API Gravity Research Articles

Modelling the flowing bottom hole pressure of oil and gas wells using multivariate adaptive regression splines

One crucial factor that aids the evaluation of oil and gas well productivity is the flowing bottom-hole pressure (FBHP). However, accurately determining the FBHP has been challenging for the oil and gas industry. Traditional methods, such as using downhole gauges or relying on empirical and mechanistic models, have limitations, prompting the exploration of alternative approaches such as machine learning (ML). However, most ML models operate as black box models, lacking transparency and interpretability. In this study, the multivariate adaptive regression splines algorithm was used to develop a FBHP estimation model. The model includes eight input variables and was built using 1001 data points from literature. The results show that the model achieved a coefficient of correlation, root mean square error and average absolute percentage error values of 0.94, 130 and 4.2% respectively. Compared to existing models, the developed model exhibited improved predictive accuracy. Sensitivity analysis indicates that water flow rate and depth had the largest effect on FBHP estimation, each contributing 17.5%, while oil API gravity had the least effect with a contribution of 3.5%. This study showcases a novel model that is explicitly presented, interpretable and physically validated, making the model suitable for integration into software applications. These attributes are lacking in many existing FBHP estimation models. By utilizing this model, the costs associated with downhole gauges can be saved, and real-time estimations can be obtained in the field. The model would be useful to oil industry players producing from unconventional wells where downhole gauges are rarely installed.

Investigating the effects of ultrasonic waves and nanosilica on the viscosity reduction of Sharqy Baghdad heavy crude oil

The current study examines the combined impacts of ultrasonic waves and nano silica (NS) on reducing the viscosity Sharqy Baghdad heavy crude oil with an API gravity of 20.32. NS of an average particle size of 59.93 nm and 563.23 m²/g surface area were produced utilizing the sol-gel technique from Iraqi sand. The XRD analysis indicates the existence of an amorphous silica, the SEM analysis showed that NS tends to agglomerate, and the FTIR spectra exhibited the presence of siloxane and silanol groups. In addition, the TGA analysis demonstrated a total weight loss of 15.62%, validating the thermal stability of the NS. The experiments included a study of the impact of ultrasonic power, exposure time, duty cycle, temperature, and the combined effects of the ultrasonic waves and silica nanoparticles on the degree of viscosity reduction percentage (DVR%). The results demonstrated that the viscosity of the heavy crude oil decreased by 27.83% at an irradiation time of 2 min, power of 360 W, 0.8 duty cycle, a temperature of 35 ⁰C, assisted by nano silica at a concentration of 1500 mg/L.

Geochemical Characteristics and Origin of Crude Oils from Sunda and Asri Basins, Indonesia

The Sunda and Asri Basins are back-arc basins located SE of Sundaland at the present day. These basins contain Cenozoic sediments deposited in a Paleogene half-graben system. This rifing was followed by sagging during the Neogene associated with a north-south major fault system in the eastern part. The Sunda and Asri Basins constitute significant petroliferous basins in Indonesia which have produced more than a billion barrels of oil equivalent. Some studies conducted focus on geochemistry only in Sunda or Asri Basins, but a comprehensive geochemical study integrating data from both basins have never been conducted. This is the first paper to integrate the geochemical characteristics and the origin of crude oils from Sunda and Asri Basins. A total of eighteen crude oils were investigated to delineate their characteristics. The results provide an explanation about the origin of the organic matter and the genetic relationship between crude oils from Sunda and Asri Basins, and their probable source rocks. This study presents an in-depth geochemical characterization. The crude oils were classified as aliphatic oils, as indicated by their high saturated hydrocarbon fractions (>50 %). The API gravity values of the crude oils range from 25.3 to 39, and their sulfur content was low (0.01 %). Geochemistry analysis reveals a novel interpretation of crude oils originating from shale source rock deposited under oxic-suboxic conditions. Sunda and Asri crude oils exhibited relatively similar stable carbon compositions. The modest concentrations of biomarker 18α(H)-oleanane (OL) indicate that the source age is younger than Late Cretaceous. The crude oil in the Sunda and Asri Basins were charged from source rocks that reached early to peak maturity. The results of the current study strongly indicate the differentiation in lacustrine organofacies of crude oils from the Sunda and Asri Basins. The source rock for these crude oils were shales from the Paleogene syn-rift Banuwati Formation.

