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Fakher, Sherif (Missouri University of Science and Technology) | El-Tonbary, Ahmed (American University) | Abdelaal, Hesham (University of Lisbon) | Elgahawy, Youssef (University of Calgary) | Imqam, Abdulmohsin (Missouri University of Science and Technology)
Carbon dioxide (CO2) is the main greenhouse gas contributing to environmental damage and global warming. It is emitted as a result of many processes, part of which is combustion of oil and gas. One of the methods by which CO2 emissions can be controlled or reduced is through CO2 sequestration processes. This research investigates the ability to store CO2 in shale reservoirs through adsorption and some of the factors impacting the adsorption capacity. CO2 adsorption was measured using the volumetric adsorption method using pulverized shale particles of uniform size. Initially, the void space in the shale-bearing cell was measured using helium. The void space is used in the CO2 adsorption calculations in order to account for the extra volume created when the shale core was pulverized. The effect of varying the CO2 pressure, temperature, and shale volume on the CO2 adsorption capacity was studied. Results showed that both pressure and temperature had a strong effect of CO2 adsorption, with an increase in pressure resulting in an increase in adsorption and an increase in temperature resulting in a decrease in adsorption. Altering the volume of the shale resulted in a change in adsorption as well due to an increase in error as the shale volume decreased relative to the vessel volume. This research provides insight on the impact of multiple factors on CO2 adsorption to shale particles thus illustrating the potential for CO2 storage in unconventional shale reservoirs.
Fakher, Sherif (Missouri University of Science and Technology) | El-Tonbary, Ahmed (American University in Cairo) | Abdelaal, Hesham (University of Lisbon) | Elgahawy, Youssef (University of Calgary) | Imqam, Abdulmohsin (Missouri University of Science and Technology)
Unconventional shale reservoirs have become and large unconventional supplier of oil and gas especially in North America. They are usually produced from using hydraulic fracturing which produces and average of 7-10% per well. This research studies the application of carbon dioxide (CO2) enhanced oil recovery (EOR) in shale reservoirs to increase oil recovery to more than 20%. Cyclic CO2 injection was used to conduct all experiments rather than flooding. The main difference between both procedures and the advantage of cyclic injection over flooding in shale reservoirs is explained. A specially designed vessel was constructed and used to mimic the cyclic CO2 injection procedure. The effect of CO2 soaking pressure, CO2 soaking time, and number of soaking cycles on oil recovery was investigated. Results showed that cyclic CO2 injection can increase oil recovery substantially, however there are some points that must be taken into consideration including optimum soaking pressure and time in order to avoid a waste of time and capital with no significant increase in oil recovery. This research not only provides an experimentally backed conclusion on the ability of cyclic CO2 injection to increase oil recovery from shale reservoirs, it also points to some major issue that should be considered when applying this EOR method in unconventional shale in order to optimize the overall procedure.
Drilling-fluid design for shale plays aims to deal with the lack of wellbore stability associated with fluid-invasion, shale-swelling, and cuttings-dispersion phenomena. Although oil-based mud can be used to achieve these goals, environmental and economic concerns limit its application. This research evaluates the potential of using silica (SiO2) nanoparticles (NPs) (SiO2-NPs) and graphene nanoplatelets (GNPs) as drilling-fluid additives in a single formulation to improve shale inhibition and long-term stability of water-based mud (WBM) against temperature effects. The design of the nanoparticle WBM (NP-WBM) followed a customized approach that selects the additives according to the characteristics of the reservoir. Characterization of Woodford shale was completed with X-ray diffraction (XRD), cation-exchange capacity (CEC), and scanning electron microscopy (SEM). The aqueous-stability test and zeta-potential measurements were used to assess the stability of the NPs. NP-WBM characterization included the analysis of the rheological properties measured with a rotational viscometer and the evaluation of the filtration trends at low-pressure/low-temperature (LP/LT) and high-pressure/high-temperature (HP/HT) conditions. In addition, dynamic aging was performed at temperatures up to 250°F for thermal-stability evaluation. Finally, chemical-interaction tests, such as cutting dispersion and bulk swelling, helped to analyze the effect of introducing NPs on the inhibition capabilities of the WBM. Conventional potassium chloride (KCl)/partially hydrolyzed polyacrylamide (PHPA) fluid was used for comparison purposes. The results of this investigation revealed that SiO2-NPs and GNPs acted synergistically with other additives to improve the filtration characteristics of the WBM, with only minor effects on the rheological properties. NPs exhibited high colloidal stability with zeta-potential values less than –30 mV, which warrants their dispersion within the WBM at an optimal concentration of 0.75 wt%. The high thermal conductivity of NPs played a key role in promoting a nearly flat trend in the cumulative filtrate for the NP-WBM at aged conditions, whereas KCl/PHPA suffered a dramatic increase. Also, NP-WBM preserved 43.97% of its initial cuttings-carrying capacity, whereas KCl/PHPA experienced a severe reduction of 95.24% at extreme conditions (250°F). Despite the high illite content of the Woodford shale, the NP-WBM exhibited superior inhibition properties that reduced cuttings erosion and swelling effect by 24.48 and 35.24%, respectively, compared with the KCl/PHPA fluid. Overall, this investigation supports the potential use of nanomaterials to enhance the inhibition capabilities and the long-term stability of WBM for unconventional shales, presenting an environmentally friendly alternative for harsher environments.
