Fom the viewpoint of those who suggest that there is no problem, the discussion that swirls over the future of global oil supplies often seems to focus 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 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. As I noted last week, it is a point that clearly was missed by Leonardo Maugeri, and equally by George Monbiot, who has 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 1) the pressure differential between the well and the rock are sustained; 2) that the rock has an adequate permeability to ensure that flow continues at a steady state; 3) that the oil itself is of relatively low viscocity and is thus able to easily flow through the rock; and 4) 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 exploit to address the coming falls in production from the historic sources. These “best of the rest” (as the late Matt Simmons called them) must now increasingly carry the burden of sustaining Saudi production fail, individually, on differing grounds from meeting those earlier parameters. Collectively and in the face of Ghawar’s decline, they will only be able to sustain production to their original targets and will not 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.

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.”

Recent Tech Talks have focused on the increased use of novel technology in Saudi Arabia as a means of recovering oil stranded during the waterfloods that have successfully sustained production over the past few decades. That technology is further expanded with the use of carbon dioxide injection as part of an Enhanced Oil Recovery program. The CO2 project has been in the works for some years, with an initial estimate that some 40 million cubic feet of CO2 would be injected daily into flooded areas of the Ghawar field. The gas will come from the Uthmaniyah Injection Plant and will be initially injected into seven wells in the Uthmaniyah section of Ghawar. The initial flood will be monitored, since it is important to ensure that the CO2 finds the oil that it will help flow to production wells.

Aramco has also recently announced success with changing the make-up of the injection water being pumped into the fields to sustain pressure. By altering the ionic composition and salinity of this water, it has been possible to significantly increase the amount of oil that is liberated and thus recovered from the reservoirs.

Ghawar is sufficiently large that it has been divided into different segments, and the conditions vary between them. Because of the differences between the various regions, the overall statement that Ghawar is producing some 5 mbd has to be read with a degree of caution, lest it be presumed that this has continued to be from the same regions of the overall field. (And while this article deals with oil production, it should be noted that Ghawar also produces around 2.5 billion cubic feet (bcf) of natural gas a day.)

The very size of oil reservoirs in Saudi Arabia means that as the dominant method of water flooding is used to sweep oil to the producing wells, not all the oil in place migrates as hoped. Some remains in place and this makes up a very significant volume of possibly lost production. This is particularly true in reservoirs such as the Hanifa and Hadriya reservoirs at Berri, where water flooding since 1975 has largely obscured the field. Recognizing this problem, Aramco has increasingly used sophisticated mathematical models of various reservoirs to help locate these remaining pools, searching for oil volumes that could be successfully recovered.

As the models were increasingly able to divide the reservoir into smaller and smaller fractions over time, the presence of these pools became increasingly apparent. Definite proof of their existence then came through drilling. Here again, the change in technology in the use of horizontal wells has allowed the recovery of volumes of stranded oil from thin layers that would have been more difficult to recover had technology not advanced. The first test of this was at Berri where the field modeling was changed from a 14-layer to a 128-layer model, revealing accessible "lost" oil. Five wells were drilled into the region and all yielded oil for a total of 17.4 million barrels by 2007, when the wells were still producing. This capability has extended the life of the Berri field, capturing much of the oil that would otherwise have been lost.

One of the problems, however, in changing to the use of the horizontal wells has been that the well diameter is reduced and as a result the ability to do remedial work on those wells as required was limited at first. The three techniques that are now being aggressively used in these cases include acidizing, advanced hydraulic fracturing, and hydrojetting. And since this latter is an area in which I “wrote the book” and controlled crack growth demonstrations led to the only time I was picketed by a union, I thought I would spend today's post explaining a couple of these developments with fluid treatments, which aren't often as simple to apply as they may appear. Next time I'll finish up with some thoughts on improving hydraulic fracturing, and the possible benefits of using carbon dioxide as the fracking medium rather than other fluids.

The problem of scale in the pumping of fluids into the reservoirs and the flow of oil out is that the quantities 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.