bluuebunny/crossref_metadata_2025_split huggingface dataset:
Dynamic Changes of Pore Structure During CO2 Mineral Sequestration in Shale
Authors: Yang Yang Ming , Chen Hao 
Published: April 2022

Abstract
The mineralization that occurs after CO2 injection into shale is one possible long-term solution considered for storage of this greenhouse gas. However, the pore structure and connectivity of rocks will be affected in the process of mineralization. The purpose of this paper is to determine the effect of mineralization on reservoir connectivity during CO2 capture and storage (CCS).
This mineralization is investigated here experimentally by injecting radially carbonate water into reactors containing rock samples. The rock samples were taken out at different mineralization times (24h, 72h, 120h, 168h), and permeability and scanning electron microscopy (SEM) tests were performed on the rock samples. According to the images of the overall characteristics and intergranular distribution characteristics under scanning electron microscopy, Avizo and Matlab software were used to divide the threshold value of gray value and statistics of gray value distribution, respectively. By defining the pore proportion degree, gray value frequency distribution and dissolution intensity, the dynamic change of pore connectivity in the process of mineralization was quantitatively analyzed.
According to the threshold segmentation calculation of gray value, different dissolution modes in different stages of carbonization process were observed, including surface dissolution and particle denudation. The gray values in different ranges are quantized to analyze the influence of different dissolution types on pore connectivity. The synergistic effect of surface dissolution and particle denudation has a positive effect on the mineralization. We demonstrate the existence of a critical reaction time for mineralization, above which reservoir pore connectivity gradually decreases. At the same time, we found that the changes of reservoir connectivity and surface corrosion strength have roughly the same trend. Finally, the decrease of permeability caused by the accumulation of dissolved particles will contribute to the formation of self-sealing phenomenon during CCS.
In this paper, the dynamic change of pore connectivity caused by mineralization during CCS is defined for the first time by statistical analysis of gray value, and the synergistic effect between surface dissolution and particle denudation is quantified, and the existence of self-sealing effect is verified. The results are of great significance for CCS.
A Novel Gas Dispersible Foam Technology Can Improve the Efficiency of Gas Injection Processes for IOR-EOR Operations in Unconventional Reservoirs
Authors: Díez Kelly , Ocampo Alonso , Restrepo Alejandro , Patiño Jonny , Rayo Juan , Ayala Diego , Rueda Luis 
Published: April 2022

Abstract
Gas injection has become one of the most investigated methods for enhanced oil recovery in unconventional reservoirs. Nonetheless, the presence of natural and induced fractures negatively impacts the gas injection efficiency due to its channeling towards nearby wells or poor coverage in the treated area due to lack of conformance. To overcome these difficulties and boost the oil recovery process by gas injection, this work presents a novel gas dispersible foam technology to improve the sweep efficiency of gas injection in unconventional IOR/EOR projects.
The development and evaluation of this technology has passed through a series of laboratory assurance stages that include fluids characterization, compatibility, and extensive coreflooding tests. A modelling approach is also presented, which was validated using lab and field data taken from the implementation of the technique in an extremely low porosity, tight and naturally fractured quartz-arenite gas condensate reservoir in Colombia. The workflow herein presented encompasses interdisciplinary components such as laboratory evaluation, reservoir modeling, treatment design, and wellsite setup and execution.
Laboratory testing and inter-well field applications results, along with the development and testing of a phenomenological modelling approach, demonstrate that the gas dispersible foam injection can be a high potential technique for oil and/or condensate recovery in unconventional reservoirs given its proven ability to improve the deep reservoir gas conformance and avoid the lack of gas containment during gas injection IOR/EOR in unconventional plays. Lab results in a tight naturally fractured sample, suggest that the estimated incremental oil recovery was ~36% and the effective gas mobility reduction was ~45%. This technique also exhibited less chemical adsorption losses, which contributes to better chemical emplacement and longer durability. The main results of the field application, including a progressive decrease in gas injectivity at the gas injector, a consistent reduction in GOR with an associated oil increase at the influenced producer well, and a reported treatment durability of ~ 6 months, were all properly represented by the model.
Each step of the workflow herein proposed not only assures the gas-based projects success, but also allows for smaller logistics footprint at the well location, along with less water consumption, which translates into cheaper and more efficient gas injection conformance operations.
First Thermo-Responsive Polymer Field Evaluation in a High Temperature Reservoir of Golfo San Jorge, Argentina. Promising Results for Cost Optimization in a Polymer Project
Authors: Hryc Maria Alejandra , Renta Daniela Verónica , Dupuis Guillaume , Leblanc Thierry , Peyrebonne Bispe Maria Eugenia , Goldman Mayra , Villambrosa Martin , Fondevila Sancet Gaston 
Published: April 2022