Characterization of the Liquid Fuel Produced from Catalytic Depolymerization of Polymeric Waste Using Batch Reactor

The high rate of generation of plastic waste in the country and the fact that all other means of Municipal Plastic Waste (MPW) management techniques had failed leading to the requirement of efficient and alternative disposal technique-depolymerization. The technique involves heating the polymeric waste at an elevated temperature in an inert environment to produce condensable, non-condensable, hydrocarbon and biochar. The plastic waste was collected at the Ilokun dumpsite in Ado-Ekiti, southwest Nigeria. Each component of the waste samples was depolymerized in a batch reactor without the use of a catalyst and with the addition of 10 g of activated carbon (AC) and calcium oxide (CaO) as catalysts. The liquid fuels which were produced between the temperature range of 219 and 232 were blended with standard fuel. Fuel samples with conventional diesel and depolymerized plastic diesel were characterized based on ASTM standards. The results of the proximate and ultimate analysis indicated that percentage moisture content ranges from 0.00-0.18%, volatile matter ranges between 96.66-99.75% and percentage ash content ranges from 0.13-3.03%. Fixed carbon ranges from 0.004-0.31% while the Gross Heating Value (GHV) ranges from 42.66-45.87 MJ/kg. The CHONS analyzer indicated the percentage of carbon, hydrogen, oxygen, nitrogen, and sulfur content range 81.64-85.51%, 12-31-18.04%, 0.00-1.51%, 0.00-0.73%, and 0.10- 0.97% respectively. The results of the physiochemical properties of the samples show that the density, API gravity, Kinematic viscosity and Flash point vary from 0.76-0.83 (g/cm3), 38.98-54.68, 17-2.80 (cm2/s) and 50.0-70.0 (°C) respectively while Cloud point, Pour point, Fire point and Cetane index range from -20-15.0 (°C), -23-7 (°C), 61.0-79.0 (°C) and 38.50-47.0. The pH values of the liquid fuel samples vary from 6.60-3.30. The overall results of the characterization indicated the fuel samples have proximity to the properties of the conventional diesel following the ASTM D975, ASTM D4737, ASTM D1298, ASTM D445, ASTM D2709, and ASTM D482 standards. The depolymerized polymeric waste is sustainable, with a low cost of production. Hence a good substitute as an alternative fuel and means of wealth creation from waste.

Microfluidic Constant Composition Expansion for Black Oils and Retrograde Gas Condensates

Summary Building a robust pressure/volume/temperature (PVT) model critically relies on accurate phase behavior data, traditionally obtained using PVT cells. While the PVT cell can provide accurate data, it requires a large volume of downhole or recombined samples, which are usually expensive to collect or time-consuming to create. A novel microfluidic chip design and method are presented in this work to rapidly measure saturation pressure, relative volume, and liquid volume percentages of black oils and retrograde gas condensates (RGCs). The chip was initially charged with the single-phase sample at a given temperature, and the saturation pressure, relative volume, and liquid volume percentages were quantified at prescribed pressure steps. The waiting time at each pressure step was adjusted to ensure that the equilibrium condition is achieved. The measurements were conducted for various oil and RGC samples with a wide range of API gravity. The high-resolution optical access along with an in-house-developed automated image analysis algorithm was used to detect the saturation pressures and quantify the phase volumes. The saturation pressures, relative volumes, and liquid volume percentages measured by microfluidics were compared with those obtained from conventional constant composition expansion (CCE) method, showing a strong agreement between the data (i.e., within less than 5% deviation). The microfluidic platform developed in this work can be an alternative approach to some of the conventional PVT tests with an order of magnitude higher laboratory throughput but similar accuracy. This makes PVT data accessible by reducing cost and sample size, and potentially moves the energy industry to a data-on-demand model. With a much smaller physical size inherent to microfluidic devices, this platform can be deployed to operation sites, alleviating the logistical challenges associated with sample handling and shipment that the industry currently struggles with.

