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.
Showing posts with label Baker Hughes. Show all posts
Showing posts with label Baker Hughes. Show all posts
Monday, February 16, 2015
Sunday, August 10, 2014
Tech Talk - Rig Counts in the Middle East
In recent posts about the situation in the Middle East, I have noted the need for Aramco to increase the number of drilling rigs that it must use, since it is now looking for natural gas in their tight sand deposits rather than finding the large reserves that they had hoped in the shale reservoirs. It is interesting in this regard to plot the number of rigs that have been working in the Middle East.
Getting the overall data from Baker Hughes the rig count can be plotted, over time, to give the following:
Figure 1. Rig Counts in the Middle East (Baker Hughes)
If one looks at the trend for the last twelve months, it has remains on a fairly consistent upward trend, following that of the longer time interval plot of Figure 1.
Figure 2. Recent trend in Middle East Rig count (Baker Hughes)
Back in the days of The Oil Drum, Euan Mearns and I had this concern, which occasionally surfaced, about these numbers. From my early post on the subject which noted that back in 2005 the KSA were running around 20 rigs, which would not be enough to get them the production they were claiming to need in the future, to Euan’s in 2011, the topic was revisited regularly over the time that the count steadily mounted as the Kingdom had to drill an increasing number of wells just to keep production at around the same overall level.
I am using the KSA as the example, given the large volume of its production relative to that of the others in the Middle East, but as the numbers show, the trend toward increased drilling rate to create enough productive wells to sustain production as the larger volume wells dry up is starting to become a steadily more frantic race across the region.
Rune Likvern used the phrase “Red Queen” in discussing the overall long-term need of the companies in the Bakken to have to drill an increasing number of wells, with individually reducing production, in order to remain in place with regard to overall production. As the production from the Bakken now exceeds a million barrels a day it may seem foolish to be predicting this “squirrel cage” view of the future, but the rig count up there is still running at around 190 rigs, which is not enough to sustain future growth for long, given that access to the sweet spots is limited, and they are beginning to run out of new sites.
So it is in the Middle East. The rig count numbers are mounting steadily, it is reported that there were 88 rigs drilling in the country in October 2012. Last year this rose to 170, and the number is expected to rise to 210 by the end of this year.
Aramco have done remarkably well, over the past decade, in developing new technologies to harvest the attic oil left around the tops of the major producing formations such as Ghawar, as the main body of the fields begin to be exhausted. But the problem with these secondary rig operations is that they were directed at the smaller pools around the field, rather than tapping into the major volume, and thus they had an expected and finite life. That life is starting to come to a close. Just as, when sucking a thick milk shake through a single immovable straw, when it stops drawing fluid, there is still a fair amount left in the cup. But as you move the straw around and slide it up and down the sides, the amount that you recover gets less, and it takes greater and greater effort to get it, to the point where you quit and discard the carton. And that is where the Middle Eastern oilfields are beginning to find themselves.
The high-quality light oils of the mainland are rapidly running out, and the remaining fields with the promise for sustaining Saudi production at around 10 mbd for the next few years, are the heavier sour crudes from the offshore fields such as Safaniya and Manifa. At the same time there is a need to reduce the increasing amount of oil (now at 3 mbd) being consumed in country, with the hope that this can be replaced by domestic natural gas. But those hopes are being reduced as the shales are found to be less productive than anticipated, and hopes are now switching to the slower production that can, hopefully, be achieved from the tight sands – but at the cost of an increased number of wells, inter alia.
This is the writing on the wall for global oil production, and in the short-term it will be neglected. Increasing the number of rigs will, in that interval, increase the number of wells that will produce, even though the volume from each well will be less, and the overall life of the wells will similarly reduce, as higher production techniques tap into smaller fields.
But we are now on the treadmill in the squirrel cage, or, as Rune would have it, we have wrapped ourselves in the cape and crown of the Red Queen, and must run faster and faster just to stay in place. (There are additional concerns since, as an example, Manifa could not be brought on line until there were refineries built that could process that crude, and so the options for increasing production beyond the capacity of refineries to absorb that increase is a futile exercise).
