Archives for posts with tag: offshore production

Vietnam has the third largest proven oil reserves in the Asia Pacific region – but much of its existing offshore production is from declining shallow water fields. So the country’s first deepwater discovery, made in October, is a potentially exciting development. Could deepwater E&P activity in Vietnam be set to take off, or will weak oil prices and disputes over territorial waters prove problematic?

Shallow Beginnings

Most of Vietnam’s 0.28m bpd of offshore oil and 0.99bn cfd of offshore gas production is derived from fields in the Nam Con Son and Cuu Long basins, all of which are in less than 200m of water. The Cuu Long basin is perhaps the most successful area off Vietnam as it is home to many large fields, including Bach Ho, Su Tu Vang and Rang Dong. The dominance of shallow fields has skewed development towards fixed platforms. 88% of all active Vietnamese fields are exploited as such. Of these fields, the Bach Ho field accounts for 34 cor 37% of the total found on active fields.

Operators in Vietnam mainly consist of local and regional NOCs as well as IOCs (most commonly via joint operating companies in partnership with Petrovietnam). While significant market reforms have increased foreign investment in Vietnam’s offshore sector, further improvements to its transaction and tax systems could quicken the pace of foreign participation in the future.

Wading Into Deeper Waters

No significant shallow discoveries have been made recently, meaning that there is little to offset Vietnam’s depleting shallow water reserves. This highlights the need to break into deepwater frontiers, which could hold substantial levels of undiscovered hydrocarbons. The VGP-131-TB well, Vietnam’s first discovery in water depths >500m, was drilled in October 2015 by the Vietgazprom JOC, at depths of 1,600m in the Saigon basin. The ultra-deep find could provide momentum for Vietnam’s push into deepwater exploration. However, unlike China, which is able to independently bring deepwater fields like the Lingshui 17-2 online, Vietnam could still need to rely on foreign cooperation to jointly develop such finds in the short term.

Shaky Prospects

Vietnam’s hydrocarbon resources mainly lie in the South China Sea, with the most recent discovery at the southern end. The sea is an area of multiple disputed territorial claims by many countries, including China. This could impede any deep developments, if international partners were to view overlapping sovereignty claims to be an excessive business risk. Perhaps more importantly though, the post-downturn attitude of IOCs is one of cost-consciousness given lacklustre economic conditions. This could skew near-term interest towards safer EOR projects instead of unproven deeper water development in the South China Sea.

Since Vietnam’s historical track record is in shallow waters, even if further deepwater discoveries are forthcoming, then the chance of rapid deepwater developments in the South China Sea is probably going to take time. It is likely to need outside expertise, and the current energy markets may well not be conducive to this. That said, the discovery of Vietnam’s first deepwater field marks a new chapter in the country’s oil and gas story.


Over the hill; past its peak; long in the tooth: like a worn-out old racehorse, the North Sea E&P sector is sometimes discussed in disparaging terms. In recent years however, it has been making something of a comeback, gaining ground when it comes to exploration and at least holding steady-ish when it comes to production. The question is, can this pace be sustained in the current oil price environment?

Saddling Up

The UK and Norway have long been the front-runners when it comes to offshore activity in the North Sea. In the 1970s, an average of 187 offshore wells were spudded per year in UK and Norwegian waters. As the graph shows, in the years 1970-76, more than 50% of these were exploration wells. Production was low (0.85m boepd in 1975), as few of the discoveries made since the first find in 1965 had been developed. But then in 1976, Brent started up, with Ekofisk following in 1977. During the course of bringing these and other large fields onstream, appraisal and development drilling raced ahead of exploration; from 1990, the number of exploration wells drilled each year began falling too. Field operators were now focusing on production over exploration. The two countries’ offshore production peaked in 2002 at 8.64m boepd from 337 fields. This year was also the nadir for exploration drilling: of 503 wells spudded, just 32 (6.4%) were exploration wells.

