OGPSS - Production from Venezuela and new customers for them

Last week I wrote a little about the planned production of heavy oil from the Orinoco Basin in Venezuela and used that as the basis for a discussion on API gravity and refinery gains. What I would like to do today is to revisit this area of Venezuela and discuss a little more of the region and the potential for increased production, and how it might be achieved. But let me start with overall production from Venezuela, for which (as my comment on Chinese imports last week exemplified) data is not always consistent.


Taking the curve developed at Energy Export Data Browser for the country, the initial impression is a classic example of a depleting system, with rising internal consumption having a negative impact on overall exports, which have already fallen below 2 mbd. The EIA note (and this has been a problem for a while) that it is difficult to assess the make-up of the production stream, but estimate that in 2008 about 250,000 bd came from condensate, NGLs and refinery gains. The United States has seen a steady decline in the amount of oil that it imports from Venezeula, with the daily rate falling below 1 mbd towards the end of last year. Within the past two weeks it has fallen as low as 650,000 bd.

The steady fall in Venezuelan imports to the USA (EIA )
Please note there is an additional comment appended on the loss in volume on going through the ugraders.

Overall Venezuela was reported as producing 2.25 mbd in November with production falling over the course of the last year. This is somewhat less than the 3 million barrels that the Venezuelan Oil Minister claims that they are producing. Hopes for the future therefore rest on increased production from oil sands of the Orinoco that I briefly described last time. I should also clear up what may be a little confusion in nomenclature. This is a map of the Belt from a study done by the Baker Institute at Rice in 2002. (H/t KLR)


At that time production came from four strategic operations built around individual upgraders: Petrozuategui, Petromonagas , Petrocedeno, and Petropiar. As some of the references here note, the upgraders are beginning to suffer from a poor record of maintenance and are thus more difficult to maintain at the original levels of production.


More recently there has been a renaming (as in the table) and the bids relate to zones now defined by PdVSA as:

Different regions of the Orinoco Belt (Energy-pedia news )

To a degree Venezuela in the same situation as Canada, as conventional production of oil diminishes, so the rise in oil prices is making it more practical to produce the heavier oils of the Orinoco Basin, although almost all the oil from Venezuela is both heavy and sour. However this also may lead to volume calculation concerns since there is a reported 10% loss in volume as the heavy crude passes through the upgraders to be pipelined as a syncrude. Thus from the four major current producers there is a variation between 640,000 bd of raw crude (API gravity between 8 and 9.3 degrees) input; and the 579,000 pf syncrude (API gravity 16 to 32 degrees) that is produced. The heavier crude is also discounted in price, so that, with the OPEC basket at $90.38 at the end of last year, the Venezuelan basket was reported to be selling at $ 84.83. Heavy Oil Guy over at TOD has commented on this loss.

Any practical process will have to reject something like 20 wt% of the original crude as useless high-sulfur, high-metals coke or asphaltenes that must be stored forever (or dumped into a deep ocean trench ;-]). Also 10% by weight would come off as fuel gas, including ethylene, that would be burned as process fuel, not recovered as a liquid.

Because of the high specific gravity and viscocity of the oil, particularly when cold, conventional methods of production cannot rely on reservoir pressure to produce the oil. In some cases it is possible to use progressive cavity pumps (Moyno pumps) that are lowered down the wells, to pump the oil out of the reservoir.

The reservoir properties for the Hamaca wells are excellent, with porosity values of up to 36% and permeability values of up to 30 darcies. Hamaca crude is considered 'foamy' and is generally saturated with gas at reservoir conditions. Over the 35-year life of the field, more than 1,000 horizontal laterals are planned to deliver the required 190,000bpd to the upgrader facility.

Oil is produced under 'cold production' methods (no need for heated steam to mobilise the deposits) using progressing cavity pumps to bring oil to the surface. Cold production is possible because of the extended length of the horizontal wells (5,000ft), excellent reservoir properties, and the foamy-oil nature of Hamaca crude.

