OGPSS - Enhancing production at Berri

In the last post I discussed how changing technologies were improving the recovery of the final significant volumes of oil from Abqaiq. New technologies have also brought additional life to the Berri field, which lies north of Abqaiq, along the coast. Berri is/was the 22nd largest oil field in the world.

Figure 1. Location of the Berri oilfield. (JoulesBurn at The Oil Drum )

In the past Rembrandt has quoted the late Matt Simmons” “Twighlight in the Desert”, on the origins of the field and its future. The field was discovered in 1964, and the first wells to find the location of the producing reservoirs were drilled in 1967. The original estimate of the size of the reserves was made in 1978, at 8.3 billion barrels. In an earlier paper Matt had plotted the production from the field and showed that it peaked in 1976, at 800,000 bd, when water flooding under the reservoir was introduced to maintain reservoir pressure.

Figure 2. Early production from Berri (Matt Simmons)

This production came, however, from the Hanifa, Hadriya and Fadhili reservoirs since, at the time, the Arab horizons (A, B and C) had not been productive in this region, which has eight Jurassic age reservoirs. Since then, however, the Arab D horizon has been developed and is now in production. That reservoir is anticipated to contribute 25% to overall field production and to be able to sustain a relatively steady production of around 85 kbd (giving a total estimated production of around 350 kbd) for ten years, after which the reservoir will see a rapid decline in production.

Figure 3. Future estimates of production from the Arab D horizon at Berri (Jokhio et al)

One of the problems that arise when long-hole horizontal wells are used to drain a reservoir comes from the need to maintain a pressure differential between the well and the surrounding rock , so that oil will continue to flow into the well over time. Up to a certain point, the longer the well the greater the production, but beyond that point, as the drawdown pressure differential falls so production will also halt in the more distant part of the well.

Figure 4. Pressure drop and production with increasing horizontal well length (after Fischbuch et al ) (To fit the curves on one plot there is no scale on the vertical axis, but the production increased from 29 to 50 bpd/psi with the increase in length, and pressure values are discussed within the post).

In addition the geological factors in the upper reaches of reservoirs that are now smaller than when these fields were initially developed, means that the horizontal sections are often limited to around 4,000 ft in length. Nevertheless this length can still initially produce up to 4,000 bd per well. In the case of the Berri wells in the Arab D, the optimal length of each horizontal section was found to be 3,000 ft, based on geology. Further this requires that a ratio of 1.2 barrels of water be injected, for every barrel of oil removed to achieve the pressures needed.

As I noted last time, and as the above plot shows, as horizontal wells get longer it becomes more difficult to sustain that pressure differential at the back of the well, which may fall to the point that there is little additional production in the rear sections. Thus greater production can be achieved from a series of shorter laterals around the well, rather than from a single, longer well. Thus it is at Berri, where the new wells have been drilled to give Maximum Reservoir Contract (MCR) by using shorter laterals, rather than single longer wells that reach further into the formation. (However, because of the geology, these are driven as separate sidetracks from the main well, rather than as laterals from a single main horizontal well).

Figure 5. Structure map showing the well layout at Berri (Jokhio et al )

There is an additional snag that arises, because of the pressure drop problem, and that is that Aramco are using valving systems to isolate individual segments of the well. This is done to protect the rest of the well from premature water breakthrough in any one section, but each of those valves also creates a resistance that diminishes the available pressure drop beyond the valve. As a result only a limited number of valves can be used in a well, and this in turn limits the number of divisions that the well can be broken into. This is a particular problem for the Arab D reservoir since, as I noted in an earlier post, this carbonate is permeated with thin, high permeability paths that can, if not isolated or treated, lead to premature watering out of the wells. (One such horizon has been identified at Berri near the top of the field and was cased to isolate it from the well).

Seven production wells were initially drilled into the reservoir in developing the Arab D, but modeling of the reservoir suggested that the wells would rapidly fall in production, due to the inability to sustain production pressure, even with perimeter water flooding. There have been two solutions proposed for this, both of which involve the use of down-hole electric submersible pumps (ESPs). The first was to install these in the wells, to help with pumping out the oil, while the more recent study has been to see if using these pumps to increase water flow into the reservoir can help sustain production.

