Tech Talk - Rig Counts in the Middle East

In recent posts about the situation in the Middle East, I have noted the need for Aramco to increase the number of drilling rigs that it must use, since it is now looking for natural gas in their tight sand deposits rather than finding the large reserves that they had hoped in the shale reservoirs. It is interesting in this regard to plot the number of rigs that have been working in the Middle East.

Getting the overall data from Baker Hughes the rig count can be plotted, over time, to give the following:

Figure 1. Rig Counts in the Middle East (Baker Hughes)

If one looks at the trend for the last twelve months, it has remains on a fairly consistent upward trend, following that of the longer time interval plot of Figure 1.

Figure 2. Recent trend in Middle East Rig count (Baker Hughes)

Back in the days of The Oil Drum, Euan Mearns and I had this concern, which occasionally surfaced, about these numbers. From my early post on the subject which noted that back in 2005 the KSA were running around 20 rigs, which would not be enough to get them the production they were claiming to need in the future, to Euan’s in 2011, the topic was revisited regularly over the time that the count steadily mounted as the Kingdom had to drill an increasing number of wells just to keep production at around the same overall level.

I am using the KSA as the example, given the large volume of its production relative to that of the others in the Middle East, but as the numbers show, the trend toward increased drilling rate to create enough productive wells to sustain production as the larger volume wells dry up is starting to become a steadily more frantic race across the region.

Rune Likvern used the phrase “Red Queen” in discussing the overall long-term need of the companies in the Bakken to have to drill an increasing number of wells, with individually reducing production, in order to remain in place with regard to overall production. As the production from the Bakken now exceeds a million barrels a day it may seem foolish to be predicting this “squirrel cage” view of the future, but the rig count up there is still running at around 190 rigs, which is not enough to sustain future growth for long, given that access to the sweet spots is limited, and they are beginning to run out of new sites.

So it is in the Middle East. The rig count numbers are mounting steadily, it is reported that there were 88 rigs drilling in the country in October 2012. Last year this rose to 170, and the number is expected to rise to 210 by the end of this year.

Aramco have done remarkably well, over the past decade, in developing new technologies to harvest the attic oil left around the tops of the major producing formations such as Ghawar, as the main body of the fields begin to be exhausted. But the problem with these secondary rig operations is that they were directed at the smaller pools around the field, rather than tapping into the major volume, and thus they had an expected and finite life. That life is starting to come to a close. Just as, when sucking a thick milk shake through a single immovable straw, when it stops drawing fluid, there is still a fair amount left in the cup. But as you move the straw around and slide it up and down the sides, the amount that you recover gets less, and it takes greater and greater effort to get it, to the point where you quit and discard the carton. And that is where the Middle Eastern oilfields are beginning to find themselves.

The high-quality light oils of the mainland are rapidly running out, and the remaining fields with the promise for sustaining Saudi production at around 10 mbd for the next few years, are the heavier sour crudes from the offshore fields such as Safaniya and Manifa. At the same time there is a need to reduce the increasing amount of oil (now at 3 mbd) being consumed in country, with the hope that this can be replaced by domestic natural gas. But those hopes are being reduced as the shales are found to be less productive than anticipated, and hopes are now switching to the slower production that can, hopefully, be achieved from the tight sands – but at the cost of an increased number of wells, inter alia.

This is the writing on the wall for global oil production, and in the short-term it will be neglected. Increasing the number of rigs will, in that interval, increase the number of wells that will produce, even though the volume from each well will be less, and the overall life of the wells will similarly reduce, as higher production techniques tap into smaller fields.

But we are now on the treadmill in the squirrel cage, or, as Rune would have it, we have wrapped ourselves in the cape and crown of the Red Queen, and must run faster and faster just to stay in place. (There are additional concerns since, as an example, Manifa could not be brought on line until there were refineries built that could process that crude, and so the options for increasing production beyond the capacity of refineries to absorb that increase is a futile exercise).

There will soon come a time when the gain from the overall increase in new wells will not match the decline in production from older wells, particularly if the effort to “run faster” is restricted to only a few players (Russia for example is not yet putting the effort and investment into increased drilling rates in order to sustain their overall levels of production, and given the age of their major fields are likely now in terminal decline).

Ouch!

Tech Talk - the difference between fracking and acidizing a well

It turns out that in the end I wrote some 929 posts on The Oil Drum, over the course of its eight-year life, 92 of them in the past two years. The posts covered the gamut from how coal mines work, to some of the innovative work being done in Saudi Arabia to extend the life of their reservoirs - sometimes straying a little from a tight focus on fossil fuel extraction but rarely for long. As I noted in last week’s post (which ran a week later on The Oil Drum as my swan song there) the audience that the site brought far exceeded any that I had during the totality of the students that sat in my classes over 40-years of teaching (a number in the low thousands).

My hope in writing was to provide a little background to some of the stories that made the news and to put some of the developments in context, so that readers might better understand. One of the most useful sources for this was always Leanan’s Drumbeat, and as this now too fades into an archive, let me pick an example from the penultimate Drumbeat as the basis for this week’s post.

The story comes from the San Francisco Chronicle and runs under the headline “Acidizing could rival fracking in Monterey Shale.” The précis for the story reads as follows:

Fracking hasn’t unleashed an oil production boom in California, at least not yet. Could acid?

Companies trying to pry oil from a vast shale formation beneath Central California have been pumping powerful acids underground to dissolve the rock and free the petroleum within.

