Tech Talk - enjoy it while you can

It is perhaps an odd time to be writing about oil shortages. The price of gas in our town has just moved above $2 a gallon up significantly from the $1.64 it was at its recent lowest point, but still very reasonable. Debate still rages as to whether the global price of a barrel of oil has found a bottom, although there are signs that the price is beginning to increase, in part due to other issues than overall availability of crude. So why be concerned?

There are several issues, and perhaps the first is that of industrial inertia. Despite the daily fluctuations in oil price, many of the events that occur between the time that oil is found in a layer of rock underground and the time that some of it is poured into your gas tank take a long time to initiate, and similarly can’t be turned off overnight. It takes, for example, roughly 47 days for a tanker to travel from Ras Tanura in Saudi Arabia to Houston.

One response to the drop in oil prices has been to reduce the number of rigs drilling for oil in the United States. Again this is not an immediate response, but rather one that grows with time. This is particularly true with the number of oil rigs that are used to gain access to the oil reservoirs. As the price for this oil falls, so rigs are idled and the potential for additional oil production also declines. This drop is particularly significant in fields that are horizontally drilled and fracked because of the very rapid decline in production with time in existing wells and the need for continued drilling to develop and produce new wells to sustain and grow production. The most recent figures show a fall of 98 rigs in the week from the 6th to the 13th of February, with the overall count now standing at 1,358. This rate of decline has held at nearly 100 rigs a week now for the past three with no indication of any immediate change in the slope of the curve. At the same time the number of well completions in the Bakken is falling, as producers hold back on the costs for producing oil that would be sold at a loss.

The impact from this will take time to appear, North Dakota has reached a production rate of 1.2 mbd in December and the DMR estimates that it will need around 140 rigs to sustain that production level this year, with the most recent rig count being 137. This number is likely to continue to fall through the first six months of the year.

The impact is not just in the immediate loss of production. Rather, once the rigs are idled it will take time, even after the markets recover, for the companies to adjust their planning and finances, and to re-activate the rigs. What this effectively does is to shift the production increment into later years, when the production base from existing wells will have declined beyond current levels. This means that the peak level of production will likely also be lower than would otherwise be the case, and the period over which this peak production is sustained will also be shorter.

The problem that this all presages is that lower levels of production against an increasing world demand will induce a faster rise in price than many now anticipate. There is a complacent feeling that oil prices won’t reach $100 a barrel for some considerable time - perhaps even years. If the current difference between available oil supply and demand is below 2 mbd, Euan Mearns has suggested that roughly half of this might be eaten up by increased demand, while the other half would disappear as production levels drop, although he doesn’t see this bringing the two volumes into rough balance until the end of 2016.

I rather think that it will happen faster than that, and that the price trough will steepen faster than currently anticipated, and likely before the end of this year. The problem (if you want to call it that) with the perceptions of the ability of global production to meet demand is that it is all tied to the production of the United States and Canada. I have noted, over the past two years, how future projections of increasing global oil demand have been met, in models, by increased production from the United States, and that this was anticipated to continue. (Increased production from Iraq, if sustained, is more likely to be needed just to balance declines in production from other countries).

Yet the US industry is going into a relatively rapid decline because of the way that it is structured that is going to be hard to stop, and much slower to reverse than anticipated. (In a way it is similar to the intermittent traffic congestion one finds on roads which result because we brake a lot faster than we then accelerate). This will not only stop the growth in production that is currently anticipated, but will go further and before the end of the year will lead to a drop in overall volumes produced. Yet demand is expected to increase. Where will the supply come from, if not the United States?

While Saudi Arabia can produce more, one gets the sense that they are quite comfortable where they are, thank you and won’t be increasing their contribution, and while Russia may bemoan the price they are getting for their oil, if the price goes up they are not going to be able to meet an increased demand, nor are there likely to be others with spare capacity that they can bring to the table. And because of the inertia in the system the United States will still be in a mode of declining production.

So I rather suspect that what we can anticipate is that prices will start to recover through the summer, and then, as the full impact of the rebalanced situation starts to become evident, will move higher at an increasing rate. Because if, in fact, we are reaching the period of a tighter balance between demand and available supply, then the market will change its perceptions quite quickly and be driven by a totally different metric.

Tech Talk - Pessimistic Talk in a time of surplus

The oil markets are concerned that there is too much oil currently available on the market, and that, as a consequence, oil prices may continue to tumble. Saudi Arabia is reportedly telling Reuters that it is happy with prices that may fall as low as $80 a barrel. As I mentioned the other day, some of this has to do with market share, and the KSA increasing production, and thereby seeking to weaken the likelihood of investment in other places, in turn ensuring their share holds up, not just now, but also down the road. The effect on gas prices has been rapid, with prices in parts of Missouri down to $2.65 a gallon – about a dollar less than I was paying only a week ago.

The effect will also have the benefit of a boost to the economy, which of course can’t hurt in the run-up to an election. But in the longer term it is hard to see how this boost can be sustained for more than a year. In the last post on this I mentioned that, outside of the US, Russia and KSA global oil production had dropped around 3 mbd over the past couple of years. Yet increased production (KSA raised production by 100 kbd in September as part of a total 400 kbd increase from OPEC overall) has, for now, been able to match and surpass this in order to meet the global demand. OPEC continues to expect that demand will increase by a million barrels a day this year and 1.19 mbd next. They further expect that the increased production to meet this will be met from outside the cartel, with the gain declining from 1.68 mbd this year, to 1.24 mbd next year, holding OPEC production to a decline of 300 kbd from the current 29.5 mbd. Simplistically the gains are maximized in increased production from the United States (880 kbd); Canada (250 kbd) and Brazil (190 kbd). They are anticipating a slight drop in Russian production, as part of an overall decline of 80 kbd for the FSU countries.

Part of the problem in projecting the balance revolves around estimating the production from Libya, Iraq and Iran (LII). Libya has reported raising production back to around 800 kbd, but some of that comes from the Shahara field, which was still involved in factional fighting, even as it came back on line at some 20% of normal. The three countries produce around 7 mbd (Iran 3 mbd, Iraq 3.2 mbd; Libya .8 mbd) so that the fluctuations in their production and sales can have a very significant impact on the global oil market, and the prices that are paid – but they function within OPEC, and it may be that the current drops in price are reminder that the big dog in that trailer is KSA, currently running at around 9.7 mbd.

It is foolish to try and predict, over the immediate short-term, how the fighting in Libya and Iraq will progress. Similarly it is hard to see how relations with Iran will change, potentially easing sanctions and allowing them to sell more product into the global market would upset the current balance in trade, and could, in the short-term, increase the glut and lower prices.

But supplies from those outside the cartel and the Americas are continuing to decline. That is not going to change. The rates may fluctuate a little (though the current drop in prices is not going to encourage large scale investment in declining fields) but the overall trend is steadily downward. And it is within that picture that potential changes in the production from the three LII countries have to be placed.