Figure 6. Components of a down-hole electric submersible pump (Aramco )

While the hope with the water injection pumps are that they will be able to draw water from overlying underground water reservoirs and use these as a water source, nevertheless in 2009 Aramco laid new pipes to carry more water to Berri and to remove the oil that it helped produce. (The new injection well array requires some 10,000 – 12,000 bd of water injection.)

Calculations had shown that a drop of 300 psi within a well would be sufficient to drop oil inflow to zero and that this would occur within two years of bringing the reservoir on line. ESPs were therefore installed in each of the seven wells, and when brought on line were able to sustain production at a level of 70 kbd, which was above the anticipated value.

The more recent work to install an inverted down-hole ESP to draw water from the Wasia aquifer and inject it into the Arab D has been in service since December 2008, and has shown an improvement in the pressure in adjacent wells.

Figure 7. Location of the sub-surface ESP injection well (Jokhio et al )

Figure 8. Location of the monitoring wells for the water injection (Shinaiber et al )

Figure 9. Monitoring well response to the use of a down-hole ESP ( Shinaiber et al)

This improvement in technology may well provide, as it allows production from reservoirs otherwise un-developable, some answer to the questions that, for example, Jud has raised over the long-term viability of the field.

While the development of the Arab D does give a boost to the production at Berri, it should be remembered that this post has only discussed how “new” reservoir development has, for the next decade, provided for 25% of Berri production, and does not address the production from the main reservoirs of the field.

OGPSS - The change in well design at Abqaiq

Current figures suggest that world liquid fuels production is running at around 90 mbd, of which roughly 74 mbd is crude. A reasonable estimate of the decline in existing well production each year lies at around 5%, so that each year new sources of oil must be brought on line that will generate 5% of 74 mbd or 3.7 mbd to cover these declines. In addition to that need, if world oil markets continue to grow as expected then an additional roughly 1 mbd of new production is going to have to be added this year to meet the growth in demand. (China imported 5.95 mbd in February, and though this dropped to 5.55 mbd in March this is still up 8.7% on March last year.) This state of affairs does not include the fall-out from political actions, such as the embargo on Iranian oil, which, in taking that production out of the market, imposes additional demands on the rest of the global suppliers of crude. As Econbrowser has just noted, the countries that are potentially capable of upping production to meet the size of this total additional demand likely foreseeable for this year seem singularly limited to a kingdom whose initials are KSA.

There is no doubt that Saudi Arabia has considerable oil assets, though I have noted in the past that they tend to use the total discovered oil volume as their reserve, without discounting the amount that they have already produced. Rather the question that will increasingly arise in the future is as to whether the country can continue to produce at the same rate, or – if they are to meet the claimed 12.5 mbd of achievable production - to be able to achieve a rate that is 25% higher than that of current levels. Not that the amount available from some of the older fields is not of some concern. Consider this plot that came from Aramco in 2004, when Mahmound Abdul Baqi and Nansen Saleri debated Matt Simmons at CSIS. And remember that production has continued from those fields in the eight years since.

Extent of Proved Reserves Depletion in Select Fields (Baqi and Saleri, 2004)

In the post last week (and my apologies to Glenn Morton for unintentionally confusing him with Greg Croft at the beginning of that piece) I pointed out that there are a significant number of rock layers under the surface in the country that contain oil. Now not all of them do this very consistently, but, as the example with Abqaiq showed, as the original oil reservoir becomes depleted so other rock layers can be tapped to produce in their turn.

However the story with Abqaiq shows the difficulty, as fields reach the end of their life, in being able to sustain production, and the increasing costs that must be incurred to do so.

In the early life of the field wells were vertical, relatively inexpensive, and produced for decades. Now it is only advances in technology that allow production to remain at high levels. The original vertical wells have been sidetracked so that a horizontal section is established in the top 10-ft of the reservoir.

