Souring is usually a consequence of water injection. Seawater brings sulphate and bacteria into a reservoir that contains organic carbon and, in the cooler zones near the injector, conditions suitable for sulphate-reducing bacteria. They reduce sulphate to hydrogen sulphide, which partitions into the oil and gas and travels to the producers. The onset is often years after injection starts, which is why fields designed as sweet become sour in mid-life.

Prediction matters because the consequences are expensive. Sour service materials, scavenging facilities, gas treating and safety systems are far cheaper to install during development than to retrofit. Souring models use injection water composition, reservoir temperature, the location of the thermal viability shell, nutrient availability and sweep to estimate when and how severely producers will sour.

Control options divide into removing the cause and treating the effect. Sulphate removal from injection water removes the feedstock; nitrate treatment stimulates competing bacteria that suppress sulphate reducers; biocides kill bacteria but are difficult to deliver deep into the reservoir. Scavengers treat the hydrogen sulphide once it has arrived. Most fields end up with a combination, chosen on cost and on how much souring the facilities and materials can tolerate. This course covers all of it, with the safety implications given full weight.

By the end of this training, participants will be able to:

• Explain biogenic and thermochemical souring mechanisms.
• Identify the reservoir conditions that favour sulphate-reducing bacteria.
• Predict souring onset and severity for a waterflooded field.
• Characterise microbial communities using culture and molecular methods.
• Design microbial monitoring programmes, including sampling and biofilm assessment.
• Select and apply biocides and evaluate their effectiveness.
• Design nitrate and nitrite treatment programmes.
• Evaluate sulphate removal from injection water.
• Select and apply hydrogen sulphide scavengers in production systems.
• Assess materials, corrosion and safety implications and build a field souring management strategy.

Organisations sending participants to this training will:

• Anticipate souring before it forces expensive retrofits.
• Reduce hydrogen sulphide levels and the associated safety exposure.
• Select cost-effective souring control for the field's conditions.
• Improve microbial monitoring and treatment effectiveness.
• Inform materials selection and facility design with credible souring forecasts.

Participants will:

• Understand why and when reservoirs sour.
• Be able to predict souring and interpret microbial monitoring data.
• Know the control options and their strengths and limits.
• Understand hydrogen sulphide scavenging in production systems.
• Understand the materials, corrosion and safety consequences of souring.

• Production engineers
• Production chemists and microbiologists
• Reservoir engineers in waterflooded fields
• Facilities and process engineers
• Integrity and materials engineers
• HSE staff dealing with hydrogen sulphide exposure

Upon successful completion of this training course, delegates will be awarded an official Certificate of Completion issued by the Petroleum Engineers Association (PEA), an ISO 9001:2015 certified training organization. The certificate carries 10 Credits and formally records the total learning hours completed.

Each certificate is signed by the Course Facilitator and the CEO of the Petroleum Engineers Association, and serves as verifiable proof of professional training that delegates can present to employers and professional bodies worldwide.