Abstract
This paper presents the results obtained during the first thermo-responsive polymer field evaluation carried out in Pampa del Castillo – La Guitarra field located in Golfo San Jorge basin, Chubut province, Argentina. For the selected reservoir conditions, two thermo-responsive (TR) polymers with the same backbone and different moieties content (TR 1 and TR 2) were designed as alternatives to the conventional HPAM polymer currently injected in the field. TR polymers are aimed to be injected at low concentration and low viscosities under surface conditions and are characterized by an activation temperature. Below this temperature threshold, they behave like regular HPAMs whereas above it they behave like associative polymers. In contrast to HPAMs, higher resistance factors are obtained with increasing temperature beyond the activation threshold, which would be achieved at reservoir conditions.
TR 1, TR 2 and a selected HPAM were injected in the same well and same layer, under the same conditions during a polymer injectivity test (PIT) in order to compare their performances. The evaluation was done in a multilayer, 80°C - temperature reservoir showing permeabilities around 20 mD. This reservoir had been waterflooded for 32 years before polymer injection started. The test was carried out using a compact polymer injection unit (PIUC) for 60 days involving TR 1, TR 2 and HPAM injection at different concentrations and flow rates, previously defined to target similar mobility reduction (Rm – also called Resistance Factor, ReF) according to coreflood experiences. Fall-off tests were run prior to, during and after polymer injection to assess changes in the well injectivity. Along with the operation, laboratory tests were carried out on site to monitor water and polymer solution parameters.
TR 1 and TR 2 polymers showed good injectivity, stable rheological properties and good performance during the injection test at all concentration values and flow rates. Well head pressure (WHP) recorded with TR 2 was higher than with TR 1, in accordance with the number of thermo-responsive moieties in each polymer formulation. TR polymers demonstrated to be purely shear-thinning while HPAM showed shear-thickening behavior in near wellbore conditions. These results indicate promising cost reduction that can be achieved through a concentration cut-back of 67%, while sustaining similar resistance factors under reservoir conditions.
The present article will elaborate on the first results of an injectivity test of thermo-responsive polymer technology conducted in Argentina.
Microscale Dynamics of Oil Connectivity and Mobilization by Controlled-Ionic-Composition Waterflooding at Elevated Temperature Using Synchrotron 3D X-Ray Microscopy
Authors: Qin Tianzhu , Fenter Paul , AlOtaibi Mohammed , Ayirala Subhash 
Published: April 2022

Abstract
Controlled-ionic-composition waterflooding improves oil displacement efficiency in heterogeneous carbonate rocks. Recent microscale experimental studies confirm that the injection of brines containing high sulfate ion concentrations alters the wettability of the pore surfaces and improves oil mobilization at elevated temperature. However, the dynamics of associated with changes in the microscale brine/oil/rock interactions at typical field flow rates is unclear due to the limited temporal resolutions of leading micro-CT scanners, which often require hours for data acquisition.
The goal of this study is to investigate microscale dynamics of oil connectivity and mobilization by controlled-ionic-composition waterflooding at elevated temperature using synchrotron-based 3D X-ray microscopy. Heterogeneous carbonate rocks were saturated and aged with formation brine and oil at 90 °C, then flooded with brine containing different ion types and concentrations at 90 °C. Each flooding cycle was visualized using 3D X-ray microscopy at Advanced Photon Source. This source is the brightest hard X-ray source in the U.S. and therefore enables us to visualize the oil displacement at high temporal resolutions (45s). The experimental results show that injection brine containing high sulfate concentration rapidly increases the oil connectivity across the porous medium within the first few minutes and consequently improves oil recovery from pores regardless of pore sizes.
Development of Bio-Based Surfactant Foams for Hydrocarbon Gas Disposal Applications
Authors: Jin Julia , Zuo Lin , Pinnawala Gayani , Linnemeyer Harold , Griffith Christopher , Zhou Jimin , Malik Taimur 
Published: April 2022

