bluuebunny/crossref_metadata_2025 huggingface dataset:
Conceptualizing Biological Aging and Frailty in Orthopaedics
Authors: Cong Ting , Hall Arielle J. , Jia Zhimeng , Christiano Anthony , Elsevier Hannah C.K. , Cheung Zoe B. , Wellman David , Forsh David , Lane Joseph M.
Published: March 2022

➤ Biological aging can best be conceptualized clinically as a combination of 3 components: frailty, comorbidity, and disability.

➤ Despite advancements in the understanding of senescence, chronological age remains the best estimate of biological age. However, a useful exercise for practitioners is to look beyond chronological age in clinical and surgical decision-making.

➤ A chronologically aging person does not age biologically at the same rate.

➤ The best way to understand frailty is to consider it as a physical phenotype.

➤ Physical optimization should parallel medical optimization before elective surgery.

➤ The poorer the host (both in terms of bone quality and propensity for healing), the more robust the implant construct must be to minimize reliance on host biology.
Seawater Intrusion-Retreat Processes and Groundwater Evolution in Intruded Coastal Aquifers with Land Reclamation: A Case Study of Eastern Jiangsu, China
Authors: Xiong Guiyao , Chen Guangquan , Wu Jichun , Fu Tengfei , Yang Yun , Xu Xingyong , Zhu Xiaobin , Yu Hongjun , Liu Shengfa , Gao Maosheng , Hou Guohua
Published: March 2022

The hydrogeochemical analysis and numerical simulation were conducted to explore the impact of land reclamation on submarine groundwater discharge and groundwater evolution in the seawater intrusion-retreat processes in eastern Jiangsu, China. The hydrogeochemical results indicated that the origin of salt in most groundwater is saltwater mixing, and weathering-dissolution of minerals enriches the salt in fresh groundwater. The evolution path of coastal groundwater in Jiangsu is Ca-Na-HCO3-Cl → Ca-Na-Cl-HCO3 → Na-Ca-Cl-HCO3 → Na-Mg-HCO3 → Na-Mg-HCO3-Cl → Na-Cl-HCO3 → Na-Cl, and the difference in groundwater evolution in different regions is obvious. The numerical simulation revealed that the land reclamation has blocked groundwater exchange and restrained the seawater intrusion. The sensitive analysis indicated that the permeability and the slope of the land reclamation have dominated the salinity distribution. And the aquifer heterogeneity promotes groundwater evolution and leads to the irregular salinity distribution of the groundwater. Moreover, the groundwater evolution in the shallow aquifer with the land reclamation shows that the residual seawater is gradually desalinating and discharged into the sea. The land reclamation is salinized by saltwater discharge and seawater intrusion together and then subsides into a stable saltwater wedge. The groundwater salinity distribution in Jiangsu is not fit seawater intrusion, which is caused by the coastline changes due to anthropogenic land reclamation and natural activities.
Experimental Study on Physical and Mechanical Properties of Beishan Granite after Cyclic Heating and Cooling with Water
Authors: Wang Z. H. , Guo L. , Li S. M. , Konietzky Heinz
Published: March 2022

Granite characterized by low permeability and high strength is commonly seen in underground construction. This paper is aiming at studying the influence of cyclic heating and water cooling on physicomechanical properties of Beishan granite, which is chosen as a potential host surrounding rock of a high level nuclear waste (HLW) repository. In this study, physical and mechanical properties of Beishan granite after repeated heating-cooling cycles are described. After five heating-cooling cycles with temperature up to 300°C, the diameter and length of specimens increase by 0.090% and 0.052%, respectively. And the mass of specimen reduces by 0.32 g. In the following conventional triaxial compression (CTC) tests, the peak strength shows a slightly increase, but the dilatancy threshold decreases. And both peak strain and dilatancy threshold strain exhibit increase, which is responsible for the decrease of Young’s modulus. During the test, acoustic emission (AE) is rarely monitored in the early loading and starts to generate systematically when the axial stress is beyond dilatancy threshold. On the other hand, in the hydraulic (HM) coupled experiments, both peak strength and dilatancy threshold show decrease. However, the ratio between dilatancy threshold and peak strength shows slightly increase. The same phenomenon can be observed for the peak strength and dilatancy threshold. The permeability shows rarely change compared with that of the specimen without experienced cyclic heating-cooling. AE is significantly monitored in the initial loading, which is seem more than that generated from dilatancy threshold to peak strength. The obtained results are useful for the construction of HLW repository.
Nanoparticle Assisted Foam Stability Under SAGD Conditions
Authors: Maaref Sepideh , Kantzas Apostolos
Published: March 2022

