Identification of SSC (Sulfide Stress Cracking)-Susceptible Wells and Risk Prediction

Chakrabarty, T.; Smith, Richard James

doi:10.2118/160489-ms

Cited by 9 publications

(4 citation statements)

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“…They modify the SARA compositions of the oil and produce the highly toxic and corrosive acid gas H 2 S in the presence of sulfur-rich heavy oil (Hyne et al 1984;Clark et al 1990;Chen et al 1991;Hoffman et al 1995;Hongfu et al 2002;Lamoureux-Var and Lorant 2005b;Uzcategui et al 2011;Lamoureux-Var et al 2011). Hence the H 2 S production observed during steam injection processes, as reported by Thimm (2001Thimm ( , 2008 and Chakrabarty and Smith (2012), is clearly a consequence of aquathermolysis reactions occurring in the reservoir. Predicting the H2S production against time at surface conditions is therefore very important for operators in order to size accordingly their H 2 S removal facilities.…”

Section: Introductionmentioning

confidence: 65%

Reservoir Simulation of H2S Production During a SAGD Process Using a New Sulfur-Based-Compositional Kinetic Model

et al. 2015

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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 H 2 S 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 H 2 S production risks.The new Sulfur-Based-Compositional Kinetic Model is firstly presented and then validated in the context of laboratory-scale experiments. Its H 2 S 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 H 2 S 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.

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Section: Introductionmentioning

confidence: 65%

Reservoir Simulation of H2S Production During a SAGD Process Using a New Sulfur-Based-Compositional Kinetic Model

et al. 2015

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“…Numerous aquathermolysis experimental simulations, performed at temperatures relevant for steam injection processes, have shown that oil composition is modified and H 2 S is yielded (Hyne et al, 1984;Clark et al, 1990;Chen et al, 1991;Hoffman et al, 1995;Hongfu et al, 2002;Lamoureux-Var and Lorant, 2005b;Uzcategui et al, 2011;Lamoureux-Var et al, 2011). Hence, H 2 S production during steam injection processes, -as reported by Thimm (2001) and Chakrabarty and Smith (2012) -, is clearly a consequence of aquathermolysis reactions occurring in the reservoir. We give here only a brief description of the aquathermolysis experiments which have been carried out for deriving sulfur-based kinetic model, more details being given in a next SPE paper more focused on the geochemical aspects (Lamoureux-Var and Barroux, 2013).…”

Section: Aquathermolysis Experiments and Related Resultsmentioning

confidence: 75%

Forecasting of H2S Production due to Aquathermolysis Reactions

2013

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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 (H 2 S) being highly toxic and highly corrosive, even at low concentrations, it is of major importance to forecast H 2 S 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 H 2 S 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 H 2 S 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 H 2 S 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 H 2 S 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 H 2 S production due to an aquathermolysis phenomenon during a steam injection process.

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“…Enhanced oil recovery by steam injection in oil sands induces chemical reactions within the reservoir, called aquathermolysis, which can lead to H 2 S production (Hyne et al, 1984;Thimm, 2001;Chakrabarty and Smith, 2012). To quantitatively forecast this risk, the reservoir simulation is the most comprehensive tool but also the most complex to handle.…”

Section: Introductionmentioning

confidence: 99%

Using Geochemistry to Address H2S Production Risk due to Steam Injection in Oil Sands

Barroux

Lamoureux-Var

2013

All Days

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Steam injection for enhanced oil recovery induces chemical reactions within the reservoir, called aquathermolysis, which can lead to in-situ H 2 S generation and to H 2 S production at the wellhead. H 2 S production risk is particularly acute in oil sand reservoirs because they contain sulfur-rich bitumens. To forecast H 2 S production risk in these conditions, a workflow based on geochemical investigation and reservoir simulation has been developed. It relies on (1) a quick estimate, using a dedicated technique, of sulfur content and thermal reactivity of a large number of reservoir samples to map the H 2 S production risk over the field; (2) carrying out more time-consuming aquathermolysis experiments on oil sand samples selected from step 1, to define a kinetic model for H 2 S generation based on atomic sulfur thermal reactivity; (3) transforming this sulfur-based kinetic model into a molecular SARA components-based kinetic model, usable in a compositional and thermal reservoir simulator; (4) simulating the EOR process with the reservoir simulator to calculate H 2 S/oil ratio at the wellhead.The geochemical methodology has been applied to four oil sand samples from Athabasca. The results have underlined that sulfur content and sulfur thermal reactivity of oil sands measured with the quick estimation technique are well correlated with the amount of H 2 S produced from the more lengthy aquathermolysis experiments. Moreover, it was shown that the sulfur in the oil sand, when distributed among Saturates, Aromatics, Resins, Asphaltenes, Solid matrix and H 2 S, as a function of time and temperature of aquathermolysis, can be interpreted in terms of sulfur-based kinetic model. This model can be used for a calculation of H 2 S generation upon aquathermolysis at field production temperature and time scale, thus for estimating the H 2 S production potential.As detailed in another SPE paper (Barroux et al., 2013), reservoir simulation has been used to simulate a SAGD process in a generic 2D model of an Athabasca oil sand. One main finding of this study has been that the H 2 S/oil ratio at the wellhead appears to depend mainly on the stoichiometry of the kinetic model.

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Identification of SSC (Sulfide Stress Cracking)-Susceptible Wells and Risk Prediction

Cited by 9 publications

References 4 publications

Reservoir Simulation of H2S Production During a SAGD Process Using a New Sulfur-Based-Compositional Kinetic Model

Reservoir Simulation of H2S Production During a SAGD Process Using a New Sulfur-Based-Compositional Kinetic Model

Forecasting of H2S Production due to Aquathermolysis Reactions

Using Geochemistry to Address H2S Production Risk due to Steam Injection in Oil Sands

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