There will soon come a time when the gain from the overall increase in new wells will not match the decline in production from older wells, particularly if the effort to “run faster” is restricted to only a few players (Russia for example is not yet putting the effort and investment into increased drilling rates in order to sustain their overall levels of production, and given the age of their major fields are likely now in terminal decline).
Ouch!
Getting the overall data from Baker Hughes the rig count can be plotted, over time, to give the following:
Figure 1. Rig Counts in the Middle East (Baker Hughes)
If one looks at the trend for the last twelve months, it has remains on a fairly consistent upward trend, following that of the longer time interval plot of Figure 1.
Figure 2. Recent trend in Middle East Rig count (Baker Hughes)
Back in the days of The Oil Drum, Euan Mearns and I had this concern, which occasionally surfaced, about these numbers. From my early post on the subject which noted that back in 2005 the KSA were running around 20 rigs, which would not be enough to get them the production they were claiming to need in the future, to Euan’s in 2011, the topic was revisited regularly over the time that the count steadily mounted as the Kingdom had to drill an increasing number of wells just to keep production at around the same overall level.
I am using the KSA as the example, given the large volume of its production relative to that of the others in the Middle East, but as the numbers show, the trend toward increased drilling rate to create enough productive wells to sustain production as the larger volume wells dry up is starting to become a steadily more frantic race across the region.
Rune Likvern used the phrase “Red Queen” in discussing the overall long-term need of the companies in the Bakken to have to drill an increasing number of wells, with individually reducing production, in order to remain in place with regard to overall production. As the production from the Bakken now exceeds a million barrels a day it may seem foolish to be predicting this “squirrel cage” view of the future, but the rig count up there is still running at around 190 rigs, which is not enough to sustain future growth for long, given that access to the sweet spots is limited, and they are beginning to run out of new sites.
So it is in the Middle East. The rig count numbers are mounting steadily, it is reported that there were 88 rigs drilling in the country in October 2012. Last year this rose to 170, and the number is expected to rise to 210 by the end of this year.
Aramco have done remarkably well, over the past decade, in developing new technologies to harvest the attic oil left around the tops of the major producing formations such as Ghawar, as the main body of the fields begin to be exhausted. But the problem with these secondary rig operations is that they were directed at the smaller pools around the field, rather than tapping into the major volume, and thus they had an expected and finite life. That life is starting to come to a close. Just as, when sucking a thick milk shake through a single immovable straw, when it stops drawing fluid, there is still a fair amount left in the cup. But as you move the straw around and slide it up and down the sides, the amount that you recover gets less, and it takes greater and greater effort to get it, to the point where you quit and discard the carton. And that is where the Middle Eastern oilfields are beginning to find themselves.
The high-quality light oils of the mainland are rapidly running out, and the remaining fields with the promise for sustaining Saudi production at around 10 mbd for the next few years, are the heavier sour crudes from the offshore fields such as Safaniya and Manifa. At the same time there is a need to reduce the increasing amount of oil (now at 3 mbd) being consumed in country, with the hope that this can be replaced by domestic natural gas. But those hopes are being reduced as the shales are found to be less productive than anticipated, and hopes are now switching to the slower production that can, hopefully, be achieved from the tight sands – but at the cost of an increased number of wells, inter alia.
This is the writing on the wall for global oil production, and in the short-term it will be neglected. Increasing the number of rigs will, in that interval, increase the number of wells that will produce, even though the volume from each well will be less, and the overall life of the wells will similarly reduce, as higher production techniques tap into smaller fields.
But we are now on the treadmill in the squirrel cage, or, as Rune would have it, we have wrapped ourselves in the cape and crown of the Red Queen, and must run faster and faster just to stay in place. (There are additional concerns since, as an example, Manifa could not be brought on line until there were refineries built that could process that crude, and so the options for increasing production beyond the capacity of refineries to absorb that increase is a futile exercise).
