Asphaltene Precipitation Research Articles

Using special additives for decreasing the asphaltene content of missan crude oil

In crude oil, asphaltene is one of the fractions that may be dissolved in aromatics like benzene or toluene but cannot be dissolved in alkanes like n-heptane, n-pentane, or petroleum ether (a mixture of alkane compounds). A typical difficulty in oil recovery and refinery processes is asphaltene precipitation, which happens when the oil stream's pressure, composition, or temperature change. So, the stability of asphaltene in crude oil needs to be looked at to find out how likely it is to form asphaltene so that it can be stopped and high treatment costs can be reduced. In the present study, saturate, aromatic, resin and asphaltene (SARA) analysis of Missan heavy crude oil from the (Omar River Field) was performed. Three additives were used to show their effect on asphaltene at different concentrations and temperatures. The additives included nanoparticles (nano ferric oxide red, nano silica oxide, and a mixture of nano silica and ferric oxide red) and the polymer fiberglass. The concentrations of the additives of the nanoparticles were (200 ppm, 3533 ppm, a867 ppm), (1667 ppm, 6667 ppm, 10000 ppm, and 16667 ppm) and (24000 ppm, 40000 ppm, and 48000 ppm) of nano-silica, ferric oxide red, and a mixture of nano silica and ferric oxide red, respectively, while fofiberglassss, 3733 ppm, 7066 ppm, 10400 ppm, and 13733 ppm) and measured at temperatures (5, 25, and 45oC) The best read I got was when it was used. 4.249% from origin to 6.375% after treating the percentage of asphaltene with 48000 ppm of ferric oxide red and nanoo-silica.

Effect of asphaltenes precipitation and Deposition by gas injection on physical Properties and oil recovery factor

Effect of asphaltenes precipitation and Deposition by gas injection on physical Properties and oil recovery factor

Modeling the phase envelope of asphaltene precipitation due to CO2 injection into oil reservoirs using the CPA equation of state

Modeling the phase envelope of asphaltene precipitation due to CO2 injection into oil reservoirs using the CPA equation of state

Asphaltene Precipitation Prediction during Bitumen Recovery: Experimental Approach versus Population Balance and Connectionist Models.

Deasphalting bitumen using paraffinic solvent injection is a commonly used technique to reduce both its viscosity and density and ease its flow through pipelines. Common modeling approaches for asphaltene precipitation prediction such as population balance model (PBM) contains complex mathematical relation and require conducting precise experiments to define initial and boundary conditions. Machine learning (ML) approach is considered as a robust, fast, and reliable alternative modeling approach. The main objective of this research work was to model the effect of paraffinic solvent injection on the amount of asphaltene precipitation using ML and PBM approaches. Five hundred and ninety (590) experimental data were collected from the literature for model development. The gathered data was processed using box plot, data scaling, and data splitting. Data pre-processing led to the use of 517 data points for modeling. Then, multilayer perceptron, random forest, decision tree, support vector machine, committee machine intelligent system optimized by annealing, and random search techniques were used for modeling. Precipitant molecular weight, injection rate, API gravity, pressure, C5 asphaltene content, and temperature were determined as the most relevant features for the process. Although the results of the PBM model are precise, the AI/ML model (CMIS) is the preferred model due to its robustness, reliability, and relative accuracy. The committee machine intelligent system is the superior model among the developed smart models with an RMSE of 1.7% for the testing dataset and prediction of asphaltene precipitation during bitumen recovery.

Crude oils mixtures: compatibility and kinetics of water-in-oil emulsions separation

Some oil fields produce from different reservoirs, which may be incompatible generating precipitates. These precipitates are often asphaltenes, which can be an emulsion stabilizing agent negatively affecting the oil treatment processes. In this work, the influence of oil incompatibility on the stabilization of water-in-oil emulsions was studied. Emulsions were evaluated from three different oils (A, B and C) and their mixtures (AB, AC, BC and ABC). The results showed that there is a relationship between separation kinetics of emulsions and asphaltene precipitation. The separation kinetics of the emulsions was faster for more compatible oils. We observed that oil A, which was the less stable regarding asphaltenes, and the ABC mixture, which was the most incompatible mixture, both presented the slowest kinetics of emulsion separation. On the other hand, mixture BC which had the highest compatibility among the other mixtures presented a faster kinetic of emulsion separation.

