Waterjetting 31d - thickening a waterjet to improve downstream pressure

There is a trick that one can learn while a teenager, which comes with the introduction “I so strong that I can blow a brick over!” Upon finding a suitable victim to impress, the brick is placed over a deflated balloon, which is then inflated, raising the brick which then, if suitably placed, topples onto its side – proving the strength of your lungs.

The critical part of the activity is to have the air that you blow be confined within the balloon, and equally exert pressure over the surface of the brick, so that a low pressure translates into a much more significant and powerful force. It is the confinement of the pressure that allows the build-up that moves the brick.

In most cases the use of high-pressure water as a cutting tool does not see much confinement of the water over the cutting process, with the water flowing into the cut, removing some material, and then flowing on out. Yet the water still has considerable energy as it leaves, and this means that the process is usually quite inefficient. How then can the contained energy in the jet be used in a secondary way to improve the removal efficiency of the process?

One answer to the question comes with the use of long-chain polymeric additives. These have recently seen a fair amount of publicity because of their use as the “slick water” components of the “slick-water-fracking” tools that have helped improve the production of oil and natural gas from long horizontal wells drilled into the hydrocarbon deposits in places such as the Bakken fields of North Dakota and the Barnett and Eagle Ford Shales in Texas. The long horizontal wells are separated into short intervals, within which the pressure within the well is raised until the surrounding rock cracks (fracks) with s series of cracks that extend out into the surrounding rock. The crack makes it easier for the hydrocarbons in the rock to escape and reach the well, improving the recovery to the point that the well can be economic to operate. The reason that the “slick water” is used is that the crack would normally close back up after the borehole pressure was lowered back down. In order to stop this happening the fluid in the well during the frack is made up with long-chain polymers and also contains grains of a sand or similar proppant. When the crack is formed the fluid in the well flows into the crack, carrying the sand with it, and this then holds the crack open when the pressure falls.

The polymer thickens the water which makes up most of the fracking fluid, so that it can carry more of the sand, and at the same time, the polymer reduces the friction of the water against the rock, so that it is easier for the water and sand to penetrate deeper into the cracks. Once the proppant particles catch against the sides of the crack they become held in place, while the fluid moves on and eventually returns back out of the well.

Back in the days when I was carrying out the research for my doctorate, I had used the long-chain polymer Polymerized ethylene oxide (Polyox) to reduce the friction in the delivery line from the pump to the nozzle. The increased cohesion of the jet (which I will cover in posts that follow this) meant that it would cut to a greater distance from the nozzle, with less decline in cutting power. However the increased cohesion of the jet had an additional benefit, which was noted by Chapman Young, as part of his development of tools for removing loose rock from around tunnels.

In a typical tunnel excavation, the miners drill a pattern of holes in the face of the tunnel, and then partially fill these with explosive, which is then set off in a controlled pattern of blasting. The central core of rock on the face is broken out by the explosive force, but some portion of the rock at the edge of the blast is only loosened from the solid, and still hangs in place. One of the more dangerous mining jobs (which I have done) is to take a long pry bar and insert this behind the loose pieces of rock around the opening, hoping to be able to wedge these loose, so that they no longer pose a risk to miners who then pass underneath.

Seeking to automate this process Dr Young and his colleagues tried using high-pressure waterjets to blast these lumps free from the wall. Subsequently investigators at Colorado School of Mines have shown that the jets give an improved cleaning of the wall, over other methods – but as normally applied they do not have the confined power to be able to get behind the block with sufficient confined force to be able to pry larger blocks free.

And this is where the balloon analogy comes in, because Dr Young realized that if he could increase the viscocity of the water in the stream sufficiently so that, for a short instance, it would be confined behind the block and could acquire some of the pressure from the following impacting jet, then enough pressure over a large enough area would provide the force needed to dislodge the block. He tried it, and it worked.

It is not, however, a simple process to carry out, since the jet path must be carefully aimed to ensure that there is enough confinement of the water behind the target block for pressure to be built up, and this requires that the jet contain a relatively high concentration of polymer. That in itself brings another problem, which can be anticipated by the “slick water” nickname. Where the water gets onto the floor the friction reduction properties mean that it makes it quite difficult to walk on the wetted rock. Now while that, in turn, opens up a new avenue for business (the chemical is sometimes referred to as Banana water in riot control) it makes it unpopular with those that have to work with it in the confines of a mining tunnel and so the technology has not caught on. But it does provide an introduction to the topic of different cutting fluids, which will be the next topic of discussion.

Tech Talk - of longer wells and drawdown pressure

There are, simply, three major parts to the coming global economic mess that will be created as we enter into the period of Peak Oil. The first of these comes from the current rising demand for oil, particularly emphasized by those countries, such as China and India, where demand is rising fastest. The second part is the declining production from existing fields as their reserves are drawn down. (Though it should be remembered that even when “exhausted” the fields will still contain vast quantities of oil, but oil which is at present not economically recoverable). And finally there is the oil in the undeveloped, and undiscovered wells and fields that can be added to the existing reserve to help ameliorate the imbalance between demand and supply from existing wells.

The high decline rates from long horizontal wells drilled into, and along the shale deposits in the United States, most particularly the Bakken and the Eagle Ford, mean that there is a constant need to drill new wells to sustain existing production. The EIA has taken note of this and calculated based on some assumptions, the number of rigs that must be operating in these fields, so that they will drill enough new wells to sustain current production.

Figure 1. The number of rigs required in the Bakken and Eagle Ford formations to sustain production at the level of the previous month (EIA).

Should the need be to increase production (which is the current assumption by most prognosticators of future equilibrium between demand and supply) then these numbers need to be significantly higher, perhaps by as many as 50 additional rigs. At present the Bakken rig count is running at around 176 rigs while there are around 270 rigs drilling in the Eagle Ford.

