Cue Energy’s Palm Valley PV14 Well Flows 3.2 TJ/d but Water Risk Clouds Output
Key Takeaways
- PV14 flowed at about 3.2 TJ/d on a 100% JV basis, peaking at 3.6 TJ/d, from the Pacoota P1 Sandstone without hydraulic stimulation.
- Water in the wellbore is the key risk, and the company says sustained production may not be possible if it can't be isolated or managed.
- Cue holds just 15% of Palm Valley permit OL3, and the announcement discloses no Cue-net production figure.
- Commissioning is targeted by the end of October 2026, subject to completion and tie-in, with the rig then moving to PV15.
- The 3.2 TJ/d rate had not stabilised, so it is a starting data point rather than a forecast, and sustained production is needed for reliable estimates.
PV14 flow test delivers ~3.2 TJ/d at Palm Valley (ASX: CUE)
Cue Energy Resources Limited (ASX: CUE) has given an update on the PV14 well in the Palm Valley gas field, with the PV14 gas flow test reaching a final estimated rate of approximately 3.2 TJ/d on a 100% joint venture (JV) basis. PV14 reached a total depth of 2,942m measured depth (MD), equivalent to 2,096m true vertical depth (TVD), and completion operations are underway.
Flow peaked at approximately 3.6 TJ/d before settling back to around 3.2 TJ/d. TJ/d means terajoules per day, a standard measure of gas volume.
Cue holds a 15% participating interest in Palm Valley permit OL3. The announcement does not disclose a Cue-net figure, so all rates here are on a 100% JV basis.
The result is encouraging, but water is an open question. Evidence of water appeared in the wellbore after the flow periods, and the company says its source and likely production impact are yet to be determined.
Flow test results at a glance
The well was flowed through the drilling rig before completion operations began. A choke is a restriction that controls how much gas can pass through, and different sizes produce different rates.
| Flow period | Choke | Estimated gas rate | Notes |
|---|---|---|---|
| Initial 90 minutes | ¾-inch | ~3.2 TJ/d | Not stabilised and still slowly increasing at a flowing tubing-head pressure of 210 psi |
| Second 90 minutes | ½-inch | 2.3 TJ/d | Flow rate reached 2.3 TJ/d |
| Reopened after 90-minute shut-in | ¾-inch | ~3.6 TJ/d | Subsequently declined, together with flowing tubing-head pressure, to approximately the end-of-initial-test level (~3.2 TJ/d) |
All rates are estimates on a 100% JV basis. Because the initial rate had not stabilised, the figures are a snapshot rather than a settled result.
Well and reservoir details
The key facts from the announcement:
- Drilling began in late July 2026.
- Open-hole packers were installed to isolate anticipated water-entry points, with the shallowest set at 2,729m MD (2,041m TVD).
- The tested interval ran from 2,102m to 2,729m MD in the Pacoota P1 Sandstone.
- No water or oil was recovered at surface during the initial flow period.
- The well has not been hydraulically stimulated.
Laboratory analysis of the PV14 gas composition is not yet complete. Current production from the P1 reservoir contains approximately 98% hydrocarbons with minimal inert content, but PV14 gas composition may differ.
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Understanding tight, naturally fractured gas reservoirs
Palm Valley is a tight, naturally fractured reservoir. In plain terms, the rock holds gas but lets it move slowly, and natural cracks in the rock provide the main pathways for flow.
That matters for how you read a test result. In reservoirs like this, a rate that has not stabilised can still be changing, so early numbers are indicative only.
Fractures can also carry water into a well. If water enters through connected fractures, it can limit how much gas the well can produce.
The company says a period of sustained production will be required before reliable longer-term production estimates can be made. For you as an investor, that means 3.2 TJ/d is a starting data point, not a forecast.
Water evidence and what could happen next
No water was recovered at surface during the flow periods. Subsequent flow-back operations, however, showed evidence of water in the wellbore, and the source and likely production impact have not yet been determined.
The company outlines two possibilities:
- The water may be standing or perched water that reduces as the well cleans up, as occurred at PV12.
- The water may be entering through connected fractures within the open reservoir interval and require further isolation work.
The company also states that if water remains and cannot be effectively isolated or managed, sustained gas production from PV14 may not be possible. That is the key risk to watch, and the outcome of completion work should show which scenario applies.
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Commissioning targeted by end of October 2026, PV15 next
The path forward is laid out in the announcement:
- PV14 is planned to be completed as a gas producer and connected to the Palm Valley gathering system.
- Subject to successful completion and tie-in activities, commissioning is targeted by the end of October 2026.
- Following completion of PV14 activities, the rig is planned to move to PV15, the second well in the campaign.
The field’s existing processing infrastructure has gross joint venture sales capacity of approximately 14 TJ/d. That figure represents infrastructure capacity and is not a production forecast. Actual production will depend on individual well performance and decline from existing wells.
If successfully completed and commissioned, PV14 and PV15 may increase Palm Valley’s available production capacity. That is the investment significance of the campaign, though the water question must be resolved first.
Palm Valley permit OL3 participants are Central Petroleum (NT) Pty Ltd (Operator, 50%), Echelon Palm Valley Pty Ltd (35%) and Cue (15%).
Cue’s FY2026 revenue was $50.3 million, generated from its interests in the Mahato and Sampang PSCs in Indonesia, the Mereenie, Palm Valley and Dingo fields in onshore Australia, and the Maari field offshore New Zealand.
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