Tech Talk - of longer wells and drawdown pressure

There are, simply, three major parts to the coming global economic mess that will be created as we enter into the period of Peak Oil. The first of these comes from the current rising demand for oil, particularly emphasized by those countries, such as China and India, where demand is rising fastest. The second part is the declining production from existing fields as their reserves are drawn down. (Though it should be remembered that even when “exhausted” the fields will still contain vast quantities of oil, but oil which is at present not economically recoverable). And finally there is the oil in the undeveloped, and undiscovered wells and fields that can be added to the existing reserve to help ameliorate the imbalance between demand and supply from existing wells.

The high decline rates from long horizontal wells drilled into, and along the shale deposits in the United States, most particularly the Bakken and the Eagle Ford, mean that there is a constant need to drill new wells to sustain existing production. The EIA has taken note of this and calculated based on some assumptions, the number of rigs that must be operating in these fields, so that they will drill enough new wells to sustain current production.

Figure 1. The number of rigs required in the Bakken and Eagle Ford formations to sustain production at the level of the previous month (EIA).

Should the need be to increase production (which is the current assumption by most prognosticators of future equilibrium between demand and supply) then these numbers need to be significantly higher, perhaps by as many as 50 additional rigs. At present the Bakken rig count is running at around 176 rigs while there are around 270 rigs drilling in the Eagle Ford.

One of the ways in which production is anticipated to expand above earlier estimates for the wells drilled in both fields comes from the ability to drill longer horizontal wells and to increase the fracture density along these wells.

However, as the Kingdom of Saudi Arabia discovered some years ago, longer wells can only be viably effective out to a certain distance, beyond which there is no gain in productivity. As a result they have changed their drilling patterns so that the wells are shorter, with multiple laterals spreading from the original wells to more thoroughly cover the rock within the formation. Initially wells were drilled out to distances of up to 12 km, but over time the KSA found that this was too long.

Since there is a somewhat similar argument to be made for the wells in the United States, as they move to longer distances, I thought I would go over the explanation as to why this is not a very productive idea a second time.

To begin consider that regardless of whether I put a tiny glass of water or a huge glass of soda in front of you, if I glue it to the table then the amount that you can drink at one time becomes limited by the size of the straw that I give you to drink the liquid, rather than the amount in the container. And to get that liquid into the straw and up into your mouth requires that you suck on the straw.

What you are doing is reducing the pressure at the bottom of the straw, while the pressure from the atmosphere on the top of the liquid remains the same. By creating this differential pressure there is now a force to move the liquid into the straw and thence up into your mouth.

But, as Fishbuch et al showed, as the horizontal well bore gets longer the pressure at the back of the hole declines as then does the difference in pressure between the oil in the rock and the well (the drawdown pressure), and while the longer hole gives an overall increase in production to a certain point this seems to maximize at a length of around 6,000 ft. Beyond that distance the differential pressure between the formation and the well falls to a point where there is less benefit to the additional cost of drilling to that distance.

Figure 2. Drop in well pressure with increased well length, while increasing overall oil flow (Simulation by Fishbuch et al )

The answer which Aramco came up with to get around this problem was to use a main lateral from which a number of shorter laterals could then be drilled out into the formation, providing higher drawdown pressures within the wells and making it also easier to isolate any well section where the underlying water broke through into the well.

Figure 3. Schematic of a Maximum Reservoir Contact well as used in Saudi Arabia (Aramco).

The optimum length at which a well can produce is a function of the rock type and structure as well as the nature of the oil/natural gas that it contains and the water content (to name by a few of the parameters). Thus there are limits to the analogy, nevertheless it does show, even in the much more productive rocks of the fields in KSA that there are limits to how far a well can be productively driven, and these limits will also exist in the shales of the United States, although the oil locations and the optimal ways of extracting it are somewhat different.

The extraction of oil and natural gas in these shales is more sensitive to the levels of drawdown pressure, since much of the oil and gas is found in natural fractures that are not that wide (although they may be spread further apart by the fracking process itself). With exposure to the lower well pressure thus being restricted to a relatively small volume, significant reduction in the pressure because of the location relative to the heel of the well can have significant effects on lowering the overall well production.

Further as a general rule the complex valve systems used in KSA are not installed in the shale wells of the United States, making it less practical to focus the relative pressure differentials at different points along the well bore as a means of increasing production sequentially along the well.