Silica/polyacrylamide nanocomposite for inhibition of asphaltene precipitation from unstable crude oils

Among various flow assurance problems, asphaltene precipitation is a major issue. This study aims to evaluate the potential application of silica-polyacrylamide nanocomposite to inhibit asphaltene precipitation for the first time. The nanocomposites were synthesized and characterized by Fourier transform infrared and field emission scanning electron microscopy techniques. The inhibitory effect of nanocomposites in water-based nanofluid on two unstable crude oils was evaluated using viscometry, asphaltene dispersion test, dynamic light scattering, and polarized microscopy techniques. The viscosity measurements indicate that nanocomposites postpone asphaltene onset of precipitation from 34 to 44 and 23 to 36 vol% nC7 for crude oil A and B, respectively. The maximum dispersion efficiency of nanocomposite was 69% and 79% at the 1% and 2.5% nanofluid volume dosages for crude oil A and B, respectively. Dynamic Light Scattering and microscopy results indicated the asphaltene size change to lower values in the presence of nanocomposites. Polyacrylamide attached to the silica surface promotes a surface with efficient functional groups that increase the asphaltene adsorption. Asphaltene adsorption leads to decreased aggregate size and controlling the asphaltene precipitation. The prepared nanocomposite was evaluated as an efficient dispersant and inhibitor that reveals the potential application of Silica-polyacrylamide for handling the asphaltene precipitation in reservoirs.

In Situ FTIR Spectroscopic Imaging of Asphaltene Deposition from Crude Oil under n-Heptane and Acetone Flows

Asphaltene deposition from crude oil, induced by n-heptane and acetone flows in a microfluidic device, was studied by optical and FTIR spectroscopic imaging techniques in situ. It was found that n-heptane and acetone penetrate crude oil in completely different ways, which is responsible for the formation of deposits with different structures and chemical compositions. The contact of the n-heptane flow with crude oil leads to fast aggregation of asphaltenes at the interface, resulting in the formation of a compact deposit fixed to the surface. Subsequent slow diffusion of n-heptane into crude oil causes asphaltene aggregation and precipitation of loose deposits. In the case of acetone, the flocculant diffuses (faster than n-heptane) into crude oil, which results in removal of its soluble components and in the formation of deposits appearing as strips as well. The distribution of the functional groups (–OH(NH), CH2–CH3, C=O, C–O, S=O) in the deposits is spatially heterogeneous. The asphaltenes deposits formed at the flocculant-crude oil interface are richer in the functional groups than those formed during diffusion. No carbonyl groups were revealed in the deposits formed in the acetone flow, while oxygen-containing groups such as –OH(NH) and S=O were present, which was an unusual result.

Performance analysis of kinetic models in predicting asphaltene precipitation rate under different conditions of temperature and percentage of precipitant molecular weight

Performance analysis of kinetic models in predicting asphaltene precipitation rate under different conditions of temperature and percentage of precipitant molecular weight

Asphaltene precipitation under controlled mixing conditions in a microchamber

Solvent exchange is a controlled process for dilution-induced phase separation. This work utilizes the solvent exchange method to reveal the effect of the mixing dynamics on the asphaltene precipitation process under 20 different mixing conditions using a model system of n-heptane and asphaltene in toluene. The external mixing between the asphaltene solution and the paraffinic solvent is strictly controlled. We employed high-spatial resolution total internal reflection fluorescence microscope to detect asphaltene precipitates with a resolution up to ∼ 200 nm. A multiphysics model is used to simulate the evolution of oversaturation pulse in the solvent exchange process. Based on the simulation results, we predicted the effect of the flow rate, dimension, orientation of the microfluidic chamber, and temperature on the surface coverage and size distribution of asphaltene precipitates. The model predictions of all factors corroborate with the experimental observations. Local concentration of the solvent and shear forces are found to be the two main reasons for the change of asphaltene precipitation caused by mixing dynamics. However, the influence of thermodynamics is more critical than the mixing dynamics as temperature changes. Through a combination of experimental and simulation studies, this work illuminates the significance of the transportation process for the final morphology of asphaltene precipitates and provides a in-depth insight into the mechanism of mixing dynamics on the asphaltene precipitation. A smart mixing may be to boost new phase formation without excessive solvent consumption.

