OGPSS - Oil production within China

If one looks at a map of China, at first it seems to be a land that has been heavily endowed with gas and oil fields. However, with the continued rise in demand for liquid fuel, exploration and development are being aggressively pursued inside the nation, as well as offshore and abroad. Current levels of production, and those planned, still leave an increasing volume that must be imported each year to meet the national demand.

Figure 1. Exploration and Production map for PetroChina (PetroChina )

And yet, as has been noted earlier, while demand has continued to soar, overall domestic production has not changed all that much. China has three major oil production companies, PetroChina, Sinopec and CNOOC, where the last of these, the Chinese National Offshore Oil Company (discussed in an earlier post) deals – as the name suggests – with offshore deposits, and the other two are concerned with onshore production.

According to the 2012 BP Statistical Review China produced an average of 4.09 mbd in 2011, which was a 0.3% increase over that produced in 2010. As mentioned in the earlier post, CNOOC is only able to project a sustained production level this year because of the increasing production from its overseas properties in Canada and Iraq. In the first half of this year they produced some 127 million barrels of oil, close enough to 700 kbd in total, and similar to last year’s average.

Within the country the industry is split between two companies, the China National Petroleum Corporation (CNPC), which has PetroChina as its publically traded division, has some 60% of the oil production and 80% of the natural gas production. Just this year PetroChina was recognized as having passed ExxonMobil to become the largest listed oil producer in the world. With overall production of 2.43 mbd it exceeded the ExxonMobil total of 2.3 mbd in January. (Although it is suggested that PetroChina made only half the profit of its competitor).

One has also to distinguish between the production that the company is able to achieve in China, relative to that which it achieves through its acquisitions abroad. The company shows a domestic record of production that has averaged 2.42 mbd in 2011 with slight rises in production for the past two.

PetroChina domestic production through 2011. (PetroChina)

For the first half of this year the company has refined an average of 2.69 mbd which was expensive for the company given that the sales price for the resulting products are controlled in China. Additional production, to the tune of 343 kbd, comes from their foreign holdings. By 2020 the company intends that this amount (almost 10% of output) will be increased to 50% of the company production. Assuming that it can sustain domestic levels of production this anticipates that it will need to be able to find roughly 1.4 mbd of additional production from sites abroad.

PetroChina, runs, inter alia, the largest field in China, that at Daqing. After the discovery of commercial oil at Songji No. 3 well in September 1959, the field was brought into production over three years. The field was where “Iron Man” Wang Xinji gained national fame through his efforts as an oil driller with the 1205 Drilling Team to bring in the first production well. Production at the field peaked in 1976 at roughly 1 mbd with more than 14 billion barrels of oil now having been produced. Oil recovery is cited at 50%, a rate that is about 10-15% higher that the average in Chinese reservoirs. Just this week the company completed an addition to the refinery there that raises capacity to 197 kbd at that refinery of Daqing Petrochemical. Production at the field itself has now fallen, in overall average for 2011, to roughly 790 kbd, and relies on tertiary recovery using a polymer based flood in a field which has an over 80% water cut. The company believes that more than 70% of the recoverable oil now has been.

Next door to Daqing lies the Jilin Oil Province, containing some 21 oil fields. Of these the Fuyu field was first discovered with the well Fu-27 in September 1959, with full exploration in 1961 though it was not developed to full potential until 1970. CNPC, PetroChina’s parent, runs the Province, which is the seventh largest in China. Last year it produced some 148 kbdoe and this is to be raised to roughly 200 kbd by 2015. CNPC also began production in Iraq this past year, and anticipates some 59 kbd from that source.

The Changqing Oil Field is also operated by CNPC. Discovered in 1971 it reached a total of 800 kbdoe in 2011 with a year-on-year growth in production of some 7 million barrels.

Figure 3. China’s major oilfields (Energy-pedia )

Far out West in China lies the Tarim Oil Field, which has been set a goal of producing sensibly 1 mbdoe by 2020, though more recent announcements have lowered that target by 20%. Operated by PetroChina, achieving that target will move it toward the front of the fields in the country, from its current fourth place. It has a reserve estimated at 100 billion barrels of oil equivalent, and is the largest natural gas producer in China.

Shengli (Sinopec) Shengli field, which is, at around 557 kbd production in 2010 is currently the second largest producing field in China.

Sinopec anticipate that by 2020 it will produce more than half of its oil and gas from abroad and by 2015 expects that it will be close to that goal.

China Petrochemical, Sinopec’s parent, seeks to produce 50 million metric tons of crude a year overseas by 2015. Last year, foreign production was 22.9 million tons. Sinopec said it boosted first-half crude output 4.3 percent to 163.09 million barrels and overseas production jumped 82 percent to 11.13 million barrels.

If Sinopec sustains domestic production at some 895 kbd through 2020, then it will need to find nearly 1 mbd of overseas production to match that in just 3 years. In short, while China is working as hard as it can to sustain current levels of production into the future, in order to meet the growth that they anticipate they will be looking to buy (combining all three company goals) close to 2.5 mbd from overseas deposits.

The big question of course remains as to where that production will come from, and, if we are at a world plateau in overall production, at whose expense will that supply need be met.

P.S. On a continuing note, it is worth remarking that the Alyeska pipeline flowed at an average volume of 430,967 bd in July.

OGPPS - Saudi Arabia and what lies ahead

Saudi Aramco has stated that it designs the well layouts and extraction patterns from its oil fields so that they effectively decline at a rate of 2% per year.* If one divides 100 by 2 it yields 50. If one subtracts 50 from 2012, one gets the year 1962. Even to those with poor math skills, these are not difficult operations, and they lead to the conclusion that those fields that came into production in the early 1960’s and earlier are now reaching the end of their productive lives. They are not there yet, since production took time to ramp up, and some fields have been rested over the years, when production was cut back, or even mothballed. But it gives you some perspective on the overall scope of the situation, without the need for complex mathematical modeling.

