Person | TU Delft Repository

A.A.A. Hussain

View Pure Profile

Authored

12 records found

Impact of Crude Oil on Pre-Generated Foam in Porous Media

Journal article - A.A.A. Hussain, S.Y.F. Vincent-Bonnieu, S.Y.F. Vincent-Bonnieu, R. Z. Kamarul Bahrim, R. M. Pilus, W.R. Rossen

As foam is injected into an oil reservoir, the region near an injector can become oil-free due to the relatively high capillary number. Foam created in this region encounters oil further out in the reservoir. The impact of oil on foam in porous media is usually investigated by co-injecting surfactant, gas and oil, or by injecting pre-generated foam into an oil-saturated core. However, the former experiment does not give information on the impact of oil on pre-generated foam, and with the latter experiment one cannot easily obtain data at different oil fractional flows, necessary to model the impact of oil on pre-generated foam. Here we present a novel but relatively simple experimental technique for investigating the effect of oil on pre-generated foam in porous media. This allows one to compare the effects of oil on pre-generated foam and on foam generation without the experimental complications involved in using two separate porous media. We co-inject surfactant solution and gas into a relative narrow core (1 cm diameter), and inject oil into the core some distance downstream from the inlet through ports in the side of the core. The relatively narrow core allows rapid contact between the injected crude oil and pre-generated foam in a porous medium much larger than pore dimensions. By injecting the three phases into the core we investigate the flow behaviour of foam with oil at fixed fractional flows of all three phases. We illustrate the technique with a study of the effect of one crude oil with two surfactants. With this system, there is a progressive decrease in the apparent viscosity of the foam after encountering oil. Foams with a higher gas fraction experiences a more-significant weakening by oil over the length of the core than foams with a lower gas fraction. By the end of the core, the apparent viscosities of foam with a higher gas fraction approach values observed with three-phase co-injection. We present a novel, but relatively simple method to investigate the change of foam mobility as it encounters oil in a porous medium, at controlled fractional flows. We show that in our case the apparent viscosity of foam with oil can decrease by more than a factor of four over a distance of 15 cm, indicating that foam and oil reach steady-state (as observed with three-phase co-injection) almost instantaneously compared to the length of a reservoir-simulation grid-block.@en

Studies on foam in porous media and the effect of oil

Doctoral thesis - A.A.A. Hussain

Foam flooding can be applied in soil-remediation techniques or for improving oil recovery processes in petroleum reservoirs. There are models which aim to predict the behaviour of foam in presence of oil in bulk and in porous media, however these models are not very reliable. In ...

The impacts of solubilized and dispersed crude oil on foam in a porous medium

Journal article - A.A.A. Hussain, S.Y.F. Vincent-Bonnieu, S.Y.F. Vincent-Bonnieu, R. Z. Kamarul Bahrim, Rashidah M. Pilus, W.R. Rossen

Dispersed and solubilized oil can impact bulk foam stability differently. Though aromatic components are more soluble in water than straight-chain aliphatic components, solubilized aromatics do not necessarily impact the stability of foam in bulk or porous media, whereas straight-chain aliphatic components can have a detrimental impact (Bergeron et al., 1993; Lee et al., 2013). However, to our knowledge there is no published research on the impact of a solubilized crude oil on foam, as distinct from a separate oil phase, in a porous medium. To investigate whether the behaviour of steady-state foam with crude oil can be explained by solubilized oil components, we perform foam-flooding experiments with surfactant solution previously equilibrated with crude oil. Furthermore, we conduct foam-flooding experiments with hexane solubilized in the surfactant solution, to determine whether straight-chain aliphatic components can explain the behaviour of the solubilized crude oil on steady-state foam mobility, in the same way that they impact bulk foam in the literature. The impact of crude oil, as a separate, dispersed oleic phase, is studied here by co-injection of crude oil, surfactant solution and gas in core-floods, focusing on steady-state mobility, captured by the pressure gradient within the core. In our experiments crude oil, as a separate oleic phase, reduces the pressure gradient within the core up to a factor of twenty compared to the case without oil. Nonetheless, this pressure gradient is about a factor three greater than we observe by co-injecting crude oil, water without surfactant, and gas. With a simplified model we fit our three-phase co-injection experimental data by increasing the viscosity of both the gas and water, indicating that some weak foam and emulsion is generated. Neither effect by itself can fit the data. In contrast, with crude oil or hexane solubilized in the surfactant solution, the pressure gradient is of the same order of magnitude as for co-injection gas and surfactant with or without solubilized oil. These results indicate that solubilized crude oil does not reduce foam mobility as much as does the crude oil as a separate oleic phase. Furthermore, the effect of solubilized crude on foam is not due only to straight-chain aliphatic components such as hexane: our experiment with solubilized hexane showed a less-significant impact on foam mobility. The major result of our work is that we find that both gas and oil mobility are reduced when co-injecting oil, gas and surfactant solution in a porous medium. Another result is that the solubilized crude oil slightly reduces foam mobility, but does not explain the much-larger detrimental impact of crude oil in a separate phase on foam in a porous media.@en