First field application of functionalized nanoparticles-based nanofluids in thermal enhanced oil recovery: From laboratory experiments to cyclic steam stimulation process

The increasing global demand for fossil fuels and the depletion of light crude oil reserves have driven the petroleum industry to focus on exploiting heavy crude oils, which present significant challenges in recovery and processing. To address these challenges, enhanced oil recovery (EOR) technologies are being developed, with a strong emphasis on advances in catalysis and nanomaterials science. This research significantly contributes to developing new technologies for petroleum exploitation by introducing a novel nanofluid designed to facilitate in-situ upgrading of heavy oil, improving its quality for downstream refining and fuel production. The nanofluid, engineered to enhance the productivity of a heavy oil reservoir under cyclic steam stimulation, targets improvements in oil recovery and fuel-quality indicators such as API gravity and viscosity. Laboratory tests demonstrated the nanofluid’s capability to reduce oil viscosity, improve oil mobility, and selectively interact with heavy oil fractions like resins and asphaltenes. Displacement tests simulating steam injection conditions showed an improvement in oil recovery, increasing from 56 % to 76 % after nanofluid application. The treatment also led to a notable increase in API gravity, from 11.6° to 29.2°, and a significant reduction in viscosity, from 39,987 cP to 104 cP, indicating enhanced crude oil quality, critical for refining and fuel production. Field trials in two wells in Colombia demonstrated the nanofluid’s practical effectiveness, with production increases averaging 97 % and incremental yields of 11,966 barrels in well A and 3213 barrels in well B. Post-treatment, the crude oil exhibited sustained improvements in quality, with API gravity increasing from 11.6° to 13.4° and viscosity decreasing from 39,987 cP to 11,734 cP. These results confirm the long-term durability of the nanofluid’s effects and its potential to enhance fuel production from heavy oil reservoirs. Additionally, the field trial indicated a 48 % reduction in operational costs, primarily due to decreased steam generation and lower CO2 emissions, highlighting the environmental and economic benefits of nanofluid technology for petroleum exploitation.

Optimizing in-situ upgrading of heavy crude oil via catalytic aquathermolysis using a novel graphene oxide-copper zinc ferrite nanocomposite as a catalyst

Unconventional resources, such as heavy oil, are increasingly being explored and exploited due to the declining availability of conventional petroleum resources. Heavy crude oil poses challenges in production, transportation, and refining, due to its high viscosity, low API gravity, and elevated sulfur and metal content. Improving the quality of heavy oil can be achieved through the application of steam injection, which lowers the oil’s viscosity and enhances its flow. However, steam injection alone falls short of meeting the growing demand for higher-quality petroleum products. Catalytic upgrading is therefore being investigated as a viable solution to improve heavy oil quality. This study experimentally investigates the application of two novel catalysts, namely copper-substituted zinc ferrite (ZCFO) synthesized via the sol–gel combustion method and a graphene oxide-based nanocomposite (GO-ZCFO) with different ratios, for catalyzing aquathermolysis reactions in the steam injection process, with the aim of enhancing the in-situ upgrading of heavy oil. These catalysts underwent characterization using X-ray powder diffraction (XRD), Fourier Transform Infrared Spectroscopy (FTIR), and Transmission Electron Microscopy (TEM). Their catalytic performance was assessed utilizing a high-pressure/high-temperature reactor (300 ml), with a comprehensive analysis of the changes in the physical and chemical properties of the heavy oil before and after upgrading. This analysis included measurements of sulfur content, SARA fractions, viscosity, API gravity, and Gas Chromatography (GC) of saturated hydrocarbons and evolved gases. All upgrading experiments, including both catalytic and non-catalytic aquathermolysis processes, were conducted under a reaction time of 6 h, a reaction temperature of 320 °C, and high pressure (86–112 bar). The results indicated that the introduction of the proposed catalysts as additives into the upgrading system resulted in a significant reduction in sulfur content. This, in turn, led to a decrease in resin and asphaltene content, an increase in the content of saturated hydrocarbon, particularly low-molecular-weight alkanes, and ultimately, a reduction in viscosity along with higher API gravity of the crude oil. GO-ZCFO with a weight ratio (50:50) exhibited the best catalytic performance. The heavy crude oil, upgraded with this 50:50 ratio, exhibited significant enhancements, including a 29.26% reduction in sulfur content, a 21.27% decrease in resin content, a 37.60% decrease in asphaltene content, a 46.92% increase in saturated hydrocarbon content, a 66.48% reduction in viscosity, and a 25.49% increase in API gravity. In comparison, the oil upgraded through non-catalytic aquathermolysis showed only marginal improvements, with slight reductions in sulfur content by 5.41%, resin content by 3.60%, asphaltene content by 11.36%, viscosity by 17.89%, and inconsiderable increases in saturated hydrocarbon content by 9.9% and API gravity by 3.02%. The GO-ZCFO, with its high catalytic activity, stands as a promising catalyst that contributes to improving the in-situ upgrading and thermal conversion of heavy crude oil.