And there are hints that the process, known as “acidizing” a well, may work better than hydraulic fracturing in California’s Monterey Shale, estimated to hold 15.4 billion barrels of oil.

There are two parts to this story that are worthy of comment. The first is to discuss the comparison between acidizing and fracking a well, while the second is the potential for an expansion of production from the Monterey Shale. (But I will cover that later topic in the next Tech Talk).

The process of fracking a well has been well discussed in the past couple of years as the success of the technique has helped make oil and gas deposits found in shale deposits more profitable and viably productive. During the time that I was writing posts on the technology of oil and gas well development, there was one post that dealt with fracking specifically. It was followed by a post last year in which acidizing was covered as part of the work that Saudi Aramco were using to improve the production from the Berri and Ghawar oilfields.

Since these posts are now a little old and separate let me repost just a couple of relevant bits, in part to explain that neither process is quite as dramatic as it was made out to be in the SF Chron article.

Figure 1. Crack growing out from a drilled hole in Plexiglas, the small notch at the top of the hole controlled the direction of the growth of the crack (We put ink in the hole to show how the fluid goes into the crack).

In the above picture you can see that when the hole was pressurized, a crack grew, and ink flowed into the crack, as it formed, but, when the pressure came off, the crack closed and most of the ink was forced back out of the crack. (We created the pressure by firing an air rifle pellet into the hole).

So if we are going to have a useful crack we need to have it open after we take the pressure back off – after all we need to get the fluid back out of the well, so that the gas can pass up the well for collection.

Now it is not quite as easy to grow the crack, or prop it open as I may have suggested earlier, and to explain some of the issues in a little more detail I am going to use an example and some details from the Modern Shale Gas Primer .

When you decide to frac the well, and each well is different, as is just about every location, so there is a significant amount of preparation and knowledge required to work out the procedure required at that particular point. Bear in mind that the crack that you are going to have to grow needs to stay in the shale layer, and not go out beyond it into the surrounding rock. One of the reasons for this is, apart from giving the gas a path to the well, if it goes outside the reservoir rock then the gas can escape, or, alternately, other fluids can gain access to the well. This is particularly true of the Barnett where the rock immediately below it, the Ellenberger limestones, can hold a lot of water that can muck up the gas recovery if it gets into the fractures. (Given this degree of control and the large distance below the ground to the reservoir rock, this is why a lot of the fears that the frac job will damage the ground water tend to be dramatically overstated).

In the example cited, which is from the Marcellus shale, the treatment of the frac takes a total of 18 steps, and because some of these are fairly similar I am going to go through them in groups. First the hole is treated with an acid, to clean away any remaining debris and mud from the drilling operation and to clean any fractures around the hole, so that they can be used to help the frac grow. After the acid the hole is filled with an initial polymeric fluid, largely water, but containing the “Banana Water” that I referred to in an earlier post. This is a friction reducing agent and will help carry the particles used to hold the crack open into the crack in the first place. The problem with that polymer is that some of the choices available, while good at reducing the friction to help move the particles, aren’t that good at holding the particles in suspension, and the last thing we need is for them to settle out in the bottom of the well, and so in the subsequent steps in the process as the particles (or proppants) are added, there is usually a second polymer in the mix to hold them in suspension.

Once the hole is full of the slickwater (the official term for the first polymer solution) the initial frac is made with a fine sand suspended in the fluid. To keep the crack open all along its length we need sand along the path and the crack gets narrower as it grows deeper. So for the first several stages of the crack growth the fluid is filled with successively greater concentrations of the fine sand, so that, in this way, it can penetrate to the deepest part of the fracture.

In the example cited there are some seven of these sub-stages with the fluid being pumped into the well at some 3,000 gpm but varying the fluid:proppant density to carry more and more of the particles into the fracture. Once these stages have been completed, then the job is finished by pumping an additional eight sub-stages of fluid, with this second set containing a larger size of proppant particles. In this way the area closest to the mouth of the fracture will be held wider apart to make it easier for the gas to escape. As with the first set of sub-stages, the concentration of proppant in the fluid increases as the stages progress. In total, in the example given, some 450,000 lb of proppant was used to make the fracture, together with some 578,000 gallons of water.

Once the fracture is created, then the well is flushed to clean out the different fluids, and make it easier for the gas to get out out of the rock and into the well. (It also removes any loose and ineffective proppant so that it doesn’t later become a nuisance). If you think that this would need a lot of equipment you are right!

Figure 2. Equipment used for hydraulic fracturing a well (Primer)

You may note that, as part of the process for preparing the well for fracturing, the well bore is first cleaned by acidizing the bore to dissolve the fine materials left along the wall and in the nearby cracks and joints of the rock, before the well is pressurized.

The description of acidizing is as follows:

The problem of scale is also that, in the pumping of fluids into the reservoirs, and the flow of oil out, the quantities that are dealt with are significantly larger than in most other countries. Flow levels are required to reach over 10,000 bd, both in oil recovery, and in the relatively precise location of water injection to sustain reservoir pressures. This led Aramco to adopt horizontal well technology, not only for the recovery of oil, but also in the injection wells that are used to inject the seawater.

