Chemical flooding is formulation specific. A polymer that performs in one reservoir may degrade in another at higher temperature or salinity. A surfactant formulation optimised for one crude and one brine will not achieve low interfacial tension with a different crude or a different salinity. This means the laboratory programme is not a preliminary but the core of the project, and screening, formulation, adsorption measurement and core flooding with actual reservoir fluids and rock consume substantial time and cost before any field decision can be made.

Adsorption and retention determine chemical cost, and chemical cost determines project viability. Polymer and surfactant are both retained on rock surfaces and in pore structure, and that retained volume must be paid for and does not contribute to recovery. Adsorption depends on mineralogy, particularly clay content, on salinity and on the chemical itself, and measured values vary widely. A project economic case built on optimistic adsorption assumptions can fail entirely when field retention proves higher.

Injectivity loss is the most common operational problem. Polymer solution is viscous by design, which reduces injectivity in proportion, and polymer can also plug near-wellbore rock through mechanical entrapment, gel formation or the presence of microgels from poor dissolution. Wells that could accept water at a given pressure will not accept polymer at the same rate, and planning for that, through well count, injection pressure limits and fracture management, is part of the design rather than a surprise.

Finally, chemical floods change produced fluid properties and the facilities must handle it. Polymer-containing produced water is viscous and difficult to treat, surfactant stabilises emulsions that the treating plant was not designed to break, and alkali produces scale in wells and facilities. Produced water reinjection becomes harder and disposal quality requirements become harder to meet. Facility modification is frequently a substantial part of the project cost and is regularly underestimated.

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

• Screen reservoirs for chemical EOR against fluid, rock, temperature, salinity and heterogeneity criteria
• Select polymer types and specify concentration, viscosity and injection conditions for mobility control
• Assess polymer degradation, retention, inaccessible pore volume and injectivity effects
• Explain surfactant phase behaviour, optimal salinity and interfacial tension reduction
• Design surfactant formulations and slug sequences including adsorption management
• Apply alkali chemistry including soap generation, consumption and scaling risk
• Design ASP formulations and evaluate their combined mechanisms
• Specify laboratory screening and core flood programmes to support a field decision
• Design and interpret chemical EOR pilots
• Plan field implementation including injectivity, facilities and produced fluid handling

The training develops the chemistry and physics of each mechanism and then applies it to design, using laboratory data, core flood results and field performance from chemical flood projects. Participants perform mobility ratio, slug sizing, adsorption loss and chemical cost calculations, and design laboratory programmes for defined reservoir conditions. Pilot results from implemented projects, both successful and unsuccessful, are examined for the design or laboratory decision that determined the outcome. Facility and produced fluid consequences are developed from operating experience on chemical flood fields.

Organisations sending participants to this training will:

• Screen chemical EOR opportunities on sound technical criteria before committing to studies
• Specify laboratory programmes that answer the questions a field decision requires
• Improve chemical flood design and reduce the risk of formulation failure in the field
• Plan realistically for injectivity, facility and produced fluid consequences
• Improve pilot design so that results support a full field decision
• Build internal capability to evaluate chemical EOR proposals and vendor claims

Participants will:

• Understand the mechanisms by which each chemical improves recovery
• Design polymer, surfactant and ASP floods for defined reservoir conditions
• Specify and interpret laboratory and core flood programmes
• Anticipate injectivity and produced fluid problems before they occur
• Evaluate chemical EOR economics realistically
• Build a specialist capability in a growing area of mature field development

• Reservoir engineers working on improved and enhanced recovery
• Production and facilities engineers supporting chemical flood projects
• Production chemists and laboratory specialists
• Development engineers evaluating EOR options for mature fields
• Simulation engineers modelling chemical flooding processes
• Technical staff assessing EOR proposals and pilot results
• Asset managers considering enhanced recovery investment

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.