There will soon come a time when the gain from the overall increase in new wells will not match the decline in production from older wells, particularly if the effort to “run faster” is restricted to only a few players (Russia for example is not yet putting the effort and investment into increased drilling rates in order to sustain their overall levels of production, and given the age of their major fields are likely now in terminal decline).
Ouch!
Read more!
Friday, June 6, 2014
Tech Talk - what the EPA Plan neglects
One of the problems, I suspect, with predictions of future energy use and production is that physical reality can become entangled in the politics of the day. Thus news that tends to negate the optimistic views of future American oil and natural gas production is subsumed by the need to keep the level of those predictions hecause of other political needs.
President Obama has now announced his decisions on a new incentive to combat his perception of the future as it sits threatened by the increased carbon dioxide produced by the burning of fossil fuels, particularly coal. As announced by the EPA, the Clean Power Plan “will maintain an affordable, reliable energy system, while cutting pollution and protecting our health and environment.”
The proposed rule has the intent of lowering carbon dioxide emissions by 30% from the levels of 2005, by 2030. As with many energy-related plans this one will take some time to implement, particularly since individual states have some input to the final program that will be put in place. More to the point, it will influence the thinking of power generators and legislators over the next few years.
Beyond the actual implementation, the real impact will be in the planning departments of the utility companies around the country. There is at least an even chance that, at some time in the future, these will become the regulations that must be followed, and as future power plant construction is planned, so the options that will be considered will now be changed to accommodate these likely regulations.
Realistically the closure of coal-fired plants will likely be followed by the construction of more natural gas plants, since the overall electrical energy needs of the country are unlikely to fall significantly. In the short term this is unlikely to be a problem. However as one moves into the intermediate term (say more than 5 years out) the old plants will have gone, and the country will become increasingly dependent on natural gas, in the same way as Europe is at present. As the old coal plants are demolished, they, and the coal mines that supply them, cannot be resurrected within a five-year period given the amount of permitting, financing and overall planning that is now required for such construction.
Natural gas has advantages over coal, in that it can be supplied by pipeline that makes it less susceptible to weather. But by the same token it is rarely stored on site, but metered along the pipeline as demand rises and falls. As history has shown, this can lead to critical shortages when, at times of high demand, the pipeline cannot keep up with demand.
At present the likelihood of problems seems remote, wells continue to be sunk and production in increasing in fields around the country. But if one goes beyond the picture that is projected as reassurance to those concerned for energy supply in the future the numbers revealed are not that comforting.
Figure 1. The changing picture of natural gas demand (EIA)
One begins with the prediction that the US has about 100 years of natural gas supply with a total extractable volume in reserves and resources of over 2,718 Tcf. It is a reassuring number but, as with the total volumes of either oil or coal in the ground, it does not really give that much information on what will be available as demand continues to rise.
Consider that, increasingly, the volumes of natural gas that are being sought are in shales, where the well must turn and drill along the shale horizon, before being fracked to produce gas and oil within the rock.
Figure 2. Number of rigs defined by type of well (Baker Hughes via EIA and Penn Energy)
The increasing dominance of horizontal well completions brings with it a considerable increase in well costs. You can see this as the technique became of increasing importance after 2005.
Figure 3. Change in the average cost of natural gas wells (EIA )
Well construction prices have continued to rise since that time, with numbers now running up to and beyond $10 million. The rising costs makes it harder to achieve a reasonable return on that investment, particularly as there has been no great increase in the overall price of natural gas to reflect its increased popularity, in large part because of the rush to drill and produce the known reserves.
Figure 4. Recent changes in natural gas prices (EIA )
As a result the number of rigs working in the natural gas fields has fallen, to the lowest levels of the recent past.
Figure 5. Change in the natural gas rig count over the past year. (Baker Hughes )
If you can’t make a profit on the merchandise, then after a while you stop trying to produce it. Despite the optimism that leads folk to anticipate large volumes of low-priced natural gas being able to sustain us into the foreseeable future if the companies cannot make a profit, after a while they stop. Which means that prices will go up, re-opening the cycle, but on a higher step. In time this will bring natural gas prices back up to around $8.00 per tcf, which will make the industry more comfortable.