Horizontal wells in carbonate are prone to well damage around the borehole, due to the drilling process, and this initially limits the flow of fluid through this annulus, or requires a higher driving pressure to inject the water into the formation. In one example it took an injection pressure of 2,350 psi to drive 13,000 bd through an exposed horizontal open hole section some 8,900 ft long. In order to improve the performance of the well it was to be treated with an acid bath to not only remove damaged sections of the wall, but also to eat wormholes into the formation. Where the wells are draining gas it is not that difficult to bullhead the acid into the well where the acid is injected and allowed to fill the well for a couple of hours before being removed. This can be successful in wells where the use of coiled tubing (CT) is limited and flow rates would otherwise not be as high as needed for an effective cleaning. But it requires considerable volumes of acid, and in filling the entire open hole, there is the risk of differential attack along the walls, providing an undesired result. The alternative was to use the smaller diameter of a coiled tubing rig and feed this first to the back of the hole and then inject acid as the coiled tubing was pulling out of hole (POOH). However it is sometimes a little difficult to feed the smaller pipe down the open hole all the way to the back, and the diameter limits the rate at which acid could be injected. Thus there was a debate as to which method would be the best to use.

Aramco have used two ways to get around this problem. The first was to use a down-hole tractor to overcome the frictional forces which were otherwise stalling the placement of the CT by overwhelming the driving force before the tool could reach the back of the hole. The tractor has a small series of wheels that are recessed within the tool while it is fed down the well to the point where it is deployed.

Figure 3. Down-hole coiled tubing tractor (Welltec )

When the CT Well Tractor is initially powered up, the wheel sections are hydraulically extended out of the tool body and activated automatically. Each wheel contains its own independent hydraulic motor, which drives the wheels and provides the forward motion of the CT Well Tractor. . . . . . The modular structure of the drive sections makes it possible to change the traction by reducing or increasing the number of wheels needed to drive the toolstring. The CT Well Tractor 318 can provide a pull of 3,500 lbs, which doubles in tandem configuration. This can further be increased to 10,000 lbs by stacking three CT Well Tractors.

The first major test of this was in the 8,900 horizontal section water injection well I referred to above. That section of the well was divided into 16 sections each of which was treated as follows:

1. First, the treatment interval has to be washed with plain 20 wt% HCl for filter-cake clean up and provide initial wormholes. The main additives to the plain acid are a corrosion inhibitor, surfactant, and friction reducer. Plain acid was used at 10 gal/ft, including additives, resulting in a total acid volume of 77,000 gallons.
2. Plain acid was followed by 20 wt% diesel emulsified acid at 20 gal/ft with a total of 154,000 gallons for the 16 treatment stages. The higher concentration of retarded acid is meant to provide deeper wormholes.
3. To achieve better acid diversion at the end of each pumping stage, viscoelastic surfactant-based (VES) water will be used at 10 gal/ft at a total volume of 7,500 gallons.
4. Finally, water over-flush of 10,000 gallons is to be pumped following the previous 16 treatment stages to break micelles formed by VES. The over-flush contained brine water mixed with 3 vol% of mutual solvent.
The total treatment fluid to be injected in this job is 248,500 gallons; this large acid job is considered one of the biggest stimulation jobs for any well in the Ghawar field.

There were a couple of glitches with running the tool, in that the well had washouts that it took a “flying leap” for the tractor to get past and it was not able to reach the last 3,000 ft of the well, which was bullheaded. Nevertheless after the treatment the flow injection rate for the well was increased from 13,000 barrels of water per day (BWPD) to 28,000 BWPD.

In a consequent test in a multilateral water injection well some 362,700 gallons of treatment fluid were used to acidize a dual lateral horizontal water injection well with a total horizontal interval of 10,335 feet. Prior to the treatment the well required an injection pressure of 2,100 psi to inject 15,000 BWPD into the formation. After the treatment the two laterals were able to inject 30,000 BWPD at 700 psi driving pressure, and at 2,100 psi the wells became capable of deliving 80,000 BWPD. This saved the cost of adding two additional wells in the neighborhood.

Hopefully this should show that there is quite a bit of difference in the techniques and in their purpose down-hole. And while acidizing has some potential for opening existing cracks and passages in a rock it depends on the rock type as to which acid might work best, and how successful it might be.

But I’ll write more on this, and with relevance to the Monterey Shale, next time.

Tech Talk - Oil Supply, Oil Prices and the Kingdom of Saudi Arabia

From the time that The Oil Drum first began, and through the years up to the Recession of 2008-9 there was an increase in the price of oil, and that resumed following the initial period of that recession, and, in contrast to the price of natural gas, oil has recovered a lot of the price that it lost.

Figure 1. Comparable price of oil from 1946 (Inflation data)

And if one were to draw a straight line on that graph from the low point in 1999 though now there hasn’t been a huge variation away from the slope of that line for long. That, of course, does not stop folk from pointing to the very short, roughly flat, bit at the end and saying that oil prices are going to remain at that level, or are even about to decline.

To address that final point first, I would suggest that those making such a foolish prediction should go away and read the OPEC Monthly Oil Market Reports. Remember that, for just a little while longer, oil is a fungible product. OPEC make no secret of the fact that they continuously examine the global economy and make estimates on how it is going to behave. This month they note that the economies aren’t doing quite as well as expected, and have revised down global growth to 2.9%, though they expect next year to be better, and hold to their estimate of a 3.5% growth rate.

But OPEC go beyond just making that prediction, they use it, and data that they have on consumption and oil supplies around the world, to estimate how much OPEC should produce each month to balance supply against demand, so that the price will remain at a comfortable level for the OPEC economies. And based on those numbers they tailor production.

