GHAWAR: an estimate of remaining oil reserves and production decline (Part 1 - background and methodology)

A two dimensional (2D) volumetric reservoir model has been developed for the Ghawar oil field in Saudi Arabia which is the world’s largest field producing over 5 million barrels of oil per day. This represents 6% of global oil supplies. Understanding the current status of this super giant is central to the peak oil debate and to understanding the security of future global energy supplies.

This article was too large for a single post and has been split in two. Part 2 - "The Results" will follow very shortly.

Stuart Staniford has been working independently on the same problem and will post his results next week.


Stuart Staniford (SS) has led a very lively debate about Saudi Arabian oil supplies on the TOD in recent weeks. Stuart (who now has 6 posts on the subject) has adopted a position describing a current crisis in Saudi oil supplies. I have adopted a counter position of “business as usual” in the Saudi oil industry. To date I only have two posts on the subject and this article in part is intended to lay out my views in more detail. A list of all recent Saudi posts on TOD is given at the end of this article (at the end of Parts 1 and 2).

Saudi Arabia, together with most other Middle East (ME) OPEC countries are secretive about their oil resources and this tends to obscure the actual position on their reserves and their productive capacity. The main issue with ME OPEC reserves estimates is that they were substantially raised in the 1980s, and since then reserves have not been declined for annual production (Figure 1). Neither of these practices should be acceptable to analysts based in the OECD.

Publication of Twilight in the Desert, authored by merchant banker Matthew Simmons caused quite a stir in Saudi Aramco, the state owned Saudi oil company. Simmons described a Saudi oil industry teetering on the brink of decline and raised concerns about the impact of falling Saudi oil production upon the Global economy. This seems to have prompted Aramco to release more data, so much in fact that it is now possible to make this independent assessment of the oil reserves remaining in Ghawar.

Figure 1. Saudi Arabian oil reserves since 1980 (BP statistical review) show a sharp rise in 1988 and since then reserves have not been properly adjusted for production, discoveries or revisions (the flat blue line). Since 1980, the red line tracks reserves decline for production (BP statistical review) pointing to a current figure of around 95 billion barrels (2005, not adjusted for revisions and discoveries). Prior to 1980, Saudi Aramco was still part owned by American companies and the 1980 reserves figure, therefore, is probably the most objective figure available. Between 1973 and 1980, there was a rolling program of nationalisation of oil resources in Saudi Arabia.

The red line has been extrapolated back from 1980 to 1936 using SPE centennial data (1936 to 1965) and BP data from 1965 to 1980. This points to an initial Saudi reserve figure of 211 billion barrels, not adjusted for revisions and discoveries made since 1980.


Ghawar, located close to the Arabian Gulf coast of Saudi Arabia is the largest oil field in the world (Figure 2). At 164 miles long and about 16 miles wide, it is difficult even for experienced geologists to comprehend the size of this colossal structure (Figure 3).

Figure 2. The location of Ghawar in eastern Saudi Arabia showing main geological faults. This map contains latitude markers that point to the field being 162 miles long (SS). Map Source Total Petroleum Systems of the Paleozoic and Jurassic, Greater Ghawar Uplift and Adjoining Provinces of Central Saudi Arabia and Northern Arabian-Persian Gulf. (large pdf).

Figure 3. Map comparing Ghawar to major North Sea oil and gas fields. Most North Sea fields have higher porosity than Ghawar, and many have stacked reservoirs (e.g. Brent Group lying above Statfjord Formation). Therefore, areal extent is not the only guide to reserves. But the scale of Ghawar is still immense. Note how the undrained crests of N and S Ain Dar are still comparable in area to giant North Sea fields. North Sea base map grabbed from PESGB Millennium atlas.

The main oil bearing reservoir in Ghawar is the upper Jurassic Arab D limestone. This is of the order 250 to 300 ft thick and the depositional facies (geological type) of limestone varies both vertically and laterally across the structure (Fig 4). Superimposed upon this depositional variance is a network of fractures and combined these features influence the productivity and production problems from one area to the next.

Figure 4. Stratigraphic section for the Arab D. The reservoir comprises those beds with significant porosity and permeability. Reservoir beds are separated from each other by low porosity / permeability beds that are non-reservoir (Saner and Sahin (1999) Lithological and Zonal Porosity-Permeability Distributions in the Arab-D Reservoir, Uthmaniyah Field, Saudi Arabia. AAPG Bulletin v83, p230-243).

Zone 1 is transitional between reservoir limestone and the anhydrite (calcium sulphate) top seal and has poor / non-reservoir qualities. The reservoir section in this well is around 250 feet thick and divided into zones 2A, 2B, 3A and 3B. Note how the upper section, Zone2, has significantly better reservoir quality than the underlying Zone 3.

Greg Croft provides average net reservoir thickness values. These net thicknesses are presumed to be for the producible reservoir and not for the gross Arab D section.

The gross thickness of the reservoir is small compared to the scale of the structure and in the various 3D renderings of Ghawar (e.g. Figure 5) the reservoir should be viewed as a thin skin coating the surface of the structure.

Ghawar may be sub-divided into 6 main production areas defined by structural closures (structural relief) and reservoir properties. From north to south (Figure 5):

North ‘Ain Dar
South ‘Ain Dar

In general terms, reservoir quality and hence productivity decreases from north to south. The key parameter that varies is permeability – 700 mD average in the north, 100 mD average in the south. As we shall see, the highly productive north will shortly be fully depleted and most of the remaining reserves are in the south and this will inevitably mean lower production rates during the final chapter of Ghawar’s history.

Figure 5. The "Linux" map showing oil saturations in Ghawar (hat tip Bob Shaw). The blue areas are interpreted to represent dry oil at the top of Arab D Zone 2. The yellow areas are interpreted to be swept, water wet at the top of Arab D Zone 2. The effects of 50+ years production in northern Ghawar are there for everyone to see (Linux Clusters driving step changes in interpretation simulation. (pdf).

Transferring the data from this 3D image onto the 2D Croft map is subject to considerable uncertainty. On the large scale, the Linux map illustrates gravitational equilibrium, i.e. the undrained areas lie in the structure highs. However, on the smaller scale there is evidence for gravitational dis-equilibrium with areas of water lying above areas of oil on the flanks of Shedgum and S Ain Dar. This may reflect local geology, faults, Super K zones and variations in reservoir quality etc.

In transferring the Linux data into 2D I have in many cases simply contoured unswept areas – presuming overall gravitational control. Note the presence of oil in the saddle between Shedgum and S Ain Dar.

The date of this image is uncertain. It was published in 2006 and refers to a simulation run in 2004. It is possible, however, that the data used pre-dates 2004 which may be significant with respect to any debate about the timing of production decline.

Ghawar has been developed using a large number of oil production and water injection wells (Figure 6). The principal reason for injecting water is to maintain reservoir pressure above bubble point. Formation of secondary gas caps in N and S ‘Ain Dar are most likely due to re-injection of produced gas.

The principal production problem in Ghawar is premature water break through whereby seawater injected down the flanks is prematurely conducted to production wells up the flanks via fracture networks. This creates a variety of problems discussed later in this article.

Figure 6. Map showing the distribution of water injection wells (blue) production wells (black) and gas injection wells (red). (Source is Voelker, J. PhD thesis 2004). The small number of wells in southern Haradh suggests this map pre-dates the Haradh II and III GOSP developments (Figure 5), which came on stream 2003 and 2006 respectively.

Note that Hawiyah has been fully developed along the flanks, presumably using vertical wells and this ties in with OWC movement observed in Figure 5. It is also worth noting that that the tongue of oil in Uthmaniyah (Figure 5) lies in an area that lacks wells on this map. The crest of Shedgum and S Ain Dar and the ridge axis of Hawiyah and Haradh are essentially undrilled.

Data sources

The main data sources used in compiling the reserves estimates and production model are:

Greg Croft Inc web site

Linux super cluster 3D rendering of produced zones (pdf)

Water Management in North 'Ain Dar, Saudi Arabia, SPE 93439, March 2005.

Water Production Management Strategies in North Uthmaniyah Area, Saudi Arabia, SPE 98847, June 2006.

Optimizing Maximum Reservoir Contact Wells: Application to Saudi Arabian Reservoirs, SPE 10395, Nov 2005.

A large number of ancillary data sources have also been used.