Catalytic Valorization of Heavy Crude Oil Via Aquathermolysis with Mo2C/S-ZrO2 System

Catalytic aquathermolysis emerges as a new approach to valorize heavy crude oil into lighter compositions with industrial compatibilities. Although several catalytic systems have been tested, certain critical issues remained unresolved. Therefore, the potential of Mo2C/S-ZrO2 as a candidate for upgrading a heavy crude oil with API gravity value of 12.0o was evaluated at the laboratory scale. Successful designed of the Mo2C/S-ZrO2 catalyst was established via FT-IR and XRD studies. Both techniques revealed features that were consistent with disappearance of MoO3 in MoO3/S-ZrO2 precursor and consequent formation of β-type Mo2C. Interestingly, the tetragonal form of ZrO2 was also unaltered by the carburization treatment (i.e. CH4/H2, 750oC, 1.5 h). Additionally, the associated physicochemical properties were strongly responsible for viscosity reduction from 250.25 mPas to 78.30 mPas. Similarly, resins and asphaltenes were successfully ruptured into lighter saturates and aromatics during the process. Thus, the Mo2C/S-ZrO2 system has good potential for this application.

Importance of Clay Swelling on the Efficacy of Cyclic Steam Stimulation in the East Moldabek Formation in Kazakhstan

Both steam and hot water flooding of high-viscosity oils in the presence of swelling clays are difficult methods for producing oil efficiently because of potential formation permeability reduction. This paper pertains to heavy oil recovery from the East Moldabek formation where the oil API gravity is about 22 and is inundated with swelling clays. To achieve this, we used the IntersectTM reservoir simulator to compare oil recovery economics using both hot water and steam injection as a function of steam cycle duration, temperature, and steam dryness. We also studied clay swelling in the East Moldabek formation where clay poses a significant challenge due to its impact on permeability reduction. In this research, we developed an equation based on experimental data to establish a relationship between water mineralization and permeability in the East Moldabek formation. The equation provides valuable insight on how to mitigate clay swelling which is crucial for enhancing oil recovery efficiency—especially in sandstone reservoirs. Our modeling studies provide the recovery efficiencies for salinities of the hot water EOR versus cyclic steam EOR methods in a formation containing swelling clays. Specifically, the reduction in formation permeability as a function of the distilled water fraction is the controlling parameter in hot water or steam flooding—when the formation water mixture becomes less saline, oil recovery decreases. Our research shows that clay swelling can significantly impact cyclic steam stimulation outcomes, potentially reducing its effectiveness, while hot water flooding may offer a more cost-effective and operationally feasible solution in formations where clay swelling is a concern. Economic analysis reveals the potential for achieving an optimal favorable condition for hot water injection. Therefore, this paper provides a guideline on how to conduct thermal oil recovery for heavy oils in fields with high clay content such as the East Moldabek deposit.

Transforming Petrochemical Processes: Cutting-Edge Advances in Kaolin Catalyst Fabrication

The depletion of conventional light petroleum reserves has intensified the search for alternative sources, notably, low-quality heavy oils and byproducts from heavy crude processing, to meet the global demand for fuels, energy, and petrochemicals. Heavy crude oil (HO) and extra heavy crude oil (EHO) represent nearly 70% of the world’s reserves but require extensive upgrading to satisfy refining and petrochemical specifications. Their high asphaltene content results in elevated viscosity and reduced API gravity, posing significant challenges in extraction, transportation, and refining. Advanced catalytic approaches are crucial for efficient asphaltene removal and the conversion of heavy feedstocks into valuable light fractions. Kaolin, an aluminosilicate mineral, has emerged as a key precursor for zeolite synthesis and a promising catalyst in upgrading processes. This article provides a comprehensive exploration of kaolin’s geological origins, chemical properties, and structural characteristics, as well as the various modification techniques designed to improve its catalytic performance. Special focus is given to its application in the transformation of heavy crudes, particularly in facilitating asphaltene breakdown and enhancing light distillate yields. Finally, future research avenues and potential developments in kaolin-based catalysis are discussed, emphasizing its vital role in addressing the technological challenges linked to the growing reliance on heavier crude resources.

