Thursday, July 26, 2012
A brief intermission for a lengthy reason
Gentle Folk:- This weekend marks our 40th Wedding Anniversary, feeling remarkably blessed there will be a short pause while this anniversary is celebrated. Nought more need be said.
Thursday, July 19, 2012
OGPSS - Saudi Arabian production - then and now
The latest OPEC Monthly Oil Market Report (MOMR) foresees that demand for OPEC crude oil will decline over the next year by about 300 kbd. This is largely in anticipation of additional production from elsewhere:
Figure 1. OPEC forecast for global demand for the rest of the year (July MOMR )
Much has happened since the late Matt Simmons and Nansen Saleri got together to debate scenario’s for future oil production in Washington, back in February, 2004. While Matt had developed his research that then led into the publication of “Twilight in the Desert”, this was the meeting where Aramco pushed back to explain that there would not be a global problem, for at least fifty years. As this series of posts on Saudi Arabia comes to a conclusion, and moves on to other countries, it is perhaps of some value to look back on the presentation by Mahmoud Abdul Baqi and Hansen Saleri to remember what was said. Back in those days oil demand was expected to steadily rise, with increasing rate, to reach 100 mbd in 2015.
Figure 2. Aramco estimate of demand from 2000 to 2020 (Baqi and Saleri)
At the time Aramco had no concern over the industry being able to meet this increase in demand, and fully expected that Aramco itself would be able to more than sustain its share of the increased demand. They had 9 seismic crews out surveying the country, and some 48 rigs drilling both to sustain their then current level of production, and also to explore for new resources.
Figure 3. Location of exploration wells in Saudi Arabia in 2004 (Baqi and Saleri)
At the time Aramco reported that with 700 billion barrels of oil initially in place, that had been already discovered in the country, they expected to find another 200 billion barrels. Of that discovered oil they considered 260 billion barrels as their reserve, of which, by 2004, they had 131 billion barrels in development. (Note that they defined the reserve as the total amount of extractable oil, not the amount left to recover, they have done that in later computations also, and the latest annual report uses 259.7 billion barrels as that discovered reserve). The Annual Report notes that they discovered one new field in 2011, the Wedyan-1 well in the Empty Quarter flowed at 2.3 kbd from the Mishraf reservoir, while they drilled 161 exploration and development wells.
Figure 4. Amount of Saudi oil that had been developed by 2004 (Baqi and Saleri)
For a short arithmetic problem consider that 260 less 131 equals 129, and it one adds another 21, as a percentage of the 200 billion barrels to be found, then one gets 150 billion barrels. Divide this by 3 billion barrels a year of rough annual production and you get the 50 years of remaining life, that Saudi Arabia considered, back then, that their oilfields have left.
And this is the interesting plot, for it shows what Aramco define as their depletion rate, which is annual reduction of the initial proved reserve. The relevant term is the annual depletion rate:
Figure 5. Annual depletion rates for Saudi and other reserves (Baqi and Saleri)
This should be read in conjunction with the state of depletion of the different reservoirs in the KSA, as reported for 2004.
Figure 6. State of field depletion in Saudi Arabia as reported in 2004 (Baqi and Saleri)
And remember that this was eight years ago, so there has been that much change in the numbers! Aramco also expects to recover about 75% of the Original Oil in Place (OOIP) in all fields. They have been able to reach around that level with Abqaiq, which also suggests that the days of that field are now very numbered. But whether this will be possible in the other reservoirs is more open to doubt, and if there is less recoverable oil, then the actual depletion rates go higher.
But where the field is just starting, such as the new development of Haradh, if they hold the extraction rate to 1.7% of the anticipated total recovery then they anticipate that the field will continue to yield 300 kbd for decades.
Figure 7. Future production anticipated for Haradh III (Baqi and Saleri)
It was this anticipation of success across their endeavours that led the company to project that they would be able to hold a Maximum Sustainable Capacity of 10 mbd until 2042, with it only then becoming necessary to replace reserves from the probable and possible fields yet to be found and developed).
The last few posts have described how, as declining output has now hit the original fields, Aramco has moved to add production from other fields (Shaybah for example will soon be producing at up to 1 mbd) and is introducing multiphase pumps to Haradh and Shaybah to improve production from marginal wells, and in Safaniya to sustain a maximum production capacity of 1.3 mbd. Production from Manifa is also anticipated to step in to cover declines in other fields, and come on line in 2014, with a capacity of 900 kbd.