Abstract
There has been increasing interest in different greenhouse gas (GHG) management strategies including the reduction of methane emissions and carbon sequestration. It has been proposed that reinjection of excess produced natural gas can mitigate GHG emissions without compromising oil production. Foam has been used as a method to reduce gas mobility, delay gas breakthrough, and improve sweep efficiency. However, industrial production of petroleum-based chemicals or surfactants to generate foam can be dependent on fossil-based resources that can be scarce or expensive.
The main objective of this work was to reduce chemical cost and oil-based chemical dependency by developing an alternative biosurfactant formulation to generate high quality foam. Biosurfactant blends were ranked in comparison to single component anionic and nonionic surfactants and other commercially available surfactant blends. Bulk stability "shake tests" were done to look at initial foamability and stability of the different candidates and then corefloods in sandpacks and surrogate rocks were completed to look at if formulations would generate foam in porous media with methane gas and in the presence of crude oil. Experiments showed success in replicating chemical performance by replacing traditional oil-based surfactants with bio-based lignin derived surfactants even at reservoir conditions. High-quality biosurfactant foams reduced chemical costs, provided an alternative method to dispose of large amounts of hydrocarbon gas, and improved oil recovery through foam displacement.
Impact of Stimulated Reservoir Volume in the Efficacy of Miscible Gas Injection EOR in Shale Reservoirs
Authors: Sahai Raki , Moghanloo Rouzbeh G. 
Published: April 2022

Abstract
As the unconventional shale development matures, the industry has been actively seeking new ways to unlock incremental value beyond primary depletion. In particular, the miscible gas injection EOR via huff-and-puff technique has garnered interest in recent years. However, the pilot tests in the field have shown lower recoveries than initially predicted by laboratory and simulation studies. The objective of this study was to develop a systematic approach to upscale the EOR results from laboratory scale to field scale and better predict recoveries.
One of the issues with existing laboratory and modeling studies is the assumption of constant-pressure or constant-rate boundary conditions at the fracture interface during the soaking stage, which is rarely achieved. A mathematical model is developed to represent this scenario better by modeling mass diffusion of a limited volume of well-stirred fluid in a non-porous body (remaining injected gas in the fracture network at the end of injection phase as compressed gas) into a porous medium (matrix). The matrix is characterized as an ensemble of rock pillars separated by fracture discontinuities to represent field conditions better. The rock pillars are of different thicknesses, with their thickness gradually increasing, moving away from the main fracture cluster. And finally, the concept of Dynamic Penetration Volume, which controls the amount of contacted oil by the EOR agent, is explored further as a function of the micro-fracture distribution function. Ultimately, this information was used to derive an updated a priori equation to better predict recovery factors of EOR processes in the field. For upscaling, we integrated concepts from both geomechanics and fluid flow. We used an existing correlation relating the fracture frequency & distribution observed in the lab-scale experiments to the fracture density in the field. By doing so, we can upscale the micro-fracture distribution to their field-scale counterparts.
Although diffusion is the main transport & recovery mechanism, this study found that the fracture geometry created near-wellbore, i.e., fracture spacing & distribution, has a first-order effect on the efficacy of the huff-and-puff process in the field. It was also observed that by varying the soaking times of each cycle, the issue of penetration length could be resolved (as it increases as a function of √time). Additionally, focusing on understanding the near-wellbore fracture geometry would help operators optimize their gas injection schemes.
The updated upscaling equation will help understand the huff-and-puff process better and predict the expected recoveries in the field more accurately. Additionally, it would help operators adjust and optimize soaking times for the process using a mechanistic approach.
Successful Implementation of an EOR Field-Trial Using Surfactant Induced Wettability: Formulation Design, Implementation & Interpretation and Key Lessons Learned
Authors: Rohilla Neeraj , Katiyar Amit , Kumar Amit , Hutson Peter , Rozowski Pete M. , Gentilucci Adriano 
Published: April 2022