One of the ways in which production is anticipated to expand above earlier estimates for the wells drilled in both fields comes from the ability to drill longer horizontal wells and to increase the fracture density along these wells.

However, as the Kingdom of Saudi Arabia discovered some years ago, longer wells can only be viably effective out to a certain distance, beyond which there is no gain in productivity. As a result they have changed their drilling patterns so that the wells are shorter, with multiple laterals spreading from the original wells to more thoroughly cover the rock within the formation. Initially wells were drilled out to distances of up to 12 km, but over time the KSA found that this was too long.

Since there is a somewhat similar argument to be made for the wells in the United States, as they move to longer distances, I thought I would go over the explanation as to why this is not a very productive idea a second time.

To begin consider that regardless of whether I put a tiny glass of water or a huge glass of soda in front of you, if I glue it to the table then the amount that you can drink at one time becomes limited by the size of the straw that I give you to drink the liquid, rather than the amount in the container. And to get that liquid into the straw and up into your mouth requires that you suck on the straw.

What you are doing is reducing the pressure at the bottom of the straw, while the pressure from the atmosphere on the top of the liquid remains the same. By creating this differential pressure there is now a force to move the liquid into the straw and thence up into your mouth.

But, as Fishbuch et al showed, as the horizontal well bore gets longer the pressure at the back of the hole declines as then does the difference in pressure between the oil in the rock and the well (the drawdown pressure), and while the longer hole gives an overall increase in production to a certain point this seems to maximize at a length of around 6,000 ft. Beyond that distance the differential pressure between the formation and the well falls to a point where there is less benefit to the additional cost of drilling to that distance.

Figure 2. Drop in well pressure with increased well length, while increasing overall oil flow (Simulation by Fishbuch et al )

The answer which Aramco came up with to get around this problem was to use a main lateral from which a number of shorter laterals could then be drilled out into the formation, providing higher drawdown pressures within the wells and making it also easier to isolate any well section where the underlying water broke through into the well.

Figure 3. Schematic of a Maximum Reservoir Contact well as used in Saudi Arabia (Aramco).

The optimum length at which a well can produce is a function of the rock type and structure as well as the nature of the oil/natural gas that it contains and the water content (to name by a few of the parameters). Thus there are limits to the analogy, nevertheless it does show, even in the much more productive rocks of the fields in KSA that there are limits to how far a well can be productively driven, and these limits will also exist in the shales of the United States, although the oil locations and the optimal ways of extracting it are somewhat different.

The extraction of oil and natural gas in these shales is more sensitive to the levels of drawdown pressure, since much of the oil and gas is found in natural fractures that are not that wide (although they may be spread further apart by the fracking process itself). With exposure to the lower well pressure thus being restricted to a relatively small volume, significant reduction in the pressure because of the location relative to the heel of the well can have significant effects on lowering the overall well production.

Further as a general rule the complex valve systems used in KSA are not installed in the shale wells of the United States, making it less practical to focus the relative pressure differentials at different points along the well bore as a means of increasing production sequentially along the well.

Tech Talk - the numbers keep going down

One problem with defining a peak in global oil production is that it is only really evident some time after the event, when one can look in the rearview mirror and see the transition from a growing oil supply to one that is now declining. Before that relatively absolute point, there will likely come a time when global supply can no longer match the global demand for oil that exists at that price. We are beginning to approach the latter of these two conditions, with the former being increasingly probable in the non-too distant future. Rising prices continually change this latter condition, and may initially disguise the arrival of the peak, but it is becoming inevitable.

Over the past two years there has been a steady growth in demand, which OPEC expects to continue at around the 1 mbd range, as has been the recent pattern. The challenge, on a global scale, has been to identify where the matching growth in supply will come from, given the declining production from older oilfields and the decline rate of most of the horizontal fracked wells in shale.

Figure 1. Growth in global demand for oil (OPEC MOMR )

At present the United States is sitting with folk being relatively complacent, anticipating that global oil supplies will remain sufficient, and that the availability of enough oil in the global market to supply that reducing volume of oil that the US cannot produce for itself will continue to exist.

Increasingly over the next couple of years this is going to turn out to have created a false sense of security, and led to decisions on energy that will not easily be reversed. Consider that the Canadians have now decided to built their Pipeline to the Pacific. The Northern Gateway pipeline that Enbridge will build from the oil sands to the port of Kitimat.

Figure 2. Route for the Northern Gateway pipeline (Northern Gateway )

The 731 mile long pipeline will carry 525 kbd to the port, and a twin pipe will carry some 193 kbd of condensate back to Bruderheim to help in the processing of the initial crude. It will, sensibly, move the oil that was to have come down through the Keystone pipeline to American refineries instead to tankers out to the Canadian coast, where it will be shipped to Asia to meet their growing demands. Given the investment in the pipe, infrastructure etc once this oil is committed to that market and the US will not be able to gain that supply back when it is needed in a few years.

There is a secondary impact to the opening of that market that may not be evident for a little time, but it something that the Russians discovered after the gas pipeline connected Turkmenistan to China. Suddenly there is a second market for the product, and producers are no longer tied to having to accept the price that the sole purchaser is willing to pay. At the moment, when there is a sufficiency of oil, that is an incidental, with significant impact only in improving the economics of the oil sand operations, but since it now ties the American refineries that would have received this oil more closely to the Venezuelan production it now receives (a somewhat less reliable supplier) this change remains as something of a future concern. It is not likely, in itself, to initially change the price of oil much ( a minor increase) but it will change the names and nationalities of those that profit from the trade.