Figure 1. Libyan oil production through September 2013. (EIA)

Yet, as the fields have brought oil back to the market, there is a concurrent fall in global prices, as the EIA note.

Figure 2. Recent oil production from Libya and the price of Brent Crude (EIA)

Pre-conflict Libya was producing over 1.6 mbd, it recovered to 1.4 and is now struggling at around 0.8 mbd. But the prospects for the levels of peace required to sustain even that level do not seem promising. The conflict is worsening and seen as spiraling out of control.

Moving East to Iraq, despite the use of air power, the situation in the North is not improving, although the Kurds have now a pipeline to carry oil up into Turkey that is not controlled by the Islamic State. While it is still a matter of debate how much oil they will be able to sell, they hope that, by the end of next year they may be able to pump as much as 1 mbd, up from the initial 0.1 mbd when the pipeline went on line. At the same time, in the South, the oil fields lie some distance from the conflict, and there seems little threat, at the moment, to the plans to increase production, and move the majority of the oil to the coast for export. It is, therefore possible to foresee an increase in Iraqi production of perhaps a million barrels a day in the next couple of years. Is it likely? It is hard to say. Factional fighting is always hard to predict, and the willingness of those involved to use explosives makes it even more of a problem to predict what will occur, given the vulnerability of pipelines to attack.

Predicting how Iran will change is similarly conflicted, in that it is hard to predict the behavior of those who control the country, and in turn impact oil exports.

But putting this within the context of OPEC, I suspect that overall production will not fall much outside of the current volumes that the MOMR are predicting – which is sensibly overall stable output over the next year or so. And if that is the case, then I would, as mentioned last time, expect to see that the global surplus of oil supply over demand will gradually disappear over the next year, with the impact becoming evident once we reach the summer of 2016. It would be nice to be wrong, but I think it unlikely.

Tech Talk - The Price of Power, and its consequences

The changing colors of the leaves carry the message that winter will soon be here, and so it is time to stock the yard with wood to carry us through until spring. In Missouri I just found wood, cut to the length I need, and stacked, for $110 a cord and (since it has to be cut) it will arrive next week. Only the chimney then needs a quick sweep, and we’ll be ready for another season. (We burn just under a cord of wood a month, and this keeps the electricity bill sensible).

At one time the wood was insurance, in case of an extended power outage (and we had one that lasted three days, one winter) but we enjoy the heat from the tile stove, and so it is now part of our life. And with the continued risk of a loss of power, the insurance remains comforting.

Driving back from Maine a couple of weeks ago, gas prices fell over $0.25 a gallon along the 1,300 mile trip, another benefit of living in the Mid-West. But at both ends of the drive, the impact of fuel prices continues to slow economic growth, as it does nationally. Gail Tverberg has written of the inter-relation between the economy and fuel prices, most recently on Monday. However we disagree on one point, since she anticipates a potential significant drop in oil prices, which I do not.

In the early days of The Oil Drum I remember walking through the streets of Denver to a meeting with two other contributors, and suddenly realizing that I, the more technically based of the three, was by far the most pessimistic. Increasingly I am realizing that while this pessimism has not ameliorated, the current relative abundance of oil and gas in the United States has given many folk an undeservedly complacent view of the next few years.

Ron Patterson recently pointed out that if one discounts US production, the rest of the world has seen a decline in production, with non-US production now down around 2 mbd from its all-time peak. (If one also removes Saudi Arabian and Russian production from the mix, the decline gets closer to 3 mbd). Now to assume that this is totally due to a loss in production capacity would be a mistake. Saudi Arabia continues to adjust the volume of their production to try and keep global prices relatively stable, dropping production by 400 kbd in August. In the immediate short-term that was not enough for their purpose, and they are now lowering price a little, perhaps in order to sustain their market share. The cuts were in the range of $0.20 to $1.20 a barrel). Although it could also be a way of trying to sustain global growth at a time of weakness.

Figure 1. Global Production without including the United States – as plotted by Ron Patterson. I added the trend line at the end of the top plot.

These flutterings at the margin however don’t help my concerns, because they are focused only on the short-term, and don’t consider the overall situation. If the production from the rest of the world is declining at around 700 kbd, and Saudi Arabia will only produce to a maximum of 10 mbd, and Russia appears to be in that plateau that precedes decline, even without the loss in funding that recent US Government mandates will impose, then that leaves the growth in US production as being the only source to match both the decline in global production, and the continuing demand for more oil which together total around 1.7 mbd. And US production projections, even at their most optimistic can’t do this, even for one more year.

Figure 2. Projected Growth in US production (EIA)

The mathematics are, of course, not absolute numbers but remain somewhat flexible. There could be a sudden cessation of conflict in Libya and full production might return; all conflict might end in Iraq and production development might surge at the investment opportunity; and sanctions might disappear against Iran – but somehow I don’t see any of these happening.

The argument of the Cornucopians, that one can either find a substitute for the fuel in some other resource, or that technology will suddenly become available to allow unanticipated levels of production from the existing reserves and resources is, perhaps why I – knowing a fair bit about the technology – am more of a pessimist than many others.

The analogy that I use may be a little crude – but you can’t have a baby in a month by making nine women pregnant. You can’t create new technology out of thin air by suddenly investing a few billion in a bunch of scientists pulled from lists on the Internet either. There are not that many folk who are sufficiently expert to be useful, particularly in the fields that relate to the production of fossil fuels. Many of those who do exist are, like me, coming to the end of their professional lives, so that the skill sets and knowledge bases that they have built are disappearing. Many of the doctorates that we see today are based more on computer modeling than on hands-on experimentation and engineering. And unfortunately the knowledge that we have about the nature of the rocks at depth, their behavior and how to change the way in which they yield their fluids still leaves a lot to be desired, when it comes to validating the models that are produced.

But even if such new technology were developed it would take decades to see it adopted in sufficient volume across the world that it would have a significant impact on global fuel production. It was for this reason that, back in 2005, the Hirsh Report discussed the need for a twenty-year lead-time to develop new technology that could replace our needs for fuel. The time that they suggested that we had available now is beginning to seem very optimistic, while the moves to ameliorate the problem have been judged less critical and thus no longer receive the attention and funding that the have in the past.

And so, when the crisis comes, and this is increasingly likely to come in the next two years, there will be no good answers, just tightening supplies and rising prices. This is perhaps why I am beginning to think that the next President of the United States still may well be, despite all the gaffs, Brian Schweitzer.

Tech Talk - Changes in global supply and demand

At the beginning of the month I pointed out that there are three components to the coming Energy Mess. The first of these is the steady increase in global demand for oil and its products, the second is the decline in production from existing wells and fields, and the third is the shrinking pool of places from which new oil can be recovered to make up the difference between the first two.

