bluuebunny/crossref_metadata_2025 huggingface dataset:
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

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

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

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

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

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

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 (> 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

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

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

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.
Polymer Containing Produced Fluid Treatment for Re-Injection: Lab Development to Field Deployment
Authors: Pinnawala Gayani Wasana , Subrahmanyan Sumitra , Alexis Dennis Arun , Palayangoda Sujeewa Senarath , Linnemeyer Harold , Matovic Gojko , Kim Do Hoon , Theriot Timothy , Malik Taimur , Dwarakanath Varadarajan
Published: April 2022

Chemical Enhanced Oil Recovery operations involve injecting polymer and surfactants for enhanced recovery. Some of the polymer and surfactant are produced in the form of emulsions. The emulsions need to be treated to recover the oil and reuse water for mixing new polymer for injection. New treatment methods are required to effectively break these emulsions. While chemical treatment and other methods are effective in breaking emulsions formed by electric submersible pumps (ESP's), these methods are not successful in breaking emulsions formed by injected chemicals for CEOR.

Reuse of produced water is important in off-shore as well as some on-shore fields. Produced water re-injection requires mixing of fresh polymer with fluid containing produced polymer and traces of oil, which can cause potential incompatibility. Ideally, removal of all produced polymer using a viscosity reducer followed by injection of fresh polymer will improve facility reliability and uptime.

Sodium hypochlorite (NaOCl or bleach) was evaluated as a viscosity reducer (VR). Bleach can reduce the viscosity of any HPAM by breaking down the polymer. Polymer destruction fortuitously causes a breakdown of emulsions which releases oil from water and results in improved water quality. After destruction of HPAM, excess bleach was neutralized by chemical means using a neutralizer. After neutralization, the resulting water is free of excess bleach and can be reused for mixing fresh polymer for injection without the risk of degradation of newly mixed polymer. Activating the VR (acidic VR) by pH adjustment can enhance the performance of VR dramatically. Improved oil separation as well as polymer removal can be realized using this technique.
Selective Crystallization - En Route to In-Situ Deep Conformance Control
Authors: Binabdi Ali , Ayirala Subash , Gmira Ahmed , Solling Theis
Published: April 2022

We have investigated the interfacial properties at a brine-hydrocarbon boundary with the prospect of understanding the crystallization process that takes place when certain electrolytes are present in the brine and when certain surfactants are present in the hydrocarbon phase. This was done in an optical force tensiometer setup with a so-called buoyant droplet configuration. It is only specific combinations (that is not all surfactants not all electrolytes) that form crystals and we aim at utilizing this specificity to form crystal plugs in particular sections of an oil reservoir, for example in zones with high flow that can then be reduced by the crystal plugs. The treatment can potentially be tailored based on the predominant acid-type in a mixture. The current study reveals several (at least three) different modes of crystal formation. The electrolyte-surfactant combination that gives rise to the most clear-cut formation of crystals directly at the interface is involving Zn2+ or Cu2+ and dodecanoic acid (C11H23COOH). Several of the systems under study appears to be forming crystals within the hydrocarbon phase and that these crystals more the likely are a result of the surfactant associated diffusive transfer of cations into the hydrocarbon phase. The next short-term goal is to induce crystals when the hydrocarbon phase is (potentially spiked) crude oil to tailor the discoveries towards the longer-term goal: In-situ deep conformance control field applications.
Gas-Oil Ratio GOR Characterization of Unconventional Wells in Eagle Ford
Authors: Zhao Yajie , Nohavitza Jack , Williams Ryan , Yu Wei , Fiallos-Torres Mauricio Xavier , Ganjdanesh Reza , Sepehrnoori Kamy
Published: April 2022

