Ali Saeedi - Academia.edu (original) (raw)

Papers by Ali Saeedi

Energies, Jun 26, 2018

Hydraulic fracturing technique is of vital importance to effectively develop unconventional shale... more Hydraulic fracturing technique is of vital importance to effectively develop unconventional shale resources. However, the low recovery of hydraulic fracturing fluids appears to be the main challenge from both technical and environmental perspectives in the last decade. While capillary forces account for the low recovery of hydraulic fracturing fluids, the controlling factor(s) of contact angle, thus wettability, has yet to be clearly defined. We hypothesized that the interaction of oil/brine and brine/rock interfaces governs the wettability of system, which can be interpreted using Derjaguin-Landau-Verwey-Overbeek (DLVO) and surface complexation modelling. To test our hypothesis, we measured a suit of zeta potential of oil/brines and brine/minerals, and tested the effect of ion type (NaCl, MgCl 2 and CaCl 2) and concentrations (0.1, 1, and 5 wt %). Moreover, we calculated the disjoining pressure of the oil/brine/mineral systems and compared with geochemical modelling predictions. Our results show that cation type and salinity governed oil/brine/minerals wettability. Divalent cations (Ca 2+ and Mg 2+) compressed the electrical double layer, and electrostatically linked oil and clays, thus increasing the adhesion between oil and minerals, triggering an oil-wet system. Increasing salinity also compressed the double layer, and increased the site density of oppositely charged surface species which made oil and clay link more strongly. Our results suggest that increasing salinity and divalent cations concentration likely decrease water uptake in shale oil reservoirs, thus de-risking the hydraulic fracturing induced formation damage. Combining DLVO and surface complexation modelling can delineate the interaction of oil/brine/minerals, thus wettability. Therefore, the relative contribution of capillary forces with respect to water uptake into shale reservoirs, and the possible impairment of hydrocarbon production from conventional reservoirs can be quantified.

Transport in Porous Media

This study is a continuation of our previous work, which focused on a near-wellbore water blockag... more This study is a continuation of our previous work, which focused on a near-wellbore water blockage alleviation by applying a thermally cured silane-functionalized benzoxazine to modify rock wettability. In this new analysis, we have demonstrated that the resin can be applied in low-permeability sandstones (approximately 15 mD as opposed to 100 to 200 mD in the previous study) to change the rock surface wettability from water-wet to intermediate gas-wet. We have also demonstrated that curing temperatures as low as 125 °C (as opposed to 180 °C in our previous study) can significantly change wettability, indicating surface functionalization through the silane moiety and ring-opening polymerization of the benzoxazine moiety. In drainage core flooding experiments at 2.5 wt.% resin loading, compared to untreated samples, brine recovery increments of 6.3 to 6.9% were obtained for curing temperatures of 125 to 180 °C, respectively. A maximum 20% increment in the end-point relative gas perme...

The transition of energy from fossil fuels to renewable energy particularly hydrogen is becoming ... more The transition of energy from fossil fuels to renewable energy particularly hydrogen is becoming the centre of decarbonization and roadmap to achieve net-zero carbon emission. To meet the requirement of large-scale hydrogen storage as a key part of hydrogen supply chain, underground hydrogen storage can be the ultimate solution to economically store hydrogen thus meet global energy demand. Compared to other types of subsurface storage sites such as salt caverns and aquifers which are limited to geographical locations, depleted gas reservoirs have been raising more interest because of the wider distribution and higher storage capacity. However, safely storing and cycling of hydrogen in depleted gas reservoirs requires caprock, reservoir and wellbore to remain high stability and integrity. Nevertheless, current research on storage integrity during underground hydrogen in depleted gas reservoirs is still scarce and non-systemic. We therefore reviewed the major challenges on storage int...