Figure 1. Table of oil fields in KSA and their start dates

(* The IEA apparently believes that the figure is closer to 3.5%) (H/t Matt) Saudi Arabia states that, without using advanced recovery techniques and “maintain potential” drilling sites – often not in the same field as that being depleted – the rate would be 8%.(h/t Darwinian ).

In earlier production practices, where companies “stepped out” production wells away from the original producers, and in this way gradually extended the knowledge of the size of the field, reserve growth over time was a normal development. However, with the large size of the fields in Saudi Arabia, and the need to maintain operational pressure during production, Aramco (as JoulesBurn has clearly shown) rings their fields with water injection wells that drive oil to the central high point of the reservoir and slowly migrates the producing and injection wells towards that center as the field is drawn down. This practice precludes the incremental increase in reserves over time, since the field boundaries are constrained and as the wells reach the central part of the reservoir (the crest of the anticline) a clear definition of the closing days of the field becomes more evident.

At the same time it is worth pointing out that until fairly recently when Aramco were carrying out their “maintain potential” drilling they were merely drilling additional wells at 1 km spacing further down the reservoir. But when one moves from the perimeter of the reservoir to the crest, then there are no more places within that reservoir to continue the practice. Thus, in more recent years Aramco have offset declines in older reservoirs by bringing new fields into production. But, as the illustration below that JoulesBurn has provided for Haradh 3 shows, in the smaller reservoirs it is no longer possible to have the space for multi-year progressions of the wells across the field and thus, to sustain production new fields will have to be added to the network at more frequent intervals to sustain levels of production.

  

Figure 2. Planned well layout in Haradh III (from Aramco via JoulesBurn

Saudi reservoirs have also been large. This brings with it the need for large infrastructure to be in place not only to remove the oil, but also to separate the oil, gas and water (and occasional sand) that come out of the well, and to inject water into the reservoir to replace the oil and maintain the reservoir pressure that drives the fluid to the well. That infrastructure is tied to specific design flow rates and it is difficult to change the volume flow rates by significant amounts at short notice. Thus when a field, such as Abu Sa’fah, for example, is brought on line to produce 300 kbd, the plant is all designed for that flow and there is no immediate way to handle an increase in flow. Aramco can only, therefore produce, to the capacity of the infrastructure in place. It is this requirement and “step-function” nature of the additions to oil flow that provides some of the shape to the flow of oil in the region.

However, it is also a limitation, in that the two remaining large sources of crude oil that Saudi Arabia anticipates coming on line must wait until all the logistical handling is in place.

The first of these is the Shaybah expansion. Shaybah began with a production of 250 kbd, and has seen this progressively increased, first to 500 kbd, and then, in 2009, to 750 kbd.. The expansion requires that additional plant be installed to process the hydrocarbons produced which will include 264 kbd of NGL. The anticipated completion date is in 2014.

Manifa has been the more controversial of the fields in Saudi Arabia for some time. Although it has been known to exist for a long time (see above table) and was initially brought into production in 1964, it has never seen the major thrust to develop production that is now underway. There have been several reasons for this, the primary one being that KSA has never needed the production in the past to be able to meet anticipated demand. However there have also been significant questions as to the make-up of the oil, and its need for special treatment. In 2005 it was producing at around 50 kbd, back in the days when KSA was admitting to a decline rate of 6%. JoulesBurn has written about the controversy over the make-up of the oil, which is a heavy, sour crude containing vanadium. Regardless of the validity of those arguments, it does appear that the oil is now going to be fed, as it is produced, to two new refineries that have been planned in the Kingdom. These are at Jubail which is expected to be completed in 2013, and will handle 400 kbd of oil, and the second at Yanbu which, as of this year is being developed with Sinopec, ConocoPhilips having pulled out of the deal. That, together, comprises some 800 kbd of the 900 kbd of oil that Manifa is being developed to produce.

It is pertinent, relative to the opening comment, to note that this is the last large project that Saudi Aramco has reported to be on their books. If one were to accept that their real decline rate is some 3.5% then, at a production level of roughly 10 mbd a year, this would be reducing at 350 kbd per year. A 1.2 mbd addition to current production (Manifa and Shaybah combined) would thus only match just over three years of such a decline rate. For there to be new sources of production brought on line in the future, there must first be a considerable infrastructure put in place, and there does not, at present, appear to be any evidence of this, nor planning and bid documents being prepared for such an eventuality. Remember that Aramco began construction for Manifa in 2007, and it is still likely at least a year from major production.

To some extent this can be overcome by feeding new production from fields not now in production into the existing GOSPs and related facilities. But what that implies is that production will not grow beyond its current levels, which is around 10 mbd. Aramco have become very skilled at controlling water floods, enhancing production from existing reservoirs, and previously bypassed oil, but those wells can only be revisited a limited number of times. Because of the large number of highly productive wells that the country has, it is possible in the short term to raise production but that increase has to go through production facilities which are of only limited volume. Thus the increase can be of only a short duration, and as has been commented by others in the past few weeks, a system cannot be run at full production for long without problems developing. Further the underlying assumption that production declines can be offset by new production to hold depletion to 2% a year is really only true for the country as a whole, and individual decline rates for specific reservoirs have been reported to run between 6 and 8%. As there are become fewer large projects to provide the offset for such decline rates, then the impact of the greater values will become more evident. And so while I expect that the Kingdom will reclaim its position as leading oil producer before long, I continue to believe it will be because of a drop in Russian production, rather than a gain in that from the Kingdom.