The hard-core effect on PC-SAFT to model asphaltene precipitation in petroleum reservoir fluids

In this work, a hard-core version of the Perturbed Chain-Association Fluid Theory Equation of State (PC-SAFT EoS) is proposed and used to predict upper asphaltene onset pressures (AOPs), bubble points (BPs), and precipitated asphaltene amounts for eighteen real petroleum reservoir fluids around the world. As a result, for the same assumed asphaltene molecular weight (MW) value, this hard-core PC-SAFT model predicts lower AOPs than the other two PC-SAFT versions here tested, including the original version of PC-SAFT. The AOPs and precipitated asphaltene amounts are found to be directly related to the asphaltene MW values used for each PC-SAFT model. The hard-core PC-SAFT model here presented is the PC-SAFT version that requires the lowest asphaltene MWs and predicts the lowest precipitated asphaltene amounts for the eighteen fluids modeled.

Introducing a new method of using nanocomposites for preventing asphaltene aggregation during real static and dynamic natural depletion tests

ABSTRACT The recent use of nanoparticles (NPs) to adsorb asphaltene from oil in the oil reservoir has been recognized by researchers as an effective method. The present study shows a new synthetic nanocomposite (NC) called zirconia-zinc-copper for the removal of asphaltene deposits. The NC structure was determined by Scanning Electron Microscopy (SEM), Transmission Electron Microscopy (TEM), Fourier transform infrared spectroscopy (FT-IR), X-ray diffraction (XRD), Brunauer-Emmett-Teller (BET), and Energy Dispersive X-ray (EDX) analysis. In this study, to investigate the reduction of permeability/porosity in porous media, dynamic natural depletion (DND) experiments in the presence of nanocomposites (NCs) under static conditions were used. Also, in the presence of NCs, isotherm models, CO2-oil (CO) IFT tests, and DND tests at the static phase were performed. In the following, the results were compared with zirconia NPs. The results showed that the mean particle diameter of NCs was measured by TEM analysis, about 27 nm. On the other hand, XRD analysis confirmed the TEM results. EDX analysis confirmed the presence of Zirconia, Zinc, Copper, and Oxygen elements in the synthetic NC structure. Also, FT-IR analysis shows the presence of zinc oxide (ZnO) and Copper oxide (CuO) peaks well. In addition, it was observed that the properties of ZrO2-ZnO NCs were well improved using copper doping. The results of adsorption data in the presence of NC and zirconiaNPs showed that the above data are more consistent with Langmuir (LI) isotherm than Freundlich (FI) isotherm. In this regard, NCs had a higher absorption rate in batch experiments than zirconia. There were two different slopes in the IFT CO reading in the static phase, where the pressure increased from 200 Psi to 2600 Psi. Also, the second slope (1700 Psi-2600 Psi) was slower than the first slope (200 Psi-1700 Psi) due to the accumulation of asphaltene. The slope ratio of 2 to 1 after adding NC and zirconia NPs increased from 19.8% to 24.1% and 26.5%, respectively. In general, the results showed in this study that NCs absorb more asphaltene than zirconia NPs. NCs reduced asphaltene precipitation (AP) more than zirconia during natural depletion experiments. In this regard, NCs were selected for natural depletion experiments. Finally, asphaltene deposits, which occur in the dynamic phase, decreased after adding NC, and, finally, the porosity/permeability parameters improved well.

Time domain NMR: An alternative for study of the asphaltenes precipitated in petroleum.

During the oil production and processing stages, the asphaltene precipitation is one of the great operation problems of oil industry. It can precipitate in the formation, tubing, or surface, causing operating problems, such as reduction in oil recovery by changing the reservoir permeability and wettability, clogging of the pipelines, and difficulty in separations process. The quantification of asphaltenes in petroleum by ASTM D6560 standard method is very laborious and use of a larger solvent volume than necessary. The present work proposes the use of time domain nuclear magnetic resonance (TD-NMR) as new methodology to quantify the asphaltene precipitated in crude oil. Three (light, medium, and heavy) crude oils with asphaltenes content of 0.97, 1.88, and 7.00 wt% were mixed with n-heptane in different R (ml of solvent/g of oil) values and analyzed by means of transverse relaxation time (T2 ). According NMR results, the R values enough for complete asphaltene precipitation for the oils A, B, and C were, respectively, equal to 16.50, 23.00, and 39.50 ml g-1 . These outcomes represent a reduction of 58.75%, 42.50%, and 1.25% in the solvent volume per mass of oil for the oil A, B, and C, respectively, compared to the ASTM D6560 method, which imposes 40 ml g-1 . Therefore, it has been shown that TD-NMR can be applied to estimate the amount of asphaltene precipitated in petroleum and have potential to be applied in routine analysis with advantages of saving time and costs.