Abstract
Wettability Alteration from oil-wet to water-wet condition is a very promising EOR technique for producing significant incremental oil recovery from oil-wet tight pores. A thorough lab program led to development of a wettability altering surfactant formulation and was validated via various laboratory Coreflood tests. Wettability Alteration (WA) as an Enhanced Oil Recovery (EOR) technique was implemented in an offshore carbonate reservoir. The field implementation was done in a systematic step wise manner to mitigate the risk in implementing such a technology field wide.
An optimal surfactant formulation is developed on the basis of favorable phase behavior at reservoir conditions, the ability to alter wettability to a more water-wet state and cause minimal chemical losses on reservoir minerals in the form of adsorption. Surfactant formulations designed in this work are unique and provide high temperature stability (above 70 °C and in some cases up to 120 °C) and high salinity tolerance (&gt; 12 % TDS and up to 22% TDS in some low temperature cases).
Reservoir modelling, logistical challenges, Environmental Health & Safety (EH&S) considerations, field applicability, and cost implications were considered for determining the optimum solution to help de-risk field scale implementation. A long term surfactant injection pilot was then conducted to evaluate efficacy of developed solution at field scale. This paper presents a phased approach to scale up an EOR project in a highly complex offshore carbonate field. Post surfactant injection, a rigorous Monitoring and Surveillance program was put in place to carefully monitor production data and quantify incremental oil gains. The pilot demonstrates the value of a phased approach to implement and monitor EOR project in an offshore carbonate field. Injection-Production data analysis shows no adverse effects at injector and significant volumes of incremental oil produced making the trial a technical as well as economic success.
A Pore-Scale Study on the Shale-Gas Transport with CO2 Injection Applying the Lattice Boltzmann Method
Authors: Li Zhuoran , You Jiahui , Qin Guan 
Published: April 2022

Abstract
CO2 injection into the shale formation has the potential of enhanced shale-gas recovery and CO2 sequestration. The gas transport exhibits slippage and adsorption phenomena because the shale formation contains numerous nanopores and organic matters. And the transport mechanism could become more complex when considers the interactions between different gas components. To provide microscopic investigations on the shale-gas transport with CO2 injection, a LB model is developed to simulate the transport process of multi-component shale-gas. To characterize the multi-component shale-gas transport, a multi-relaxation-time LB model is developed. The interactions between CO2 and CH4 is described by introducing a diffusion force into the evolution equation. The relaxation times are determined by considering the Knudsen effect. The gas slippage is described by the bounce-back combined with the full diffusive boundary condition. The gas adsorption effect near the organic matters is captured by introducing an adsorption force between gas and organic matter nodes. In this work, we first validated the numerical model with several benchmark problems. Then the CH4-CO2 mixture transport during CO2 injection in a micro-tube is simulated. The effects of several influential factors, including the Knudsen number (Kn), adsorption effects, on the CO2 molar fraction distribution (CMFD) along the domain were analyzed. The independent impact of KN was first analyzed. Simulation results showed that when it is less than 0.05, the slippage effect is weak, resulting in piston-like CMFD. As it increases, the slippage effect is significantly increased, and the Knudsen layer becomes a flowing channel for CO2 to flow bypass the front. Thus, the trend of CMFD function changes from the piston-like form to the linear form. Because the adsorption strengths of organic matters on CO2 is stronger than CH4, we also considered the adsorption effects on the gas transport in organic tube. The results showed that when the KN is larger than 0.1, the slippage effects could become stronger due to adsorption, especially for CO2. The transport of the adsorbed CO2 could contribute a large portion of the gas transport in the small pores. The adsorbed CO2 failed to displace the CH4 at the center of pores, weakening the CO2-EGR performance. The LB model proposed in this study is capable to simulate the multi-component shale-gas transport, including the components interactions, slippage, and adsorption phenomena. The effects of the KN and adsorption phenomenon were quantitively analyzed by simulating the CH4-CO2 mixture transport during CO2 injection in a micro-tube.
An Investigation of In-Situ Upgrading the Shale Oil By Air Injection
Authors: Qin Jianhua , Wan Tao , Zhang Jing , James Sheng 
Published: April 2022