This month, for example, they note that global oil demand is anticipated to grow by 0.8 mbd this year (and by 1.04 mbd in 2014). They anticipate growth in production of around 1.0 mbd from the non-OPEC nations, with projected increases from Canada, the United States, Brazil, the Sudans and Kazakhstan contributing to an additional 1.1 mbd next year. From these numbers they can project that demand for OPEC oil will be slightly down this year, at 29.9 mbd down 0.4 mbd on last year, with next year seeing an additional fall of 0.3 mbd on average.

Figure 2. Projected oil demand for 2013 (OPEC MOMR )

Thus slight reductions in production from OPEC, and particularly the Kingdom of Saudi Arabia, (KSA) can keep the world supply in balance with demand and more critically for them keep the price up at a level that they are comfortable with. Note that in relation to the overall volumes of oil being traded they are not talking much adjustment in their overall volume (around 1% of the total 30 mbd) in order to sustain prices. The USA produces more, OPEC produces less – not much less because global demand is growing – and the price is sustained.

This has virtually nothing to do with the speculators on Wall Street and the corrections they might impose, this is all about supplying a needed volume to meet a demand and controlling that supply to ensure that the price is sustained.

There are a number of caveats to this simplified explanation, one being the short-term willingness and ability of some producers to keep to their targets. One of the imponderables is the production from Iraq. Although Iraq has been given a waiver through 2014 on the need to limit their production, the increasing violence has led to a drop in production, back below 3 mbd.

Figure 3. OPEC production based on data from secondary sources (OPEC MOMR)

As I have noted in the past, OPEC is sufficiently suspicious of the reported numbers from the countries themselves that they check from secondary sources, and provide both sets of numbers.

Figure 4. OPEC production numbers from the originating countries. (OPEC MOMR August 2013)

Note, for example, that Iran says that it is producing over 1 mbd more than other sources report, and Venezuela is around 400 kbd light. The balancing act is largely the charge of KSA, since it produces the largest amount and can adjust more readily to balance the need.

One of the other caveats is that the internal demand in these countries is rising, and that lowers the amount that can be exported. This will in time require that OPEC produce more, just to sustain the amounts that they export. And the problem here is the biggest caveat of all. Because KSA cannot continue to produce ever increasing amounts of oil.

Just exactly how much the country can produce is the subject of much debate, and has been at The Oil Drum since its inception. But if I can now gently admonish those who think it can keep increasing forever, and that it has vast reserves that can flood the market at need. This fails to recognize that the major fields on which the country has relied are no longer capable of their historic production levels, and that, over the time that TOD has been in existence, production has switched to the new fields that KSA had promised it would, back in time.

But these new fields, including Manifa and Safaniya produce a heavier crude that, for years, KSA struggled, usually in vain, to find a market for internationally. It is only now that it is building its own refineries to process the oil that it can find a global market for the product. Yet those refineries have only a limited capacity. If you can’t ship, refine and market your product in the form that the customer needs, it can’t be sold, regardless of how much, instantaneously, you can pump out of the ground. And so KSA is starting to look harder for other fields. They have increased the number of rigs employed to 170 by the end of the year (in 2005 they had about 20 oil and 10 gas rigs operating), going beyond the 160 estimated earlier, seeking both to raise production from existing fields, but also to find new ones. This is almost double the number that Euan reported at the end of last year. That this is being expedited is not good news! Because new fields will very likely be smaller, and more rapidly exhausted, and may not have the quality of the oil produced from Ghawar and the other old faithfuls.

Realistically, over a couple of years, I would suspect that the oil price line, that I mentioned was rising at the beginning of the piece will continue to rise and we are just going to have to accommodate to it.

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 - The "best of the rest" in Saudi Arabia

The discussion that swirls over the future of global oil supplies often seems to focus, from the side of those who suggest that there is no problem, on the large volumes of oil that still remain in place around the world. The critical point however is not that this oil exists, but rather the rate at which it can be recovered. This is perhaps most obviously pertinent to the discussion of the oil coming from the Bakken formation in North Dakota, where the rapid decline in individual well performance means that a great many wells must be developed and remain on line in the out years to sustain any significant flow past peak. It is a point that clearly was missed by Leonardo Maugeri, as I noted last week, and equally by George Monbiot, who has now finally been swayed to the side of the cornucopians, after years of doubt.

But the issue of individual well flow rates are an increasingly critical factor when future oil production in oilfields around the world are considered and this holds equally true when the fields in Saudi Arabia are discussed.

The history of oil production from Saudi Arabia has largely come from individual wells that produced in the thousands of barrels a day. In order to sustain that production over decades it has been necessary to ensure that the pressure differential between the well and the rock are sustained; that the rock has an adequate permeability to ensure that flow continues at a steady state; that the oil itself is of relatively low viscocity and is thus able to easily flow through the rock; and that there is a sufficient thickness and extent in the reservoir to allow such sustained production. All of those factors came together in the giant fields that provided high levels of production over many decades, most particularly in the northern segments of Ghawar.

 Yet those conditions are less commonly congruent in the fields that Aramco must now move into to address the coming falls in production from the historic sources. These “best of the rest” (as the late Matt Simmons called them) that must now increasingly carry the burden of sustaining Saudi production fail, individually, on differing grounds from meeting those earlier parameters, but collectively, and in the face of Ghawar’s decline, they will only be able to sustain production to their original targets and will not be able to provide replacement production as the oldest and larger begin to fade. I would remind you of the curve that Euan put up back in 2007 .