Initial sidetrack from an original vertical well in Abqaiq (Abduldayem et al)

However, to reduce costs and improve production (which stalls at a certain production level as an individual horizontal well gets longer) Aramco has changed to the use of Maximum Reservoir Contact wells (MRC). These initially started out as being a series of laterals drilled out from the main horizontal well, so that, although the distance from the vertical remained quite short for each segment, the overall exposure of the well to the formation could reach, in this case, some 12 km.

Initial MRC pattern of laterals used at Shaybah (Baqi and Saleri, 2004)

However with the laterals laid out in this manner alone, the entire layout become vulnerable if there was premature water breakthrough in any of the laterals. The initial test at Abqaiq, for example, watered out in six months. A second test with five laterals to give a total reservoir contact of 6.9 km produced initially at 19,000 bd and lasted for two years..

First MRC well at Abqaiq (Sung et al )

To prevent water penetration into individual lateral having a fatal result on the whole well, a series of small valves was interposed at the entry to each lateral, so that it could be bypassed, if flooded, without impacting the rest of the well.

Flow control of laterals at Abqaiq (Abduldayem et al)

The life of each well is limited, since, as I noted last time, these technologies were introduced as the water flood reached close to the top of the reservoir, and the remaining oil (sometimes referred to as ‘Attic” oil) is thinner in depth and underlain by varying heights of water column.

Saturation log over the full height of the original oil in the main reservoir at Abqaiq taken in 2007 (Lyngra et al)

By 2008 some 30% of the field production was coming from these attic wells, with 71% of that coming from 15 medium radius horizontals, 1 MRC well and 15 MRC wells with smart completions. In 2009 the program had 98 km of reservoir contact. (Lyngra et al). The more recent innovation has been to switch to a segmented slim smart completion product (SSC) with a more sophisticated valving system.

The SSC system consists of three major components:
1. Downhole hydraulic flow control valves: Three downhole valves were run. These valves provide the necessary controls to choke/shut-in laterals.

2. Permanent downhole pressure and temperature gauges: These provide important real-time data used for optimization of the well production. After production start up, individual lateral production tests are performed to determine the Productivity Index (PI) and reservoir pressure for each lateral. This information is used with flow modeling software to determine the optimum flow control setting for each valve to achieve the desired rate from each lateral.

3. Open hole packers: These are utilized to hydraulically isolate and compartmentalize the three laterals. The packer is a hydraulically set, open hole packer with a high expansion solid rubber element capable of setting and sealing in washouts up to 21⁄2” higher than the run- in Outer Diameter (OD) of the completion string. The packers were set in anhydrite sections to ensure complete isolation from the other laterals. The proposed packer depths were confirmed suitable by the four-arm caliper log at gauge hole intervals.

The advantage of the SSC completion is that with valves down the laterals, it can be divided into segments and thus water inflow in one section of the lateral does not shut down the whole lateral.

SSC completion valve layout in well C – (Lyngra et al)

Lyngra et al note that for best success the laterals should be located in the 3-10 ft thick upper lobe of the attic oil zone, with entry being through side-tracks from wells that have been otherwise defined as dead. Life of the wells will still, however remain limited, due to the fact that this is the very last of the trapped oil that is now being recovered from Abqaiq, and then it will be over. Some of the initial wells watered out within six months.

But the technology has proved beneficial, already, in extending the life of not only Abqaiq, but also of the reservoirs in the nearby Berri field. Back in 2004 Baqi and Saleri noted that this field had the highest depletion rate of the major fields in the kingdom.

Depletion rates for different fields in KSA when compared with other major fields. The rate is given as a percentage of the original proven reserves in the field (Baqi and Saleri, 2004)

Note that these rates were reported in 2004, and that the fields have shrunk a little in size over the past eight years, so that, at a relatively constant draw-down of the oil, so the amount that is removed becomes an increasingly large fraction of that remaining, and the lifetime of the wells and now the field, shrinks accordingly.

As I just commented it is the evolution of this technology which has provided new life to Berri, but given the length of this post already, I will postpone that discussion until next time.

P.S. Although the representations of the wells shown above are relatively straight and have a smooth path, the reality is not quite that simple. Sung et al have shown the reality of the first five-lateral MRC well paths in their paper.

The actual lateral paths from the Abqaiq well, shown using a GeoMorph model (Sung et al).

