Particle gel propagation and blocking behavior through high permeability streaks and fractures

Water channeling, one of the primary reservoir conformance problems, is caused by reservoir heterogeneities that lead to the development of high-permeability streaks and fractures. These streaks and fractures prevent large amounts of oil from being recovered. The ultimate objective of this research was to provide comprehensive insight into designing better particle gel treatments intended for use in large openings, including open fractures, high permeability streaks, and conduits to increase oil recovery and reduce water production. An intensive laboratory study was conducted to better understand the injection and placement mechanisms of millimeter and micron size preformed particle gels (PPGs) through thief zones. Core flooding experiments were also conducted to investigate the effectiveness of micron-size PPGs to correct the heterogeneity within reservoirs. The effectiveness of combined conformance control (gel), stimulation treatments (acid), and mobility control treatments (polymer) were examined for their ability to increase oil recovery from non-cross flow heterogeneity cores. A PPG partially blocks a large channel rather than fully blocking it. A PPG pack permeability of oil was much more than PPG pack permeability of water. The gel formed a cake on the low-permeability layers, reducing their permeability. Fully swollen gel particles had better injectivity than did partially swollen particles with a larger diameter size. The PPG was used successfully used to correct both non-cross and cross flow heterogeneity problems. Combined PPG with either acid or polymer showed promise results of increasing oil recovery. --Abstract, page iii

The Potential of using Micro-Sized Crosslinked Polymer Gel to Remediate Water Leakage in Cement Sheaths

Cementing is a major step in the construction and sealing of hydrocarbon wells. During the life cycle of the well, cement is prone to cracking due to a change in downhole conditions. This research investigates the use of micro-sized crosslinked polymer gel as a sealant material to mitigate cracked cement sheaths. Two experimental setups were designed to investigate water leakage through cement. The impact of polymer gel strength on the gel\u27s ability to seal cement cracks was investigated using four gel strengths, including 500 pa, 1200 pa, 1450 pa, and 2440 pa. The impact of the width of the cement crack was also investigated using 0.5, 2, 3.2, and 6.75 mm. Results showed that the polymer gel propagated across fractures like a piston with no gravity effect and with angle with gravity effect. Blocking efficiency to water flow is controllable, and it can be increased if a high strength polymer gel is selected. To the authors\u27 knowledge, very little experimental work has been conducted to investigate the use of crosslinked micro-gel in cement zonal isolation. This study can provide the oil and gas industry with a better understanding of the materials to use in improving cement zonal isolation and thus reduce the impact of cement failure

Flow of Carbon Dioxide in Micro and Nano Pores and its Interaction with Crude Oil to Induce Asphaltene Instability

This study presents an investigation of the flow mechanism of carbon dioxide (CO2) through nano and micro pores and the impact of this flow on oil mobilization and asphaltene instability in the crude oil. The flow mechanism of CO2 is determined using numerical modeling through the Knudsen number to determine the flow regimes under different thermodynamic conditions. Following this, the oil production and asphaltene stability are studied using a filtration vessel supplemented with nano and micron sized filter membranes. The effect of varying CO2 injection pressure, oil viscosity, porous media pore size, and porous media thickness on oil mobilization and asphaltene stability are studied. Regarding the flow regimes, it is found that four distinct flows are observed during CO2 injection in the nano and micro pores. These flow regimes included diffusion, transition, slippage, and viscous flow. As the pore size increases, the flow becomes viscous dominated. Crude oil flow through the nano pores required higher pressure and also resulted in more severe asphaltene damage and plugging compared to the micro pores. Increasing the CO2 injection pressure increased oil production and decreased the asphaltene concentration in the bypassed crude oil, which is the oil remaining in the filtration vessel and could not be produced. The lower oil viscosity is associated with a lower asphaltene concentration and thus yields an overall higher oil viscosity as well. By undergoing this research, a better understanding of how the CO2 flows through nano and micro pores can be achieved, and oil mobilization and asphaltene instability with time can also be understood