Thermal oil recovery processes, and more specifically steam assisted gravity drainage (SAGD), is one of the two commercial methods to produce heavy oil. In the later stages of SAGD heat losses increase. One solution to improve heat losses in the steam chamber is to co-inject a foaming solution with non-condensable gases. It is expected that such a scheme will redirect steam towards heating oil and not the overburden. An appropriate foaming agent is required for successful implementation of a steam-foam process. Conventional laboratory techniques have provided some indication of foam stability with different types of surfactants but failed to match the reservoir conditions and time scale. Recently, the use of nanoparticles along with surfactants has gained attention as a method to stabilize foams under thermal operating conditions. The aim of this research is to investigate the thermal stability of foam under steam conditions (temperatures around 200 °C) using mixtures of different surfactants and silica nanoparticles. A series of foam stability tests were conducted at temperature ranges of 170 °C to 212 °C and pressures of 2.78 MPag and 4.22 MPag using two different anionic surfactants and four different bare and coated silica nanoparticles. The foamy solutions were prepared with a combination of different surfactants and nanoparticles, which were co-injected with N2 gas into a sand pack to generate foam at different temperatures and pressures. The generated foam was then transferred to a high pressure and high temperature visual cell and the foam half-life was measured as the indicator of its decay.

It was observed that a small deviation from the dew point (decreasing the temperature or increasing the pressure) significantly improved foam stability. Addition of nanoparticles proved to be synergistic as the foam half-life near the steam dew point increased about four-fold compared to surfactant only foams. Among the tested nanoparticles, the use of polyethylene glycol (PEG) coated silica nanoparticles along with an anionic surfactant resulted in the highest foam stability near the steam dew point.

To date, most of the foam stability tests have been conducted at temperatures below 200 °C with the focus on using surfactants. This research extended the foam stability tests to temperatures in excess of 200°C using mixtures of surfactants and nanoparticles. Although the foam stability still needs to be improved for reservoir-scale application, our screening methodology presents a realistic process of generating foam in a porous medium with nanoparticles and surfactants under a desired thermodynamic state for subsequent foam thermal stability testing.
Enhancing Reservoir Engineering Workflows with Augmented and Virtual Reality
Authors: Cartwright Stephen , Samoil Steven , Lawton Bryson , Hu Die , Xie Siqi , Wang Eric , Aminbeidokhti Amir , Dawar Seher , Dalton Rachel , Daeijavad Parisa , Maurer Frank , Chen Zhangxin
Published: March 2022

Reservoir engineers must analyze and work with complicated 3D subsurface datasets. Extended reality (XR) hardware has undergone a renaissance in recent years and high-quality hardware is now widely available and affordable. What remains unsolved is how these technologies may be applied to improve reservoir engineering workflows, in order to help plan scenarios that reduce emissions and improve project efficiencies. We detail and discuss the first-year outcomes of an industry-academia collaboration which explores the application of XR technologies to a reservoir engineering workflow.

A thorough review of the benefits of XR technology compared with conventional display and input devices was performed. The results of this were used to inform the design and development of a proof-of-concept visualization and analysis application for reservoir engineering workflows that utilizes the strengths of XR technology. Using this tool, representations of numerical reservoir models can be visualized and analyzed along with other data within virtual working spaces. User-driven interactions were designed for this application and implemented to be as intuitive and effective as possible. Networking capabilities were implemented so that multiple devices and multiple users may access any given virtual workspace, supporting both remote collaboration and cross-reality functionality. The features and design of the application were all developed with the intention of directly supporting the visualization and analysis of reservoir data.

The benefits provided by utilizing XR technology include increased working space, improved spatial perception, and more intuitive user interaction. Features such as multi-model visualization, integration of 2D information visualization, data analysis features, and several different filtering techniques were developed to further enhance reservoir engineering workflows. Additional features in development that are highly anticipated by our industrial partner include methods to better facilitate clear communication when working with data in groups, the integration of presentation and group-work modes, and enhancing workflows with AI-assisted tasks. Careful consideration went into designing interactions that were natural and intuitive, yet flexible and efficient when working within 3D virtual environments.

The innovation demonstrated in this project contributes to advancing the Canadian energy industry to a new era of exciting new visual and interactive technologies, while ensuring that these technologies can be utilized to provide true value to real-world problems. The lessons learned and design insights gained from this project may be applied far beyond reservoir engineering to enhance workflows in any domain where analysis of complex scientific datasets is required.
Consideration of Various Parameters and Scenarios in the Simulation of Hydrate Formation
Authors: Sahari Moghaddam Farzan , Hamid Ali , Abdi Majid , James Lesley
Published: March 2022

This study investigates the effect of various parameters on hydrate formation under two scenarios of regular and cold start-up operations in a flowline and a subsea network. Parameters including hydrate adhesion forces, required subcooling for hydrate nucleation, and a weighting parameter for hydrate-oil slip (COIL) are evaluated. The effect of methanol injection and the mentioned parameters on hydrate formation are compared to 0.2 hydrate fraction threshold from literature.