What it will not do, however, will be to favorably impact the economics of the electricity business, where doubling the cost of fuel has a quite negative effect on prices and overall economics. But concerns over the rising price to be paid has had little impact yet on political decisions on energy in Europe, and one has to presume that a similar blindness to energy price consequences will also prevail in the United States. After all there is lots of natural gas around, it just has to be perceived as remaining a cheap fuel to validate the political plans . . .right ??!!
President Obama has now announced his decisions on a new incentive to combat his perception of the future as it sits threatened by the increased carbon dioxide produced by the burning of fossil fuels, particularly coal. As announced by the EPA, the Clean Power Plan “will maintain an affordable, reliable energy system, while cutting pollution and protecting our health and environment.”
The proposed rule has the intent of lowering carbon dioxide emissions by 30% from the levels of 2005, by 2030. As with many energy-related plans this one will take some time to implement, particularly since individual states have some input to the final program that will be put in place. More to the point, it will influence the thinking of power generators and legislators over the next few years.
Beyond the actual implementation, the real impact will be in the planning departments of the utility companies around the country. There is at least an even chance that, at some time in the future, these will become the regulations that must be followed, and as future power plant construction is planned, so the options that will be considered will now be changed to accommodate these likely regulations.
Realistically the closure of coal-fired plants will likely be followed by the construction of more natural gas plants, since the overall electrical energy needs of the country are unlikely to fall significantly. In the short term this is unlikely to be a problem. However as one moves into the intermediate term (say more than 5 years out) the old plants will have gone, and the country will become increasingly dependent on natural gas, in the same way as Europe is at present. As the old coal plants are demolished, they, and the coal mines that supply them, cannot be resurrected within a five-year period given the amount of permitting, financing and overall planning that is now required for such construction.
Natural gas has advantages over coal, in that it can be supplied by pipeline that makes it less susceptible to weather. But by the same token it is rarely stored on site, but metered along the pipeline as demand rises and falls. As history has shown, this can lead to critical shortages when, at times of high demand, the pipeline cannot keep up with demand.
At present the likelihood of problems seems remote, wells continue to be sunk and production in increasing in fields around the country. But if one goes beyond the picture that is projected as reassurance to those concerned for energy supply in the future the numbers revealed are not that comforting.
Figure 1. The changing picture of natural gas demand (EIA)
One begins with the prediction that the US has about 100 years of natural gas supply with a total extractable volume in reserves and resources of over 2,718 Tcf. It is a reassuring number but, as with the total volumes of either oil or coal in the ground, it does not really give that much information on what will be available as demand continues to rise.
Consider that, increasingly, the volumes of natural gas that are being sought are in shales, where the well must turn and drill along the shale horizon, before being fracked to produce gas and oil within the rock.
Figure 2. Number of rigs defined by type of well (Baker Hughes via EIA and Penn Energy)
The increasing dominance of horizontal well completions brings with it a considerable increase in well costs. You can see this as the technique became of increasing importance after 2005.
Figure 3. Change in the average cost of natural gas wells (EIA )
Well construction prices have continued to rise since that time, with numbers now running up to and beyond $10 million. The rising costs makes it harder to achieve a reasonable return on that investment, particularly as there has been no great increase in the overall price of natural gas to reflect its increased popularity, in large part because of the rush to drill and produce the known reserves.
Figure 4. Recent changes in natural gas prices (EIA )
As a result the number of rigs working in the natural gas fields has fallen, to the lowest levels of the recent past.
Figure 5. Change in the natural gas rig count over the past year. (Baker Hughes )
If you can’t make a profit on the merchandise, then after a while you stop trying to produce it. Despite the optimism that leads folk to anticipate large volumes of low-priced natural gas being able to sustain us into the foreseeable future if the companies cannot make a profit, after a while they stop. Which means that prices will go up, re-opening the cycle, but on a higher step. In time this will bring natural gas prices back up to around $8.00 per tcf, which will make the industry more comfortable.
