Dune Oil’s Case for Horizontal Drilling in Turkey’s Carbonate Play

Every other operator in Turkey’s Zagros basin drills straight down into a thin carbonate reservoir and pumps oil to surface with an electric submersible pump. Dune Oil Corp. (CSE: DUNE), rebranded from Trillion Energy International in 2026, is betting that drilling sideways changes the economics entirely. The company holds a 29% working interest in Block M47 in southeastern Turkey’s Gabar oil fairway, a basin where recent discoveries have established regional production exceeding 80,000 bbl/d from analogous carbonate plays. Dune’s strategy is not to drill more vertical wells than its neighbours; it is to introduce horizontal wellbore geometry that no operator in the region has systematically deployed at scale. This analysis examines the technical logic behind Dune Oil’s horizontal drilling thesis in Turkey, the phased plan to test and de-risk it, the cost structure created by its partner network, and the unresolved questions that will determine whether this approach represents a genuine competitive edge or a capital allocation risk.

Why Turkey’s Zagros basin is under-optimised and what that means for investors

The Gabar oil fairway in southeastern Turkey sits within the Zagros fold belt, a geological province that has already proven its commercial credentials. Regional production from analogous Mardin and Beloka carbonate plays exceeds 80,000 bbl/d, a figure that confirms basin-level commerciality rather than defining its ceiling.

Kurdistan oil flows into Turkey through the Iraq-Turkey Pipeline represent the broader regional supply context within which the Gabar fairway operates; any sustained resumption of cross-border volumes can affect regional infrastructure utilisation, local service costs, and the competitive intensity facing smaller working interest operators in southeastern Turkey.

Regional production from analogous Mardin and Beloka carbonate plays in the Gabar fairway currently exceeds 80,000 bbl/d, establishing the basin as a proven commercial oil province.

Gabar field record production figures published in August 2026 confirmed daily output reaching 83,300 barrels, a basin-level data point that contextualises the 80,000 bbl/d threshold Dune references as its regional commercial benchmark.

The primary reservoir target on Block M47 is the Mardin Group limestone and dolomite, a carbonate sequence approximately 300 metres thick in gross terms. The highest-quality pay, however, concentrates near the top of the section: an 8-9 metre interval of adequate porosity and permeability. The Çetinkaya-1 (C1) discovery well encountered light oil in the Mardin Group in 2025, confirming the target interval on Dune’s acreage.

The defining characteristics of the regional play establish both the opportunity and its current limitation:

• Confirmed basin production exceeding 80,000 bbl/d from carbonate reservoirs
• Primary target: Mardin Group carbonate, approximately 300 metres gross thickness
• Best pay concentrated in an 8-9 metre interval near the top of the Mardin section
• All existing operators use vertical wells with electric submersible pumps (ESPs) for lift
• No operator has systematically deployed horizontal completions at scale

Every producing well in the surrounding area perforates this thin interval vertically and relies on an ESP to overcome low reservoir pressure. The uniformity of this approach is not merely an industry standard. It is a gap, and Dune’s entire thesis is built around exploiting it.

The geometry argument: how a horizontal wellbore turns 8 metres into a productive asset

A vertical well perforating 8-9 metres within a 300-metre carbonate column has a fundamentally restricted drainage footprint. Regardless of how productive the rock itself may be, the wellbore contacts only a narrow vertical slice of the pay zone, limiting deliverability at the surface.

The arithmetic of a horizontal lateral changes this constraint. A wellbore drilled laterally within that same 8-9 metre interval for 300-500 metres multiplies reservoir contact by an order of magnitude through geometry alone, before any stimulation or fracturing. The surface area exposed to producible rock increases from metres to hundreds of metres.

Management expects lateral wells to produce approximately 4x the output of a comparable vertical completion in the same pay zone, a figure consistent with international carbonate analogues where horizontals are properly placed.

Critically, the Mardin carbonate is not an ultra-low-permeability shale. Dune’s bet is that the rock already possesses sufficient natural permeability and fracture networks to deliver the productivity uplift without a North American-style multi-stage hydraulic fracturing programme. The planned completion method uses open-hole packers rather than shale-style stimulation, a simpler and less capital-intensive approach that relies on the reservoir’s inherent flow characteristics.

International case studies in Middle Eastern and North African carbonate fields support the principle: horizontal wells in conventional carbonates have delivered material productivity improvements when laterals are accurately placed within the target interval. Whether the approximately 4x figure is achievable with open-hole completions in the Mardin specifically remains the central unresolved technical question.