Hydrate formation from oil having 184 m3/m3 GOR and 35% WC is studied using two scenarios of regular and cold start-up operations in a 6-km flowline and a subsea tieback network (consisting of two branches and a main flowline). The overall heat transfer coefficient is 22.7 W/(m2.K), and the simulation is conducted by OLGA-CSMHyK-MUTIFLASH. Slurry relative viscosity, hydrate fraction, and hydrate propensity in terms of temperature difference known as DTHYD are used as indicators, and a hydrate fraction threshold of 0.2 is considered. Adhesion forces (0.5 - 0.005 N/m), required subcooling (3.61 - 10 °C), COIL (0.2-1), and methanol injection are investigated.

During regular operation, the flow pattern remains stratified in a single flowline having 35% WC and 1 COIL. By increasing the required subcooling for hydrate nucleation from 3.6 °C to 10 °C, the hydrate fraction was reduced from approximately 1.7% to zero. COIL has the greatest effect on hydrate fraction. The reduction of adhesion forces had a noticeable effect on oil viscosity compared to the other indicators. Plug formation is not expected in the studied single flowline and subsea network under normal operation. On the other hand, a potential plug based on higher hydrate formation occurs in a cold start-up operation even under the effect of the studied parameters. However, the chance of plug formation is considerably reduced by injecting 20 wt% methanol. Overall, assessing the three indicators of hydrate formation (slurry relative viscosity, hydrate fraction, and DTHYD) are critical and provide more realistic insight about hydrate formation compared to using only one of the indicators for the evaluations.

This work investigates the three aforementioned indicators of hydrate formation rather than relying on only one indicator (e.g., hydrate fraction) under regular and cold restart operations. The study evaluates hydrate formation based on a hydrate fraction threshold of 0.2 for a potential plug, compared to thermodynamically preventing hydrate formation.
No Reservoir Model? No Problem. Unconventional Well Spacing Optimization With Simple Tools
Authors: Miller Patrick , Redpath Darcy , Dauncey Keane
Published: March 2022

Optimizing economics for unconventional resource development is a delicate balance among four main factors: reservoir deliverability, commodity price, completion design, and well spacing. For a certain reservoir, commodity price, and completion design, there is a well spacing that will optimize field development net present value (NPV). However, if we consider a different part of the reservoir (area or landing zone), commodity price, or completion design, that optimal well spacing changes. Given that this problem is fraught with uncertainty (in price, reservoir deliverability, and the impact on production of changing completion design or well spacing), we need simple, flexible tools to make better decisions about unconventional pad design.

From a technical perspective, teams of subsurface professionals strive to understand the relationship between well productivity and well spacing for a given completion design (or vice versa). If the well spacing is too tight relative to the size of fracture stimulation, the recovery factor will be high, but the development plan will be over-capitalized. If the well spacing is too wide relative to the fracture stimulation, the per-well recovery will be high, but too much resource will be left in the ground and the NPV of the development plan will be low. To search for the optimal pad design, operators often invest in integrated technical workflows with multi-well fracture modeling and reservoir simulation; although useful, these workflows are not practical to apply for every asset in a portfolio because they simply take too long. As an alternative approach, this paper builds on existing tools in the literature to quantify the impact of changing well spacing on well productivity for a given completion design, using a new, simple, intuitive empirical equation.

Using real data from the Permian basin, this paper applies the empirical equation to model the relationship between well performance and well spacing, and quantify uncertainty in that relationship. By linking this equation with a simple economic model, the paper shows how to make appropriate well spacing decisions under uncertainty, and how those decisions would change due to changes in reservoir deliverability or commodity price.

Compared to similar methods in the literature, this approach better captures the physics associated with overlap in drainage areas for adjacent unconventional wells, while maintaining simplicity and ease of implementation. The paper also discusses how to integrate various diagnostics that give information about fracture geometry, to help guide the bounds of uncertainty in the well performance relationship. Even with limited data, this approach can be applied to yield useful information for decision makers about how to adjust unconventional pad design to improve development plan economics.
Statistical and Machine-Learning Methods Automate Multi-Segment Arps Decline Model Workflow to Forecast Production in Unconventional Reservoirs
Authors: Jha Himanshu Shekhar , Khanal Aaditya , Lee John
Published: March 2022

This paper provides a workflow to automate the application of multi-segment Arps decline model to forecast production in unconventional reservoirs. Due to significant activity in the shale plays, a single reservoir engineer may be tasked with managing hundreds of wells. In such cases, production forecasting using a multi-segment Arps model for all individual wells can be a challenging and time-consuming process. Although popular industry software provide some relief, each approach has its individual limitations. We present a workflow to automate the application of multi-segmented Arps decline model for easier and more accurate production forecasting using suitable statistical and machine learning methods.

We start by removing outliers from our rate normalized pressure (RNP) data using angle-based outlier detection (ABOD) technique. This technique helps us clean our production data objectively to improve production forecasting and rate transient analysis (RTA). Next, we correct the non-monotonic behavior of material balance time (MBT) and smooth the RNP data using a constrained generalized additive model. We follow it by using the Ramer–Douglas–Peucker (RDP) algorithm as a change-point detection technique to automate the flow regime identification process. Finally, we calculate a b-value for each identified flow regime and forecast future production. We demonstrate the complete workflow using a field example from shale play.

