Showing posts with label EOR. Show all posts
Showing posts with label EOR. Show all posts

Thursday, May 31, 2012

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.

Read more!
Posted by Heading Out at 10:09 PM 5 comments
Labels: , , , , , , ,

Thursday, May 24, 2012

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.

Read more!
Posted by Heading Out at 8:57 PM 0 comments
Labels: , , , , , , , ,

Sunday, May 29, 2011

OGPSS - Chemical floods to enhance oil recovery

Before returning to look at the larger oilfields in the United States, I thought to describe ways of increasing the oil produced from the stripper wells that I mentioned last time. It seems appropriate to tie this to the time that I am writing about Texas, since some 41% or so of marginal oil well production comes from that state. And I would acknowledge again the help of the Stripper Well Consortium.


In the main, as Rockman has pointed out, the economics of production severely limit the options for increasing the flow of oil from these strippers. However changes in market price, and the reduction in costs of some of these treatments can make enhanced oil recovery (EOR) techniques worthwhile. And, even if not presently economic, as research studies ways of lowering the cost, driven in part by the size of the market, and the need for oil, so the likely increase in the price of that oil will change the economics in a positive (for the well owner) direction. This post is therefore going to look at the use of chemicals to stimulate enhanced oil recovery with a particular thought for stripper wells.

As an example I am going to consider the Lawrence field on the Illinois side of the Illinois:Indiana border, since this is part of an ongoing project.

Location of the Lawrence oil field in Illinois (Rex Energy )

The field had, by 1950, peaked and was in decline. However by waterflooding the field at that time, generally recognized as secondary recovery, the water displaced the oil, while maintaining pressure in the reservoir as fluid left, thus increasing production. though that too then began to decline.

Production from the Lawrence field in Illinois (DOE )

Some time ago Stuart Staniford explained some of the problems with a water flood, in terms of ultimately recovering all the oil from a formation.. The post itself deals with what is going on in the Ghawar oil field in Saudi Arabia, but, to understand that, one has to understand a little of the physics of fractional flow in a multi-phase fluid. And so he provided that explanation, which I am now going to borrow:
if there is 10% water and 90% oil in a particular volume of rock (.........), then a well into that part of the rock would be receiving 10% water and 90% oil. Similarly, an area with 60% water and 40% oil might be producing at 60% water cut into a well into that area. However, this is not so: the difference is much more dramatic than that. The reason has to do with the physics of two phase flow in a permeable medium. If you want a mathematical treatment, try this, but let me try to illustrate the basic idea.

In a set of interconnected pores through which oil and water are being forced at pressure, the flow is too turbulent for large areas of the two fluids to separate out from one another. And yet, oil and water do not like to mix, and will tend to bead up in the presence of the other. If there is only a little water and a lot of oil, then the oil will form an interconnected network of fluid throughout the rock pores, whereas the water will tend to make small beads within the oil. Conversely, a little oil in a lot of water will result in a network of water throughout the rock, and small beads of oil within that network. Now, in either situation, the fluid that is interconnected can flow through the rock without making any change in the arrangement of beads and surfaces between oil and water. However, the fluid that is beaded up can only move by the beads physically moving around, and they are going to tend to get trapped by the rock pores.

So for this reason, in a mixture of almost all oil, the water cannot flow at all. Conversely, once there is almost all water, the oil cannot flow at all (which sets an upper limit on the amount of oil that can ever be recovered by a water flood). In between, there is a changeover in which the proportion of oil flowing to water flowing changes much more rapidly than the changeover of the actual mixing ratio. The curve that describes this is called the fractional flow curve.

For example, the tutorial I referenced earlier shows this picture for a typical fractional flow curve:

"Typical" fractional flow curve (from this tutorial). Fw is the fraction of the flow out of the well that is water, i.e. a value of 1 is sensibly 100%.

So the way to read this is that when we are below 20% on the X-axis (less than 20% water in the oil), there is zero (water flow shown Ed) on the y-axis (the water will not flow through the rock at all). As we get above 20% water saturation, the flow of water increases rapidly, until above 80% water, there is no flow of oil at all. In the linear region at the center of the curve, the slope is about 3.6. That is, each 1 percentage point increase in water saturation results in a 3.6 percentage point increase in water flow in the rock.
Now this is not absolutely true, in that the mechanical motion of the water through the rock will drag a small fraction of oil along with it. Thus, at flows above 80% there will still be a small amount of oil that comes out with the water.

The amount of water that comes out of the well, as a percentage of the total flow, is known as the “water cut.” (And the obverse, or oil percentage is referred to as the “oil cut".) In Illinois the wells in the Lawrence field are running at a water cut of 98%. In other words for every 100 barrels of fluid pumped out of a well, only 2 barrels will be oil, and that must be separated from the water. In Saudi Arabia one of the characteristics of production that initially caught Matt Simmons attention was that the oil had a water cut of around 30 – 35%. But I’ll leave that issue to another day – though in passing, if you haven’t read Stuart’s post in it’s entirety (and the debate between him and Euan Mearns on Saudi productivity) it is well worth taking the time to do so.