With the increased exploration and development of unconventional reservoirs, the complicated production mechanisms of unconventional wells have gradually become a hot topic among the oil and gas industry. Due to the ultra-low permeability and porosity, the fluid phase behavior in shale reservoirs significantly differs from the conventional fluid phase behavior, increasing the production forecasting complexity. A substantial effort to better understand the mechanisms is the ability to characterize the unconventional well gas-oil ratio (GOR) behavior. The GOR always plays a critical indicator to help predict long-term oil/gas production trends and develop appropriate production strategies. In this paper, GOR behavior was discussed based on an unconventional parent-child horizontal well set in the Eagle Ford shale formation. Subsequently, fracture hit intensity can be determined through the producing GOR characterization. Afterward, the historical production data were well matched. The long-term GOR trends (20 years) were then predicted with the calibrated reservoir model. Based on the simulation results, an interpretation of the fracture hit impact on GOR behavior, and the well productivity was established. This study provides some key insights into GOR behaviors, especially for the parent-child well GOR trends with considering the impact of fracture hits. The Eagle Ford GOR is strongly influenced by the flowing bottomhole pressure. Meanwhile, the GOR trends of both parent and child wells are extremely sensitive to fracture hits, strong correlations between GOR and fracture hits are observed. Compared to the parent well, the flat GOR period of the child well is much shorter due to pressure depletion. The existence of a child well also reduces the rising speed of the parent well with a lower plateau. In addition, the long-term production prediction shows that fracture hits negatively influenced both well performances, where the child well has a more severe production loss than the parent well. Through the findings presented in this work, a better understanding of the unconventional well GOR behaviors can be obtained. The analysis approaches proposed in this paper provide valuable insights into GOR characterization and contribute to the production forecasting from unconventional plays. The results can help to improve the efficiency of reservoir management, field development, and economic valuation in future projects.
Understanding Foam Flow in Rough Carbonate Fractures
Authors: Radhakrishnan Anuradha , Gigliotti Alex , Johnston Keith P. , DiCarlo David , Prodanovic Maša
Published: April 2022

Foams are used to improve the sweep efficiency during oil recovery in carbonates. Carbonates have high permeability fractures and vugs which can alter the foam structure, potentially changing the flow and sweep efficiency of the foam. In this paper, we investigate how the roughness of fractured carbonates affects the foam structure stability. The behavior of foam in a rough and saw-cut fractures was observed experimentally and with simulations using Lattice Boltzmann method to qualitatively assess their structure. In the experiments, it was observed that a fracture with a rough surface decreased the collapse of foam lamella and increased apparent viscosity in comparison to the saw-cut fracture. In the temperature range of 40°C to 60°C, foam structure was more stable at lower ends of this temperature range. In the simulations, we observed that the foam bubbles in the smooth fracture tended to undergo Ostwald ripening. This led to a more heterogeneous distribution of bubble sizes inside the smooth fracture. Whereas the average size of the polygonal bubbles was fairly small and uniformly distributed across the rough fracture, leading to more stable foams.
A Molecular Level Study of Water-Oil Interface in the CO2 EOR Under Low Pressure Condition
Authors: Chang Qiuhao , Huang Liangliang , Wu Xingru
Published: April 2022

In this study, molecular dynamics simulations have been performed to study the interfacial properties between water and oil with different mole fractions of CO2 under 8 MPa and 345 K. Simulation results show that with the increase of CO2 mole fraction, more CO2 got adsorbed in the water-oil interface region. Such CO2 increase weakened water and oil interactions at the interface, resulting in a decrease of the interfacial tension (IFT). Moreover, the water-oil IFT decreased significantly from 0 to 0.40 CO2 mole fractions. But the change was small for higher CO2 mole fractions of 0.40 to 0.80. From those calculations, we conclude that in the CO2-EOR, the volume of injected CO2 needs to be at least more than 0.4 mole fraction (to the oil) to achieve a decent reduction of the water-oil IFT. This study can provide a molecular level reference for implementing the CO2-EOR in the oil field under a low-pressure condition.
Surfactant Enhanced Oil Recovery from Tight Carbonates: Core-Scale Experiments to Reservoir-Scale Modeling
Authors: Shi Yue , Mohanty Kishore
Published: April 2022