Production and Characterization of Duckweed Bio-Oil via Pyrolysis: A Renewable Alternative to Fossil Fuels

Duckweed bio-oil has gained significant interest due to its exceptional benefits in raw material utilization and eco-friendliness. Research on microalgae cultivation and pyrolysis production lines is vital to enhancing the efficiency of duckweed biomass consumption for renewable energy. In this work, the pyrolysis process was applied to create bio-oil from duckweed. A fixed-bed reactor was connected to condensers, with heat delivered via a gas burner, and a thermocouple used to measure the reactor’s temperature. A stopwatch was used to track the elapsed time until the last drop of product was visible from the system. The results show that both duckweed oils are heavy oils, with an API gravity of 8.73, densities of 1.079 g/cm³ and 1.006 g/cm³, high viscosities of 8.24 mm²/s and 9.32 mm²/s, respectively, a specific gravity of 1.01, a high flash point of 96 °C, and a pour point of 16 °C. The research confirms that duckweed biomass can be pyrolyzed to produce bio-oil. GC/MS analysis was conducted on the generated bio-oil, revealing the presence of multiple polyaromatic hydrocarbons. Consequently, carbon chain elements (C8-C28) are present in duckweed bio-oils. According to the findings, duckweed-derived bio-oil shows great promise as a fossil fuel alternative. This study suggests that, since microalgae have the potential to be a viable replacement for fossil fuels, efforts should be made to scale up microalgae production from the laboratory to industrial levels.

A novel mathematical model for modeling viscosity and temperature relationship for dead oils

Viscosity is crucial in subsurface and surface transport, used in engineering domains like heat transfer and pipeline design. However, measurements are limited, necessitating predictive viscosity relationships. Existing models lack precision or pertain to limited fluids, and accurately forecasting dead oil viscosity remains challenging due to errors. The study presents a mathematical algorithm to accurately estimate viscosity values in hydrocarbon fluids. It uses a robust non-linear regression technique to establish a reliable relationship between fluid viscosity and temperature within a specific temperature range. The algorithm is applied to extra-heavy to light crude oil samples from Iranian oilfields, revealing viscosity values ranging from 0.29 cp to 5328.74 cp within a dataset of 243 viscosity data points. After modeling each of these five fluids, the highest values obtained for the maximum absolute error and relative error are related to the fluid with an API gravity of 12.92. The maximum absolute error and relative error for this fluid sample are 1.25 cp and 6.04%, respectively. The algorithm offers acceptable precision in outcome models, even with limited training data, demonstrating its effectiveness in training models with less than 30% of available data. Moreover, these models end up with a near-unity coefficient of determination in testing data, reaffirming their proficiency at reflecting empirical data with remarkable accuracy.

Upgrading vacuum residue in a supercritical CO2 environment with polypropylene and steam: Insights into products distribution and characterization of liquid products

The pyrolysis of vacuum residue (VR) using polypropylene (PP) under supercritical carbon dioxide (scCO2) conditions represents a novel approach to converting this abundant and difficult-to-process feedstock into lighter liquid products. In this paper, a set of experiments was performed to analyze the impact of scCO2, PP and steam on the yields of pyrolysis products (i.e., liquid, gas and coke) and characteristics of the liquid fractions. The findings indicated notable improvements when scCO2 was used instead of subcritical CO2 in the pyrolysis of VR with PP. These included decreased viscosity and improved API gravity, alongside increased maltene yield and reduced coke yield. Furthermore, the inclusion of PP markedly elevated the quality of the obtained liquid, whereas steam + scCO2 primarily affected the product distribution by raising the yield of coke and gas fractions. VR pyrolysis under scCO2 conditions at 380 °C, 8 MPa, PP/VR ratio of 0.23 for 60 min in a batch system, without the use of catalyst, resulted in the highest liquid yield of 83.7 ± 1.9 wt%, and minimum coke yield of 9.8 ± 1.3 wt%. Under these conditions, the upgraded liquid consisted of 75.2 wt% light and middle distillates with boiling points below 350 °C. Additionally, the proportion of oxygenates in the pyrolysis oil reduced by 60.5 %, improving its heating value. Moreover, adding PP to the upgrading process resulted in a higher proportion of isoparaffins, cycloparaffins, and aromatics, coupled with a decrease in olefins, aligning the liquid specifications more closely with fuel standards.