Internal demand gnaws away at that available for export, as the situation in Saudi Arabia clearly illustrates:

Figure 1. Changing relation between Saudi production, internal demand and thus available exports. (Energy Export Databrowser)

Internal consumption has now reached 3 mbd – out of a production of around 10 mbd, a trend bound to go higher, as the country’s population continues to grow, having risen from 20 million in 2000 to 28.3 million in 2012, with no significant change in rate apparent.

Back in 2011 Chatham House produced a report expressing concern over the future that this prefaces. The report began with this predictive plot:

Figure 2. Projected changes in Saudi production and consumption (Chatham House )

It is regrettable to note that there is really no viable justification given for the assumption that Saudi production will rise from the current 10 mbd to the roughly 14 mbd that the plot suggests by 2020. Without that increment the world is going to be in quite a bit of hurt somewhat earlier than the above graph would suggest – as perhaps will be the Kingdom of Saudi Arabia. (Hopes for large increases in domestic production of natural gas seem to have foundered in their tight shales and are switching to efforts to develop the tight sand deposits although the mechanisms of gas flow may not be as advantageous in the sand. Similarly there is little in the report to explain why demand – once it reaches the current levels, should suddenly stabilize for three years before starting back up. Without that “hiccup” the dark blue line (which is already down to around 7 mbd, not 8) will rather continue downward, rather than the optimistic uptick that Chatham House predicted.

On the other side of the house China provides a clear example of the changes in global demand, with imports in 2013 having increased by 5.8% over 2012, and with consumption now above 10 mbd.

Figure 3. Changing relation between Chinese production, internal demand and thus necessary imports. (Energy Export Databrowser)

The other country where demand can clearly be seen to increase is India. The recent flattening of demand is likely to prove only transient, given the policies of the new government.

Figure 4. Changing relation between Indian production, internal demand and thus necessary imports. (Energy Export Databrowser)

The Indian economy has been growing at around 7% a year since 2000 and the EIA anticipates that by 2020 it will become the world’s largest oil importer, even though overall demand will not surpass China’s – which is anticipated to rise to 15.7 mbd by 2025. Although a primary focus for the new government is to give every household at least one light bulb by 2019, a significant portion of this will come from solar power. This is particularly necessary in rural areas where there is poor to no grid service. However experience in Botswana would suggest that this policy can be more difficult to achieve and sustain, given the difficulty in getting adequate maintenance outside of the cities. The Energy and Resources Institute anticipates that growth will exceed 8%. (It should be noted that the Director-General of TERI is R K Pachauri – better known for his role at the IPCC). It might further be noted that while he was still Chief Minister in Gujarat before the election, the new Indian Prime Minister had raised the GDP of that state to an average of 13.4% in comparison with the national rate of 7.8%.

To a degree this problem of imbalance in the supply:demand situation that will develop in the next couple of years will be rectified by a change in the price structure of oil. Tightening of supply against even current levels of supply (let alone that needed to meet the July 2014 OPEC MOMR estimate of a continued growth in demand of the order of 1.16 mbd) will lead to an increase in price. It is that cost increase that will most likely impact countries such as India, who have, in the past, been bid out of a number of foreign oil investments by China, and who are likely to see that situation continue, of not get worse.

The presumption that Russia will be able to help China by exporting more oil East, while sustaining its exports to the West, is likely an unrealistic projection. Russia is already seeing their overall export levels decline, even before production itself significantly falls off, and the combination will tighten the market in the near future.

Figure 5. Changing relation between Russian production, internal demand and thus exports. (Energy Export Databrowser)

China is currently seeing an ongoing internal fight over the China National Petroleum Corporation (CNPC). Jiang Jiemin has been arrested and the investigation is progressing down his chain of command and influence.

CNPC is one of the world's largest companies, with global operations and 2013 revenue of $432 billion. Its publicly listed subsidiary, PetroChina, trades in Hong Kong, Shanghai and New York and is the world's fourth-biggest oil producer by market capitalization. Jiang ran both the parent and PetroChina from 2007 until last year, when he briefly headed the State-Owned Assets Supervision and Administration Commission (SASAC).

The investigation has already touched CNPC group operations in Canada, Indonesia, China and Turkmenistan, say people familiar with the proceedings. In addition to Jiang, the Chinese authorities have confirmed the arrests of CNPC vice president Wang Yongchun, PetroChina vice presidents Li Hualin and Ran Xinquan, and the listed unit's chief geologist, Wang Daofu.

The arrests and investigations will likely slow the rate of Chinese investment in the foreign energy market, but is not likely to have any impact on internal energy consumption. Rather it may make it more difficult for China to sustain their necessary supply of oil as times become more troubled.

An increase in the price of oil, just as the links to foreign suppliers become questioned through this internal investigation that may spread beyond China, may weaken those links and give countries such as India an opportunity to achieve supplies that might otherwise be more difficult to achieve.

OGPSS - The Harvard Energy Report, another cough

The OGPSS posts of the last few months have been following a path of looking in a relatively realistic manner at crude oil production with emphasis on that coming from the United States, Russia and Saudi Arabia – the current focus of the weekly pieces. An earlier piece, looked at a Citigroup report of considerable optimism, and the post explained why, in reality, it is impractical to anticipate much increase in US production this decade. Since then, after reviewing the production from Russia, several posts have shown why their current lead in daily crude oil production is likely to be soon over, and that Russian production will then decline, as the oil companies are not bringing new fields on line as fast as the old ones are running out. Saudi Arabia, as the current section of posts are in the process of explaining, is unlikely to increase production much beyond 10 mbd, since Ghawar, the major field on which its current production level is built, is reaching the end of its major contribution, though it will continue to produce at a lower rate into the future. The bottom line, at least to date, is that there is no evidence from the top 3 producers that their production will be even close, in total, to current levels by the end of the decade.
 So, (h/t Leanan) there now comes an Energy Study from Harvard which boldly states that this is rubbish, and that by 2020 global production will be at 110.6 mbd and these concerns that most of us have at The Oil Drum (inter alia) are chimeras of the imagination.
Figure 1. Anticipated Growth in global oil production by the end of the decade (Maugeri, Leonardo. “Oil: The Next Revolution” Discussion Paper 2012-10, Belfer Center for Science and International Affairs, Harvard Kennedy School, June 2012. )
It is therefore pertinent to begin with examining where the study (which was prepared with BP assistance) anticipates that the growth in supply will come from. 
 That too is shown as a plot: 
  