But these new additions are required to offset the decline in existing fields, which have been somewhat protected from the severity of declining well production by the switch from vertical to maximum reservoir contact (MRC) wells. Although this conceals the depletion of the oil in the reservoir during normal production it does not, by itself, improve the ultimate production from the field, but rather can shorten field life, since these wells have proved to be more productive in rate. Nansen Saleri now appears to duck questions which ask if KSA can increase production beyond 10 mbd.
Within The Oil Drum (TOD) there has been considerable discussion over the rate at which well production declines, and the remaining reserve in the field depletes. One impact of the shift in wells from old established fields is that production from the average well will decline over time, a subject that Euan has visited in the past.
Figure 8. Individual oil well production values for Aramco (Euan Mearns)
It should be noted that the use of the submersible pumps are reported to have brought wells back to around 3,000 bd. But the move over to horizontal and MRC wells has slowed the impact of other changes in the country.
Nevertheless, after putting all this together, I re-iterate my conclusion from last time in that I doubt that KSA will increase production much above 10 mbd, (in June it was producing 9.888 or 10.103 mbd depending on source, and with the rising internal demands (domestic use in the Middle East is now projected to average 7.7 mbd in 2012) world markets will get tighter in the shorter, rather than the longer term.
Non-OPEC supply is forecast to increase by 0.7 mb/d in 2012, supported by the anticipated growth from North America, Latin America, and FSU. In 2013, non-OPEC oil supply is expected to grow by 0.9 mb/d. The US, Canada, Brazil, Kazakhstan, and Colombia are expected to be the main contributors to supply growth, while Norway, Mexico, and the UK are seen experiencing the largest declines. OPEC NGLs and non-conventional oils are seen averaging 5.9 mb/d in 2013, indicating an increase of 0.2 mb/d over this year.Overall OPEC sees demand staying below 90 mbd over the remainder of this year, with total growth in demand lying at 1.01 mbd.
Figure 1. OPEC forecast for global demand for the rest of the year (July MOMR )
Much has happened since the late Matt Simmons and Nansen Saleri got together to debate scenario’s for future oil production in Washington, back in February, 2004. While Matt had developed his research that then led into the publication of “Twilight in the Desert”, this was the meeting where Aramco pushed back to explain that there would not be a global problem, for at least fifty years. As this series of posts on Saudi Arabia comes to a conclusion, and moves on to other countries, it is perhaps of some value to look back on the presentation by Mahmoud Abdul Baqi and Hansen Saleri to remember what was said. Back in those days oil demand was expected to steadily rise, with increasing rate, to reach 100 mbd in 2015.
Figure 2. Aramco estimate of demand from 2000 to 2020 (Baqi and Saleri)
At the time Aramco had no concern over the industry being able to meet this increase in demand, and fully expected that Aramco itself would be able to more than sustain its share of the increased demand. They had 9 seismic crews out surveying the country, and some 48 rigs drilling both to sustain their then current level of production, and also to explore for new resources.
Figure 3. Location of exploration wells in Saudi Arabia in 2004 (Baqi and Saleri)
At the time Aramco reported that with 700 billion barrels of oil initially in place, that had been already discovered in the country, they expected to find another 200 billion barrels. Of that discovered oil they considered 260 billion barrels as their reserve, of which, by 2004, they had 131 billion barrels in development. (Note that they defined the reserve as the total amount of extractable oil, not the amount left to recover, they have done that in later computations also, and the latest annual report uses 259.7 billion barrels as that discovered reserve). The Annual Report notes that they discovered one new field in 2011, the Wedyan-1 well in the Empty Quarter flowed at 2.3 kbd from the Mishraf reservoir, while they drilled 161 exploration and development wells.
Figure 4. Amount of Saudi oil that had been developed by 2004 (Baqi and Saleri)
For a short arithmetic problem consider that 260 less 131 equals 129, and it one adds another 21, as a percentage of the 200 billion barrels to be found, then one gets 150 billion barrels. Divide this by 3 billion barrels a year of rough annual production and you get the 50 years of remaining life, that Saudi Arabia considered, back then, that their oilfields have left.
