OGPSS - Saudi Arabian production - then and now

The latest OPEC Monthly Oil Market Report (MOMR) foresees that demand for OPEC crude oil will decline over the next year by about 300 kbd. This is largely in anticipation of additional production from elsewhere:

Non-OPEC supply is forecast to increase by 0.7 mb/d in 2012, supported by the anticipated growth from North America, Latin America, and FSU. In 2013, non-OPEC oil supply is expected to grow by 0.9 mb/d. The US, Canada, Brazil, Kazakhstan, and Colombia are expected to be the main contributors to supply growth, while Norway, Mexico, and the UK are seen experiencing the largest declines. OPEC NGLs and non-conventional oils are seen averaging 5.9 mb/d in 2013, indicating an increase of 0.2 mb/d over this year.

Overall OPEC sees demand staying below 90 mbd over the remainder of this year, with total growth in demand lying at 1.01 mbd.

Figure 1. OPEC forecast for global demand for the rest of the year (July MOMR )

Much has happened since the late Matt Simmons and Nansen Saleri got together to debate scenario’s for future oil production in Washington, back in February, 2004. While Matt had developed his research that then led into the publication of “Twilight in the Desert”, this was the meeting where Aramco pushed back to explain that there would not be a global problem, for at least fifty years. As this series of posts on Saudi Arabia comes to a conclusion, and moves on to other countries, it is perhaps of some value to look back on the presentation by Mahmoud Abdul Baqi and Hansen Saleri to remember what was said. Back in those days oil demand was expected to steadily rise, with increasing rate, to reach 100 mbd in 2015.

Figure 2. Aramco estimate of demand from 2000 to 2020 (Baqi and Saleri)

At the time Aramco had no concern over the industry being able to meet this increase in demand, and fully expected that Aramco itself would be able to more than sustain its share of the increased demand. They had 9 seismic crews out surveying the country, and some 48 rigs drilling both to sustain their then current level of production, and also to explore for new resources.

Figure 3. Location of exploration wells in Saudi Arabia in 2004 (Baqi and Saleri)

At the time Aramco reported that with 700 billion barrels of oil initially in place, that had been already discovered in the country, they expected to find another 200 billion barrels. Of that discovered oil they considered 260 billion barrels as their reserve, of which, by 2004, they had 131 billion barrels in development. (Note that they defined the reserve as the total amount of extractable oil, not the amount left to recover, they have done that in later computations also, and the latest annual report uses 259.7 billion barrels as that discovered reserve). The Annual Report notes that they discovered one new field in 2011, the Wedyan-1 well in the Empty Quarter flowed at 2.3 kbd from the Mishraf reservoir, while they drilled 161 exploration and development wells.

Figure 4. Amount of Saudi oil that had been developed by 2004 (Baqi and Saleri)

For a short arithmetic problem consider that 260 less 131 equals 129, and it one adds another 21, as a percentage of the 200 billion barrels to be found, then one gets 150 billion barrels. Divide this by 3 billion barrels a year of rough annual production and you get the 50 years of remaining life, that Saudi Arabia considered, back then, that their oilfields have left.

And this is the interesting plot, for it shows what Aramco define as their depletion rate, which is annual reduction of the initial proved reserve. The relevant term is the annual depletion rate:

Figure 5. Annual depletion rates for Saudi and other reserves (Baqi and Saleri)

This should be read in conjunction with the state of depletion of the different reservoirs in the KSA, as reported for 2004.

Figure 6. State of field depletion in Saudi Arabia as reported in 2004 (Baqi and Saleri)

And remember that this was eight years ago, so there has been that much change in the numbers! Aramco also expects to recover about 75% of the Original Oil in Place (OOIP) in all fields. They have been able to reach around that level with Abqaiq, which also suggests that the days of that field are now very numbered. But whether this will be possible in the other reservoirs is more open to doubt, and if there is less recoverable oil, then the actual depletion rates go higher.

But where the field is just starting, such as the new development of Haradh, if they hold the extraction rate to 1.7% of the anticipated total recovery then they anticipate that the field will continue to yield 300 kbd for decades.

