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

2© 2017 Chevron Corporation

Presentation outline

• Reservoir souring introduction• Souring field case

– Historical data review– Impact of reservoir souring– H2S sulphur isotope data– SourSimRL simulations

• Conclusions


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


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


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


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


Reservoir souring characterization

Maximum H2S production vs Distance to injector for active producers (from 2012 to 2014)

Log1

0 Sc

ale


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


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


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


Reservoir souring activityConceptual model


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


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


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


• 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


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


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


Thank You

Handling Microbiological Uncertainty in Reservoir Souring...

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