And this is the interesting plot, for it shows what Aramco define as their depletion rate, which is annual reduction of the initial proved reserve. The relevant term is the annual depletion rate:
Figure 5. Annual depletion rates for Saudi and other reserves (Baqi and Saleri)
This should be read in conjunction with the state of depletion of the different reservoirs in the KSA, as reported for 2004.
Figure 6. State of field depletion in Saudi Arabia as reported in 2004 (Baqi and Saleri)
And remember that this was eight years ago, so there has been that much change in the numbers! Aramco also expects to recover about 75% of the Original Oil in Place (OOIP) in all fields. They have been able to reach around that level with Abqaiq, which also suggests that the days of that field are now very numbered. But whether this will be possible in the other reservoirs is more open to doubt, and if there is less recoverable oil, then the actual depletion rates go higher.
But where the field is just starting, such as the new development of Haradh, if they hold the extraction rate to 1.7% of the anticipated total recovery then they anticipate that the field will continue to yield 300 kbd for decades.
Figure 7. Future production anticipated for Haradh III (Baqi and Saleri)
It was this anticipation of success across their endeavours that led the company to project that they would be able to hold a Maximum Sustainable Capacity of 10 mbd until 2042, with it only then becoming necessary to replace reserves from the probable and possible fields yet to be found and developed).
The last few posts have described how, as declining output has now hit the original fields, Aramco has moved to add production from other fields (Shaybah for example will soon be producing at up to 1 mbd) and is introducing multiphase pumps to Haradh and Shaybah to improve production from marginal wells, and in Safaniya to sustain a maximum production capacity of 1.3 mbd. Production from Manifa is also anticipated to step in to cover declines in other fields, and come on line in 2014, with a capacity of 900 kbd.
But these new additions are required to offset the decline in existing fields, which have been somewhat protected from the severity of declining well production by the switch from vertical to maximum reservoir contact (MRC) wells. Although this conceals the depletion of the oil in the reservoir during normal production it does not, by itself, improve the ultimate production from the field, but rather can shorten field life, since these wells have proved to be more productive in rate. Nansen Saleri now appears to duck questions which ask if KSA can increase production beyond 10 mbd.
Within The Oil Drum (TOD) there has been considerable discussion over the rate at which well production declines, and the remaining reserve in the field depletes. One impact of the shift in wells from old established fields is that production from the average well will decline over time, a subject that Euan has visited in the past.
Figure 8. Individual oil well production values for Aramco (Euan Mearns)
It should be noted that the use of the submersible pumps are reported to have brought wells back to around 3,000 bd. But the move over to horizontal and MRC wells has slowed the impact of other changes in the country.
Nevertheless, after putting all this together, I re-iterate my conclusion from last time in that I doubt that KSA will increase production much above 10 mbd, (in June it was producing 9.888 or 10.103 mbd depending on source, and with the rising internal demands (domestic use in the Middle East is now projected to average 7.7 mbd in 2012) world markets will get tighter in the shorter, rather than the longer term.
Thursday, July 12, 2012
OGPPS - Saudi Arabia and what lies ahead
Saudi Aramco has stated that it designs the well layouts and extraction patterns from its oil fields so that they effectively decline at a rate of 2% per year.* If one divides 100 by 2 it yields 50. If one subtracts 50 from 2012, one gets the year 1962. Even to those with poor math skills, these are not difficult operations, and they lead to the conclusion that those fields that came into production in the early 1960’s and earlier are now reaching the end of their productive lives. They are not there yet, since production took time to ramp up, and some fields have been rested over the years, when production was cut back, or even mothballed. But it gives you some perspective on the overall scope of the situation, without the need for complex mathematical modeling.
Figure 1. Table of oil fields in KSA and their start dates
(* The IEA apparently believes that the figure is closer to 3.5%) (H/t Matt) Saudi Arabia states that, without using advanced recovery techniques and “maintain potential” drilling sites – often not in the same field as that being depleted – the rate would be 8%.(h/t Darwinian ).
In earlier production practices, where companies “stepped out” production wells away from the original producers, and in this way gradually extended the knowledge of the size of the field, reserve growth over time was a normal development. However, with the large size of the fields in Saudi Arabia, and the need to maintain operational pressure during production, Aramco (as JoulesBurn has clearly shown) rings their fields with water injection wells that drive oil to the central high point of the reservoir and slowly migrates the producing and injection wells towards that center as the field is drawn down. This practice precludes the incremental increase in reserves over time, since the field boundaries are constrained and as the wells reach the central part of the reservoir (the crest of the anticline) a clear definition of the closing days of the field becomes more evident.