The problems that the Keystone pipeline had are, to a degree, a function of the lack of concern over the supply of oil to the American market. As long as oil production continues to increase, from the Bakken and Three Forks in North Dakota, and the Eagle Ford in Texas, then there is no clear evidence for concern. But those wells are cumulatively starting to reach peak production, and the next shales on the list (the Spearfish and the Tyler) don’t hold the potential to match the gains that have been achieved to date. Particularly this is when, as the North Dakota DMR notes, the wells see an average decline of 65% in the first year.

Figure 3. Typical Oil production from a well in the Bakken:Three Forks region of North Dakota (ND DMR Oil and Gas Division )

The projections that gains in production continue thus rely on a continued high level of drilling and production with a defined rig count required having been estimated, and an assumed sustained level of production even beyond the time that the “sweet spots” start to disappear.

Figure 4. Projected production from the Bakken:Three Forks formations, assuming well productions are sustained and that the rigs are available. (ND DMR Oil and Gas Division )

At the end of June, 2014 the rig count in North Dakota is less than 190 (DNR says 189, but Kirk Eggleston notes that some 15 of these are moving, so that the real number is 173, a bit less than 225. That suggests that peak production may be delayed, and lowered from 1.75 mbd down to around 1.4 mbd. This reduction in short-term supply will have less impact in the US than elsewhere since it will be used to release oil that the US would otherwise have bought to the world market, but less than anticipated, and at a slower rate than expected. (Note that Eagle Ford production growth rate is also slowing and that this also affects OPEC projections which anticipates that US oil production will grow some 950 kbd this year).

At the same time, as I have noted in an earlier piece the reliance of many models of future oil supply have focused on Iraq as the next major supplier to sustain growth in production, even as other suppliers decline. But those projections are increasingly obsolete. It is unrealistic to expect the oil export business from Iraq to be sustained and continue to grow in the face of the developing civil war. The nature of the conflict makes it difficult to see how it can be easily resolved, and particularly if the country becomes divided, then the oil pipelines become a target of opportunity to attack the financial underpinnings of the different sectors. It is likely that the pipeline from Kurdistan into Turkey will carry increasing volumes up to Ceyhan and thence to the world market, under better security, given that does not now venture into Sunni territory, but the vulnerabilities likely remain.

The result of these declines in anticipated production (not to mention Libya, the Sudan’s etc) is likely to become evident within a year, while demand continues to grow. The balance need change only a small amount however, for the consequences to be dire. As Mr. Micawber said in “David Copperfield”:

Annual income twenty pounds, annual expenditure nineteen [pounds] nineteen [shillings] and six [pence], result happiness. Annual income twenty pounds, annual expenditure twenty pounds ought and six, result misery.

Tech Talk - Natural Gas, China and Russia in the post-Crimea time.

The recent takeover of Crimea by Russia has given China a strengthened hand as it continues to negotiate with Gazprom over the supplies of natural gas for the next few years.

It was not that long ago that Gazprom was riding high around the world, as it supplied large quantities of its own and Turkmen gas to Europe, and was negotiating to sell more into China and Asia in general. Then Turkmenistan and China arranged their own deal, and with the construction of a direct pipeline between the two countries, suddenly the market was no longer running entirely Gazprom’s way. They could no longer mandate that Turkmenistan take the price that they offered at the time that Russia controlled all the pipelines that carried the gas to market. And with that change, and the changing natural gas market, so Gazprom’s fortunes have started to teeter.

At the same time the anticipated Russian market in the United States, which would have been supplied from newly developed Russian Artic reserves such as those in the Shtokman field are no longer needed, as the American shale gases have come onto the market in increasing quantities. The world has, in short, become a somewhat less favorable place for Gazprom and the Chinese have hesitated to commit to a further order of natural gas, in part because they anticipate getting a better deal for the fuel than Gazprom would like them to pay.

Russia would like, and is anticipating, that the deal for some 38 billion cubic meters/year of natural gas, starting in 2018 will be signed when President Putin visits China in May. (In context Russia, which supplies about 26% of European natural gas, sends them around 162 bcm per year). Negotiations over the sale of the gas have dragged on for years, having first started in 2004 but the major disagreement continues to be over price. At a time when Norway is seeing a peak in production and Qatar is moving more of its sales to Asia, Russia had seen an increase in European sales, and has been able to move that gas at a price of $387 per 1,000 cubic meters (or $10.54 per kcf/MMBtu. The price of such gas in the US is quite a bit cheaper.

Figure 1. Natural gas prices in the United States. (EIA )

Russia would like to get a price of around $400 per kcm ($10.89 per kcf) with the slight extra going to pay for the pipeline and delivery costs. Whether the two countries can come to an agreement on the price may well now depend on how vulnerable Russia really is to any pressure on its markets from other sources of natural gas. Japan, for example, is now considering re-opening its nuclear power stations, as the costs for imported fuel are having significant consequences on their attempts at economic growth.

Similarly there is talk that the United States may become a significant player on the world stage by exporting LNG as it moves into greater surplus at home, thereby providing another threat to Russian sales. Part of the problem with that idea comes from the costs of producing the gas, relative to the existing price being obtained for it, and part on the amount of natural gas viably available. Consider that, at present, some of the earlier shale gas fields, such as the Barnett, Fayetteville and Haynesville are showing signs of having peaked.

Figure 2. Monthly natural gas production from shale fields (EIA)

While production from the Marcellus continues to rise, there is some question as to whether the Eagle Ford is reaching peak production although that discussion, at the moment relates more to oil production. However given that it is the liquid portion of the production that is the more profitable this still drives the question.