Horizontal well execution in conventional carbonate reservoirs requires directional drilling precision that most basins in the Middle East and Central Asia have not yet standardised, and the operational lessons from analogous programmes in other geologies are increasingly informing how first-mover operators like Dune sequence their learning curves.

From re-entry to pad development: Dune’s three-phase execution roadmap

The horizontal thesis is ambitious, but the execution plan is sequenced to test before it commits. Three phases gate capital deployment against progressive technical validation:

1. Phase 1, C1 sidetrack and vertical pilot: Re-enter the existing C1 wellbore (originally halted approximately 100 metres above target due to lost circulation in 2025), complete a managed-pressure sidetrack with open-hole packers, cement and perforate the 8-metre target zone, and install an ESP. This phase generates early production data and cash flow before any horizontal capital is deployed.
2. Phase 2, seismic de-risking: Acquire a 40 km 2D seismic survey (targeted for summer 2026) and conduct vertical seismic profiling (VSP) within the C1 wellbore to constrain reservoir structure and pay geometry for lateral well design.
3. Phase 3, pad-based horizontal development (contingent): Drill 2-5 or more laterals from single surface pads into the thin pay interval, with lateral lengths of 300-500 metres refined using Phase 2 data. This phase proceeds only if Phase 1 confirms commercial reservoir performance.

Scott Lower, President of Dune Oil, indicated that C1 re-entry and testing were targeted within approximately 2-3 months of the interview, with first production anticipated within approximately 6-12 months and lateral drilling to follow initial vertical validation.

Phase 2 seismic program and its role in lateral well design

The seismic programme is not an optional refinement. Placing a 300-500 metre lateral within an 8-9 metre target interval demands precise structural control. Drifting even a few metres out of pay renders the lateral unproductive.

The 40 km 2D survey and C1 VSP data together are intended to characterise the structure, reservoir extent, and pay geometry with enough resolution to guide lateral well designs confidently. The quality and coverage of this data will directly determine at what stage Dune can sanction the pad development programme and how many laterals can be committed per surface location.

The cost advantage built into the partner structure

Block M47’s three-party ownership creates a cost structure that, if it holds in practice, could materially improve horizontal well economics. The drilling contractor partner’s rig contribution is estimated by management to reduce overall programme drilling costs by approximately 40%, though this figure has not been independently verified in external disclosures.

Management estimates that the drilling contractor partner’s rig contribution reduces overall programme drilling costs by approximately 40%. This figure is based on management commentary and has not been independently verified in external disclosures.

The economic logic is straightforward: having a 20-rig operator as a working interest partner provides rig access at contributor rates rather than market charter rates. For horizontal wells specifically, where longer wellbores, directional tooling, and higher technical demands raise costs relative to vertical drilling, a 40% rig cost reduction is proportionally more valuable than it would be in a vertical-only programme.

The governance layer beneath this advantage warrants attention. With only 29% working interest, Dune’s ability to direct horizontal design and completion decisions depends on the formal terms of the joint operating agreement and the continued cooperation of the 51% non-operating majority partner. The majority partner has reportedly agreed to defer operational decisions to Dune, but the formal documentation of this arrangement will materially affect Dune’s capacity to advance a non-standard horizontal programme through a majority-owned asset.

What Chapman’s resource evaluation actually says about the commercial upside

The Chapman Petroleum Engineering Ltd. independent evaluation (effective 31 December 2025) provides the quantitative floor for the investment case. The evaluation is built on a vertical development programme and does not yet capture horizontal upside.

Key Chapman evaluation metrics for the North Prospect:

• 2C contingent resource: 27.6 million barrels net to Dune (29% WI)
• Unrisked NPV10: US$733.5 million net to Dune
• Total unrisked prospective resources across all prospects: 51.6 million barrels net
• Chance of commerciality on the North Prospect: 81%
• Vertical development campaign: 82 wells, peak rate 8,816 bbl/d net to Dune, net CAPEX approximately US$90 million, modelled to 2030 peak

These figures describe the documented base case: what the asset could deliver under conventional vertical development alone.

The investment case for early-stage oil development programmes like Dune’s is shaped not just by reservoir economics but by the macro price environment: a structural oil supply deficit driven by years of underinvestment in conventional production provides a more supportive backdrop for higher-cost horizontal drilling programmes than a market in cyclical surplus would.

