handling microbiological uncertainty in reservoir souring...

© 2017 Chevron Corporation

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