What it will not do, however, will be to favorably impact the economics of the electricity business, where doubling the cost of fuel has a quite negative effect on prices and overall economics. But concerns over the rising price to be paid has had little impact yet on political decisions on energy in Europe, and one has to presume that a similar blindness to energy price consequences will also prevail in the United States. After all there is lots of natural gas around, it just has to be perceived as remaining a cheap fuel to validate the political plans . . .right ??!!
Read more!
Tuesday, March 3, 2009
Natural Gas and some worrying numbers
Their Website will tell you that they are the number one independent producer of natural gas in the country. When Boone Pickens needed a natural gas partner as part of his plan to change the mix of American Energy Supplies, he turned to Chesapeake. And yesterday they issued a statement that included the following:
This got me thinking about how much we use, who produces it, and issues such as the understanding of the different units that are used. So I am working on a standardized presentation of units – and see the sidebar for conversions etc.
Putting the Chesapeake statement in context, the CEO is quoted
To put the price in context Atlas Energy just reported that their drilling costs in the Marcellus Shale where they are currently developing production in the Applachian Basin, were $1.49 per kcf.
In 2008 the United States consumed a total of 23,241,512 mcf of natural gas, of which 21,328,916 mcf is delivered to customers (91.7%). This averages 63.6 bcf a day of total consumption, with 58.4 bcf going to customers. This is not an even consumption, but as you might imagine, is a function of the month (as shown below).
Natural Gas Consumption by month for 2008 (Source EIA )
And for those curious as to whether the weather was exceptional in those months, the average heating degree days for the regions of the country were higher in the 2008-2009 heating season over the previous season by over 7% on average.
Natural gas is supplied to four main markets electrical power generation (18.2 bcf/d); industrial use (18.2 bcf/d); Residential (13.4 bcf/d) and Commercial (8.6 bcf/d) use. The natural gas that goes to power generation now produces roughly 25% of US electrical power, and has the advantages of being both cleaner than coal, and also more flexible. This is particularly useful as more renewable sources such as wind and solar come into the grid, where their fluctuating power needs to be balanced, and natural gas is better at doing this.
To get some sense of where this came from, consider that Devon Energy drilled 2,441 wells in 2008, with a claimed 98% success rate. 659 of these were in the Barnett Shale, where the company now has a total of 3,809 wells, which produced 398 bcf in 2008. By the end of 2008 company gas production was nearly 1.2 bcf/day. Devon actually produces both oil and gas and so I can’t do the following calculation using their numbers, but let me instead set up a hypothetical company, but using some similar numbers.
Let us assume that this company is producing 1.2 bdc/day of natural gas. It only produces natural gas, and it got this production from 4,000 wells in 2008. If it drilled 2,500 wells in 2008 of which 90% were productive, then it would have 2,250 new productive wells. If one divides the daily volume among the producing wells that gives a daily average production of 300 kcf/day. However it is important to remember that in the gas shales some 60% of production comes from the well in the first year, and if, for simplicity we say that 36% comes in year 2, and that the remainder can be neglected, then I can illustrate the drilling need with a very crude calculation.
Let us say that wells come on stream at the first of the next year. Then at the beginning of 2009 1,750 wells were entering the second year of production while 2,250 were just starting up, then the production number changes so that in their first year the new wells will produce an average 363 kbd and this drops to 218 kbd in the second year, and the well is then done. Now we move forward to the start of 2010, so the original wells drop out of production, and the new wells drop down to second year production values. In order to sustain gas production the company will have to drill an additional 2,167 wells this year, at the assumed new production rate and success rate.
