What is workover candidate selection?

It is the process of identifying which wells, and which intervention, will most economically recover otherwise-lost production. It combines geoscience, reservoir engineering and production engineering to move from a measured production gap to a ranked, risked work program.

How do you choose workover candidates?

Quantify the production gap (potential minus actual rate), diagnose the cause across G&G, reservoir and production engineering (skin, liquid loading, water, depletion), map each diagnosis to a candidate intervention, then rank by risked value.

What is the production gap?

The production gap is the difference between a well's potential rate — estimated from analog type-wells, the well's own history, and nodal analysis — and its current actual rate. It is the recoverable upside a workover targets.

How are workover candidates ranked?

By expected monetary value, EMV = Ps·NPV − (1 − Ps)·Cfail, which balances the probability of success, the value if it succeeds, and the cost if it fails, so limited budget goes to the highest risk-adjusted return.

What interventions does candidate selection consider?

Artificial-lift installation or change, sand control, water shut-off, stimulation and de-skinning, recompletion, and zone changes — each matched to the diagnosed cause of the well's underperformance.

From exploration well to development plan — the reservoir and petroleum engineer’s role

● Field Development·June 19, 2026·18 min read

An exploration well is one of the most expensive, highest-uncertainty decisions a company makes — and it is drilled only once. The reservoir and petroleum engineer is not a post-well analyst who arrives after the rig leaves; they shape the well from the first objective statement, through the data acquired while drilling and testing, to the development plan that turns a geological prospect into an investable project. This article traces that role across the exploration well lifecycle: planning, execution, and development.

Figure 1. The exploration well lifecycle. Reservoir and petroleum engineering deliverables run through all four phases — from the pre-drill data-acquisition plan, through the data captured while drilling and testing, to the reserves and the field development plan that supports the final investment decision.

The engineer across the lifecycle — the big picture

Exploration and appraisal is a sequence of decisions under deepening but never-complete knowledge. The reservoir engineer owns the subsurface volumes, the recovery, and the forecasts; the petroleum (or production) engineer owns well productivity, completion, and testing. Between them they answer the two questions an investment rests on: how much is there, and will it flow at a rate that pays. Everything below is in service of answering those two questions well enough, early enough, to commit capital responsibly.

Phase 1 — Planning the exploration well

Planning starts not with the drill bit but with the question the well must answer. The engineer writes the well objectives: prove the presence of hydrocarbons, establish reservoir quality and fluid type, and — critically — gather what is needed to size a potential development. From those objectives comes a data-acquisition plan: the logs, cores, fluid samples, pressure points, and well tests that will convert an unknown interval into calibrated reservoir properties.

Before the well is drilled, the engineer produces a pre-drill volumetric estimate. It is never a single number; every input is uncertain, so the volumes are expressed as a distribution.

Volumetric oil in place (field units, STB) N = 7758 · A · h · φ · (1 − S_w) / B_oi

A is area (acres), h net pay (ft), φ porosity, S_w water saturation, B_oi the initial oil formation volume factor. Recoverable volume then applies a recovery factor: reserves = N · RF. For gas, the equivalent GIIP uses B_gi. Each input is entered as a range.

Figure 2. Pre-drill resource is a distribution, not a number. Gross rock volume, net-to-gross, porosity, saturation, formation volume factor and recovery factor are each ranges; combined by Monte Carlo they give a P90 (conservative), P50 (median) and P10 (optimistic) resource.

The engineer also supplies the subsurface inputs to well design. A pore-pressure and fluid prognosis — expected pressures, temperature, and fluid type by depth — feeds the drilling engineer’s casing and mud-weight programme. Reservoir and drilling disciplines meet here: the reservoir side predicts the pressures, the drilling side keeps the well within the safe window between them.

Figure 3. The mud-weight window. Pore pressure sets the lower bound (below it the well flows uncontrolled); the fracture gradient sets the upper bound (above it the formation breaks down). The engineer’s pressure and fluid prognosis is what lets the well be designed to stay safely between them.

Finally, planning includes test design — what a drill stem test must measure if the well finds pay — and an economic screen: the minimum field size that would be commercial. If the pre-drill P50 sits below that threshold, the prospect may not be worth drilling at all. Framing that trade-off is a reservoir-engineering judgement, not an afterthought.

Phase 2 — Executing the drilling: the well as a data event

Because an exploration well is drilled once, execution is dominated by one imperative: capture the right data. The engineer is active throughout — picking coring points, deciding whether and where to test, and making the total-depth call — because those decisions cannot be repeated later.

Figure 4. The exploration well is a one-time data event. Mud logging and LWD, wireline logs, core, fluid samples, formation pressures and the well test each resolve a different piece of the reservoir. Together, and only together, they yield calibrated properties and a verdict on producibility.

While drilling, mud logging and logging-while-drilling (LWD) give the first evidence — shows, gas readings, lithology, and real-time pore-pressure indicators that keep the well safe. Wireline logs (the triple-combo, plus NMR, sonic and image tools where justified) are interpreted into porosity, water saturation, net pay and fluid contacts. Core, routine and special, measures permeability, capillary pressure, relative permeability and wettability directly, calibrating what the logs infer. Fluid samples feed the PVT analysis — formation volume factor, solution gas-oil ratio, viscosity, composition — while formation pressure points give gradients that locate the fluid contacts independently of the logs.

The most decisive acquisition is the well test (DST): flowing the well to prove it can produce, and to measure how well.

Radial inflow — deliverability & productivity index q = k·h·(p̄ − p_wf) / [ 141.2 · B · μ · ( ln(r_e/r_w) + s ) ] → J = q / (p̄ − p_wf)

The productivity index J captures how much rate each unit of drawdown buys; the skin s captures near-well damage or stimulation. A test that establishes J is what turns “there is oil here” into “this well can make so many barrels a day.”

