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What does a digital workflow change on a geothermal project?
A digital workflow connects measurement to an operational decision. A drilling crew, for example, can combine surface and downhole readings, diagnose why drilling performance is changing, and adjust how the well is being drilled. During reservoir stimulation or operation, teams can combine seismic, fiber-optic and production observations to understand how the subsurface is responding.
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This is more than installing sensors or storing data. The information has to be reliable, compatible with geothermal field conditions, interpreted in time, and made available to the people who can use it. The U.S. Department of Energy (DOE) describes data-driven drilling as a way to improve hole advancement and reduce nonproductive time linked to wasted energy, vibration and tool failure.
| Project phase | Data and timing | Potential operational use | Evidence and qualification |
|---|---|---|---|
| Drilling | Surface and downhole measurements collected during drilling | Diagnose drilling performance and adjust operations | DOE describes mechanical specific energy (MSE) as one decision input; it is the energy needed to remove a unit volume of rock. |
| Stimulation and reservoir development | Microseismic, fiber-optic, deformation, tracer and well measurements; some streams are continuous, others periodic | Assess how the reservoir responds and inform decisions about stimulation or flow testing | DOE identifies these as useful monitoring approaches while noting that deployment and timely interpretation remain challenging. |
| Plant operations | Historical operating data analyzed with machine-learning algorithms | Identify patterns that may inform operations and maintenance | NREL’s FY 2023 project-summary search text describes a platform tested on data from three fields and reports potential, not guaranteed, availability gains. |
| Across projects | Drilling, stimulation, well-log and microseismic records preserved in a shared repository | Make it easier for later teams to learn from earlier work | DOE says FORGE contributes these data to the Geothermal Data Repository. |
How can drilling data help a geothermal crew?
Use MSE as one signal, not a standalone answer
Mechanical specific energy estimates the energy needed to remove a unit volume of rock. In a data-driven drilling workflow, it is considered alongside other surface and downhole measurements to help diagnose performance. A change in MSE can prompt investigation and operational adjustment; it does not, by itself, identify every cause of poor drilling or dictate a universally correct response.
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DOE says these practices have been adopted much less in the U.S. geothermal industry than in oil and gas, despite their demonstrated influence on drilling performance. Dupriest’s 2011 work, as cited by DOE’s Geothermal Technologies Office, is associated with a 40% improvement in average hole-advancement rates. That figure is a reported result from that work, not a typical geothermal-project forecast.
Apply the diagnosis to the well being drilled
DOE also describes a FORGE example combining a physics-based limiter redesign, staff training and polycrystalline diamond compact bits. Together, those measures cut anticipated drilling time by more than half for a first-of-its-kind, highly deviated well at the site. It is a site-specific demonstration, not evidence that the same reduction will transfer to another well with different geology, design or equipment.
The construction lesson is to connect measurements to a defined decision process: who reviews the data, what conditions trigger a closer look, and how the crew records the effect of an adjustment. Without that loop, collecting more data can add workload without improving execution.
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How do operators monitor a changing geothermal reservoir?
Reservoir conditions can change during development and operation, so a single survey or model may not capture the full response. DOE describes microseismic monitoring as a primary way to track changes associated with permeability and stimulation. Other observations can add context:
- Fiber-optic measurements: continuous observations of subsurface strain, temperature and acoustics can help teams understand flow and reservoir changes during stimulation and flow testing.
- Ground deformation: GPS or InSAR observations can track surface movement associated with subsurface changes.
- Tracer studies: tracer results can help characterize connections and fluid movement through the reservoir.
- Production and injection measurements: flow, pressure, temperature and fluid chemistry provide operational evidence about well and reservoir behavior.
These streams are not interchangeable: they observe different aspects of the system and may arrive at different intervals. Useful monitoring depends on combining the measurements that fit the project question and interpreting them quickly enough to inform an operational response.
At DOE’s FORGE site, fiber-optic cable is used to continuously monitor subsurface strain, temperature and acoustics. DOE reports that the Geothermal Data Repository held more than 133 terabytes of FORGE data as of May 2026. The figure describes the repository holdings at that date, not the volume of usable data for any particular project or an assurance that every dataset is immediately actionable.
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Why does sharing field data matter?
Drilling and reservoir work generate information that can be expensive to reproduce. DOE identifies limited availability of drilling data and the absence of widely accepted platforms for acquiring and sharing high-rate digital data as barriers. Its geothermal program set a goal of implementing a drilling-data acquisition and sharing platform for DOE-funded drilling work, while encouraging wider industry and international sharing.
FORGE data in the Geothermal Data Repository include well logs, drilling and stimulation records, and microseismic catalogs. DOE says the site contributes those materials to the repository. Shared records can help later teams compare designs and field observations rather than starting with an empty information base; their value still depends on data quality, documentation, access and relevance to the new site.
Can oil-and-gas digital methods transfer to geothermal construction?
Some capabilities transfer: subsurface evaluation, modeling, drilling and completion, facilities construction and maintenance, and operations monitoring. The International Energy Agency (IEA) estimates that around two-thirds of investment in conventional geothermal operations overlaps significantly with oil-and-gas skills and expertise; for next-generation geothermal technologies, the estimate is more than three-quarters. These are estimates of skill and expertise overlap—not portions of project costs that can automatically be removed or savings a geothermal project should expect.
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Geothermal conditions also create constraints. DOE notes that some tools used in oil and gas are unavailable or unsuitable for geothermal temperatures and well sizes. Equipment selection and digital-system design therefore need to account for temperature, well diameter, deployment conditions and reliability rather than assuming an oil-and-gas solution will work unchanged.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.What can plant analytics contribute?
Digital workflows can continue after construction and commissioning. NREL’s FY 2023 project-summary search text describes the Geothermal Operational Optimization with Machine Learning (GOOML) project, which completed a platform that analyzes historical plant operational data using custom machine-learning algorithms. The summary says it was tested with data from Ormat’s McGinness Hills in Nevada, Ngāti Tūwharetoa Geothermal Assets’ Kawerau plant in New Zealand, and Contact Energy’s Wairakei plant in New Zealand.
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What should project teams evaluate before adopting a workflow?
- Project phase: Is the need exploration, drilling, stimulation, plant operations or maintenance?
- Data type and cadence: Does the decision depend on high-rate drilling data, continuous fiber-optic observations, periodic tracer results, seismicity or historical plant records?
- Actionability: Will analysis reach a responsible operator in time to affect a real decision?
- Geothermal compatibility: Can sensors and equipment withstand project temperatures, fit the well design and operate reliably in field conditions?
- Integration and retention: Can the workflow work with existing systems, preserve useful records and support appropriate sharing?
- Evidence level: Is the claim a scenario, modeled potential, analysis of historical data or field demonstration? Those are different kinds of evidence and should not be presented as equivalent.
What digitalization cannot solve on its own
The IEA describes geothermal as an underused source of electricity, heat and storage, with technology improvements and oil-and-gas practices among the routes to expanding access to deeper resources. But digital operations do not independently resolve project-development risk, permitting and licensing delays, environmental concerns or social acceptance. Nor do they erase uncertainty about subsurface conditions or the capital required to develop a project.
The IEA’s 2024 outlook estimates that geothermal could meet up to 15% of global electricity-demand growth to 2050, corresponding to as much as 800 GW of capacity, if technology improvements and cost reductions continue. These are scenario estimates, not current deployment or a promise of future capacity. Separately, the IEA reports that global geothermal capacity had an average utilization rate above 75% in 2023. That is historical utilization context, not proof that every plant or prospective project will achieve the same level.
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