The presented workflow effectively and efficiently automates the rate transient analysis work and production forecasting using multi-segment Arps decline model. This results in more accurate production forecasts and greatly enhanced work productivity.

The workflow presented, based on selected algorithms from statistics and machine-learning, automates multi-segment Arp’s decline curve analysis, and it can be used to forecast production for a large number of unconventional wells in a simple and time efficient manner.
Machine Learning Enhanced Upscaling of Anisotropic Shear Strength for Heterogeneous Oil Sands
Authors: Zhang Bo , Ma Zhiwei , Zheng Dongming , Chalaturnyk Rick , Boisvert Jeff
Published: March 2022

Weak shale beddings are widely distributed in the overburden and reservoir of oil sand deposits and lead to reduced anisotropic shear strength. Understanding the shear strength of the overburden and the reservoir is important in risk assessment of slope stability in open-pit mining and caprock integrity of in-situ thermal recovery of oil sands while optimizing the production of bitumen.

Due to the restrictions of computational efficiency, cells used for simulation cannot be smaller enough to capture the details of heterogeneity in the reservoir. Therefore, a robust and efficient upscaling technique is important for modeling the impact of heterogeneity on the deformation and failure of oil sands during mining and in-situ recovery. However, current analytical and numerical upscaling techniques cannot provide computationally efficient geomechanical models that consider the impact of inclined shale beddings on shear strength. Therefore, we propose a machine learning enhanced upscaling (MLEU) technique that leverages the accuracy of local numerical upscaling and the efficiency of machine learning techniques. MLEU generates a fast and accurate machine learning-based proxy model using an artificial neural network (ANN) to predict the anisotropic shear strength of heterogeneous oil sands embedded with shale beddings. The trained model improves accuracy by 12%-76% compared to traditional methods such as response surface methodology (RSM). MLEU provides a reasonable estimate of anisotropic shear strength while considering uncertainties caused by different configurations of shale beddings. With the increasing demand for regional scale modeling of geotechnical problems, the proposed MLEU technique can be extended to other geological settings where weak beddings play a significant role and the impact of heterogeneity on shear strength is important.
A Novel Approach to Post-Combustion Carbon Capture Processes in Natural Gas Plants By Reduction of Solvent Regeneration Time
Authors: Ekpotu Wilson , Nwabueze Queen , Akintola Joseph , Obialor Martins , Ansa Idongesit
Published: March 2022

Objectives/Scope

Carbon Capture processes have been utilized in various sectors, but limitations in its large parasitic load have been observed in its use in Natural Gas Process Plants, and that is mostly associated with the energy penalty incurred during its processes. The energy penalty is mainly caused by the solvent regeneration in the stripper column, the CO2 compression process, and the low amount of CO2 levels in the combustion flue gas, which is usually less than 15% (7-14 % for coal-fired and as low as 3% for gas-fired). This research work, therefore, has the objective of solving the challenges of solvent regeneration time in the stripper column, as the packing arrangement, corrugation angle, and crimp height can influence the capture efficiency through the solvent.

Methods, procedures, process

Aspen HYSYS was adopted for modeling the absorption rate through the stripper column in order to understand the hydrodynamic phenomenon in absorbers using solid absorbents under plug flow and well-mixed flow conditions. The rate fraction was analyzed at various process configurations and staged regeneration simulation processes in a packed column considering enthalpy changes at both gas and liquid phases.

Results, Observations, Conclusions

The results showed a 20% reduction in the solvent regeneration time, as against existing processes & technologies. It was observed that operating at a lower circulating rate results in a lower utility requirement on the reboiler hence increasing the circulation flow rate, which has little to no effect on the condenser utility. And this additionally led to a reduction in the energy penalty, as low-pressure steam was used as the energy input for the solvent regeneration process, thus posing a significant efficiency penalty. In conclusion, the modeling by the process optimization and modification of the post-combustion carbon capture plant reduced the regeneration energy requirements. Novel/Additive Infirmation: The solvent solution flowrate in the absorber was optimally considered with various lean CO2 solvent loadings in order to achieve higher CO2 capture and removal efficiency.
Carbon, Capture, Utilization and Storage CCUS: How to Commercialize a Business with No Revenue
Authors: Terdal Rohit Madhva , Steeghs Nathan , Walter Craig
Published: March 2022

Canada has joined the growing list of countries committed to achieving net zero emissions by 2050. This will require a rapid transition to carbon-free energy systems over the next three decades, with Carbon Capture, Utilization, and Storage (CCUS) a core component of unlocking Canada's decarbonization objectives.

It is estimated that Canada will need to capture upwards of 100 million metric tonnes of CO2e per year through CCUS to achieve net zero by 2050. However, Canadian CCUS projects currently face a plethora of commercial hurdles, ranging from capital intensive technology, long investment time horizons, lack of clarity of government incentives and policies, and disjointed carbon markets.