Figure 2. Anticipated sources of the growth in global production by 2020 (showing only the top 23 producers). ((Maugeri, Leonardo. “Oil: The Next Revolution” Discussion Paper 2012-10, Belfer Center for Science and International Affairs, Harvard Kennedy School, June 2012.) 
 It is instructive, in reading this plot, to first recognize that it is a plot of anticipated production capacity, rather than projected actual production. The reason for this can perhaps be illustrated by an example. Within the current production capacity that Saudi Arabia claims adds up to 12 mbd is the 900 kbd that will come from Manifa as it is further developed and comes on line within the next few years. However at that time the increase in production is going, to some degree, to offset the declines in existing wells and producing fields that will become more severe as more of existing horizontal wells water out. Manifa is not currently in significant production, and is unlikely to be at such a level for at least another 18-months, with production being tied to the construction of the two new refineries being built to handle the oil. It is not therefore a currently instantaneously available source of oil. At a relatively normal 5% per year decline in production from existing fields, Saudi Arabia will have to bring on line (and sustain) at least 500 kbd per year of new production, and while it is likely that it can do this for a year or two more, betting that it will be able to do this and to raise production 2 mbd or more in 2020 is on the far side of optimistic. Just because a reserve exists does not mean that it can be brought on line without the physical facilities in place to produce it. 
 It is interesting, however, to note the report’s view on field declines in production:

Throughout recent history, there is empirical evidence of depletion overestimation. From 2000 on, for example, crude oil depletion rates gauged by most forecasters have ranged between 6 and 10 percent: yet even the lower end of this range would involve the almost complete loss of the world’s “old” production in 10 years (2000 crude production capacity = about 70 mbd). By converse, crude oil production capacity in 2010 was more than 80 mbd. To make up for that figure, a new production of 80 mbd or so would have come on-stream over that decade. This is clearly untrue: in 2010, 70 percent of crude oil production came from oilfields that have been producing oil for decades. As shown in Section 4, my analysis indicates that only four of the current big oil suppliers (big oil supplier = more than 1 mbd of production capacity) will face a net reduction of their production capacity by 2020: they are Norway, the United Kingdom, Mexico, and Iran. Apart from these countries, I did not find evidence of a global depletion rate of crude production higher than 2-3 percent when correctly adjusted for reserve growth.

Sigh! I explained last time that with the change in well orientation from vertical to horizontal, that there was a change in the apparent decline rates. This is because when the wells run horizontally at the top of the reservoir that they are no longer reduced in productive length each year, as vertical wells are, as the driving water flood slowly fills the reservoir below the oil as it is displaced. This does not mean that though the apparent decline rate from the well has fallen that it will, in the ultimate, produce more oil.
 The amount of oil in the region tapped by the well is finite, and when it is gone it is gone, whether from a vertical well that shows that gradual decline with time, or from the horizontal well that holds the production level until the water hits the well and it stops. I am not sure that the author of the report understands this. 
 The point concerning support logistics is critical in a number of instances. The political difficulties in increasing production from the oil sands in Alberta, through constraints on pipeline construction either South or West, are at least as likely to restrict future growth of that deposit as any technical challenge. The four countries that the report sees contributing most to future oil supplies are (in the ranked order) Iraq; the United States; Canada and Brazil. For Iraq he sees production possibly coming from the following fields, within the next eight years. 
   
Figure 3. Anticipated production gains in Iraq in the next eight years. (Maugeri, Leonardo. “Oil: The Next Revolution” Discussion Paper 2012-10, Belfer Center for Science and International Affairs, Harvard Kennedy School, June 2012. )
 I understand that one ought to show some optimism at some point over Iraq, but it has yet to reach the levels of production that it achieved before the Iran:Iraq War, and that was over some time ago. The EIA has shown that it is possible to get a total of over 13 mbd of production, but it requires investment and time, and some degree of political stability in the country. That is still somewhat lacking. Prior to that war Iraq was producing at 3.5 mbd, the production curve since then has not been encouraging:

Figure 4. History of Iraqi Production since the start of the Iran:Iraq War. (EIA) 
 Recognizing that the country has problems, the report still expects that there will be a growth in production of some 5.125 mbd by the end of the decade. This appears to be a guess as to being some 50% of the 10.425 mbd that the country could potentially achieve. 
 As for US production, this is tied to increasing production from all the oil shales in the country, which will see spurts in growth similar to that seen in the Bakken and Eagle Ford.

I estimate that additional unrestricted production from shale/tight oil might reach 6.6 mbd by 2020, or an additional adjusted production of 4.1 mbd after considering risk factors (by comparison, U.S. shale/tight oil production was about 800,000 bd in December 2011). To these figures, I added an unrestricted additional production of 1 mbd from sources other than shale oil that I reduced by 40 percent considering risks, thus obtaining a 0.6 mbd in terms of additional adjusted production by 2020. In particular, I am more confident than others on the prospects of a faster-than-expected recovery of offshore drilling in the Gulf of Mexico after the Deepwater Horizon disaster in 2010.

As I noted in my review of the Citicorp report this optimism flies in the face of the views of the DMR in North Dakota – who ought to know, since they have the data. The report further seems a little confused on how horizontal wells work in these reservoirs. As Aramco has noted, one cannot keep drilling longer and longer holes and expect the well production to double with that increase in length. Because of the need to maintain differential pressures between the reservoir and the well, there are optimal lengths for any given formation. And, as I have also noted, the report flies in the face of the data on field production from the deeper wells of the Gulf of Mexico. 
 It seems pertinent to close with the report’s list of assumptions on which the gain in oil production from the Bakken is based:

*A price of oil (WTI) equal to or greater than $ 70 per barrel through 2020 

*A constant 200 drilling rigs per week; 

*An estimated ultimate recovery rate of 10 percent per individual producing well (which in most cases has already been exceeded) and for the overall formation; 

*An OOP calculated on the basis of less than half the mean figure of Price’s 1999 assessment (413 billion barrels of OOP, 100 billion of proven reserves, including Three Forks). Consequently, I expect 300 billion barrels of OOP and 45 billion of proven oil reserves, including Three Forks; 

*A combined average depletion rate for each producing well of 15 percent over the first five years, followed by a 7 percent depletion rate; 

*A level of porosity and permeability of the Bakken/Three Forks formation derived from those experienced so far by oil companies engaged in the area. 

Based on these assumptions, my simulation yields an additional unrestricted oil production from the Bakken and Three Forks plays of around 2.5 mbd by 2020, leading to a total unrestricted production of more than 3 mbd by 2020.

Enough, already! There are too many unrealistic assumptions to make this worth spending more time on. To illustrate but one of the critical points - this is the graph that I have shown in earlier posts of the decline rate of a typical well in the Bakken. You can clearly see that the decline rate is much steeper than 15% in the first five years.Figure 5. Typical Bakken well production (ND DMR )  
Oh, on a related note the Alaskan pipeline was running at an average of 571,462 bd in May.

OGPSS - A recap with some updates on North American production

This series of posts has just completed a review of the different regions of Russian oil production, with the conclusion that while Russia may maintain current production levels of around 10.4 mbd for a short while, it faces rising domestic consumption levels at the same time that it is not replacing existing production at a fast enough rate to be able to sustain exports. Without more investment than is likely available, the rate of new field development (given the harsh and remote nature of the sites) means that there will be a slow decline in available oil to the market starting fairly soon. (Given the large supplies of natural gas that are coming available, this series is going to focus a bit more on oil as we continue the review).

