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Abstract Steam injection has been recognized as an efficient process for recovering hydrocarbons from heavy oil and bitumen reservoirs. However, it is now well known that the steam injection induces chemical reactions within the reservoir, called aquathermolysis and yielding acid gases. Hydrogen sulfide (H2S) being highly toxic and highly corrosive, even at low concentrations, it is of major importance to forecast H2S production. However, until now, there are only very few publications relating reservoir simulations of steam injection processes accounting for thermal and compositional effects in a chemically reactive context. The proposed paper relates a work focused on H2S production forecast during a SAGD process from aquathermolysis experimental results and simulation. After a description of the aquathermolysis experiments, the simplified sulfur-based kinetic model deduced from the experimental results is presented. This sulfur-based kinetic model has been used to build a thermo-kinetic component-based model usable in a compositional and thermal reservoir simulation. A simulation of the experimental aquathermolysis reactor being run for validating the thermo-kinetic model, the simulation results of H2S production and oil SARA composition versus time are shown to be in good agreement with the experimental results. Then, the thermo-kinetic modeling has been input in a cross-section model designed for simulating a SAGD process. The H2S production results were found to be consistent with published field data. The work related in the paper contributes to provide a new insight to the simulation of H2S production by aquathermolysis, through the presentation of a simplified modeling of the aquathermolysis reactions, and the description of a methodology for building an EOS (Equation Of State) model compatible with the reactive model. The followed approach is shown to be usable for forecasting H2S production due to an aquathermolysis phenomenon during a steam injection process.
- North America > United States (1.00)
- North America > Canada > Alberta (0.94)
- Asia (0.67)
- Research Report > New Finding (0.68)
- Research Report > Experimental Study (0.46)
- Geology > Petroleum Play Type > Unconventional Play > Heavy Oil Play (1.00)
- Geology > Geological Subdiscipline > Geochemistry (0.93)
- North America > Canada > Alberta > Fisher Field > Aec Burnt Lake 11-12-68-4 Well (0.99)
- South America > Venezuela > Orinoco Oil Belt > Eastern Venezuela Basin > Junin Block > Junin Field (0.98)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)
Reservoir Simulation of Hydrogen Sulfide Production During a Steam-Assisted-Gravity-Drainage Process by Use of a New Sulfur-Based Compositional Kinetic Model
Ayache, Simon V. (IFP Energies Nouvelles) | Lamoureux-Var, Violaine (IFP Energies Nouvelles) | Michel, Pauline (IFP Energies Nouvelles) | Preux, Christophe (IFP Energies Nouvelles)
Summary Steam injection is commonly used as a thermal enhanced-oil-recovery (EOR) method because of its efficiency for recovering hydrocarbons, especially from heavy-oil and bitumen reservoirs. Reservoir models simulating this process describe the thermal effect of the steam injection, but generally neglect the chemical reactions induced by the steam injection and occurring in the reservoir. In particular, these reactions can lead to the generation and production of the highly toxic and corrosive acid gas hydrogen sulfide (H2S). The overall objective of this paper is to quantitatively describe the chemical aquathermolysis reactions that occur in oil-sands reservoirs undergoing steam injections and to provide oil companies with a numerical model for reservoir simulators to forecast the H2S-production risks. For that purpose, a new sulfur-based compositional kinetic model has been developed to reproduce the aquathermolysis reactions in the context of reservoir modeling. It is derived from results gathered on an Athabasca oil sand from previous laboratory aquathermolysis experiments. In particular, the proposed reactions model accounts for the formation of H2S issued from sulfur-rich heavy oils or bitumen, and predicts the modification of the resulting oil saturate, aromatic, resin, and asphaltene (SARA) composition vs. time. One strength of this model is that it is easily calibrated against laboratory-scale experiments conducted on an oil-sand sample. Another strength is that its calibration is performed while respecting the constraints imposed by the experimental data and the theoretical principles. In addition, in this study no calibration was needed at reservoir scale against field-production data. In the paper, the model is first validated with laboratory-scale simulations. The thermokinetic modeling is then coupled with a 2D reservoir simulation of a generic steam-assisted gravity drainage (SAGD) process applied on a generic Athabasca oil-sand reservoir. This formulation allows investigating the H2S generation at reservoir scale and quantifying its production. The H2S- to bitumen-production ratio against time computed by the reservoir simulation is found to be consistent with production data from SAGD operations in Athabasca, endorsing the proposed methodology.
- Europe (1.00)
- North America > Canada > Alberta > Athabasca Oil Sands (0.44)
- North America > Canada > Alberta > Fisher Field > Aec Burnt Lake 11-12-68-4 Well (0.99)
- South America > Venezuela > Orinoco Oil Belt > Eastern Venezuela Basin > Junin Block > Junin Field (0.98)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- (2 more...)
Abstract Nowadays steam injection is commonly used as a thermal EOR method due to its efficiency for recovering hydrocarbons from heavy oils and bitumen. Reservoir models simulating this process describe the thermal effect of the steam injection, but generally neglect the chemical reactions induced by the steam injection. These reactions are called aquathermolysis and have been previously investigated through laboratory experiments. Based on these experimental results, this paper proposes a new compositional kinetic model to reproduce these reactions in the context of reservoir modeling. In particular the proposed reactions model accounts for the formation of the highly toxic and corrosive acid gas H2S in the presence of sulfur-rich heavy oil and predicts the modification of the oil SARA composition versus time that results from the aquathermolysis reactions. The overall objective of this paper is to understand the aquathermolysis reactions in reservoir undergoing steam injections and to provide the Oil companies with a numerical model for reservoir simulators that forecasts H2S production risks. The new Sulfur-Based-Compositional Kinetic Model is firstly presented and then validated in the context of laboratory-scale experiments. Its H2S and SARA composition predictions are based on a new simplified reactive scheme of 5 reactions coupled to a compositional and thermal reservoir simulation with no mass transfer (0D). Finally the thermo-kinetic modeling is coupled with a 2D reservoir simulation of a SAGD process for a generic Athabasca oil sand. The H2S to SARA (bitumen) production ratio against time computed by the reservoir simulation is found to be consistent with data from a SAGD process in Athabasca, which validates the modeling approach followed.
