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Compare geothermal steam performance only after putting actuals and the forecast on the same physical boundary, time period, units and operating assumptions. Use a dated well-and-plant data table, calculate both absolute and percentage variance, then separate reservoir effects from well availability, gathering constraints and power-plant losses. A lower MW number alone cannot prove that the reservoir is under-producing.
Start by defining what “actual steam” and “base case” mean
The phrase “steam production” can describe several different measurements. Before calculating a variance, write a one-sentence boundary definition for each series. Otherwise, a gross wellhead forecast can be compared accidentally with net turbine output and produce a meaningless shortfall.
Choose the physical measurement boundary
- Gross wellhead steam: steam leaving production wells before field gathering losses, separation or plant constraints.
- Separator steam: the vapor stream after a separator removes brine. The separation pressure and steam-quality convention must be recorded.
- Turbine-inlet steam: steam delivered to the turbine after gathering, separation, treatment and field availability losses.
- Equivalent steam energy: a heat or enthalpy basis that can compare two streams with different temperatures, pressures or quality.
State whether the project forecast is a reservoir-model output, a plant-feed forecast or the financial base case used for debt, equity or contract decisions. Those are not interchangeable. A reservoir model can predict pressure, enthalpy and well deliverability; a plant-feed forecast includes gathering and separation assumptions; a financial case may additionally include outages, curtailment and the planned make-up-well schedule.
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Fix the time basis
Use the same calendar or operating period for both series. A monthly average actual should not be compared with a nameplate or first-year forecast. Keep commissioning, ramp-up, planned outages, forced outages, curtailment and make-up-well start dates as explicit tags. For mature operations, add rolling 30-, 90- and 365-day views when the data density supports them; the shorter windows reveal recent changes while the annual window reduces seasonal and outage noise.
Build a dated actuals table before doing any arithmetic
Make the well-level record the primary source of truth and derive plant totals from it. Each row should identify the well, the measurement date and the operating state. CalGEM’s GeoSteam database and guide define production, injection, test and shut-in status codes; preserve those codes instead of collapsing every non-producing day into zero production.
| Field | What to record | Why it matters |
|---|---|---|
| Well identity | Well ID, pad or area, completion or workover date | Prevents commingling and makes make-up-well effects traceable. |
| Status | Producing, testing, shut-in, injection, workover or unavailable, using the project’s code set | Separates reservoir capability from an intentional or forced outage. |
| Flow | Steam mass flow and brine flow, with units and meter basis | Allows a consistent mass or energy balance. |
| Pressure | Wellhead, separator and turbine-inlet pressure where measured | Shows whether pressure loss occurs in the reservoir, gathering system or plant. |
| Temperature and enthalpy | Measured temperature, fluid enthalpy and calculation method | Two streams with equal mass can carry different usable energy. |
| Steam quality | Quality definition, sampling method and separation pressure | “Steam flow” can include different vapor fractions. |
| Injection | Injection-well ID, brine rate, pressure and operating status | Reinjection changes reservoir pressure and the field water balance. |
| Availability | Operating hours, planned and forced outage hours, curtailment | Distinguishes physical under-performance from lost operating time. |
| Plant tags | Gathering restrictions, separator limits, turbine or condenser status, ambient conditions | Captures downstream causes of a lower electrical output. |
| Well additions | Make-up-well drilling, connection and first-production dates | Prevents a new well from being mistaken for natural field behavior. |
Store raw readings as well as daily, monthly and annual aggregates. Record meter uncertainty, missing intervals and any imputation. A monthly total without the underlying status and pressure history cannot support a reliable cause analysis.
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Match mass-flow units
Convert both series to the same mass unit, such as tonnes per hour or kilograms per second. Do not mix a reported steam rate with a volumetric water rate without a documented density and phase conversion. If the forecast is in pounds per hour and the actual is in tonnes per day, convert first and retain the conversion in the calculation log.
Match energy units when quality or enthalpy differs
For an energy comparison, calculate the usable thermal rate from mass flow and enthalpy on the same reference basis. The exact equation depends on the project’s thermodynamic convention, but the essential inputs are mass flow, fluid enthalpy, reference state and steam quality. A gross steam-mass comparison can overstate performance when actual quality or enthalpy is lower than assumed.
Match plant and operating assumptions
- Use the same number of producing wells and identify whether the forecast assumed future wells.
- Use the same separation pressure and steam-quality convention.
- Apply the same operating hours, plant-factor assumption and outage treatment.
- Keep commissioning and make-up-well production separate from natural decline.
- Use the same gross-versus-net convention. Net electric output subtracts parasitic loads; steam does not.