Co-adsorption behaviors of asphaltenes and different flow improvers and their impacts on the interfacial viscoelasticity

Different co-adsorption behaviors and interfacial viscoelasticities are attributed to the different interaction mechanisms between the flow improvers and the asphaltenes. Commonly used flow improvers in oilfields, such as ethylene–vinyl acetate copolymer (EVA), poly(octadecyl acrylate) (POA), and polymethylsilsesquioxane (PMSQ) are proven to be effective to enhance the flowability of crude oil. However, the addition of these flow improvers may change the stability of the emulsion and make the crude oil treatment process challenging. In this research, the impacts of different flow improvers on the interfacial properties of the emulsions containing asphaltenes are systematically investigated. The co-adsorption behaviors of the flow improvers and asphaltenes are analyzed through dynamic interfacial tension (DIFT). The rheological properties of the interfacial layer after the adsorption are explored via dilational viscoelasticity. Significant difference is observed in the structural properties of the interface adsorbed by different flow improvers, which is attributed to different interactions between the flow improvers and asphaltenes. To investigate these interactions, conductivity, asphaltenes precipitation, dynamic light scattering (DLS), and contact angle experiments are conducted systematically. Results show that EVA and POA can alter the interfacial properties by changing the asphaltene dispersion state. The interaction between EVA and asphaltenes is stronger than that between POA and asphaltenes due to the difference in molecular structures. Unlike EVA and POA, the change of interfacial property with the addition of PMSQ is attributed to the partial adsorption of asphaltenes on PMSQ.

An Investigation of the Effect of Asphaltene Polydispersity on Asphaltene Precipitation and Deposition Tendencies

An Investigation of the Effect of Asphaltene Polydispersity on Asphaltene Precipitation and Deposition Tendencies

Asphaltene adsorption of Co3O4 nanoparticles modified by SiO2 film

Asphaltene precipitation could have several negative consequences, including production decline, wellbore plugging, and even severe safety concerns. Therefore, an effective strategy of asphaltene adsorption is highly significant. Nanoparticles possess a large surface area, showing a high adsorption potential for asphaltene. However, the self-aggregation property limits its adsorption capacity. In this work, the Co3O4 nanoparticles were ingeniously selected as an inhibitor of asphaltene precipitation, and a porous SiO2 film was formed via the sol-gel method. The evaluation experiments indicated that the SiO2 film significantly reduced the self-aggregation. Hence, the specific surface area of nanoparticles increased from 20.87 m2/g to 29.25 m2/g. Meanwhile, molecular dynamics simulations confirmed that the modified nanoparticles exhibited 1.6 times higher adsorption energy and a lower mean square displacement than the fundamental nanoparticles. With these improvements, the Co3O4-SiO2 nanoparticles developed greater stability and dispersion, which raised the adsorption of the nanoparticles on asphaltene from 1.24 mg/m2 to 1.53 mg/m2, presenting a considerable adsorption capacity. This study broadens the selection of nanoparticles for asphaltene adsorption. It demonstrates the improvement of nanoparticles by porous SiO2 film in various aspects, which can provide a solution for inhibiting asphaltene precipitation in oil fields as well as guidance for subsequent functionalization of nanoparticles.

Experimental investigation and thermodynamic modeling of asphaltene precipitation during pressure depletion and gas injection at HPHT conditions in live oil using PC-SAFT EoS