Tech Talk - the difference between fracking and acidizing a well

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

The description of acidizing is as follows:

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

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

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

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

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

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

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

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

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

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

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

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.

OGPSS - a little more detail on hydraulic fracturing

There is a real, practical limit to the amount of oil that can be recovered from a reservoir. Depending on the availability and economic viability of different technical approaches that limit might be less than 25% of the total volume of oil originally in place, or it can be more than 50%, as has been achieved in some of the fields in the Kingdom of Saudi Arabia(KSA). But one cannot get out more oil than is originally there, and in most cases it is difficult to reach even half that value.  However, where the volumes of oil that have been left by conventional methods remains high, as it does in the KSA, then the use of advanced technology, as I began to explain last time, become easier to justify.

 KSA is now reaching the point where the easy production of oil, as in sink vertical wells at kilometer intervals and watch an average of 10 kbd merrily bubble to the surface, is now largely over. Increasingly the oilfields are moving into the more advanced, and costly, procedures that help sustain a production that would, under earlier production regimes, by now have long faded into memory. Ghawar, for example, is moving into CO2 injection and some steam assist (likely with the areas with heavier, tar-ier deposits) seeking to maintain an overall 5 mbd production. But today I want to talk a little about their increasing use of hydraulic fracturing of their horizontal wells, and a little more technical detail about growing cracks through rocks. Consider the problem that high production fields have, when a horizontal well runs through a high permeability, or densely fractured zone. The impact of this on premature water breakthrough is well documented. The relative preferential movement, for example of water along faults can be seen in this model from Ghawar.

Figure 1, Relative water movement along faults in Ghawar (Dogru et al)

 It is also evidenced by this simulated model of the effect of high fracture densities on the performance of MRC wells, where increasing the drawdown pressure to pull fluid into the wells can lead to premature watering out of the well.

Figure 2. Use of a low draw down pressure to maintain oil flow.

With low draw down, the flow rates are reduced, but the fluid entering the well remains largely oil (Mubarak et al) In contrast if the differential pressure is increased (by lowering well pressure) then the greater flow rates allows the underlying water to flow up the fractures and prematurely waterflood the well.

Figure 3. The use of a higher draw down pressure preferentially encourages water migration up the fractures, killing the well prematurely. (Mubarak et al)


It has been obvious to Aramco (who run the KSA fields) for some time that adding their own fracture paths to the field would result in better performance, and could also help overcome the problem of natural fractures and high-permeability zones such as those known as the Super-K in Ghawar.

Figure 4. Section through conventional dolomite at Ghawar (Cantrell et al) 

 Contrast this with the blue epoxy-filled pores of the super-K layers which indicate the high permeability.

Figure 5. Section through the super-K dolomite (0nly 5-ft from the sample in figure 2, in the same well. (Cantrell et al)

 There is thus an incentive to provide paths for the oil to make it as easy to reach the well. What follows is a more advanced discussion of hydraulic fracturing, but for those who are not that interested, the earlier simpler description is given here (TOD and BTE). Now just a little bit of extra tech talk. If you take a rectangular piece of Plexiglas (which gets around the geological variations in properties that occur with rock) as an example, and carefully cut a notch into the center of the block, you can grow a crack out from that notch, by putting the beam into simple 3-point bending. (We started doing this because we wanted some experimental results to compare with the various theories predominant at the time over the stresses required to initiate fractures).

Figure 6. Crack grown out from a wire-sawn notch in Plexiglas, under 3-point bending. 

 One of the first practical steps you take is to stop using a wire saw for the entire crack but cut most of the notch with a milling tool, and only use the wire saw for the last few mm. (The reason is that the heat on the wire causes a high failure rate of the cutting wire, particularly with a set of neophyte graduate students, and the wire, being diamond impregnated, is very expensive). 

 The next thing that you learn is that if you adjust the crack length, you can grow the crack very slowly and stop if where you want, so that it is fairly easy to work out how much work you are putting in relative to the crack surface generated, and the force required to start the crack. Further the surface of the fractured surface has a characteristic look, which we called “river lines.”

Figure 7. Surface of a crack grown out slowly from the initial notch (finger for scale) 

 However if you changed the notch length so that so that it was less of a percentage of the sample width, the crack almost immediately moved much faster, and unless you made a special effort, could not be stopped within the sample (as occurred in Figure 4). And further the crack surface was very smooth, in contrast with the "river lines" of the slower moving crack.

Figure 8. Crack grown from a shorter notch, with a higher speed of advance in the sample, note the smooth surface. 