Greg Croft provides a contoured map of the Ghawar structure that dates from 1959. This map provides a scaled area of the structure. Croft also provides average net reservoir thickness and petrophysical data for the reservoir in the various producing regions, described below, including average porosity and formation volume factor. All this information is used in compiling the reserves estimates and it is therefore assumed that the information is broadly reliable. Croft’s map would appear to be based upon a map published by “Arabian American Oil Company Staff” in the Bulletin of The American Association of Petroleum Geologists; vol 43, no 2, 1959 (Figure 7). This map, is produced by company professionals, is published in a reputable journal, but is inevitably based on old and perhaps out dated data.

Figure 7. The Arabian-American map of Ghawar dating from 1959. The contour map looks like it is the base map used by Croft and has a better scale bar. Measuring four easily identifiable dimensions on this map gave the exact same lengths as Croft’s map indicating that the scale bars on these two maps are compatible with each other – but both may be wrong. Note that Arabian American Oil Company was the predecessor to Saudi Aramco.

The Linux 3D rendering of Ghawar (hat tip Bob Shaw) is believed to show areas of the reservoir that have been produced and are now water wet (coloured yellow in Figure 5) versus those that have not been produced (coloured blue). This 3D image is not an official Aramco data release and was published (by accident?) in an obscure source. Furthermore, what this image shows is subject to conjecture.

The Linux image looks highly plausible from geological and engineering perspectives and it is possible to cross link observations from this image to other more reliable sources. For example, the elongate tongue of oil in Uthmaniyah (Figure 5) can be correlated with unswept oil zones in oil saturation profiles published in SPE papers and other sources (Figure 8). Furthermore, zones of unswept oil correlate with zones that lack production wells (Figure 6), e.g. The crests of Shedgum and S ‘Ain Dar and the unswept tongue of Uthmaniyah.

My interpretation of the Linux super cluster image is that yellow areas are swept, and will have high water saturation. With respect to primary and secondary (water drive) oil production, these areas are now essentially dead, though they may continue to produce oil with very high water cut for decades. The blue areas I interpret to be essentially dry oil at top reservoir (accept Ain Dar). As we shall see in the story of the 10 ft oil column, top reservoir is the top of Zone 2 that is not the top of the Arab D (see below).

Gas caps in N and S ‘Ain Dar (Figure 11, hat tips to Stuart Staniford and Fractional_Flow) means that gas replaces dry oil in the crest of these structures and this is taken into account in the reserves estimates.

Should this interpretation of the Linux Super cluster visualisation be incorrect then it will render as meaningless all estimates produced in this report.

SPE papers provide information on oil and water saturations in the vicinity of the water flood front. This provides insight to recovery mechanism, controlling the flows of produced water and to recovery factor.

Figure 8. Time-lapse series of oil saturation profiles, east and west Uthmaniyah. Image source: Water in the gas tank by SS, original source is: Water Production Management Strategies in North Uthmaniyah Area, Saudi Arabia, SPE 98847, June 2006.. Ghawar was discovered in 1948 and production began in 1951 so the provenance of the 1940 vintage data is dubious and is presumed to denote pre-production data. The 1980 profiles show a zone of low oil saturation along the base of the profile (yellow colour) which may reflect poor quality zone 3 reservoir.

The 2004 profiles show the east and west flanks are swept and that water is climbing over the east ridge leaving a tongue of dry oil in the saddle axis that corresponds with the tongue of oil observed in the Linux visualisation (Figure 5).

The preponderance of dark blue colours along the west flank in 2004 suggests a very high recovery factor in this area that translates to high recovery factors being used for Uthmaniyah in the reserves presented below.

Figure 9. Oil saturation profiles from the flank of N ‘Ain Dar. Image source: Water in the gas tank by SS, original source is: Water Management in North 'Ain Dar, Saudi Arabia, SPE 93439, March 2005.. These profiles are believed to lie just to the N of the small crest illustrated in Figure 5 of this SPE paper. They are therefore believed to mount the ridge well below the crest area of N Ain Dar.

The 10 foot oil column

In the period March – April 2007, there was much debate on TOD about the significance of water saturation profiles for N ‘Ain Dar showing a single 10 ft layer of oil at the top of a predominantly water swept section (Water Management in North 'Ain Dar, Saudi Arabia, SPE 93439, March 2005., Figure 9). Many argued that these sections showed only 10 ft of oil remaining at the crest of the S ‘Ain Dar structure. The position I adopted was that these profiles were from the flanks of the structure and said nothing about the height of the oil column at the crest (this conservative point of view did not receive much support).

Hat tip to F_F who dug up SPE paper 81567 (Asphaltene Precipitation in High Gas-Oil Ratio Wells, SPE 81567, June 2003.) showing gas caps at the crest of N and S ‘Ain Dar. (Figure 11). Transferring this data and that contained in SPE 81567 onto Croft’s contoured map suggests that the secondary gas caps are in excess of 100 ft thick. So much for the 10 ft oil layer and I hope this data lays this debate to rest once and for all.

Further to the above, SS has described via e.mail that the uppermost layer(s) of the Arab D are a transitionl depositional facies between the limestone reservoir (highly permeable) and the overlying anhydrite (calcium sulphate) seal that has virtual zero permeability. This transitional boundary layer (about 10 ft thick) has low permeability and porosity. The buoyancy pressure produced by a 1300 ft + oil column has been sufficient to force oil into this boundary layer, but extreme poor reservoir quality means that this layer is by passed by the water flood front (see Figures 10). So there is a default tendency for the uppermost 10 ft layer to remain oil saturated.

This is significant for the interpretation of the Linnux Supercluster 3D visualistaion. My interpretation is that this shows top reservoir (Top Zone 2) and not top Arab D – as the uppermost layer is non-reservoir. Others may choose too interpret this differently.

The water / oil saturation profiles from Shedgum (Figure 10) and Uthmaniyah (Figure 8) are useful in providing an indication of oil column thickness. However, I have tended to use these in conjunction with contour intervals on Croft’s map to guide guesswork about oil column height.

Figure 10. Oil saturation profile for Shedgum used in estimation of recovery factor. The annotations illustrate water control strategies described in the text. Image source: Optimizing Maximum Reservoir Contact Wells: Application to Saudi Arabian Reservoirs, SPE 10395, Nov 2005. The profile is presumed to be from the flanks, and contouring the dry oil areas from the Linux map onto Croft’s map would suggest a full oil reservoir still exists on the crest of Shedgum that in Figure 6 still had a small number of wells. Modelling the geometry of mobile contacts is problematic and subject to uncertainty. In the Base Case reserves model, oil column thickness is reduced by 20% across the whole dry oil area to account for contact geometry along the flood front.

Water flood, secondary recovery, water handling strategies

The natural aquifer under Ghawar is not sufficiently active to provide pressure support to production. Producing oil, therefore, causes the reservoir pressure to drop. In the early 1960s, a program of peripheral water injection was initiated to maintain reservoir pressure above bubble point – the pressure at which solution gas comes out of the oil which has negative impact upon reservoir productivity.

The distribution of peripheral water injection wells is shown in Figure 6 and the movement of the mobile oil water contact resulting from oil production is illustrated for Shedgum in Figure 10.

We have had some debate about the dynamics of flow in this reservoir. Some have argued for a purely gravity driven system – water floating on oil with vertical movement of the flood front. However, the Arab D reservoir is layered (it is not a uniform tank) and contains low permeability horizons that inhibit vertical flow (Figure 4). These impermeable baffles may be kilometres across but lack the extent and geometry to form actual seals within the reservoir. Furthermore, production pressure gradients tend to be horizontal with higher pressure around the periphery related to water injection draining laterally towards the low-pressure sinks associated with producing wells. Layering, and pressure gradients therefore in my opinion give rise to a strong lateral flow component.

The effect of layering on channelling flow can bee seen in Figure 10 where step changes in oil saturation occur across some but not all layer boundaries. These step changes are associated with high water saturation layers down dip. The flood front is neither horizontal (gravity driven) nor vertical (piston layer driven) but has a shape consistent with a dynamic equilibrium between these two processes.

Figure 10, will show only a tiny segment of the Shedgum reservoir. You can imagine that a few years ago the whole section would be coloured red and in a few years time it will be coloured green and blue. As the flood front passes through a vertical production well, it will start to produce water from the base of the well. As water begins to replace oil throughout the oil column (fractional flow) the water cut increases due to increasing ingress of swept reservoir at the base and progressively higher water cuts above the mobile flood front. Eventually, as the flood front passes through, the water cut will get too high and the well may be retired or abandoned altogether.