Laboratory Comparative Study of Anionic and Cationic High-Viscosity Friction Reducers in Moderate to Extremely High Total Dissolved Solids Environments

High-Viscosity Friction Reducers (HVFRs) Have Been Recently Gaining More Attention and Increasing in Use, Not Only as Friction-Reducing Agents But Also as Proppant Carriers. Reusing Produced Water Has Also Been Driven by Both Environmental and Economic Benefits. Currently, Most Friction Reducers on the Market Are Anionic Friction Reducers, Which Are Fully Compatible with Most Produced Water with Low to Medium Level of Total Dissolved Solids (TDS) But Show a Significant Drop at High TDS Conditions in Terms of their Friction Reduction Performance in Most Cases. on the Contrary, Cationic Friction Reducers Are Believed to Have Better TDS Tolerance and Friction Reduction Performance under High TDS Conditions. However, Concerns Remain About Performance of using Anionic and Cationic HVFRs with Produced Water to Transport Proppant. the Ultimate Objective of This Experimental Study is to Comparably Analyze the Proppant Transport Capabilities of Anionic and Cationic HVFRs in High TDS and Reservoir Temperature Environments. an Anionic HVFR and a Cationic HVFR, Both at 4 Gallons Per Thousand Gallons (GPT), Were Selected and Analyzed. the Rheology Measurements of These Anionic and Cationic HVFRs Were Conducted in Deionized (DI) Water and High TDS Water Conditions. Static and Dynamic Proppant Settling Tests Were Conducted at Various TDS Conditions at Reservoir Temperature. Wall Retardation and Particle Hindering on the Performance of Both Anionic and Cationic HVFRs Were Also Observed and Investigated using the Particle Image Velocimetry (PIV) Method. the Results Showed that the Anionic HVFR Had Higher Viscosity Than the Cationic HVFR Due to Larger Molecular Weight and Had Much Higher Elasticity. Increase in TDS Concentration Would Decrease the Viscous and Elastic Profiles of Both Anionic and Cationic HVFRs. in Particular, the Elastic Profile Became Negligible for Both HVFRs. Besides, the Critical Salinity Phenomenon Was Observed. above This Salinity, the Viscosity of HVFRs Was No Longer Affected by Increasing TDS Level. the Critical Salinity for Both of the 4-GPT Anionic and Cationic HVFRs Was in the Range of 30 000 to 200 000 Mg/L. Moreover, the Cationic HVFR Had Lower Critical Salinity Than the Anionic HVFR. Finally, the Correlation between Rheology and Proppant Transport Capabilities of HVFRs is Discussed in This Paper, and a Simplified Decision-Making Process of Selecting Fracturing Fluids is Proposed

A Simplified Method for Experimentally Quantifying Crude Oil Swelling during Immiscible Carbon Dioxide Injection

Immiscible carbon dioxide (CO2) injection is one of the highly applied enhanced oil recovery (EOR) methods due to its high oil recovery potential and its ability to store CO2 in the reservoir. The main mechanism of immiscible CO2 injection is oil swelling. Generally, oil swelling is measured experimentally or measured using modeling methods. This research conducts oil swelling experiments using a simplified method in order to easily and accurately measure oil swelling and determines some of the most significant factors that may impact oil swelling during CO2 injection. The impact of varying CO2 injection pressure, temperature, oil viscosity and oil volume on oil swelling capacity was investigated. The simplified method managed to accurately determine the value of oil swelling for all the experiments. One of the factors that was found to impact the method significantly was the oil volume used. The oil volume in the experimental vessel was found to be extremely important since a large oil volume may result in a false oil swelling value. The oil swelling results were compared to other researches and showed that the method applied had an accuracy of over 90% for all the results obtained. This research introduces a simple method that can be used to measure oil swelling and applies this method to investigate some of the factors that may impact the oil swelling capacity during immiscible CO2 injection