What I want to return to for today is the remaining oil in the field. To put it simplistically, under normal conditions that oil is attached to the particles of rock in the formation, and the water flowing past only marginally can dislodge it and carry it to the well (hence the low oil cut numbers). Now if the chemistry of the oil could be changed, so that, for example, it did not cling quite as strongly to the rock, and, at the same time the viscocity of the oil was reduced, so that it would flow more effectively, then perhaps the water could carry a higher percentage of the oil away, increasing not only the oil cut, but also the total amount of oil that could be economically recovered from the wells. (This might also require getting the oil into an emulsion with the water).

There are a number of different techniques and fluids that can be used to make this work. The idea is not new, and back in the ‘80’s the hot topic was “Micellar flooding”, although it, and its cousin ASP flooding, have not been that successful – in the United States.

Production from chemical flooding of oilwells in the USA. (Dr. Sara Thomas*)

The letters that make up ASP stand for alkaline, surfactant and polymer. Generally the chemicals are injected as a slug, or a series of slugs, into the water injection well (s) and then pass through the formation to the collection wells, being pushed through by subsequent injections of more water.

The first of these, the alkaline chemical (think caustic), is aimed to mix with the oil and lower its bond attachment (the interfacial tension) between the oil and the rock so that it can be removed more easily. By itself, however, it does not seem have that great a level of success in improving oil cut, but it sustains the flow of the oil for a longer period.

Alkaline - polymer flood of the David Field in Alberta (Dr. Sara Thomas*)

The S in ASP stands for surfactant, and this acts in much the same way as does the alkali in changing the adhesion of the oil, but acts more as a soap in helping to break the oil free. It has been shown to be more effective as a tool for improving recovery than the alkaline solution.

Effect of a surfactant flood on well performance and oil cut – Glenn Pool Field OK (Dr. Sara Thomas*)

The polymer can either be used to thin the oil, so that it is easier to move, or to thicken the water so that it adds a more effective drag to move the oil. The benefits of this can be seen from a trial at the Sanand Field in India. Note that it also provides a more sustained effect.

Effect of injecting a polymer slug to enhance oil recovery (Dr. Sara Thomas*)

While each of these individually provided some gain, the impetus at present is to combine them in consecutive slugs (hence the acronym) and the benefit can be seen from the sustained improvement in oil recovery. (As you will note from the dates, this is not a totally novel concept).

EOR from a field in Daqing, China after an ASP treatment (Dr. Sara Thomas*).

And here is a different example from Tanner, WY.

Change in oil cut and monthly oil production following an ASP flood in Tanner, WY (Oil Chem technologies ). The cost per incremental barrel including chemical and facilities was estimated at $4.49.

With this understanding of the background to the potential use of the ASP treatment, lab tests have shown that it might be possible with this technique to recover an additional 130 mbbl from the Lawrence field. (Until now it has produced a total of 400 mbbl). The potential, if the technology can be proven to work is quite significant.

Potential additional oil that can be recovered if Chemical EOR is successful (Dr. Sara Thomas*).

The big question, that I included in my second paragraph, and that Rockman, (our resident realist) reminds us of, is the need for this to be a significant cost benefit to the operator before it will be implemented. Technically chemical floods can increase the oil cut from 1 to 20% of the flow, but in the earlier tests the chemicals used cost more than the oil recovered. It is not a simple process, since it depends on the rock geology to ensure that the chemicals have the proper access to, and path from the oil in place. And the additional services to ensure this also cost. Lawrence was the site where Marathon tried using chemical EOR in the past and achieved the technical success of increasing the oil cut to 20% from 1%) but it was uneconomic. With the new program Rex Energy are reporting, in their first quarter report, that the program is successful so far.
We are seeing positive results from the Middagh ASP project area with increasing oil cuts and oil production. . . . . . . . . . . . .

As a result, we have the confidence to increase our capital budget for the ASP program by $3 million to fund the larger 58-acre ASP project in the Perkins-Smith area. Results from the Middagh ASP are being analyzed to maximize oil recovery in the Perkins-Smith Unit. ASP injection on the Perkins-Smith Unit is expected to begin during the fourth quarter this year following brine water injection, which we expect to commence shortly.

The program is an area of considerable interest for the Stripper Well Consortium to whom I am indebted for some of the information in this post.

