Biased samples to study reservoir souring processes: A numerical analysis

Moein Jahanbani Veshareh,Hamidreza M Nick

doi:10.1016/j.jclepro.2021.127944

Moein Jahanbani Veshareh, Hamidreza M Nick

Open Access

https://doi.org/10.1016/j.jclepro.2021.127944

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Abstract

Production water samples are commonly used to study reservoir souring process. The aim of this study is to examine the reliability of these samples by using a state of the art coupled Thermo-Hydro-bioChemical numerical model. The transport and growth of five different representative sulfate-reducing strains (SRSs) in a model subsurface environment are simulated numerically by considering various biofilm formation characteristics and injection flow rates. After one pore volume (PV) injection, and assuming no biofilm formation, for three injection flow rates corresponding to pore velocities of 5.58 × 10−8, 83.7 × 10−8 and 167.4 × 10−8 m/s, souring within the reservoir is partially or completely derived by two SRSs that have an optimal growth temperature of 28 and 39 °C. However, the produced water taken after one PV is dominated by a SRS that has an optimal temperature of 82 °C. For a higher pore velocity of 558 × 10−8 m/s, without considering any biofilm formation, produced water sample contains the same SRSs as the reservoir. However, if half of the produced biomass by various SRSs participates in biofilm formation, even for the high pore velocity of 558 × 10−8 m/s, the produced water sample cannot reveal the SRSs that derive souring in the reservoir. Therefore, utilizing produced water samples may be misleading in reservoir souring studies. The results presented in this work suggest that more accurate prediction of reservoir souring requires characterization of the major groups of sulfate reducing bacteria in the injection water and undisturbed formation brine, and understanding their biofilm formation behavior.

Highlights

Biologic production of hydrogen sulfide (H2S) by sulfate-reducing bacteria (SRB) in oil reservoirs usually happens as the consequence of seawater flooding and is referred to as reservoir souring (Veshareh and Ayatollahi, 2019)
At L = 130 m, H2S concentration is equal to 0.028 M for both V = 5.58 × 10− 8m/s (Fig. 1e) and 83.7 × 10− 8m/s (Fig. 1f) despite a significant difference in their sulfate-reducing microbial community (SRMC) (Fig. 1a and b)
Based on the results shown in this work, the extent of biofilm formation, reservoir temper ature variation and substrate availability control SRMC dynamics

Summary

Introduction

Biologic production of hydrogen sulfide (H2S) by sulfate-reducing bacteria (SRB) in oil reservoirs usually happens as the consequence of seawater flooding and is referred to as reservoir souring (Veshareh and Ayatollahi, 2019). Over the past few decades numerous research studies have been completed on biological aspects of reservoir souring. In the experimental studies commonly batch or flow experiments are performed to find the souring rate and sulfate-reducing microbial community (SRMC) (do Vale et al, 2020; Marietou et al, 2020; Prajapat et al, 2021). Reservoir souring simulations are commonly employed to utilize the laboratory scale observations for predicting the field scale responses (de Jesus and de Andrade Lima, 2021; Veshareh et al, 2021). The reliability of reservoir souring simulation studies depends significantly on the quality and the relevance of experimental studies utilizing actual or analogous fluid and porous media samples of the reservoir

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