Figure 1, Euan’s production estimates from 2007.
Euan’s overall estimates for total production have not been met, rather KSA chose to reduce the volumes that they provided to the world market in order to sustain a higher price for their product. (And I would note that it was their recent production of an increased flow into that market that provided the cushion for the rest of the world, so that it can view the current sanctions on Iran (which came into full force at the beginning of this month) with considerable equanimity – at least for the next few months. That supply has provided the backup as Iranian exports are reported to have already halved.(Now, if supply starts to get tight, it won’t be the fault of the KSA.)

 But, in regard to the longer term question of total flow, will KSA increase their production to the 12 mbd that appears as some magic figure in the tables of the cornucopians as they look toward the end of the decade? I think not. Euan’s plot, if perhaps a little pessimistic over the rate at which Ghawar is declining is nevertheless true from an overall perspective of the changes that we can anticipate. Bear in mind that Aramco was only then moving to increase the size of their drilling fleet from historic levels of around 20 rigs to as many as 200 in the years since. And it is that change, with the underlying realities that it implies, that must be recognized when looking into the future.
 As the largest fields are depleted, so production moves from them to smaller fields in the region. And as those fields are depleted production moves to yet smaller, and initially relatively uneconomic fields, that now have value. But to achieve the same production a greater number of wells must be drilled, as their individual production levels and operational lives are now shorter. 

 The Kingdom has been building production in a number of different regions over the past ten years. These have added considerably to overall Saudi capacity, but even if they are being drawn down at only 2% p.a. (as has been claimed in the past) that slow reduction makes it more difficult for them to be the source of additional production to meet any future increase in demand/replacement of depleted reserves. As I list the fields remember that when Ghawar‘s decline becomes evident these fields are already in production, and so it must be the smaller fields that lie beneath them in the hierarchy that will then have to carry the burden. 

Qatif has been producing 500 kbd since 2004, from a field that started with a projected 6.2 x 31 mile size, with 151 development wells, and an 8.4 billion barrel reserve. Both it and Abu Sa’fah lie near Abqaiq and Berri. 

 Abu Sa’fah, which was expanded at the same time as Qatif, to 300 kbd is an offshore field that covers 6.2 by 11 miles and in the expansion had 90 wells and reserves of 6.1 billion barrels. (Half the revenue from Abu Sa’fah goes to Bahrain as JoulesBurn has explained and that arrangement continues with Bahrain getting the revenue from 150 kbd of oil. 

    
Figure 2. The location of Qatif and Abu Sa’fah (JoulesBurn)

 In 2007 Aramco brought 500,000 bpd of Arabian Light onto the market through the Khursaniyah development. (this included the onshore Abu Hadriya, Harmaliyah, and Fadhili fields) though it first began production at a lower volume in 2008. The associated gas plant ran through some troubles and delays before coming on line in 2010, and this also delayed the time over which the field came up to full production. 
 Down at the other end of Ghawar there are a group of oilfields found since 1967 including Hawtah and Nuayyim, in the Central Region. The group of fields, referred to as the Hawtah Trend or Najd Fields has had problems in the past with sand inflow into the wells, and there is some debate as to whether the reserves in the region total 10 billion or 30 billion barrels of light, sweet crude. Hawtah itself produces around 150 kbd, but the associated fields brought this up to 400 kbd.

Nuayyim came on line with an additional 100 kbd in August 2009.

Figure 3. Named Saudi fields, with those coming on line or expanded in 2009 being emphasized. (Energy-pedia ) 

 Haradh has been discussed earlier as part of Ghawar, and the major addition that came that year was at Khurais, which added 1.2 mbd to supply potential. (Increase in production from Shaybah brought another 250 kbd to the total). Khurais, was mapped by JoulesBurn in 2008, and it was here that the need for additional drilling rigs became more evident in getting all the wells brought on line in time for the scheduled start of the upgrade. With that completed, the increase (which actually comes from the three adjacent fields of Khurais, Abu Jifan and Mazalij) of 1.2 mbd began production in June 2009. 

 In terms of the production of the heavier oils that are taking a greater portion of the marketable Saudi product it has been suggested that KSA have planned to increase production at Zuluf, which has some 8 billion barrels in reserve, to a capacity of 1.2 mbd from 500 mbd (but with 200 mbd mothballed). 

 Up on the Kuwaiti border lies the Hout oilfield, where work is now being developed to capture increasing volumes of natural gas now flared from the field. This is one of the four fields that the two countries share, and which includes Khafji, Lulu and Dorra. Most of the oil goes to Japan. Khafji came on line in 1960, and Hout in 1963. The fields have produced around 4 billion barrels of oil, and are now producing at around 610 kbd. Bids for the new development are now due in September.

 I will leave Shaybah and Manifa until next time.

OGPSS - Saudi Arabia - production from Safaniya

In recent posts I have been looking at the potential for the historically high producing Saudi oilfields at Abqaiq, Berri and Ghawar to increase, or even sustain current levels of production into the future. This is particularly important when one considers the historic main oilfields in production within that country. And of these the largest not yet covered is the offshore field at Safaniya, today's topic.

 Because of the change in well design, so that long horizontal wells, many with a number of lateral feeds, known collectively as Maximum Reservoir Contact (MRC) wells, located within the top 5 ft of the reservoir are now used, initial declines in production in the major fields have largely stopped. This is partially explained because as a vertical well through an oil reservoir sees the pool getting smaller, the length of well productively exposed to the oil in the reservoir reduces, and so there is a steady reduction in well performance over the years. Where the oil is, however, being pushed up to the horizontal well by an under-flood of injected water (which sustains the differential pressure between the fluid in the rock and the well bore) then the exposed length, and the driving pressure both remain relatively constant, and production is sustained at closer to a constant level until the water flood reaches the well, when the well dies.