Handling water production on Ghawar is one of the greatest challenges facing Aramco today. Various strategies have been deployed to manage water cut. In the early years, they could simply go and drill new wells in dry areas and balance wet area with dry area production. In more recent years, they have deployed two strategies in the wet areas to reduce water cut in wet area production. One has been to set cement plugs in the well to cut off water production from the base (Figure 10). The other has been to drill short radius horizontal wells at the top to increase the well contact area with dry oil (Figure 10, Water Management in North 'Ain Dar, Saudi Arabia, SPE 93439, March 2005.). Both of these are temporary measures because once the flood front passes through, the well will be “totally watered out”. When this happens, it is time to drive a few miles up the road and drill new wells in dry areas.

As the areas of dry production shrink in Northern Ghawar, the ability to maintain water cut at the target 40% will become increasingly difficult – and this may be significant in determining oil flow rates in the immediate future. High contact area horizontal wells will be deployed to counter this problem – but this represents the final roll of the dice in Northern Ghawar.

Figure 11. N and S Ain Dar have secondary gas caps formed as a result of gas injection aimed at improving reservoir sweep. The presence of gas caps gives rise to a complex geometry for the remaining oil reservoir in these areas (Figure 14). Westexas has on very many occasions mentioned on these pages thinning oil columns sandwiched between oil-water and gas-oil contacts. In N and S ‘Ain Dar this is indeed the case. These thin (50 to 200 ft thick?) oil horizons will lend themselves ideally to production via multi-lateral horizontal wells in a manner analogous to that used in the W Troll Field, Norway (see Figure 3). At the time SPE 93439 was written, only one such well had been drilled on N ‘Ain Dar and Aramco said they were planning to drill more. This will be the last roll of the dice for dry oil production in the Ain Dar area.

Image source: Asphaltene Precipitation in High Gas-Oil Ratio Wells, SPE 81567, June 2003.


The Arab D and net reservoir

The Arab D section shown in Figure 4 has a gross thickness of around 250 ft (Uthmaniyah) for Zones 2 and 3 combined. The average net reservoir thickness for Uthmaniyah given by Croft is 180 feet. The net reservoir only includes producible beds and the cut off between producible and non-productive layers can be somewhat arbitrary. Figure 4 shows that the best quality reservoir is Zone 2 and the 180 feet of pay in Figure 4 is most likely distributed as 150 feet in Zone 2 (near 100% pay) and 30 feet distributed throughout Zone 3.

Zones 2 and 3 have very different reservoir qualities. It is to be expected that Zone 2 should be uniformly swept and more efficiently swept than Zone 3. Zone 3, on the other hand should experience uneven sweep owing to inter-bedded good and poor quality reservoir.

The saturation profiles for N Ain Dar (Figure 9) and Shedgum (Figure 10) do not display the variability expected if these represented full Zone 2 + 3 sections and it is considered more likely that they portray Zone 2 only, which is expected to have a uniform sweep.

The saturation profiles for Uthmaniyah (Figure 8) exhibit more heterogeneity, and in particular, the 2004, W flank section appears less well swept in the lower half, suggesting these profiles may represent the full Zone 2 and 3 interval.

In summary, the net reservoir figures from Croft are interpreted to represent producible beds from Zones 2 and 3 with the producible beds concentrated in Zone 2.

One of my reviewers pointed out that with the advent of horizontal drilling over the last 25 years, many companies view of net pay has become more generous. This is because horizontal wells allow greater recovery from poor permeability rock. It is possible, therefore, that horizontal wells may allow greater recovery from Zone 3 than assumed at the time Croft’s figures were compiled. This will be booked as one possible source of underestimation in my reserves figures.

Scaling factors

All the volumetric calculations presented here hinge on the accuracy of Croft’s map and the scale bar on that map which is best described as a bit scrappy. Measuring the length of Ghawar from the tip of Fazran to the toe of Haradh yields a length of 164 miles using Croft’s scale bar. However, in his text Croft says that Ghawar is 174 miles long and this raises concern about the reliability of that scale bar.

SS sourced a second map produced by “Arabian American Oil Company Staff” (Fig 7) that had a better scale bar attached and measuring 4 easily identifiable dimensions on this map yielded the exact same dimensions as Croft. It would seem that the “Arabian American Oil Company Staff” map was probably the base map used by Croft, so this agreement is not surprising. What it does show is that the scale bars on these two maps are compatible with each other – but they may both be wrong.

A second contoured map came to light from a confidential industry report. On this map, Ghawar is 181 miles long and is proportionally wider in the north relative to Croft. This map therefore has a significantly larger surface area than Croft’s map – very approximately 24% larger area. This would clearly have a significant impact upon volumetric calculations.

The Ghawar wells map (Figure 6) showing the distribution of oil production and water injection wells was overlaid on both of these maps. This provides a good fit with the Croft map, the injectors fit snugly around the map outline in Haradh, Hawiyah, Uthmaniyah and N Ain Dar (Figure 12). The fit is less good to the east of Shedgum and to the west of South Ain Dar and in the large saddle area between Ain Dar, Shedgum and Uthmaniyah.

The fit of the injector well profile to the confidential map was good in Uthmaniyah and Hawiyah but it was not good in the north with most injector wells lying inside the structure outline.

Figure 12. Wells map (Figure 6) overlaid upon Croft’s map (Figure 16). The wells map had to be rotated anti-clockwise and rescaled (constant x-y axes scaling) to produce the fit of water injectors around the peripheral contour on Crofts map believed to be the oil water contact. The fit is excellent around Haradh, Uthmaniyah, N Ain Dar and the northern rim of Shedgum. The fit is not so good down the W margin of S Ain Dar and the E margin of Shedgum or in the large saddle area suggesting that Croft’s map may be a bit narrow across S Ain Dar – Shedgum.

Working in 2D

The main uncertainty working in 2D arises from what are known as edge wedge effects. Where the reservoir plunges through the OWC working with 3D cubes breaks down as shown in Figure 13. On Ghawar, these edge wedge effects are estimated to penetrate about 1.1 miles from the edge of the structure (300 ft thick Arab D section, 2.8 degrees dip) and this will result in overestimation of reserves working in 2D.

In the Arab D reservoir the upper Zone 2 has superior reservoir quality to the underlying Zone 3 (Figure 4) and as illustrated in Figure 13, the overestimation resulting from the edge wedge is mainly the poorer quality Zone 3 reservoir. Very roughly the edge wedge comprises 25% Zone 2 and 75% Zone 3. This will significantly reduce errors arising from ignoring the edge wedges where this has been done in calculating initial reserves and the remaining reserves in South Ghawar.

In the Base Case scenario, edge wedge effects, and contact dip effects have been accounted for by reducing column height by 20% in Ain Dar and Shedgum. In Uthmaniyah, owing to the unpredictability of the underlying shape of that tongue of oil, oil layer heights have been reduced by 33% in both Base and High Cases to account for this and for edge wedges.

Figure 13. Diagram illustrating errors arising from edge wedge effects at the OWC whilst working in 2D. The area counted will tend to overestimate reserves. However, in the Arab D reservoir, good quality productive horizons are concentrated in the top half of the reservoir and this tends to reduce errors arising from edge wedges as illustrated.

Secondary gas caps in N and S ‘Ain Dar

The presence of secondary gas caps in N and S ‘Ain Dar has a significant impact upon the volume of reservoir that is now occupied by oil. These gas caps have formed as a result of re-injection of produced gas. This is an efficient way of displacing oil and is a commonly used secondary recovery mechanism.

Figure 14 illustrates how the gas caps and volume of underlying oil rim has been modelled in North and South Ain Dar. This exercise is subject to large uncertainties. 200 ft thick gas caps have been assumed leaving a complex oil volume geometry as illustrated in Figure 14. Modelling this as cubes will tend to underestimate oil remaining oil volumes. Note that thin oil layers below gas in N and S ‘Ain Dar occur in poorer quality Zone 3 reservoir and present ideal drilling targets for high contact area horizontal wells.

Note also, that the model for S ‘Ain Dar actually shows gas on water at the south end of the closure (Figure 16) – indicating how close we may be to the final stages of primary oil production in this area.