- North America > Canada > Alberta > Fisher Field > Aec Burnt Lake 11-12-68-4 Well (0.99)
- South America > Venezuela > Orinoco Oil Belt > Eastern Venezuela Basin > Junin Block > Junin Field (0.98)
Numerical Prediction of H2S Production in SAGD: Compositional Thermal-Reactive Reservoir Simulations
Ayache, Simon V. (IFP Energies Nouvelles) | Preux, Christophe (IFP Energies Nouvelles) | Younes, Nizar (IFP Energies Nouvelles) | Michel, Pauline (IFP Energies Nouvelles) | Lamoureux-Var, Violaine (IFP Energies Nouvelles)
Abstract Nowadays EOR methods such as thermal techniques are widely used to recover the viscous hydrocarbons from heavy oils and bitumen reservoirs. One of the thermal methods is the Steam-Assisted Gravity Drainage (also called SAGD), which consists in injecting steam into the reservoir to melt the viscous oil and allow its mobility. The melted oil falls by gravity to the production well. The injected hot steam, once it reaches the heavy oils/bitumen, induces chemical reactions called aquathermolysis. These reactions generate gases such as hydrogen sulfide (H2S) or carbon dioxide (CO2). The H2S is known to be highly toxic and corrosive. Hence it needs to be given a particular attention when it is produced at the surface. Reservoir models have been built to simulate thermal effects during a SAGD process but only few publications in the literature deal with the aquathermolysis reactions occurring in reservoirs where steam is injected. This paper focuses on building a reservoir simulation model to forecast the H2S production. The example of the Hangingstone heavy oil field in Canada has been chosen. This simulation model is based on a compositional PVT description for heavy oil/bitumen and on a recently developed sulfur-based compositional kinetic model to describe the aquathermolysis reactions. The description of the heaviest components found in heavy oils/bitumen is made through a SARA decomposition. The reactive model that describes the aquathermolysis reactions is firstly presented. Then a section of this paper is dedicated to the building of a PVT model for heavy oil. Another chapter presents the 2D heterogeneous reservoir models used for the simulations. Finally the simulations results are presented. A sensitivity analysis has been performed to investigate the effect of the rock conductivity and the pressure/temperature of the injected steam on the H2S production. The different simulations have given consistent results with production data in terms of H2S production at surface. This shows that both the fluid description and the aquathermolysis kinetic model used in the study are relevant for the prediction of H2S production in the context of steam injection.
Tailor-Made Workflow to Understand and Forecast H2S Production Risks in Thermal Projects
Ayache, Simon Victor (IFP Energies Nouvelles) | Gasser-Dorado, Julien (IFP Energies Nouvelles) | Michel, Pauline (IFP Energies Nouvelles) | Preux, Christophe (IFP Energies Nouvelles) | Lamoureux-Var, Violaine (IFP Energies Nouvelles)
Abstract In-situ extraction of heavy sulfured oil based on steam injection comes with a high level of risk in terms of H2S production, resulting from aquathermolysis reactions. This could lead to on-site living being casualties, environment damage, surface facilities and wells corrosion. Also, there is a strong need to understand aquathermolysis reactions and to forecast acid gases generation in such context. For that aim a tailor-made workflow was developed to estimate H2S concentration at the well-head. To meet these challenges, a 3-steps approach combining laboratory studies and numerical predictions has been developed. It firstly consists in a fast preliminary assessment of the highest H2S risk areas, based on the measurements of sulfur characteristics of reservoir core samples using our Rock-Eval Sulfur set-up. Then aquathermolysis experiments from the previously selected core samples are conducted in order to calibrate the compositional chemical model of the reservoir simulator. The latter is eventually used to carry out thermal compositional reactive simulations at field scale. The reservoir simulator allows simulations of SAGD processes and handles H2S distribution over oil/water/gas phases and its migration in these phases. Simulation results show that acid gases are generated within the steam chamber, before they accumulate at the chamber edges where they dissolve in the water and oil phases. This contributes to reduce viscosity, allowing the oil to flow along the steam chamber edges before it has reached the steam temperature. Therefore the H2S produced at surface is mainly carried towards the wells by water and to a lesser extent oil. This flowing oil has not reacted with the steam: its composition is close to the initial reservoir oil but enriched with dissolved gases. The steam chamber shape, the temperature distribution and the H2S produced at surface are strongly modified when heterogeneities are introduced in the reservoir model. Synthetic cases allow a deeper understanding of the effects of heterogeneities. Vertical permeability is thus found to be a key factor of H2S production variations. When steam reaches a lower permeability lithology, a delayed rise in H2S production at wellhead is observed as aquathermolysis reactions rates increase. Finally Foam Assisted-SAGD has been considered. While the foam improves the Steam-Oil ratio, no clear improvement was observed regarding the H2S production.
- North America > Canada (0.46)
- North America > United States (0.46)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Thermal methods (1.00)
- Production and Well Operations > Production Chemistry, Metallurgy and Biology > Corrosion inhibition and management (including H2S and CO2) (1.00)
- Health, Safety, Environment & Sustainability > Health > Noise, chemicals, and other workplace hazards (1.00)