Evaluation of recrosslinkable preformed particle gel (RPPG) as a fluid loss control material during drilling operations

One of the most intense, expensive, and time-consuming problems during drilling operations is the loss of circulation, which could result in several consequences, including wellbore collapse, fluid inflow, formation damage, environmental issues, and nonproductive time. This research aims to evaluate novel materials that can mitigate lost circulation and overcome the limitation of other materials. In this research, a comprehensive evaluation of a re-crosslinkable preformed particle gel (RPPG) has been conducted to determine the extent to which it can be used to control drilling fluid losses during drilling operations. The RPPG consists of swellable gel particles that can self-crosslink to form a strong bulk gel in fractures to form strong plugging after being placed in the loss zones. Different RPPGs were investigated and evaluated for different reservoir temperature conditions, including Low-Temperature RPPG for reservoirs up to 80°C, Medium Temperature RPPG (80 to 100°C), and High-Temperature RPPG (130 °C). The effect of the RPPG swelling ratio, drilling fluid, conventional LCMs, and fracture width on its plugging efficiency were investigated. Based on this research, the LT-RPPG can withstand pressure up to 1381 psi/ft in a 2.0 mm fracture width, while MT-RPPG can seal fracture widths up to 3.0 mm and hold pressure up to 6234 psi/ft when a swelling ratio of eight is used. The HT-RPPG sealing pressure can reach up to 1077 psi/ft when a fracture width of 1.5 mm is used. Hence, Each RPPG achieved an excellent plugging and sealing performance related to its application. Thus, the RPPGs can be an excellent candidate to work as a fluid loss control material during drilling operations. --Abstract, page iv

The development of a new formulation of fly ash class C based geopolymer and assessing its performance in presence of drilling fluid contamination

Cementing is one of the most critical steps in the drilling and completion of oil wells. Traditionally, Portland cement is used for oil cementing operations; however, geopolymer materials have recently attracted much attention because they are more cost-effective and have less environmental impacts. An intensive laboratory work was conducted to obtain a new formulation of fly ash class C based geopolymer cement to be used as a potential alternative cementing material to Portland cement in oil and gas cementing. Twenty-four variations of fly ash class C based geopolymers were prepared, and by comparing several of their properties using API standard tests, the optimum geopolymer formulation was determined. The selection of the optimum formulation was based on five different tests, including rheology, density, compressive strength, and fluid loss. Further tests were performed for optimized geopolymer, including stability tests. Then, a comparison between the optimum mix design and Portland cement was done using the same tests. One of the main issues regarding oil well cementing is drilling fluids\u27 contamination. This research also investigates the effect of drilling fluid contamination with geopolymer cement to understand its impact on geopolymer rheological and mechanical performance. After geopolymer optimum design was selected, the slurries were mixed with 0, 5, and 10 weight percent drilling fluid ratio to determine the effects of drilling fluids on geopolymer properties using rheology, density, fluid-loss, and compressive strength tests. Results showed that geopolymer had better performance compared to Portland cement in the presence of drilling fluid contaminations, where geopolymer exhibited higher compressive strength compared to Portland cement --Abstract, page iv

Critical Review of Asphaltene Properties and Factors Impacting its Stability in Crude Oil

Asphaltene is a component of crude oil that has been reported to cause severe problems during production and transportation of the oil from the reservoir. It is a solid component of the oil that has different structures and molecular makeup which makes it one of the most complex components of the oil. This research provides a detailed review of asphaltene properties, characteristics, and previous studies to construct a guideline to asphaltene and its impact on oil recovery. The research begins with an explanation of the main components of crude oil and their relation to asphaltene. The method by which asphaltene is quantified in the crude oil is then explained. Due to its different structures, asphaltene has been modeled using different models all of which are then discussed. All chemical analysis methods that have been used to characterize and study asphaltene are then mentioned and the most commonly used method is shown. Asphaltene will pass through several phases in the reservoir beginning from its stability phase up to its deposition in the pores, wellbore, and facilities. All these phases are explained, and the reason they may occur is mentioned. Following this, the methods by which asphaltene can damage oil recovery are presented. Asphaltene rheology and flow mechanism in the reservoir are then explained in detail including asphaltene onset pressure determination and significance and the use of micro- and nanofluidics to model asphaltene. Finally, the mathematical models, previous laboratory, and oilfield studies conducted to evaluate asphaltene are discussed. This research will help increase the understanding of asphaltene and provide a guideline to properly study and model asphaltene in future studies

An Experimental Investigation of Asphaltene Stability in Heavy Crude Oil during Carbon Dioxide Injection