 What this shows is something that Dick Bieniawski was also finding in rock itself (as we later also demonstrated). Depending on the initial length of the crack, so the speed that the crack grows at changes, and at the higher speed it moves, not around the particles of rock, but often through them. (In our case we were seeing the effects of discontinuities in the Plexiglas as the cause of the deviations in the surface). Dick’s work is given here and here, though I found it in the International Journal of Rock Mechanics and Mining Science (vol 4 no. 4 pp 395 – 430). Essentially he found (and this has been confirmed by others that based on initial geometry a crack begins to grow relatively slowly, but then accelerates to a terminal velocity, which remains relatively constant. Unfortunately the papers are behind a paywall, so I cannot use the exact curve that Dick drew, but I am going to approximate it, as follows:

Figure 9. Change in crack velocity with length (after Bieniawski IJRMMS) 

 (Half lengths are used, since for many theories the crack is anticipated to initiate as an oval shape. For the fractures in the field these are usually measured in tens of feet. (Rahim and Al-Qatani) 

 There are two critical points that come out of this work. The first is that it is preferable to start with a crack of a significant length so that the acceleration rapidly moves to a trans-granular surface, rather than just growing around the grains. The reason for this is practical in that small cracks can be stopped if they reach an area with a large radius (as in the reason you drill a hole at the end of a crack to stop it growing through a sheet of metal). Having the crack initially moving faster means that it can overcome small open spaces, but also that it can create a smoother, slicker path along which fluid can flow with less resistance. 

 The other aspect of growing the crack is that if you try putting too much energy into it (for example by over-pressuring the borehole) the crack will not grow faster, rather it will expend the additional energy by splitting into a number of cracks that deviate off somewhat from the original direction. That also tends not to be a good thing if you are trying to open a single passage way through the rock, wide enough to push particles into, along with the fracturing fluid. To stop that happening one can, for example pulse the pressure in the well so that only enough energy gets to the crack tip so as to keep only a single fracture growing out. One also has to ensure that the crack is initiated within the right orientation to the existing stress fields. Aramco have, however, become skilled in determining the effectiveness of the fractures by monitoring, among other things, the temperature flows of fluids into the well.

Figure 10. Induced fracture and the evidence for it from the temperature log (Rahim and Al-Qatani )

 Aramco have started to use hydraulic fractures in their horizontal wells, including those with open hole completions with the interval between packers ranging from 100 to 1000 ft, depending on geology. The pressure within the packed off section of the horizontal well is then increased until the wall fractures and the crack grows out into the formation. An example of how the pressure changes in the well as the fracture grows is given by Al-Naimi et al.

Figure 11. Pressure plot during the generation of a hydraulic fracture (Al-Naimi et al). 

 Getting the rest of the oil, after the best is gone, is an ongoing effort, particularly in older fields such as Ghawar. But understanding some of the technology makes it possible to further appreciate what Aramco are developing to further produce some of the more difficult regions within the field. (But that is a topic for another day).

Treating Oil, Gas and Water - more on GOSPs

My apologies that this is running a little late, unfortunately what looked as though they were minor weather problems on national television become a lot more personal when you're waiting for small planes to take you to smaller than normal airports.

At the end of the last tech talk I was commenting on the amount of water that usually comes out of the ground whenever we extract fossil fuels. Once it gets to the surface the questions become two-fold. The first is how do we get it out of the mix, so that we can separate what we would like to have (the fuel/fuels) and then we have the problem of what we do with what is left.

The simple answer (as in easy to write) to the separation of the different components of the fluid is the Gas Oil Separation Plant. However, as you can imagine, if you are tasked with separating, for the sake of example, the liquids and hydrogen sulphide from a gas flow of 1.5 billion cf/day, which is coming from some 87 wells that concurrently produce some 300,000 bd of Arabian Light crude, the actual design of such a plant is anything but trivial. Even the sulfur that is drawn off, at some 90 tons/day must needs be provided for in the design of the plant.