Figure 7. Future production anticipated for Haradh III (Baqi and Saleri)

It was this anticipation of success across their endeavours that led the company to project that they would be able to hold a Maximum Sustainable Capacity of 10 mbd until 2042, with it only then becoming necessary to replace reserves from the probable and possible fields yet to be found and developed).

The last few posts have described how, as declining output has now hit the original fields, Aramco has moved to add production from other fields (Shaybah for example will soon be producing at up to 1 mbd) and is introducing multiphase pumps to Haradh and Shaybah to improve production from marginal wells, and in Safaniya to sustain a maximum production capacity of 1.3 mbd. Production from Manifa is also anticipated to step in to cover declines in other fields, and come on line in 2014, with a capacity of 900 kbd.

But these new additions are required to offset the decline in existing fields, which have been somewhat protected from the severity of declining well production by the switch from vertical to maximum reservoir contact (MRC) wells. Although this conceals the depletion of the oil in the reservoir during normal production it does not, by itself, improve the ultimate production from the field, but rather can shorten field life, since these wells have proved to be more productive in rate. Nansen Saleri now appears to duck questions which ask if KSA can increase production beyond 10 mbd.

Within The Oil Drum (TOD) there has been considerable discussion over the rate at which well production declines, and the remaining reserve in the field depletes. One impact of the shift in wells from old established fields is that production from the average well will decline over time, a subject that Euan has visited in the past.

Figure 8. Individual oil well production values for Aramco (Euan Mearns)

It should be noted that the use of the submersible pumps are reported to have brought wells back to around 3,000 bd. But the move over to horizontal and MRC wells has slowed the impact of other changes in the country.

Nevertheless, after putting all this together, I re-iterate my conclusion from last time in that I doubt that KSA will increase production much above 10 mbd, (in June it was producing 9.888 or 10.103 mbd depending on source, and with the rising internal demands (domestic use in the Middle East is now projected to average 7.7 mbd in 2012) world markets will get tighter in the shorter, rather than the longer term.

OGPPS - Saudi Arabia and what lies ahead

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

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

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

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

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

  

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

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

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

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

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

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

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

OGPSS - NPRA and ANWR, will they help TAPS?

When I wrote about the Alaskan Pipeline last week I noted that the pipeline was currently flowing at a volume of 495 kbd, after the Alyeska folk who run the system had just issued a report indicating that there would be problems once the flow fell below 600 kbd. Checking the flow rate for August (posted on Sept 1), the flow rate has risen back to 539 kbd, with average flow for the year to date running at 568 kbd. (The EIA reported final average for 2010 was 589 kbd)

The problems that come with low flow (including reduced revenues) are recognized within the state, and Alaskan Governor Parnell has urged that enough new wells be brought on line to allow flow to be raised back up to 1 millions barrels a day (mbd) within ten years. With the ongoing decline of current reservoirs, one has, therefore to look at the reservoirs that lie North of the Brooks Range in what is known as the North Slope (though it is rather flat) and see what can be brought on line.

It should be remembered, as a part of this, that despite talk of global warming, Northern Alaska is not a place where you can just drive a rig to a promising site and drop a new well in place within a couple of weeks. Nor has it the same level of Government scrutiny. For while the President has encouraged renewed drilling in the region, Shell, who were planning on a new program this year, have had to postpone it until next year because of an EPA concern over air quality permits. The nearest community to the planned wells in the Chukchi Sea, is some 70 miles away, and has 245 inhabitants.

Relative location of the proposed new drilling activity off Alaska

The need to find and develop a replacement for the Prudhoe Bay field and its adjacent fields is clear from the way in which the fields have been depleting.

Contribution of the different fields to Alaskan Production (Governor’s Office )

The impracticality of an immediate turn-around in the current decline is perhaps indicated by the fact that only one exploratory well will have been drilled in the state in 2011.

Exploratory wells drilled in the North Slope (Governor’s Office )

There must therefore be some incentives if companies are to drill in the future and the Governor believes that this will come about with a change in the tax incentives from the State. This need for some incentives is particularly true given the cost of operations that far North. Shell, for example, has spent close to $4 billion so far and has yet to start development. It is also expensively seeking to ameliorate some of the concerns raised after the Deepwater Horizon disaster.