And in this regard, the rising costs of wells, against the more difficult to assure profits is beginning to have an impact on the willingness of companies in the United States to invest the large quantities of capital into new wells that is needed to sustain and grow production. A recent article in Rigzone took note that the major oil companies are rethinking their strategies of investment, with some reorganization of their plans in particular for investment in shale fields. This raises a question for the author:

Another question for the industry is who will supply the risk capital for exploratory drilling, both on and offshore, if the majors pull back their spending? Onshore, for the past few years, a chunk of that capital has been supplied by private equity investors who have supported exploration and production teams in start-up ventures. They have also provided additional capital to existing companies allowing them to purchase acreage or companies to improve their prospect inventory. Unfortunately, the results of the shale revolution have been disappointing, leading to significant asset impairment charges and negative cash flows as the spending to drill new wells in order to gain and hold leases has exceeded production revenues, given the drop in domestic natural gas prices. Will that capital continue to be available, or will it, too, begin demanding profits rather than reserve additions and production growth?

Before investors put up the money for new LNG plants they need to be assured that there will be a financial return for that investment. Given that it takes time for such a market to evolve, and given the need that Russia has to sustain its market and potentially to increase it, the volumes that the US might put into play are likely to be small, with little other than political impact likely.

If Russia recognizes this, and feels relatively confident that Europe must continue to buy natural gas from Gazprom, particularly with the current move by Europe away from other sources of fuel such as coal, then they are likely to be more resistant to bringing the price down for their Chinese customers. On the other hand if China thinks that it might be able to get a better deal from Iran, were sanctions to ease, or from other MENA countries, then – thinking perhaps that Russia needs the sale more – they might toughen their position and the price debate may continue.

It will be interesting to see if it resolves within the next few weeks, and if so, at what a price.

Tech Talk - Arthur Berman talks to OilPrice

One of the great concerns that I have expressed in the pieces I write here relates to the high decline rates, and increasing costs of fossil fuel extraction from oil shales. Just recently Oilprice discussed this with Arthur Berman, and have allowed me to reproduce the interview here. Since Arthur is more articulate than I on this subject I am glad to do so.

Oilprice.com: Almost on a daily basis we have figures thrown at us to demonstrate how the shale boom is only getting started. Mostly recently, there are statements to the effect that Texas shale formations will produce up to one-third of the global oil supply over the next 10 years. Is there another story behind these figures?

Arthur Berman: First, we have to distinguish between shale gas and liquids plays. On the gas side, all shale gas plays except the Marcellus are in decline or flat. The growth of US supply rests solely on the Marcellus and it is unlikely that its growth can continue at present rates. On the oil side, the Bakken has a considerable commercial area that is perhaps only one-third developed so we see Bakken production continuing for several years before peaking. The Eagle Ford also has significant commercial area but is showing signs that production may be flattening. Nevertheless, we see 5 or so more years of continuing Eagle Ford production activity before peaking. The EIA has is about right for the liquids plays--slower increases until later in the decade, and then decline.

The idea that Texas shales will produce one-third of global oil supply is preposterous. The Eagle Ford and the Bakken comprise 80% of all the US liquids growth. The Permian basin has notable oil reserves left but mostly from very small accumulations and low-rate wells. EOG CEO Bill Thomas said the same thing about 10 days ago on EOG's earnings call. There have been some truly outrageous claims made by some executives about the Permian basin in recent months that I suspect have their general counsels looking for a defibrillator.

Recently, the CEO of a major oil company told The Houston Chronicle that the shale revolution is only in the "first inning of a nine-inning game”. I guess he must have lost track of the score while waiting in line for hot dogs because production growth in U.S. shale gas plays excluding the Marcellus is approaching zero; growth in the Bakken and Eagle Ford has fallen from 33% in mid-2011 to 7% in late 2013.

Oil companies have to make a big deal about shale plays because that is all that is left in the world. Let's face it: these are truly awful reservoir rocks and that is why we waited until all more attractive opportunities were exhausted before developing them. It is completely unreasonable to expect better performance from bad reservoirs than from better reservoirs. The majors have shown that they cannot replace reserves. They talk about return on capital employed (ROCE) these days instead of reserve replacement and production growth because there is nothing to talk about there. Shale plays are part of the ROCE story--shale wells can be drilled and brought on production fairly quickly and this masks or smoothes out the non-productive capital languishing in big projects around the world like Kashagan and Gorgon, which are going sideways whilst eating up billions of dollars.

None of this is meant to be negative. I'm all for shale plays but let's be honest about things, after all! Production from shale is not a revolution; it's a retirement party.

OP: Is the shale “boom” sustainable?

Arthur Berman: The shale gas boom is not sustainable except at higher gas prices in the US. There is lots of gas--just not that much that is commercial at current prices. Analysts that say there are trillions of cubic feet of commercial gas at $4 need their cost assumptions audited. If they are not counting overhead (G&A) and many operating costs, then of course things look good. If Walmart were evaluated solely on the difference between wholesale and retail prices, they would look fantastic. But they need stores, employees, gas and electricity, advertising and distribution. So do gas producers. I don't know where these guys get their reserves either, but that needs to be audited as well.

There was a report recently that said large areas of the Barnett Shale are commercial at $4 gas prices and that the play will continue to produce lots of gas for decades. Some people get so intrigued with how much gas has been produced and could be in the future, that they don't seem to understand that this is a business. A business must be commercial to be successful over the long term, although many public companies in the US seem to challenge that concept.

Investors have tolerated a lot of cheerleading about shale gas over the years, but I don't think this is going to last. Investors are starting to ask questions, such as: Where are the earnings and the free cash flow. Shale companies are spending a lot more than they are earning, and that has not changed. They are claiming all sorts of efficiency gains on the drilling side that has distracted inquiring investors for awhile. I was looking through some investor presentations from 2007 and 2008 and the same companies were making the same efficiency claims then as they are now. The problem is that these impressive gains never show up in the balance sheets, so I guess they must not be very important after all.