OGPSS - Production from Abqaiq, an Ageing Queen

The topic of rising gas prices is pervasive, and at a breakfast meeting last Monday Richard Williams, a friend commented that he had seen some cores from Saudi Arabia, and they looked so weak that he felt he could put his fist through them. It reminded me of a passage that Glenn Morton had also caught in Ken Deffeyes book “Hubbert’s Peak”:

Most massive and nonporous limestones contain textures made by invertebrate animals that ingest sediment and turn out fecal pellets. Usually, the pellets get squished into the mud. Rarely do the fecal pellets themselves form a porous sedimentary rock. In the 1970s the first native-born Saudi to earn a doctorate in petroleum geology arrived for a year of work at Princeton. I used the occasion to twist Aramco’s collective arm for samples from the supergiant Ghawar field. As soon as the samples were ready, I made an appointment with our Saudi visitor to examine the samples together using petrographic microscopes. That morning, I was really excited. Examining the reservoir rock of the world’s biggest oil field was for me a thrill bigger than climbing Mount Everest. A small part of the reservoir was dolomite, but most of it turned out to be a fecal-pellet limestone. I had to go home that evening and explain to my family that the reservoir rock in the world’s biggest oil field was made of shit.

Such it may be, but it has supplied a form of liquid gold to the world for the past 50-years. Ali Naimi, the Minister for Petroleum and Mineral Resources in Saudi Arabia had an article in the Financial Times in which he re-iterated that the kingdom can produce some 12.5 mbd, and that it thus has more than enough in reserve to meet any supply shock that might be reasonably foreseeable at present. (There was a time when Texas was in the same position, and proved its capacity on occasion, before it lost it). There are times when the true size of the Saudi reserve is not fully recognized, as the late Matt Simmons noted in his early presentations on the subject.

Some of the reservoir rocks found in Saudi Arabia (there are over 300 recognized reservoirs) (Matt Simmons at the CSIS meeting, Feb 2003)

In writing of the oil production from the most active drilling sites in the United States, the last post noted that there are thousands of wells being drilled in the Bakken and Eagle Ford regions and that they average less than 100 bd of production. Consider that there are about 100 rigs in Saudi Arabia, and that in 2010 they drilled some 386 wells, in a country that had a total of 2,880 producing wells in 2010 (not counting the 527 wells in the Saudi:Kuwait Neutral Zone). (And in perspective there are roughly a million producing wells around the world). Those wells produced roughly 8.1 mbd on average in 2010, or an average of 2,800 barrels a day. (OPEC Annual Statistical Review 2010:2011).

However even the most massive of reservoirs must, over time, begin to run out of crude, and that has, for some time, been an area of concern, particularly in the older fields perhaps best exemplified by the adjacent fields of Abqaiq and Ghawar. The first well at Abqaiq was spudded in August 1940, not that much later than the first oil wells at Dammam. At that time the company now known as Aramco had 3,229 Saudi employees, 363 Americans and 121 other nationalities working to produce some 15 kbd.

Location of Abqaiq relative to Dammam – the red line (derived from Joules Burn’s post) shows roughly the center-line and linear extent of the field.

The EIA reported in their last Country Analysis brief that in 2010 Abqaiq was still producing at 400,000 bd, but that the available reserves for the field had been depleted by 74%. Times have changed from those early days however, and (as the late Matt Simmons noted in 2008) all the 40,000 to 60,000 bd wells that existed in Abqaiq have long stopped producing at that rate and the average has fallen by an order of magnitude.

Historic production from Abqaiq including water cut (Abduldayem et al)

I am going to append an abbreviated and slightly modified description that I gave in an earlier post at this point, because in the next couple of posts understanding a little of the technology is going to be helpful. It begins with a simple model, and does not get very complicated.
. . . . . . .
Assume that there is a layer of rock that is 300 ft thick, five miles wide and thirty miles long. This has, over time, been folded in the middle, so that it now has trapped oil within all the pores of the rock. And, for the sake of discussion let's assume that it has a porosity of 20%. This gives a very rough initial approximation to the conditions of the Arab D horizons at Abqaiq.

