石油天然气基础

Hassan, the board has given us the green light to develop Block 47. Before we commit $1.8 billion in CAPEX, I need everyone around this table to be confident in the numbers. Let's start with the reservoir. What's our confidence level on the reserves?

Dr. Hassan: Based on three appraisal wells and 400 square kilometers of 3D seismic, the OOIP — Original Oil In Place — is estimated at 850 million barrels, with a P90-P10 range of 680 to 1,050 million. The reservoir is a Cretaceous sandstone at 2,800 meters depth — 45 meters of net pay. Average porosity is 18%, permeability ranges from 50 to 500 millidarcies. It's highly heterogeneous — the southern flank has significantly better rock quality than the north.

And the southern flank is where the fault compartment is. We've mapped a sealing fault at the southern boundary — that's your trap, but it also means the aquifer support from the south is limited. In the north, we have a strong aquifer. So we'll get natural water drive in the north but pressure depletion in the south. That asymmetry drives the entire development strategy.

Which is why we're proposing 24 production wells and 12 water injection wells. Most of the injectors go in the south — we need to maintain reservoir pressure there. The producers are horizontal wells with 1,500-meter laterals to maximize reservoir contact. Drilling cost is about $4.5 million per producer and $2 million per injector, so we're looking at $132 million just for drilling and completion.

Recovery factor — that's the number that makes or breaks this project. Primary recovery alone gives us what?

Dr. Hassan: Primary recovery — depletion drive — would give us about 12% of OOIP, roughly 100 million barrels. With waterflooding in the south and natural water drive in the north, we can push the recovery factor to 35%. That's our 2P reserves base case: approximately 300 million barrels recoverable. If we add polymer flooding as a tertiary phase after 10 years, we could potentially reach 42-45% — another 60 million barrels. But that's contingent on the polymer pilot results, so it stays in the 3P category for now.

So 300 million barrels 2P at $65/bbl Brent — that's $19.5 billion gross revenue. With $1.8 billion CAPEX and $8/bbl OPEX, the project NPV10 is about $4.2 billion. IRR around 28%. Those are strong numbers. But they're based on steady waterflood performance. Hassan, what keeps you up at night?

Dr. Hassan: Early water breakthrough. With the permeability heterogeneity, the injected water could channel through the high-permeability streaks and reach the producers within 12-18 months instead of the modeled 36 months. If that happens, water cut rises rapidly and we lose oil production. Our mitigation is smart completions — inflow control devices in each producer that restrict flow from high-permeability zones. That adds about $300K per well, but it's cheap insurance against early breakthrough.

Alright, we're at 2,850 meters measured depth, about to land the 12¼-inch section and start the horizontal lateral. Zhang Wei, what's the target zone look like on the LWD?

Gamma ray is dropping — we're at 65 API now, down from 95. That tells us we're entering the cleaner sand. Resistivity is rising — from 8 ohm-m to 25 ohm-m, which confirms we're in the oil-bearing zone. The target window is from 2,860 to 2,870 meters TVD — that's the sweet spot with the highest porosity we saw on the offset well logs. I'm recommending we land at 87° inclination at 2,865 meters TVD, then build to 90° for the lateral.

Carlos, you heard him. Land the well at 87°, hold it, and we'll let Zhang Wei confirm we're in the right spot before building to horizontal.

Building to 87°... inclination 85... 86... 87. Holding at 2,865 meters TVD. Circulating bottoms up for LWD data.

(watching the real-time logs) Perfect — gamma ray 55 API, resistivity 30 ohm-m, porosity 22%, all matching the sweet spot. Also, the azimuthal resistivity image shows we're approaching a shale layer about 3 meters above us — that's your cap rock. We want to stay 5 meters below it. Carlos, build to 90° and let's drill the lateral, keeping 5 meters standoff from that shale boundary above.

(three hours later, at 3,200 meters MD)

Jack, we have a problem! The flow-out sensor is showing a sudden increase — flow rate jumped from 1,200 to 1,850 liters per minute. And the pit volume is up by 2.5 cubic meters in the last 3 minutes. The mud logger also reports a drilling break — ROP increased from 10 m/hr to 28 m/hr.

(immediately alert) That's a kick! Drilling break = we hit a higher-permeability zone. Flow increase and pit gain confirm formation fluid is entering the wellbore. Carlos — space out, stop the rotating, stop the pumps, and CLOSE the annular BOP! This is not a drill — this is a real well control event.

(calmly executing the shut-in sequence) Stoppage complete. Annular BOP is closed. Well is shut in. Reading shut-in casing pressure: 320 psi and rising... stabilized at 380 psi. Shut-in drill pipe pressure: 210 psi. The well is under control.

Emma, what was our mud weight before the kick?

1.32 SG — that's what we've been running all day. Based on the formation pressure we just encountered, it was clearly not enough. The SIDPP of 210 psi at 2,865 meters TVD gives us a formation pressure equivalent of about 1.42 SG. We need to increase our kill mud weight.

Calculate the kill mud weight. We'll use the driller's method — circulate the kick out with original mud first, then weight up and circulate kill mud in the second circulation. Carlos, prepare the kill sheet. Emma, start mixing the kill mud — target 1.48 SG to give us a 0.06 SG trip margin. Let's do this by the book. No shortcuts on well control. Ever.