Figure 14. Diagram illustrating errors arising from measuring oil rims below the gas caps of N and S Ain Dar. In these structures, the area of gas has been deducted form the area of oil and a “cuboid” volume of oil determined on that basis. In reality, the oil volume has complex geometry with larger volume than the cuboid.

Recovery factor

The recovery factor is the percentage of the initial oil in place that may be recovered.

Recovery factors have been estimated from the published water saturation sections for N ‘Ain Dar, Shedgum and Uthmaniyah (Figures, 8, 9 and 10).

The procedure followed is to estimate the initial oil saturation (Soi) and the minimum final residual oil saturation (Sor). Note that water saturation Sw = 1 – So. This allows a value to be calculated for the mobile oil that is recovered. The recovery factor then equals Soi-Sor / Soi. (Figure 15).

This provides an estimate for optimum recovery in the most efficiently swept zones, and not all zones will be swept by this optimum efficiency. Thus the recovery factor is multiplied by an efficiency factor. In the base case scenario a sweep efficiency of 80% has been assumed whilst for the high case a sweep efficiency of 95% has been assumed.

Figure 15. Diagram illustrating how recovery factors have been estimated. The recovery factor = mobile oil / initial oil * a sweep efficiency factor. Mobile oil = the residual water saturation (Swr) minus the initial water saturation (Swi). Minimum Swi and maximum Swr have been estimated from the saturation profiles in N Ain Dar, Shedgum and Uthmaniyah (Figures 8, 9 and 10). This provides a picture of optimum recovery that will not likely be achieved throughout the whole reservoir owing to uneven sweep. The base case model uses a sweep efficiency factor of 0.8 and the high case model a sweep efficiency factor of 0.95.

Reserves Calculation

The following methodology was used to obtain a Base Case and High Case for the remaining recoverable oil reserves in Ghawar. The Base Case is based on what are considered to be conservative assumptions. The High Case is based on more optimistic assumptions that are more closely aligned with Aramco’s input data.

Step 1

The oil saturation data on the Linux visualisation was transferred by hand onto the 2D Greg Croft map (Figure 16). No bias between base case and high case.

Step 2

The total areas of N ‘Ain Dar, S ‘Ain Dar, Shedgum, Uthmaniyah, Hawiyah and Haradh were measured by counting squares on a square mile grid overlaid on the map. The process was repeated for the unswept areas (Figure 16). No bias between base case and high case. The total map area determined in this way is 1625 square miles. Stuart S has made the same measurement using computer code and got 1663 square miles. This is considered to be extremely good agreement.

Step 3

Oil rock volumes were determined for initial and remaining reserves. The details are on the spreadsheet. In short, the main difference between high and base cases is that thinner oil layers have been used in the latter, especially in N and S ‘Ain Dar and Shedgum.

Step 4

Oil rock volumes calculated in cubic feet are converted to barrels by dividing by 5.615.

Step 5

Hydrocarbon pore volumes are calculated using the average porosity data for each area provided by Greg Croft (no bias between high and base case) and oil saturation data. Initial oil saturation data has been estimated from the published saturation profiles for the North. In the south, with the absence of independent data, the 89% So values from Croft have been used. These seem appropriately lower for the poorer reservoir quality in the southern area.

The initial oil saturations used are as follows (no bias between high and low case):

N Ain Dar 95%
S Ain Dar 95%
Shedgum 95%
Uthmaniyah 96%
Hawiyah 89%
Haradh 89%

Step 6

Dividing the hydrocarbon pore volume by the formation volume factor yields stock tank barrels in place (STOIP). Note that the volume of oil shrinks under surface conditions owing to degassing and cooling. No bias between high and base cases.

Step 7

Recoverable reserves are determined by multiplying STOIP by a recovery factor (see above). In the North, recovery factors are based on the published saturation profiles using methodology described above (Figure 15). In Haradh, High Case recovery factor is calculated using 900,000 bpd for 30 years as a percentage of STOIP yielding 53%. This factor is then applied to Hawiyah. The Base Case recovery factor in the south has been assumed to be 45%. In summary, the net recovery factors are as follows:

Base Case High Case
N Ain Dar 59% 70%
S Ain Dar 59% 70%
Shedgum 54% 64%
Uthmaniyah 67% 80%
Hawiyah 45% 53%
Haradh 45% 53%

The recovery factors calculated for Uthmaniyah are very high. The saturation profiles (Figure 8) suggest very high recovery and in the absence of other evidence this has been accepted at face value. Note that a sweep efficiency of 95% is assumed for the High Case and 80% is assumed for the Base Case.

The main differences between high and base cases are:

Base Case High Case
Oil coulmn thickness reduced in north full reservoir (accept Uthmaniyah)
Recovery factor lower higher

And that brings us to the end of the background and methodology section. Part 2 - results will be along very shortly.

Full acknowledgements will be included at the end of Part 2. However, at this point I feel obliged to point out that Stuart Staniford (in conjunction with certain posters) provided most of the reference material used in this article and he provided the images for Figures 2, 4, 6, 7, 8 and 9.

Recent Oil Drum articles on Saudi Arabia:

by Stuart Staniford

The Status of North Ghawar

Further Saudi Arabia Discussions

Water in the Gas Tank

Saudi Aramco's Astrologers

A Nosedive Toward the Desert

Saudi Arabian oil declines 8% in 2006

by Euan Mearns

Saudi production laid bare

Saudi Arabia and that $1000 bet

by Heading Out

Simple mathematics - The Saudi reserves, GOSPs and water injection

Of Oil Supply trains and a thought on Ain Dar

by Ace

Saudi Arabia's Reserve "Depletion Rates" provide Strong Evidence to Support Total Reserves of 175 Gb with only 65 Gb Remaining

Further Evidence of Saudi Arabia's Oil Production Decline

A note to posters

Part 2 is written but needs some revisions and then coding for publication. I got to work my socks off to have it ready to go for tomorrow (or as soon as the TOD bosses see fit) so won't be able to answer many questions today.

I'll be around tomorrow to answer as many questions as I can.


Hello Euan,

I noticed your qualification of fit geometry in your FIG 12:

Croft Bouguer Gravity Map [1959] to Voelker Well overlay

Perhaps this newer Bouguer Gravity Map [1987] might better fit the Voelker Well overlay:

Figure 9 from original link:

Bob Shaw in Phx,Az Are Humans Smarter than Yeast?

It's quite an impressive post that is matching the scale of Ghawar!

An executive summary would have been welcomed.

Should this interpretation of the Linux Super cluster visualisation be incorrect then it will render as meaningless all estimates produced in this report.

With possibly thousands of parameters impacting the result of this simulation, how likely is it that this particular result is meaningful?

At the end, you are estimating recovery factors but you are not giving reserve estimates despite the title. According to your analysis, how much is left in Ghawar? in part II?

An executive summary would have been welcomed.

Yes. But also it would be great if someone able to follow this debate could summarize the keys points for us mortals. It's frustrating to see such a debate, realizing its immense significance, and yet not really be able to understand the key points of difference.

Hello Davebygolly,

My suggestion is to download the Voelker Phd thesis or what I call the Voelker Motherlode, then read it without worrying about the math or other extreme detail. The pictures and graphs with the associated 'light' discussion will reveal alot of clarification in most reader's minds, IMO. I am on my third skim or surf thru this huge PDF, but I understand more each time.

SS, F_F, Euan, and any others with advanced reservoir extraction and production understanding will then pound out the key details for us mere amateurs. I sure hope SS has invited Joe Voelker to comment on TOD. A online discussion with Joe, SS, Euan, and F_F would be DYNAMITE!

Of course, don't overlook the previous TOD keyposts & comments that Euan has highlighted in his text topthread.

Bob Shaw in Phx,Az Are Humans Smarter than Yeast?


Nice work, I'd love to see your final "adding the squares" number plot - and see how it compares to mine!

Three points:

1) Ghawar is 180miles tip of Fazran to tip of Haradh. Its Fazran that makes for the problem, where you assume this to finish makes the difference in length. 170miles is also justifiable with different assumptions. Some question marks about the extent of Shedgum as well.

2) I wouldn't use that Fig 6 for anything. The original resolution is too low to draw conclusions. Other data suggests more interesting effects.
[Edit: Here's an alternate well overlay map of the same vintage to play with]

3) From what I've seen Uthmaniyah is anything but smooth sailing - I think you may overestimate the recoverable numbers unless that is taken into account.