 Aramco have changed the design of their MRC wells so that the arrival of water at one location along a lateral is no longer sufficient to kill the well. Installed valves isolate the region of the well where the water enters, and the rest of the well can remain in production. But it will produce at a reduced rate, and is an early warning that the water levels are nearing the well location, and that, before long, the well will no longer be able to sustain the x,000 bd production which has been the characteristic of most Saudi wells for over five decades. This is not to decry the efforts that have been made to recover residual oil left in those fields. As I have noted Aramco have been diligent in seeking to find additional ways to extract the oil that has been left as the waterfloods progressed through their senior fields. But they are also smart enough to know that alternate fields would have to be developed, and brought on line as the limits in the older fields are reached, as they now have been, in some cases for years. There is an interesting feature to the sources of production, back in 1994.
 
Figure 1 Saudi oil production, by field, in1994 (Matt Simmons, “Twilight in the Desert”)
   
Figure 2. Oilfields in Saudi Arabia (from Aramco via energy-pedia 


 The immediately obvious characteristic is that they are, at least to some degree (as with Berri) land-based. (Other less obvious differences are a change in the host rock and the quality of the oil). The most significant of the remaining four is Safaniya which came on line in 1951. But it was not, immediately, produced.

Aramco, in accordance with the terms of its concession, went ahead with the careful development of the field. Between 1951 and 1954, 17 wells were drilled, but they were not produced. . . . . . When it was first put in production in 1957, it flowed 50,000 barrels of crude oil a day from 18 wells. At the beginning of 1962 it possessed the facilities to handle 350,000 barrels a day (almost 128 million barrels a year) from 25 wells.

It was found to be the world’s largest offshore oilfield, and Matt Simmons has conjectured (in Twilight in the Desert) that it is connected to Khafji and through that field into Burgan. When Saudi oil production peaked in 1980/81 he notes that it was producing at over 1.5 mbd. Since then production fell to around 600 kbd, but then has increased back to 900 kbd with plans now afoot to bring it back up to full volume of earlier levels of production, which will require additional forms of artificial lift this being the electrical submersible pumps that have already been introduced into Ghawar. 


 The phase 1 upgrade at Safaniya is anticipated to be completed by next year. The oil is found in sandstone, rather than the carbonates at Ghawar, and in the original development Matt has noted that the weak nature of the sand was causing the wells to collapse as the oil was removed, and that the flow of water into the reservoirs was bypassing a lot of the oil being left in place. As other fields have been developed, they have largely been brought into production fairly quickly. This has not been the case at Safaniya, which as Matt noted:

. . .holds the entire remaining spare daily oil supply of any magnitude . .

In the sense that other fields and opportunities take a little time to bring on line this remains true.

 Manifa, for example, will only start to bring in significant production as the refineries to accept the oil are themselves brought on line in the years ahead. Yet it is still counted as part of the total volume that KSA can bring to the market. Safaniya had, however, been integrated with secondary development of the nearby fields of Marjan and Zuluft into a Northern Area Producing Region (NAPR) back in 1995 and there are enough wells and Gas Oil Separation Plants available, to be able to handle flows of up to 2 mbd. Because, however, the oil produced is Heavy (relative to the Arab Light classification of the production from the land-based reservoirs initially) Aramco also found it sometimes more difficult to market, though that demand also fluctuates. And it has been this marketing problem that sometimes seems to produce the headlines when Aramco sees a world that is increasingly demanding more oil, but has not always been willing to use this heavier supply as an immediate fill-in for existing shortages. (It could not, for example, provide an immediate replacement for Libyan oil last year, even though it was available). As a result the heavier oil is discounted against other Saudi oil. 

 At present the major effort offshore is going toward development of Manifa, which will ultimately bring an additional 900 kbd into production (staged to coincide with refinery construction) but as those wells come on stream (starting next year) so the effort will swing back to Safaniya, Marjan and the related fields of the NAPR. (And as an aside I had mentioned at the beginning of this series of posts there was some talk of bringing Damman back into production, and those talks are apparently still continuing). This additional production capability will, with the further development of some of the other fields in the region (which I will discuss next time) leaves me believing that, of the three largest oil producers, it will be Saudi Arabia that sustains its current levels of production (give or take 500 kbd) much longer than its two rivals. Though I would again stress the difference between production and export volumes.

OGPSS - Current oil production and the future of Ghawar

(Updated intro)There is a growing impression being given in the discussion of oil and natural gas supplies, that the world is moving into a period where there will soon be such a plentiful sufficiency of crude that the US may consider exporting some of its production. (h/t Leanan). But if one looks behind the headlines, and particularly at the current status of the largest oilfield contributing toward this rosy picture, the Ghawar field in Saudi Arabia, that optimism becomes more evidently built on a very transient set of data that, as this series of posts seeks to show, will not be sustainable for any significant period into the future.