Carbon dioxide (CO2) injection is one of the most applied enhanced oil recovery methods in the hydrocarbon industry, since it has the potential to increase oil recovery significantly and can help reduce greenhouse gases through carbon storage in hydrocarbon reservoirs. Carbon dioxide injection has a severe drawback, however, since it induces asphaltene precipitation by disrupting the asphaltene stability in crude oil that bears even the slightest asphaltene concentration. This can result in severe operational problems, such as reservoir pore plugging and wellbore plugging. This research investigates some of the main factors that impact asphaltene stability in crude oil during CO2 injection. Initially, asphaltene precipitation, flocculation, and deposition were tested using visual tests without CO2 in order to evaluate the effect of oil viscosity and temperature on asphaltene stability and content in the crude oil. The results obtained from the visualization experiments were correlated to the Yen-Mullins asphaltene model and were used to select the proper chemical to alter the oil\u27s viscosity without strongly affecting asphaltene stability. After performing the visual asphaltene tests, a specially designed filtration vessel was used to perform the oil filtration experiments using filter membranes with a micron and nanometer pore size. The effect of varying CO2 injection pressure, oil viscosity, filter membrane pore size, and filter membrane thickness on asphaltene stability in crude oil was investigated. The results were then correlated with the Yen-Mullins asphaltene model to characterize the asphaltene size within the oil as well. Results showed that as the oil viscosity increased, the asphaltene concentration in the oil also increased. Also, the asphaltene concentration and filter cake thickness increased with the decrease in filter membrane pore size, since the asphaltene particles either plugged up the smaller pores, or the asphaltene nanoaggregates were larger than the pore sizes, and thus the majority of them could not pass. This research studies asphaltene instability in crude oil during CO2 injection in different pore sizes, and correlates the results to the principle of the Yen—Mullins model for asphaltenes. The results from this research can help emphasize the factors that will impact asphaltene stability during CO2 injection in different pore sizes in order to help reduce asphaltene-related problems that arise during CO2 injection in hydrocarbon reservoirs

Laboratory Evaluation of a Novel Self-Healable Polymer Gel for CO2 Leakage Remediation during CO2 Storage and CO2 Flooding

For CO2 storage in subsurface reservoirs, one of the most crucial requirements is the ability to remediate the leakage caused by the natural fractures or newly generated fractures due to the increasing pore pressure associated with CO2 injection. For CO2 Enhanced Oil Recovery (EOR), high conductivity features such as fractures and void space conduits can severely restrict the CO2 sweep efficiency. Polymer gels have been developed to plug the leakage and improve the sweep efficiency. This work evaluated a CO2 resistant branched self-healable preformed particle gel (CO2-BRPPG) for CO2 plugging purpose. This novel CO2-BRPPG can reform a mechanical robust adhesive bulk gel after being placed in the reservoir and efficiently seal fractures. In this work, the swelling kinetics, self-healing behavior, thermal stability, CO2 stability, rheology, adhesion property and plugging performance of this novel CO2-BRPPG were studied in the laboratory. Results showed that this CO2-BRPPG has good self-healing abilities, and the self-healed bulk gel has excellent mechanical and adhesion strength. Gel with a swelling ratio of ten has an elastic modulus of over 2000 Pa, and the adhesion strength to sandstone is 1.16 psi. The CO2-BRPPG has good CO2 phase stability at 65 °C, and no dehydration was observed after 60 days of exposure to 2900 psi CO2 at 65 °C. Core flooding test proved that the swelled particles could reform a bulk gel after being placed in the fractures, and the reformed bulky gel has excellent CO2 plugging efficiency. The supercritical CO2 breakthrough pressure gradient was 265 psi/feet (5.48 MPa/m). This work could offer the experimental basis for the field application of this CO2-BRPPG in CO2 storage and CO2 enhanced oil recovery

Fly Ash Class C based Geopolymer for Oil Well Cementing

For many years Portland cement has been used in oil well cementing. Even though Portland cement has been used for many years, it has several drawbacks, including operational failures and severe environmental impacts. Fly ash based geopolymer cement has been recently investigated as a low-cost, environmentally friendly alternative to Portland cement. This research develops a novel formulation of Class C fly ash based geopolymer and investigates its applicability as an alternative to Portland cement in hydrocarbon well cementing. Twenty-four variations of fly ash Class C based geopolymers were prepared, and by comparing several of their properties using API standard tests, the most favorable geopolymer formulation was determined. The effect of varying the ratios of alkaline activator to fly ash, sodium silicate to sodium hydroxide, and sodium hydroxide concentration was investigated. The selection of the formulation was based on four different tests, including rheology, density, compressive strength, and fluid loss test. Then, a comparison between the selected mix design and Portland cement was conducted using the same tests, in addition to stability tests (sedimentation test and free fluid test). Based on our results, geopolymer was found to have superior rheological and mechanical properties compared to the Portland cement. The geopolymer design, which had lower fluid loss, 93 ml after 30 min, sufficient compressive strength, 1195 psi in 24 h, and an acceptable density, 14.7 lb/gal, and viscosity, 50 cp, was further compared to the Portland cement. The higher mechanical strength of geopolymer using fly ash Class C compared to Portland cement is very promising for achieving long-term wellbore integrity goals and meeting regulatory criteria for zonal isolation