Comparative Analysis of Biodiesel Produced from Blends of Palm Kernel Shell and Cocoa Pods Oils with Conventional Diesel Fuel: Characterizations, FTIR, GC-MS, XRD and SEM Analysis of the Nano Catalyst

The uncertainty of predicting the conditions of bio oils for the production of quality biofuels and reusability of catalyst, saving cost of production and time, make characterization of the oils/catalyst imperative. Characterization of bio oils, extracted from palm kernel shell and cocoa pods, the blends, catalyst and biodiesel produced therefrom is investigated. A maximum biodiesel yield of 76.05% was obtained at optimal conditions. Titanuim oxide used proved to be efficient catalyst for converting the oil blends to biodiesel. The established results obtained show kinematic viscosity of 5.65 – 7.78 mm2s-1 @ 40 oC, density of 0.8428 – 0.8642 kg/m3, cloud point of 4.48 – 6.48 oC, fire point of 108 – 150 oC, cetane index of 37.78 – 30.13, acid value of mg KOH/g, API gravity of 32.89 – 29, anicidine point of 50 – 46 oC etc. All the values fell within the recommended ASTM and EN standards. The GC-MS, XRD, EDX, SEM, and FTIR analyses carried out to evaluate the quality of the sample with respect to deterioration, gave an ester percentage of 99.9% for the bio-oil and biodiesel, which is within the minimum standard range of not less than 96.5% recommended. The GC-MS of the blended oil shows that the most prevalent fatty acids identified amongst 13 other distinct compounds were methyl linolenate, methyl palmitate, methyl oleate and methyl eicosadinoate with percentage concentrations of 63.03, 26.9, 8.1 and 2% respectively. The XRD analysis confirmed the titanium oxide anatase structure with a peak of 25.4 degrees. The SEM analysis shows high porosity with high specific surface area of the catalyst at magnification of 80 – 269μm; and the FTIR analysis revealed that the functional groups for the bio-oil and blended biodiesel were in range.

Development of Nanofluid-Based Solvent as a Hybrid Technology for In-Situ Heavy Oil Upgrading During Cyclic Steam Stimulation Applications.

This paper evaluates solvent-based nanofluids for in situ heavy oil upgrading during cyclic steam stimulation (CSS) applications. The study includes a comprehensive analysis of the properties and characteristics of nanofluids, as well as their performance in in situ upgrading and oil recovery. The evaluation includes laboratory experiments to investigate the effects of the nanoparticle's chemical nature, asphaltene adsorption and gasification, heavy oil recovery, and quality upgrading. The results show that alumina-based nanoparticles have a higher efficiency in asphaltene adsorption and catalytic decomposition at low temperatures (<250 °C) than ceria and silica nanoparticles. Specifically, alumina nanoparticles achieved asphaltene adsorption of 48 mg g-1, while ceria adsorbed 42 mg g-1. Alumina and ceria required around 90 and 135 min for 100% asphaltene conversion. Nanofluids were designed by varying nanoparticle and surfactant concentrations dispersed in naphtha, obtaining that the nanofluid containing 0.05 wt % of nanoparticles and 0.05 wt % of surfactant presents the highest yield in increasing API gravity by 5° and reducing oil viscosity by 90% in thermal experiments. Finally, the nanofluid was evaluated under dynamic conditions. The results show that nanofluid-based solvents can significantly improve the recovery and upgrading of heavy oil during CSS applications. When the steam injection technology was assisted by naphtha and nanofluid, 64% and 75% of the original oil in place were recovered, respectively. The effluents obtained in each stage presented lower API gravity values and higher viscosities for those obtained without a nanofluid. Specifically, the API gravity of the recovered oil rose from 11.9° to 34°, and the viscosity decreased to below 100 cP. The paper concludes by highlighting the potential of nanofluid-based solvents as a promising technology for heavy oil recovery and upgrading in the future.

