
Authors: Chowdhuri M. A. K. , Filstein Alex , Huang Haibo 
Published: March 2022

Abstract
Due to extensive energy requirements and the volume of emitted greenhouse gases associated with burning natural gas to generate steam in the SAGD process, there has been always a strong motivation to develop oil recovery processes for bitumen reservoirs with lower energy and emissions intensities. A hybrid steam-solvent co-injection process, which is to synergize the advantages of both SAGD and VAPEX processes and minimize their drawbacks is the subject of ongoing research and field piloting since early 2000. Most of the past efforts of the steam-solvent process were primarily focused on improving the oil rate or improving the process's economic benefits. However, due to Canada's ambitious greenhouse emission reduction target (net zero emission by 2050) along with the significant increase of carbon tax ($170 by 2030), the primary focus of the oil industry is shifting towards reducing steam injection and cutting the GHG emission drastically. This study revisited the steam-solvent process to find a suitable combination of solvent type and operating strategies that can reduce the steam injection and GHG emission significantly, and without significantly compromising the oil production. Two hydrocarbon pure solvents, propane and butane were recommended in this project to cut the steam injection drastically and without having a significant negative impact on the oil production. Among the two solvents, butane may be preferred. However, to reduce the cost further and cut energy input, propane may be a better choice than butane. Propane is cheaper than butane and it requires less energy to vaporize propane. The process should start with steam-only injection (as SAGD) and next inject solvent after the chamber is somewhat developed. The solvent may not be effective if the oil production is already in the natural decline stage. At later stages, the solvent retention in the reservoir could also be high. During the solvent injection period, a small amount of steam could be continuously injected with the solvent or steam could be intermittently injected as needed to keep enough energy in the reservoir. This will help to vaporize the solvent and prevent the chamber from being cooled down significantly.
Powering Offshore Installations with Wind Energy
Authors: MacDougall Blair , Nash Phil , Doyle Bruce , Hudson Joshua , Murphy Rick , Meyers Justin 
Published: March 2022

Abstract
The offshore Oil and Gas industry continues to explore and develop oil and gas fields using installations powered by generators burning either natural gas or marine gas oil (MGO), similar to diesel. There is increasing pressure on the industry to explore and produce hydrocarbons responsibly, cost effectively and with the lowest emissions. By employing renewable sources of power, Waterford Energy Services Inc.'s (WESI) methodology provides a possible solution using Floating Offshore Wind Turbine (FOWT) to power offshore installations. Various methods are being proposed and developed to maintain production while bringing down overall greenhouse gas emissions (e.g. CO2, NOx, SOx).
This paper outlines the methodology used for a conceptual design of a "Plug and Play" hybrid power solution in the Canadian Offshore Oil and Gas Industry. FOWTs are electrically connected to offshore installations such as Mobile Offshore Drilling Units (MODU), Floating Production Storage and Offloading (FPSO) and fixed production platforms in a harsh environment to replace large portions of the onboard power generation. Battery Energy Storage Systems (BESS) are incorporated to transition from wind power, increase efficiency, provide safety backup and enhance emissions reduction. The plan includes considerations for the optimal electrical and battery storage topology and the electrical equipment necessary to connect the FOWT Array to the offshore facility.
For the purposes of this paper, a representative location was chosen offshore Newfoundland and Labrador, Canada to assess both local conditions and design requirements. WESI has evaluated additional global locations for this FOWT solution.
The conceptual design considers the wind turbine power output and examines the components required to deliver the power to the installation's electrical system (e.g. transformers, batteries, switchgear, static and dynamic cables, disconnects, communications/monitoring and required safety systems).
Although there have been incremental improvements in emissions via advancements in fuel standards and engine exhaust abatement modifications, the only approach to have a significant step-change improvement in emissions is through replacement of onboard power generation with renewable sources. It anticipated that the installations’ greenhouse gas (GHG) emissions can be reduced in excess of 70% by combining wind power and battery supplementation.
Oil and Gas operations are ideal applications of this decarbonization approach, presenting an opportunity to mature FOWT technology which can readily adapt to other grid isolated applications such as Remote Communities, Aquaculture and near-shore Industries.
Pore-Scale Modellings on the Impacts of Hydrate Distribution Morphology on Gas and Water Transport in Hydrate-Bearing Sediments
Authors: Li Zhuoran , You Jiahui , Qin Guan 
Published: March 2022

Abstract
Gas and water transport behavior, which is controlled by the pore characteristics and capillarity in hydrate-bearing sediments (HBS), is one of the key factors affecting the gas production. Hydrate distribution morphology (HDM) can significantly influence the pore structures of HBS, affecting the relative permeabilities of gas and water. To elucidate the impacts of HDM in microscopic scale, a phase-field lattice Boltzmann (LB) model is developed to describe the gas and water transport in HBS.To simulate the transport of immiscible fluids, which exist obvious density and viscosity contrasts, a phase-field LB model with the conservative form of interface-tracking equation is developed to suppress the spurious currents at phase interfaces. To describe the fluid-solid interactions, the bounce-back condition is applied for both solid phases (hydrate and grains) to achieve the non-slip condition and the wettability condition is applied for grains and hydrate to describe the wettability behavior. To improve the numerical stability, the multi-relaxation-time (MRT) collision operator is applied and the discretization schemes with 8th order accuracy for the gradient operator are selected. In this work, we first validated our model by applying several benchmark cases aiming at fluids with obvious density contrasts such as the layered Couette/Poiseuille flows, Rayleigh–Taylor instability. Then the synthetic geometries of the pore-filling and grain-coating HBS with several hydrate saturation (Shyd) were constructed by guaranteeing the same extent of connectivity. Then the steady-state relative permeability measurement and drainage capillary pressure measurement processes were simulated by the LB model for two HDM cases under several Shyd. The results showed that in the hydrophilic HBS, the relative permeability of gas in the pore-filling case is obviously larger than that in the grain-coating case at the same Shyd, and larger capillary pressure can be obtained in the pore-filling case. In addition, as the Shyd increased, it would notably enhance these differences of fluids relative permeability and capillary pressure between two HDM cases. Because the HDM can not only influence the pore space structures but also the wettability of the porous medium by creating solid surfaces of varying wettability, the distribution and transport of fluid phases in different HDM cases can be obviously affected. The phase-filed LB model applied in this study is capable to handle and suppress the spurious currents at phase interfaces, ensuring a satisfactory numerical stability and accuracy. Thus, the real density and viscosity contrasts between the water and gas under the in-situ thermodynamic conditions can be considered in the simulation. The impacts of HDM on the gas and water transport were quantitively analyzed by simulating multiphase flow processes in HBS.