Experimental Investigation of Asphaltene Deposition and its Impact on Oil Recovery in Eagle Ford Shale during Miscible and Immiscible Co2huff-N-Puff Gas Injection

One of the challenges in extracting oil from unconventional resources using hydraulic fracturing and horizontal drilling techniques is the low primary recovery rate, which is caused by the ultra-small permeability of these resources. Consequently, it is essential to investigate gas injection methods to produce the trapped oil in shale formations. However, the injection process can cause asphaltene depositions inside the reservoir, leading to plugging of pores and oil recovery (OR) reduction. There has been limited research on using gas injection techniques to improve oil production in tight/unconventional resources, although carbon dioxide (CO2) and gas-enhanced oil recovery methods have been used in conventional resources. In order to determine whether or not the cyclic (huff-n-puff) CO2 process improves OR and aggravates asphaltene precipitation, a rigorous experimental investigation was undertaken utilizing filter membranes and Eagle Ford shale cores. After the minimum miscibility pressure was calculated for CO2, various injection pressures were selected to perform CO2 huff-n-puff experiments. Investigations were carried out at 70 °C on injection pressure, cycle number, production time, and huff-And-puff mode injection. The results demonstrated that when the pore size structure of the membranes used was smaller and gas injection cycles increased, a higher asphaltene weight percent (wt %) was determined during the static experiments (i.e., employing filter paper membranes). Miscibility improved OR in dynamic testing (i.e., using shale cores), but a more oil-wet system was detected in wettability measurements taken following CO2 huff-And-puff tests. The plugging impact of asphaltene particles on the pore structure was studied using optical microscopy and scanning electron microscopy imaging. Following the huff-And-puff tests, a mercury porosimeter revealed how severely the pores were plugged, and after the CO2 tests, the pore size distribution reduced as a consequence of asphaltene deposition. This study examines the significance of CO2 injection in OR under miscible/immiscible conditions to identify the critical parameters that could impact the effectiveness of CO2 huff-n-puff operation in unconventional formations

Settling of Spherical Particles in High Viscosity Friction Reducer Fracture Fluids

Investigating the key factors that impact fluid rheology and proppant static settling velocity in high viscosity friction reducers (HVFRs) is a critical aspect for successful proppant transport in hydraulic fracture treatment. In this study, the rheological properties of HVFRs were tested at various temperature ranges (i.e., 25, 50, 75, and 100◦C) and different HVFR concentrations (i.e., 1, 2, 4, and 8 gpt). Three sizes of spherical particle diameters (i.e., 2, 4, and 6 mm) were selected to measure the static settling velocity. The fracture fluid was tested in two fracture models: an unconfined glass model and a confined rectangular model with two fracture widths (7 and 10 mm). The settling velocity in the confined and unconfined models was measured using an advanced video camera. HVFR results exhibited acceptable thermal stability even at higher temperatures, also the viscosity and elasticity increased considerably with increasing concentration. Increasing the temperature cut the friction reducer efficiency to suspend the spherical particles for a significant time, and that was observed clearly at temperatures that reached 75◦C. Spherical particles freely settled in the unconfined model due to the absence of the wall effect, and the settling velocity decreased significantly as the HVFR concentration increased. Additionally, the fracture angularity substantially slowed the proppant settling velocity due to both the wall effect and several types of friction. This research provides insights into the rheological parameters of a high viscosity friction reducer as a fracturing fluid and its efficiency in transporting particles in bounded and unbounded fracture networks

A Data Analysis of Immiscible Carbon Dioxide Injection Applications for Enhanced Oil Recovery based on an Updated Database