Maybe I will have to finish the work I was doing...

Hello Euan & GaryP,

First--Kudos to Euan for all the work resulting in this impressive and highly-detailed keypost! I DUGGIT.

GaryP: Link for well graph detail? Or else, please email to SS, Euan, and F_F. I think it shows the Shedgum leak area quite "white" by the absence of black dots. Also interesting is the black dot crestal difference between North and South Ain Dar. In this graph: the Shedgum-Uthmaniyah connection ridge is much more drilled than I expected [perhaps now totally watered out?].

Also, the "white" area in SE Uthmaniyah [western flank of Eastside crestal ridge] is the highly problematic and erratic reservoir sweep area that has been detailed previously in earlier SPE papers and Voelker's Motherlode PDF. I suggest that this area is generally shut-in or sporadic extraction as Aramco is trying to carefully detail DFNs in this area for more efficient sweep strategies to optimize economic extraction and minimization of watercuts. See MORABT and flux chart in Voelker PDF for more explanation: page 76, frame 106.

Hawiyah: see page 113, frame 143 of Voelker PDF. If this detail of problematic Super-k distribution and DFNs could be obtained for all of Ghawar--we could make much progess in our analysis. My amateur WAG would be that Ghawar volumetric sweep may have to be derated by 10% because the economic limitations imposed by geologic problems from DFNs, Super-k, fines and tarmat migration, over-pressurized injectors, gas cap formation, and the nearly constant well work-overs to minimize watercuts, along with other problems, will limit production rates and the decline tail going forward. But more detailed assessment I will leave to the TopTODers.

Consider the work required to just generate the maps of page 96,97, frame 126,127 to make future extraction decisions! The Law of Ever Receding Horizons is rapidly coming into play for Ghawar's subfields.

Bob Shaw in Phx,Az Are Humans Smarter than Yeast?

I'm getting closer to having the data quality I want, but other stuff takes the time. This is an extract from a PDF, I've forgetten which one. Hopefully will have this tranche of work done by the end of the weekend.

Shedgum-Uthmaniyah connection is productive, or was, but is at a comparible level of depletion to South Ain Dar.

Hello GaryP,

Thxs for responding. I hope you and the other TopTODers will carefully evaluate North Uthmaniyah [UTMN] with the Voelker PDF page 90, frame 120, in your analysis. IMO, this injector to producer analysis covering over 9,300 ft in roughly 4,000 days right in the heart of N. UTMN does not bode well for the rest of Ghawar. This area of Ghawar should theoretically have the lowest occurence of super-k and DFNs because it is a non-crestal area less prone to tectonic fracture forces.

If I understand the UTMN graphic correctly [left to right Saturation graphical series]:

1. [No fault] Waterfront override predominates the sweep in non-DFN and non-super k gridded blocks. Higher permeability in the upper layers at the detriment of lower porosity/perm in the lower layers largely prevents uniform 'piston sweep' of the payzone layers.

2. [Middle of Blocks] Water quickly seeks the interlayer high perm zones as primary conduits. Zonal thieving may be just as important to optimal sweep efficiencies as gravity drive because of these multi-layers.

3. [Next to Fault] IMO, this clearly shows non-ideal sweep phase separation or non vertical 'piston sweep' due to multilayer differentials, not ideal gravity drive.

4. [Fault Plane] Here the well data seems to illustrate ideal vertical sweep, but as has been previously seen in the earlier graphics-- this amalgamation with data interference caused by the fault or DFN distortion paints a false picture of what really occurred from across the injector to producer distance.

It suggests that Aramco will need to do a lot of down-dip studies to best identify lower perm payzone pockets that were bypassed, then carefully install horizontals or downbore pumps to best extract these payzones at low watercuts. If one considers that they might have been misreading some or much of the reservoir sweep data for thirty or more years because of super-k and DFNs: is it any wonder that Aramco is now struggling with high watercuts and declining production?

I hope the TopTODers can cut my WAG to pieces, for all our sakes. Have at it, Gentlemen. Thxs for any reply.

Bob Shaw in Phx,Az Are Humans Smarter than Yeast?

Hello TODers,

I done some googling on Fracture Networks that might simplify one's understanding of the problems it presents to optimal reservoir extraction. Hopefully, it will aid in your understanding of Voelker's Motherlode PDF and his voluminous detail on Ghawar Super-k & DFNs.

Are you ready for a 3D fly-thru of Ghawar?
Bring your imagination!

The first link is a supercluster rotational animation of a simulated fracture network in a material. Now use your imagination: picture a 3d graphic of Ghawar spinning slowly instead, and each color spot or squiggle represents a bypassed pocket of oil that can be tapped if it can be identified by Aramco supercomputer simulation [easier said than done]. Imagine this cube being stretched to approx. 170 miles long, 20 miles wide, and 200 ft thick! Each one of those squiggles could represent a supertanker VLCC if they could be tapped precisely. At Ghawar's current advanced age: If the well misses the squiggle target from incomplete or bad data --> then you get a hell of a lot of water instead.

The red layer [nearer the bottom of the cube] could be analagous to the bottom layer of Arab Zone D with lower permeability/porosity-->here, as Voelker suggested, horizontal wells will be more effective in sweeping thru this geo-interlayer.

Maybe SS, Euan, and F_F would think it more accurate if you mentally flipped this rotating cube: then the red layer cluster would represent the topmost crestal dry oil in the previously discussed waterflood geo-slices.

The toplink was taken from this source:

Here is another rotating simulation showing vertical and horizontal faulting:

taken from this source:

Again, if you mentally transpose the Shedgum leak area into vertical faulting as illustrated by this simulation--> then you can understand why Aramco doesn't want to just pump water from this area.

Here are some more links with good illustrations to further aid amateur understanding:

Use the PDF zoom tool to look at the pictures in greater detail.

Hope this helps bring people up to speed so that they have a greater understanding of what the TopTODers are writing about. Cheers!

Bob Shaw in Phx,Az Are Humans Smarter than Yeast?

My amateur WAG would be that Ghawar volumetric sweep may have to be derated by 10% because the economic limitations imposed by geologic problems from DFNs, Super-k, fines and tarmat migration, over-pressurized injectors, gas cap formation, and the nearly constant well work-overs to minimize watercuts, along with other problems, will limit production rates and the decline tail going forward.

Bob - first of all thank you for all the Sterling work digging up all the information on Ghawar. You may be interested to know that WAG stands for Water alternating Gas injection - the Snorre Field in Norway is one well known example.

So what does DFN mean - had a quick look at Voelker who seems to like the term.

In my Base case model I have used 80% sweep efficiency and in the high case 95% sweep efficiency - I'm not sure what Aramco use here, but I am now using higher recovery factors than Aramco in the High Case and lower recovery factors in the Low Case. I suspect de-rating sweep by 10% across the whole field is a bit extreme - but certainly in some areas sweep may be significntly less efficient.

One thing to bear in mind is that most oil fields will have production problems of one sort or another. Ghawar may appear to have more than most, but this in part is related to its immense size. I think a lot of these problems may be managed - especially since this is on shore and shallow drilling, and the well spacing is still massive compared to other onshore fields.

IMO, the main issue with the Super K problems etc is simply handling the water production. The oil will be recovered ultimately, but managing water production may determine the rate - both in Uthmaiyah but also in Ain Dar.

Hello Euan,

DFNs = Discrete Fracture Networks

Voelker Motherlode PDF page 1, frame 31:
We hypothesize that super-k systems that are laterally extensive, for example those systems of greatest interest that enable premature breakthrough of injection water to adjacent producers, often in well spacing exceeding 1 km, are comprised predominantly of one or more discrete fracture networks, combined with a localized, thin,
high-permeability facies generally providing connections to the wells. An analysis of super-k mechanics, Chapter 6, shows the discrete fracture model to be plausible, and
in fact, likely.

My use of WAG = Wild Ass Guess, because I know my limitations-- I wouldn't stand a technical chance of doing a true Ghawar reservoir evaluation because I don't have the skills and experience compared to someone like you or F_F.

My hope is that you and the other TopTODers, using dated info with clever analysis, can generate a fairly accurate SWAG to get Aramco to become more transparent as Simmons suggests.

Bob Shaw in Phx,Az Are Humans Smarter than Yeast?

