217. History of the Liza oil field discovery offshore Guyana

1.2 The博弈 between Technology and Risk In 2008, to mitigate risk, ExxonMobil sold a 25% stake in the Stabroek Block to Shell for joint seismic studies. However, the data revealed a critical problem: the area lacked conventional 'structural traps' and possessed only difficult-to-detect 'stratigraphic traps.' With no anticlinal or fault traps—and extremely gentle strata (Figure 2)—geoscientists lacked confidence in whether such stratigraphic-lithologic traps had been charged with hydrocarbons, deeming the exploration target highly risky! Shell ultimately exited the project in 2014. Yet ExxonMobil’s commercial advisor, Rudy Dismuke, proposed a pivotal strategy: bringing in partners to share costs and reduce the company’s risk to near zero. 2. A Counter-Cyclical Decision 2.1 Dekkerstuis’s Persistence In 2013, Dekkerstuis’s team, through 3D seismic data analysis and interpretation, inferred the presence of an oil-bearing sandstone layer up to 90 meters thick in the Liza area, estimating reserves at 890 million barrels. Nevertheless, senior management judged the 22% success probability insufficient to justify a $175 million drilling campaign. At this critical juncture, Dismuke proposed a 'nearly free drilling' scheme: attracting Hess Corp and CNOOC to take 30% and 25% stakes respectively, thereby bearing most of the drilling costs. ExxonMobil needed to invest less than $100 million to retain a 45% interest. 2.2 The Make-or-Break Drilling Moment In May 2015, ExxonMobil commenced drilling Liza-1 using Transocean’s drillship Deepwater Champion. The operation was fraught with peril: drill pipe stuck, equipment losses exceeding $15 million—dubbed the 'Hell Well.' Ultimately, the team salvaged the project via sidetracking. When the bit reached the target formation, rock samples exuded crude oil, and on-deck geologist Kerry Moreland smelled 'gas-station-like oil fumes.' At that moment, Guyana officially entered the global petroleum map. 3. A Discovery That Rewrote a Nation’s Destiny 3.1 Guyana’s Economic Takeoff Liza field production is projected to make Guyana’s per capita oil output surpass that of Saudi Arabia and Kuwait by 2027. According to IMF forecasts, the country’s GDP will grow over 300% within the next five years, making it South America’s second-largest oil producer (after Brazil). Although the Guyanese government has drawn criticism over contract terms—particularly its mere 1% royalty rate—oil revenues have already boosted infrastructure investment and social welfare. 3.2 ExxonMobil’s Strategic Victory The Liza reservoir exhibits excellent porosity and permeability (Figure 4). Liza’s breakeven cost per barrel is under $35—profitable even if oil prices halve to $42.50. As of 2023, ExxonMobil’s stock price had doubled since 2019, significantly outperforming peers such as Shell and BP.

Discuss deep-sea mining

Restoring Real Equipment Requirements: A single standard contract area requires 12 offshore engineering systems. In the previously outlined expenditure structure, TMC shifts part of its offshore capacity-expansion investment from upfront CAPEX into operational OPEX—via contractor financing and capital recovery fees for systems. However, from an industrial-chain perspective, such financial treatment does not alter the underlying equipment demand. To achieve full production, a project must deploy the requisite number of production vessels, risers and air-compression units, subsea collection vehicles, launch-and-recovery systems, and umbilicals—among other offshore production equipment. Taking TMC’s benchmark project as reference, achieving full-scale, multi-million-ton annual production at the NORI-D site alone would require four complete offshore production systems. Meanwhile, the actual area of the NORI-D site accounts for only about one-third of the area covered by a single standard exploration contract held by TMC under the International Seabed Authority (ISA). Extrapolating accordingly, full-scale commercial development across an entire standard contract area would require approximately 12 independent offshore production systems. Based on an all-inclusive cost of ~$468 million for the first system, a single standard exploration contract corresponds to roughly $5.62 billion in front-end hardware procurement demand. Globally, the 19 polymetallic nodule contracts translate into a theoretical market space of ~$10.68 billion for offshore production systems. Specifically: at ~$468 million per system and 12 systems per contract, equipment demand per contract totals ~$5.62 billion; linear extrapolation based on licensed area implies that the 17 nodule contracts in the CCZ’s core zone alone represent ~$9.55 billion in initial offshore equipment demand; extending to all 19 nodule contracts worldwide, the TAM (theoretical absolute maximum) for offshore production system capital expenditure stands at ~$10.68 billion. Further breakdown by value composition of the first system reveals that risers and air-compression units account for over $3.56 billion; production vessel retrofits, over $2.26 billion; and subsea collection vehicles, over $1.76 billion—collectively exceeding $7.5 billion. These three components constitute the highest-value, most technologically demanding segment of the offshore production system equipment market. Note: (1) The hull of the first production vessel is retrofitted from an existing vessel, thus representing a relatively low share of total cost; subsequent systems cost ~$670 million each, but lack detailed capital-expenditure breakdowns—hence the conservative use of the first-system cost for estimation. (2) This calculation reflects a theoretical upper bound derived from linear area extrapolation; actual deployment timing depends on regulatory progress, contract-area development pace, and other factors. The long-term market potential for environmental monitoring and intelligent scientific survey services reaches the tens-of-billions-of-dollars level. Deep-sea mining entails environmental concerns including seabed disturbance, sediment plumes, biological impacts, and water-column changes. From baseline environmental surveys and pilot-mining validation to commercial operations and post-operation reviews, sustained investment is required in research vessels, AUVs/ROVs, underwater sensors, environmental monitoring personnel, marine fuel, and data evaluation services.

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