At the same time it is worth pointing out that until fairly recently when Aramco were carrying out their “maintain potential” drilling they were merely drilling additional wells at 1 km spacing further down the reservoir. But when one moves from the perimeter of the reservoir to the crest, then there are no more places within that reservoir to continue the practice. Thus, in more recent years Aramco have offset declines in older reservoirs by bringing new fields into production. But, as the illustration below that JoulesBurn has provided for Haradh 3 shows, in the smaller reservoirs it is no longer possible to have the space for multi-year progressions of the wells across the field and thus, to sustain production new fields will have to be added to the network at more frequent intervals to sustain levels of production.
Figure 2. Planned well layout in Haradh III (from Aramco via JoulesBurn
Saudi reservoirs have also been large. This brings with it the need for large infrastructure to be in place not only to remove the oil, but also to separate the oil, gas and water (and occasional sand) that come out of the well, and to inject water into the reservoir to replace the oil and maintain the reservoir pressure that drives the fluid to the well. That infrastructure is tied to specific design flow rates and it is difficult to change the volume flow rates by significant amounts at short notice. Thus when a field, such as Abu Sa’fah, for example, is brought on line to produce 300 kbd, the plant is all designed for that flow and there is no immediate way to handle an increase in flow. Aramco can only, therefore produce, to the capacity of the infrastructure in place. It is this requirement and “step-function” nature of the additions to oil flow that provides some of the shape to the flow of oil in the region.
However, it is also a limitation, in that the two remaining large sources of crude oil that Saudi Arabia anticipates coming on line must wait until all the logistical handling is in place.
The first of these is the Shaybah expansion. Shaybah began with a production of 250 kbd, and has seen this progressively increased, first to 500 kbd, and then, in 2009, to 750 kbd.. The expansion requires that additional plant be installed to process the hydrocarbons produced which will include 264 kbd of NGL. The anticipated completion date is in 2014.
Manifa has been the more controversial of the fields in Saudi Arabia for some time. Although it has been known to exist for a long time (see above table) and was initially brought into production in 1964, it has never seen the major thrust to develop production that is now underway. There have been several reasons for this, the primary one being that KSA has never needed the production in the past to be able to meet anticipated demand. However there have also been significant questions as to the make-up of the oil, and its need for special treatment. In 2005 it was producing at around 50 kbd, back in the days when KSA was admitting to a decline rate of 6%. JoulesBurn has written about the controversy over the make-up of the oil, which is a heavy, sour crude containing vanadium. Regardless of the validity of those arguments, it does appear that the oil is now going to be fed, as it is produced, to two new refineries that have been planned in the Kingdom. These are at Jubail which is expected to be completed in 2013, and will handle 400 kbd of oil, and the second at Yanbu which, as of this year is being developed with Sinopec, ConocoPhilips having pulled out of the deal. That, together, comprises some 800 kbd of the 900 kbd of oil that Manifa is being developed to produce.
It is pertinent, relative to the opening comment, to note that this is the last large project that Saudi Aramco has reported to be on their books. If one were to accept that their real decline rate is some 3.5% then, at a production level of roughly 10 mbd a year, this would be reducing at 350 kbd per year. A 1.2 mbd addition to current production (Manifa and Shaybah combined) would thus only match just over three years of such a decline rate. For there to be new sources of production brought on line in the future, there must first be a considerable infrastructure put in place, and there does not, at present, appear to be any evidence of this, nor planning and bid documents being prepared for such an eventuality. Remember that Aramco began construction for Manifa in 2007, and it is still likely at least a year from major production.
