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A geothermal prospect is ready for drilling only when its expected heat, fluid-delivery capability, reservoir volume, chemistry, depth and development concept support a specific decision despite quantified uncertainty. Surface heat or one geophysical anomaly is not enough. Combine geology, geophysics and geochemistry, state what each dataset actually proves, identify the uncertainties that could change production or economics, and design the next well as both a development step and an information purchase.
Start with the decision, not the survey
“Good enough to drill” has no universal probability threshold. The answer depends on what you are trying to build, the well’s purpose, the cost of failure, financing terms, offtake and the value of information from the next measurement. Write the decision down before collecting more data:
- Lease or relinquish the area.
- Run a regional screening program.
- Acquire prospect-scale geophysical, geological or geochemical data.
- Drill a temperature-gradient or slim exploratory well.
- Drill a full-size exploration or confirmation well.
- Redesign, stimulate or abandon after a test result.
Conventional hydrothermal projects depend on naturally permeable formations and circulating fluids. Enhanced geothermal systems (EGS) may require stimulation and a deliberately engineered fracture network. Closed-loop concepts place different demands on natural permeability, while direct-use projects can work at lower temperatures if the heat demand and surface system match. A screening result suitable for one concept may be inadequate for another. DOE describes characterization and confirmation work for both conventional hydrothermal and next-generation resources in its Exploration and Characterization material and Geothermal Drilling Research overview.
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What a drill-ready resource must demonstrate
Temperature alone does not make a commercial geothermal well. Deliverable thermal power depends principally on the heat or enthalpy of the produced fluid and the rate at which the reservoir can transmit that fluid. The World Bank’s Geothermal Exploration Best Practices, 2nd Edition identifies temperature (or enthalpy) and transmissivity (often expressed as permeability-thickness) as the principal resource risks. Reservoir volume, fluid chemistry and depth add further production, engineering and economic risk.
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| Risk element | What it controls | Evidence to assemble | Decision question |
|---|---|---|---|
| Temperature or enthalpy | Thermal energy available per unit of produced fluid | Measured temperatures, chemistry-based geothermometers, gradients, heat-flow interpretation and uncertainty ranges | Will the fluid temperature support the intended power or direct-use process at the expected flow rate? |
| Transmissivity or permeability-thickness | How much fluid a well can produce or inject | Structural interpretation, fracture indicators, well tests, pressure data and analogues | Is there a connected flow path at the planned well location, not merely a conductive anomaly? |
| Reservoir volume and geometry | Number of wells, pressure decline and sustainable output | Mapped faults, stratigraphy, seismic interpretation, gravity or magnetic constraints and conceptual-model alternatives | Is the hot, permeable volume large and connected enough for the project life? |
| Fluid chemistry | Scaling, corrosion, reinjection, disposal and environmental controls | Surface and subsurface samples, gas composition, isotope data and expected changes with production | Can the fluid be produced and reinjected with manageable materials and treatment requirements? |
| Depth and drilling conditions | Well cost, schedule, temperature exposure and mechanical risk | Depth-to-target, pressure and stress estimates, lithology, offset-well records and access constraints | Can the target be reached with a design and budget that survive dry, lost-circulation or high-temperature contingencies? |
For every element, record the current estimate or range, observations supporting it, method and assumptions, spatial coverage, confidence, and the next measurement that could materially change the decision. Keep measured values separate from interpretations and model assumptions. A single “best estimate” without sensitivity to flow, net power and cost conceals the risk a lender or investment committee actually needs to see.
Build one conceptual model from the three Gs
DOE groups geothermal characterization into geology, geophysics (including remote sensing) and geochemistry. The purpose is not to accumulate disconnected maps; it is to explain a heat source, fluid source, pathways, structures, reservoir boundaries and stress regime in one testable model.
Geology: identify the plumbing and the seal
- Map lithology, alteration, faults, fractures, intrusive bodies and stratigraphic contacts that could conduct or contain fluid.