First, as the gas is produced from the wells, it must be collected into a common feed line, through a connector, called a manifold, that takes in the various smaller pipes from the individual wells, and feeds the result out in a larger pipe to the GOSP. Because the pressure that the fluid retains is useful as part of the separation process, we don’t want to lose any more of it than we have to in overcoming the friction in the pipes that it is passing through. (I have a couple of horror stories from my past about occasions when folk who should have known better used pipes that were too small, and ended up reducing both the flow rate and available pressure at the delivery end of the line). The pipes that carry the flow must, therefore, be large enough to carry the flows, though many miles of pipe to the GOSP. Thus we find, at Haradh, that the initial flows were collected into three different manifolds, and that they in turn carried the mix to the GOSP through five pipes which are, depending on flow, either 20 or 30-inches in diameter. (Different pipes are needed to continue to separate the sour (hydrogen sulphide containing) gases from the sweet before it gets to the GOSP.

To construct the plant required

The main plant is made up of 100,000m³ of concrete, 22,000t of structural steel, 410,000 welded joints, 4,000km of cabling, 540km of plant piping, 1,400 items of engineered equipment and 750km of line piping, ranging from 18in to 56in in diameter.

The construction was also expensive of manpower:

For the construction of the facilities, the companies used 32,000m² of office and workshop space, a residence camp for 1,000 men and supporting facilities and a Boeing 737-qualified airstrip, 8,000ft in length with day and night operations. Support systems included 2,500 telephone exchange lines and video conferencing, data networks for 470 users, ground-to-air radio, 306km of fibre-optics and five communications towers.

It cost $2 billion and at peak construction had some 10,600 men working. It took 3 years to build (coming on stream in January 2004).

To sweeten the gas (get rid of the sulfur) it is generally bubbled through columns containing an absorbent liquid (typically sulfur-attracting amines) which remove the sulfur (which can then be recovered by heat in a stripping column, while the amine is then recycled).

In the more recent construction required at the GOSPs put in to add 1.2 mbd of Arabian Light crude from the Khurais addition, which came onstream this year there was an additional consideration. In order to help get the oil out, Aramco is simultaneously injecting 4.5 million bd of treated seawater. The main treatment plant at Qurayyah can process more than 13 million bd. The treatment involves removing particulate solids, ensuring that the oxygen content is below detection (this is needed to prevent corrosion), that there be no scaling products in the water and that there is a minimum amount of microbial content that could lead to biofouling of both the distribution pipeline and the injection wells. (Note that many of these concerns also relate to cleaning up the produced water from the wells before it is re-injected. ) The volumes that are treated are expensive, and thus there has been a recent move to simplify this treatment. Getting the solids out is relatively straightforward. Horizontal sand filters (albeit some 11 ft in diameter, 40 ft long) can treat up to 125,000 barrels of water a day bringing the particulate matter down below 0.2 mg/L. (On a personal note, again, sand filters work very well as long as there is no clay in the water - it takes just a few minutes for clay to coat and plug the top of the filter and make life really, really interesting).

At the same time, to ensure that there is no corrosion in the pipelines that carry the water (perhaps over 150 miles to a well in a journey that might take 36 hours) the pipes themselves are given a special internal coating to try and retain water quality integrity and to ensure that the injection wells do not become plugged. The pumps and equipment are powered by gas turbines.

And speaking of gas the recovery of the oil at Khurais is also expected to generate some 0.3 bcf of a sour natural gas that will be sent to Shedgum to have the sulfur removed, and 70,000 bpd of NGL.

Getting the gas out of the oil (as both Darwinian and idontno commented after my last post appeared on TOD

Very basic, the oil, gas, water, and sometimes sand enter a hydrotreater. The flash gas compressor takes suction from the hydrotreater to remove the gas. The hydrotreater normally will have an electric grid that helps to corral the gas at the top of the hydrotreater. The gas is drawn off and flows to the flash gas compressor. The water and oil separate in the hydrotreater. There’s usually two hydrotreaters and sometimes three to separate the oil from the gas. The velocity of the fluid as it passes through the treaters is critical since if flow is too high there will not be enough time for the oil and water to separate. The water is drawn off for further processing. The sand is separated in the sand separators and bagged for deposit ashore. The oil is processed to get the salt down to specification. Nalco, one manufacturer who fabricates different kinds of production equipment, has a very good web site to visit. They include flow diagrams.

Depending on the gas and oil mix the process of getting the gas out can pass through more than one stage where the pressure in the vessel is dropped, and at the lower pressure the gas bubbles out of the oil. (As noted just as carbon dioxide bubbles out of soda when the can is opened).

In order to accelerate the separation of the water from the oil (remembering that oil floats on water) the vessel is often now heated, so as to speed the process up. Sand in the fluid is going to be an increasing problem as wells get deeper and more of them are horizontal, but it can be exemplified by the way in which the oil and sand are separated up at Fort McMurray, and for that there is a video.

