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Handling Microbiological Uncertainty in Reservoir
Souring Simulation
6th International Symposium on Applied Microbiology and Molecular Biology in Oil
Systems
San DiegoJune 6 - 9 2017
Paul Evans, Chevron ETC Bruno Dujardin, Chevron Upstream Europe
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Presentation outline
• Reservoir souring introduction• Souring field case
– Historical data review– Impact of reservoir souring– H2S sulphur isotope data– SourSimRL simulations
• Conclusions
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Reservoir souring schematic
Retardation of H2S transportby residual oil + H2S adsorption
Water swept
Waterswept+ H2S
Injection well m-SRB biofilm
Water swept
Water swept + H2S
Oil
Thief zone / fracture
Oil
H2SSulphate + Nutrients
Mesophilic SRB
Thermophilic SRB / Archaea
Injection water cooled
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Field X characteristics
• Reservoir temperature 78 C• High permeability reservoir sandstone
(average 2.6 Darcy)• Formation water:
– TDS 38,600 mg/l– VFA 320 mg/l– Sulphate 5 mg/l
• Field ~12 km long
• Seawater injection since 1994• Mature water flood - 85% water cut in field
production• Injection water transit time typically
several years• Approximately 70 production wells over
field life• Frequent, high quality monitoring data is
available
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Injection water breakthrough
• High percentage seawater breakthrough at production wells– Percentage of seawater in produced water
calculated based on Boron concentration• High sulphate depletion compared to
seawater – formation water mixing composition– Limited barium sulphate scaling– Microbial sulphate reduction– Other geochemical reactions / adsorption?
Seawater breakthrough
Sulphate depletion
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Historical H2S well profiles
• Increasing number of wells with significant level of H2S since 2010• Limited amount of wells with significant H2S before 2010• H2S increases very sharply when it reaches a well• Above a certain H2S level wells have to be shut-in• Wells A and B are outliers above trend
Well A
Well B
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Reservoir souring characterization
Maximum H2S production vs Distance to injector for active producers (from 2012 to 2014)
Log1
0 Sc
ale
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Impact of reservoir souring
• H2S impacts well and facility equipment: corrosion limits are based on partial pressure of H2S (combination of pressure and concentration of H2S)
• If H2S partial pressure limit is reached, wells need to be shut-in
• High H2S concentration also creates FeS that creates process issues (emulsion) and requires treatment
• Understanding increasing H2S trend help to design equipment metallurgy
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Possible electron donors
• Volatile Fatty Acids (acetate, propionate, butyrate, etc.) – fast kinetics sulphidogenesis
• Residual oil components with low water solubility e.g. toluene, other BTEX components, n-alkanes
• Fermentative microbiological activity generating electron donors (acetate, H2) used by sulphate-reducing microbes
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Produced sulphide isotopic composition
δ34S versus Test Separator Gas H2S Calculated isotopic fractionation factors
• Correlation between extent of souring development and H2S sulphur isotopic composition• Isotopic fraction factor (ε) calculated from produced gas δ34S data
• Higher isotopic fractionation factor at higher levels of SRB activity
Increasing SRB activity
Increasing SRB activity
δ34S = ε ln(f) + δ34Sinitial
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Reservoir souring activityConceptual model
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SourSimRL (SSRL) souring simulator
Souring Kernel;Temperature distribution;
SRB growth;H2S generation, partitioning
and transport;Nitrate module;
Oil biodegradation
User Inpute.g. formation
& injection water chemistry
Reservoir Simulator Interface; Eclipse, etc.
SourSimRLPre-Processor
Visualisation
Surface Facilities H2S Partitioning
Parallel / distributed simulation;
Sensitivity handling
kg H2S/day
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Reservoir souring model characterization
• Injection water breakthrough history matched in reservoir simulation• Model Input Parameters:
– Initial souring study 2010:• Moderate electron donor availability from biodegradation in near injection wellbore region• Rock H2S scavenging capacity (0-30 mg H2S / kg rock)
– Subsequent souring study 2014:• High electron donor availability from biodegradation in near injection wellbore region• Rock H2S scavenging capacity (40 mg H2S / kg rock)
– Seawater composition– Formation water composition– H2S partitioning coefficients (function of P, T, TDS, pH)– Bottomhole injection water temperature– Reservoir temperature
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2014 Field history match and forecast
• Both models match historical data until 2014 at the field level• Range of outcomes is captured in the 2014 model and H2S forecast is higher
History match Forecast
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• The 2014 model better match individual wells for most recent H2S data since 2010 especially the sharp H2S increase in some wells
• The 2014 H2S forecast is higher and more aligned with most recent data
• Key differences in model:– Higher electron donor availability from
biodegradation– Higher H2S scavenging capacity
Individual well forecast
Water H2S concentration - 2020
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Recent H2S experience
Actual well water cut increased more rapidly
than in reservoir simulation
Well F
Well C
Well G
Well D Well E
Well H
History Match
History Match
History Match
History Match History Match
History Match
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Conclusions
• Critical to have good quantity and quality of field monitoring data to enable reservoir souring history matching
• Quality of souring simulations is dependent on the quality of the reservoir simulation
• Reservoir souring history matching should consider more than just field H2S profiles e.g. Individual well profiles, injection water breakthrough, sulphate depletion
• Sulphur isotope data indicates differences in source of sulphidogenesis over life of well
• Determination of rock H2S scavenging capacity and rate of sulphidogenesis due to oil biodegradation in near injection wellbore necessary to develop accurate forecasts, especially for late in field life
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Thank You