- Distinguish permeable zones from merely fractured-looking outcrops; continuity at depth is the critical unknown.
- Use structural history to determine which faults are open, sealed, reactivated or favorably oriented in the present stress field.
- Document uncertainty in contacts, fault locations and depth conversion rather than drawing a single deterministic reservoir boundary.
Geophysics and remote sensing: constrain, do not certify
Electrical, electromagnetic, seismic, gravity, magnetic, thermal and remote-sensing data can identify contrasts associated with alteration, fluid, structure or heat. They differ in depth sensitivity, resolution and non-uniqueness. A conductive zone can reflect clay alteration or hot fluid; a seismic feature can be structural without being hydraulically productive. Calibrate interpretations against geology and any wells, and show alternative explanations where the same anomaly has more than one cause.
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1Repair Windows errors before they cause bigger problems2Scan for outdated or missing drivers - takes under a minute3Clear out junk files and repair common Windows errorsGeochemistry: test origin, temperature and fluid movement
Water, gas and isotope measurements can indicate fluid source, mixing, residence time and subsurface temperature. Sampling must account for contamination, boiling, seasonality and surface mixing. A geothermometer is an interpreted estimate with assumptions, not a direct temperature log. Chemistry also needs to be carried into engineering: dissolved minerals and non-condensable gases can alter scaling, corrosion, separator design and reinjection strategy.
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DOE states the central limitation plainly: “No singular non-invasive (non-drilling) characterization method provides resolution on the spatial distribution of subsurface permeability, temperature, fluid, chemistry, or stress sufficient to enable the high-confidence well targeting necessary for industry’s desired drilling success rates.” The implication is practical: integration can rank targets and reduce uncertainty, but it cannot turn a surface anomaly into proof of a productive well.
Use staged exploration to reduce uncertainty before committing capital
- Screen the opportunity. Define the development concept, heat market or power target, access constraints, land and permitting conditions, and an initial depth and cost envelope. Assemble public data, legacy wells, regional heat-flow information and analogues. Mark missing or low-quality data.
- Construct competing conceptual models. Describe at least the leading heat-source, fluid-pathway and reservoir-geometry interpretation, then document credible alternatives. State which observations distinguish them.
- Acquire targeted data. Choose surveys because they resolve a named uncertainty. For example, a structural question may justify detailed mapping or seismic work, while a temperature question may justify a gradient well or improved geochemical sampling. Do not purchase a survey merely because it is customary.
- Update the model quantitatively. Convert new evidence into ranges for temperature, transmissivity, volume, chemistry and depth. Track spatial coverage and confidence. Recalculate expected production, net power, schedule and cost under low, central and high cases.
- Rank targets transparently. Score the joint evidence for heat, permeability, fluid, geometry and practical drillability. Preserve the evidence trail so a target’s rank can be audited when new data contradict an assumption.
- Define the next well before tendering. Specify the hypothesis, planned trajectory and depth, geological and engineering success criteria, measurements, decision gates, contingency budget and outcomes that trigger a stop, sidetrack, stimulation or redesign.
- Reassess after the well. Integrate temperature logs, pressure response, lost-circulation intervals, image logs, cores, fluid samples and injectivity or production tests. Update the conceptual model and development decision rather than treating a binary “hit” or “miss” as the only result.
DOE’s Play Fairway Analysis applies systematic, oil-and-gas-style screening to identify favorable resource combinations and reduce early exploration uncertainty and drilling costs. Regional or basin-scale fairway maps are useful for narrowing the search; they are not prospect-scale confirmation. A fairway score should therefore be one layer in a traceable target-ranking system, not a substitute for a well test.
Do not misread hidden geothermal systems
A concealed system may lack hot springs, fumaroles or other obvious surface manifestations. DOE’s Hidden Systems work treats that absence as a targeting challenge, not proof that no resource exists. For a hidden prospect, place greater weight on integrated subsurface evidence, structural interpretation and uncertainty reduction. Also increase the burden of proof for target location: a broad regional anomaly must be narrowed to a drillable structure with a defensible temperature and permeability hypothesis.