Doing the arithmetic - 300 x 5 x 5280 x 30 x 5280 = 1,254,528,000,000 cu.ft. At 20% porosity, this means that some 250,905,600,000 cu. ft. are not rock, and in this case are going to be full of fluid. This is equivalent to 1,876,773,888,000 gallons or 44,685,092,571 barrels of oil. This is, roughly 45 billion barrels of oil. That's how much is there, or the oil initially in place. (We're neglecting, for now any water that is also in the rock).

This is a relatively light oil (API gravity 37 deg) and flows through the cracks in the rock quite easily, and there are a lot of these fractures, and it doesn't stick to the rock that tightly, so the assumption is made that production can get out some 50% of the original oil in place. So, at this point we can say that the ultimate resource recovery (URR) is going to be 22.5 billion barrels.

When production began vertical wells were drilled a quarter of a mile apart. Consider therefore a one-quarter-mile section of the reservoir, taken along the length. If the slice is 5 miles long, then it has 20 wells set along the section, so that each well will pull the oil out of a box that extends out one eighth of a mile laterally from the well, out toward the next. The total recoverable oil for each well is roughly 10 million barrels, or 30,000 barrels per foot of the oil well in the reservoir.

Showing location of wells quarter-mile apart and in a quarter-mile thick slice along the reservoir. The rock thickness is exaggerated and this is not to scale.

The rate at which the oil flows into the well is related to the difference in pressure between the oil in the rock, and the fluid in the well; the frictional resistance of the rock to the oil flow through it; and the length of the well that is exposed to the rock. Let us assume that the rock resistance remains the same and that production varies directly with changes in the pressure difference and the length of the exposure. And let us start by assuming that the well produces 3,000 barrels of oil a day. (i.e. 10 barrels per foot of well exposed to the rock). Then, in the course of a year the well will produce one million barrels of oil.

After production begins however the volume coming out of the well will, if nothing else is done, begin to decline. This is because, as the oil leaves the reservoir, so the pressure on the oil reduces, and with a lower driving force the flow slows down. To counteract the loss in pressure through the fluid loss, water can be added to the reservoir. This was initially achieved by adding water wells around individual production wells, but this was later changed so that the water is, instead, fed to wells around the perimeter of the field. Joules Burn showed how these were laid out at Abqaiq in an earlier post.

Water injection wells (blue) around the perimeter of Abqaiq, with production wells in red and green. (Joules Burn )

If the water enters the reservoir beneath the oil, then it will fill holes left as the oil leaves, and maintain pressure in the oil, and the oil flow will not drop as fast, and production rates will increase (Note that when this was done at Berri it took a field that was producing at 155 kbd in 1971 and raised production to 800 kbd in 1976 when production peaked).

Initial pattern of water flood, adjacent wells flood under the producing central well

Production per well will not, however, return to peak values, and it will continue to decline with time. To explain why return to the model calculation. If 4 million barrels has been removed from the well, then as the water fills the void left beneath the oil and compresses the fluid back to the original pressure (we're neglecting the gas issue for now) it will now only occupy 60% of the original space, or the top 180 ft of the reservoir. With the same driving pressure we will now only get 60% of our original flow, because the length of the well exposed to the rock has been reduced (and flow is related to length and pressure).

This decline in production will continue each year since the flow will decline as the length of exposed well in the rock gets smaller, with the water rising up behind the oil. For example, assume that in the next year the well will produce at 1,800 bd,(10 barrels/day/ft) then at the end of that year it will have delivered (simplifying) 650,000 bd of oil, and so the volume of oil will be reduced by (roughly) 11% of the 6 million barrels that were left, and so the following year the production will come from only 160 ft of the reservoir, and, at the same reservoir pressure, the flow will be reduced because of the shorter exposed length. And the flow will be, accordingly also reduced by 11%, assuming that the overall area remains the same. (Some folks might call this depletion, it is the decline in production with time).

One of the reasons that this is a simplified explanation is that the water does not fully displace the oil, but only some of it, and thus there will be some oil left that can be recovered later in the process. This can be illustrated by looking at open hole (OH) well logs from a survey done in the region which shows the relative quantities of oil, (red) and water (blue) over the reservoir column before and after the water flood - the well was shut-in prior to 2007.