Most carbonate reservoirs are oil-wet/mixed-wet and heterogenous at multiple scales. Majority of the injected water flows through the high permeability regions/fractures and bypass the oil in the matrix due the high negative capillary pressure (Pc). To enhance oil recovery from such reservoirs, the sign of the Pc should be changed by wettability alteration (WA) or the Pc should be reduced by lowering interfacial tension (IFT). In this study, surfactants which can either alter wettability or develop ultra-low IFT were identified through laboratory measurements for the target carbonate reservoir. The performance of these two types of surfactants was systematically evaluated at the core scale and scaled-up to the reservoir scale. A reservoir-scale model was developed to simulate injection-soak-production (ISP) tests and evaluate performance of the selected surfactants at the field scale. Experiments showed that quaternary ammonium cationic surfactants have excellent WA ability, while a series of propoxy sulfate anionic surfactants showed intermediate WA and ultra-low IFT. Spontaneous imbibition tests showed that WA surfactants have fast initial oil production, while ultra-low IFT surfactants has low initial oil rate but higher final oil recovery, which was validated by mechanistic simulation. Low IFT results in low Pc and slow imbibition, but also triggers gravity-driven drainage. For ultra-low IFT system, gravity drainage is more dominant than WA, and Pc-alteration is less important than relative permeability (Kr) alteration. As reservoir thickness increases, Kr-alteration is more important than Pc-alteration. Gravity drainage is expected to be scaled up by length of matrix (L), while Pc-driven imbibition is scaled by L2. Field-scale simulation showed that low-IFT surfactant has better injectivity than WA surfactant during injection phase. In soaking phase, spontaneous imbibition by WA surfactant is much more significant than that by low-IFT surfactant. In production phase, post-waterflood achieved higher oil recovery from low-IFT surfactant treated matrix due to its low residual oil saturation and high oil relative permeability.
Screening of Topside Challenges Related to Polymer Presence in the Back Produced Fluids – Casabe Case Study
Authors: Mouret Aurélie , Blazquez-Egea Christian , Hénaut Isabelle , Jermann Cyril , Salaün Mathieu , Quintero Henderson , Gutierrez Mauricio , Acosta Tito , Jimenez Robinson , Vargas Nadine
Published: April 2022

Polymer enhanced oil recovery (EOR) pilots were implemented in various mature oilfield reservoirs in Colombia with encouraging results. That chemical EOR technology is often considered as a promising process to faster recover oil. To increase the chance of success of such an industrial project it is important not to neglect the potential impact of residual polymer in back produced effluents. The objective of this work is to highlight the impact of back-produced EOR polymer at the laboratory scale on various topside equipment before deploying the polymer injection at wider scale in a heavy oil field (18° API).

A topside facility review was first performed to collect operational conditions and parameters, to identify applied treatment technologies and to define relevant sampling locations for the laboratory study. The impact of the residual acrylamide/ATBS ter-polymer selected for the future polymer implementation was then explored in a set of experiments as part of a dedicated laboratory workflow representing the whole surface treatment chain. The scope of the study has covered primary separation, static gravity water clarifying, deep-bed filtration and heater fouling. Large residual polymer concentration and water cut ranges were investigated to anticipate some produced fluid composition change over time.

In the case studied, the selected polymer does not stabilize tight water-in-oil emulsions, but it has a negative impact on the water quality. Some compatibility issues are observed with incumbent demulsifiers, which seems to be sensitive to both polymer concentration and water cut. The fouling risk of heat exchanger is very low in the testing conditions. In the water de-oiling side, filtration and gravity settling performance are reduced but the right chemical and equipment combination enables to obtain a better water quality and to meet injection specifications targets.

Novel/Additive Information: This work illustrates that management of produced fluid containing EOR polymer has to be considered as early as possible in the project implementation. It also points out that laboratory experiments are useful to better appraise and mitigate the potential operational issues. All the results obtained in such a study are valuable guideline and input data for treatment facilities upgrade studies. In polymer flooding roadmap implementation, it is key to bond operational conditions and laboratory parameters in order to be as close as possible to the field conditions as each case is unique.
Predictive Model for Relative Permeability Using Physics-Based Artificial Neural Networks
Authors: Yoga Hanif Farrastama , Purswani Prakash , Johns Russell Taylor
Published: April 2022

Hysteresis of transport properties like relative permeability (Kr) can lead to computational problems and inaccuracies for various applications including CO2 sequestration and chemical enhanced oil recovery (EOR). Computational problems in multiphase numerical simulation include phase labeling issues and path dependencies that can create discontinuities. To mitigate hysteresis, modeling Kr as a state function that honors changes in physical parameters like wettability is a promising solution. In this research, we apply the state function concept to develop a physics-informed data-driven approach for predicting Kr in the space of its state parameters.

We extend the development of the relative permeability equation-of-state (kr-EoS) to create a predictive physics-based model using Artificial Neural Networks (ANN). We predict kr as a function of phase saturation (S) and phase connectivity (χ^), as well as the specific S−χ^ path taken during the displacement, while maintaining other state parameters constant such as wettability, pore structure, and capillary number. We use numerical data generated from pore-network simulations (PNM) to test the predictive capability of the EoS. Physical limits within S−χ^ space are used to constrain the model and improve its predictability outside of the region of measured data.