Iraqi Journal of Oil and Gas Research (IJOGR)

CO 2 injection has proven to be one of the most successful EOR (Enhanced Oil Recovery) methods, a... more CO 2 injection has proven to be one of the most successful EOR (Enhanced Oil Recovery) methods, as compared with other injection gases CO 2 miscibility with oil is easier to achieve. During gas injection into reservoirs, oil might be bypassed on either a micro-or macroscopic scale because of different types of heterogeneities. In this work, the performance of first-contact-miscible (FCM) and immiscible (IM) CO 2 injections were investigated experimentally using outcrop sandstone core samples. Decane was also used as the hydrocarbon phase as it has a relatively low minimum miscibility pressure (MMP) with CO 2 (12.4 MPa). Core flooding experiments were conducted at two pressures of 17.2 MPa and 9.6 MPa and the common temperature of 343 K. Furthermore, analytical calculations of dimensionless numbers are used to study the dominant forces and mechanisms which are correlated with the results of the core flooding experiments. The impacts of gravity, swelling and vaporization on the end results were inferred from the oil recoveries, variations in the pore pressure and dimensional analysis. For CO 2 injection in homogeneous core samples, a maximum recovery of 93.5% and 76% was achieved for the FCM and IM displacements, respectively. The higher recovery results of FCM is attributed to the vanishing capillary pressure between displacing and displaced phases. Dimensional analysis showed that the flow is at the capillary-gravity equilibrium at immiscible conditions, while there is dominance of gravity-viscous forces at miscible conditions.

Iraqi Journal of Oil and Gas Research (IJOGR)

Carbon dioxide (CO 2) flooding deliberated as one of the most common and feasible used gas to imp... more Carbon dioxide (CO 2) flooding deliberated as one of the most common and feasible used gas to improve oil recovery. CO 2 utilization has grown significantly due to availability, greenhouse effect and easy achievement of miscibility relative to other gases. There have been limited experimental efforts conducted at core-scale focused on evaluating the influence of permeability heterogeneity on oil recovery. Thus, the results from this manuscript are essential to highlight the importance of geological uncertainties in the current and future enhanced oil recovery projects. This manuscript presents a coupled experimental and simulation study to assess the effect of cross bedded reservoir heterogeneity on WAG flooding performance. We performed core flooding experiments with a fluid system consisting of n-C 10 , synthetic brine, and CO 2 at a temperature of 343 K and 17.2 MPa pore pressure. In addition to the experimental work, a 2D core scale CMG-GEM simulation associated with PVT module CMG WinProp has been built based on our experimental results. We found that oil recovery decreases dramatically with increasing permeability ratio of cross bedded core samples. Besides, our results revealed channeling of injected CO 2 in high permeability beds leaving a considerable amount of oil untouched in low permeability bed. Furthermore, we pronounced a water shielding effect which reduces further contact of the injected CO 2 with oil. We thus conclude that reservoir heterogeneity significantly impact WAG flooding performance and evaluation of these influences on oil recovery before any field application are essential.

Energy & Fuels, 2020

Wettability of subsurface reservoir rocks is a key parameter that influences multiphase flow char... more Wettability of subsurface reservoir rocks is a key parameter that influences multiphase flow characteristics of the fluid−rock system, including relative permeability, capillary pressure, saturation distribution, and displacement efficiency. To investigate such effects, various techniques have been implemented to change wettability, including nanoparticle injection, chemical treatment, surfactant injection, brine salinity adjustment, etc. However, most studies have focused on the use of model surfaces (e.g., mineral surfaces) and not actual rock samples, which are far more representative of real-world application. The ability to modify the wettability of the pore space in the reservoir has implications in a range of areas, such as reducing/preventing water/condensate banking around hydrocarbon production wells, CO 2 geo-sequestration, enhanced hydrocarbon recovery, and separation of CO 2 using porous media. In light of the above findings, in this research, we primarily explored supercritical fluid-based silane surface modification of quarried sandstones (i.e., Gray Berea, Upper Gray Berea, Bentheimer, and Bandera Brown). Using high-throughput treatment methods, these samples were treated with five different silanes and then characterized using X-ray photoelectron spectroscopy and contact angle measurements. Conventional techniques for depositing silanes onto a surface from organic solvent (i.e., toluene) were also conducted for comparison. In all of the cases studied, our experimental results show that, when supercritical CO 2 (scCO 2) is used as a carrier for the silanes, improved surface coverage and wettability alteration were achieved in comparison to when the conventional solvent (e.g., toluene) is used. As a result, the wettability of sandstone surfaces as measured under highpressure conditions was altered significantly from strongly water-wet (θ ≈ 11 ± 5°) to strongly non-water-wet (θ ≈ 145 ± 6°). Furthermore, we showed that scCO 2 at even relatively modest reservoir conditions (10 MPa at 60°C) could be used rather than toluene for application in real-world scenarios; this reduces environmental and safety concerns significantly.