Hello TODers,

From the Motherlode PDF page 74, frame 104:
The opposite extreme occurs if the intervals are laterally extensive such that both production and injection wells are intersected by them, or if one or more DFNs intersect the intervals at such an orientation as to facilitate the flow of injection water to the interval. The first condition has not been verified in the literature, and in fact
contradicts the prevailing facies distribution model for the Arab-D (Chapter 4).

The second condition, however, may be prevalent. The existence of faults and discrete fracture systems have been confirmed throughout the field.[5] Furthermore, the high conductivity of these systems has been accepted as prevalent,[1],[52],[46],[51] and the orientation of the fracture systems, although becoming better defined with seismic studies currently being conducted over much of the field, may be practically irrelevant, as coning within a DFN has been demonstrated, as cited in the previous section.

Thus, under this condition, a DFN of any orientation, and any appreciable length, for that matter, that has a sufficient vertical thickness to connect a permeable interval intersected by a well, to a region of high water fractional flow, located at a greater depth, may contribute to high water cut at the well.

Thus, the existence of DFNs in the Arab-D favors, and may in fact determine completely, the detrimental effects of
the high permeability intervals.

Note that we have adopted, in the title of this section, the traditional parlance for super-k, as describing only the thin, permeable interval. It must be made clear that
our model of super-k consists of the combination, thin conductive interval and DFN.

Therefore, under our definition, it is concluded definitely that super-k is bad: under waterflood conditions, DFNs provide conduits for water flow, and the conductive
intervals provide connections from DFNs to producing wells.

Al-Ajmi, et al.[54] presented the results of a study of well productivity for 450 wells (over half of the total) in the Uthmaniyah Sector, that clarifies which of the
two classes of wells, those favorably disposed to thin, conductive intervals, and those rendered non-productive by them, prevails.

To me, this is very compelling reading: how much worse has DFN coning gotten in the intervening years? There is probably no way to cost-effectively minimize for this geologic effect. Aramco probably has to accept ever-increasing watercuts and declining production.

DFNs and super-k was ideal in the early stages before the application of waterflooding; it allowed very high, dry oil barrels/well. Now the opposite effect is occurring: the easy waterflood flow through DFNs is inhibiting effective and economic sweep efficiencies from the low porosity/permability payrock.

Bob Shaw in Phx,Az Are Humans Smarter than Yeast?

Hello TODers,

Please see the cubes at Voelker Motherlode PDF pages 459- 461, frames 489-491: Wouldn't you love to 3D fly-thru these blocks trying to best determine injection, drilling, and water-handling decisions?

From the little information Euan presented it seems to me that you folks are simply comparing charts produced using different cartographic projections.

Especially the insider one that has 180 mi N to S seems to have been produced using a non equal-area projection, making it useless for area readings.

GaryP - I've tried fitting your map to Croft's and am sorry to say that your map seems to be bent.

Kind of strange - it took about 2 mnutes to fit the wells map from Volker's thesis, but this one just won't fit at all.

Luis de Sousa has been reminding us about map projections and scaling, so this is clearly one further variable / uncertainty that needs to be taken into account.

Reply sent via email.


Great work so far (if a little hard for us non-engineering types to follow), can't wait for the results in Part II and then SS's own article on the same thing.

Outside of the Chief Geologist's office at Saudi Aramco, this level of research has not been carried out anywhere else in the world (that we know of..... Langley, anyone?)

Thanks are due to Matt Simmons who managed to get the Saudis to bite with his publication of Twilight in the Desert, directly leading to Saleri's 2004 CSIS presentation, which has played a small part in the recent analysis.

I wonder if a new book (Nightfall in the Desert...?) based on all the various posts by SS, EM, FF, Ace et al might tease the Saudis into another rebuttal. Or have they decided that last time was not a smart move....

Certainly there has been enough subject matter for those authors to put together a book, which could have both technical sections and a "layman's summary" extrapolating what the peak and decline of Ghawar means in terms of Saudi and global oil production.

Alternatively maybe Simmons himself would write a sequel to Twilight (with co-authorship and subsequent revenues goign to the above-mentioned posters). Food for thought. Mr Simmons, are you reading??

Very good presentation.

The CIA Fact book indicates that Saudi Arabia was the world's leading exporter of petroleum in 2005.

The CIA published Saudi proved reserves as "262.7 billion bbl (2006 est.)"

The U.S. government intelligence sector needs improvement. I guess it is not in their job description to accurately forecast a country's oil reserves, it was someone elses job.

The CIA Factbook is a public service provided by the CIA and is not intended to be be that actual intelligence brief(s) developed. It is not really its mission to do geophysical research, and it is just as likely that analysts review TOD as anything else.

I totally agree all this wonderful material should be published as a book. I hope you guys are working on that already!

Isn't Matt Simmons working on another book right now? I don't remember exactly what it's supposed to be about, but I'm sure it'll touch upon the issues you have elaborated on in such a scrupulous manner.

Best hopes for finding out what the heck is really going on in KSA!

I just want to point out that the assumption implicit in the first graph, that Saudi reserves should not have increased since the 1980s, flies in the face of experience everywhere else on the globe. See this article:

It references this graph by Stuart showing non-OPEC reserves and production since 1980:

It shows that non-OPEC reserves have increased from 232.5 Gb to 298.2 Gb over this time, while producing 376 Gb of oil! So we produced more oil than were in the initial reserve estimates while still ending up with more oil reserves than we started.

It is in fact very natural for reserve estimates to grow over time. There is nothing surprising about the fact that Saudi reserves grew. Of course, the precise shape of these graphs with their "step function" reserve increase would reflect the timing of public announcements by the Saudi government rather than internal geological estimates.

But the red line in that graph at the top of this posting is completely implausible as an extrapolation of Saudi reserves. Failing to account for the natural growth of reserve estimates that we have seen in every other part of the globe makes this undoubtedly a serious under-estimate of present day Saudi reserves.

Oh, yes, a related posting:

If we want to follow those 1980-era reserve estimates and not account for reserve increases, JD points out that the entire Ghawar oil field had an estimated URR of 60 Gb in 1975, but since then it has produced at least 60.4 Gb. So if we strictly follow those initial reserve estimates, we must conclude that Ghawar is now completely empty.

Again, the point is that reserves grow over time. Everyone knows that Ghawar as a whole is not empty, and that the initial estimate of 60 Gb URR was too low. It's reasonable that the other estimates of Saudi Arabia's recoverable oil were also too low and should have grown over time, contrary to what is shown in the top graph above.

This is irrelevant for what he's trying to do with Ghawar. More important is the oil column heights he's using across the field. Probably see that in part 2.

1) Most new non-opec reserves are from new fields, certainly fields developed in the last 1/4 century. SA has no new fields. SO, for a proper comparison, look at how reserves have grown (or shrunk) for non-opec old fields (original production c1950) vs. production for the period under discussion, ie from 1980 to the present.
2) Reserve increases are mostly oil that is more difficult (energy) and costly ($) to produce than what was produced previously, and the oil itself is heavier, ie resulting in lower flow rates and less product.

Proven (1P) reserves are notoriously unreliable. They are either grossly underestimated or overestimated for various economic or political reasons.

True reserve growth does not occur by large jumps as above, it's a slow and long term process. SA raised their proven reserves in 1988 by 100 Gb without any new field discoveries.

Right, I'm not defending this step function in reserve estimates. But it would be equally false to accept that reserves remained level for so many years prior to the jump up, or in the years since. Based on experience elsewhere, the most likely case is that reserves were rising all that time. The fact that they were shown as flat merely reflects the government's choice not to update its reserve estimates in a timely fashion. It's possible that the big jump up represented reserve growth that had taken place over a number of years.

Halfin et al - my only comment today....

I think it is crucial to understand the different approaches adopted by the OECD and OPEC in reserves estimates. The OECD are way too conservative which results in reserves growth with every well that is drilled.

ME OPEC make an estimate of what they think they might recover from the outset - and the pattern that is emerging for me is that they stick to that initial reserves figure come what may.

The fact ME OPEC don't decline their reserves for production is clearly wrong (by our metrics) but they don't revise upwards very much for new discoveries and revisions either.

This gives me a chance to raise another question. The conventional peak oil explanation of these semi-synchronized reserve increases is that it's due to "quota wars". When I was going through tons of OPEC MOMRs and the quota statistics etc for my posts a couple of weeks back, I wasn't able to find any substantiation of this idea. I didn't find any discussion of a relationship between quotas and reserves, and there wasn't an obvious pattern of countries actually getting a bigger quota as a function of the step function reserve increases.