The reason that the shale gas boom is not sustainable at current prices is that shale gas is not the whole story. Conventional gas accounts for almost 60% of US gas and it is declining at about 20% per year and no one is drilling more wells in these plays. The unconventional gas plays decline at more than 30% each year. Taken together, the US needs to replace 19 billion cubic feet per day each year to maintain production at flat levels. That's almost four Barnett shale plays at full production each year! So you can see how hard it will be to sustain gas production. Then there are all the efforts to use it up faster--natural gas vehicles, exports to Mexico, LNG exports, closing coal and nuclear plants--so it only gets harder.

This winter, things have begun to unravel. Comparative gas storage inventories are near their 2003 low. Sure, weather is the main factor but that's always the case. The simple truth is that supply has not been able to adequately meet winter demand this year, period. Say what you will about why but it's a fact that is inconsistent with the fairy tales we continue to hear about cheap, abundant gas forever.

I sat across the table from industry experts just a year ago or so who were adamant that natural gas prices would never get above $4 again. Prices have been above $4 for almost three months. Maybe "never" has a different meaning for those people that doesn't include when they are wrong.

OP: Do you foresee any new technology on the shelf in the next 10-20 years that would shape another boom, whether it be fossil fuels or renewables?

Arthur Berman: I get asked about new technology that could make things different all the time. I'm a technology enthusiast but I see the big breakthroughs in new industries, not old extractive businesses like oil and gas. Technology has made many things possible in my lifetime including shale and deep-water production, but it hasn't made these things cheaper.

That's my whole point about shale plays--they're expensive and need high oil and gas prices to work. We've got the high prices for oil and the oil plays are fine; we don't have high prices for the gas plays and they aren't working. There are some areas of the Marcellus that actually work at $4 gas price and that's great, but it really takes $6 gas prices before things open up even there.

OP: In Europe, where do you see the most potential for shale gas exploitation, with Ukraine engulfed in political chaos, companies withdrawing from Poland, and a flurry of shale activity in the UK?

Arthur Berman: Shale plays will eventually spread to Europe but it will take a longer time than it did in North America. The biggest reason is the lack of private mineral ownership in most of Europe so there is no incentive for local people to get on board. In fact, there are only the negative factors of industrial development for them to look forward to with no pay check. It's also a lot more expensive to drill and produce gas in Europe.

There are a few promising shale plays on the international horizon: the Bazherov in Russia, the Vaca Muerte in Argentina and the Duvernay in Canada look best to me because they are liquid-prone and in countries where acceptable fiscal terms and necessary infrastructure are feasible. At the same time, we have learned that not all plays work even though they look good on paper, and that the potentially commercial areas are always quite small compared to the total resource. Also, we know that these plays do not last forever and that once the drilling treadmill starts, it never ends. Because of high decline rates, new wells must constantly be drilled to maintain production. Shale plays will last years, not decades.

Recent developments in Poland demonstrate some of the problems with international shale plays. Everyone got excited a few years ago because resource estimates were enormous. Later, these estimates were cut but many companies moved forward and wells have been drilled. Most international companies have abandoned the project including ExxonMobil, ENI, Marathon and Talisman. Some players exited because they don't think that the geology is right but the government has created many regulatory obstacles that have caused a lack of confidence in the fiscal environment in Poland.

The UK could really use the gas from the Bowland Shale and, while it's not a huge play, there is enough there to make a difference. I expect there will be plenty of opposition because people in the UK are very sensitive about the environment and there is just no way to hide the fact that shale development has a big footprint despite pad drilling and industry efforts to make it less invasive. Let me say a few things about resource estimates while we are on the subject. The public and politicians do not understand the difference between resources and reserves. The only think that they have in common is that they both begin with “res.” Reserves are a tiny subset of resources that can be produced commercially. Both are always wrong but resource estimates can be hugely misleading because they are guesses and have nothing to do with economics.

Someone recently sent me a new report by the CSIS that said U.S. shale gas resource estimates are too conservative and are much larger than previously believed. I wrote him back that I think that resource estimates for U.S. shale gas plays are irrelevant because now we have robust production data to work with. Most of those enormous resources are in plays that we already know are not going to be economic. Resource estimates have become part of the shale gas cheerleading squad's standard tricks to drum up enthusiasm for plays that clearly don't work except at higher gas prices. It's really unfortunate when supposedly objective policy organizations and research groups get in on the hype in order to attract funding for their work.

OP: The ban on most US crude exports in place since the Arab oil embargo of 1973 is now being challenged by lobbyists, with media opining that this could be the biggest energy debate of the year in the US. How do you foresee this debate shaping up by the end of this year?

Arthur Berman: The debate over oil and gas exports will be silly.

I do not favor regulation of either oil or gas exports from the US. On the other hand, I think that a little discipline by the E&P companies might be in order so they don't have to beg the American people to bail them out of the over-production mess that they have created knowingly for themselves. Any business that over-produces whatever it makes has to live with lower prices. Why should oil and gas producers get a pass from the free-market laws of supply and demand?

I expect that by the time all the construction is completed to allow gas export, the domestic price will be high enough not to bother. It amazes me that the geniuses behind gas export assume that the business conditions that resulted in a price benefit overseas will remain static until they finish building export facilities, and that the competition will simply stand by when the awesome Americans bring gas to their markets. Just last week, Ken Medlock described how some schemes to send gas to Asia may find that there will be a lot of price competition in the future because a lot of gas has been discovered elsewhere in the world.

The US acts like we are some kind of natural gas superstar because of shale gas. Has anyone looked at how the US stacks up next to Russia, Iran and Qatar for natural gas reserves?

Whatever outcome results from the debate over petroleum exports, it will result in higher prices for American consumers. There are experts who argue that it won't increase prices much and that the economic benefits will outweigh higher costs. That may be but I doubt that anyone knows for sure. Everyone agrees that oil and gas will cost more if we allow exports.

OP: Is the US indeed close to hitting the “crude wall”—the point at which production could slow due to infrastructure and regulatory restraints?