Impact of surfactant depletion on foam in porous media

Poster - A.A.A. Hussain, Sebastien Vincent-Bonnieu, W.R. Rossen

Foam can be applied as an Enhanced Oil Recovery (EOR) process. Foam stability in porous mediadecreases with decreasing surfactant concentration. It is also known that foam collapses belowa “limiting water saturation” in porous media. However, there isn’t a complete theory for the relationship between surfactant concentration and the water saturation below which foam coarsens ina specific porous medium. The aim of this study was to find a relationship between the surfactantconcentration, the foam bubble radius, and the limiting water saturation. This research gathersand analyses experimental data from the literature on foam properties in porous media. The foamswere stabilized with the same anionic surfactant (AOS), at different surfactant concentrations andporous media.The experimental data shows that for a specific porous medium, the limiting water saturation exponentially decreases with increasing surfactant concentration. These results can be explainedby the surfactant depletion from the solution to the gas-water interface. This work shows that thelimiting water saturation approximates the water saturation for which the gas-water interfacial-areais equal to the surface-area that could be covered by the surfactant molecules in the surfactant solution in the given porous medium. A fundamental assumption in this calculation is that gas bubblesin the porous medium correspond to pore size, as is thought to apply to foams at water saturationsabove the limiting water saturation.The general implication of these results is that from two known parameters, the third parameter canbe calculated (the three parameters are surfactant concentration, the average foam bubble sizeand limiting water saturation). A possible implication on the modelling of the foam flood in porousmedia was investigated in this research. The observed relationship was applied to a simulation ofsurfactant-alternating-gas injection in a homogenous reservoir with a uniform residual oil saturation. In this simulation the limiting water saturation was a function of the foam bubble size and thesurfactant concentration@en

Impact of Solubilized and Dispersed Crude Oil on Foam in a Porous Medium

Abstract - A.A.A. Hussain, Sebastien Vincent-Bonnieu, R. Z. Kamarul Bahrim, W.R. Rossen