This is part of a series and I am grateful for the help that is given both by those asking questions, and those with practical experience that help with replies.

Produced Water, GOSP's and Saudi Arabia

To the uninitiated the thought of a gas or oil well is one where a pipe goes down into the ground, and out of it flows either a steady stream of oil or natural gas, that is fed straight into a pipeline and then delivered to them (often at what they consider to be an outrageous price) with no further treatment. Or the crude oil that comes out runs straight over to a refinery where (with minimum effort and maximum profit) it is transformed into the gasoline or diesel fuel that they must then again buy at great cost in order to drive in to the liquor store to buy some beer.* The reality of oil and gas production is considerably different, and fluid that comes out of the well is not the ideal that the uninitiated imagines. So today’s topic will deal with the initial separation of a couple of the parts. This is a part of the technical pieces that I write on Sundays about various aspects of fossil fuel production, and it is a relatively simplistic explanation which seems to fit most folks needs, though it also has considerable help from those with more technical knowledge who add comments.

There are three major fluids that come out of a well and these are gas, crude oil and water. If the well is a natural gas one, the oil component will not be the heavier fractions that we associate with an oil well, but rather the higher end liquids such as propane and these are referred to as the natural gas liquids (NGL). NGLs include ethane, propane, butane, iso-butane, and natural gasoline. But today I am going to talk about the water.

Back when I first started writing about this separation oilcanboyd was kind enough to point me to the Produced Water Society.

The Produced Water Society is a collection of engineers and industry professionals with the common purpose to study and improve the separation, treatment, and analysis of Offshore and Onshore Produced Water with the goal to meet the discharge and reinjection requirements of the industry and the environment.

And just to be clear about what Produced Water is:

Produced water is mainly salty water trapped in the reservoir rock and brought up along with oil or gas during production. It can contain very minor amounts of chemicals added downhole during production. These waters exist under high pressures and temperatures, and usually contain oil and metals. . . . . . . The treatment of produced water is a major component of the cost of producing oil and gas. Wells may start out producing little water but sooner or later all oil wells produce a much larger volume of water than oil. The ability to efficiently and economically dispose of this water is critical to the success in the oil production business.

Back in April 2007, oilcanboyd quoted volume flows for the lower 48 US States as being 4.8 mbd of oil, 128 mbd of brine (the typical term for produced water). His number was considerably higher for the water than that offered by the Argonne report given below, though they admit that their count could be significantly under true values.

The changes in pressure, temperature, and the possible access to oxygen when the water reaches the surface, means that the water can precipitate out dissolved minerals and hydrocarbons such as paraffin, which can plug wells that are being used for disposal,

65% of the produced water generated in the US is injected back into the producing formation, 30% into deep saline formations and 5% is discharged to surface waters.

Argonne National Labs recently reviewed the status of this brine, providing not only a review of the process, but also the summary of conditions for each state. They show the relative volumes of water produced, in 2007, by the five largest producing states:

Total produced water generated by wells in the United States in 2007 (with top 5 state producers identified) Source Argonne National Labs

To try and give some sense of the scale of these numbers they point out that Washington DC and its local communities collectively use some 300 million gallons a day, which is only 13% of the amount of produced water that must be dealt with. The water comes from the roughly 1 million oil and natural gas wells that are still producing in the United States. Texas, while the largest producer of natural gas (6.9 tcf in 2007) lagged offshore in the amount of crude that it produced. The national average amount of water produced per barrel of oil was 7.6 barrels of brine, which produced about 87% of all the produced water developed. The average gas well production was around 270 barrels of water per mcf of natural gas. Some 59% of this is reinjected into the producing formations in onshore facilities (only about 9% offshore) in order to enhance production. These relatively large volumes that must be processed and disposed of can control the economics and life of the operation. As the Argonne report notes:

early in the life of an oil well, oil production is high and water production is low. As the production age of the well increases, the oil production decreases and the water production increases. When the cost of managing produced water exceeds the profit from selling oil, production is terminated and the well is closed. This is contrary to the typical production cycle of a coal bed methane (CBM) well. Initially CBM wells produce large volumes of water, which decline over time. Methane production is initially low, increases over time to a peak, and then decreases.

Because the US fields are, in the main, much older from a production point of view, than the average well in the total world, the average water flow is higher, the report estimates that the global value is around 3 barrels of water per barrel of oil.

