No abstract

Venezuela has a big potential for the generation of energy from renewable resources (e.g. water, wind, solar, biomass, etc.), geothermal reservoirs, and from its huge reserves of hydrocarbons in conventional and highly viscous oil reservoirs. Due to the great efforts being made by several countries worldwide to reduce the emission of greenhouse gases and global warming, the production of clean fuels (e.g. hydrogen) with low-carbon content to reach net zero is a great challenge, but yet of keen interest, for the Venezuelan industry. The objective of this article is to review most of the relevant techniques and propose potential scenarios/technologies for the reduction of greenhouse gases and the generation of clean fuels from reservoirs in Venezuela. The methodologies that have been envisaged in various industry and research segments in hydrogen and low-carbon fuels include, but are not limited to, steam reforming, pyrolysis, gasification, combustion, CCUS, oil, etc. A detailed description of each technology along with relevant scenarios and main conclusions are given. Also, the processes and procedures undertaken in these clean fuel generation technologies are addressed in this article to cover advances made in various industry disciplines and to highlight potential future breakthroughs. For the Venezuelan particular case, the following major scenarios are predicted for the generation of clean fossil fuels: 1) production of hydrogen from natural gas with CO2 capture and storage in aquifers or in depleted hydrocarbon reservoirs, 2) use of the produced or sequestered CO2 for Enhanced Oil Recovery (EOR) in reservoirs with production decline, 3) production of clean fossil fuels from upgrading techniques and applicable EOR methods (e.g. in-situ combustion), 4) perspectives for the generation of hydrogen from renewable resources, among others. The application of each of these technologies/scenarios is closely linked to underlying technical feasibility and economics. This article presents an approach to producing hydrogen and low-carbon fossil fuels, upstream and downstream, with CO2 capture and storage. The sequestered CO2 could then be used in miscible gas floods in conventional oil reservoirs for improved recovery, despite the possible effect on asphaltene precipitation and related flow assurance issues. Reconversion schemes for existing flow lines and new infrastructure designs would be necessary for the application of hydrogen and low-carbon fuel technologies, which would involve significant investments in terms of OPEX and CAPEX.

The formation of emulsions during the production of highly viscous crude oils is one of the biggest issues observed both in cold production and after the application of IOR methods in Venezuelan heavy and extraheavy oil reservoirs, with impact on the lifting of crude oils, separation of phases, fouling, production costs, etc. For the cold production case, the presence of water with strong compositional and salinity variation, coupled with the presence of gas in the case of foamy oil, could generate very stable oil-water and gas-oil emulsions; hence complicating the phenomena after the application of thermal or chemical IOR methods. This article presents a review of: 1) different types of emulsions found in cold production as well as thermal and chemical IOR methods, 2) factors that affect the stability of the emulsions (compositions of crude oil and formation and injection waters, type of injection fluid, temperature, etc.), 3) fluid characterization methods (gravimetric method, droplet size distribution, centrifugation, rheology, etc.), 4) recommended demulsifiers based on laboratory, and field experiences in Venezuela and internationally. These criteria will be reviewed in detail, establishing the main insights associated with the emulsion formation, providing related conclusions and perspectives for treatment and prevention measures. Based on the results of this review, it can be highlighted that the presence of resins and asphaltenes in the crude oil has a fundamental role in the stability of the emulsions found during cold production in the Orinoco Oil Belt and that the composition of the formation water might increase the stability of the emulsions (Mg2+ and Ca2+). The application of thermal as well as diluent injection methods generates emulsions that involve precipitation of asphaltenes, which together with sand production in the process, leads to making phase separation processes more complex. Furthermore, the application of chemical methods could cause phase trapping (for the surfactant case) with impact on chemical losses, and water- in-oil emulsion with high viscosity after the addition of alkali in lab experiments. A worldwide review of field and laboratory remediation methods indicates that possible emulsion treatments include the use of silica nanoparticles, polyglycerol fumarate ester, heavy aromatic naphtha, electrical heaters, among others. This article presents the main insights related to the generation of emulsions in Venezuela and for developing strategies for emulsions breakers adapted to each IOR process. It also covers the effect of water chemistry, oil composition and type of IOR/EOR process on the characteristics of emulsion and emulsion stability, and consequently the impact on the technical and economic criteria of the process.

A model for single-phase fluid flow in tight UCRs was previously produced by modifying the flow Forchheimer’s equation. The new modification addresses the fluid transport phenomena into three scales incorporating a diffusion term. In this study, a new liner model, numerically solved, has been developed and deployed for a gas huff and puff project. The new model has been numerically validated and verified using synthetic data and huff and puff case study. Ideally, the new model suits fluid flow in tight UCRs. The modified Forchheimer’s model presented is solved using the MATLAB numerical method for linear multiphase flow. For the huff & puff case, very simple profiles and flow dynamics of the main flow parameters have been established and a thorough parametric analysis and verifications were performed. It has been observed that the diffusion system becomes more prominent in regulating flow velocity with low permeability of the formation rock and low viscosity of the flowing fluid. The findings indicate a behavioral alignment with a previous hypothesis that matches actual reservoir behavior.

Although gas desorption is a known phenomenon, modeling fluid flow in tight gas reservoirs often ignores the governing desorption effect, assuming that viscous transport is the predominant controller, resulting in an erroneous prediction of mass transport and fluid flow calculations. Thus, developing a new model accommodating all the major contributing forces in such a medium is essential. This work introduces a new comprehensive flow model suitable for tight unconventional reservoirs, including viscous, inertia, diffusion, and sorption forces, to account for fluid transport. Based on Langmuir law and Knudsen diffusion effect, three models were generated and compared with different known models using synthetic data. The model was solved and analyzed for different scenario cases, and parametric studies were conducted to evaluate the desorption effect on different reservoir types using MATLAB. Results show that the contribution of the sorption mechanism to the flow increases with the reducing permeability of the medium and lower viscosity of the flowing fluid and an additional pressure drop up to 10 psi was quantified.