Once at the surface the crude is mixed with a chemical/diluent that allows it to be pumped to the upgrader. It was the use of the pumps to extract the oil with sand that led to the acronym CHOPS (Cold Heavy Oil Production with Sand), although in an earlier article I discussed the use of the technique in Canada, where higher reservoir pressures and lower viscosity allowed the oil to be produced without the pump, by allowing the well to flow freely.

In Venezuela, though it is thought to be used in many of the heavy oil deposits, it is estimated to be only able to produce 5 – 10% of the oil. Problems are then anticipated to arise in changing the well designs to use alternate means to go after the remaining 90%, and it is anticipated that by 2012 CHOPS will no longer, in consequence, be used in Canada.

With 80% to 90% of the resource still in the ground after cold production, the reservoir is in a disturbed state, perhaps with wormholes or channels that have found a way to water. It may, however, be a severely depleted reservoir with low pressure and a network of channels.

If CHOPS has not been used extensively in Venezuela there are a variety of ways that the heavy oil can be encouraged to flow to the production wells. More modern trends are to rely on such thermal techniques as Steam Assisted Gravity Drainage, (SAGD). These are necessary since the deposits are too deep to be mined using the surface mining techniques that are used in Canada. SAGD is where steam is injected into the formation from one horizontally drilled well, and the heated (and thus less viscous) oil then flows through the deposit to a second well where it is recovered.

Artist's illustration of the SAGD process (Devon Canada Corp)

An alternate has been proposed, in which single horizontal wells can act both as an injection source for the steam, and then after the oil has been conditioned, they will serve to produce the lower viscocity, hotter fluid.

Kerosine can also be injected into the formation ahead of the steam, which then forces it through the oil. In this way it is claimed that production can be greatly enhanced. However, to be viable more than 70% of the solvent must be recovered for re-use. Canada is also investigating the JIVE process. (Joint Implementation Vapour Extraction)

(Source HeavyOilInfo.com)

However all this development will cost a considerable amount of investment, and as Robert Rapier noted last September, Hugo Chavez is not keen to make those investments himself, and the result has been seen in the declining levels of production.

However he is still trying to persuade others to make the investments that he will not, and the evidence, given the perceived coming shortage of oil, and the needs of countries to ensure a steady, stable supply, means that he is currently still able to negotiate deals to get those funds. The different alliances that have evolved for this development can be seen from this map from Petroleum World.



The swop deal that I mentioned last week involving Venezuela, Belarus and Azerbaijan is proving to be a little more complex than the original simple swop I mentioned, since it involved lighter crudes from Venezuela, particularly the Santa Barbara crude which has an API gravity of 39 degrees.

“We have to work with different blends, and in terms of its functional properties, the Santa Barbara blend is among the best. This blend can produce 20 percent more gasoline, kerosene, or diesel fuel than Russian blends, and these products are in high demand in Europe.”

Originally that was being shipped to Belarus in tankers from Venezuela, and my impression initially was that Venezuela was swopping production with Azerbaijan (Venezuelan crude would go to the USA and Azer crude would go to Belarus) as a way of reducing the shipping. However this week, it transpires that the problem apparently is that Venezuela cannot supply sufficient of the sweet crude to meet world demand, and in particular the 30 mb it sold Belarus. PdVSA is thus having to buy Azer crude to make up the difference between what it can send and what it contracted for.

Plans, stated recently by the Belarusian authorities, to use the swap scheme in oil supplies "do not deal with the substitution of Venezuelan oil with Azerbaijan," the diplomat said.

"Oil company PDVSA will purchase an additional amount of oil in Azerbaijan to ensure the execution of the contract to supply up to ten million of oil a year to Belarus," ambassador said.

This oil will go to Belarus through "Odessa-Brody" pipeline. The Belarusian side will pay Azerbaijan not for the oil itself, but only for its delivery. "As you can see, this cooperation is beneficial for both parties and, in particular, for Belarus," Americo Diaz Nunez said.