Steam mass flow or steam energy is primarily a reservoir-and-field metric. Megawatts are a downstream plant metric that also depends on turbine efficiency, condenser performance, ambient conditions, parasitic consumption and design margins. The performance guidance notes that resource temperature, ambient conditions, fouling, wear and design margins can move actual output away from design even when steam supply is adequate.
Calculate level, percentage and cumulative variance
For each period, calculate the level difference first:
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Absolute variance = actual − forecast
Then calculate the relative difference:
Percentage variance = (actual − forecast) ÷ forecast × 100
A negative result indicates a shortfall; a positive result indicates production above the base case. Always display the forecast value beside the percentage, because a small absolute change can create a large percentage when the forecast is small.
Use cumulative and rolling measures
Cumulative variance is the sum of period variances when periods have equal duration and a consistent rate basis. For irregular sampling, integrate the rate over time (for example, tonnes per hour multiplied by operating hours). Report cumulative lost steam or energy in addition to the average percentage so a reader can see both the size and persistence of the gap.
Plot rolling 30-, 90- and 365-day actual-versus-forecast values where data density permits. A single low month may reflect an outage; a steadily widening 365-day gap is evidence of a trend. Mark every make-up-well connection and major workover on the chart.
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Suppose a forecast calls for 100 tonnes per hour at the agreed separator boundary and the dated actual is 90 tonnes per hour for the same operating hours. The absolute variance is −10 tonnes per hour and the percentage variance is −10%. If the plant operated 720 hours in that month, the implied gross shortfall is 7,200 tonnes for the period. That arithmetic is illustrative; a project report must use measured hours, quality and the agreed boundary.
Decompose the gap instead of assigning it to the reservoir by default
Use a bridge from forecast steam or energy to actual plant output. Quantify each item where measurements support it and label the remainder as unallocated.
Reservoir pressure and enthalpy
Lower wellhead pressure can reduce well deliverability and turbine-inlet pressure. Lower enthalpy or steam quality can reduce energy even when mass flow appears stable. Compare pressure, temperature, enthalpy and quality against the forecast assumptions for the same wells and dates. If wellhead pressure is proprietary or missing, state that the reservoir attribution cannot be independently verified.
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Natural decline
Separate the decline of existing wells from a planned make-up-well contribution. Fit a decline model to a consistent well cohort rather than mixing new wells, tests and shut-ins into one series. Decline is a trend, not a one-month variance.
Well availability and scaling
Count lost operating hours, workovers, scaling, mechanical failures and test periods. A well producing zero while shut in is not evidence of zero reservoir capacity. Where scaling restricts flow, record the onset, intervention and post-intervention rate so the effect is not misclassified as natural decline.
Reinjection and field-water balance
Compare injection rates and pressures with the base case. Changes in reinjection location or rate can affect pressure support and breakthrough risk. Treat this as a reservoir-management variable, not simply as an outage.
Steam gathering and separation
Check pressure and flow at the wellhead, gathering header, separator and turbine inlet. A growing difference between those points identifies field piping, separator capacity, liquid carryover or pressure-drop constraints.
Turbine, condenser and auxiliary systems
If steam reaches the turbine boundary at the forecast rate but MW is low, inspect turbine availability, condenser backpressure, fouling, wear, parasitic loads and ambient temperature. The performance guidance specifically lists resource temperature, ambient conditions, fouling, wear and design margins as drivers of output away from design.
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Tag grid instructions, contract limits and operator curtailment separately from equipment outages. Curtailment lowers delivered energy without demonstrating a steam-field shortfall.
Test the decline model, including model-form sensitivity
When the series is long and consistent enough, fit at least exponential and harmonic decline forms and compare out-of-sample error. Use a training period to estimate parameters and a later period to test the forecast; do not select the model solely because it fits historical points best.
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A World Geothermal Congress case reported 5.4% annual exponential decline versus 3.8% annual harmonic decline. The study used the decline result to forecast future well performance and plant capacity. Those percentages are case-specific, not a universal geothermal rate.
Another World Geothermal Congress reservoir-forecast case reported 4.9% modeled decline against 5% observed natural decline. Present both the model estimate and observed result, with the well cohort, dates and operating conditions that produced them.
For each model, report parameter uncertainty, residual patterns, the out-of-sample error and the effect on plant capacity. If make-up wells are included, show a natural-decline case without additions and a separate schedule that adds each well at its actual connection date.
Keep plant design, field supply and operating performance distinct
Use three linked but separate reconciliations:
- Reservoir and well reconciliation: forecast versus actual pressure, enthalpy, quality and well deliverability.