To some extent this can be overcome by feeding new production from fields not now in production into the existing GOSPs and related facilities. But what that implies is that production will not grow beyond its current levels, which is around 10 mbd. Aramco have become very skilled at controlling water floods, enhancing production from existing reservoirs, and previously bypassed oil, but those wells can only be revisited a limited number of times. Because of the large number of highly productive wells that the country has, it is possible in the short term to raise production but that increase has to go through production facilities which are of only limited volume. Thus the increase can be of only a short duration, and as has been commented by others in the past few weeks, a system cannot be run at full production for long without problems developing. Further the underlying assumption that production declines can be offset by new production to hold depletion to 2% a year is really only true for the country as a whole, and individual decline rates for specific reservoirs have been reported to run between 6 and 8%. As there are become fewer large projects to provide the offset for such decline rates, then the impact of the greater values will become more evident. And so while I expect that the Kingdom will reclaim its position as leading oil producer before long, I continue to believe it will be because of a drop in Russian production, rather than a gain in that from the Kingdom.
(* The IEA apparently believes that the figure is closer to 3.5%) (H/t Matt) Saudi Arabia states that, without using advanced recovery techniques and “maintain potential” drilling sites – often not in the same field as that being depleted – the rate would be 8%.(h/t Darwinian ).
In earlier production practices, where companies “stepped out” production wells away from the original producers, and in this way gradually extended the knowledge of the size of the field, reserve growth over time was a normal development. However, with the large size of the fields in Saudi Arabia, and the need to maintain operational pressure during production, Aramco (as JoulesBurn has clearly shown) rings their fields with water injection wells that drive oil to the central high point of the reservoir and slowly migrates the producing and injection wells towards that center as the field is drawn down. This practice precludes the incremental increase in reserves over time, since the field boundaries are constrained and as the wells reach the central part of the reservoir (the crest of the anticline) a clear definition of the closing days of the field becomes more evident.
At the same time it is worth pointing out that until fairly recently when Aramco were carrying out their “maintain potential” drilling they were merely drilling additional wells at 1 km spacing further down the reservoir. But when one moves from the perimeter of the reservoir to the crest, then there are no more places within that reservoir to continue the practice. Thus, in more recent years Aramco have offset declines in older reservoirs by bringing new fields into production. But, as the illustration below that JoulesBurn has provided for Haradh 3 shows, in the smaller reservoirs it is no longer possible to have the space for multi-year progressions of the wells across the field and thus, to sustain production new fields will have to be added to the network at more frequent intervals to sustain levels of production.
Figure 2. Planned well layout in Haradh III (from Aramco via JoulesBurn
Saudi reservoirs have also been large. This brings with it the need for large infrastructure to be in place not only to remove the oil, but also to separate the oil, gas and water (and occasional sand) that come out of the well, and to inject water into the reservoir to replace the oil and maintain the reservoir pressure that drives the fluid to the well. That infrastructure is tied to specific design flow rates and it is difficult to change the volume flow rates by significant amounts at short notice. Thus when a field, such as Abu Sa’fah, for example, is brought on line to produce 300 kbd, the plant is all designed for that flow and there is no immediate way to handle an increase in flow. Aramco can only, therefore produce, to the capacity of the infrastructure in place. It is this requirement and “step-function” nature of the additions to oil flow that provides some of the shape to the flow of oil in the region.
However, it is also a limitation, in that the two remaining large sources of crude oil that Saudi Arabia anticipates coming on line must wait until all the logistical handling is in place.
The first of these is the Shaybah expansion. Shaybah began with a production of 250 kbd, and has seen this progressively increased, first to 500 kbd, and then, in 2009, to 750 kbd.. The expansion requires that additional plant be installed to process the hydrocarbons produced which will include 264 kbd of NGL. The anticipated completion date is in 2014.
Manifa has been the more controversial of the fields in Saudi Arabia for some time. Although it has been known to exist for a long time (see above table) and was initially brought into production in 1964, it has never seen the major thrust to develop production that is now underway. There have been several reasons for this, the primary one being that KSA has never needed the production in the past to be able to meet anticipated demand. However there have also been significant questions as to the make-up of the oil, and its need for special treatment. In 2005 it was producing at around 50 kbd, back in the days when KSA was admitting to a decline rate of 6%. JoulesBurn has written about the controversy over the make-up of the oil, which is a heavy, sour crude containing vanadium. Regardless of the validity of those arguments, it does appear that the oil is now going to be fed, as it is produced, to two new refineries that have been planned in the Kingdom. These are at Jubail which is expected to be completed in 2013, and will handle 400 kbd of oil, and the second at Yanbu which, as of this year is being developed with Sinopec, ConocoPhilips having pulled out of the deal. That, together, comprises some 800 kbd of the 900 kbd of oil that Manifa is being developed to produce.