As the series continues, and moves slightly down the list to consider the future of the oil and gas fields in Saudi Arabia, it is worth noting that while there is little that Russia can do to significantly raise production in the short term, that does not hold for the desert kingdom. However, before moving on to KSA in detail, this week is a pause to consider some contextual changes in the overall picture.

One of the questions that has been raised many times relates to the reality of the true maximum production levels that Saudi Arabia can achieve. As oil prices have continued to rise politicians are calling for the Saudi’s to increase oil production, so that the price may fall. (This is a rather odd and unrealistic request when the KSA needs all the income it can get to help domestically.) The EIA, in considering the global oil flow as sanctions begin to bite on Iran have projected that OPEC has a spare capacity of 2.5 mbd, most of which comes from KSA. At present the KSA is producing at around 9.7 mbd up some 600 kbd from this time last year, according to the EIA, although there is a little question as to how accurate that number is. (The IEA is reportedly saying that KSA is already producing at 11.5 mbd.. However the IEA counts all liquids, as Gail has pointed out, while EIA values are for the crude and condensate, which add up to 9.7 mbd, so that while there appears a discrepancy there really is not). The debate is likely to see some harder numbers in the months ahead. Iran is already having problems marketing their oil, since after January 23rd the European Mutual Protection and Indemnity Club is no longer covering shipping contracts. This is making it difficult for consumers such as India to maintain supply, and they are already considering the use of sovereign guarantees for its shipping lines. At the same time the EU is not calling for coverage to be phased out until July 1.

The EIA report notes that Iran is currently the 5th largest producer of liquid fuels at 4.1 mbd, although it consumes 1.8 mbd of that internally. Thus the threat to the global market runs at around a 2.3 mbd reduction on current overall demand of around 88.1 mbd. The series will discuss Iranian production, and its prospects somewhat later, but before getting into an analysis of Saudi Arabia, it might be worth just a quick glance back at a couple of countries that have been covered earlier.

Estimates of future production are only that, and, as has been noted in comments on recent posts, not all anticipated production or plans work out as anticipated. To give but a few examples pointed out in comments, and elsewhere:

The Russian oilfield at Yuzhnoye Khylchuyu was initially estimated to hold 505 million barrels of oil, but has now been reported as only having reserves of 142 mb.. (Noted by voiceinyourhead) On the other hand the Sarmatskoye field in the Caspian is now considered to have double the original estimate, and is estimated as just under 1 billion barrels of oil equivalent in natural gas and condensate. It is anticipated to come on stream in 2016. And, while on the topic of natural gas, both toolpush and RayRay have noted that the natural gas from Sakhalin Island is not going to see the 3rd LNG train that I mentioned in the post on that topic, and that the natural gas will instead feed into a pipeline to the mainland.

In regard to the posts that were written to cover the United States and Canada, the February monthly flow of oil through the Alaskan pipeline has fallen to an average of 609,805 bd. This is down from an average of 624,716 bd in January and gets the flow closer to the point where solidifying wax and water start to cause problems.

In the time since the posts were written on North American production and promise (politically including Canada with the United States makes the overall change in production figures look better than if the figures were based solely on US production, particularly as oil from the Albertan oil sands rises to production levels of 3 mbd by 2015) the Canadian National Energy Board (NEB) released their “Canada’s Energy Future: Energy Supply and Projections to 2035” report. In seeking to predict future production the NEB anticipated that the price of a barrel of oil would rise relatively modestly over the next 20-years. Even in their high estimate they do not see the price rising to more than $160 a barrel by 2035 (who would bet that the estimate is exceeded this year or next?).

Canadian estimate of the future of crude oil prices (NEB )

The report estimates that in the Reference case, oil production from the oil sands will reach 5.1 mbd in 2035, which is three times 2010 production. This will be mainly from in-situ methods.

Canadian crude oil production (NEB )

Over the ten years from 2010 to 2020 in-situ production is anticipated to grow at 9% p.a., while mining production will rise at 5% p.a. The North West Upgrader is anticipated to come on stream in 2014, with an initial 50 kbd of throughput. Carbon dioxide produced during the process will be used in Enhanced Oil Recovery (EOR) locally. If the price rises to the highest levels anticipated, then production might be estimated to rise to just under 7 mbd in total for Canada by 2035.

Canadian production for different case estimates of price, as above (NEB

However the NEB do recognize that domestic consumption will affect overall supply, but consider that it will likely only significantly impact the lighter crudes, and that the difference between the roughly 4 mbd of heavy crude produced and the 3.8 mbd available for export in 2035 will reflect a relatively constant 0.2 mbd of internal consumption.

Canadian light oil future predictions (NEB

With considerably more oil, therefore, being available from Canada, albeit there remain concerns over how much will be shipped to the USA, there is somewhat less pressure on domestic producers. Which is likely good news since the likelihood of US production remaining at current levels is still doubtful.

One of the hopes for the future comes from the wells being drilled in the Gulf of Mexico, with DoE projecting that gulf production will rise to some 2 mbd by 2020, from 1.3 mbd at present.

One concern that remains however, lies in the actual levels of production that will be achieved. As Jean Laherrère has noted the wells in the deep water have not all held up their promise, peaking on average within a year of coming on line. Jean notes that the production decline with the Mars and Ursa fields are at about 9% per year, which he notes is less than half the decline rate at Thunder Horse. Darwinian is also tracking production, and although he notes that Tahiti is performing relatively consistently at 110 kbd, Atlantis is not coming close to the 185 kbd projected.

Atlantis production (Darwinian )

Exploration and development in the Gulf are, apparently now back to pre-Deepwater Horizon levels, one can only hope that future developments will be less dramatic and more successful.

The speed of that recovery is encouraging, though the results to date have been a little less promising than anticipated. But, as with operations in the Arctic, investment costs are going to be high for any new finds that are viable, and will take a number of years to develop, at a time when demand is going to continue to increase. The Gulf discoveries, for example, will likely start to come ashore about the time that the Bakken and Eagle Ford plays start to fall in production, and thus, overall, may not give the boost to American volumes that are currently being projected.

OGPSS - Future Russian production from the Arctic

In the past few weeks I have been looking at the potential for sustainability in oil and gas production in Russia, now producing at a predicted recent peak of 10.36 mbd, when condensate is included. But the question increasingly becomes whether or not Russia can sustain these levels through this decade, as has been assumed by those suggesting that there will be no supply problems in the near future. In order to sustain this level of production, against falling volumes from the current major sources in Western Siberia (estimated as 300 kbd in 2010 ), Russia is so far relying on bringing new fields into production in Eastern Siberia and Timan-Pechora (as well as some increase in condensate as natural gas production continues to increase). However these developing fields, as a broad generalization, are at a size of about 500 mbd each, with an anticipated maximum individual production level of around 150 kbd. (Prirazlomnoye for example, which is coming on line has 526 million barrels in reserves, and will be producing at 132 kbd).