Carbon pricing policies are one lever to drive industry adoption of CCUS, but a cohesive industry and government collaboration is required to establish the national infrastructure needed to scale and support the development of CCUS in Canada.

The recent announcement of the Oil Sands Pathways to Net Zero comprises of six oilsands producers, representing 90 percent of oilsands production, and signals a willingness of industry to come together with government to tackle these issues and support the oil sands industry which is projected to add $3 trillion to GDP by 2050. The central pillar of their vision is the use shared transportation infrastructure and storage hubs. This model will require significant government support but what is the right model to secure Canada's future while de-risking public funding.

Policy development is still required by government bodies to encourage the investment in, and the implementation of these multibillion-dollar, long term projects. The announcement of a Canadian federal investment tax incentive and enforcement of the incoming clean fuel standard may further drive organizations to incorporate CCUS into their decarbonization plans. To proceed, industry will require further clarification to determine the effects of policy decisions and potential government partnerships will have on the cost structure and commercial viability of CCUS projects.

This paper will outline some of the current commercial barriers that industry faces with the adoption of CCUS. It will provide a roadmap on how to mobilize and partner to scale CCUS in Canada.
Assessment of Oil Recovery Methods for Reservoirs in the Flemish Pass Basin
Authors: LaFitte C. , James L. A.
Published: March 2022

In recent years, the Flemish Pass Basin has been gaining momentum as an area of potential high-volume resources on the frontier of remote, deep-water offshore oil development. This simulation study utilizes three sector models representing regional, discovered reservoirs, and two tuned fluid models representing oil sampled from wells in the Flemish Pass Basin. Generally speaking, WAG is considered a late-life enhanced oil recovery (EOR) technique, while implementing WAG immediately upon first oil for secondary recovery is less common; however, may be equally or more valuable.

This study aims to evaluate three secondary oil recovery methods, water flooding, gas flooding, and water-alternating-gas (WAG) flooding. Each recovery method is simulated with Schlumberger’s ECLIPSE reservoir simulator and uses a combination of three distinct reservoir geo-models and two fluid models. This study is a sensitivity analysis using geo-models that represent three discovered regions and two sampled fluids from the Flemish Pass Basin. The study is aimed at evaluating the effects of the various recovery methods over a duration of either five- or twenty-year forecast periods.

Results from this study capture an inherent uncertainty by drawing from eighteen simulation cases to quantify the relative benefit of each recovery method. These results indicate that using WAG as a secondary recovery method can yield a 4% to 10% increase in recovery over water or gas flood, and that secondary WAG can extend a well pair’s production plateau by up to 80% in specific circumstances.

Further observations indicate that secondary WAG in light oil reservoirs yield a ∼10% increase in recovery over secondary water or gas flooding. Using WAG in a medium oil reservoir yields a 4% to 9% increase in recovery over water flood, and a 2% to 16% increase in recovery over gas flood. In terms of geology, WAG is observed to be most valuable in ultra-high-quality reservoirs. The better the reservoir quality, the more recovery improvement. In terms of fluids, the medium oil responds best to the gas injection phase of WAG while the light oil appears to respond well to both phases. During development optimization, these trends can be accounted for in the injection cycle timing and duration for each phase.

In terms of using WAG as a tertiary recovery method after a period of water or gas flooding, tertiary WAG is observed to be most beneficial in the low to medium quality reservoirs. Tertiary WAG extends the production duration and results in a ∼4% increase in recovery beyond water flooding. Study results go on to quantify the differences in water and gas breakthrough as a factor of pore volume injected (PVI) and conclusions further indicate which reservoirs are best suited for each recovery method.
Evaluating the Prospect of Oil Production in Tight Winterhouse Formation Rocks in Western Newfoundland
Authors: Hawco Jessica , Burden Elliott , Sripal Edison , James Lesley
Published: March 2022