Due to the high costs associated with asphaltene precipitation and deposition, the study of this flow assurance problem has always been a major issue in the petroleum industry. We studied the asphaltene phase behavior in four Iranian live oil samples. First, asphaltene onset pressure and the amounts of the precipitated asphaltene during pressure depletion and gas injection at high-pressure high-temperature (HPHT) conditions were measured, experimentally. Then, thermodynamic modeling of asphaltene precipitation was performed using the perturbed chain form of the statistical associating fluid theory (PC-SAFT). In previous researches, PC-SAFT equation of state (EoS) along with the standard method of characterization was applied to light crude oil having low asphaltene content only, while in this work, three of the samples were heavy oil with high asphaltene content. To perform the thermodynamic modeling, the oil samples were characterized by two different methods. In the first method, the adjustable parameters of the model, which are the aromaticity of aromatics + resins and the aromaticity of asphaltene, were adjusted separately. In the second method, both of the parameters of the model were tuned simultaneously, as one of the novelties of this research. Then the amounts of precipitated asphaltene were modeled using the aforementioned characterization methods, and the results were compared to the experimental data. According to the results, simultaneous adjustment of the model parameters in the heavy oil samples could improve the average absolute deviation (AAD) by 5% - 12%. However, no remarkable improvement was observed for the light oil sample. For two of the oil samples, the proposed model showed a good agreement with the experimental data as the calculated AAD were 14% and 26%. For the other oil samples, the trend of the experimental data was predicted by the model, but the values of the experimental data could not be matched. We were able to solve this problem by introducing a confidence factor for experimentally measured data. By considering this weight factor, in one of the samples, the AAD was reduced by about 70% and reached 24%, and in other oil sample, the error decreased by 90% and reached 31%.

Asphaltene Precipitation and Deposition under Miscible and Immiscible Carbon Dioxide Gas Injection in Nanoshale Pore Structure

Summary Asphaltene precipitation and deposition is considered one of the prevailing issues during carbon dioxide (CO2) gas injection in gas enhanced oil recovery techniques, which leads to pore plugging, oil recovery reduction, and damaged surface and subsurface equipment. This research provides a comprehensive investigation of the effect of immiscible and miscible CO2 gas injection in nanopore shale structures on asphaltene instability in crude oil. A slimtube was used to determine the minimum miscibility pressure (MMP) of the CO2. This step is important to ensure that the immiscible and miscible conditions will be achieved during the filtration experiments. For the filtration experiments, nanocomposite filter paper membranes were used to mimic the unconventional shale pore structure, and a specially designed filtration apparatus was used to accommodate the filter paper membranes. The uniform distribution (i.e., same pore size filters) was used to illustrate the influence of the ideal shale reservoir structure and to provide an idea on how asphaltene will deposit when utilizing the heterogeneous distribution (i.e., various pore size filters) that depicts the real shale structure. The factors investigated include immiscible and miscible CO2 injection pressures, temperature, CO2 soaking time, and pore size structure heterogeneity. Visualization tests were undertaken after the filtration experiments to provide a clear picture of the asphaltene precipitation and deposition process over time. The results showed an increase in asphaltene weight precent in all experiments of the filtration tests. The severity of asphaltene aggregations was observed at a higher rate under miscible CO2 injection. It was observed that the miscible conditions have a higher impact on asphaltene instability compared to immiscible conditions. The results revealed that the asphaltene deposition was almost equal across all the paper membranes for each pressure used when using a uniform distribution. Higher asphaltene weight percent were determined on smaller pore structures of the membranes when using heterogeneous distribution. Soaking time results revealed that increasing the soaking time resulted in an increase in asphaltene weight precent, especially for 60 and 120 minutes. Visualization tests showed that after 1 hour, the asphaltene clusters started to precipitate and could be seen in the uppermost section of the test tubes and were fully deposited after 12 hours with less clusters found in the supernatant. Also, smaller pore size of filter membranes showed higher asphaltene weight percent after the visualization test. Chromatography analysis provided further evaluation on how asphaltene was reduced though the filtration experiments. Microscopy and scanning electron microscopy (SEM) imaging of the filter paper membranes showed the severity of pore plugging in the structure of the membranes. This research highlights the impact of CO2 injection on asphaltene instability in crude oil in nanopore structures under immiscible and miscible conditions. The findings in this research can be used for further research of asphaltene deposition under gas injection and to scale up the results for better understanding of the main factors that may influence asphaltene aggregation in real shale unconventional reservoirs.