Prirazlomnoye drilling rig representation (Gazprom).

Since the high flow rates will likely not be sustained for long intervals, and declining production in Western Siberia will continue, so Russia will need to continue major programs of development to find further fields to bring on line later in the decade and beyond. In addition the declining production in other fields (which might increase overall decline in existing production to 5% or more, i.e. above 500 kbd) will add further pressure to sustain current levels, particularly given the criticality of oil and gas income to the Russian Government.

With much of the land already surveyed, the potential for large fields lies mainly offshore, and particularly in the various national continental shelves and the disputed underwater territory between them in the Arctic. It is a region where there are multi-national concerns and involvement, with the USGS having previously estimated that it is home to about one-fifth of the world’s undiscovered, but yet recoverable oil and natural gas resources, an estimate, at the time, of 44 billion barrels of oil and 1,670 Tcf of natural gas.

Map of the Arctic showing relative location of some development sites (Google Earth)

From the US perspective the US Bureau of Safety and Environmental Enforcement ((BSEE) seems finally willing to let Shell begin exploratory drilling in the shallow waters of the Chukchi Sea, although there has been a challenge to the recently awarded air Permit from the EPA. At the same time that the USGS is set to issue a new report that projects that shales on the North Slope may hold as much as 80 Tcf of natural gas and 2 billion barrels of oil, with initial drilling to prove the reserves anticipated to start this year. But those developments are on the other end of Russia, to the majority of current developments.

The recent discoveries by Statoil off the Norwegian coast and in the Barents Seas(at Skrugard-Havis, and Aldous Major South, show the potential that still remains in the North. Roughly a third of the world’s largest gas fields lie north of the Arctic Circle with Russia having significant reserves among them.

World’s largest gas fields (can you name the others?) (Shtokman )


Russia is therefore moving toward a planned program of development of the resources off its own continental shelf, where it is expected to be able to produce up to between 0.8 and 1.6 mbd of oil production and 18 to 20 bcf/day of natural gas. Part of the problem, however, is going to be cost. The new program is expected to cost some $216 billion, at a time when the investments in developing the current projects in Yamal and Eastern Siberia are also demanding large investment, if those goals are to be met.

Definitions of regions offshore (pertinent in future debates over who owns what in the Arctic) (Extended Continental Shelf Project)

TNK-BP are spending $12 billion to develop the Russkoe, Suzunskoe, Tagulskoe, Russko-Rechenskoe, and Messoyakhskoe fields in the Yamal region, with the hope that these can contribute at the end of this decade, and into the next, at a total level of around 300 kbd. Suzunskoye is targeted to begin production in 2016, running at around 100 kbd once on line. Russkoye is projected to start in 2017, and produce 150 kbd of a heavier oil. Tagulskoye and Russko-Rechenskoe will come on line in 2019. Messoyakhskoe is a joint project with Gazprom and (at $17.3 billion cost) will not come on stream until 2024, at 320 kbd. These fields will, however, feed into the pipelines that head East, to China, Japan and Korea.

Closer to Murmansk Exxon Mobil and Rosneft are exploring blocks in the Kara Sea anticipating that it may ultimately cost $500 billion to develop reservoirs in the difficult conditions with moving icebergs but for now expect that initial exploration and development will cost in the $10’s of billions.

Perhaps, of these fields it is the Shtokman natural gas field, which lies under the Barents Sea, 550 km north of the Kola Peninsula which has drawn most attention. Currently expected to start production in 2016, costs may well run over $15 billion.

Location of the Shtokman field (Shtokman Project)

Shtokman was discovered in 1988 (the name comes from Professor Shtokman who gave his name to the research vessel that found the field and contains an estimated 85 Tcf of natural gas, as well as around 400 million barrels of concentrate. It lies under 1,000 ft of water, with the interesting occasional problem of visiting icebergs that can weigh up to 4 million tons apiece. Planned to come on line in with an average production of 2.3 bcf/day, the supply (as the above map shows) half the supply is anticipated to feed into the Nord Stream pipeline for shipment to Western Europe, while the rest is converted to LNG and will be shipped out by tanker. Gazprom has recently increased the area of its license rights for the field, with a new date for commitment set for this month.

The current intent is to use a series of buoyed risers to connect from the wells to the surface, so that, should an extra-large iceberg appear the Floating Production Unit (FPU) can detach and move out of the way – should tugs not be able to divert it.

Artist’s concept of the layout for development of the Shtokman field (Shtokman Project)

The pipeline shipments are planned to begin in 2016, but the LNG shipments (some 7.5 million tonnes a year) will not start until 2017. The project is a joint venture between OAO Gazprom, Total S.A., and Statoil A.S.A.

The USGS has noted that there are considerable regions in the Arctic that have, as yet, been poorly explored. In 2005 they produced this map of the then state-of-knowledge:

Status of oil and natural gas evaluations around the Arctic (USGS)

From this they produced two maps showing the location of possible undiscovered deposits. The potential undiscovered oil deposits are shown below:

Potential oil discoveries and size remaining in the Arctic. (USGS)

The point however, is not that there is going to be no more oil, it is just, as the production schedules above illustrate, that it is going to be slow and expensive to develop that which remains. Over the next decade Russia will have to bring three or four new fields on line each year at around 100 – 150 kbd each, if it is to sustain production at current levels. It is somewhat difficult to see them being able to hold to that schedule, even for a year or two.

OGPSS - The oil in Eastern Siberia

In the last post on Russian oil production I discussed the amounts of oil that have been produced from Western Siberia, the region that currently produces the most, and which in its prime contained the second largest producing oilfield in the world at Samotlor. But those fields are now in decline, and while modern technology is seeking to retain as much production as possible, Russian investment is moving further East to the region known as Eastern Siberia. It is not the most hospitable of places, even when compared with Western Siberia.

The cold is staggering, even for Siberia: winter temperatures can fall to minus 70 degrees Fahrenheit, at which point all outside work is banned. The nearest human settlement is 250 miles away, and the forests are full of bears, wolves and elk. . . . Workers shivered in winter and in summer were tormented by midges so vicious they have been known to kill cows.

Depending on who it is that you consult, Eastern Siberia can either include, or not, some of the northern part of the Western Siberia Basin:

Eastern Siberia as defined by Stratoil.

Clearly, however, when one compares the two regions, the prospects for Eastern Siberia are much less well defined, and much less well developed. However it is a region that the Government is anxious to develop and in July 2009 the export duty on the 13 oil fields in Eastern Siberia, including Vankor, was annulled. (at the time the duty on $70 a barrel oil would have been $34). This was expanded to all 22 fields in East Siberia the following January. The tax was re-instated at a lower level than usual (45% of the excess over $50 a barrel) in July 2010.