RESPONSE SURFACE METHODOLOGY OPTIMIZATION AND UPGRADING OF AGBABU BITUMEN IN THE PRESENCE OF RICE HUSKS

With the current global trend in energy demand due to the increase in human population and technological inclination in carrying out day to day activities, the conventional crude oil is fast depleting and thus an alternative source of energy is needed for sustainability for the fuel/energy supply. Natural bitumen upgrading could serve as an alternative source for the future fuel supply but the process of upgrading the bitumen needs to be optimized to obtain the best conditions at which the bitumen upgrading process would effectively take place which brought about this study. In this study research work, optimization of Agbabu bitumen in the presence of rice husks using response surface methodology (RSM) was carried out to determine the optimal conditions at which the bitumen could be upgraded. Box-Behnken Designed experiment (BBD) was used as the template to design the experiment where the chosen variable factors were temperature, residence time and rice husks at a range or level of (300 – 350 oC), (30 – 180 min) and (0.6 – 1.0 wt.%) for each of the variable factor respectively and the chosen responses were viscosity, API gravity, residue yield and light oil yield. The Agbabu bitumen was characterized by viscosity at 70 oC to be 86.78 Pa.s, density at 60 oC to be 1.0153 Kg/L, H/C ratio 1.19:1 and API gravity of 7.87 o etc. The optimum conditions at which the Agbabu bitumen could be upgraded for maximum yield of light oil was found to be (temperature 345.716 oC, residence time 30.0 min, and rice husks 1.0 wt.%) at response value of viscosity 8.340 Pa.s, API gravity 24.520 o, residue yield 22.39 w/w% and light oil yield 50.064 w/w%. The light oil yield for the upgraded Agbabu bitumen at the optimum conditions had a desirability of 0.688989, amounting to 68.4% yield. The overall desirability for the whole upgrading process was 0.909415 at the optimum conditions. Thus, indicating an acceptable optimization and upgrading process for Agbabu bitumen.

Sulfured FeMo carbides and nitrides catalysts upgrade extra heavy crude oil quality

In the context of the energy transition scenario, effective sulfur management is crucial. Enhancing the quality of extra heavy crude oil (EHCO) through catalytic processes, specifically hydrotreatment, is essential for reducing pollutant emissions like SOx into the atmosphere. Traditional hydrotreatment, utilizing MoS2-based catalysts typically on Al2O3 support, faces challenges with EHCO due to its elevated S and N content, which hampers catalyst efficiency. Metal carbides and nitrides exhibit promising electronic structures that confer resistance to deactivation in the presence of heteroatoms. This study compares the catalytic performances of Fe-promoted Mo sulfides, carbides, and nitrides (FeMoS(C,N)) in the thiophene hydrodesulfurization (HDS) reaction, serving as a model molecule for sulfur removal. Subsequently, we investigate the upgrading of a Venezuelan EHCO in terms of pollutant reduction, API gravity, and feedstock aromaticity. Catalysts were prepared from oxide precursors, varying the (Fe/(Fe+Mo)) atomic ratios (x = 0.00, 0.10, 0.33, 0.50, and 1.00), employing a temperature-programmed reaction protocol. Catalytic upgrading of EHCO was conducted in a stirred batch reactor, and the results were compared with a commercial CoMo-based catalyst. FeMoC(N) outperformed the commercial catalyst in sulfur removal. The elemental composition and nitrogen content of the feed remained constant; however, the sulfur content of asphaltenes decreased. Furthermore, the API gravity of crude oil increased when employing FeMoS and FeMoN catalysts, except with FeMoC, possibly linked to dealkylation reactions and the enrichment of lighter fractions with alkanes. FeMoN increased asphaltene aromaticity, while FeMoC decreased it. These results highlight the promise of FeMoC(N) as catalysts for HDS and upgrading heavy feedstocks.

Processing and Recovery of Heavy Crude Oil Using an HPA-Ni Catalyst and Natural Gas.

To maintain economic profitability and stabilize fuel prices, refineries actively explore alternatives for efficiently processing (extra) heavy crude oils. These oils are challenging to process due to their complex composition, which includes significant quantities of asphaltenes, resins, and sulfur and nitrogen heteroatoms. A critical initial step in upgrading these oils is the hydrogenation of polyaromatic compounds, requiring substantial hydrogen sources. Methane from natural gas streams is known to act as an effective hydrogen donor. This study investigates the use of a heteropolyacid (HPA) catalyst modified with nickel and methane to enhance the quality of heavy crude oil with an initial 8.0°API (at 15.5 °C) and 2200 cSt viscosity (at 37.5 °C). After treatment in a batch reactor at 380 °C and 4.4 MPa for 2 h, the oil properties markedly improved: API gravity increased from 8.0 to 16.0 (at 15.5 °C), and kinematic viscosity reduced from 2200 to 125 cSt (at 37.5 °C). Additionally, there was a significant decrease in asphaltenes (from 38.7 to 16.4% by weight), sulfur (from 5.9 to 4.0% by weight), and nitrogen (from 971 to 695 ppm). This was accompanied by an increase in the volume of light distillates from 1.3 to 4.9%, and middle distillates from 8.8 to 21.0%. These results suggest that nickel-modified HPA catalysts, combined with methane as a hydrogen donor, are a promising option for upgrading heavy crude oils.