Abstract
Conventional in-situ upgrading techniques use electric heaters to heat oil shale. However, the efficiency of electrical heating method is very slow which requires preheating more than a year. Most conventional heating technologies focused on converting the oil shale, not shale oil reservoirs. The shale oil matrix is very tight and the pore scale is in micro to nano-meter. In this paper, it has been attempted to inject air into hydraulically fractured horizontal wells to create in-situ combustion of shale oil in ultra-low permeability formations. Heat is introduced into the formation through multistage fractured horizontal wells, which enhances the contact area of exposed kerogen.
The main focus of this paper is to evaluate the technical feasibility of recovering shale oil resources by air injection. It involves the application of hydraulic fracturing technology to enhance the kerogen exposure to oxygen. Heat flows from the fracture into shale oil formation, gradually converting the solid kerogen into mobile oil and gas, which can be produced via fractures to the production wells.
Assisted 3D Model Construction and Facies Propagation in Golfo San Jorge Basin Reservoirs for Modelling EOR
Authors: Llanes Jose Damian , Viñales Alejo , Juri Juan 
Published: April 2022

Abstract
Three-dimensional modelling is at the critical path to map the by-passed oil in multilayer fluvial systems in the San Jorge Basin. Integrated reservoir modelling teams dedicate an important amount of time to create these three-dimensional models to decrease risk pursuing chemical injection for enhanced oil recovery. Traditional static reservoir modelling requires an important effort from the geologist to construct the interwell correlation. The objective of this work is to show the implementation of two unsupervised algorithms to automate/assist integrated reservoir modelling. We create multiple possible three-dimensional models of real multilayer static reservoirs and accelerate simulation.
The first part of the work obtains the stratigraphic representation of the entire reservoir structure. We use the available lithology well logs as spontaneous potential and gamma ray to identify automatically the permeable and shale rocks with unbiased interpretation by their deflection responses in each well for the entire target reservoirs. Then we construct a graph in which each of the deflections is represented by a node. The edges that join each pair of nodes have an assigned weight depending on the difference in depth and the distance in plan of the nodes. We draw edge weights from a multivariate distribution with interwell distances and dipping angle. Then we use an adapted version of the Girvan-Newman algorithm to make a community detection by eliminating nongeological connections/features, to find the community with greater modularity. These communities represent the existing correlations between the deflections of the different wells.
In the second part of this work, we obtain the facies distribution in the reservoir, using one-, two- and three-dimensional Markov chains. We implemented Jaccard distance to measure the mismatch of geological features and objects between the true synthetic case and the reconstructed model.
With the modified Girvan-Newman algorithm we obtained multiple stratigraphic representations similar to the 3D model created by a geologist. Through modeling of two incomplete synthetic cross section cases using Markov chain propagation of a transition matrix the reconstruction reveals that we recover 90% of the original case even when we Input only 5% of the true data initially in the model. Then we tested a very fine real three-dimensional case created by an experienced geologist.
The Markov reconstruction algorithm was able to recover up to 60 percent of the model true real three-dimensional model. The analysis of the reconstructed model features reveals that the Jaccard distance is a reliable indicator of the geological features.
Using the computational algorithms implemented, it is possible to obtain a stratigraphic model and the facies model in less than four hours speeding up reservoir modeling. And core data is sufficient to recover a reasonable model to input to the simulator.