Reinjection is required and creates the central engineering tension. The produced brine carries dissolved solids and sometimes hazardous constituents, it cannot generally be discharged, and reinjecting it maintains reservoir pressure and prevents subsidence. But reinjected water is cold, and it travels toward the producers through whatever flow paths exist, cooling them progressively. Placing injectors far enough away to delay thermal breakthrough while close enough to provide pressure support is the fundamental well placement problem, and getting it wrong shortens field life substantially.

Flow is frequently fracture-dominated, which makes prediction harder than in porous media. Many high enthalpy systems produce from fracture networks rather than from matrix permeability, and tracer tests routinely show breakthrough times far shorter than a porous medium calculation would predict. A single conductive fracture connecting an injector to a producer can deliver cold water in months rather than decades. Tracer testing is therefore a core characterisation tool in geothermal practice rather than a supplementary one.

Chemistry is an operational constraint on the same scale as flow. Geothermal brines are frequently saturated in silica, calcite or sulphides at reservoir conditions, and cooling or flashing them causes precipitation in wells, surface pipework and injection wells. Scaling can reduce injectivity to the point of failure within months, and managing it through inhibition, temperature control and operating practice is continuous work. Non-condensable gases, hydrogen sulphide in particular, add emissions and safety requirements.

Finally, enhanced geothermal systems extend the resource to rock that is hot but not permeable, by creating permeability through stimulation. The technical challenge is creating a connected fracture network with adequate heat exchange area and controlled flow paths, and the recurring difficulty has been short circuiting, where flow concentrates in a few paths and thermal breakthrough is rapid. Induced seismicity has also constrained several projects, and managing it is now integral to EGS development rather than a peripheral concern.

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

• Classify geothermal resource types and assess their development characteristics
• Estimate heat in place and recoverable energy and apply appropriate recovery factors
• Design and interpret geothermal well tests including injection and tracer testing
• Characterise fracture-dominated flow and identify preferential flow paths
• Analyse two-phase and flashing flow in the reservoir and wellbore
• Design reinjection strategy and predict thermal breakthrough timing
• Assess and manage scaling, corrosion and non-condensable gas problems
• Evaluate induced seismicity risk and design monitoring and mitigation
• Assess enhanced geothermal system development including stimulation and flow path control
• Manage a geothermal reservoir for sustained output over decades

The training develops geothermal reservoir behaviour and applies it through calculation using data from operating geothermal fields. Participants estimate resource, interpret well and tracer tests, calculate thermal breakthrough timing for well configurations and assess scaling risk from brine chemistry. Field operating histories are examined for thermal decline, injectivity loss and the management responses applied. Enhanced geothermal projects are examined for their stimulation outcomes, flow path behaviour and seismicity experience, including projects halted for seismicity reasons.

Organisations sending participants to this training will:

• Assess geothermal resources on sound reservoir engineering criteria
• Improve well placement decisions and delay thermal breakthrough
• Sustain injectivity and reduce scaling-related capacity loss
• Improve production forecasting and resource sustainability assessment
• Manage induced seismicity risk and its project consequences
• Transfer petroleum reservoir engineering capability into geothermal development

Participants will:

• Apply reservoir engineering to heat extraction rather than fluid production
• Design injector and producer configurations that sustain output
• Interpret tracer tests and identify preferential flow paths
• Anticipate and manage scaling and chemistry problems
• Assess enhanced geothermal proposals critically
• Build a capability that transfers directly from petroleum engineering

• Reservoir engineers entering or working in geothermal development
• Petroleum engineers transferring into geothermal projects
• Geoscientists characterising geothermal systems
• Production engineers managing geothermal wells
• Drilling and completion engineers on geothermal wells
• Project and development engineers on geothermal projects
• Technical staff evaluating geothermal opportunities

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.