Almahfood, Mustafa Mohammed (Saudi Aramco – Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology)
The aim of this study is to examine the effect of a novel combination that consists of polymeric nanogel and surfactant on oil recovery. The paper will report the extent to what the nanogel, alone and combined with surfactant, can improve oil recovery for sandstone reservoirs and reveal the mechanisms behind it. A negatively charged nanogel was synthesized using a typical free radical suspension polymerization process by employing 2-acrylamido-2-methyl propane sulfonic acid monomer. In addition, a fixed concentration of negatively charged surfactant (sodium dodecyl sulfate or SDS) was combined with different concentrations of the nanogel using seawater. The combination effect on sandstone core plugs was examined by running a series of core flooding experiments using multiple flow schemes. The synthesized nanogels showed a narrow size distribution with one peak pointing to a predominant homogeneous droplet size. They were also able to adsorb at the oil-water interfaces to reduce interfacial tension and stabilize oil-in-water emulsions, which ultimately improved the recovered oil from hydrocarbon reservoirs. The results suggest the ability of the nanogel, both alone and combined with SDS, to improve the oil recovery by a factor of 15% after initial seawater flooding. Although nanoparticles have received a great attention in the research aspect of the oil industry, however, the characterization of polymeric nanogels, alone and combined with other additives, is still to be investigated. Due to their unique properties and mechanisms, nanogels have a great potential for application in the oil industry. This study is aimed to examine and evaluate the combination of charged polymeric nanogel and surfactant dispersed in seawater through core flooding experiments using multiple injection schemes.
Sun, Lin (Southwest Petroleum University) | Li, Daibo (Southwest Petroleum University) | Pu, Wanfen (Southwest Petroleum University) | Li, Liang (Northwest Oilfield Company) | Bai, Baojun (Missouri University of Science and Technology) | Han, Qi (Southwest Petroleum University) | Zhang, Yongchang (Southwest Petroleum University) | Tang, Ximing (Southwest Petroleum University)
Summary Preformed-particle-gel (PPG) treatments have been successfully used in injection wells to reduce excessive water production from high-temperature, high-salinity fractured reservoirs. However, PPG itself cannot be used in fractured producers because it tends to wash out after the wells resume production. Therefore, we proposed to combine curable resin-coated particles (CRPs) with PPG to control water production from fractured producers. In this paper, millimeter-sized tubes and fractured carbonate cores were designed to comprehensively investigate water-plugging behaviors of the combined system under the conditions of various fracture parameters and PPG/CRP sizes. Particular attention was given to control the PPG washout after production was resumed. The results showed the cured CRPs could generate immobile packs in fractures and dramatically mitigate the PPG washout. The small size of the CRPs and the small ratio of CRP size to tube diameter contributed low permeability and homogeneity to CRP packs. Meanwhile, the less-permeable and more-homogeneous CRP pack, as well as the larger-sized PPGs, contributed to a higher PPG breakthrough pressure gradient. Moreover, some of the PPG particles blocked in the CRP packs could be released through high-speed brine injection from producers, which indicated the recoverability of the water plugging. This study provides a promising approach to reduce the highwater-cut problem in fractured producers. Introduction Gel treatment is one of the most cost-effective methods to reduce excessive water production worldwide (Sydansk and Southwell 2000; Seright et al. 2003; Seright 2003a; Goudarzi et al. 2015; Saghafi 2018). The most popular gel systems include in-situ-crosslinked polymer gels, PPGs, and microgels. The original diameters of microgels range from nanometer to micrometer scale, thus they can provide an in-depth conformance control, but cannot be applied in reservoirs with fractures (Abdulbaki et al. 2014; Zhu et al. 2017; Zhao et al. 2019).