It is pertinent, relative to the opening comment, to note that this is the last large project that Saudi Aramco has reported to be on their books. If one were to accept that their real decline rate is some 3.5% then, at a production level of roughly 10 mbd a year, this would be reducing at 350 kbd per year. A 1.2 mbd addition to current production (Manifa and Shaybah combined) would thus only match just over three years of such a decline rate. For there to be new sources of production brought on line in the future, there must first be a considerable infrastructure put in place, and there does not, at present, appear to be any evidence of this, nor planning and bid documents being prepared for such an eventuality. Remember that Aramco began construction for Manifa in 2007, and it is still likely at least a year from major production.
To some extent this can be overcome by feeding new production from fields not now in production into the existing GOSPs and related facilities. But what that implies is that production will not grow beyond its current levels, which is around 10 mbd. Aramco have become very skilled at controlling water floods, enhancing production from existing reservoirs, and previously bypassed oil, but those wells can only be revisited a limited number of times. Because of the large number of highly productive wells that the country has, it is possible in the short term to raise production but that increase has to go through production facilities which are of only limited volume. Thus the increase can be of only a short duration, and as has been commented by others in the past few weeks, a system cannot be run at full production for long without problems developing. Further the underlying assumption that production declines can be offset by new production to hold depletion to 2% a year is really only true for the country as a whole, and individual decline rates for specific reservoirs have been reported to run between 6 and 8%. As there are become fewer large projects to provide the offset for such decline rates, then the impact of the greater values will become more evident. And so while I expect that the Kingdom will reclaim its position as leading oil producer before long, I continue to believe it will be because of a drop in Russian production, rather than a gain in that from the Kingdom.
Friday, July 6, 2012
OGPSS - The "best of the rest" in Saudi Arabia
The discussion that swirls over the future of global oil supplies often seems to focus, from the side of those who suggest that there is no problem, on the large volumes of oil that still remain in place around the world. The critical point however is not that this oil exists, but rather the rate at which it can be recovered. This is perhaps most obviously pertinent to the discussion of the oil coming from the Bakken formation in North Dakota, where the rapid decline in individual well performance means that a great many wells must be developed and remain on line in the out years to sustain any significant flow past peak. It is a point that clearly was missed by Leonardo Maugeri, as I noted last week, and equally by George Monbiot, who has now finally been swayed to the side of the cornucopians, after years of doubt.
But the issue of individual well flow rates are an increasingly critical factor when future oil production in oilfields around the world are considered and this holds equally true when the fields in Saudi Arabia are discussed.
The history of oil production from Saudi Arabia has largely come from individual wells that produced in the thousands of barrels a day. In order to sustain that production over decades it has been necessary to ensure that the pressure differential between the well and the rock are sustained; that the rock has an adequate permeability to ensure that flow continues at a steady state; that the oil itself is of relatively low viscocity and is thus able to easily flow through the rock; and that there is a sufficient thickness and extent in the reservoir to allow such sustained production. All of those factors came together in the giant fields that provided high levels of production over many decades, most particularly in the northern segments of Ghawar.
Yet those conditions are less commonly congruent in the fields that Aramco must now move into to address the coming falls in production from the historic sources. These “best of the rest” (as the late Matt Simmons called them) that must now increasingly carry the burden of sustaining Saudi production fail, individually, on differing grounds from meeting those earlier parameters, but collectively, and in the face of Ghawar’s decline, they will only be able to sustain production to their original targets and will not be able to provide replacement production as the oldest and larger begin to fade. I would remind you of the curve that Euan put up back in 2007 .
Figure 1, Euan’s production estimates from 2007.
Euan’s overall estimates for total production have not been met, rather KSA chose to reduce the volumes that they provided to the world market in order to sustain a higher price for their product. (And I would note that it was their recent production of an increased flow into that market that provided the cushion for the rest of the world, so that it can view the current sanctions on Iran (which came into full force at the beginning of this month) with considerable equanimity – at least for the next few months. That supply has provided the backup as Iranian exports are reported to have already halved.(Now, if supply starts to get tight, it won’t be the fault of the KSA.)