Permeability-thickness from a Horner build-up k·h = 162.6 · q · B · μ / m

where m is the slope of the pressure build-up plotted against Horner time. The same build-up yields skin, average reservoir pressure, and evidence of nearby boundaries — a remarkable amount of reservoir description from shutting a well in and watching the pressure recover.

Figure 5. What a well test delivers. The flow period gives the inflow performance relationship — productivity index and open-flow potential. The build-up, analysed on a Horner plot, gives permeability-thickness (kh), skin, average pressure and boundary effects.

Phase 3 — Post-well evaluation and the development plan

With the data in hand, the engineer integrates it into a picture of the reservoir: a static model (structure, properties, contacts) and, where warranted, a dynamic model that can be history-matched and used to forecast. The pre-drill volumetrics are revised — now anchored by real well control — and the resource is reclassified.

Reserves classification follows the Petroleum Resources Management System (PRMS): as commerciality is established, quantities move from prospective resources toward contingent resources and, once a development project is defined and sanctioned, toward reserves (1P/2P/3P). What lets a volume be booked as a reserve is not just its presence but demonstrated producibility and a viable development — which is exactly what the test and the plan provide.

Concept selection is where reservoir engineering drives the development. How many wells, of what type, in what pattern? What recovery mechanism — natural depletion, water or gas injection, or a later enhanced-recovery scheme? Each concept is turned into a production profile using material balance, decline analogues, or full simulation, and each profile feeds the economics.

Figure 6. Concept selection produces forecasts. Natural depletion declines steeply once the drive energy is spent; pressure maintenance by injection can hold a plateau and lift recovery — at the cost of facilities. Comparing profiles, reserves and economics is how the development concept is chosen.

The output is the Field Development Plan (FDP), sometimes a Plan of Development. It is largely a reservoir-engineering document: the resource basis, the selected concept and recovery mechanism, the well count and placement, the production profile and reserves, the facility requirements, and the surveillance plan that will let the model be checked against reality once production starts. It is the basis on which the final investment decision is taken. Where uncertainty remains too high to commit, the honest answer is an appraisal well — more data before more capital — rather than a premature plan.

Phase	Reservoir / petroleum engineering deliverable
Plan	Well objectives, data-acquisition plan, pre-drill P90/P50/P10 volumetrics, pressure & fluid prognosis, DST design, economic field-size screen
Drill	Real-time pore-pressure & shows, log/core/fluid acquisition calls, coring & casing points, total-depth decision, well test
Evaluate	Petrophysical & PVT interpretation, static/dynamic model, contacts, revised volumetrics, reserves under PRMS
Develop	Concept selection, recovery mechanism, well count & placement, production forecasts, Field Development Plan, input to FID

Two roles, one objective

Reservoir and petroleum engineering overlap heavily across this arc, but the emphasis differs. The reservoir engineer is accountable for volumes, recovery, forecasts and the development concept; the petroleum (production) engineer for well productivity, completion and testing, deliverability and lift. On an exploration well the handoffs are constant — the reservoir side specifies what the test must prove, the production side executes it and interprets the deliverability — and both author parts of the plan.

Figure 7. Two overlapping roles. The reservoir engineer owns the subsurface volumes and the development concept; the petroleum/production engineer owns well productivity and the completion. Well objectives, the data plan, testing and the development plan are shared ground.

Pitfalls

The recurring failures are avoidable. Drilling an exploration well without a clear, uncertainty-driven data-acquisition plan wastes a once-only opportunity. Not testing a discovery when a test was feasible leaves producibility unproven and reserves unbookable. Reporting a single deterministic volume hides the range that actually drives the decision. Selecting a development concept before the recovery mechanism is understood commits facilities that may not fit the reservoir. And skipping the surveillance plan means the forecast can never be checked — so the next well repeats the same guesses.

Closing

The through-line is simple: an exploration well is where a geological idea is tested against rock and fluid, once, at great cost — and the reservoir and petroleum engineer is the discipline that decides what that test will reveal and what is done with the answer. Plan for the data you will need, capture it while you can, evaluate it honestly, and let the development plan follow the reservoir rather than the other way around. That discipline is what separates a lucky discovery from a well-run field.

References

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Frequently asked questions

What is the reservoir engineer's role in exploration well planning?

They translate subsurface uncertainties into well objectives and a data-acquisition plan — which logs, cores, fluid samples, pressure points and well tests are needed to reduce the uncertainties that matter for a development decision — and provide the pre-drill volumetrics and the pressure and fluid prognosis that shape the well design.

Why is an exploration well called a data event?

Because it is usually drilled only once. The data captured while drilling and testing — logs, core, fluid samples, formation pressures, well test — is the only direct evidence of the reservoir, so the acquisition plan decides what will ever be known about it.

What does a drill stem test (DST) tell you?

Flowing the well gives deliverability (productivity index and absolute open-flow potential) and, from pressure build-up, permeability-thickness (kh), skin, average reservoir pressure and nearby boundaries, plus representative fluid samples — confirming the zone can actually produce.

How are resources estimated before drilling?

Probabilistically: gross rock volume, net-to-gross, porosity, hydrocarbon saturation, formation volume factor and recovery factor are each entered as ranges and combined by Monte Carlo into a P90/P50/P10 distribution rather than a single deterministic number.

What is a Field Development Plan (FDP)?

The reservoir-engineer-led document that sets out the resource basis, the chosen development concept and recovery mechanism, well count and placement, the production profile, reserves, facility requirements and the surveillance plan — the basis for the final investment decision.