Open hole surveys of a water-flooded well, before and and after production, showing, as a function of depth the relative oil (red) and water(blue) content. (Mark Ma et al )

There are ways in which the relative penetration of the water through the formation can be controlled, so that more of the oil is initially moved and less is left in place. This requires detailed knowledge of the reservoir and knowing where zones of high permeability exist that can, otherwise, allow water to bypass oil. (These are the Super K layers shown below, as well as the fractures).

Reservoir characterization (Saudi Aramco via Matt Simmons 040224)

In order to overcome the problem of declining production over time, as the water flood rises up the well, the alternative (which has not been around that long) is to drill the wells horizontally. These wells can be drilled over the full two-and-a-quarter miles from the center out to the edge of the reservoir and just two would have the same exposed length in the reservoir as forty of the original wells. Now the exposed length to the oil stays the same, and at a constant pressure (held through water injection) production from the horizontal wells may reach 18,000 barrels of oil a day.

Water flood under horizontal wells, in this ideal case the water is fed from the outside of the reservoir and rises as a steady horizontal lift over time - until it reaches the wells.

When horizontal wells were introduced (1992) the field had already been in production for decades. Thus, while horizontal well technology allowed some gain in daily production, the rate of oil removal still had to be controlled, in order to maximize overall total recovery. And thus, from time to time, the field was “rested.” In addition, over the years, smart well technology has been introduced, with isolating valves located along the horizontal section of the well, so that should water break through at one section of the well this can be shut off from the rest of the well, which can continue to produce.

As the technology improved, over the life of the field, was found in an additional mile of rock to either side of the zone that had been initially identified and the field extended about 7 miles longer than originally anticipated. However, with the new additions and as the field finally began to play out it turned out that the average thickness of the carbonate grainstone was only 240 ft. Repeating the calculation changes the estimate of the original oil in place to be some 62 billion barrels. This change in reserves as the field is developed is not uncommon in oil fields and is one of the ways in which reserves grow, often quite significantly after the field has started to be developed.

(The above exemplary numbers other than the geometric size of the field, and its porosity and depth were invented to illustrate the developments of the technology that have been applied to that field). The oil has a 36deg API, with a gas/oil ratio of 860 cf/barrel. (It is also sour). The rock permeability is 400 millidarcies in the Arab D formation (this info is from "Twilight").

The first well at Abqaiq was spudded in August 1940. It began production at 9,720 bd in October 1940, but had to be temporarily shut-in the following February because of the adjacent war. Early development was slow, but began to pick up as the conflict moved further away.

If the expansion of 1936 had struck some of them as a period of hectic confusion, this 1944 expansion struck them as bedlam. Their goal by the end of 1945, they were told from San Francisco, was 550,000 barrels a day, nearly 25 times what they were turning out now in their standby operation, and much more than the capacity of their existing wells. There would have to be a massive drilling program involving perhaps 20 strings of tools, and drilling that many oil wells meant developing adequate water supplies both at Abqaiq and at Qatif, where they had been instructed to put down a wildcat. . . . . . . . By June 13th, too, Phil McConnell had entirely shut down the Abqaiq field after completing No. 5, and had diverted his entire Drilling Department to Ras Tanura.

By 1962 only 72 wells had been drilled in the field. At the same time the gas was being extracted with the oil, and 50% of it was being used. Most of it was pumped back underground to maintain pressure and in some cases it was mixed with LPG (Liquefied petroleum gas) and this helped dilute and increase the flow of oil from the reservoir. (But sometimes it did not work). It was used in the Ain Dar part of the Ghawar field and right next door to Abqaiq. But in 1982 the gas was collected for sale abroad.

By 1972 Aramco was drilling a well at the rate of 1 every 2.1 days. Shortly thereafter Abqaiq peaked, at 1,094,062 bd. In the area of Abqaiq there were 4 drilling rigs and 5 workover drigs in the period around 1977, as the field fell back to a production of less than 800,000 bd. By 1981 production was down to 652,000 bd In the mid-80's it was partially shut-in, and flow was reduced to 200,000 bd as demand declined.