Al-Saedi, Hasan N. (Missouri University of Science and Technology/Missan Oil Company) | Flori, Ralph E. (Missouri University of Science and Technology) | Al-Jaberi, Soura K. (Missan Oil Company) | Al-Bazzaz, Waleed (Kuwait Institute for Scientific Research)
Summary Generally, injecting carbon dioxide (CO 2) into oil reservoirs is an effective enhanced oil recovery (EOR) technique that improves oil recovery, but injecting CO 2 alone can be compromised by problems, such as early breakthrough, viscous fingering, and gravity override. The base CO 2 injection method was improved by water-alternating-gas (WAG) injection with formation water (FW) and with low-salinity (LS) water (LSW), with LSW WAG achieving greater recovery than WAG with FW. This study investigates various combinations of standard waterflooding (with FW); flooding with nonmiscible gaseous CO 2; WAG with CO 2 and FW and/or LSW; foam flooding by adding a surfactant with CO 2; adding an alkaline treatment step; and finally adding an LSW spacer between the alkaline step and the foam. These various EOR combinations were tested on Bartlesville sandstone cores (/ of approximately12%, K of approximately 20 md) saturated with a heavy oil diluted slightly with 10% heptane for workability. The ultimate outcome from this work is a "recipe" of EOR methods in combination that uses alkaline, LSW, surfactant, and CO 2 steps to achieve recovery of more than 63% of the oil originally in place (OOIP) in coreflooding tests. Combining CO 2 injection with surfactant [sodium dodecyl sulfonate (SDS)] to produce a foam resulted in better recovery than the WAG methods. Adding alkaline as a leading step appeared to precipitate the surfactant and lower recovery somewhat. Adding an LSW spacer between the alkaline treatment and the foam resulted in a dramatic increase in recovery. The various cases of alkaline þ LSW spacer þ surfactant þ CO 2 (each with various concentrations of alkaline and surfactant) achieved an average improvement of 7.71% of OOIP over the identical case(s) without the LSW spacer. The synergistic effect of the LSW spacer was remarkable. Introduction Improving oil recovery, especially for heavy oil, is a central goal of petroleum engineers. For heavy oils, thermal methods are the most widely used methods because they reduce oil viscosity and enable better flow. However, thermal EOR techniques are not always suitable because of their higher cost compared with chemical EOR processes (Alvarado and Manrique 2010). They also require a thick pay zone. Thermal EOR techniques, such as steamflooding, encounter drawbacks such as heat loss (Al-Saedi et al. 2019a). Because of these disadvantages, can chemical EOR techniques be used to extract the enormous quantities of heavy oils that are in North America, South America, the Middle East, and China? LSW flooding is an emerging low-cost EOR technique for both sandstone and carbonate hydrocarbon reservoirs (Alhammadi et al. 2017; Al-Saedi et al. 2019c; Chequer et al. 2019). Recently, the potential of LSW has drawn the attention of academic researchers and the oil industry.
Abbas, Ahmed K. (Iraqi Drilling Company, Missouri University of Science and Technology) | Alhameedi, Hayder A. (University of Al-Qadisiyah, Missouri University of Science and Technology) | Alsaba, Mortadha (Australian College of Kuwait) | Al Dushaishi, Mohammed F. (Oklahoma State University) | Flori, Ralph (Missouri University of Science and Technology)
Coiled tubing (CT) technology has been widely used in oilfield operations, including workover applications. This technology has achieved considerable economic benefits; however, it also raises new challenges. One of the main challenges that were encountered while using this technology is the buckling of the CT string. It can occur when the axial compressive load acting on the CT string exceeds the critical buckling loads, especially in highly deviated/horizontal and extended reach wells. Moreover, this issue becomes more critical when using non-Newtonian fluids. Therefore, the major focus of this study is to identify the frictional pressure loss of non-Newtonian fluids in an annulus with a buckled inner tubing string.