But, in regard to the longer term question of total flow, will KSA increase their production to the 12 mbd that appears as some magic figure in the tables of the cornucopians as they look toward the end of the decade? I think not. Euan’s plot, if perhaps a little pessimistic over the rate at which Ghawar is declining is nevertheless true from an overall perspective of the changes that we can anticipate. Bear in mind that Aramco was only then moving to increase the size of their drilling fleet from historic levels of around 20 rigs to as many as 200 in the years since. And it is that change, with the underlying realities that it implies, that must be recognized when looking into the future.
As the largest fields are depleted, so production moves from them to smaller fields in the region. And as those fields are depleted production moves to yet smaller, and initially relatively uneconomic fields, that now have value. But to achieve the same production a greater number of wells must be drilled, as their individual production levels and operational lives are now shorter.
The Kingdom has been building production in a number of different regions over the past ten years. These have added considerably to overall Saudi capacity, but even if they are being drawn down at only 2% p.a. (as has been claimed in the past) that slow reduction makes it more difficult for them to be the source of additional production to meet any future increase in demand/replacement of depleted reserves. As I list the fields remember that when Ghawar‘s decline becomes evident these fields are already in production, and so it must be the smaller fields that lie beneath them in the hierarchy that will then have to carry the burden.
Qatif has been producing 500 kbd since 2004, from a field that started with a projected 6.2 x 31 mile size, with 151 development wells, and an 8.4 billion barrel reserve. Both it and Abu Sa’fah lie near Abqaiq and Berri.
Abu Sa’fah, which was expanded at the same time as Qatif, to 300 kbd is an offshore field that covers 6.2 by 11 miles and in the expansion had 90 wells and reserves of 6.1 billion barrels. (Half the revenue from Abu Sa’fah goes to Bahrain as JoulesBurn has explained and that arrangement continues with Bahrain getting the revenue from 150 kbd of oil.
Figure 2. The location of Qatif and Abu Sa’fah (JoulesBurn)
In 2007 Aramco brought 500,000 bpd of Arabian Light onto the market through the Khursaniyah development. (this included the onshore Abu Hadriya, Harmaliyah, and Fadhili fields) though it first began production at a lower volume in 2008. The associated gas plant ran through some troubles and delays before coming on line in 2010, and this also delayed the time over which the field came up to full production.
Down at the other end of Ghawar there are a group of oilfields found since 1967 including Hawtah and Nuayyim, in the Central Region. The group of fields, referred to as the Hawtah Trend or Najd Fields has had problems in the past with sand inflow into the wells, and there is some debate as to whether the reserves in the region total 10 billion or 30 billion barrels of light, sweet crude. Hawtah itself produces around 150 kbd, but the associated fields brought this up to 400 kbd.
Nuayyim came on line with an additional 100 kbd in August 2009.
Figure 3. Named Saudi fields, with those coming on line or expanded in 2009 being emphasized. (Energy-pedia )
But the issue of individual well flow rates are an increasingly critical factor when future oil production in oilfields around the world are considered and this holds equally true when the fields in Saudi Arabia are discussed.
The history of oil production from Saudi Arabia has largely come from individual wells that produced in the thousands of barrels a day. In order to sustain that production over decades it has been necessary to ensure that the pressure differential between the well and the rock are sustained; that the rock has an adequate permeability to ensure that flow continues at a steady state; that the oil itself is of relatively low viscocity and is thus able to easily flow through the rock; and that there is a sufficient thickness and extent in the reservoir to allow such sustained production. All of those factors came together in the giant fields that provided high levels of production over many decades, most particularly in the northern segments of Ghawar.
Yet those conditions are less commonly congruent in the fields that Aramco must now move into to address the coming falls in production from the historic sources. These “best of the rest” (as the late Matt Simmons called them) that must now increasingly carry the burden of sustaining Saudi production fail, individually, on differing grounds from meeting those earlier parameters, but collectively, and in the face of Ghawar’s decline, they will only be able to sustain production to their original targets and will not be able to provide replacement production as the oldest and larger begin to fade. I would remind you of the curve that Euan put up back in 2007 .
Euan’s overall estimates for total production have not been met, rather KSA chose to reduce the volumes that they provided to the world market in order to sustain a higher price for their product. (And I would note that it was their recent production of an increased flow into that market that provided the cushion for the rest of the world, so that it can view the current sanctions on Iran (which came into full force at the beginning of this month) with considerable equanimity – at least for the next few months. That supply has provided the backup as Iranian exports are reported to have already halved.(Now, if supply starts to get tight, it won’t be the fault of the KSA.)