Miscible Gas Injection Application for Enhanced Oil Recovery: Data Analysis

One of the most common techniques used to increase oil recovery is gas injection. The gas injection can be either miscible or immiscible depending on the injection pressure. Miscibility can be reached when the pressure exceeds the minimum miscibility pressure (MMP). Temperature and pressure are important factors that usually affect the MMP. Oil properties play an important role in the success of miscible injection, with the miscible gas injection working optimally when oil is light. Here, we performed data analysis based on more than 1500 experiments, simulation and field tests from more than 170 researchers to show the conditions at which miscible injection can be applied. We investigated various gases, including carbon dioxide (CO2), nitrogen (N2), and hydrocarbon gases. Different statistical analysis tools, including histograms, boxplots, and cross-plots, are used in this study. The data demonstrate that CO2 is the most commonly used gas during miscible injection. The majority of studies performed their experiments at temperatures between 40 to 100 °C using oil with a viscosity of 0.25 to 1.5 cp, and an API gravity between 35.1 to 45 °API. Since a variety of gases have been investigated in this research, a variety of MMP has been reported

Investigating Geopolymer Cement Performance in Presence of Water based Drilling Fluid

Oil well cementing is one of the most important steps in drilling and completion processes and providing a full zonal isolation which is the most important features in the oil cementing. Traditionally, Portland cement is used for oil cementing operations, however, a few years ago, a new cost-effective material came to light called geopolymer. In this research, a fly ash class C based geopolymer was used. This research investigates the effect of drilling fluid contamination with geopolymer cement to understand its impact on geopolymer rheological and mechanical performance. Initially, the optimized geopolymer was prepared and mixed with different drilling fluid ratios, including 0%, 5%, and 10% by weight of cement at atmospheric pressure and ambient temperature (24 °C). Same percentages were added to Portland cement to compare it with the geopolymer. Four tests were conducted to determine the effects of drilling fluids including: rheology, density, fluid-loss, and compressive strength for different curing time (1 day, 3 days, and 7 days). Results showed that drilling fluids enhanced the geopolymer rheological behavior by improving geopolymer viscosity and reducing the fluid loss. Drilling fluids reduced the geopolymer viscosity which facilitates the pumping operation during the cementing. In contrast, mixing the drilling fluid with Portland cement had a negative effect on rheological behavior as well as fluid loss. Mixing the drilling fluid with Portland cement increased the fluid loss significantly. In term of compressive strength, as the amount of drilling fluids increased, the compressive strength of geopolymer was not significantly affected. After 3 days curing time, geopolymer lost about 8.5% of its strength when 5% of drilling fluids weight percent was added. Whereas, Portland cement has lost 38.4% of its strength when 5% of drilling fluids weight percent was added. After 7 days curing time, geopolymer lost about 23% of its strength when 5% of drilling fluid by weight of cement was added. However, Portland cement lost 49% of compressive strength in the same conditions. These obtained results indicates that geopolymer has the ability to withstand the drilling fluids contamination

Hydrolyzed Polyacrylamide -- Fly Ash Reinforced Polymer for Chemical Enhanced Oil Recovery: Part 1 -- Injectivity Experiments

Polymer Injection is a mobility control enhanced oil recovery (EOR) method used to increase recovery beyond that of primary and secondary production mechanisms. One of the most used polymers in the hydrocarbon industry due to its cost, availability, and ease in handling is hydrolyzed polyacrylamide polymer (HPAM). Even though this polymer is widely used, it has been reported to degrade under different conditions. Another major parameter affecting polymer flooding is the injectivity, or the ease by which the polymer can be injected. This research reinforces HPAM with fly ash, which is an extremely low cost material, and studies the injectivity of this new reinforced polymer at different conditions. Different reinforced polymer solutions were prepared, and the stable solutions were determined and used for the injectivity experiments. The impact of varying polymer concentration, fly ash concentration, and polymer injection flowrate on polymer injectivity was investigated. Results showed that the new reinforced polymer could be easily injected and thus the presence of fly ash did not impact the ability to inject the polymer greatly. This novel HPAM -- fly ash polymer can prove to be a better alternative to using conventional HPAM in polymer injection operations to increase oil recovery

The Impact of Thermodynamic Conditions on CO₂ Adsorption in Unconventional Shale Reservoirs Using the Volumetric Adsorption Method

Carbon dioxide (CO2) injection is an enhanced oil recovery method that can increase oil recovery from different types of oil reservoirs. It has been recently applied in unconventional shale reservoirs for both enhanced oil recovery and CO2 storage applications. This research explains the main mechanism of adsorption, which is the main force by which CO2 can be stored in shale reservoirs, and then performs an experimental study to investigate the factors impacting CO2 adsorption using the volumetric adsorption method. The review will cover the main definition of adsorption and how it can help in CO2 storage. It will also include the mathematical equations used to obtain adsorption for the volumetric adsorption method. The experimental study then investigates the impact of three major parameters including CO2 injection pressure, temperature, and shale volume on the adsorption capacity of the shale. The experimental results showed that the factors studies had a strong influence on the CO2 storage potential. Increasing the CO2 injection pressure increased the adsorption capacity, whereas increasing the temperature reduced the adsorption greatly. The shale volume strongly impacted the accuracy of the results obtained using the volumetric method and thus is an extremely important parameter in the design of adsorption experiments if the volumetric method is to be used. The parameters studied in this research should be accounted for when designing a CO2 enhanced oil recovery operation if CO2 storage is a part of the project