I seem to recall that the earliest reference I could find on the "quota war" explanation was in Colin Campbell's writings (but don't have links to hand). Does anyone know if there is any substantiation for this explanation?

A second serious problem with the proved reserves data is the opposite of the above. For the main Middle East OPEC countries their P50 reserves data held by industry are considerably smaller than their proved reserves. This anomaly was due to the ‘quota wars’ increases of the late 980s, where allowable production under OPEC’s quota was driven in part by the size of a country’s reported proved reserves. As Table 1 shows, the changes adopted by the countries were dramatic, doubling proved reserves overnight in a number of countries and trebling them in the case of Abu Dhabi. In total the increases added 300 Gb to global proved reserves.

From this excellent article of Roger Bentley (page 6):

IAEE Newsletter, 2006

Well, yes, but how does he know? He doesn't give any source for the idea. My point is, we are all repeating this idea, but I at least 1) don't know where it came from in the first place, 2) cannot substantiate it with a somewhat significant effort looking through OPEC materials.

Is there any support for the "quota war" theory other than the fact that peak oilers all repeat it all the time? Right now, the oldest reference I have is from the 1998 Campbell/Laharrere Sciam piece where it says:

The members of OPEC have faced an even greater temptation to inflate their reports because the higher their reserves, the more oil they are allowed to export. National companies, which have exclusive oil rights in the main OPEC countries, need not (and do not) release detailed statistics on each field that could be used to verify the country’s total reserves. There is thus good reason to suspect that when, during the late 1980s, six of the 11 OPEC nations increased their reserve figures by colossal amounts, ranging from 42 to 197 percent, they did so only to boost their export quotas.

Now, I'm not saying this isn't so. But there's no reference, and I can't find any OPEC document that says quotas have anything to do with reserves. And if you look at the actual history of quotas you'll find there's no sign anyone got a bigger quota immediately after their reserve change. It doesn't have any obvious correlation with the BP reserve data graph you posted up above.

So what's up with that? I'm not saying these graphs show any sign of being the result of any kind of regular honest reporting of the best technical evaluation of reserves. But, at least at present, I can't substantiate the Campbell quota war theory either.

I guess if no-one comes up with anything here after a while, I'll email them and ask them.

Does this help?

From page 4

Another important oil related factor that could be considered in an allocation formula would be proven reserves. however, reserves figures from OPEC member countries reflect a bumpy trend. During the 1980's, OPEC proven crude oil reserves increased by 80 percent. Many of the countries upped their 'book' reserves, in some cases by a factor of three, to position themselves in anticipation of a quota system.

If I'm reading that paper correctly, reserves were one of the criteria considered in 1986 for a new quota system. But because of the increases reserves were eventually left out of the formula when they revised the country allocations.

Got to love how the piece opens (in July of 2003):

Probably for the first time in its 42 year history, OPEC has gained the respect of the world oil community as a technically competent organization. An organization capable of managing the fundamentals of the oil market, managing global stocks and movements, refinery throughputs etc., to "achieve stable oil prices which are fair and reasonable for oil producers and consumers", as stated in their primary mission.

Oops. That lasted less than a year...

However, you are right that it's reassuring to see the discussion in this document and the hypothesis of "they were going to and then they didn't" (make quotas dependent on reserves) at least fits the known facts (huge inexplicable instantaneous reserve jumps, but no match with quotas). Still, I'd love to see some contemporaneous account.

You could always email the author. His email is in the document.

The fact that they were shown as flat merely reflects the government's choice not to update its reserve estimates in a timely fashion. It's possible that the big jump up represented reserve growth that had taken place over a number of years.

IMO totally implausible that all of these governments followed the exact same process of deciding to suddenly update their reserves at virtually the same time.

What's the expression? This dog don't hunt...


I dont post on stuff I know nothing about like gardenin... I might be the exception to the rule....

but we are going to be going deep Bradshaw to Stallworth like on 7758 * A * phi * h * delta So / Boi the next few days my man.... and Euan has done the work to bring us here.

quit worrying about the forest for a minute- I don't know why Euan ever brought it up (it doesn't really mean anything)

We don't need to play a game of Saleri says.... Rockdoc likes that one...

But the guy is really plowin virgin soil here and he needs to focus thereto.

This is groundbreaking stuff believe me.


"But the guy is really plowin virgin soil here and he needs to focus thereto."

Paranoid: maybe that's what he tries to avoid?

Yep, once Euan comes out with part 2 I'm gonna get me a cole Arhn and a Primanti's sammitch and take it all in.

Reserves do not grow!

Reserves are sometimes underestimated. When these estimates are updated, this appears as growth. It is not.

New technology may, (or may not), enable us to get more oil out of a reservoir. This is not growth, it is simply pulling a greater percentage of the oil out than was originally expected. Also higher oil prices may enable us to milk a well for oil long after it would have been shut down if prices were lower. This is not growth, and at any rate, the extra oil recovered is not usually very much.

The chart above showing Non-OPEC reserves growing is not growth at all. Some of it is new discoveries, like in Brazil, Angola, Nigeria, Sakhalin Island, the Gulf of Mexico and other places. And of course part of it is just updating previously underestimated reserves.

If we are to assume Saudi reserves will grow, or did grow, then they had to have been underestimated to begin with, since very few new discoveries have been found in Saudi. They could have very well been underestimated but the evidence does not support this. The evidence supports the proposition that they are in decline. If they are in decline then there is no possible way they could have 260 to 360 GB of reserves that they claim to have.

It is also natural for reserves to shrink. Check out Mexico in this chart:

They went from 55.6 to 13.7 billion barrels in 20 years. When all you are talking about is an estimation of reserves, then reserves can shrink just as easily as they can grow. Saudi Arabia, and other Middle Eastern countries are in for some very severe reserve shrinkage in the near future.

Ron Patterson

Hi Darwinian/Ron,

I'm always glad to see explanations that illuminate the overall picture.

re: "New technology may, (or may not), enable us to get more oil out of a reservoir."

After reading the response of Charles and Nate to that NYT piece, I wondered if anyone has done a study or otherwise written up the "may or may not" in more detail - ?

When - may? When - may not? (When and where?) Any useful generalizations to be gained, (especially those) which may help in responding to the "new technologies" argument?

re: "This is not growth, it is simply pulling a greater percentage of the oil out than was originally expected."

Well, it's not reserves growth, is what you're saying (yes?). Still, it's growth of *something* (yes?), which is what the lay person is attempting to get a handle on.
What would you call it?

re: "Also higher oil prices may enable us to milk a well for oil long after it would have been shut down if prices were lower. This is not growth, and at any rate, the extra oil recovered is not usually very much."

WRT, "...not usually very much". Again, has anyone laid this out in some kind of summary? With some boundary numbers or something?

I'm also wondering what the limits high the price...until price rise no longer has an influence...? (Or, can we even talk about this...past a certain point?)

I was taken aback that before this post no one (including me) had noticed the 1940 date on the graphs. Duh!

I hope this astonishing amount of work will in the end lead to better information about extraction rates. I've been trained here well enough to know that total reserves are only a small part of the story. How fast will the oil come out of the ground.

The 1940 date jumped out at me immediately but I kept my mouth shut as much of the data was beyond my paltry intellect. But even when I can't keep up with everything posted I find the work of Euan, SS, RR, FF and others to be some of the most fascinating material that I've ever read. And it's actually free!


The story is filtering through (apologies if this has already been posted)

FRIDAY, APRIL 15, 2005

Bank says Saudi's top field in decline
By Adam Porter in Perpignan, France

Speculation over the actual size of Saudi Arabia's oil reserves is reaching fever pitch as a major bank says the kingdom's - and the world's - biggest field, Gharwar, is in irreversible decline.

Yeah, check the date on that

FRIDAY, APRIL 15, 2005

Euan, superb analysis. One caveat from near total ignorance of the technical aspects - The flank cross sections seem to suggest a much more horizontal water flood face than you have chosen for fig 10. If so your remaining oil estimate would be high. Murray

I am not a real expert on the subject but, still, I know a little about it. From my (limited) point of view, your approach seems faultless, although it illustrates very well the difficulty of analyzing a very vast (and, so, very complex) field like Ghawar on the basis of uncertain, indirect deductions. (We already have lots of useful data, but it is still insufficient and, in some cases, of bad quality – due to unknown dates for some particularly important parts, etc..)