Carbon dioxide (CO2) injection is an enhanced oil recovery technique used worldwide to increase oil recovery from hydrocarbon reservoirs. Immiscible CO2 injection involves injecting the CO2 into the reservoir at a pressure below which it will become miscible in the oil. Even though immiscible CO2 injection has been applied extensively, very little research has been conducted to provide a comprehensive understanding of the mechanism and the applications of immiscible CO2 injection. This research performs an in-depth data analysis is performed based on more than 200 experiments and 20 field tests from more than 40 researches to show the conditions at which immiscible CO2 injection has been applied and the most frequent application conditions. Histograms and boxplots have been generated for temperature, CO2 injection pressure, oil viscosity, molecular weight, and API gravity, CO2 solubility, and finally oil swelling to show the ranges and frequency of application for all these parameters. Finally, crossplots have been generated from the data to show the relation of pressure and temperature to CO2 solubility and oil swelling. The crossplots function to illustrate a relation between the variables and draws a conclusion as to what effect each parameter will have on the other

A Review of Carbon Dioxide Adsorption to Unconventional Shale Rocks Methodology, Measurement, and Calculation

Carbon dioxide (CO2) injection has been applied extensively in hydrocarbon reservoirs for both increasing oil recovery and CO2 storage purposes. Recently, CO2 injection has been proposed to increase oil recovery and for CO2 storage in shale reservoirs. During CO2 injection in shale reservoirs, adsorption will take place on the surface of the rock, which will impact both the oil recovery and the storage capacity. This research provides a roadmap to the different types of adsorption and the adsorption measurements and calculations with emphasis on the ones most applicable during CO2 injection in shale reservoirs. The main two types of adsorption are initially explained including physisorption and chemisorption, and the major applicable adsorption isotherms are explained and their limitations are listed. The research then focusses on physisorption and its types, and hysteresis trends since chemisorption does not occur in shale reservoirs during CO2 injection. The different methods used to measure adsorption are then illustrated and explained including volumetric, gravimetric, volumetric-gravimetric, oscillometry, and impedance spectroscopy. The different calculation methods for volumetric adsorption are then explained. Finally, the most common errors that have been observed during measurement and calculation of adsorption are listed and explained, while mentioning the method to avoid each error. This research provides a guideline to the proper and accurate measurement of CO2 adsorption on shale rock during enhanced oil recovery applications and CO2 storage operations in unconventional shale reservoirs to improve the productivity and applicability of this application

Long-Time Kinetic Impact on Key Factors Affecting Asphaltene Precipitation

The employment of predictive techniques combining kinetic and thermodynamic analyses is the succinct solution to effectively control asphaltene precipitation during crude oil production. Although thermodynamic processes and conditions have been well studied in the literature, the effect of long-time kinetics on the key factors affecting the precipitation of asphaltenes was not critically studied. This work employed a model oil for asphaltene precipitation long-time kinetic observations. Filtration and confocal microscopy experimentations for time periods of 0-7200 min were utilized to study asphaltene yields and sizes at room and high temperatures (25, 50, and 70 °C), rotation speeds (60 and 150 rpm), and precipitant concentrations (50 and 60 wt %). The results from both experiments were fitted with DLVO models. The experimental results confirmed that the effects of temperature, rotation speeds, and precipitant compositions on asphaltene precipitation were significantly affected by time. The asphaltene yields increased from 27 to 83% within 7200 min when the heptane concentration increased from 50 to 60 wt %. Conversely, increasing temperatures from 25 to 70 °C reduced the cumulative asphaltene yields by 20-40% when observed for a long time (0-7200 min). Significant reductions in the mean equivalent diameter (MED) of precipitating asphaltenes upon increasing temperature within the studied timeframes were observed via the confocal experimentations. The rotation speeds also showed an inverse relationship with asphaltene yields and particle size. A reduction from 30 to 50% of the yield was observed as the rotation speeds of the system were increased from 60 and 150 rpm. The results of this work confirmed the significant impact of contact time on the precipitation of asphaltenes. In addition, DLVO theory employed to predict the experimental data obtained from the confocal microscopy fitted the data with mean absolute errors ranging from 4.44 to 5.15, which showed significant limitations upon increasing temperature. This development is progress toward enhancing the predictability of a production route devoid of asphaltene-related problems