However the price of natural gas having fallen the company which drilled last years wells with say 160 rigs decides to cut back to 110 rigs in the same vein as Chesapeake. Then if the 160 rigs drilled 2,500 wells in 2008, the rig production is about 15.6 wells/year. So the number of wells drilled this year at that rate, but with the lower number of rigs, will be 1,718. At 90% success rate this gives 1,546 new wells at 363 kbd and 2,250 old wells at 218 kbd. The total is roughly 1.0 bcf/day. In other words the company will see a 20% drop in production next year. It gets a little worse in 2011. Consider that if the same number of wells are generated in 2010, then we have 1,546 wells at 363 kbd and 1,546 wells at 218 kbd, so the production drops to 0.9 bcf, at which it stabilizes, if the success rate and well production rates remain constant. As a matter of reality it is likely that they will drop.
To revert back to real numbers the Baker Hughes rig counts for 27 Feb, 2009 had 1,243 rigs operating in North America, of which 78% were gas (970). Of the total some 37% (460) were drilling horizontal wells. Incidentally the site presents these in a rather informative graphic:
Source Baker Hughes
It is interactive and, for example, by selecting for the Williston Basin find that there are 34 rigs drilling, that they are all drilling for oil, and that 89% of them (30) are drilling horizontal wells.
Source Baker Hughes
This is a much faster and more visual understanding of the data than the old way of downloading spreadsheets, which is the way you still have to look to find, for example, that in January Saudi Arabia had 46 rigs drilling for oil, and 28 drilling for natural gas. But it still leaves me wondering what that one rig is doing drilling a geothermal well in Illinois.
Well enough for crystal gazing for today, as I mentioned this is just an illustrative example of what might happen in the none-too-distant future. It is not accurate since some companies are cutting back harder on rig counts than I have suggested, success rates are not all the same (it has been suggested that as an industry average only 28% of the gas shale wells make a profit at a reasonable price for gas). But it might help understand why it is very unlikely that gas prices will remain as low as they are now for very long.
Chesapeake has elected to curtail approximately 240 million cubic feet of natural gas equivalent (mmcfe) per day ( 0.23 bcf/day) of its gross natural gas and oil production due to currently low wellhead prices in the Mid-Continent region. The company has curtailed approximately 200 million cubic feet per day of gross natural gas production and approximately 6,000 barrels per day of gross oil production for at least the month of March 2009. The curtailed production represents approximately 7% of Chesapeake’s current gross operated production capacity. Additionally, the company is considering a further 10% reduction in its drilling activity during 2009 if natural gas and oil prices remain low during the next few months. The company’s attractive hedges and cash availability provide it with the operational and financial flexibility to curtail production during periods of unusually low prices, such as the current market environment. The company believes conditions are developing that will support higher prices for natural gas and oil later this year and in 2010.
This got me thinking about how much we use, who produces it, and issues such as the understanding of the different units that are used. So I am working on a standardized presentation of units – and see the sidebar for conversions etc.
Putting the Chesapeake statement in context, the CEO is quoted
During March 2009, most Mid-Continent natural gas prices at major interstate pipeline delivery points will average around $2.70 per thousand cubic feet (kcf), a price at which most natural gas production is unprofitable. We believe low wellhead prices combined with constrained capital availability will likely cause U.S. drilling activity to decline well beyond the 40% drop already seen since August 2008. As a result, U.S. natural gas production will begin to dramatically decline before the end of 2009 and consequently natural gas markets will regain better supply/demand balance by the end of 2009, if not sooner. …… In addition, we have reduced our drilling activity from 158 operated rigs in August 2008 to 110 currently. We are considering a further 10% reduction in our drilling activity, which if implemented, will be in areas where we do not have joint venture drilling carries.
To put the price in context Atlas Energy just reported that their drilling costs in the Marcellus Shale where they are currently developing production in the Applachian Basin, were $1.49 per kcf.
In 2008 the United States consumed a total of 23,241,512 mcf of natural gas, of which 21,328,916 mcf is delivered to customers (91.7%). This averages 63.6 bcf a day of total consumption, with 58.4 bcf going to customers. This is not an even consumption, but as you might imagine, is a function of the month (as shown below).
Natural Gas Consumption by month for 2008 (Source EIA ) And for those curious as to whether the weather was exceptional in those months, the average heating degree days for the regions of the country were higher in the 2008-2009 heating season over the previous season by over 7% on average.