Because of the high salinity (generally greater than that of seawater) the amount of sodium and salt in the water make it difficult to use for agriculture (which has a very large demand for water in its own right). However in states where the water is reinjected to maintain reservoir pressure even the volumes available may not be enough, and thus one finds, for example in Alaska, that the 842 wells using this EOR used about 1 billion barrels of water in 2007. Given the recent controversy over the disposal of water from the development of the Marcellus shale in New York, it is perhaps interesting to quote the numbers for that state.

The most recent available report is for 2007. According to the 2007 data, 13,113 wells were reported to the division. Of the total, 7,387 were natural gas wells, 4,874 were oil wells, and the remaining wells were gas storage, dry holes, and solution salt wells. The database provided production volumes of 55,001 Mmcf for natural gas and 377,514 bbl for oil. The state-produced water volume was 649,333 bbl from active wells for 2007, which included 215,050 bbl that were associated with water injection wells.

Handling the water from these wells is thus not a small matter, especially in the larger production fields around the world such as Saudi Arabia. When Aramco decide to increase production from a field, or to add another field to their supply network, they cannot just drill another well, hook it into the line and see their exports increase. Because of the nature of the fluid that actually comes out of the hole, it has to be run, first through a Gas Oil Separation Plant or GOSP. Here the oil, formation water and gas that come out of the well together are separated, so that they can be piped to the different treatment plants. (And as a side point readers might want to look at some of the articles on oil production from Saudi Aramco World since they are written more for a family audience than a technical one.) These plants are generally rather large, the one in the article treats 450,000 bd of oil, and they take considerable time to build, install and connect up. Thus when new production is planned one has to wait for the plant to be in operation before the wells themselves can be productive. The new addition at Khurais, for example, required a new central processing plant, and when Haradh Stage 3 began, it had, first to have the new GOSP in place and running, which is was by the second quarter of 2006. Thus the production increments in the country are controlled by the rate at which these can be brought on line. In addition the older ones had to be upgraded, particularly in the controls for the system. (Side comment, though the KSA centralize their GOSPs, they don’t have to be that big. We have had an individual well unit hauled through our yard behind an SUV). But we’ll talk about them a little more another time.

Putting this all together the oil and gas industry have been handling, without significant public complaint, relatively large volumes of water for a considerable time. The processes are handled through the state agencies (which is where Argonne got much of their information) in a set of processes that seem to be under control.

* across the street, last week.

Water Floods and improving oil flow

I am going to insert a topic here before going on to Carbonates, as I had mentioned doing in the last post, because it will help to explain a developing problem that comes when extracting oil from rocks such as chalk. And, because I used this example in my original post let me again start by creating an analogy.

The oil business is one of great complexity and there are some challenges even in trying to explain some of the basic reasons why, when price goes up, producers can't just turn a tap and pull more oil out of the underground reservoir.

I was trying to think of a way of explaining it, and offer the following, in the hope that not too many of those who know reality will be offended at the simplification.

Way back at the beginning of the current Elizabethan era it used to be fun, after dinner, to float cream on top of coffee. I still do it when the cream is of the right sort, and it gives the coffee a different taste. Putting the cream over the coffee is a bit of a challenge, you start by using the back of a spoon, and when you get better pour it down the side of the cup.

So now we have quarter of an inch of cream floating, unmixed, on top of the coffee. This can be very simply considered to be the oil floating on an underground pool of water in the porous rock underground. Now take a straw, put it into the cream and try and remove it without sucking up any coffee. If you suck gently you might be able to get a lot of the cream up, especially if you bend the straw to run across the top of the cup. But if you suck too hard then you not only pull the coffee into the straw and can't get any more cream from that particular place, but you also mix up the cream around that point into the coffee, and you lose the chance to recover that cream later. Separating the cream from the much larger amount of coffee beneath it is not really an option (though as you will see it is needed with oil and water).

Oil is somewhat the same, in that, if you try pulling it out of the ground too fast, you can cause changes in the flow pattern that drop the total amount you can get out from any one well, and the immediately surrounding rock, pretty severely. I will return to this topic of fluid control in a later post (and yes I know, there is an alcoholic version of this example, but it would be (grin) socially highly irresponsible to encourage folk to try doing this with different layers of liquor - especially since I can't remember which colors you have to use and which liquor you have to float on which to get them to stay separate. Research may be needed.)