Arthur Berman: No matter how much or little regulation there is, people will always argue that it is still either too much or too little. We have one of the most unfriendly administrations toward oil and gas ever and yet production has boomed. I already said that I oppose most regulation so you know where I stand. That said, once a bureaucracy is started, it seldom gets smaller or weaker. I don't see any walls out there, just uncomfortable price increases because of unnecessary regulations.

We use and need too much oil and gas to hit a wall. I see most of the focus on health care regulation for now. If there is no success at modifying the most objectionable parts of the Affordable Care Act, I don't suppose there is much hope for fewer oil and gas regulations. The petroleum business isn't exactly the darling of the people.

OP: What is the realistic future of methane hydrates, or “fire ice”, particularly with regard to Japanese efforts at extraction?

Arthur Berman: Japan is desperate for energy especially since they cut back their nuclear program so maybe hydrates make some sense at least as a science project for them. Their pilot is in thousands of feet of water about 30 miles offshore so it's going to be very expensive no matter how successful it is.

OP: Globally, where should we look for the next potential “shale boom” from a geological perspective as well as a commercial viability perspective?

Arthur Berman: Not all shale is equal or appropriate for oil and gas development. Once we remove all the shale that is not at or somewhat above peak oil generation today, most of it goes away. Some shale plays that meet these and other criteria didn't work so we have a lot to learn. But shale development is both inevitable and necessary. It will take a longer time than many believe outside of North America.

OP: We've spoken about Japan's nuclear energy crossroads before, and now we see that issue climaxing, with the country's nuclear future taking center-stage in an election period. Do you still believe it is too early for Japan to pull the plug on nuclear energy entirely?

Arthur Berman: Japan and Germany have made certain decisions about nuclear energy that I find remarkable but I don't live there and, obviously, don't think like them.

More generally, environmental enthusiasts simply don't see the obstacles to short-term conversion of a fossil fuel economy to one based on renewable energy. I don't see that there is a rational basis for dialogue in this arena. I'm all in favor of renewable energy but I don't see going from a few percent of our primary energy consumption to even 20% in less than a few decades no matter how much we may want to.

OP: What have we learned over the past year about Japan's alternatives to nuclear energy?

Arthur Berman: We have learned that it takes a lot of coal to replace nuclear energy when countries like Japan and Germany made bold decisions to close nuclear capacity. We also learned that energy got very expensive in a hurry. I say that we learned. I mean that the past year confirmed what many of us anticipated.

OP: Back in the US, we have closely followed the blowback from the Environmental Protection Agency's (EPA) proposed new carbon emissions standards for power plants, which would make it impossible for new coal-fired plants to be built without the implementation of carbon capture and sequestration technology, or “clean-coal” tech. Is this a feasible strategy in your opinion?

Arthur Berman: I'm not an expert on clean coal technology either but I am confident that almost anything is possible if cost doesn't matter. This is as true about carbon capture from coal as it is about shale gas production. Energy is an incredibly complex topic and decisions are being made by bureaucrats and politicians with little background in energy or the energy business. I don't see any possibility of a good outcome under these circumstances.

OP: Is CCS far enough along to serve as a sound basis for a national climate change policy?

Arthur Berman: Climate-change activism is a train that has left the station. If you've missed it, too bad. If you're on board, good luck.

The good news is that the US does not have an energy policy and is equally unlikely to get a climate change policy for all of the same reasons. I fear putting climate change policy in the hands of bureaucrats and politicians more than I fear climate change (which I fear).

The interview was with James Stafford of Oilprice.com, and I am grateful for the chance to reproduce it. Arthur Berman writes at Petroleum Truth Report.

Tech Talk - Production, Profit and Projection

As we move steadily through the first month of this new year, US production of crude has continued to increase, with the EIA now showing levels of around 8.2 mbd production.

Figure 1. US Domestic Crude production through the end of 2013 (EIA TWIP)

Finished gasoline production has been floating around a level of 9.2 mbd.

Figure 2. U.S. Finished gasoline production at the end of 2013. (EIA TWIP)

At the same time ethanol production continues at around 0.9 mbd.

Figure 3. U.S. Ethanol production at the end of 2013 (EIA TWIP)

US gasoline demand, on the other hand, has fallen below 9 mbd, in the normal seasonal decline during the winter months.

Figure 4. US gasoline demand at the end of 2013. (EIA TWIP)

In the latest Director’s Cut of the news from the North Dakota Department of Mineral Resources the state reports that production averaged 973 kbd in November, up from 945 kbd in October). The rig count is running around 190 rigs (below the all time high of 218 – roughly 18-months ago) and the agency notes that companies are moving toward a higher density for horizontal wells as a means of enhancing oil recovery. They estimate that at the current rig count there will be enough work under this program to sustain the industry for more than 20-years. However production will decline as the richer spots are drained, and in the most favorable scenario production will rise for another 2 to 3 years before stabilizing and then declining. At present the rate of growth in production is in the range of 300 kbd per year.

Figure 5. North Dakota Oil Production – historical and projected (ND Dept of Mineral Resources )

This is roughly similar to the growth in production from the Eagle Ford Shale in Texas over the past year.

Figure 6. Changes in production from the Eagle Ford Shale in Texas (Texas Railroad Commission )

Growth in production from the deep waters of the Gulf are likely to be closer to 50 kbd. Even combined, and recognizing that there may be some additional production from developing shale prospects, it is difficult, as the above three regions hit production peaks in the near future, to anticipate that US production will increase by the 2 mbd that is projected by some forecasts.