Dispersed and solubilized oil can impact bulk foam stability differently. Though aromatic components are more soluble in water than straight-chain aliphatic components, solubilized aromatics do not necessarily impact bulk foam stability, whereas straight-chain aliphatic components can have a detrimental impact (Lee et al., “Stability of Aqueous Foams in the Presence of Oil: On the Importance of Dispersed vs Solubilized Oil”, Ind. Eng. Chem. Res., 52,pp. 66−72, 2013). However, to our knowledge there is no research on the impact of solubilized oil on foam in porous media. The impact of the crude oil, as a separate oleic phase, was studied by co-injection of crude oil, surfactant solution and gas in coreflood, on steady-state mobility, captured by the pressure drop across the core. To investigate if the behaviour of steady-state foam with dispersed crude oil can be explained by the solubilized oil components, we perform foam-flooding experiments with surfactant solution previously equilibrated with crude oil. Furthermore, we conduct foam-flooding experiments with solubilized hexane in surfactant solution, to determine if the straight-chain aliphatic components can explain the behaviour of the solubilized crude oil on steady-state foam mobility as it impacts bulk foam in the literature. The crude oil , as a separate oleic phase, reduces the pressure gradient across the core by a factor of twenty compared to the case without oil. Nonetheless, this pressure gradient was about a factor three higher than we observed by co-injecting crude oil, water without surfactant, and gas, which indicates that some weak foam and emulsion was generated by co-injecting surfactant, crude oil, and gas. In contrast, with solubilized crude oil and with solubilized hexane, the pressure gradient is in the same order of magnitude for co-injection gas and surfactant with and without solubilized oil. These results indicate that solubilized crude oil cannot explain the impact of the crude oil as a separate oleic phase on foam mobility in our case. Furthermore, the impact of solubilized crude oil on steady-state foam mobility cannot be explained as the effect of a solubilized straight-chain aliphatic component such as hexane. The major result of our work is that the impact of solubilized crude oil on foam does not explain the detrimental impact of crude oil in a separate oleic phase on foam in a porous media. Another result is that though co-injected water, gas and crude oil might not generate strong foam, it can result in somewhat higher pressure gradients with surfactant in the aqueous phase than without surfactant. This is possibly caused by smaller oil droplets in presence of surfactant and a weak foam.@en

Impact of Different Oil Mixtures on Foam in Porous Media and in Bulk

Journal article - A.A.A. Hussain, S.Y.F. Vincent-Bonnieu, S.Y.F. Vincent-Bonnieu, R. Z. Kamarul Bahrim, R.M. Pilus, W.R. Rossen

Foam can be applied to enhance oil recovery from a reservoir. Currently, to understand and model the behavior of foam in an oil reservoir, experiments need to be conducted in the presence of the specific crude oil, and extrapolating from one crude oil to another is not possible. It is therefore desirable to model the impact of a crude oil on foam solely based on the crude-oil composition. This would allow one to efficiently screen reservoirs for foam application. Here we investigate the behavior of foam in the presence of a crude oil and in the presence of mixtures of pure components, which we choose based on the gas chromatography analysis of the crude oil as well as its total acid number and total base number. To analyze the impact of an oil mixture on bulk foam we shake test tubes with surfactant solution and either a mixture of pure oil components or crude oil and analyze foam height and liquid height over time. We also conduct experiments in a porous medium, where we coinject mixtures of pure components, surfactant solution, and gas. We fix the oil injection rate and vary the ratio of the gas to surfactant solution. We use the following organic compounds (OC) to represent the crude oil: toluene (an aromatic), oleic acid (an organic acid), octanol (an organic base), methylcyclohexane (a cycloalkane), dimethyl sulfoxide (an organosulfur), n-octane, and hexadecane. However, when one or all of the first components is added to a 50/50 (vol %) mixture of n-octane and hexadecane, in proportions similar to their presence in the crude oil, the impact of the oil mixture on foam (both in bulk and in porous media) is only slightly different from the impact of the n-octane and hexadecane mixture. We formed a “synthetic” crude oil, with its composition mimicking the composition of a crude oil and its total acid/base number. Although the pure OC and synthetic crude oil weaken foam in bulk and in porous media, their impact on foam was less severe than the impact of the crude oil on the foam. Based on the composition of an oil mixture and the impact of its components, separately, on foam, it is not clear how to predict the impact of the oil mixture on foam in bulk or porous medium. However, in our case we find a good correlation between the foam apparent viscosity in porous media and the product of the bulk foam half-life and initial volume. One implication is that if either the half-life or initial volume of bulk foam is poor, the foam performs poorly in the porous medium.@en

Effect of Oil on Gravity Segregation in SAG Foam Flooding

Conference paper - A.A.A. Hussain, A. Amin, S.Y.F. Vincent-Bonnieu, A Andrianov, A Andrianov, P. Abdul Hamid, W.R. Rossen