Details of some of the fields in Eastern Siberia. Note that the region is still defined as “prospective” by Irkutsk Oil. (Map from 2009)

When the Eastern Siberian Pacific Ocean (ESPO) pipeline started shipping oil to China in 2010 the two fields that it initially tapped into included both Vankor, which was defined as being in Eastern Siberia, and which was discovered in 1988 as the largest discovery in 25-years at the time, and came on line in 2009, and from Samotlor, which as was mentioned last time, is in Western Siberia. (That feed flows through the Purpe: Vankor pipeline) When phase 2 is completed this year the ESPO pipeline will be able to carry up to 1.6 mbd, which is about a third of the total amount that Russia exports. There is some question, however, whether Russia will be able to achieve the volumes that are going to be required for sales to the East, at the same time as it meets demand from the West. Projected demands of over 11 mbd would require an increase in production over last year of more than 600 kbd, and the ability of Russia to meet that increase is one of the current questions.

East Siberian Pacific Ocean (ESPO) pipeline path (Financial Times ) showing the part remaining to be completed to Vladivostok

The initial fields scheduled to feed into the pipeline included Vankor(400 kbd), Verkhnechonsk (200 kbd) and Talakan (140 kbd). In phase 1, which first delivered oil to the port in Kozmino Bay on December 28th, the oil is transferred to rail cars in Skovorodino and carried by rail the rest of the way. Phase 2 completes the pipeline.

Vankor, now that it is connected through Purpe into the Transneft oil pipeline network can supply oil to the West as well as to the East and has been delivering to both, with roughly 55% going East. Vankor is operated by a subsidiary (Vankorneft) of Rosneft, and has proved reserves of 1.6 billion barrels, and probable reserves of about the same. In 2010 there were 124 production wells in operation with another 19 drill pads completed. The average well was producing at 2,606 bd, though this was constrained as the surface treatment plant had not been completed. (It now has). Plans are for a total of 425 wells to be drilled, of which 307 will be horizontal completions. Peak production is scheduled to reach 510 kbd in 2014, and be held at that level. Gas injection will be used to hold reservoir pressure, and is expected to increase the oil recovery factor from the 0.34 Russian average to 0.434. Advanced technology has also helped:

The well drilling operations also involve advanced technologies. Rotor-controlled systems increased overall drilling efficiency by 2.5 times, while the use of smart well systems for inflow management produced over 500,000 additional tons of oil in two years.

Wear-resistant equipment used at the field ensures a flow rate of up to 1,500 tons per day (over 430 tons per day on average compared to the national average daily flow rate of 39.5 tons).

Gas production will drive a local power plant, as well as being available for re-injection.

The gas (its volume exceeds 1 billion cubic meters per year) will mainly be consumed by a gas-turbine power plant. In order to maintain the reservoir pressure, 2.5 billion cubic meters of associated gas will be re-injected annually. There are plans to deliver up to 5.6 billion cubic meters per year to Gazprom’s transportation system.

Verkhnechonsk, which came on line in 2008 is still only pumping at around 100 kbd but has recently hit a problem in that though there is more than the usual amount of natural gas coming out with the oil, there is nowhere to deliver it. (Irkutsk is 750 miles away and there is no gas pipeline) It is therefore being flared. It is hoped to start reinjecting the gas in 2013 (they have to build a compressor first) which is when the field should reach its 200 kbd peak, four years earlier than initially expected. It has around a billion barrels in reserve, and is about twice as old as the average oil field. Perhaps as a result the oil is cooler than that found almost anywhere else and, has to be heated to stop wax precipitating out and to allow the water and the high concentration of salts to be removed. It is being developed with horizontal completions.

Talakan came on line with the ESPO pipeline connection in October 2008. It is operated by Surgutneftegaz, who paid 1.66 billion rubles ($45.8 million) for it. It is believed to hold about 0.8 Tcf of natural gas and up to 2.3 billion barrels of oil.It is sometimes referred to as the Severo-Talakanskoye field and initial production has been low, until a booster station is built in 2013. Output will then be 16 kbd snd it will only slowly ramp up to the 140 kbd target.

Within Eastern Siberia’s Sakha (Yakutia) Region, the major strategic fields include the Verkhnevelyuchanskoye oil and gas field, the Sobolokh-Nedzhelinskoye and Srednetyungskoye gas condensate fields, and the Chayandinskoye and Tas-Yuryakhskoye oil and gas condensate fields.

The Chayandinskoye oil and gas field will be developed by Gazprom, starting in 2014 for the oil (576 million barrels), and 2016 for the gas deposits (about 46 Tcf), with the products being shipped to Valdivostok for export. It is expected that it will produce at around 2.9 bcf/day.

The Tas-Yuryakhskoye oil and gas condensate field will also be developed by Gazprom, however that process has just been completed last December and so plans are indefinite. The prices paid are:

The company will pay 7.29 billion rubles for the right to use the sites: the payment for the Verkhnevilyuchanskoye gas condensate field is set at 3.63 billion rubles, Tas-Yuryakhskoye is at 2.479 billion rubles, Sobolokh-Nedzhelinskoye gas condensate field is at 344 million rubles, Srednetyungskoye is at 836.6 million rubles.

(There are roughly 30 rubles to the dollar. Development of the fields will require additional pipeline construction, which is anticipated to start this year. The total gas reserve in the four fields is estimated to lie around 17.5 Tcf.

The ESPO pipeline is also now, since last November, carrying oil from the Irkutsk region, where the Yaraktinsky field has begun producing at 35 kbd.

And speaking of Gazprom they have just taken control of the Kovykta gas field from BP, after a long struggle. Kovykta remains relatively undeveloped with about 70 Tcf of natural gas and 500 million barrels of gas condensate. It is suspected that the gas will now go to a market in China, though whether this will happen before 2018, when Gazprom was anticipating developing the field, is open to question.

Possible routes for the Kovykta resources (BP )

In total the reserves in Eastern Siberia are likely to be only a fraction of those that were found in Western Siberia, but as the latter are in decline, finding a replacement means that even these smaller and more difficult reserves become more attractive. Not all the fields have yet been defined, there was a new one announced with a billion barrels of reserves, near Irkutsk in January 2010, so there is still a possibility for greater finds. It remains, however, (with Alaska and Fort McMurray) one of the last frontiers that are not in deep water.

OGPSS - Oil and Natural Gas in the Volga-Ural Basin

In the last post on the oil and gas fields of the Northern Caucasus, I commented that one of the reasons that these older oil and gas fields were being further developed was due to the introduction of advanced Western techniques. As John Grace points out in “Russian Oil Supply” another reason that there are fields left to develop is due to the philosophy by which the Soviet government marshaled resources to keep the Union supplied with oil for domestic and export use. Because of its centralized nature, as the resources in one region declined, so the financial support and technical equipment were removed and taken to other parts of the country, where a more plentiful supply source was available. This frequently left smaller fields behind, and removed the incentive for further exploration in the older regions.

