OGPSS - The potential for Saudi EOR

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

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

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

Figure 1, Euan’s production estimates from 2007.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

OGPSS - conditions and treatments in North Ghawar

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

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

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

Figure 1. Sectors of Ghawar with the date of discovery (Afifi )


Ain Dar came on line in 1951, with an initial yield of 15.6 kbd of dry oil, and the field was given the overall name of Ghawar (from the Bedouin name of the overlying pasture) in 1952. The original well was still producing 2,100 bd of oil in 2008, having, by then produced a total of 152 million barrels. Down at the other end of the field the first Haradh well was put into production in 1964, and though mothballed for a while due to lack of demand, was still also producing in 2008, at a rate of 2,300 bd – for a total production of 24 million barrels. Shedgum 1 was brought onstream in 1954, and was sidetracked with a horizontal section in 2008, which brought production back to 3,700 bd. The first Hawiyah well went on stream in 1966, and by 2008 was still producing at 4,600 bd – having by that time produced some 51 million barrels of oil. 


 Stuart Staniford and Euan Mearns have, among others at The Oil Drum, provided extensive sets of information on Ghawar over the years. For those that are not familiar with the region, Stuart’s early description is a good place to start. In this brief overview I will not get into any of the details of those descriptions, though I will quote one or two of the most relevant highlights. The debate initially focused on the amount of the waterflood in different regions of the field, since it was possible, with extensive work, to extract information on the rate that the water was advancing, relative to the remaining volumes in the different regions. For example, in one of his earlier posts, Stuart showed the following sequence of profiles for the water progression across a section of the field at Uthmaniyah. This was followed by an additional response from Euan.

Figure 2. Sections of the Uthmaniyah region of Ghawar showing the water flood progression. (Original source: Figure 12 of Al-Mutairi et al, Water Production Management Strategies in North Uthmaniyah Area, Saudi Arabia, SPE 98847, June 2006.) 

 Stuart then continued this analysis into evaluating the conditions in North Ghawar (i.e. Shedgum and Ain Dar) leading him, based on figures such as this:

Figure 3. Section through Ain Dar region, from Stuart Staniford,original source Alhuthali et al, Society of Petroleum Engineers Paper #93439, March 2005. 

 This led him to accept a prediction from Fractional Flow, who had earlier noted that production in Northern Ghawar had fallen (in 2007) from the 2mbd oil and 1 mbd water of 2003 to 300 kbd oil and 2.7 mbd water in 2007, as follows:

*90% or so of 'Ain Dar/Shedgum's 2mbpd could water out over the course of a few years. *We are likely somewhere in the midst of that process.

*That is likely the explanation for most of the Saudi production declines we have seen since June 2005 (including the failure of Haradh III and Qatif/Abu Safah to raise production).

The discussion at the time (which is still present in comments under the main papers) was fascinating, since it was based, inter alia, on information such as the speed at which the water front was advancing.

Figure 4. Speed of water front advance in North Ghawar (Fractional Flow ). 

 The use of horizontal wells and MRC came late in the development of North Ghawar, which is why the use of carbon dioxide injection for EOR, smartwater injection, induced fractures and long horizontal wells to capture otherwise stranded oil, will play a more important part in the production from the region. 

What these new technologies bring with them is the ability to go back into the older regions of Ghawar and extract some of the oil that was left in place during the original water floods. Because a number of them will be dealing with regions of the reservoir that are already flooded, so that the oil will be coming from wells with a high water cut, it is in my opinion unlikely that these will allow increases in production from the region, but rather that it will allow a sustaining of existing production levels somewhat further into the future than we (the collective wisdom of the TOD writers) have predicted in the past. 

 But Ghawar is not just the original wells of the North, and I will have more to say about the field, and then about other fields in the country in future posts.