We report a simulation study of surfactant-alternating-gas (SAG) foam injection into a waterflooded oil reservoir. We show the effects of oil, and of SAG cycle size and number on sweep efficiency, and the longterm impact of a single surfactant slug on the areal sweep efficiency of a gas-flood. Shan and Rossen (2004) show that a single-cycle SAG flood with fixed injection pressure can effectively overcome gravity override in a homogeneous reservoir with a uniform residual oil saturation. A single cycle works better than multiple cycles. We show that the presence of mobile oil can invalidate this model, but not simply because oil weakens or destroys foam. If foam is weakened by oil, moderately but uniformly, vertical sweep efficiency can still be good. Of course if oil kills foam nearly completely, gravity override occurs. In our simulations, foam collapses where oil saturation is above a certain threshold value greater than waterflood residual. Oil mobilized by the foam bank flows downward. This can lead to an oil bank at the bottom of the reservoir, and in single-cycle SAG this oil bank is not displaced by foam if its oil saturation is sufficient to destroy foam. Meanwhile, gas flows upward and the low-mobility front advances rapidly across the top of the reservoir, leading to an override zone. It is the non-uniformity of the resulting oil saturation and gas mobility that invalidates Shan and Rossen's model in this case. Instead there is an oil-rich zone at the bottom of the reservoir, foam above the oil-rich zone, and a foam-free override zone above the foam. In this case, if foam is injected in several relatively small slugs, oil production can be better than that with fewer relatively large slugs. We also illustrate the impact of injecting a single surfactant slug on the areal sweep efficiency of a long-term gas-flood. By injecting a surfactant slug prior to the gas slug, stronger foam can form in parts of the reservoir with a lower oil saturation. Foam then diverts gas flow to oil-rich areas in the reservoir, in our case the bottom of the reservoir. In a conventional gas flood gas flows primarily across the top of the reservoir with poor sweep efficiency. By injecting a single surfactant slug ahead of gas, higher oil recovery can be achieved at the same injected PV of gas. @en

Impact of Crude Oil on Pre-generated Foam in Porous Media

Conference paper - A.A.A. Hussain, S. Vincent-Bonnieu, R. Z. Kamarul Bahrim, Rashidah M. Pilus, W.R. Rossen

As foam is injected into an oil reservoir, the region near an injector can become oil-free due to the relatively high capillary number. Foam created in this region encounters oil further out in the reservoir. The impact of oil on foam in porous media is usually investigated by co-injecting surfactant, gas and oil, or by injecting pre-generated foam into an oil-saturated core. However, the former experiment does not give information on the impact of oil on pre-generated foam, and from the latter experiment one cannot easily obtain data at different oil fractional flows, necessary to model the impact of oil on pre-generated foam. Here the impact of crude oil on pre-generated foam is studied by co-injecting surfactant solution and gas into a relative narrow core (0.01 m diameter), and injecting oil into the porous medium some distance downstream from the inlet, through ports in the side of the porous medium. By injecting the three phases into the core we investigate the flow behaviour of foam with oil at fixed fractional flows of all three phases. The relatively narrow core allows rapid contact between the injected crude oil and pre-generated foam. We observe a progressive decrease in the apparent viscosity of the foam after encountering oil. Foams with a higher gas fraction experience a more significant weakening by oil over the length of the core than foams with a lower gas fraction. By the end of the core, the apparent viscosities of foam with a higher gas fraction approach values observed with three-phase co-injection. Foam made with surfactant pre-equilibrated with the crude oil propagated for a shorter distance in presence of oil than foam made with surfactant that hasn’t contacted oil before. We present a novel, but relatively simple method to investigate the change of foam mobility as it encounters oil in a porous medium, at controlled fractional flows of all phases. We show that in our case the apparent viscosity of foam with oil can decrease by more than a factor of four over a distance of 0.15 m, indicating that foam and oil reach steady-state (as observed with three-phase co-injection) almost instantaneously compared to the length of a reservoir-simulation grid-block.@en

Impact of surfactant depletion on foam in porous media

Abstract - A.A.A. Hussain, S.Y.F. Vincent-Bonnieu, W.R. Rossen

Development of a well impairment model for predicting geothermal clogging (DIMOPREC)

Report - A.A.A. Hussain, B.J. Meulenbroek, K.H.A.A. Wolf, N. Khoshnevis Gargar, J. Bruining, Wouter R L van der Star, Han Claringbould, Isabelle Llaneza