 The three major oil producers (i.e. those producing more than 5 mbd each) are currently seeing surges in production as the world moves to an overall production of 90 mbd. The OPEC June Monthly Oil Market Report (MOMR) notes that this has brought Russia to 10.33 mbd in May, some 100 kbd over the same period in 2011; and Saudi Arabia is reported to have averaged 9.917 mbd in May, up 40 kbd over April. The United States is running at 6.236 Mbd of crude (from the EIA TWIP), while importing 9.117 mbd. The MOMR reports US oil supply at 9.66 mbd on average, but counts more than just crude in this value. The gain over the past year is around 600 kbd. It is interesting to note, in regard to OPEC production the continued difference between the volumes that OPEC reports from direct contact with the suppliers, and that when the numbers are obtained from “secondary sources.”
Figure 1. OPEC production from its members, with values provided by them (OPEC June MOMR)

 
Figure 2. OPEC production from information provided by secondary sources (OPEC June MOMR).

 This surge from the majors has, in part, led the EIA to project that oil prices will, for the remainder of the year, remain relatively stable.
 
Figure 3. EIA estimate of crude oil prices going forward over the next eighteen months (EIA TWIP)

 In the short term, and leading into a national election, there is no significant event (short of a hurricane or two) that obviously threatens this projection – though the Iranian situation and the questionable stability of nations in the Middle East and North Africa (MENA) has to remain a concern. But sadly the continued ill health of the global economy, with no evident savior or realistic plan for growth now visible, means that demand – which OPEC projects will still grow 1.17 mbd y-o-y on average this year, may continue to be met.

I have, however, in previous posts, given my reasons for anticipating that the surge in both Russian production and that in the United States are at near peak, and will soon decline. Saudi Arabia’s fall will be less dramatic and a little later, but the combination does not bode well for the international supply in the next presidential term. The big question with Saudi Arabian production has been, to date, more focused on the production from Ghawar, which at 5 mbd has been the rock on which the overall production builds. But that rock is continuously eroding under the long production periods that its different regions have seen. The final major new effort to bring new production on line in the overall field was the effort at Haradh, down in the South tip of the field.

 JoulesBurn has written comprehensively on this region, beginning with the first well that came into production. In 1979, as the late Matt Simmons pointed out in “Twilight in the Desert”, the three northern segments of Ghawar, Ain Dar, Shedgum and North Uthmaniyah were producing 4.2 mbd of the 5.3 mbd total Ghawar output, with South Uthmaniyah producing another 400 kbd. By 2006 North Uthmaniyah was running at a 46% water cut. Joules has taken the historic record for that region of the field and made a short movie presentation included in a post that shows how Uthmaniyah was developed over the years.
 
Figure 4. Single frame from the movie on drill site development in Uthmaniyah, over time (JoulesBurn)

 The sequence of wells, moving inexorably to the crest of the field, shows how the wells had to move as the underlying reservoir became more depleted in oil. Uthmaniyah is the region where the test program to inject carbon dioxide to enhance EOR is under construction, as mentioned earlier, and scheduled for completion in the fourth quarter of 2013. It is worth noting that Aramco are also planning on using more steam injection for enhanced oil recovery (EOR) and that plans have just been signed to increase steam production at the Ju’aymah, Shedgum and Uthmaniyah plants, with completion dates in 2014 and 2015.

Figure 5. Sectors of Ghawar with the date of discovery (Afifi )
As one moves south the quality of the reservoir changes, and becomes more difficult to produce. However as Greg Croft has noted the two lower segments of the field Hawiyah and Haradh were developed with horizontal wells, rather than the vertical wells further north in Ghawar. This has overcome some of the geological constraints and the fact that the productivity index drops from around 140 barrels of oil per day/psi to 45 BOPD/psi at Hawiyah, and 31 at Haradh. In 2008 the Hawiyah NGL recovery plant was commissioned, to yield 310 kbd of ethane and NGL. 

 The further development of the lowest segment of Ghawar, down at Haradh, was one of the major projects that Aramco listed as contributing to their ability to produce up to 12.5 mbd. The latest development built on earlier development and because the use of horizontal wells had transitioned into maximum reservoir contact (MRC) designs by the time of Haradh III reduced the anticipated number of wells from 280 verticals to 32 MRC wells.

  

Figure 6. Planned well layout in Haradh III (from Aramco via JoulesBurn) 

 In his initial review of how that developed JoulesBurn showed how the wells were developed and laid out and explained how he was able to use satellite images to determine the different components of the production equipment. It is relevant to note that Joules updated his view of the region in 2010 when he noted that, after looking at the satellite images of the region, he was able to show that instead of the production coming from the original 32 wells, there were actually some 52 production wells connected up, which – as he noted – raise a few questions as to the actual performance of the wells over the original projections. 

 Aramco have reported, however (pdf) using Real-Time Reserve Management, that it had by the summer of 2009, been more successful than anticipated. Some of the additional wells drilled were to allow cross-hole tomography (pdf) to monitor the location of the oil:water front which, as production evolved, did not follow the anticipated path. This was particularly important to establish given the 1 km spacing between wells and the more complex geology relative to that further north in Ghawar. 

 

Figure 7. Schematic showing how cross-hole tomography is carried out (Stephen Prenskey ) 

 

Figure 8. Image from Crosshole tomography at Haradh (out (Stephen Prenskey) 

 What is, however, also clear from looking at the different regions of Ghawar is that there are no places left for new programs to restore production as wells become exhausted. If KSA is to sustain its production it must look beyond the King of Oil Fields, who now lies stricken in years.