Some of this doubt comes from North Dakota agency itself, which has some concerns over the continued ability of the industry to attract drilling capital, as well as the impact of additional regulations. This limit of available funds is something that Gail Tverberg has pointed out in a recent post. Shell is only one of the major companies recognizing that the increasing costs of development in more difficult parts of the world are not being offset by compensating increases in production, price and profit. As operations around the world continue to attest, (offshore Brazil being but one example) just because the money is invested does not mean that production will of a certainty arrive on the original date forecast, nor will it be at the original price estimated. In the case of Brazil, while new fields show the promise for the future with a steady increase in the reserves that the country projects, this has yet to be reflected in increased production.

Figure 7. Growth in projected reserves offshore Brazil over the past 30 years (Offshore )

The problems of development are being blamed on a lack of available drilling rigs as well as budget constraints. This may be a considerably simplified version of the realities which are likely to continue to see delays in production against target figures into the medium term future. This is unfortunate since there remain few places where global production can be expected to increase in the near future.

In the latest Monthly Oil Market Report (MOMR) OPEC notes that non-OPEC supply growth is anticipated to be 1.2 mbd this year, with the bulk of that growth coming from the United States, Canada, Brazil and the two Sudans. Oil production from the Canadian oil sands is anticipated to reach 3 mbd by 2015 on its way to a total production estimate of around 6 mbd by 2035, at an approximate growth rate of 100 kbd per year.

Figure 8. Anticipated growth in Canadian oil production (NEB )

Perhaps more than most the Canadian growth is likely to follow the projected path, although there, as in other parts of the world, the need to ensure future capital for the increasingly expensive operations, and the provision of sufficient infrastructure to handle the increased production are matters that will continue to provide caveats to the overall levels achieved.

And as regards the increase in production from Sudan and South Sudan, certainly the conditions in South Sudan are not encouraging to hopes for increased production at any time in the near future. Fighting in the regional capital of Malakal shows the increasingly tribal nature of the conflict and this may well indicate that fighting will not easily be stopped and order (let alone oil flow) restored. This is of concern to China, which imported some 14 million barrels of oil from the region in 2013 but is now faced with the problems of sustained investment in the face of lost production and facilities after seeing a similar collapse in production from Libya. And while these problems are considered relatively small at the moment, at this time when global production and supply are relatively closely tied, the continuation of problems will mean the China must look elsewhere for that production, with consequent impacts on overall prices.

The problem, as the very short list from OPEC illustrates, is that there are not that many places around the world where increased production is likely and where China can invest to achieve the levels that it anticipates that it will need as demand continues to grow. And as the market becomes more competitive, so prices are unlikely to decline much (apart from regional short term issues such as the recent desire in the US to produce more diesel from refineries). Yet while this will give some reassurance to those seeking to invest capital in the industry it comes at a time where there remain concerns over regulation in some countries, and conflicts in others both of which cause investors to hesitate in their commitment. The problem is that there aren’t that many alternative strategies that hold much hope for working.

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.

The Citicorp Energy Projection - a Gentle Cough

Gasoline prices remain high, and Reuters recently noted that there are enough countries with civil unrest, technical problems and bad weather that there are around a million barrels a day of possible supply that are not getting to the market. . Yet with Saudi Arabia continuing to reassure that it is willing to pump more oil, if needed, there appears to be, superficially, little cause for supply concerns this year. By the same token, in the longer term, concerns over supply also seem to be increasingly discounted. For example Citigroup has just released a new report on Energy 2020:North America as the new Middle East. The report suggests that there is really no concern with future supplies of oil and gas, perhaps most clearly shown with this plot:

The Citigroup view of the coming energy future (Citigroup)

I would argue that the numbers for Saudi Arabia and Russia are difficult to realistically justify. For the Kingdom, which is reported to be producing 9.9 mbd, to increase production by another 2 mbd is optimistic, given the ageing of their primary fields and the decline in remaining volumes that I will discuss in future posts in the current series on that country. The projection of an increase in Russian production is a similar concern. With the decline in production from Western Siberia there is not enough new production coming from Timan-Pechora and Eastern Siberia to sustain existing levels let alone see an increase in production – a point that has been made by Russian officials in the past. However the real concern lies with the relatively unrealistic image that is being projected for US production over the next eight years.

North American shale plays (EIA map, cited by Citigroup)

The image that the above figure projects is that the country is covered in shale, all waiting to provide its wealth to the nation. But that is not the case and shale plays have been a hot topic for a number of years now. And while the map above shows a carpet of shale that has the potential to produce oil and/or natural gas it does not clearly enough distinguish the considerable difference between deposits that are presently economic, and those that are not. (The small number of fields that are labelled as prospective does not speak well for the future).

If one examines the prediction for future production it shows that overall US growth in production of all liquids will rise from some 9 mbd at the end of 2011 to 11.6 mbd in 2015 and then go on to a figure of 15.6 mbd in 2020. (Note that this includes natural gas liquids (NGLs), refining gains and growth in the production of biofuels). The contribution of the various sectors is broken down into:

Projected growth in US production (Citigroup )

In the Deepwater category Citigroup cite existing production from Atlantis, Perdido, Shenzi, Silvertip, Tahiti, and Thunder Horse. Future gains will then come from Big Foot, Gunflint, Hadrian, Jack, Knotty Head, Lucius, Moccasin, St. Malo, Stones, Tubular Bells and Vito. Tiber, Buckskin, Kaskida, Appomattox and Heidelberg. But the report sees gains in the Gulf of Mexico (GOM) total liquids as likely peaking in 2016 at around 2.2 mbd and the gains projected in the above table that might come beyond that as being an “upside potential” based on a change in regulatory factors and the ability of oil companies to bring their reserves on line.

Citigroup projection of future production from Deepwater (Citigroup)

Part of my problem with this approach is that it totally seems to discount the declining production and failure to meet target projections from existing GOM platforms which, among others, has been well documented by Jean Laherrère (here, here and here) and by Darwinian at The Oil Drum (TOD). Looking at the fields that Citigroup have cited it is pertinent to examine first their relative size, as Jean illustrated.