Downhole Hydrogen-Generation System Stimulates Challenging Formations in Kuwait

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper OTC 34832, “Successful Trial of Innovative Downhole Hydrogen-Generator System To Stimulate Hard-to-Recover Formations: First in Onshore Kuwait,” by Mustafa Al-Hussaini, Hamad S. Al-Rashedi, and Nada Al-Saleh, SPE, Kuwait Oil Company, et al. The paper has not been peer reviewed. Copyright 2024 Offshore Technology Conference. _ The objective of the pilot trial described in the complete paper was to provide an economic solution to develop tight and hard-to-recover formations within the operator’s fields. These assets represent a major challenge because of their low recovery factor (1–3%), the high cost of available conventional stimulation technologies, low revenue, and inability to sustain production rates. Introduction To establish an integrated stimulation solution for tight and heavy oil formations, the concept of using active single-atom hydrogen power to enhance near-wellbore permeability was evolved. This technology is based on downhole hydrogen generation from an in-situ exothermic multistage chemical reaction between two unique hydroreacting agents (HRAs). This reaction generates a huge amount of thermal energy, active hydrogen, and other hot active gases and acid vapors. The selection of HRA compounds, and their amount and concentration, is customized for each field. Development of Business Cases West Kuwait (WK) Business Case. The M formation in the WK region is a carbonate, multifractured tight reservoir that had been producing for years but had begun experiencing a low recovery factor. Some of its wells had low-productivity issues related to tight formation characteristics and low pressure. Production could not be sustained for long periods of time even after conventional acid stimulation. The reservoir featured a carbonate reservoir thickness of 300 ft, with 70% of oil in place at the top section. The reservoir is classified as tight (less than 0.1–10 md average permeability and 10–25% porosity), with 10 fractured multilayers. Only 1–3% recovery could be achieved despite many vertical, horizontal, and multilateral wells having been drilled in the M formation. Oil is considered nonviscous (28 cp, 21 °API). Current stimulation approaches included conventional acid stimulation, which elicited a poor response, and multistage fracturing, which encountered mixed results at best. North Kuwait (NK) Business Case. The tight T formation in this region featured poor reservoir connectivity. Minimal aquifer support led to a rapid decline in reservoir pressure. In general, low mobility of oil, poor API gravity, and low permeability were the main obstacles in draining oil from the T formation, in addition to reservoir heterogeneities such as facies distribution, fracture patterns, and pressure regimes. The formation consisted of tight limestone deposited on a carbonate ramp. The reservoir is divided into three main stratigraphic units (Upper, of approximately 110 ft; Middle, of approximately 60 ft; and Lower, of approximately 16 ft). The reservoir exhibits porosity of approximately 14% and permeability of approximately 14 md and is filled with relatively-low-API hydrocarbon (19–22 °API).

CFD simulation of the surface pumping of heavy crude oil in eastern Ecuador

The research addresses the study of heat exchange between heavy crude oil and the environment during surface pumping, specifically of a crude oil with an API gravity of 17.5, under the particular atmospheric conditions of Eastern Ecuador. The main objective of the study is to evaluate the temperature loss in a 50-meter segment of SCH-80 pipe, with a diameter of 4 inches, used for the transportation of heavy crude. This aims to understand how heavy crude loses temperature and to determine the convective coefficient, knowing that the heat loss from the fluid to the environment occurs mainly by convection. This is to determine what the temperature losses will be in longer pipe sections. For this purpose, a methodology using computational fluid dynamics (CFD) simulation was employed, a key tool for predicting the thermal behavior of crude in interaction with the environment. It was determined that the convective coefficient is 52 W/m2.K, and there is a temperature loss of 3.2 K in the 50-meter section. With this data, future research could evaluate potential heating technologies that facilitate the transport of heavy crude oil. This approach would allow for exploring innovative solutions to improve efficiency and effectiveness in managing heavy crude, facing one of the main challenges in its transport: managing its high viscosity