Development of a well impairment model for predicting geothermal clogging (DIMOPREC)

Report - A.A.A. Hussain, B.J. Meulenbroek, K.H.A.A. Wolf, N. Khoshnevis Gargar, J. Bruining, Wouter R L van der Star, Han Claringbould, Isabelle Llaneza

Modelling Mineral-Scaling in Geothermal Reservoirs Using Both a Local Equilibrium and a Kinetics Approach

Abstract - A.A.A. Hussain, N. Khoshnevis Gargar, B.J. Meulenbroek, Wouter R L van der Star, J. Bruining, Johan Claringbould, Ayla Reerink, K.H.A.A. Wolf

Contributed

3 records found

Geothermal mining

The potential for environmentally friendly extraction of valuable components from geothermal brines in the Netherlands

Student report - M.E. Biagini, A.A.A. Hussain, K.H.A.A. Wolf, D.F. Bruhn, M. Soleymani Shishvan

In a world transitioning towards renewable energies and lithium-battery powered cars, there has been an annual increase in demand of 6% for lithium and other rare metals between 2000 and 2008 (Stringfellow & Dobson, 2021a), and this increase in demand is forecast to continue through 2040 (Latnussa et al., 2020). Meanwhile, there is a concern that supply will not be able to keep up with demand. Most of the lithium in the European markets comes from other countries such as Chile and Australia, making the European lithium supply vulnerable to supply chain disruptions, as was observed during the COVID-19 pandemic (Latnussa et al., 2020). In addition, the economic value of lithium has increased more than threefold compared in 2022 compared to 2017 (Latnussa et al., 2022). The geological information of Northern-Western Europe at the latest stage, gives an explanation to the occurrence of lithium in the Netherlands. 50 water samples of 13 fields are considered for the chemical composition and origin of their brine. All geothermal brines contain dissolved lithium and other metals from the reservoir formation and surroundings, allowing for metal ‘mining’ in an environmentally friendly manner. The highest lithium concentrations in aquifer brines are in the province of Drenthe and Limburg, specifically in the Akkrum-13 gas field (47-48 ppm) and the Californie Geothermie (20-28 ppm). The correlation is positive only for lithium against rubidium and lithium against the vicinity of volcanic intrusions, from mineral mobilization through groundwater flow. There are no specific formations with high lithium concentrations. In Germany, construction has started on a project to extract lithium from geothermal process water, indicating that it is economically viable (Wedin, 2022). For the Netherlands there are 5 different surface options to extract the highest lithium concentrations. Reverse osmosis, nanofiltration, ion-exchange, sorbents and electrodialysis can be used as direct lithium extraction methodologies. One potential economical method to extract lithium from geothermal brines is by utilizing two centralized lithium extraction plants. A plant for the direct lithium extraction with ion-exchange resins, placed before injection wells, and one for the refinement of the material.

Injection of Water above Gas for Improved Sweep in Gas EOR: Non-uniform Injection and Sweep