The Winterhouse Formation (Port au Port Peninsula, western Newfoundland, Canada) is a lateral equivalent to the Utica and Macasty formations farther west. With hydrocarbon stains and odours as a guide towards a common and regional upper Ordovician hydrocarbon system, Winterhouse rocks may yet contain their own suite of source reservoir and seal strata, with coarser, sandier beds perhaps playing host to other varieties of conventional and unconventional hydrocarbon traps. Hence, addressing basic properties of fluid transmission is an important and unknown variable that needs to be addressed for this formation. In this pilot study, Mercury Intrusion Porosimetry (MIP) is applied to measure the petrophysical properties of a single tight (low porosity, low permeability) quartz-carbonate sandstone sample from a Winterhouse outcrop. As a tool, Mercury Intrusion Porosimetry is strongly dependent on conformity of sample size and shape as a determinant of pore accessibility. Hence two sample types (i) plugs and (ii) cuttings (both real and artificial) are analyzed to explore aspects of core and cuttings preparation and data reduction work flow measurements of storage and transport properties. For artificial "cuttings" a horizontal 2.5 cm core plug and rock fragments are crushed and sieved to replicate fine and coarse fractions. For porosimetry, a Micromeretrics AutoPore IV porosimeter with a maximum pressure of 33,000 psi is used to determine the porosity, pore size distribution, surface area, and bulk density of all samples. Additionally, the FEI Quanta 650 Field Emission Gun (FEG) SEM is used to take images of the pore structure. Mineralogy is determined from the GXMAP measurement mode within FEI Mineral Liberation AnalyzerTM software. A comprehensive analysis corroborating results from MIP and SEM indicates that for these tight rocks, and namely, outcrop plugs, artificial cuttings, and real drill cuttings from a nearby well, all show a similar spectrum of results, but smaller coarse fragments are recommended for reliability. In terms of the Winterhouse strata, it is clear that some of this rock is very tight and highly cemented, but that it also possesses fractures and high permeability values which may make it a good unconventional reservoir. These porosity-permeability results are simply a beginning in a search to understand the petrophysical properties of the strata on the western coast of Newfoundland. The western part of Newfoundland has seen extensive oil exploration efforts in the last few decades, these efforts have resulted in little success. A large degree of this is due to the complex geological history and overall lack of knowledge concerning the structure and diagenesis of these rocks (Cooper et al, 2001). This study will support the new sampling programs in the hope of gaining new insights into potential oil exploitation.
Performance Analysis of Autonomous Inflow Control Valve in a SAGD Late Life Process with Non-Condensable Gases
Authors: Taghavi Soheila , Aakre Haavard , Moldestad Britt M. E.
Published: March 2022

The performance of an autonomous inflow control valve (AICV), used to restrict the inflow of unwanted fluids like gas and/or steam was simulated using an industrial reservoir simulator. The simulation results were used to determine how AICVs can improve the oil recovery in steam assisted gravity drainage (SAGD) operations. Utilizing inflow or flow control devices (ICDs/FCDs) in SAGD wells is a method with promising results. FCDs delay steam breakthrough and increase the oil recovery. The recently developed technology, AICV, further improves the oil recovery from SAGD operations. This paper provides a summary of the test data acquired from the full-scale flow loop testing that replicates the downhole operating conditions. Single and multiphase flow performance of an orifice type ICD and AICV is presented and compared. The results confirm the ability of the AICV to restrict the production of gas and/or steam. A performance analysis based on the results from the experiments and well case simulations is presented. The paper also presents an innovative approach on analyzing the well conditions which brings an insight into SAGD production wells completed with AICVs.

Simulations are performed in different scenarios of a SAGD late life process with non-condensable gases (NCGs), and these results confirmed a significant reduction in the gas liquid ratio (GLR), and an increased oil production when using AICV compared to the open hole case. Simulation results demonstrated that utilizing AICV in the SAGD production wells will reduce the gas and steam production by 64%. The reduction of steam production from the breakthrough zones allows a lower bottom hole pressure. This gives a higher sandface drawdown in the zones with less mobile oil, and thus a higher production from these zones. Further, this forces the steam chamber to be more evenly distributed along the different zones, resulting in increased oil recovery.

Considering the environmental aspect, AICV can contribute to a considerable reduction in the steam use which will consequently reduce the energy and water usage for steam generation. As a result, utilizing AICV in SAGD operations will improve the economics of SAGD projects.
Assess the Impact of Shallow Water Flow Geohazard on Drilling Operations in the Riserless Sections of Deepwater Well Construction
Authors: Kulkarni Nitin , Heinze Lloyd
Published: March 2022

Riserless drilling of the upper intervals of subsea wells has been standard practice in deepwater well construction, while taking mud returns to the sea floor. It has dramatically increased the safety of drilling shallow sections of subsea wells by reducing the hazard of handling gas at the rig, should shallow gas zones be encountered. It has also been very beneficial in controlling shallow water flows in deepwater areas of the Gulf of Mexico (GOM).

The shallow water flow (SWF) is a typical offshore drilling hazard, defined as the phenomenon involving the flow of water from the surrounding region of a casing up to the ocean floor together with formation sands and sometimes free gas. The flowing water is driven by a pressure difference that occurs when the drill bit has encountered the unconsolidated but over-pressured sand sections.

In the past 40 years of drilling practices, the SWF hazard has been experienced in several deep-water basins around the world, especially in the deep-water area where the water depth ranges from 1300 to 8200 ft and the formation depth ranges from 300 to 4000 ft below mud line (BML).

Shallow water flows from overpressure aquifers have been a serious concern in the deepwater Gulf of Mexico for drilling and production operations. They can create significant financial and operational risks for exploration and development projects. In the GOM, SWF intervals typically occur between 300 and 2,500 ft BML and in water depths greater than 1,500 ft. If left unchecked, the disturbance from the water flow can cause loss of soil strength surrounding the wellbore, thereby compromising the structural integrity of the well. In extreme cases, SWFs have led to collapsed casing and/or total loss of wellbores.