OGPSS - The potential for Saudi EOR

Without getting into the discussion of the other aspects of the site, it was interesting to read a post dealing with future oil production on “Watts Up with That” today, in which it is suggested that the forthcoming fall in Saudi oil production will presage the decline in overall global oil production. (The site has won the “Best Science” weblog award the past two years). The relevant quote is

The next big one to tip over into decline will be Saudi Arabia.

And, if you have been following this series, then you will understand the basis on which I make the observation that this is, in fact, incorrect. The site uses a plot by Euan (without the link) from back in 2007, though it is credited to 2008.

Figure 1, Euan’s production estimates from 2007.

 One of the reasons that I am writing the current OGPSS series is to see how the earlier estimates that we made “back when” are playing out, and, for reasons I have explained both in earlier posts and below, Saudi Arabia is likely still a couple of years away from peaking. No, (to finish the opening thought) the major player who will tip over first is much more likely to be Russia (of which I have written earlier) than the Kingdom of Saudi Arabia (KSA). Very simply Russian producers will likely soon yield back global production leadership to the KSA, (though presently still slightly ahead) and further, since they run on maximizing current production, rather than overall field yield, they are not doing the necessary steps to sustain future production which is a growing characteristic of the KSA operations.  There are a number of different examples to illustrate this, as I have documented earlier. In addition the KSA seems increasingly interested in developing the enhanced oil recovery (EOR) techniques that have helped other fields in the latter stages of their lives.

Figure 2. Enhanced Oil Recovery methods and production volumes (Saudi Aramco)

 As Aramco note, as the price of oil has risen, so the economic viability of EOR technologies covers a greater range of options.

Figure 3. Comparative volumes of oil available as the price (in 2008 US$) rises (Saudi Aramco )

 Traditional CO2 injection, for example, can enhance overall field production by perhaps 18% or more.

Figure 4. Traditional use of CO2 for EOR (DOE ) DOE notes

In WAG injection, water/CO2 injection ratios have ranged from 0.5 to 4.0 volumes of water per volume of CO2 at reservoir conditions. The sizes of the alternate slugs range from 0.1 percent to 2 percent of the reservoir pore volume. Cumulative injected CO2 volumes vary, but typically range between 15 and 30 percent of the hydrocarbon pore volume of the reservoir. Historically, the focus in CO2 enhanced oil recovery is to minimize the amount of CO2 that must be injected per incremental barrel of oil recovered, especially since CO2 injection is expensive. However, if carbon sequestration becomes a driver for CO2 EOR projects, the economics may begin to favor injecting larger volumes of CO2 per barrel of oil recovered, i.e., if the cost of the CO2 is low enough.

And how effective can it be? Consider this plot of production gains in the Wasson field in West Texas. 

Figure 5. Production gains from the injection of CO2 in the Wasson field of West Texas (DOE ) 

 Note that the DOE reported that in 2008 the industry was injecting 1.6 bcfd (billion cubic ft/day) into Permian Basin fields to produce 170 kbd of oil.

Figure 6. Sites of US Co2 injection projects as reported in 2010 (DOE )

 It is worth noting that the KSA initial site is being set up to inject 40 mcf/d (million cubic ft/day) some 2.5% of the US volume, into 7 wells in the initial pilot project, in Uthmaniyah so that the initial gain in KSA production may well be quite small, but there are additional CO2 sources in country which, should the pilot show to the gains potentially possible, can be tapped and which could significantly change the overall ultimate recovery of oil from Ghawar (and others). Further there is ongoing research into enhancing the performance of CO2 in EOR, that will likely pay off in the medium term.

 In regard to the SmartWater flooding the first field injections have been successful, and a full scale demonstration is now planned. The advantages for this change are considered to be:

• It can achieve higher ultimate oil recovery with minimal investment in current operations (this assumes that a water- flooding infrastructure is already in place). The advantage lies in avoiding extensive capital investment associated with conventional EOR methods, such as expenditure on new infrastructure and plants needed for injectants, new injection facilities, production and monitoring wells, changes in tubing and casing, for example 

• It can be applied during the early life cycle of the reservoir, unlike EOR. 

• The payback is faster, even with small incremental oil recovery.

A BP study (Lager, A., Webb, K.J. and Black, J.J.: “Impact of Brine Chemistry on Oil Recovery,” Paper A24, presented at the EAGE IOR Symposium, Cairo, Egypt, April 22-24, 2007. Also Strand, S., Austad, T., Puntervold, T., Høgnesen, E.J., Olsen. M. and Barstad, S.M.: “Smart Water for Oil Recovery from Fractured Limestone: A Preliminary Study,”) showed the following incremental gains over conventional water flooding.

Figure 7. Gains achieved by BP in changing salinity in recovery from different fields (Saudi Aramco ). 

 The current areas of investigation have extended into dealing with the tar mats that are present in parts of Ghawar.

Figure 8. A core of tar-bearing carbonate rock under attack by hydrochloric acid (Aramco Journal of Technology) 

 Current research is aimed at extending wormholes into the formation, through which it will be possible to pass different EOR treatments in order to further improve the extraction rate from the field. 

 When these current projects, in their various stages, are combined with the future production from Manifa, and enhanced production from Safaniyah, I expect that the Kingdom will continue to produce at around 10 mbd for at least a few years more, though I continue to doubt that it will be able to increase much beyond that. After all, even when field declines are held to 2% a year, after 50 years the arithmetic starts to take an increasing toll – Ghawar began production in 1951. And so, with respect, I disagree with David Archibald, if only in the short term - but for those of you with a few minutes, the comments that follow his post at WUWT are quite entertaining.