So, if we can’t just change the differential pressure between the well and the surrounding rock to get more of the oil out, then how can we do it?

Given the volumes of space that the oil occupies, and the distances and rock it must pass through to get to the well, it would be easier if the oil continued to flow out of the well by itself. But if the natural driving forces that I mentioned last time (the pressure difference and the gas and water pressures) have all played their part then the next step is often to pump another fluid back into the ground to fill the space left by the oil and thus to recreate, or better to keep up the pressure in the oil, so that there is still a differential pressure that is pushing the oil out. So let’s go back to the section of the rock that contains the oil, and which I have used before:

Simplified sketch of an oil bearing layer in the ground.

There are two ways to inject fluid to keep up the oil pressure. One is to pump in a gas, under pressure, into the rock just over where the oil is, and this will move the oil to the well. If you have that sort of imagination it is similar in effect to going from the small toy water pistol that I could just about hit my baby brother with when he was really close, and still a child, to now having one of those more modern Super Soaker water guns that pump air under pressure behind the water. Now you put out more water faster, and can hit that obnoxious kid over on the next block.

However when this is tried in an oil well, while the gas works, you have to get it from somewhere, and it also turns out not to work as well as pumping in water below the oil. And so pumping water into the ground is often used, after the initial pressure has dropped, to keep some pressure in the well and help with what is known as secondary recovery (the initial flow being called primary).

In developing the large Saudi oil fields Aramco decided to speed the process up by combining the water flood with the initial extraction since, in this way they could keep a higher pressure in the rock, and the oil would thus flow out faster (the Super Soaker approach). The idea, as I recall, originated in what was then the Soviet Union, water injection being used at Samotlor, for example, in the 1970’s, for which I will quote from John Grace’s “Russian Oil Supply”, later.

It I possible, though it depends on individual project economics to also include a surfactant with the water (think detergent) so that the oil can be more efficiently driven ahead of what is known as a water flood.

When the technology was first developed pre-existing wells were used to pump water into the ground in a relatively localized operation so that, for example in the illustration above, I might use four wells surrounding well A to inject water so that locally I could raise the pressure, so that A would continue to produce.

However, with larger fields this tends to be less efficient, and so what is now more common in larger fields, is to start at the edge of the field , say at B, and inject water along the edge of the field. This not only increases the pressure in the overlying oil, but also, as the water level rises, it helps “sweep” the oil from the edge of the field up towards the center. Thus, over time, the oil would pass the well at A, and a new well would be drilled closer to the crest of the field, while A would then become a water injection well.

Now there are two problems (this being a simple explanation) with this way of increasing production. The first is shown with a simple mathematical calculation. Let us say the original well at A was drilled through 100 ft on oil bearing rock. At a given differential pressure the well produced some 100 barrels a day. Now we inject water under the oil, and this replaces the oil as it is removed. So, after a while the bottom of the oil layer in the well has risen by, say 25 ft. With the layer under that now being water. If we maintain the same differential pressure across the well, we will see a 25% drop in production, because we are now only drawing oil from the 75 ft of rock that still has oil in it. We will also see additional water coming out of the well with the oil.

Initially this might not be much of a problem – but over time this “water cut” can become very significant. Here is that quote from John Grace:

Water cut also played a major role (in the collapse of Samotlor production). The water injected into the ground with such fervor in the seventies had to be pumped back to the surface in the eighties. Water climbed from 24% of the fluid lifted by Samotlor’s wells in 1980, to 68% by 1985 – an extraordinarily quick rise. The field was drowning in water, all of which required pumping, and processing to recover any oil.

The current water cut at Samotlor is around 90%.

Saudi Aramco, as I mentioned, also extensively uses water flood to assist production. Some of the most productive regions have been the Ain Dar/Shedgum portions, which are to the north end of the main field. These are the regions that have been producing at around 30% water cut, and are some of the oldest of the producing regions of the Kingdom, with a current water injection rate of 2 mbd It is thus interesting to see look at the new water pumping stations that are being installed. The new construction for the Qurayyah Seawater Treatment Plant to be used to supply seawater for the Khurais expansion that has been put in and will provide the fields with 4.5 million barrels of water, to help in pressure maintenance and production. The overall water capacity of the plant has, however, grown to 14 mbd . Of this flow some 2.5 million will now go to the Ain Dar/Shedgum fields.

(Note I will try and remember to update a sort of “worked example” of all this with Abqaiq that I have previously posted next time) to help make this perhaps a little more real.