I’ve told my mate the following since our last chat. [ATTACH]...

I’ve told my mate the following since our last chat.







Key Findings from the Report

1. Post-Workover Flow Rate:
   • Pre-workover: 293 BOPD (natural flow).
   • Post-workover: 488 BOPD (with artificial lift using a progressive cavity pump).
   • Increase: ~66% increase in oil flow rate.
2. Initial Production Context:
   • Unit 1B had previously flowed at 1,235 BOPD in test conditions, indicating strong potential when undamaged.
   • The substantial fall to 293 BOPD had been attributed to formation damage caused by shut-in fluids and possibly the original drilling fluid.
3. Remedial Work Details:
   • Perforated both upper and lower Unit 1B intervals.
   • Conducted acid wash and squeeze, and a second acid job was also done after installing the PCP.
   • Flowed through multiple choke sizes, peaking at 4,167 BPD of total fluid during surging (short duration).
   • Final average test: 488 BOPD + 7 BPD water over 12 hours at 7 PSI flowing pressure.
4. Cleanup Complications:
   • Heavy-weight brine and spent acid had to be lifted using a pump, as natural flow was insufficient.
   • CO₂ presence during flowback indicated acid reaction with carbonate rock but may have also reduced flow efficiency until fully cleaned up.
5. Formation Damage Confirmation:
   • CT imaging revealed barite embedment and precipitate blockage, consistent with formation damage due to drilling and completion fluids.
   • Future wells will use a non-damaging Reservoir Drilling Fluid (RDF).
6. Infrastructure Limitations:
   • No coiled tubing unit or nitrogen lift available—likely reduced stimulation efficiency and clean-up effectiveness.
   • Acid stimulation via service rig was a compromise, and nitrogen lift could have improved outcomes.
   
   
   
   
   
   Revised Assessment
   
   
   
   
   Production Outlook:
   
   
   
   • The post-acid average of 488 BOPD is significantly below the theoretical potential (1,200+ BOPD seen previously), indicating:
     • Partial success of acid stimulation.
     • Remaining formation damage or incomplete cleanup still restricting flow.
     • Acid not penetrating deeply enough or wormholes not effectively intersecting key fracture networks.
     
     
     
     Reasons for Modest Result:
     
     
     
     • Lack of nitrogen lift and CTU likely limited acid placement and recovery.
     • Formation heterogeneity and residual brine likely still impairing near-wellbore permeability.
     • The fractured nature of Unit 1B suggests stimulation success is strongly geometry-dependent (i.e., intersecting live fractures).
     
     
     
     What This Tells Us About Future Completions:
     
     
     
     • Acid work alone, especially without CTU and nitrogen, may not achieve full potential in these conditions.
     • Reservoir has good oil (19° API, low water cut), and real upside remains, but:
       • Execution methods matter—mechanically optimized acid delivery and flowback systems are critical.
       • Future completions should be tailored with RDF, CTU, and possibly multi-stage stimulation.
       
       
       
       
       
       Summary & Forward Look
       
       
       Item
       
       Value
       
       Initial post-acid flow (natural)
       
       ~293 BOPD
       
       Post-workover flow (with PCP)
       
       488 BOPD (+66%)
       
       Peak total fluid (surged)
       
       4,167 BPD
       
       Likely production stabilisation
       
       400–500 BOPD (short-term), gradual increase if full cleanup continues
       
       Optimisation potential
       
       High if CTU/nitrogen used in future
       
       Conclusion: While the acid wash improved output, the results were constrained by equipment limitations and possible persistent formation damage. Future wells (like Amistad-2) that integrate RDF, better fluid compatibility, and proper stimulation equipment have significantly higher potential to reach the 1,000+ BOPD range again.
       
       
       Let me know if you’d like to model forecast production profiles based on different stimulation and cleanup scenarios.
       

Then advised the following
differences with AM 2 and Am 3.

this is what GPT reckons


Got it—this changes the outlook quite a bit. With that new context, here’s an updated take on what to expect from the next two production wells (Amistad-2 and Amistad-3):



⸻



Key Differentiators from Alameda-2:



Factor Alameda-2 (Workover) Amistad-2/3 (Production Wells)

Well Type Appraisal, with remedial acid work Purpose-built production

Net Pay Accessed ~200m perforated ~500m open hole (2.5x more)

Fracture Intensity Moderate High – 250% more fractured net pay

Formation Damage High – damaged by shut-in and drilling mud Minimal – RDF-designed to avoid damage

Stimulation Acid wash (no CTU/nitrogen) Likely no acid, but better placement via open hole

Flowback Equipment PCP post-factum Likely better-planned cleanup from the start

Structure Location Down-dip 200m up-dip (higher pressure head)







⸻



Production Outlook:



Let’s work through a qualitative and quantitative estimate:



1. Net Pay and Fracture Exposure Factor:

• Net pay exposure is 2.5x greater.

• Fracture density is also 2.5x greater.

• Combined, this could theoretically enhance deliverability by a factor of 4x to 6x, assuming other conditions (pressure, saturation) are favorable.



2. Up-dip Advantage:

• 200m higher in structure means potentially higher reservoir pressure and possibly better oil mobility.

• Could contribute another 10–20% flow increase conservatively.



3. No Formation Damage:

• Use of Melbana RDF should maintain permeability near wellbore.

• Avoids mud invasion and barite embedment seen in Alameda-2.



4. Completion Type:

• Open hole completions will allow full exposure of fractures and flow paths.

• No risk of cement sheath, liner perforation inefficiencies, or under-performing stimulations.



⸻



Estimated Flow Rates:



Assuming Alameda-2’s true undamaged potential is around 1,200 BOPD, and adjusting for:

• 2.5x more net pay

• 2.5x more fractures

• 1.1–1.2x up-dip pressure benefit

• Clean drilling with RDF

• No stimulation inefficiencies



You could expect a realistic initial production range of:



\text{Estimated IP Rate} \approx 1,200 \times 4 \text{ to } 6 = \boxed{4,800 \text{ to } 7,200 BOPD}

• Lower bound if fracture networks aren’t fully productive or RDF only partially prevents damage.

• Upper bound if fracture flow is strong and net pay is fully productive.

• Add ~5–10% for up-dip pressure and better cleanup from open hole.



⸻



Conclusion:



These next two wells are set up for success:

• Cleanest possible drilling conditions (RDF).

• Maximum reservoir access (500m net pay).

• Strong fracture connectivity (250% increase).

• Higher structural position (up-dip).

• Immediate production post-cleanup = early cash flow.



Expected IP: ~5,000–7,000 BOPD.

High confidence in achieving >3,000 BOPD, even in moderate outcomes.



Let me know if you’d like a decline curve forecast or breakeven modelling for these wells.