The paper aims to present the origin of shallow water flows in a deepwater environment and mitigation strategies adopted by industry to carry out the operations safely.
An Experimental Study of Single Component Adsorption/Desorption Isotherms
Authors: Wolf Jeremy , Maaref Sepideh , Tutolo Benjamin , Kantzas Apostolos
Published: March 2022

Within tight reservoirs, gas is stored both as free gas contained in the pores and adsorbed gas on the rock matrix. Adsorbed gas exhibits liquid-like densities resulting in significantly more gas being stored on the rock surface. By having accurate adsorption/desorption data of injected and reservoir gases, one can acquire a better understanding of the true original gas in place, as well as how to maximize production through optimal enhanced gas recovery (EGR) techniques.

The aim of this research is to measure the adsorption/desorption isotherms of single-component gases on activated carbon in a series of pressure steps up to 1500 psi. The experiments are conducted at varying temperatures to establish a wide array of isotherms. Temperatures are maintained through the use of a water bath. The obtained isothermal pressure data is modeled using the Gibbs sorption isotherm and the Langmuir mathematical model, the most popular and simplistic approach. Furthermore, by plotting pressure divided by adsorption capacity as a function of pressure, Langmuir parameters are determined.

From the experiments, isothermal pressure data was able to be modeled using the Gibbs sorption isotherm and the Langmuir isotherm and Langmuir parameters were determined and compared. It was observed that decreasing temperature and increasing hydrocarbon molecular weight were the main contributing factors to higher sorption capacities of the single component gases. It is important to quantify both adsorption and desorption processes because in EGR techniques such as cyclic solvent injection (CSI) injected gas is competitively adsorbing onto the rock, causing the adsorbed reservoir gas to be displaced, desorb, and subsequently be produced. Due to the aforementioned irreversibilities, by using adsorption metrics to quantify the amount of gas desorbed within the reservoir, gas production may be overestimated.

To date, most adsorption/desorption experimental work has been conducted on methane, carbon dioxide, and nitrogen. This research aims to expand on previous literature by performing adsorption/desorption experiments on higher chain hydrocarbons, such as ethane and propane. By doing so, CSI EGR schemes can be more meticulously modeled as the inclusion of higher chain hydrocarbons allows for the model sorption inputs to be more representative of typical unconventional reservoir gas. This in turn will allow for more accurate production forecasting, helping minimize the financial risk of costly EGR projects.
Mitigating Surge and Swab by Changing Tripping from a Batch to a Continuous Process
Authors: Pilgrim Rick , Butt Stephen
Published: March 2022

A significant portion of the time required to drill an oilwell is spent moving the drillpipe in or out of the wellbore, called "Tripping". The drill crew must trip pipe for numerous reasons. These include changing the bit as it wears out, inserting new casing strings, cleaning and treating the drillpipe and/or wellbore to allow more efficient drilling, and to run in various tools that perform specific jobs required at certain times in the oilwell construction plan.

The traditional tripping process (TTP) inherently creates pressure transients developed from stopping and starting the vertical motion of the drillpipe during connections. These pressure transients called, "Swapping" and "Surging", contribute to borehole instability, restrict tripping speed, and increase non-productive time (NPT). This paper focuses on the benefits that can be gained from a bottom hole pressure (BHP) surge/swab perspective. Specifically, how these undesirable pressure transients can be dramatically reduced by modifying the TTP from a start/stop (batch) process to a continuous tripping process (CTP), where drillpipe tripping speed is kept constant throughout the entire tripping sequence and thereby significantly reducing the numerous starts and stops associated with traditional tripping.

In this paper both the TTP and CTP systems were kinematically modeled using a custom simulator coded in C#. It is important to note that all the equipment used in the modified CTP exists and has only been reconfigured to facilitate a continuous process. This is inclusive of real-life limits for such items as derrick height, traveling block (TB) height as well as velocity, acceleration and inertia limits for TB, crown blocks, drawworks, their associated reeving configurations as well as racking system arms, grippers, and latches.

The simulation results indicates that for a continuous tripping system we can achieve a ~73% slower average pipe speed that has an overall tripping speed approximately 4 times faster than traditional tripping. CTP decreased BHP deviation significantly. The continuous tripping process was awarded a patent by USTPO in 2016, US 9,441.247 B2.
Child/Parent Well Interactions; Study the Solutions to Prevent Frac-Hits
Authors: Haghighat Alireza , Ewert James
Published: March 2022

Maximizing the hydrocarbon recovery for a given unconventional asset often clashes well spacing considerations against completion design. This can result in complex child/parent well interactions that can include frac-hits and reserve reallocation. In planning for a successful field development within the vicinity of producing assets, the risk of frac-hits must be evaluated carefully to minimize any damage and potential profit loss.