Natural gas is supplied to four main markets electrical power generation (18.2 bcf/d); industrial use (18.2 bcf/d); Residential (13.4 bcf/d) and Commercial (8.6 bcf/d) use. The natural gas that goes to power generation now produces roughly 25% of US electrical power, and has the advantages of being both cleaner than coal, and also more flexible. This is particularly useful as more renewable sources such as wind and solar come into the grid, where their fluctuating power needs to be balanced, and natural gas is better at doing this.
To get some sense of where this came from, consider that Devon Energy drilled 2,441 wells in 2008, with a claimed 98% success rate. 659 of these were in the Barnett Shale, where the company now has a total of 3,809 wells, which produced 398 bcf in 2008. By the end of 2008 company gas production was nearly 1.2 bcf/day. Devon actually produces both oil and gas and so I can’t do the following calculation using their numbers, but let me instead set up a hypothetical company, but using some similar numbers.
Let us assume that this company is producing 1.2 bdc/day of natural gas. It only produces natural gas, and it got this production from 4,000 wells in 2008. If it drilled 2,500 wells in 2008 of which 90% were productive, then it would have 2,250 new productive wells. If one divides the daily volume among the producing wells that gives a daily average production of 300 kcf/day. However it is important to remember that in the gas shales some 60% of production comes from the well in the first year, and if, for simplicity we say that 36% comes in year 2, and that the remainder can be neglected, then I can illustrate the drilling need with a very crude calculation.
Let us say that wells come on stream at the first of the next year. Then at the beginning of 2009 1,750 wells were entering the second year of production while 2,250 were just starting up, then the production number changes so that in their first year the new wells will produce an average 363 kbd and this drops to 218 kbd in the second year, and the well is then done. Now we move forward to the start of 2010, so the original wells drop out of production, and the new wells drop down to second year production values. In order to sustain gas production the company will have to drill an additional 2,167 wells this year, at the assumed new production rate and success rate.
However the price of natural gas having fallen the company which drilled last years wells with say 160 rigs decides to cut back to 110 rigs in the same vein as Chesapeake. Then if the 160 rigs drilled 2,500 wells in 2008, the rig production is about 15.6 wells/year. So the number of wells drilled this year at that rate, but with the lower number of rigs, will be 1,718. At 90% success rate this gives 1,546 new wells at 363 kbd and 2,250 old wells at 218 kbd. The total is roughly 1.0 bcf/day. In other words the company will see a 20% drop in production next year. It gets a little worse in 2011. Consider that if the same number of wells are generated in 2010, then we have 1,546 wells at 363 kbd and 1,546 wells at 218 kbd, so the production drops to 0.9 bcf, at which it stabilizes, if the success rate and well production rates remain constant. As a matter of reality it is likely that they will drop.
To revert back to real numbers the Baker Hughes rig counts for 27 Feb, 2009 had 1,243 rigs operating in North America, of which 78% were gas (970). Of the total some 37% (460) were drilling horizontal wells. Incidentally the site presents these in a rather informative graphic:
Source Baker HughesIt is interactive and, for example, by selecting for the Williston Basin find that there are 34 rigs drilling, that they are all drilling for oil, and that 89% of them (30) are drilling horizontal wells.
Source Baker HughesThis is a much faster and more visual understanding of the data than the old way of downloading spreadsheets, which is the way you still have to look to find, for example, that in January Saudi Arabia had 46 rigs drilling for oil, and 28 drilling for natural gas. But it still leaves me wondering what that one rig is doing drilling a geothermal well in Illinois.
Well enough for crystal gazing for today, as I mentioned this is just an illustrative example of what might happen in the none-too-distant future. It is not accurate since some companies are cutting back harder on rig counts than I have suggested, success rates are not all the same (it has been suggested that as an industry average only 28% of the gas shale wells make a profit at a reasonable price for gas). But it might help understand why it is very unlikely that gas prices will remain as low as they are now for very long.
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