SSRN Electronic Journal, 2019

Understanding the behaviour of CO2 in heterogeneous oil reservoir is very important for assessing... more Understanding the behaviour of CO2 in heterogeneous oil reservoir is very important for assessing both storage and enhanced oil recovery (EOR) opportunities. This paper presents the results of an experimental study into the effect of crossflow on ultimate oil recovery during miscible and immiscible CO2 flooding in heterogeneous sandstone reservoirs.

Energy & Fuels, 2020

Hydraulic fracturing has been widely implemented to enhance hydrocarbon production from shale res... more Hydraulic fracturing has been widely implemented to enhance hydrocarbon production from shale reservoirs. However, one of the main challenges during hydraulic fracturing is to understand what factor(s) triggers high salinity of flowback water, which sometimes can be up to 300,000 mg/L. While several mechanisms have been proposed to explain the controlling factor behind the high salinity of flowback water, there has been little discussion about the effect of fluid-shale interactions (e.g., mineral dissolution and surface complexation) on the high salinity, and far too attention has been paid to quantify the contribution of fluid-shale interactions. We thus conducted spontaneous imbibition experiments using deionised water and outcrops from Marcellus, Barnett and Eagle Ford shale plays with minor in-situ precipitated salts. We also monitored the pH, electrical conductivity and ion concentrations (Cl-, K+, Ca2+, NO3-, F-, Br- and NH+) of the surrounding water during spontaneous imbibition process in consecut...

Energies, 2019

Excessive water production is becoming common in many gas reservoirs. Polymers have been used as ... more Excessive water production is becoming common in many gas reservoirs. Polymers have been used as relative permeability modifiers (RPM) to selectively reduce water production with minimum effect on the hydrocarbon phase. This manuscript reports the results of an experimental study where we examined the effect of initial rock permeability on the outcome of an RPM treatment for a gas/water system. The results show that in high-permeability rocks, the treatment may have no significant effect on either the water and gas relative permeabilities. In a moderate-permeability case, the treatment was found to reduce water relative permeability significantly but improve gas relative permeability, while in low-permeability rocks, it resulted in greater reduction in gas relative permeability than that of water. This research reveals that, in an RPM treatment, more important than thickness of the adsorbed polymer layer ( e ) is the ratio of this thickness on rock pore radius ( e r ).