Shell is proposing to use two drill ships, each capable of drilling a relief well for the other in case of the kind of blowout that destroyed the Deepwater Horizon rig. The company is also promising to add more testing and an extra set of shears to its blowout preventers and to keep emergency capping systems near drilling sites to capture any potential leaks.

But disregarding the politics, there is the question of how much oil is there?

The USGS has often given estimates of the technically recoverable resources that can be found in a region, but in the case of the North Slope they have taken this analysis one step further. A recent report took a review of the resources likely to be found in the National Petroleum Reserve- Alaska (NPRA) and applied some costs for the likely development of those resources, from which they came up with an estimate of the likely economically recoverable amount of oil that the NPRA holds. The analysis, both of what is there, and its likely extraction cost, included some 30 exploration wells, not previously considered. The analysis is also statistical in that, without actually drilling the rock, they can only estimate the likelihood of how much oil and gas are there. However one thing that the exploration wells showed is that a lot of what was thought to be oil in the reserve is actually gas. Further that the reservoir quality is worse than originally estimated. When the two are combined the estimate of the likely oil to be found and recoverable fell from 10.6 billion barrels of oil (bbo) to 895 million barrels of oil (mbo), of which some 500 mbo are likely to be economically recoverable. (This is the mean estimate).

The USGS also considered the gas volumes present, and with no present way of getting the large quantities of natural gas that exist up there down to a consumer (and with costs likely at the moment to exceed those at which natural gas is available from other sources) they assumed that it will take at least 10 years for the gas to find a path to market. If it takes twice as long, then the amount of recoverable oil is likely to be only about 358 mbo. For a 10-year delay the mean estimate for the amount of recoverable natural gas is 17.5 Tcf (trillion cubic feet) but this drops to 7.3 Tcf if it takes 20-years to get a pipeline in place. (Note that the amount of natural gas held in the NPRA is, at the mean, considered to be 52.8 Tcf). I am not going to go into the details of either the geological estimate, or the economic analysis but these are provided in the USGS reports. It is interesting, however, that they used a 12% decline rate (which they defend). The news about the condition of the reserves has apparently led some companies to relinquish their assets in the NPRA.

On the other side of Prudhoe Bay lies the Alaskan Wildlife Refuge, and particularly that part running along the coast which has been designated as ANWR – 1002, or, more comprehensively, the ANWR Coastal Plain. Just North of the Coast lies Camden Bay in the Beaufort Sea, and it is here that Shell has just had permits approved for four exploratory wells that should be drilled next year.

Location of the ANWR Coastal Plain, relative to Prudhoe Bay ( ANWR )

For the Coastal Plain itself, the USGS last updated their assessment in 1999, and using the mean values (the others are given in the report) considered that the technically recoverable oil in place would be 7.7 bbo out of a total 20.7 bbo in Area 1002. If one assumes that the same sort of economic criteria apply to ANWR as applies to the NPRA, then one might assume that roughly 55% of that technically recoverable might be also economically recoverable, for a total potentially available therefore from ANWR as being around 4.3 bbo. However it may also be that the same changes in both the reservoir rock and the type of hydrocarbon present may occur in ANWR as in NPRA, and if that comes to be the case, then the economically recoverable oil may fall to 10% of the current estimate, or around 430 million barrels. Not to be sneezed at, but not nearly as promising a number as has been discussed in the past.

More detailed view of the 1002 Area (USGS via planetforlife)

While these numbers are still somewhat speculative, until a bit actually drills down to the rock, and validates what is really there, the conclusion that is likely more critical at this time is that it is unlikely that there will be enough new oil coming into the pipeline in the next few years to stave off continued decline, and potential pipeline closure.

I had planned on writing about drilling in the Arctic and development and the off-shore fields, however I will put that off until next time.

A 6.7% decline rate from the IEA

For a number of years two of the major sources from which Energy related information is available, the Energy Information Agency in the US, and the International Energy Agency (IEA) in Europe, both agreed that the world had a plentiful sufficiency of oil and natural gas for at least a couple of decades or more. With that in mind they projected forward an ever-increasing use of oil and gas, which led, in turn, to some of the Climate Change models positing an ever-increasing level of carbon dioxide in the air. However in the recent past, while the EIA and Secretary Chu still hold to the concept that climate change (as a result of that increase) is the more worrisome topic, the IEA has begun to take a different track.

