Hemanta Kumar Sarma

Diffusivity of Citric Acid During its Reaction With Calcite

The mass transfer process during the reaction of citric acid with calcite was investigated using a rotating disk apparatus. The effects of disk rotational speed, initial citric acid concentration and temperature on the effective diffusion coefficient of citric acid were examined. Using various citric acid concentrations (1 wt%, 2 wt%, 5 wt% and 7.5 wt%), the diffusion coefficient of citric acid was calculated at 25°C, 40°C and 50°C. The effective diffusion coefficient of citric acid was found to be a function of the interplay between the calcium citrate precipitation and the presence of the counter-calcium ions. At high-initial acid concentration (5 wt% and 7.5 wt%), the effects of calcium citrate precipitation and counter-calcium ions were significant and the calculated citric acid diffusion coefficients were not comparable with those obtained using the rotating disk. However, the effects of both the calcium citrate precipitation and the counter-calcium ions on the citric acid diffusivity were minimal at low-initial citric acid concentrations. The effect of temperature on the diffusion coefficient of citric acid at a constant citric acid concentration was found to follow Arrhenius law, and the activation energy was 37.9 kJ/mol.

A Genetic Algorithm-Based Model to Predict CO-Oil Physical Properties for Dead and Live Oil

Paper first presented at the 7th Canadian International Petroleum Conference the 57th Annual Technical Meeting of the Petroleum Society), June 13-15, 2006, in Calgary, Alberta.

Numerical Simulation and Sensitivity Analysis of Gas-Oil Gravity Drainage Process of Enhanced Oil Recovery

This paper presents a challenging work of simulating the top-down CO2-asssited gravity drainage EOR method. It investigates the effect of injection / production rate combinations, porosity heterogeneity, connate water saturation and type of injection well on the reservoir performance monitoring parameters including oil production rate, gas/water-oil ratio (GOR/WOR), cumulative oil production, average pressure supported by 2D oil saturation movement. It is becoming a benchmark for reservoir simulation studies of this specific process, reflected through the number of downloads; 31 times in past 30 days; 843 times Since 2007 (as on 19 Oct 2012); third most downloaded paper in 2010 (Onepetro.org).

Prediction of CO2 Solubility in Oil and the Effects on the Oil Physical Properties

Abstract CO2 solubility in oil is a key parameter in CO2 flooding process. It results in oil swelling, increased oil density, and decreased oil viscosity. Laboratory studies needed to cover a wider range of data, and are time consuming, costly, and may be not available or possible in many situations. On the other hand, although various models and correlations are useful in certain situations, they may are not be applicable in many situations. In this study, a new genetic algorithm- (GA)-based technique has been used to develop more reliable correlations to predict CO2 solubility, oil swelling factor (SF), CO2-oil density, and viscosity of CO2-oil mixtures. Based on the Darwinian theory, the GA technique mimics some of the natural process mechanisms. Furthermore, GA-based model correlations recognize all the major parameters that affect each physical property and also well address the effects of CO2 liquefaction pressure. Genetic algorithm-based correlations have been successfully validated with published experimental data. In addition, a comparison of these correlations has been made against widely used correlations in the literature. It has been noted that the GA-based correlations yield more accurate predictions with lower errors than all other correlations tested. Furthermore, unlike other correlations that are applicable to limited data ranges and conditions, GA-based correlations have been validated over a wider range of data.

Genetic Algorithm (GA)-Based Correlations Offer More Reliable Prediction of Minimum Miscibility Pressures (MMP) Between Reservoir Oil and CO or Flue Gas

Two new genetic algorithm (GA)-based correlations were proposed for more reliable prediction of minimum miscibility pressure (MMP) between reservoir oil and CO 2 or flue gas. Both correlations are particularly useful when experimental data are lacking and also in developing an optimal laboratory program to estimate MMP. The key input parameters in a GA-based CO 2 -oil MMP correlation, in order of their impact, were: reservoir temperature, MW of C 5+ , and volatiles (C 1 and N 2 ) to intermediates (C 2 -C 4 , H 2 S and CO 2 ) ratio. This correlation, which has been successfully validated with published experimental data and compared to common correlations in the literature, offered the best match with the lowest error (5.5%) and standard deviation (7.4%). For a GA-based flue gas-oil MMP correlation, the MMP was regarded as a function of the injected gas solvency into the oil which, in turn, is related to the injected gas critical properties. It has also been successfully validated against published experimental data and compared to several correlations in the literature. It yielded the best match with the lowest average error (4.6%) and standard deviation (6.2%). Moreover, unlike other correlations, it can be used more reliably for gases with high N 2 (up to 20%) and non-CO 2 components (up to 78%), e.g., H;S, N 2 , SO x , O, and C 1 -C 4 .

A New Method to Characterize the Size and Shape Dynamics of Asphaltene Deposition Process in CO2 Miscible Flooding

Use of miscible solvents in improved-oil-recovery processes requires knowledge of how the solvent will behave over all mixing ratios of oil and solvent. In particular it is important to know at what solvent concentration the asphaltenes start to precipitate and what conditions will cause the particles to flocculate and eventually deposit in the reservoir pore network. A new method was developed that uses image analysis to convert information obtained from a sequence of images to describe the process of asphaltene precipitation under reservoir conditions. The full-length paper describes application of frequency-domain imaging to study the asphaltene-precipitation/-flocculation/-deposition process for a Japan Natl. Oil Corp. (JNOC) CO 2 miscible flood.

