Predicting Reservoir Souring in the Alba Field Using Produced Water Compositions – A Study of Biogenic Sulfate Loss

Giulia Ness, Kenneth Sorbie, Nancy Lugo, Júlia R. de Rezende, Xiang Shi

Research output: Chapter in Book/Report/Conference proceedingConference contribution

Abstract

Microbial reservoir souring poses a significant threat to safe oil and gas production and operations and it is difficult to control and mitigate. Predicting future H2S trends with reservoir souring models is done in an attempt to define the worst-case scenario and make critical decisions related to the asset field life. Unfortunately, these predictions often prove wrong because of the large uncertainties around parameters used within these models and because predicting the behaviour of living microorganisms is much more complex than dealing with most other chemical challenges in oil & gas.

This work proposes an alternative data-driven and mechanistic approach to the investigation of the souring problem in Alba, a mature North Sea field water flooded since 1994. A comprehensive dataset including water chemistry analyses, gas composition trends, fluid rates etc. is used to find important correlations between produced fluid compositions and changes in H2S production. The concept of biogenic sulfate loss is introduced to allow the comparison of results for wells located in different parts of the field and drilled at different stages of the field life.

When looking at produced sulfate concentration, injection water fraction (IWF) and produced H2S we clearly identify 5 stages of H2S generation in the Alba field. Sulfate loss in produced fluids is detected first and it is followed by a delayed H2S production. Eventually both biogenic sulfate loss and H2S generation reach a plateau although it is not easy to determine the end members of these concentrations.

Produced water data shows a significant sulfate loss in excess of 1000 mg/l caused by reservoir biogenic souring. To account for sulfate loss caused by changes in the IWF, the biogenic sulfate loss is calculated. This is defined as the SO42− drop from the expected SO42− concentration calculated using injection water fraction based on boron.

A plot of maximum produced H2S and biogenic sulfate loss is constructed to compare all wells, show the souring trend and bracket the maximum H2S generation for the field. Sulfate and BTEX are not the limiting factor in H2S generation in this field but the maximum concentration of sulfide that bacteria can tolerate determines how high H2S can rise.

This work shows for the first time how the change in produced sulfate concentration can be used to study the different stages of well reservoir souring in high sulfate waters. A new method of comparing wells based on biogenic sulfate loss and H2S production is proposed to bracket the maximum H2S generation expected in this field. This straightforward data analysis method is generally applicable in fields that are souring due to microbial activity and where the produced fluid compositions are available.

Original languageEnglish
Title of host publicationSPE International Conference on Oilfield Chemistry 2023
PublisherSociety of Petroleum Engineers
ISBN (Print)9781613998748
DOIs
Publication statusPublished - 21 Jun 2023
EventSPE International Conference on Oilfield Chemistry 2023 - The Woodlands, Texas, USA
Duration: 28 Jun 202329 Jun 2023

Conference

ConferenceSPE International Conference on Oilfield Chemistry 2023
Period28/06/2329/06/23

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