Discoveries in the GOM (Jean Laherrère)

In this context it might be well to remember that as a rule of thumb (from the Russian posts) a 500 mmboe field may produce around 120 kbd. However it should be noted that some of the GOM fields are having problems reaching their target, and that production is falling at a rate of around 20% per year, as Darwinian showed for the cumulative production of Thunder Horse Atlantis and Tahiti, which were projected to produce 550 kbd in total.

History of production from Thunder Horse, Atlantis and Tahiti combined (Darwinian )

With production having already fallen 300 kbd from projections, mainly through lower production from Thunder Horse and Atlantis, it is hard to see how to justify the numbers that Citigroup are using.

The Citigroup projection for Alaska anticipates possible gains from the Shell activities in the Chukchi Sea, although the exploratory wells have yet to be drilled and the geographical challenges to be met in bringing that oil ashore are not yet fully addressed. The Alaskan pipeline is currently flowing at around 609 kbd, which is high enough to prevent wax and ice build up, but with ongoing declines in production and problems arising once the flow falls below 600 kbd how long it can continue to perform satisfactorily is open to question. They cite heavy oil operations at Milne Point which has been declining in production, and West Sac which is a very heavy, cold oil which has raised considerable technical issues in achieving the production of around 15 kbd at present, with existing plans only adding 150 million barrels in total to reserves. The other source that is cited is to produce the light crude from the National Petroleum Reserve in Alaska (NPRA). Given that the bridge from Alpine into the Conoco-Phillips wells in the NPRA has just been approved suggests that an increase in production from the region is still some time away. Put together it suggests that the estimates for a 500 kbd increase in Alaskan production within the next eight years is not a reasonably likely occurrence.

Location of fields and development along the North Slope (Free Republic )

And the third source that Citigroup cite are the oil from shale deposits shown at the top of the post. They see growth of 2.4 mbd in oil production and 1.5 mbd in NGLs from the increase in production from natural gas. The production gains are broken down as follows:

Projected sources of oil from shale plays (Citigroup)

The plot, again, includes a large volume of “upscale potential” which might come from a change in regulations, government and oil company attitudes. I have written about some of the more realistic views of the possible future production of the Bakken and the Niobrara, the Tuscaloosa and the Chatanooga. In this regard it is worth noting that while Citigroup see production from the Bakken rising to around 1 mbd in 2016, and being sustained at that level through 2022, this is not the view of the folk in North Dakota who are monitoring well production and permits.

Anticipated production from the Bakken and Three Forks in North Dakota (DMR March 2012 )

It is instructive to this argument to note that Fidelity E&P has just celebrated reaching a production record of 3,500 bd in the Bakken which it derives from 58 wells. As they continue to run 5 rigs, and have been able to drill a long lateral horizontal well in 28 days they should be able to increase production this year, but they are fighting the rapid decline in existing wells, which requires that more wells be drilled every year, and that (as the better spots become drained) so the drilling activity must accelerate to sustain existing production.

Typical Bakken well production (ND DMR )

Production from the Bakken in North Dakota reached 546 kbd in January, and this production came from 6,617 wells which gives an average of 82.5 bd production from each well. Activity is such that some 250 wells are waiting on fracture services and rigs capable of drilling 20,000+ ft are at 95% utilization in the area. And prices of natural gas are down to $1.89/kcf. Bear in mind that, after a while, it becomes harder to find a spot where no-one has already been.

Map of wells planned and drilled in a section of the Bakken (DMR Presentation to Farm Bureau )

On the ground it looks more like this:


Well sites in the Bakken (Vern Whitten for DMR – Farm Presentation)

The North Dakota Department of Mineral Resources has a series of very informative presentations on the Bakken, including hydraulic fracturing, and the above were taken from the Presentation to the Piece Country Farm Bureau on March 15th.

Current plans anticipate that the Niobrara may reach 250 kbd of production by 2020. The problem, however, as Art Berman has skillfully pointed out is that, as the ND plot above shows, the current wells have a high decline rate, and production levels drop dramatically once the wells are brought on line. Art has explained the background to this for gas wells drilled into shale but the impact for oil wells, where the oil has a higher viscocity than the natural gas, can be significantly greater. Given that well costs are in the order of $10 million per well (depending on location DMR gives the ND price at around $8.5 million, and numbers for the Eagle Ford have been quoted at $8 million) the amount of oil that must be produced over the first few years to justify investment is significant. There are, for example, some 1,400 wells producing in the Eagle Ford play. The play produced 30.4 million barrels of oil in 2011, and is anticipated to add 200 kbd of production this year with the potential to reach 1.2 mbd by 2015. But the high decline rates mean that wells must be replaced rapidly to sustain those levels of production.

It is this disregard for the declining production from existing and future wells that appears to be neglected in the Citigroup study. Those plays which will yield rapidly in generating high initial well production will, in turn, be the first that decline significantly and need replacement. Yet replacement will, over time, have to be in poorer parts of the formation, requiring that multiple wells replace the initial producer, and so bounds on production will be reached, likely before the end of the decade. Citigroup anticipate that the risks in development of the shale plays, whether in Texas or California, come as much from an inability to transport the oil generated and from environmental policy, they see few geological risks – which is a pity, since it is the geology that will control production and its decline, and the ultimate profitability of these ventures.

And finally Citigroup see that cellulosic ethanol will come into its own this decade, and that it will provide half the 2 mbd of biofuels produced in 2020. Unfortunately the economics of large scale production that have led to failures of ventures to date have over-ridden the mandated production levels that the group cite as their foundation, and there is no indication that this will change in the next eight years.

In short, though this is an interesting exercise it is too full of “could” and thus will not make much of a useful contribution to meaningful discussion of future production.