Multiple factors such as depletion, well spacing, rock properties, and completion design all contribute to the risk of a frac-hit. Understanding the probable cause of a frac-hit allows for appropriate mitigation operations such as parent well pre-loading, re-fracturing, increased offset spacing, and revised completion design to be considered. To evaluate each remedial operation, several unconventional Permian oil wells were studied with Rate Transient Analysis (RTA) to identify well and reservoir characteristics. Based on these results multi-phase/multi-well numerical modeling was performed to evaluate how effective each operation would be to minimize the risk of future frac-hits.

Simulation results regarding pressure and production performance of parent/child wells will be presented applying different frac-hit mitigation methods. Pressure build-ups around the wellbore were determined considering parent well shut-in; gas injection and water injection (pre-loading). Water injection resulted in the highest pressure build-ups in the vicinity of the wellbore (which reduces the risk of a frac-hit); however, it takes several months to unload the injected water. Production uplift due to a re-fracturing operation was evaluated with numerical modeling assuming different fracture designs that include the extension of current hydraulic fractures and adding new fractures. The performance of child and parent wells were then investigated by changing the well spacing and completion. Optimum combinations of well spacing and completion designs were determined to maximize child/parent well production and minimize the risk of frac-hits. Finally, the impact of parent well depletion on the productivity of the child well is determined.

This work presents a replicable and accessible workflow to assess the impact of multiple frac-hit mitigation methods on reservoir performance.
Characterization of Dynamic Wormhole Growth and Propagation During CHOPS Processes by Integrating Rate Transient Analysis and Pressure-Gradient-Based Sand Failure Criterion
Authors: Jiang Liwu , Liu Jinju , Liu Tongjing , Yang Daoyong
Published: March 2022

In this work, theoretical models have been formulated, validated, and applied to characterize the dynamic wormhole growth and propagation dynamics during CHOPS processes by integrating rate transient analysis (RTA) and a pressure-gradient-based (PGB) sand failure criterion. More specifically, a coupling fluid-solid flow model is proposed by incorporating the recently proposed PGB sand failure criterion with sand production. Then, the source function method is applied to solve the fluid flow problem in the matrix subsystem by considering each generated wormhole segment as a sink source, while the finite difference method is applied to solve the fluid-sand flow problem in the wormhole subsystem. The sand failing at each segment is induced and propagated once the PGB sand failure criterion has been reached. Furthermore, transient rate type curves are generated to determine the dynamic wormhole network conditioned to the measured fluids and sand production profiles. Also, effects of the PGB sand failure criterion and reservoir properties on the transient rate behaviour for CHOPS wells can be examined and analyzed. A gradual increase in the production rate profile occurs at the early times due to the wormhole growth and propagation. The wormhole network can be dynamically characterized by matching both the sand production rate and transient fluid production rate. The former is found to be greatly affected by the breakdown pressure gradient, while the effective wormhole coverage and intensity dominate the latter. Once the pressure responses on a static wormhole network are validated with numerical simulation, the newly proposed method has been extended to field applications under various constraints, demonstrating that the fluid and sand production data of CHOPS wells can be integrated to accurately characterize the dynamic wormhole network within a unified, consistent, and efficient framework.
A CPP Model to Asphaltene Precipitation; Mapping p-p Interactions onto an Equation of State
Authors: Alimohammadi Sepideh , James Lesley , Zendehboudi Sohrab
Published: March 2022

Asphaltene may destabilize during the oil recovery, transportation, and processing and cause significant flow assurance problems that negatively affect the operational expenditures (OPEX). Modeling investigation of asphaltene precipitation and consequently deposition is a vital research component in flow assurance requiring the accurate description of the phenomena under various operational conditions. The structure of asphaltene molecules and the presence of heteroatoms play a significant role in the intermolecular forces and the mechanism of asphaltene aggregation. Nevertheless, the intermolecular forces, e.g., polar forces, and their addition to thermodynamic modeling of asphaltene phase behavior still need investigation. While the traditional equation of state (EoS), e.g., cubic EoS, does not provide any special treatment to polar energy, the π-π interaction and polar effect can be mapped into the EoS using a separate polar term. In this research, we use cubic EoS, cubic plus polar (CPP) EoS, and molecular dynamics (MD) (three different modeling approaches) to analyze the effect of asphaltene structure and operational conditions on the precipitation phenomenon. Comparing the error associated with correlation and prediction results of the models, we show that the CPP approach using optimization to tune parameters of the EoS is the most reliable approach, followed by CPP EoS using MD to find dipole moment for the aryl-linked core asphaltene structure. The CPP EoS and MD optimizing island structure for asphaltene is the third-best model, and SRK EoS is a less efficient approach. Considering the values for dipole moment and molecular weight of asphaltene, along with correlation and prediction ability of the techniques, it is revealed that polar forces can be considered in a separate term in addition to van der Waals force to increase the model efficiency. Moreover, the aryl structure with a 750 g/mol molecular weight and one/two thiophene/pyridine group is the most proper asphaltene structure.