Why horizontal upside is not yet in the resource numbers

Chapman’s evaluation models the 82-well vertical programme. Horizontal wells would require separate resource bookings contingent on demonstrated commercial performance, meaning the approximately 4x productivity thesis, if validated, sits entirely above the current evaluated numbers.

The Petroleum Resources Management System defines the classification criteria that independent evaluators like Chapman Petroleum Engineering must apply when assigning 2C contingent resource status and chance of commerciality estimates, including the specific conditions under which horizontal well productivity uplifts could be separately booked as contingent volumes.

This gap is both a limitation and a potential catalyst. The current resource figures do not reflect the value that horizontal development could add, but any future horizontal drilling announcement will be measured against a base case that investors can already size. If lateral wells deliver on the productivity thesis, the implication is fewer total wells needed to reach comparable production targets, with higher per-well recovery and potentially improved project returns against Chapman’s US$90 million net CAPEX base.

Five questions that will determine whether the horizontal thesis is real

The thesis is coherent, but coherence is not confirmation. Five unresolved variables will determine whether Dune’s horizontal approach delivers on its technical promise. Each is testable, and the phased programme is designed to address them in sequence.

1. Reservoir deliverability at C1: Flow-test data, VSP, and pressure-transient analysis from the sidetrack will determine whether the 8-9 metre pay can sustain rates and pressures that justify more expensive horizontal wells. This is the nearest-term gate.
2. Technology translation without heavy fracturing: Whether the approximately 4x productivity uplift is achievable with open-hole completions and packers, rather than multi-stage hydraulic fracturing, is the central unresolved technical question. The Mardin carbonate’s natural permeability and fracture networks must do the work that fracturing does in shale plays.
3. Operational control under split ownership: Dune holds 29% working interest. Practical control over horizontal design and completion decisions depends on formal joint operating agreement terms and the continued cooperation of the 51% non-operating majority partner.
4. Capital adequacy and financing capacity: Chapman’s vertical campaign alone implies approximately US$90 million net CAPEX. Horizontal wells raise per-well costs while increasing per-well reserves potential. Dune must demonstrate balance sheet and financing capacity to fund the learning curve inherent in introducing first-of-kind horizontal drilling to this basin.
5. Seismic data quality: The 40 km 2D seismic programme and any VSP data from C1 must adequately characterise structure and pay geometry to guide lateral placement within the narrow 8-9 metre target. Data quality directly constrains how confidently horizontal well designs can be committed.

The incoming COO, a US-based executive with international oil and gas experience and specific lateral drilling expertise, represents a direct operational response to the technology translation risk. Expertise, however, does not resolve the underlying question of whether the Mardin carbonate will perform as modelled under lateral completion.

The first two questions are near-term and data-dependent. The last three require ongoing monitoring regardless of early results.

The horizontal thesis has internal logic, but the basin still has to answer

The geometry is sound. A horizontal lateral within an 8-9 metre pay zone mathematically multiplies reservoir contact in a way that vertical wells cannot replicate. The cost structure, if the 40% drilling cost reduction holds through a horizontal programme, could materially improve individual well returns against Chapman’s base case. The phased execution plan shows appropriate sequencing discipline, gating horizontal capital behind vertical validation data.

None of this resolves the central empirical question: how the Mardin carbonate will actually perform under lateral completion. That answer arrives with C1 production test results and the 40 km seismic programme outcomes, likely the two most consequential data points for this investment case in 2026.

What Dune has assembled, incoming lateral drilling expertise, a 20-rig drilling partner, an 81%-assessed North Prospect, and a basin producing over 80,000 bbl/d from analogous carbonates, is a legitimately differentiated setup in an emerging Turkish oil fairway. Whether differentiation translates to commercial validation remains conditional on results that have not yet arrived.

Global oil flow disruption at major chokepoints introduces pricing asymmetry that can materially shift the economics of landlocked basin production, and operators in southeastern Turkey sit within a geography where regional export route constraints and Brent-WTI differentials can affect realised prices independently of any reservoir performance outcomes.

This article is for informational purposes only and should not be considered financial advice. Investors should conduct their own research and consult with financial professionals before making investment decisions. Financial projections and resource estimates referenced are subject to market conditions and various risk factors. Forward-looking statements, including management’s productivity expectations and cost estimates, are speculative and subject to change based on operational results and market developments.