Energy & Fuels, 2019

Multiphase fluid flow characteristics of a reservoir rock, such as capillary pressure, displaceme... more Multiphase fluid flow characteristics of a reservoir rock, such as capillary pressure, displacement efficiency, relative permeability, and saturation distribution are substantially influenced by the wettability state of the rock. Being able to change the affinity of the rock toward different fluid phases present in the formation has implications in various petroleum applications (e.g., CO 2 geo-sequestration, EOR, gas production). In this study, silylation of sandstone core samples using nonfluorinated compounds is accomplished using supercritical CO 2 as a solvent and carrier. This approach is cost-effective and less environmentally sensitive compared to other approaches which use fluorinated silylation reagents. By using small molecules to only change the wettability characteristics of core samples without altering other parameters (e.g., rock pore structure) noticeably, the effects of wettability alteration alone on multiphase flow (i.e., relative permeability) can be identified. Spontaneous imbibition tests were conducted on Gray Berea sandstone before and after silylation treatment, which showed a diminished rate of water uptake in the post-treatment sample. The wettability alteration caused by this functionalization and its impact on multiphase flow characteristics were analyzed using core flooding tests. The experimental results show that supercritical CO 2-based (scCO 2-based) silylation changes the wettability of the formation from strongly water-wet to intermediate gas-wet. Core flooding tests showed that the effective permeability for the water phase was significantly increased, resulting in higher water removal from the rock matrix. Furthermore, the relative permeability for the gas phase (in this study, CO 2) at residual water saturation is higher after treatment. Such an outcome confirms that the change in wettability could be beneficial in geological CO 2 storage as well as gas production.

Energies, 2019

While the effect of polar-oil component on oil-brine-carbonate system wettability has been extens... more While the effect of polar-oil component on oil-brine-carbonate system wettability has been extensively investigated, there has been little quantitative analysis of the effect of non-polar components on system wettability, in particular as a function of pH. In this context, we measured the contact angle of non-polar oil on calcite surface in the presence of 10,000 ppm NaCl at pH values of 6.5, 9.5 and 11. We also measured the adhesion of non-polar oil group (–CH3) and calcite using atomic force microscopy (AFM) under the same conditions of contact angle measurements. Furthermore, to gain a deeper understanding, we performed zeta potential measurements of the non-polar oil-brine and brine-calcite interfaces, and calculated the total disjoining pressure. Our results show that the contact angle decreases from 125° to 78° with an increase in pH from 6.5 to 11. AFM measurements show that the adhesion force decreases with increasing pH. Zeta potential results indicate that an increase in p...

Enhanced Oil Recovery Processes - New Technologies, 2019

Direct gas thickening technique has been developed to control the gas mobility in the miscible ga... more Direct gas thickening technique has been developed to control the gas mobility in the miscible gas injection process for enhanced oil recovery. This technique involves increasing the viscosity of the injected gas by adding chemicals that exhibit good solubility in common gasses, such as CO 2 or hydrocarbon (HC) solvents. This chapter presents a review of the latest attempts to thicken CO 2 and/or hydrocarbon gases using various chemical additives, which can be broadly categorised into polymeric, conventional oligomers, and small-molecule self-interacting compounds. In an ideal situation, chemical compounds must be soluble in the dense CO 2 or hydrocarbon solvents and insoluble in both crude oil and brine at reservoir conditions. However, it has been recognised that the use of additives with extraordinary molecular weights for the above purpose would be quite challenging since most of the supercritical fluids are very stable with reduced properties as solvents due to the very low dielectric constant, lack of dipole momentum, and low density. Therefore, one way to attain adequate solubility is to elevate the system pressure and temperature because such conditions give rise to the intermolecular forces between segments or introduce functional groups that undergo self-interacting or intermolecular interactions in the oligomer molecular chains to form a viscosity-enhancing supramolecular network structure in the solution. According to this review, some of the polymers tested to date, such as polydimethylsiloxane, polyfluoroacrylate styrene, and poly(1,1-dihydroperfluorooctyl acrylate), may induce a significant increase of the solvent viscosity at high concentrations. However, the cost and environmental constraints of these materials have made the field application of these thickeners unfeasible. Until now, thickeners composed of small molecules have shown little success to thicken CO 2 , because CO 2 is a weak solvent due to its ionic and polar characteristics. However, these thickeners have resulted in promising outcomes when used in light alkane solvents.