But, in regard to the longer term question of total flow, will KSA increase their production to the 12 mbd that appears as some magic figure in the tables of the cornucopians as they look toward the end of the decade? I think not. Euan’s plot, if perhaps a little pessimistic over the rate at which Ghawar is declining is nevertheless true from an overall perspective of the changes that we can anticipate. Bear in mind that Aramco was only then moving to increase the size of their drilling fleet from historic levels of around 20 rigs to as many as 200 in the years since. And it is that change, with the underlying realities that it implies, that must be recognized when looking into the future.
As the largest fields are depleted, so production moves from them to smaller fields in the region. And as those fields are depleted production moves to yet smaller, and initially relatively uneconomic fields, that now have value. But to achieve the same production a greater number of wells must be drilled, as their individual production levels and operational lives are now shorter.
The Kingdom has been building production in a number of different regions over the past ten years. These have added considerably to overall Saudi capacity, but even if they are being drawn down at only 2% p.a. (as has been claimed in the past) that slow reduction makes it more difficult for them to be the source of additional production to meet any future increase in demand/replacement of depleted reserves. As I list the fields remember that when Ghawar‘s decline becomes evident these fields are already in production, and so it must be the smaller fields that lie beneath them in the hierarchy that will then have to carry the burden.
Qatif has been producing 500 kbd since 2004, from a field that started with a projected 6.2 x 31 mile size, with 151 development wells, and an 8.4 billion barrel reserve. Both it and Abu Sa’fah lie near Abqaiq and Berri.
Abu Sa’fah, which was expanded at the same time as Qatif, to 300 kbd is an offshore field that covers 6.2 by 11 miles and in the expansion had 90 wells and reserves of 6.1 billion barrels. (Half the revenue from Abu Sa’fah goes to Bahrain as JoulesBurn has explained and that arrangement continues with Bahrain getting the revenue from 150 kbd of oil.
Figure 2. The location of Qatif and Abu Sa’fah (JoulesBurn)
In 2007 Aramco brought 500,000 bpd of Arabian Light onto the market through the Khursaniyah development. (this included the onshore Abu Hadriya, Harmaliyah, and Fadhili fields) though it first began production at a lower volume in 2008. The associated gas plant ran through some troubles and delays before coming on line in 2010, and this also delayed the time over which the field came up to full production.
Down at the other end of Ghawar there are a group of oilfields found since 1967 including Hawtah and Nuayyim, in the Central Region. The group of fields, referred to as the Hawtah Trend or Najd Fields has had problems in the past with sand inflow into the wells, and there is some debate as to whether the reserves in the region total 10 billion or 30 billion barrels of light, sweet crude. Hawtah itself produces around 150 kbd, but the associated fields brought this up to 400 kbd.
Nuayyim came on line with an additional 100 kbd in August 2009.
Haradh has been discussed earlier as part of Ghawar, and the major addition that came that year was at Khurais, which added 1.2 mbd to supply potential. (Increase in production from Shaybah brought another 250 kbd to the total).
Khurais, was mapped by JoulesBurn in 2008, and it was here that the need for additional drilling rigs became more evident in getting all the wells brought on line in time for the scheduled start of the upgrade. With that completed, the increase (which actually comes from the three adjacent fields of Khurais, Abu Jifan and Mazalij) of 1.2 mbd began production in June 2009.
In terms of the production of the heavier oils that are taking a greater portion of the marketable Saudi product it has been suggested that KSA have planned to increase production at Zuluf, which has some 8 billion barrels in reserve, to a capacity of 1.2 mbd from 500 mbd (but with 200 mbd mothballed).
Up on the Kuwaiti border lies the Hout oilfield, where work is now being developed to capture increasing volumes of natural gas now flared from the field. This is one of the four fields that the two countries share, and which includes Khafji, Lulu and Dorra. Most of the oil goes to Japan. Khafji came on line in 1960, and Hout in 1963. The fields have produced around 4 billion barrels of oil, and are now producing at around 610 kbd. Bids for the new development are now due in September.
I will leave Shaybah and Manifa until next time.