Belarus has now found it makes more money (about $30 a ton) doing it this way, since the pipeline is cheaper than the rail transport they would have to pay for in buying from Russia, which also charges a 100% duty. But the limited supplies of the sweet Santa Barbara crude have also been bought by the Japanese. However Venezuela may have a further problem, since in October they signed a deal with Belarus that will increase the amount shipped to 220 mb over the next three years. They are apparently getting $88 a barrel for it. (Though the price for Urals crude to Belarus was only $57 a barrel – that may have been before shipping and duty were added.)

So Venezuela has a global market, the question now becomes as to whether it can supply it.

The Russia:Belarus oil dispute and Western Oil supplies

I hadn’t actually been paying much attention to the Russian:Belarus dispute over oil supplies. After the annual debacles that we are used to over natural gas supplies that flow from Russia to Western Europe through Ukraine, and which seem somewhat quiescent at the moment, I had failed to grasp how much Western supplies of oil from Russia flow through Belarus. But as is pointed out in Foreign Policy the flow is significant, and this is a more far-reaching conflict than I grasped. As a brief review:

In 2001, Belarus unilaterally canceled a contract that mandated the sharing of these revenues, leading to substantial losses for Russian pipeline monopoly Transneft and the Russian state budget. Now, Transneft is demanding that Belarus pay full import duties for the portion of Russian oil that it resells on the European market, a demand that could cost Belarus as much as $5 billion per year. The Belarusian government argues that the Russia-Belarus customs union obviates the need for Minsk to pay duty on imports from Russia. Although deliveries through the Druzhba pipeline have not, as of mid-January, been cut off, the prospect that Transneft (whose chairman is Russian Deputy Prime Minister Igor Sechin, a close confidant of Prime Minister Vladimir Putin) will turn off the taps to force compliance from Minsk is clearly one that has European leaders worried because the European Union imports about a third of its oil from Russia, mostly via Belarus. Already, the prospect of supply disruptions has driven U.S. crude oil prices to a 15-month high, presumably to Moscow's delight.

Well, as my post yesterday showed, I am not convinced that this conflict had a lot to do with the rise in oil prices (which actually dropped a little today, on their overall march upwards). But that does not lessen the longer-term impact of what is going on. It is, as it was with the Ukraine dispute, to with control, with Russia seeking to control fuel distribution in these countries, and through supply controls also influence the directions in which the country moves.

Russia is now warning that it will reduce oil flows to Belarus even further and wants the duty on the roughly 290,000 bd that is refined in Belarus and then exported to the West. At the moment the refineries in Belarus have a relatively short reserve (between a few days and a week, reportedly - depending on source) and the current contracts have expired.

Germany and Poland are believed to be hit hardest once Russia halts shipments through the Druzhba pipeline. Germany depends on Russian crude for about 15 percent of its total consumption, and Poland buys from Russia to meet 75 percent of its market demands.

Minsk has threatened to raise the transit fee for its European customers more than tenfold, from 3.9 dollars to 45 dollars per metric ton, should Moscow not agree to its conditions, RIA Novostinews agency quoted an unidentified expert close to the talks as saying.

At the moment the talks appear to be stalled. However they are not limited to the transit of oil. There is also a dispute over the transmission of electric power. Belarus acts as a transit country for power both to Kalingrad and to the countries of the Baltic. It has assumed somewhat greater urgency with the closure of the Ignalina nuclear power plant in Lithuania. The plant closed on December 31, and there are fears of greater dependence on Russia for future power. Russian complacency about the situation is not, I suspect, exactly helpful.

“It is inevitable that Russia is going to become a bigger supplier of energy to Europe and particularly to the Baltic countries. Ultimately there comes a point where you have to let the old days go,” Chris Weafer, chief strategist on Moscow’s Uralsib bank, told New Europe on 5 January, adding that the Baltics, which sorely need energy supplies, should adopt a pragmatic approach and rely on their eastern neighbor and forget the legacy of the Soviet Union. As long as Russia continues to try and build a modern and diversified economy with greater global integration, then it needs the goodwill of the West just as much as the West needs Russia’s energy.

Bids for construction of a new plant are due to be submitted by the end of this month, with the hope of getting the new plant on line by 2018. (Kalingrad is hoping to have its own reactor in about the same time frame).