Energies, 2018

Energy & Fuels, 2018

Supercritical carbon dioxide (scCO 2) is considered to be an excellent candidate for miscible gas... more Supercritical carbon dioxide (scCO 2) is considered to be an excellent candidate for miscible gas 13 injection (MGI) as it can reduce oil viscosity, induce in situ swelling of the oil and reduce the 14 IFT of the in situ fluid system. However, the unfavourable mobility associated with scCO 2 15 flooding poses a major challenge due to the large viscosity contrast between the crude oil and 16

Scientific Reports, 2018

Injecting CO2 into oil reservoirs appears to be cost-effective and environmentally friendly due t... more Injecting CO2 into oil reservoirs appears to be cost-effective and environmentally friendly due to decreasing the use of chemicals and cutting back on the greenhouse gas emission released. However, there is a pressing need for new algorithms to characterize oil/brine/rock system wettability, thus better predict and manage CO2 geological storage and enhanced oil recovery in oil reservoirs. We coupled surface complexation/CO2 and calcite dissolution model, and accurately predicted measured oil-on-calcite contact angles in NaCl and CaCl2 solutions with and without CO2. Contact angles decreased in carbonated water indicating increased hydrophilicity under carbonation. Lowered salinity increased hydrophilicity as did Ca2+. Hydrophilicity correlates with independently calculated oil-calcite electrostatic bridging. The link between the two may be used to better implement CO2 EOR in fields.

Industrial & Engineering Chemistry Research, 2018

Direct gas thickening is a conventional mobility control method to improve volumetric sweep effic... more Direct gas thickening is a conventional mobility control method to improve volumetric sweep efficiency for miscible gas injection (MGI) projects. However, the viability of this approach with technically feasible thickeners has not been verified at the field-scale due to a combination of high costs and/or environmental issues. One approach to make this technique economically more attractive is the implementation of an alternating injection scheme (similar to water-alternatinggas (WAG)) that would require less of the thickened gas compared with a continuous injection scheme. In this study, the effectiveness of this approach where a miscible alternating injection of thickened associated gas (TAG) or thickened CO2 (TCO2) with unthickened AG is explored in both non-fractured and fractured composite carbonate cores. Twelve core-flooding experiments were conducted using different injection schemes (i.e. continuous unthickened, continuous thickened and alternating thickened-unthickened). These tests demonstrate that Overall, the experimental results indicate that the alternating injection of TAG or TCO2 with unthickened AG mixture as an enhanced recovery technique may produce results similar to continuous thickened gas injection. This reduces the consumption of thickening agents noticeably resulting in reduced operational costs and improved economic viability for this method.

International Journal of Greenhouse Gas Control, 2016

Petroleum, 2016

Nanotechnology has attracted a great attention in enhancing oil recovery (EOR) due to the costeff... more Nanotechnology has attracted a great attention in enhancing oil recovery (EOR) due to the costeffective and environmental friendly manner. The size of nanoparticles for EOR usually is in a range of 1e100 nm, which may slightly differ from various international organisations. Nanoparticles exhibit significantly different properties compared to the same fine or bulk molecules because of much higher concentration of atoms at their surface as a result of ultra-small size. In particular, one of the most useful and fascinating properties of these particles is to creating a massive diffusion driving force due to the large surface area, especially at high temperatures. Previous studies have shown that nanoparticles can enhance oil recovery by shifting reservoir wettability towards more water-wet and reducing interfacial tension, yet this area is still open for discussion. It is worth noting that the potential of nanoparticles to reduce the oil viscosity, increase the mobility ratio, and to alter the reservoir permeability has not been investigated to date. Depending on the operational conditions of the EOR process, some nanoparticles perform more effectively than others, thus leading to different levels of enhanced recovery. In this study, we aim to provide a summary on each of the popular and available nanoparticles in the market and list their optimum operational conditions. We classified nanoparticles into the three categories of metal oxide, organic and inorganic particles in this article.