We find that the predicted relative permeabilities result in a smooth and physically consistent estimate. Our results show that ANN can more accurately estimate kr surface compared to using a high-order polynomial response surface. With only a limited amount of drainage and imbibition data with an initial phase saturation greater than 0.7, we provide a good prediction of kr from ANN for all other initial conditions, over the entire S−χ^ space. Finally, we show that we can predict the specific path taken in the S−χ^ space along with the corresponding kr for any initial condition and flow direction, which makes the approach practical when phase connectivity information is not available. This research demonstrates the first application of a physics-informed data-driven approach for prediction of relative permeability using ANN.
Evaluating the Effect of Carbonate Impurities on Wettability Alteration Using a Geochemical Model
Authors: Hao Xingjuan , Abu-Al-Saud Moataz , Ayirala Subhash , Elakneswaran Yogarajah
Published: April 2022

Wettability alteration considered as the principal mechanism has attracted more attention for low salinity waterflooding effect. It was significantly affected by electrokinetic interactions, which occurred at the interfaces of rock/brine and crude oil/brine. The mineral impurities of natural carbonate releasing ions have an important impact on the electrokinetics, which could lead to wettability shift subsequently. In this study, the effect of dolomite and anhydrite as the main impurities in natural carbonate, which caused wettability alteration, was evaluated using triple-layer surface complexation and thermodynamic equilibrium models coupled with extended Derjaguin-Landau-Verwey-Overbeek (DLVO) theory. The electrokinetics of crude oil and carbonate in brines were predicted by the triple-layer surface complexation model (TLM) based on zeta potential, while thermodynamic equilibrium model was mainly used for analyzing the carbonate impurities on wettability alteration. The equilibrium constants of reactions were determined by successfully fitting the calculated zeta potentials with measured ones for crude oil and carbonate in different solutions, which were validated for zeta potential prediction in smartwater. The disjoining pressure results show that there is a repulsion between crude oil and carbonate in Na2SO4 brine (Brine3) or smartwater (Brine4) equilibrating with calcite when comparing to that in MgCl2 (Brine1) and CaCl2 (Brine2), indicating the water-wet condition caused by the presence of sulphate ions. Moreover, the equilibrium of carbonate impurities with smartwater increases the repulsion between oil and carbonate. When the sulphate ion concentration in the adjusted smartwater exceeds a certain value, the effect of carbonate impurities on wettability alteration is not significant. Finally, the influence of smartwater pH on the interaction between oil and carbonate was evaluated with or without considering the equilibrium of carbonate impurities.
Polymer Injectivity Enhancement Using Chemical Stimulation: A Multi-Dimensional Study
Authors: Chandrasekhar Sriram , Alexis Dennis Arun , Jin Julia , Malik Taimur , Dwarakanath Varadarajan
Published: April 2022

Chevron injected emulsion polymer in the Captain field, offshore UK in the last decade at various scales (Poulsen et al., 2018). Pilot horizontal wells had exhibited faster than designed injectivity decline and Jackson et al. (2019) documented the causes to include oleic phase damage from a) injection of produced water containing crude oil after imperfect separation, and b) entrainment of injected emulsion polymer’s carrier oil. The wells were remediated with a surfactant stimulation package (Alexis et al., 2021; Dwarakanath et al., 2016). The remediation boosted the water relative permeability near wellbore which enhanced injectivity and allowed higher processing rates for subsequent continuous polymer injection.

In this work, we conducted a set of core floods in slabs of surrogate rock of varying dimension and patterns to demonstrate the beneficial effect of near wellbore stimulation in the general case. 0.04 PV of the remediation package was injected and we show consistent injectivity enhancement across the experiments. We demonstrate the dominant effect of well skin treatment on the pressure drop profile compared to flow resistance from a) residual oil saturation and b) viscous fingering. The result is an important reminder for injectivity maintenance for high polymer flood processing rates for the life of the project. Clean injection fluids were demonstrated to maintain injectivity. We show applicability of stimulation for injectors into viscous oil reservoirs with adverse viscosity ratio. The robust nature of the remediation package developed by Alexis et al. (2021) is also shown, working to efficacy on viscous oil, as well as in situ phase separated polymer. We estimated skin and stimulation depth for a line drive case with low chemical dosage finding that 0.04 pore volumes of surfactant injection at 0.33 oil saturation units gave injectivity improvement of 31%. Surfactant stimulation is thus broadly applicable to wells with oleic phase skin.
Design of Surrogate Oils for Surfactant-Brine-Oil Phase Behavior
Authors: Park Jaebum , Mohanty Kishore
Published: April 2022