In the interim the Baltic states are going to be dependent, not only on Russia for their electricity and oil, but also on satisfactory conditions to allow the transit of both through Belarus on their way.

Meanwhile, over in Ukraine, there is an election underway, with initial voting to take place on Sunday. It is perhaps for that reason that there have been no major gas disruptions so far this year. Anger with the current administration is giving a bit of a boost to a third candidate, so perhaps it is in Russia’s best interests to retain a low profile at this point. In fact Russia is claiming credit for keeping the UK supplied with gas as supplies from Norway dropped due to bad weather at some of the production sites. However Russia is also being nice to Turkey as insurance just in case it will still need to do some bypassing around Ukraine to supply Western Europe after the election is over.

Not that conditions in Ukraine itself have been unaffected. There are some 175 towns and villages that are reported to be still without power, due to the bad weather. This is a decided improvement from the 1,598 who lost power in the Dec 29th storm. At least they are more used to the cold.

Those in Florida who aren’t, and plugged in too many heaters, are also causing power outages down there.

6. The Natural Gas dispute between Ukraine and Russia

It is a ritual that now seems set to occur at the beginning of every year as Russia and Ukraine face off over the payment of previous gas bills, and Russia cuts off, or threatens to do so, all gas supplies to Ukraine (while urging them to continue to allow gas supplies to flow west through the pipelines to Western Europe). This year it has, again reached the point that the conflict has led to a shut-off in the gas supply. And now Western Europe is going to watch the same familiar dance play out once again as they wait to see how their supplies will be affected. Early this morning Naftogaz, the Ukrainian energy firm, announced a drop in gas pressure in the lines from Russia. Russia has also raised its price to Ukraine from $215 to $415 per 1,000 cu m (kcum).

To briefly review the background to the problem, one has first to look at a map of that part of the world and see that at present almost all the gas from Russia flowing West passes through Ukraine. However, at the same time Ukraine is one of the largest consumers of natural gas - it was sixth in 2006. This map is taken from Eastern European Gas Analysis.


At present Russia pays Ukraine some $1.70 per 1,000 cu m as a transit fee to allow gas to flow through the pipeline to the West. The scale of this dependence can be illustrated with some figures from 2007.

Germany bought 34.5 billion cu m (bcm) or 42% of its consumption.
Turkey imported 23.4 bcm for 67% of its use.
Italy was third using 22 bcm for 28% of consumption.
Britain bought 15.2 bcm for 16% of consumption.
France imported 10.1 bcm for 24% of consumption.
Hungary got 7.5 bcm for 60% of consumption.
The Czech Republic bought 7.2 bcm for 80% of consumption
Poland bought half its natural gas from Russia
Austria bought 5.4 bcm for 60% of requirements
Greece buys 75% of its gas from Russia
While Slovakia, Bulgaria and Finland get all of their supplies from those pipelines.

There have been some attempts to get around the problem, but until the alternate pipelines known as the Nord Strream and South Stream pipelines, come on stream at some time in the future, the gas must largely flow through Ukraine.

Earlier this fall Turkey had tried to increase the amount of gas that it could purchase from Iran. This despite the fact that last January they were buying more from Russia to offset shortages from Iran.

Now there is an additional catch to all this, in so far as the Russian supply, to some extent, actually comes from Turkmenistan, Azerbaijan and Kazakhstan. The Russians, in the same way as the Ukrainians, charge a fee to transit the gas West. Gazprom has been busy this past year trying to lock up that supply. However their history in dealing with Turkmenistan has not always been that amicable with Turkmenistan getting paid considerably less than the price that Russia obtained for the gas at the other end of the pipeline.

The differences in price that Russia charges to favored customers can be quite dramatic, with Belarus for example only paying $119.53 per kcum. Prices, however, are slated to go up. Belarus also provides a secondary pipeline that carries natural gas to the West, and flow rates through that pipe have already increased by 25%.

We are now just at the start of this years dance, and we shall just have to wait now and see how this plays out over the next few days.