Petroleum, 2016

The mechanism(s) of Low salinity water flooding (LSWF) has been extensively investigated for 15 e... more The mechanism(s) of Low salinity water flooding (LSWF) has been extensively investigated for 15 e20 years, as a cost-effective and environmentally friendly technique for improved oil recovery. However, there is still no consensus on the dominant mechanism(s) behind low salinity effect due to the complexity of interactions in the Crude oil/Brine/Rock (COBR) system. While wettability is most agreed mechanism of low salinity EOR effect. Nevertheless, the mechanism(s) behind the wettability change is debated between multi-component ion exchange (MIE) and double layer expansion (DLE) in sandstone reservoirs. This paper aims to investigate the effectiveness of MIE with a coupled geochemical-reservoir model using published experimental data reported by Nasralla and Nasr-El-Din [1]. We created core-scale numerical models with parameters identical to those used in the experiments. We simulated the low salinity effect using a commercial reservoir simulator, CMG-GEM, by coupling three chemical reactions: (1) aqueous reaction, (2) multi-component ion exchange, and (3) mineral dissolution and precipitation. We modelled the adsorption of divalent cations on the surface of the clay minerals during low salinity water injection. Simulation results were compared with the experimental results. Simulation results show that the fractional adsorption of divalent cations (Ca 2þ) increased almost 25% by injecting a 2000 ppm NaCl solution, compared to initial 10,000 ppm NaCl. Injecting a 2000 ppm of CaCl 2 solution, however, significantly increased the adsorbed Ca 2þ from 0.1 to 1, which implies the complete saturation of mineral surface with divalent cations. Moreover, injecting 50,000 ppm of CaCl 2 solution also demonstrated the same effect as the 2000 ppm CaCl 2 solution but with a faster rate. Upon combining the simulation and experimental results, we concluded that the multicomponent ion exchange is not the sole mechanism behind low salinity effect for two reasons. First, almost 10% additional oil recovery was observed from the experiments by injecting the 2000 ppm CaCl 2 compared with 50,000 ppm CaCl 2 solutions. Even though in both cases the surface is expected to be fully saturated with Ca 2þ according to the geochemical modelling. Second, 6% incremental oil recovery was achieved from the experiments by injecting 2000 ppm NaCl solution compared with that of 50,000 ppm NaCl. Although 25% incremental adsorption of divalent cations (Ca 2þ) were presented during the flooding of the 2000 ppm NaCl solution. Therefore, it is worth noting that the electrical double layer expansion due to the ion exchange needs to be taken into account to pinpoint the mechanism(s) of low-salinity water effect.

Journal of Petroleum Science and Engineering, 2016

Previous research has demonstrated Hydrolysed Poly-Acrylamide (HPAM) exhibits poor thickening abi... more Previous research has demonstrated Hydrolysed Poly-Acrylamide (HPAM) exhibits poor thickening ability even under mild reservoir condition; furthermore, it would detrimentally affect the foamability of the foaming system. This work presents the finding of an investigation using a novel polymer named AVS which is a ter-polymer of AM, AMPS and one functional monomer and which can stabilize CO2 foam under relatively high salinity and temperature without greatly compromising foamability. Core flooding experiments indicate the optimal injection method for AVS enhanced CO2 foam flooding is direct injection of foam and the suitable gas/liquid ratio is determined to be around 3:1. Under these experimental conditions, tertiary oil recovery differences between foam flooding enhanced by AVS and that enhanced by HPAM are 3.7% and 6.6% for low and high permeability respectively, suggesting AVS possesses great EOR potential in the CO2 foam flooding process.

Energies, Jun 26, 2018

Transport in Porous Media

Iraqi Journal of Oil and Gas Research (IJOGR)

Energy & Fuels, 2020

SSRN Electronic Journal, 2019

Energy & Fuels, 2020

Energies, 2019

Energy & Fuels, 2019

Energies, 2019

Enhanced Oil Recovery Processes - New Technologies, 2019

Energies, 2018

Energy & Fuels, 2018

Scientific Reports, 2018

Industrial & Engineering Chemistry Research, 2018

International Journal of Greenhouse Gas Control, 2016

Petroleum, 2016

Journal of Petroleum Science and Engineering, 2016