A novel improved oil recovery approach for increasing capillary number by enhancing depth of penetration in abu dhabi carbonate reservoirs

During the last few decades, there has been a globa l increase in oil demand by 35%. Besides, the petroleum industry is faced with a number of challe nges when considering the reservoir such as low swe ep efficiency, formation damage and implementing costl y techniques to enhance and improve the oil recover y. Electrokinetic Low-concentration acid IOR (EK LCA-I OR) is one of the emerging IOR technologies, which involves the application of the Low-concentration a cidizing integrated with electrically enhanced oil recovery (EK-EOR). This research focusses on analyzing the e ffectiveness of the EK LCA-IOR process in Abu Dhabi carbonates, improving the capillary number and enha ncing depth of penetration. Core-flood tests were conducted by saturating Abu D habi carbonate core-plugs with medium crude oil in a specially designed core-flood setup at Abu Dhabi re se voir conditions. After the water flooding stage, EK LCAIOR was applied using varying voltage gradients and ci concentrations upto 1.2% HCl injected at the anode and transported by EK to the target producer (catho de). Moreover, the capillary number change, and Sin gle Energy CT Scan (SECTS) results were analyzed in ord er to observe the effect on rock-fluid interaction t control rock adsorption capacity through interfacial tensio and depth of penetration. Several correlations at reservoir conditions relate d o acid concentration, displacement efficiency an d permeability enhancement have shown that the applic ation of water flooding on the carbonate cores yiel ds an average oil recovery of 58%. An additional 17-28% o il recovery was enhanced by the application of EK L CAIOR recording a maximum oil displacement of 88%. In addition, EK LCA-IOR was shown to enhance the reservoir’s permeability by 53% on average across t he tested core-plugs. EK LCA-IOR also improves the capillary number by 500% in Water-wet core plugs an d 1500% in Oil-wet core plugs, mainly due to a decr ease in interfacial tension. This indicates the decrease in acid adsorption as acid is precisely transporte d to the targeted production well through the tortuous path with an increased depth of penetration as proven by the SECTS results where EK LCA-IOR has penetrated 60% o f core-length that revealed minor fractures, precis ely delivering the acid front throughout the core-plug. Finally, EK LCA-IOR enhances capillary number along with an increased depth of penetration while allow ing us to save on the OPEX by maintaining decreased power consumption while reducing the acid/water requireme nt upto 10 times. This study takes one step forward to wards the development of EK Low-concentration acid IOR method feasible for Abu Dhabi oil fields in order t o make smart water floods applicable for complex fr actured reservoirs of UAE.

Uncertainty Analysis of Smart Waterflood Recovery Performance in Clastic Reservoirs

In recent years, numerous laboratory studies have documented the benefits of smart waterflooding as an emerging enhanced oil recovery (EOR) process, along with a few successful field applications, notably clastic reservoirs. In most cases, there are undeniable inconsistencies between lab and field results. This process has led to unpredictable outcomes and misleading prediction of smart waterflooding projects. Hence, this work is conducted to evaluate uncertainties in smart waterflooding from laboratory to field-scale. An one-dimensional (1-D) reactive transport model was developed and validated with flooding experiments. Validation shows that combinations of various matching parameters can be used to interpret the experiment. Different realizations lead to different results when extended to 3-D heterogeneous model. The sensitivity of parameters like grid size and heterogeneity in full-field model majorly influences smart waterflooding performance, which is responsible for the inconsistencies. Therefore, these parameters should be considered in field-scale simulation to fully demonstrate the potential of smart waterflooding.

Brine Chemistry Effects in Waterflood and CO2 Injection in Carbonate Reservoirs

It has been reported that the waterflood performance in carbonate reservoirs could be significantly ameliorated by tuning the injected brine salinity and ionic composition. Also, it is noted that the brine salinity affects the CO2 injection process. This study looked into such possible effects of brine chemistry on waterflood and CO2 injection for typical UAE carbonate reservoir conditions of high temperature and pressure (T = 120°C and P = 20.68MPa).Effects on waterflood performance were investigated experimentally by a series of flooding tests at temperatures of 70°C and 120°C. In addition, an imbibition test was conducted at 70°C, followed by wettability monitoring tests at 90°C to investigate the impact of brine salinity variations and ionic compositions on waterflood performance.The impact of brine salinity on CO2-brine system properties including CO2 solubility in brine, interfacial tension between CO2 and CO2-saturated brine, and density and viscosity of CO2-saturated brine were evaluated through correlation-based studies in conjunction with some experimental data. A mathematical pore-scale model was developed to assess the brine salinity effect on water-isolated oil recovery by CO2 diffusion through water barrier. This study led to the following findings:(1) Incremental oil recovery could be obtained by either reducing salinity or increasing sulfate concentration of the tertiary injected brine at both 70°C and 120°C. However, the incremental recovery was more remarkable at the higher temperature of 120°C.(2) At 70°C, lowering the water salinity is more effective than raising the sulfate concentration in injected water in terms of incremental oil recovery. It also exhibited a similar potential for increased oil recovery at 120°C.(3) Wettability monitoring tests showed that water-wetness of carbonate rock studied could be increased by either reducing the water salinity or increasing sulfate concentration of the surrounding water. This is consistent with the imbibition test, in which wettability alteration towards more water-wetness by low salinity water was noted.(4) Under typical UAE reservoir conditions, reducing the brine salinity could significantly enhance CO2 dissolution in brine, consequently inducing significant variation to the CO2-brine system properties. This would undoubtedly impact CO2 injection performance.(5) Under typical UAE reservoir conditions, the capacity and rate of CO2 diffusion through water barrier to oil phase could be significantly reinforced by lowering the brine salinity of the water barrier.Copyright