Conversely, a visible hot spring proves that hot fluid reaches the surface somewhere; it does not prove that the planned production well will encounter adequate flow, temperature or reservoir volume. Surface discharge can be fed by a narrow upflow zone, a cooler outflow or a pathway that is offset from the proposed pad.
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Evaluate drilling as an information purchase
Drilling is both a capital asset and an experiment. DOE says drilling can represent more than half of total geothermal project costs; this is a DOE summary statement, not a project-specific estimate. The World Bank’s 2013 Drilling Down on Geothermal Potential report described test drilling as arguably the highest-risk activity because substantial resources are committed before the subsurface outcome is known.
Prepare a well decision sheet with these fields:
- Target hypothesis: the structure, temperature interval and fluid pathway the well is intended to test.
- Success criteria: minimum temperature, stable flow or injectivity, pressure response, chemistry and reservoir evidence required for the next stage.
- Information objectives: measurements that remain valuable even if commercial flow is not achieved, such as temperature at depth, stress, lithology, fracture orientation or pressure connectivity.
- Failure and redesign rules: conditions for stopping, sidetracking, stimulating, changing the well pattern or abandoning the concept.
- Decision value: how each possible result changes the resource range, expected net power, number of wells, schedule and financing case.
- Contingencies: allowance for lost circulation, unstable formations, high-temperature tools, stuck pipe, well-control events, sidetracks and extended testing.
A well that misses the original target can still be valuable if it distinguishes competing models or locates the temperature and permeability boundary. Conversely, a hot but nonproductive well may falsify the assumption that temperature and transmissivity coincide. Define these interpretations in advance so optimism does not rewrite success after the result.
How risky is exploration drilling?
The World Bank report cited a historical general-consensus estimate that about one out of three greenfield deep geothermal wells would succeed. That figure is from 2013 and is not a current global probability or a site-specific forecast. “Success” can mean different things—commercial flow, a temperature hit, a technically completed well or confirmation of a geological model—and outcomes vary with geography, well purpose, exploration maturity and the number of wells already drilled. Use current comparable projects and site-specific evidence for underwriting; do not multiply a project forecast by one-third simply because the historical ratio is familiar.
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| Scenario | Subsurface result | Likely development response |
|---|---|---|
| Commercial confirmation | Target temperature and sustainable flow or injectivity demonstrated; chemistry manageable | Proceed to confirmation or production-well planning, subject to surface and financial checks |
| Hot but tight | Temperature meets the concept, but transmissivity is below the flow requirement | Evaluate stimulation or a different structural target; revise cost, induced-seismicity and schedule assumptions |
| Permeable but too cool | Fluid movement is demonstrated, but enthalpy is inadequate for the planned use | Consider a lower-temperature direct-use case only if the heat load and economics support it |
| Model-discriminating result | Data reject one model or locate the reservoir boundary without commercial flow | Redesign the next target if the information value exceeds the remaining drilling cost |
| Nonproductive outcome | No useful temperature, permeability or interpretable data at the planned target | Stop or abandon unless an independent, evidence-backed target justifies a new program |
Compare prospects on the same axes
When choosing between sites, do not let a spectacular temperature estimate mask weak permeability evidence or an easy drill site mask a small reservoir. Use a common comparison sheet:
| Comparison axis | What to report for each prospect |
|---|---|
| Temperature or enthalpy | Measured and interpreted ranges, depth of estimate, method, uncertainty and fit with the proposed surface use |
| Transmissivity | Direct tests if available; otherwise structural, geophysical and analogue evidence, with confidence explicitly labeled |
| Reservoir size and geometry | Connected-volume interpretation, boundaries, alternative models and implications for well count and pressure decline |
| Chemistry | Scaling, corrosion, gas, reinjection and treatment implications; sample quality and representativeness |
| Depth and drilling conditions | Target depth, pressure, stress, lithology, access, expected hazards and contingency requirements |
| Evidence quality | Data age, spatial coverage, calibration, independent confirmation and unresolved interpretations |
| Next-step cost and schedule | Price and duration of the specific survey, gradient well or exploration well that resolves the next decision |
| Production and finance sensitivity | How low, central and high resource cases change flow, net power, well count, revenue timing and funding need |
If a value is not established, label it “not stated” and identify the missing measurement. Do not convert a qualitative anomaly into a numeric probability without a defensible calibration set.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.Turn uncertainty into an investable decision
Financiers and owners need more than a geological narrative. The World Bank best-practices guide recommends a qualified—ideally quantified—estimate of uncertainty in thermal production and sensitivity to net power outcomes. Present a decision model that links subsurface variables to the project:
- Show low, central and high temperature/enthalpy and transmissivity cases.