In the present study, a laboratory-scale flow loop was used to investigate the influence of various buckling configurations (i.e., sinusoidal, transitional, and helically) of the inner pipe on the annular frictional pressure losses while circulating non-Newtonian drilling fluids. The experiments were conducted on a horizontal well setup with a non-rotating buckled inner pipe string, considering the impact of steady-state isothermal of laminar, transition, and turbulent flow regions on frictional pressure losses. Six different Herschel-Bulkley fluids were utilized to examine the dependence of pressure losses on fluid rheological properties (i.e., yield stress, consistency index, and flow behavior index).
Experiments showed potential to significantly decrease the frictional pressure losses as the axial compressive load acting on the inner pipe increases. The effect of buckling was more pronounced when fluids with higher yield stress and higher shear-thinning ability were used. In addition, by comparing the non-compressed and the compressed inner pipe, an additional reduction in frictional pressure losses occurred as the axial compressive load increased. However, the effect of the compressed inner pipe was insignificant for fluids with a low yield stress, consistency index, and high-flow-behavior index, especially in the laminar region. The information obtained from this study will contribute toward providing a more comprehensive and meaningful interpretation of fluid flow in the vicinity of a buckled coiled tubing string. In the same manner, accurate knowledge of the predicted friction pressure will improve safety and enhance the optimization of coiled tubing operations.
Sun, Xindi (Slippery Rock University of Pennsylvania and Missouri University of Science and Technology) | Long, Yifu (Missouri University of Science and Technology) | Bai, Baojun (Missouri University of Science and Technology) | Wei, Mingzhen (Missouri University of Science and Technology) | Suresh, Sujay (Missouri University of Science and Technology)
Traditional polyacrylamide (PAM)-based superabsorbent polymer has been applied to control excess carbon dioxide (CO2) production in CO2-flooding fields. Nevertheless, the application results are mixed because the polyacrylamide-based superabsorbent polymer dehydrates significantly when exposed to supercritical CO2; therefore, we evaluated a novel CO2-resistant gel (CRG) with reliable stability and CO2-responsive properties. Particularly, the CRG swelling ratio (SR) and gel-volume increase after CO2 stimulation if additional water is available. Swollen CRG was placed in high-pressure vessels to examine the weight loss and the property changes before and after exposure to CO2. The breakthrough pressure and CRG-plugging efficiency to CO2 were measured using partially open fractured-sandstone cores. Two water/alternating/gas (WAG) cycles were conducted to test the CRG-plugging performance after CRG injection. The high-pressure vessel-test results show that the CRG is very stable under the supercritical-CO2 condition and no free water is released from the samples. The scanning-electron-microscope (SEM) images confirm that no structural damage was observed in CRG after exposure to CO2. The breakthrough pressure increases with the matrix permeability, which is mainly induced by the internal and external gel cake formed on the rock surface. CRG can reduce the water permeability more than CO2 permeability. CRG-plugging efficiency to CO2 decreases with the increase of WAG cycles. However, in the 0.5-mm fracture model and the 390-md model, CRG-plugging efficiency to water increases with WAG cycles. This phenomenon further indicates that CRG can be stimulated by CO2, which allows CRG to absorb additional water during post-waterflooding. In general, this study reports the concept of the novel CRG and a systematical evaluation of CRG stability under supercritical-CO2 conditions and CRG-plugging efficiency using a partially open fractured-sandstone model.
In a previous work (Al-Saedi et al. 2018c), we studied the effect of mineral composition of cores (using synthetic columns with varying mineralogy) on low-salinity (LS) waterflooding, and we presented a reactive-transport model (RTM) for the water/rock interactions. The results showed that kaolinite has the strongest effect and then quartz because of the high kaolinite surface area, and the most effective complexes were >SiOH (hydroxylated Si), >AlO– (aluminum oxide complex on quartz surface), and >SiO– (silicon mono oxide complex on quartz surface).