Many conventional surfactant-brine-oil phase behavior tests are conducted under ambient pressure conditions without the solution gas. It is known that the solution gas lowers the optimum salinity. Researchers often mix toluene (or cyclohexane) with the dead oil and form a surrogate oil to mimic the live oil. The objective of our work is to study the effect of gas and toluene on phase behavior, and to provide the proper amount of toluene to be mixed to mimic the live oil. Effects of toluene in surrogate oil and solution gas in live oil are examined by hydrophilic-lipophilic difference and net average curvature (HLD-NAC) structural model simulation and the equivalent alkane carbon number (EACN). Experimental values from literature and our experiments are also examined to compare those with the simulation results. For the simulation, both the mole fraction and mass fraction were used to calculate mixture EACN and examine the effect of additional components. HLD-NAC simulation results showed that the mass fraction-based simulation is more accurate (~7% error) than mole fraction-based simulation (~19% error) with a toluene EACN of 1. For larger molecules like toluene in surrogate oil, EACN using mole fraction also works with a toluene EACN of 5.2. The EACN of the surrogate oil should match the EACN of the live oil to determine the proper amount of toluene in the surrogate oil.
Small Scale EOR Pilot in the Eastern Eagle Ford Boosts Production
Authors: Bozeman Tim , Nelle Will , Nguyen Quoc
Published: April 2022

Low primary and secondary recoveries of original oil in place from modern unconventional reservoirs begs for utilization of tertiary recovery techniques. Enhanced Oil Recovery (EOR) via cyclic gas injection ("huff ‘n puff") has indeed enhanced oil recovery in many fields and many of those projects have also been documented in industry technical papers/case studies. But the need remains to document new techniques in new reservoirs. This paper documents a small scale EOR pilot project in the eastern Eagle Ford and shows promising well results.

In preparation for the pilot, full characterization of the oil and injection gas was done along with laboratory testing to identify the miscibility properties of the two fluids. Once the injection well facility design was completed a series of progressively larger gas volumes were injected followed by correspondingly longer production times. Fluids in the returning liquid and gas streams were monitored for compositional changes and the learnings from each cycle led to adjustments and facility changes to improve the next cycle.

After completing five injection/withdrawal cycles in the pilot a few key observations can be made. The implementation of cyclic gas injection can be both a technical and a commercial success early in its life if reasonable cost controls are implemented and the scope is kept manageable. The process has proved to be both repeatable and predictable allowing for economic modeling to be utilized to help determine timing of subsequent injection cycles. A key component of the success of this pilot has been the availability of small compressors capable of the high pressures required for these projects and learning how to implement cost saving facility designs that still meet high safety standards.
Miniature Viscosity Sensors for EOR Polymer Fluids
Authors: Gonzalez Miguel , Ayirala Subhash , Maskeen Lyla , Sofi Abdulkarim
Published: April 2022

There are currently no technologies available to measure polymer solution viscosities at realistic downhole conditions in a well during enhanced oil recovery (EOR). In this paper, custom-made probes using quartz tuning fork (QTF) resonators are demonstrated for measurements of viscosity of polymer fluids. The electromechanical response of the resonators was calibrated in simple Newtonian fluids and in non-Newtonian polymer fluids at different concentrations. The responses were then used to measure field-collected samples of polymer injection fluids. The measured viscosity values by tuning forks were lower than those measured by the conventional rheometer at 6.8 s-1, indicating the effect of viscoelasticity of the fluid. However, the predicted rheometer viscosity versus QTF measured viscosity showed a perfect exponential correlation, allowing for calibration between the two viscometers. The QTF sensors were shown to successfully produce accurate viscosity measurements of polymer fluids within the required polymer concentration ranges used in the field, and predicted field sample viscosities with less than 5% error from the rheometer data. These devices can be easily integrated into portable systems for lab or wellsite deployment as well as logging tools for downhole deployment.