- Translate each case into expected well flow, number of production and injection wells, and reservoir pressure behavior.
- Include chemistry-driven equipment, treatment and maintenance differences.
- Carry target depth, drilling hazards, contingency days and dry-hole or sidetrack costs into the schedule.
- Show how a successful, marginal or failed next well changes the capital plan and go/no-go decision.
- Separate exploration expenditure that buys information from expenditure that creates long-lived production capacity.
There is no source-established universal minimum confidence, success probability or bankability cutoff. A project may justify drilling with substantial uncertainty when the well is affordable, highly informative and the upside is large; another may not justify it when a moderate chance of success still produces unacceptable downside. The threshold belongs in the project’s decision analysis, not in a generic industry rule.
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Pre-drill review checklist
- Is the development concept explicit, including temperature, flow, stimulation and reinjection requirements?
- Is the decision being made now clearly defined?
- Are geology, geophysics and geochemistry integrated into one conceptual model?
- Does each dataset state what it measures, its resolution and its alternative interpretations?
- Are temperature/enthalpy and transmissivity ranges quantified separately?
- Are reservoir volume, chemistry and depth included in the production and cost model?
- Has a hidden-system interpretation been considered where surface manifestations are absent?
- Does the target ranking show how each evidence layer changes probability or uncertainty?
- Does the proposed well have explicit success criteria, information objectives and stop rules?
- Are drilling hazards, contingency costs and schedule impacts included?
- Does every likely well outcome have a predefined development response?
- Has the project avoided treating the historical one-in-three figure as a forecast?
- Can an investment committee see how the result changes net power, well count and financing?
Common evaluation errors and their fixes
Using a surface temperature as a reservoir forecast
Why it fails: surface discharge may be cooled, mixed or spatially offset from the productive zone.
Fix: combine chemistry, structure, temperature-depth evidence and a well-test plan tied to the proposed pad.
Treating a geophysical anomaly as permeability
Why it fails: anomalies are non-unique and can reflect alteration, lithology, fluid or structure without open flow paths.
Fix: state competing interpretations and identify the measurement that distinguishes them.
Reporting only a central model
Why it fails: lenders and developers cannot see how a lower-flow or higher-cost case affects the project.
Fix: publish ranges and sensitivity to net power, well count, schedule and chemistry.
Drilling without an information plan
Why it fails: an expensive well can produce ambiguous data and no defensible next decision.
Fix: specify measurements, success thresholds and stop or redesign rules before spudding.
Applying an industry statistic mechanically
Why it fails: the historical one-in-three estimate mixes regions, well purposes and definitions of success.
Fix: use it only as dated context and build a site-specific scenario analysis.
Bottom-line test
Authorize drilling when the integrated model supports a plausible heat-and-fluid system, the target addresses the highest-value uncertainty, the well’s cost and contingencies are affordable, and every credible result has a predefined decision consequence. If temperature, transmissivity, reservoir volume, chemistry or depth remains too uncertain to connect the well outcome to production and net power, spend the next dollar on the measurement that resolves that uncertainty—or stop—rather than treating another survey or a compelling surface signal as proof.
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