The first region to see that removal of support was around Baku, and then the North Caucasus, as more plentiful resources became evident up in the region around Almetyevsk, in what is now the Republic of Tatarstan. The region lies considerably north of Volvograd (Stalingrad) and further east, though it still lies on the banks of the Volga, though also just to the West of the Ural Mountains, and thus the more popular and general description is the Volga-Ural Basin.

Relative location of Almetyevsk, showing the Volga (black line) Stalingrad (now Volvograd), and the Caspian. (Google Earth)

The Volga-Urals Basin is now recognized to be extensive with the USGS estimating that there remain some 1.5 billion barrels of oil, and 2.3 Tcf of natural gas (at the mean) left to be discovered and produced.

Extent of the Volga-Ural Basin (USGS )

Prior to the Second World War, the region saw little development. Tar pits within the Basin had indicated the presence of oil, and Grace has pointed to outhouses exploding around the town of Orenburg, as natural gas from the underlying field collected in the buildings, as the first indicator of the presence of that field. But the fields all appeared to be small, and with enough production from Baku and Grozny to meet existing needs, there was little initial incentive to develop what seemed to be a series of small shallow fields.

Oilfields of the Volga-Ural Basin (Russian Oil Supply)

With the German advances into the Caucasus, that oil became lost or more difficult to bring north, and the relative security of the Volga-Urals meant that a greater effort was made to bring those fields on line. Production had reached 55 kbd in this “second Baku” by the end of the war. The first break had come with the discovery of the relatively shallow oil field at Tuymazinskoye in 1937, but it was not until they deepened one of the wells into the lower Devonian layers in 1944 that they hit the more productive reservoirs and the potential of the region became evident. In 1943 a test well had been sunk at Shugurovo and flowed at 140 bd from a reservoir at 2,000 ft. With the knowledge of the deeper reservoirs a third well in the region, near the town of Romashkino was drilled down to 6,463 ft, penetrating the casing on July 10, 1948. Because of formation damage the well was slow to produce, but within a short while was up to 876 bd. Holding 17 billion barrels of oil, and thus the largest oil reservoir discovered at the time, the Romashkino field (which included the well at Shugarovo) had been tapped. In time another seven fields, each of more than a billion barrels, were added to the inventory for the Basin.

The deeper Devonian beds required a number of innovations to produce at the levels that Moscow was requiring. The first of these was the development of the down-hole turbo drill. Russian steel making was not on a par with that available in the West, and the torque requirements for drilling the harder and deeper rocks were a challenge, overcome by putting the turning motor at the bottom of the well. The second problem that arose was in maintaining well pressure as the oil was removed. The use of contour water flooding evolved from the initial Master Plan in 1956 and was successively modified to perimeter flooding, so that by 1960 the basin was producing at 2.9 mbd, comfortably exceeding the target 1.2 mbd. Romashkino itself peaked at just under 1.6 mbd in 1968 and began to decline in production in 1976. As production declined, so the water cut also rose and by 1993 production was down to around 300 kbd, with about 85% water cut.

Production of oil from Romashkino (Russian Oil Supply)

Overall production from the Volga-Urals Basin includes some of the fields that lie outside of Tatarstan, as a result the decline of the Basin was a little later than that of the main field within it. For example further to the East lies the Arlan field in Bashkortostan, run by Bashneft. That too, however, is now in decline. In its 50-year life it has produced, with the Shkapovo field, over 4.7 billion barrels of oil. The overall basin produced from over 800 discrete fields.

Production history of the fields of the Volga Ural Basin (IHS via Dave Cohen )

More recently the EIA reported that the Volga-Urals Basin produced 2.03 mbd in 2009, while the Northern Causasus produced some 800 kbd.

Romashkino lies in Tatarstan, and the Tatneft Company had been formed to develop the oil in the Republic, of which some 6.3 billion barrels was in reserve. Realizing that their geography precluded independence, they became an associate subject of the Russian Federation, and Tatneft was privatized. Through helpful arrangements with the local government production, which had declined through lack of investment, was brought back to 465 kbd for the region, and has held at that level, through the collapse of the ruble. As the economy was restored the company began to expand, and has helped, for example, Kalmykia to develop their resources. (The Caspian oilfields that are now being developed lie off shore Kalmykia).

With over 15 billion barrels now produced from Romashkino more advanced techniques are being used to improve recovery of the remaining oil. These include the use of carbon dioxide injection, which has improved some production by as much as 12%.

Because Volga Urals oil has a high sulfur content (around 2.5%) this has, in the past, led to it being blended with West Siberian oil prior to refining. As the resource has declined the oil that is left is increasingly heavy, merging into the Melekess oil sands.

(Russia in total is estimated to have around 246 billion barrels of bitumen in sand formations, though most of it is in Eastern Siberia). The USGS has estimated that, at present, some 13.4 billion barrels of the Melekess oil is technically recoverable. Working with MicroPro GMBH
the bacteria Clostridiae has been tested as a means of improving production.

Improved flow conditions in the reservoir and increased gas/oil ratios led to an enhanced net oil production by 50% to 65% without changing production regime. The water content of the entire field was reduced from 74% to 57%. Between 1992 and 1995 the MEOR treatment resulted in an additional MEOR oil production of 4,200 ton (26,400 bbl)

Whether the small fields that remain in the Volga Ural Basin will be developed in the short term (as they likely would be by small independents were they in the West) appears to be currently less likely as both Tatneft and Bashneft see better returns by investing outside the region than within it. They are also reputed, by Grace, to retain a lot of Soviet-era infrastructure and thinking within the companies, which may also reduce the effort to invest in the smaller fields. It is difficult, therefore, to see the region have much increase in production from current levels, but rather it may continue a decline into the future.

In regard to natural gas, down by the border with Kazakhstan lie the natural gas deposits of the Orenburg field (of exploding outhouse fame). Production began in 1974, reaching a steady state of production in 1979, holding a 48 bcm production per year until 1984. In order to maintain pressure water flooding was used, and its influence on the production of a typical well can be seen below. Overall production has since fallen to 18 bcm per year.

The use of water pressure to sustain production from a well in the Orenburg field (Ivanov)

More recently the field has changed to the use of initially horizontal wells, and then, since 2009, the use of multi-laterals in order to sustain production and increase reserves, still considered to be around 280 bcm of natural gas (9 Tcf). This is a little more than the EIA estimate. However, given the increasing cost of developing this, when set against the much larger volumes that can be found in other parts of Russia (not to mention Kazakhstan and Turkmenistan to the south) it is reasonable to assume that the region will continue to decline in natural gas production also.