- Field and gathering reconciliation: wellhead flow versus separator and turbine-inlet flow, including line and separator constraints.
- Plant reconciliation: turbine-inlet steam versus gross and net MW, accounting for efficiency, condenser conditions, parasitics, outages and ambient temperature.
A California Energy Commission project page reported an 80 MW design and 69 MW output as of January 2021 because of reduced steam pressure. That example illustrates why design MW should not be treated as a direct steam forecast or why a reduced MW figure should automatically be labeled a reservoir failure.
Likewise, a JICA 2017 example described a 70 MW project, an average 8.6 MW contribution per production well, a 90% plant factor and a 3% annual steam-production decline. Those are planning assumptions for that example, not benchmarks that can be transferred to another field without matching resource and plant conditions.
Independent reader supportYour contribution helps us test, update, and keep practical guides available for everyone.Interpret test data without confusing thermal extraction and steam production
Short tests can validate equipment or resource behavior but do not automatically establish an annual steam trend. A California Energy Commission report in 2026 described a 30-day test at 330 gallons per minute, an outlet temperature of about 311°F (155°C), and 7.4 MW of thermal extraction. The test’s flow and thermal-extraction metrics must be kept distinct from a project’s steam mass-flow forecast unless the report explicitly defines an equivalent steam-energy conversion and boundary.
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For any test, record test duration, stabilized hours, inlet and outlet conditions, pressure, fluid phase, instrumentation and whether the result is gross or net. Compare only with a forecast built on the same test boundary and thermodynamic basis.
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Report uncertainty and decision thresholds explicitly
Publish a base, downside and upside case. Each case should state:
- the decline form and rate;
- the well count and make-up-well timing;
- pressure, enthalpy and quality assumptions;
- availability, outage and curtailment assumptions;
- the boundary (wellhead, separator, turbine or net plant);
- the confidence range or other uncertainty treatment.
Mark each input as measured, calculated, inferred or assumed. A pressure value inferred from a plant model should not have the same visual status as a calibrated wellhead gauge.
There is no universal geothermal steam-variance tolerance established by the cited literature. Use the project’s power-purchase agreement, financing model, reserve policy or board-approved trigger. Define escalation levels such as an observation band, an investigation band and a corrective-action band, but do not present those bands as industry-wide standards.
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Use a repeatable monthly review workflow
- Freeze the boundary: write the exact stream, pressure, quality and gross/net convention being compared.
- Close the data period: export well, injection, plant, outage and curtailment records with timestamps.
- Validate status codes: reconcile producing, test, shut-in, injection and unavailable wells with operator logs.
- Normalize units: convert mass, energy, pressure and temperature to the project’s standard units.
- Reconcile well to plant: explain every material difference between wellhead, separator and turbine measurements.
- Calculate variance: show absolute, percentage, cumulative and rolling 30-, 90- and 365-day results.
- Decompose causes: quantify reservoir, well, gathering, plant, ambient and curtailment contributions.
- Refresh decline models: fit exponential and harmonic forms when data support them and test on held-out periods.
- Update scenarios: revise base, downside and upside cases only through documented assumptions.
- Record decisions: compare the result with the project-specific tolerance and assign an owner and due date for each unresolved cause.
What makes projects difficult to compare
Cross-project comparisons are limited by proprietary wellhead-pressure data, different separator pressures, steam-quality conventions, well-status definitions, plant boundaries and make-up-well schedules. A reported percentage decline may describe natural production from existing wells, total field output including additions, or net plant energy after outages. Put those definitions beside every number.
Use comparisons only along matched axes: gross versus net steam, wellhead versus turbine boundary, mass flow versus energy, base versus downside or upside decline, natural decline versus the make-up-well plan, and reservoir availability versus plant availability. If a comparable value is not established, report it as “not stated” and name the source and date rather than filling the gap with a proxy.
Minimum contents of a defensible variance report
- A boundary statement and diagram from wellhead to plant output.
- A dated well-level actuals table with status, flow, pressure, temperature, enthalpy, quality, injection and operating hours.
- The forecast version, issue date and assumptions.
- Unit conversions and gross/net treatment.
- Absolute, percentage, cumulative and rolling variances.
- A cause bridge separating reservoir, wells, gathering, plant, ambient conditions and curtailment.
- Decline-model forms, rates, out-of-sample errors and make-up-well treatment.
- Measured-versus-inferred input flags and uncertainty ranges.
- The project-specific decision threshold and follow-up actions.
With those elements, the report answers the three practical questions separately: whether the field is delivering the steam promised, how large the gap is against the base case, and whether the gap originates in the reservoir, the wells or the power plant.
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