Master thesis - Adhitomo Adhitomo Sulistyo, A.A.A. Hussain, W.R. Rossen

One proposed method to delay the onset of gravity segregation between water and gas in enhanced oil and gas projects and extend the period of effective macroscopic sweep in “SWAG” is by separating the injection wells into two parallel horizontal wells (Stone, 2004). In this “modified SWAG”, the water injection well is aligned at a distance above the gas injection well, and both water and gas are pumped simultaneously to displace the reservoir fluids. The significant density difference between the fluids and the ensuing counter-direction flow impede the segregation process. Initially Rossen et al. (2007) investigated the effectiveness of the technique based on 2D modelling and found that it increased the fluid segregation length. Van der Bol (2007) and Jamshidnezhad et al. (2010) broadened the scope of study and observed a non-uniform gas injection profile and volumetric sweep in 3D. Injection instability occurred in most of the simulation cases, despite the assumption of an ideally homogenous reservoir in the model. Mahalle (2013) identified several factors that triggers instability such as gas saturation and relative permeability behaviors in adjacent grid blocks. Since the instability was found to originate in the near-wellbore region, local grid refinement was applied along the entire length of the horizontal well, with more uniform gas-injection profile observed. Using a different reservoir simulator, Ranjan (2015) extended the previous study by checking again the effect of local grid refinement. The result, however, contradicts with the preceding finding. Grid refinement near the injection well did not improve stability in Ranjan’s study. The author also checked the effect of gas injection rate on the non-uniformity. Again, contradictory results were observed. While Ranjan reported that doubling the gas injection rate promotes non-uniform behavior, the earlier study obtained the opposite outcome. This thesis extends the previous studies by examining other parameters that may influence non-uniformity. We developed a method to quantify non-uniformity by calculating the coefficient of variation and max-min ratios for gas injection rate along the well. We looked at the effect of changes in well placement, reservoir properties, reservoir boundaries, reservoir fluids and operating constraints. We also fundamentally modified how the perturbation is applied along the gas-injection well by altering the skin factor while maintaining constant permeability. Results show that the type of perturbation significantly effects the non-uniformity of gas injection. We believe that perturbing permeability promotes the uniformity of gas-injection rate because of flow to neighboring grid blocks, and thereby more simulations are seen to be uniform compared the results with perturbation in skin factor. The results from this study suggests that non-uniformity is associated to the feedback between gas injection rate, water saturation and gas relative permeability, which is shown by the gas injection rate to vary more than proportionally to permeability or skin, even in relatively uniform cases. The effect of adjacent grid blocks also plays a crucial role, as we can see from the different results between the two types of perturbations. Finally, the mobility ratio of the fluids strongly influences the occurrence of the instability.

A case study of Pb-scaling in a geothermal project in the West Netherlands Basin

Master thesis - N. Essaf, K.H.A.A. Wolf, A.A.A. Hussain, Han Claringbould

This research was done in the framework of the RVO project on Development of a well impairment model for predicting geothermal clogging (DIMOPREC) . The importance of developing new energy sources with lower carbon emissions than conventional hydrocarbon based energy sources has been globally recognized (Andrews-Speed, 2016). Geothermal energy is a lower carbon energy source, which can be used for both electricity production and for direct heat use (Fridleifsson, 2001). However, radioactive mineral scaling can accumulate in filters and tubing of the geothermal facilities, which can be an operational hurdle as this scale needs to be removed with necessary caution. The problem is not only the riskiness of being exposed to radioactive elements, but also the rise in pressure caused by scale accumulation. This occurs at the filters resulting in more process stops. Another problem with the scaling is that it causes increasing injection pressure. Since there is a regulatory limit to this pressure, an increase in injectivity is not preferable. Here, a case of a low-enthalpy geothermal project is discussed where very limited radioactive galena, PbS, is found. This geothermal system is modelled in the geochemical software package PHREEQC. The PHREEQC model shows that a fraction (78 wt.%) of the collected galena is produced in solid phase from the reservoir, and a smaller fraction (22 wt.%) is formed after the heat exchanger. Gamma ray logs analyses and sedimentation history are presented to find potential sources of Pb and S ions. With the geological history and literature study it is found that the radioactive Pb could be originated from the Zechstein and Rotliegend where it attaches strong to the Copper shale formations. Scale and water analysis show that most of the captured galena is transported in a solid phase into the geothermal facility. In the second part we discuss the development of a SKID for scaling determination during geothermal production. It is proposed to design a new SKID with additional measurement and monitoring options, which is able to provide the requested input parameters for the PFREEQC model. Requested data acquisition for long term monitoring includes fluid pressure, flowrate, temperature and pH values. The mobile function makes it possible to sample at several surface locations along the line of the geothermal facility. The obtained and stored data can be analyzed and compared to other locations in order to find out whether or not the brine and its composition change, and if so, how it changes In order to reduce the amount of radioactive PbS in the filters of the geothermal system, it could be considered to acidify the brine to a level where the minerals are dissolved. In addition, increasing the facility pressure and/or increasing the minimum brine temperature after the heat exchanger, could reduce the amount of galena precipitation captured in the filters of the geothermal facility.