Second Wind

Oil companies therefore found total production falling just as reserves were being replaced at the slowest rate since North Sea exploration began. The more prudent then applied the spur to exploration once more, even as they tried to stop production decline using EOR. Exploration in the years 2003-14 in the central North Sea met with some notable successes, like the giant Johan Sverdrup discovery in 2010, with 2P reserves of 2.2bn bbl oil and 394bn cf gas. Operators also began venturing into the mostly unexplored Barents Sea and west of Shetlands waters. Hence, in 2014, 27% of wells spudded in UK or Norwegian waters were for exploration, a share similar to the late 1980s. Production, meanwhile, fell by only 0.8% y-o-y, versus the average y-o-y decline over 2002-14 of 3.9%.

The Final Furlong?

The area’s offshore sector was thus moving at a relatively good pace. However, 2014 exploration campaigns and most incipient development projects were conceived in a more robust oil price environment than the present: E&P economics in frontier areas like the Barents Sea are highly uncertain while the oil price is less than $80/bbl. Perhaps then, with oil company spending cuts, the recovery in exploration will be stopped in its tracks and production decline may resume. On the other hand, some smaller operators are taking advantage of low rig and OSV day rates to increase exploration. Falling EPC costs could also help to reduce development project breakevens, flogging North Sea E&P onwards once more. And if the oil price were to return to $100/bbl+, then there is the potential for further upside.

So there you have it. The weaker oil price has made some oil companies pull on the reins, but there is still potential for the second burst of North Sea E&P activity to run on, in the right conditions. The area may no longer be the fiery colt of offshore E&P, but it probably has some way to run yet before being put out to pasture.


OIMT201405Russia is forecast to account for 13% of world crude oil production and 18% of world natural gas production in 2014. While its prodigious Siberian flows tend to receive most of the credit for this feat, fields located off the country’s 16 million km of coastline are nonetheless projected to produce 390,000 bpd oil and 2.64 bcfd gas in 2014. So where exactly is Russian offshore production to be found? And what is the outlook?

Mastering the Arctic

As the Graph of the Month shows, offshore oil and gas production in Baltic & Arctic Russia stagnated after the break-up of the USSR, declining to 0.03m boepd in 2013, when it accounted for 4% of Russian offshore production. This trend was thrown into reverse when the Prirazlomnoye field came onstream in December 2013. Located 23km from shore in the Pechora Sea, the field is exploited via a ice-class platform and production is scheduled to reach 120,000 bpd by 2019. New technologies and robust oil prices are thus unlocking reserves hitherto stranded, and by 2023 Arctic oil and gas is forecast to constitute 11% of Russia’s offshore production.

Caspian and Crimean Conquests

Russia’s southern offshore fields, mainly in the Caspian, accounted for 9% of Russian offshore production in 2013. In the Caspian, as in the Arctic, harsh conditions have limited field development and disincentivised efforts to halt production decline. However, as in the Arctic, decline is now forecast to be arrested. Lukoil, for example, are planning substantial investment over the next four years at fields like Khvalynskoye and Yuri S. Kuvykin, where ice-class jack-up production units are likely to make development feasible. By 2023, the area is forecast to account for 24% of Russian offshore oil and gas production (excluding gas produced by fields off the Crimea, over which Russia now has de facto control, and which produced 410m cfd in 2013).

Expanding Eastwards

The Russian Far East is a relatively new area of offshore E&P. The Sakhalin-2 project started up in 1996 but offshore activity is still geographically limited, even if production volumes, at 0.78m boepd, are significant. The area accounted for 88% of Russian offshore production in 2013. Moreover, the Far East is Russia’s window on the developing economies of the Asia Pacific region, so companies are seeking to increase activity there, particularly with regards to LNG. In October 2013, the first Sakhalin-3 field, Kirinskoye, a subsea-to-shore development, began ramping up to 580m cfd. Further such field developments are planned out to 2023, when the area is projected to produce 0.95m boepd, its share falling to 65% despite new Capex due to faster Arctic and Caspian growth.

Thus production is forecast to grow in each of Russia’s offshore areas, driven largely by investment in high-spec jack-up, fixed platform and subsea field solutions. Total offshore oil production is projected to grow with a CAGR of 8.9% from 2014 to reach 890,000 bpd in 2023, and gas production likewise at 2.5% to reach 3.36 bcfd. Offshore would then account for 6.7% of the country’s oil and gas production, a far cry from the 2% nadir of post-Soviet decay.