An insight into molecular weight distributions of asphaltene and asphalt using Gel Permeation Chromatography

Asphaltene and asphalte precipitations during production, transportation and processing of crude oil are one of the problems in the oil industry. The amount and characteristics of these precipitations depend on the type of solvent, oil–solvent ratio, time, pressure, temperature, etc. Measuring molecular weight distributions of asphaltene and asphalt could be necessary to predict the phase behavior and prevent asphaltene and asphalte depositions. Therefore, in this study, the molecular weight distributions of asphaltene and asphalt were studied. For this purpose, asphaltene and asphalt samples were prepared by adding different ratios of precipitants such as n-pentane, n-hexane, and n-heptane in an Iranian crude oil using the IP-143 method. Then, we used Gel Permeation Chromatography to measure the molecular weight distributions of these samples. The obtained results indicate that asphaltene has more aggregation with higher molecular weight compared to asphalt. In addition, results show that the molecular weight distribution of asphaltene is generally wider than the molecular weight distribution of asphalt.

Perspectives on Microfluidics for the Study of Asphaltenes in Upstream Hydrocarbon Production: A Minireview

The utilization of microfluidics has generated deep insights into asphaltene precipitation mechanisms and oil–water emulsion stabilization. Agglomeration and precipitation of asphaltenes can cause flow assurance problems during the extraction and transportation of crude oil. Change in temperature, pressure, reservoir conditions, and solvents can change the local environment, leading to asphaltene precipitation. Understanding asphaltene properties and precipitation pathways becomes critical in devising mitigation methods, demulsifiers, and suitable conditions during hydrocarbon processing. Microfluidics has helped in high throughput measurement studies, understanding critical processing conditions, fast demulsifier screening, and the effect of solvent concentration on deposition, generating useful information for utilization at the point of resource extraction facilitating improved resource management. It has become possible to capture the porous, complex nature of reservoir formations and the interaction of chemicals during precipitation through integrated analytics and visualization studies available only through microfluidics. The use of droplet microfluidics, with optical microscopy and high-speed imaging to study the oil–water interface, has resulted in greater understanding of the role of asphaltenes in interfacial properties and emulsion stabilization. This minireview highlights the crucial aspects of microfluidics that have been used to understand physicochemical behavior and dynamics of asphaltene deposition. Some of the unique devices have been presented focusing on the key elements of microfluidics design, fabrication, and analysis, as the insight obtained from microfluidics strongly depends on the device design and the controllability of the experimental parameters. Successful implementation of microfluidics for efficient and controlled experiments, short analysis time scales and rapid screening, and generation of high-quality, reliable data that convey asphaltene deposition issues and interface behavior in emulsions shows the importance of microsystems for advancing knowledge in hydrocarbon production and processing.

The bitumen formation and Re-Os characteristics of a CO2-rich pre-salt gas reservoir of the Kwanza Basin, offshore Angola

Here we present a study on the formation process and Re–Os systematics of the bitumen discovered in a CO2-rich pre-salt gas reservoir, south Kwanza Basin, offshore Angola. The magmatism-derived CO2 may have expanded downwards from the top of the reservoir, creating CO2 concentration and temperature gradients within the reservoir, and leading to the gradients of asphaltene precipitation and thermal cracking. The heat front may have been behind the CO2 front due to the heat exchange with surrounding rocks. Thus, asphaltene precipitation has likely occurred before the thermal cracking. Such bitumen formation process is consistent with the observed decreasing bitumen content and Rock-Eval Tmax with depth, and also the characteristics of the whole rock and bitumen Re and Os concentrations.Five closely spaced bitumen samples define a Re–Os age of 116 ± 29 Ma that is identical to the timing of CO2 charging and thus may indicate the timing of bitumen formation. The heterogeneous 187Os/188Os and lack of mobility of the asphaltene deposit, and the relatively low extent of thermal cracking (Tmax of 425–470 °C) may account for the lack of homogenization of the bitumen initial 187Os/188Os.Given the highly radiogenic initial 187Os/188Os (ca. 1.2–1.8) of the bitumen and limited 187Os/188Os ingrowth within the ca. 15 million years from the deposition of potential source rock (Barremian-Aptian Red and Grey Cuvo formations) to the bitumen formation, the source rock should possess a highly radiogenic initial 187Os/188Os (>1). This is consistent with that of the equivalent lacustrine strata in the conjugated Brazilian marginal basins. Thus, the Os isotope composition indicates that the lacustrine Red and Grey Cuvo formations could be the source rock for the bitumen of the studied CO2-rich pre-salt gas reservoir in the south Kwanza Basin.