The latest version of this has just been published in an interview by the IEA Chief Economist, Dr. Fatih Berol with the Independent paper in the UK. (h/t Leanan and Gail). Dr. Birol notes that it would take the discovery of 4 sets of reserves the size of the Saudi Arabian fields to maintain current production until 2030, an it would need 6 to meet the demand, if it continues to grow at the anticipated rate. Recognizing the unrealistic nature of that condition, he then starts to walk back the date at which the world is going to realize that it is in trouble.

He first notes that “peak oil” the point at which global oil production reaches its highest point, is now likely to occur no later than 2020. Until now the 2030 date has been, for a number of agencies the earliest at which this was projected to arrive. Now that date is just over 10 years away, leaving half the period that the Hirsch Report felt was needed to find a realistic alternate solution to the liquid fuels shortage. But he does not stop with that date, but goes on to note that there is a more likely crisis coming first. That is the point where global supply of oil can no longer keep up with demand. This is a topic I have harped on before, and his new numbers are depressingly close to estimates I have posted. The date where it becomes a problem – the end of next year!
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There are two significant causes to the more immediate arrival of this new (and unfortunately thereafter continuing) crisis. Part of the problem has arisen since the oil-producing nations of the world, particularly those with a fair bit left, have chosen not to make the large investments needed to increase access to both current reserves, and to find and develop areas which are only, as yet, possible reserves. This part of the message is not new, Dr. Birol has been raising concerns about the gap between needs and what is going to be available for over a year. What is more of a concern is the rate at which the IEA is now reporting that existing oil fields are declining.

Historically the number that has been used is around 4.5%, which I started to explain last January . Unfortunately I don’t think I have recently gone into detail on why I think this is too small (it is because of the much higher decline rates where the wells are turned horizontal and start to water out). But I briefly referred to the concern last September) with the aid of a couple of graphs I took from Khebab’s Megaprojects update of August 2008. The first plot shows the world condition with the assumed 4.5% decrease in current field production.World Oil Projections with a 4.5% decline rate (Khebab at The Oil Drum (ibid)

He then recalculated the graphs with a 5.2% decline rate and got the following:

World Oil projections with a 5.2% decline rate Khebab at The Oil Drum (ibid)

Note that the peak date has dropped back until now (this was before the economic crisis became all that evident last year).

Now that is worrying enough, but the IEA report goes one step further noting that it now recognizes that the oil fields are declining at 6.7% per year, which is a condition that is much worse than that modeled above.

It makes it that much more difficult to sustain current levels of production as a plateau, and suggests that the decline in global production will be upon us much faster than the plot above shows. Sam, (who used to write as Khebab), provides updates with the input from last years IEA report.

The IEA now recognizes that non-OPEC country production has peaked and (according to Dr. Birol) that satisfactory levels of global production rests in the hands of very few.

"The market power of the very few oil-producing countries, mainly in the Middle East, will increase very quickly. They already have about 40 per cent share of the oil market and this will increase much more strongly in the future," he said.

Unfortunately it has been the optimism of the IEA in the past that has, in part, brought us to this point. It would help if the EIA would also begin to recognize reality, but perhaps they still have that different agenda. . . . . .

The question of course now becomes what will replace the fuel we need for vehicles, given the short time available to find and produce it. I note, over at Climate Progress that there is some hope expressed in comments about the potential for algae.

Well as a strong proponent of that idea (though my proposals for funding keep getting shot down) I should be extremely surprised if any significant production comes about in less than an 8 – 10 year time frame. Bear in mind that to have any significant impact we are talking about needing a production base of more than 2 mbd against the likely shortfall within the next couple or three years. And I cannot see the will or funding to move the technology forward that fast. (Plus there is the “baby in a month” problem).

It will be interesting to see how fast (given that everyone is now off for vacations) if at all, this message spreads to the more general public.

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:

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 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.