I am sure everyone will be eagerly looking forward to the second part of your great work.
(I suppose I have a pretty good idea about your conclusions, but since you promised to present the second part soon, there is no need to try to speculate on that… :-)

Precisely. Let us merely hold our breath for now! :)

Euan, thank you.

This is a mammoth undertaking and I am sure Stuart is busy with his interpretations as well. Regardless of how we all see this once you and Stuart have both presented your cases, I want you to know that I and many others greatly appreciate your inputs here, even if we sometimes disagree with conclusions amongst one another.

I eagerly look forward to Part II while I continue to try to digest this mass of information in Part I!

Again, kudos to you, Stuart, and anyone else involved behind the scenes.

Ghawar Is Dying
The greatest shortcoming of the human race is our inability to understand the exponential function. - Dr. Albert Bartlett


I am beginning to wonder if you guys are not a bit obsessed with Ghawar. It is one field in the world. KSA actually has mammoth heavy deposits too. They say they are going to be able to reach 12 mbd within a few years.
Meanwhile, you are missing a whole 'nother picture: Declining demand. Remember, higher prices translate into lesser demand. World fossil fuel consumption is flatlining as we speak. (It fell after the price spike of 1978). It will be interesting to watch this go 'round. The price spike is not as pronounced, but may be more sustained. Look for long-term declining demand for fossil oil at more than $60 a barrel. All sorts of alternative liquid fuels coming online. And a few years out: Plug-in hybrids. They will break the back of the oil industry.
Also remember: There is no major field in the world in which oil costs more than $30 to lift. Most are under $20, many under $10. Already, OPEC is cutting production to avert oversupply.
As for the world running out of oil, the picture radically changes if one assumes 1 percent or less in annual demand increase for fossil fuels. We are getting there already.

Benjamin, please read McKillop on price driven demand destruction. So far demand is still going up, and probably will as long as the ratchet is gradual, at least to over $90.00/b. For sure USA demand is nicely up so far this year. Murray

havent you heard, your president, el'befuddleoso, has said : " amerika is addicted to oil"

I agree with Benjamin that there may be too much focus here on Ghawar. Euan writes, "Understanding the current status of this super giant is central to the peak oil debate and to understanding the security of future global energy supplies."

I don't agree that Ghawar is "central" to the debate. It is an important field, yes, but it is not the main issue where peak oil is concerned. There are many oil producing countries and regions which are also important in terms of the future of their oil production. Russia produces as much as Saudi Arabia and so the status of their production levels is equally as important as for SA.

It seems that TOD is getting stuck in the syllogism: As Ain Dar goes, so goes Ghawar; as Ghawar goes, so goes Saudi Arabia; as Saudi Arabia goes, so goes the world. All this in service of the dogma that we have already passed peak oil production levels.

But this line of reasoning fails in both directions. Even if Ain Dar production is falling, we could still be several years away from worldwide Peak Oil. Or in the other direction, even if Ain Dar can produce for a few more years, we could still be facing a major Peak Oil crisis. As Benjamin points out, worldwide demand trends are an equally important part of the picture, and those are highly uncertain at present.

The point is that we should keep this in perspective. IMO entirely too much effort is going into working with inadequate data sources and trying to build elaborate chains of logic on an insecure foundation. In the computer field there is an old saying: garbage in, garbage out. Nothing conclusive or convincing can come of the kind of reasoning we have been seeing with regard to Ghawar, and the very effort elevates the field to an almost mystical level of importance that goes beyond its position in the world today.

Its a political problem that why the focus is on Ghawar. KSA makes some pretty huge claims basically that they have almost a order of magnitude more oil than any place on earth. The claim should be dismissed out of hand but TPTB take it seriously or at least they act like they do.

If Ghawar is declining its almost certain that KSA cannot increase production much above what they do today since it represents about 50% of their current production. So even if their claims are reasonably true your still looking at break even at best for a long time. Considering their announced projects if Ghawar is declining we should actually see a decline in production from KSA for the foreseeable future.

So overall the issue is not about the geology its political.
For the rest of the world we have a pretty good understanding of the future production profiles outside of a major new discovery so KSA and in particular their claims are really the only issue that would prevent or alleviate peak oil now or in the near future.

Of course if you step back and simply use common sense then KSA is not that important since at best it will continue to produce about where it is now and thus won't be able to prevent world peak at worst our decline rate is steeper than people anticipate depending on the decline rate of Ghawar.
Its a big enough field that it will effect the total amount of oil available world wide. So the decline of all the giant fields will be a big part of our initial decline rate and on the economic front its when supply is permanently below potential demand that price change rapidly.

So your back focusing on Ghawar :)

Halfin, there are approximtely 50,000 oil fields in the world today.

The top 20 out of 50,000 produce 20% of the oil. Got that yet?

The top 1%, 507 to be exact, produce over 60% of the oil.

In our entire history we have found these 49,500 "other" fields which are incredibly small compared to the 507 giants and the 20 super giants. Can you do simple math and calculate the average size of the 49500 remaining fields in barrels per day? Can you do simple math and calculate how many of these small fields we would need per day to even match existing giant and super giant production?

You are flat out wrong. As Matthew Simmons said, "As Ghawar goes, so goes the world" and he said that with good reason.

By the way, Halfin, 19 of the 20 top fields are confirmed in decline. Only Ghawar remains and it certainly looks like it is in decline, doesn't it?

There is no garbage in the numbers I just gave you, Halfin. They are all confirmed FACTS. This is why the status of Ghawar is so important.

Do you see the problem yet? Or will you continue to deny, obfuscate, and dally while Rome burns?

Ghawar Is Dying
The greatest shortcoming of the human race is our inability to understand the exponential function. - Dr. Albert Bartlett

You're under no obligation to read this stuff. There's plenty of other sites on the Internet. Presumably, the fact that you take quite a bit of time to read this one, and these posts in particular, suggests it is in fact of some value to you...

Hi Halfin,

And congratulations on your son's graduation (even though last year).

A question to those who responded to your post here:

So, to address mem, Stuart and others, (and if you'd like to elaborate, as well, Halfin)

I have a question about just one part of what Halfin is saying, namely,

re: "Or in the other direction, even if Ain Dar can produce for a few more years, we could still be facing a major Peak Oil crisis."

I believe I understand the context of the Ghawar discussion WRT the confirmed decline rates of the "giants" and open (or *more* open - ?) data from the rest of the world.

My question is, what's your take on this one sentence above?
Crises - yes, due to geologic factors? Or "merely" "above ground" - ? Yes? No? Maybe?

Any comments on just this particular point?

euan, nice work and i think is see where you are going with it. your recovery factors appear altogether reasonable. we are just waiting on the big one, ooip. i am just wondering if this figure has been published (prior to the nationalization of aramco). wouldnt that figure be fairly reliable ?

I don't know if this is helpful or not:

Jean Laherrere showed that Saudi Arabia had been well explored by 1980 when ARMCO was nationalized. See page 12 of this presentation:

I've been following this series with interest. Great work by Stuart and everyone else who has contributed to the discussions. I've been doing some work with a few GIS programs and would like to offer the following.

I've always been struck by the dimensions of Ghawar versus those of Long Island, NY, where I live. Virtually all published dimensions of Ghawar have it almost exactly the same width as LI and about half again as long. To get a visual on this I georeferenced an outline map of LI with a map of KSA's Eastern Province and made the scales equal. Then I overlaid the LI outline on top of the Ghawar map and rotated LI until it lined up in general agreement with Ghawar's North-South axis. What you see above is the result. It is to-scale. In stark visual terms Ghawar is indeed about the same width as LI and 50% longer.

This little experiment with GIS software tools led me to do a few more. The results were interesting and a bit more on-topic for the discussion. I'll be posting those shortly.

Where those two charts produced with equal-area projections?

Great post Euan.

I am humbled and contrite in the presence of greats!

Saudi production is down again, 50k barrels per day from March to 8.27mbpd.

I have agreat chart, but don't know how to post it.

You get the feeling that the Saudis must get production going in the other direction almost immediately or all hell breaks loose? you have a link to this march (?) saudi data?

Why are these charts all 250k barrels higher than table 3?

IEA website - OMR - Oil Market Report

Then select the type of report and date you want

part two is on TOD: Europe now - don't seem to be seeing it on the front page of the main site yet.