In this paper, we use the same Bartlesville Sandstone cores (constant mineralogy) for all cases to investigate the effect of water chemistry on water/rock interactions during seawater and smart waterflooding of reservoir sandstone cores containing heavy oil. Oil recovery, surface-reactivity tests, and multicomponent reactive-transport simulation using CrunchFlow (Steefel 2009) were conducted to better understand smart waterflooding.
Bartlesville Sandstone cores were saturated with heavy oil and connate formation water. Secondary waterflooding of these cores with formation water (FW) at 25°C resulted in an ultimate oil recovery of approximately 50% original oil in place (OOIP) for all reservoir cores in this study. FW salinity was 104,550 ppm. FW was diluted twice to obtain Smart Water 1 (SMW1). SMW2 was similar to SMW1 but depleted in divalent cations (Ca2+ and Mg2+). SMW3 was also similar to SMW1 but depleted in Mg2þ and SO2–4 , whereas SMW4 was the same as SMW1 but Ca2+ was diluted 100 times. Seawater (SW) salinity was 48,300 ppm, which is close to the SMW salinity (52,275 ppm). No oil recovery was observed during SMW1 flooding, whereas softening SMW1 (SMW2) resulted in a significant additional oil recovery of OOIP. Depleting Mg2+ and SO2–4 resulted in additional oil recovery but less than in SMW2. Diluting Ca2+ 100 times was the second-best scenario, after depleted Ca2+ in SMW2. The results of this study showed that the more diluted Ca2+ is in the injected brine, the more additional oil recovery that can be obtained, although the other divalent/monovalent cations/anions were increased or decreased or even depleted.
Additional reservoir cores were allocated for surface-reactivity tests. The absence of an oil phase allows us to isolate the important water/rock reactions. The Ca2+, Mg2+, and SO2–4 effluents for all cores were matched using CrunchFlow, and then further investigations of the water/rock interactions were conducted. The RTM showed that decreasing the Mg2þ concentration will decrease the number of the most effective kaolinite edges Si-O– and Al-O–, but was not as pronounced as that in the presence of Ca2+, which explains why lowering the Mg2+ concentration gives lower additional oil recovery and why lowering the Ca2þ concentration gives higher additional oil recovery.
Al-Hameedi, Abo Taleb T. (Missouri University of Science and Technology) | Alkinani, Husam H. (Missouri University of Science and Technology) | Dunn-Norman, Shari (Missouri University of Science and Technology) | Trevino, Hector A. (Missouri University of Science and Technology) | Al-Alwani, Mustafa A. (Missouri University of Science and Technology)
The purpose of this paper is to create a starting point for research into using friendly and biodegradable waste material as supportive items for hydraulic fracturing fluids and additives. Conventional fluids and additives, although they can be effective, they pose serious threats to work personnel and public health and to the environment. Conventional fluids and additives can also be very costly. These risks and concerns should drive the oil and gas industry to pursue alternative options, safer and cheaper options, from conventional fracturing fluids and additives. Some waste materials provide this opportunity. It is apparent through many forms of research that waste materials are readily available globally making it easy and cheap to obtain. A driving force for this research was research previously done on finding alternative additives for drilling fluids. Researchers have proven that some of the waste materials, such as food waste, grass waste, palm tree waste, among many others, can and should replace or at least boost conventional drilling fluids and additives through a series of experiments and tests. Not only are these materials easier and cheaper to obtain, but they are also efficient and safer for both the environment and people. The same could be said for alternative hydraulic fracturing fluids and additives if proper research is done. The strides made in finding alternatives for drilling fluid additives have pushed the revolutionizing of the oil and gas industry, acting as a catalyst for the research into alternative hydraulic fracturing fluids and additives. In this work, a more thorough investigation into conventional fracturing fluids and their downfalls regarding price and health and environmental concerns are illustrated as well as the function of the main fracturing fluids; water fracs, linear gels, crosslinked gels, oil-based fluids, and foam/poly-emulsions. Throughout this paper, it becomes apparent that the oil and gas industry should attempt replacing or decreasing conventional fracturing fluids additives because of the negative influences they have on profit, people's health and safety, and the environment.