And while the rest of Saudi production continued to grow, in 1988 it had 550 wells in production, by 1990 Abqaig had only 47 flowing wells, and by 2002 had dropped to 500,000 bd. Abqaiq is currently 73% depleted, according to Aramco in 2004 and 74% according to the EIA . Horizontal wells were introduced in 1992, and maximum reservoir contact (MRC) wells with 15,000 ft of contact have been extensively used. Since 2004 Aramco have also gone back into “dead” wells with perhaps 10 ft of remaining oil and run short laterals (up to 1,000 ft long) across the top of the reservoir to gain that additional production. These typically produced around 1,000 bd for 6 months before water breakthrough. By combining those into MRC layouts production could be increased to 4-5,000 bd and held for a year before watering out.

Now beyond this point there are some conflicting numbers. Let me just list some of the information that is out there.

In the 50 years since discovery it yielded 7.5 billion barrels of oil.

Abqaiq production history from Saleri via Joules Burn

The EIA considers that Abqaiq has 17 billion barrels of proven reserves. This is in contrast with the recent "World Energy Outlook 2005", which projected (through 2004) that Abqaiq had 5.5 billion barrels remaining and had produced some 13 billion. (But it got the start date wrong as well). It uses IHS data for its projections.

From that data, quoted by Jean Laherrere, one can estimate the total oil contained in the field. Using their anticipated total of 19 billion barrels, and that this is considered to have a recovery factor of 60% indicates that the overall oil in place is about 31 billion barrels. This is about half of the theoretical prediction I had made, using total volume and porosity, but given the variations in geology over the region, that the field has about 50% of the oil that the general assumption predicted is not bad.

However using the Aramco statement that the field is 73% depleted implies that the total oil that can be recovered from the field is around 11 - 12 billion barrels, which is in line with an HL projection created by Jean Laherrere.

Production for Abqaiq (Jean Laherrere )

The above presentation also assumes only production from the upper (Arab D) reservoirs available at Abqaiq. Joules Burn has, however, carried out a detailed analysis looking at additional production that can be achieved from the underlying Hanifa reservoir, which is 450 ft lower, and is some 300 ft thick and has a higher porosity (perhaps 30%). Unfortunately, as he points out, the permeability of the rock is much poorer than that of the Arab D, and thus production has not been as easy from the reservoir, nor can as high an overall yield be anticipated.

Nevertheless this explains why production levels of up to 434,000 bd can be achieved. However will there is a considerable oil resource in the lower reservoir, it is not as extensive as the Arab D.

Relative size and position of the Hanifa reservoir under the Arab D at Abqaiq (Abdulayem et al )

Production from the Hanifa reservoir began in 1954 and was limited since, with a matrix permeability of only 1-2 millidarcies much of the flow relies on fractures in the rock for production. (The Arab D has a permeability of some 400 millidarcies). Fractures do extend between the two reservoirs and so there has also been some migration of oil up into the overlying reservoir.

As the field has aged there is some problem in achieving enough pressure in the center (crest) of the field when the water is being injected only at the perimeter. Thus, as the field now enters the latter stages of production, a novel solution to extracting the oil has been tested. It is referred to as a SmartWell technology and simplistically uses the gas in the gas cap, as it enters the well through a choked valve, to create enough suction in the well as to draw the underlying oil into the lower section of the well, and thence be taken, with the gas, to the surface.

Relative size of the Hanifa reservoir under Abqaiq (Al-Otaibi et al )

The gas enters the well through side vents and a constriction in the well (the collar) which generates the suction needed.

The use of the gas cap to power production from the Hanifa at Abqaiq (Al-Otaibi et al )

While the idea is ingenious the use of the gas cap to draw out the remaining oil from the field does suggest that the age of Abqaiq is coming to a close. Aramco have recently stated that, using EOR they anticipate they may get up to 80% of the recoverable oil, although they are now running at 40% water cut. By 2006 some 60% of the oil initially in place (OIIP) had been produced. Joules’ post goes into more detail on the field with a greater discussion of the well patterns and what they mean.