I would close, however, with a slide from Dr. Thomas’s presentation:

The growth of oil produced by chemical EOR (ASP flooding etc) in China (Sara Thomas)

* The graphs identified as “Dr. Sara Thomas” were taken from the SPE Distinguished Lecturer Series 2005 – Dr. Sara Thomas “Chemical EOR – the Past, Does it have a Future?” (Abstract here )

Read more!
Posted by Heading Out at 8:01 AM 1 comments
Labels: , , , , , , , ,

Wednesday, March 10, 2010

Carbon Sequestration sites and their success

There are a number of questions on the ease with which carbon dioxide can be sequestered underground, and I alluded to some of them in yesterday’s post. That led me to a quick review of the status of the concept, and I thought I would pass on information from some of the papers that I looked at. Some of the different options that can be used for carbon dioxide injection underground are illustrated by a review of the Polish program.

Different options for carbon dioxide disposal underground.

Of these the use for enhancing oil recovery has, perhaps the longest history. Some sense of the work can, perhaps, be seen by looking at CO2 injection at the Cranfield site in Mississippi.


The site is in an oilfield that was discovered in 1943, and abandoned in 1966. Since that time, under the influence of a strong aquifer drive, it has returned to its original reservoir pressure. There is a layer of residual oil, under a gas cap..

Section through the Cranfield site

The site is actually a dome, folding in both directions, so that the residual oil forms a ring. It is a part of the Tuscaloosa Formation, which MIT has calculated should be able to retain some 10,000 million metric tons of CO2. Adjacent continuations in East Texas and the Gulf would add an additional 187,000 million tons of capacity. Validation of the performance of the test site would thus go a long way to answering some of the critics of the technology. Because of the limited volume of oil available, the project is also looking into injecting CO2 into the brine interval during the third phase of the program.

At Cranfield the CO2 has been injected continuously, starting in July 2008, at a rate of 500,000 tons per year. so that, as Professor Economides discussed, the injection pressure remains high. At present the analysis of the samples shows little change in the water chemistry as a result of the injection. Last November it became the fifth site in the world to store more than a million tons of CO2. Monitoring of the pressures as the third stage has begun, does show a pressure increase, although this may be injection rate sensitive.


Monitored pressures for Cranfield 3 (U of Texas)

A second site is being prepared in Alabama at the Citronelle oil field, near Mobile. Both carbon dioxide and water will be injected at that site, with the intent that the CO2 will allow an additional 15 to 20% increase in overall production from the field, before the site is left to sequester the CO2.
In the United States, CO2 injection has already helped recover nearly 1.5 billion barrels of oil from mature oil fields, yet the technology has not been deployed widely. It is estimated that nearly 400 billion barrels of oil still remain trapped in the ground. Funded through the D.O.E.'s Office of Fossil Energy, the primary goal of the Citronelle Plan is to demonstrate that remaining oil can be economically produced using CO2-EOR technology in untested areas of the United States, thereby reducing dependency on oil imports, providing domestic jobs, and preventing the release of CO2 into the atmosphere. . . . . . . When the 5-month injection is completed, incremental oil recovery is anticipated to be 60 percent greater than that of conventional secondary oil recovery by water flood. A recent study by Advanced Resources International of Arlington, Va., estimates that approximately 64 million additional barrels of oil could be recovered from the Citronelle Field by using this tertiary recovery method.

In the last Oil and Gas Journal survey (April 2008) they found 100 miscible ongoing CO2 projects and 5 immiscible ones, with enhanced oil production, at the beginning of 2008, running at 250,000 bd.
Costs for CO2 EOR have been given as $20.86 boe, divided out as follows:
* $3.68/boe for CO2.
* $5.72/boe for power and fuel.
* $3.34/boe for labor and overhead.
* $2.00/boe for equipment rental.
* $1.36/boe for chemicals.
* $3.05/boe for workovers.
* $1.71/boe for miscellaneous.

One of the Centers most active in the monitoring of CO2 plumes as they migrate from the wells out into the formation is at the University of Texas-Austin. Sue Hovorka, for example, monitored a CO2 plume migration after it was injected as part of a test in the Frio Blue sand, although in that test the injection was of the gas.
Several times a day during injection, trucks hauling 20-ton tanks of cold liquified CO2 arrive at the test site, where it is transferred to two 70-ton storage tanks. The CO2, which comes from a natural reservoir near a Mississippi salt dome, is transported most of the way by train.

During injection, the liquid CO2 is pumped through a heat exchanger, which warms it up to 21 degrees C (70 degrees F), converting it to a gas. Then it is pumped through the injection well head and a mile down the well. The CO2 enters the porous sandstone and brine through perforations in the well casing and spreads out in a plume.
She also described, briefly how the process was supposed to work.
Before the first tests, the scientists had predicted that an effect called residual saturation, caused by capillary forces, would cause the brine-filled pores in the stone to trap and hold about 20 percent CO2. The other 80 percent moves on to the next set of pores, and as it moves, it’s continuously diminished. In other words, the plume smears out. Hovorka said the effect is intuitive.

“It’s the same reason you can’t get grease off the stove,” she said. “You can’t wash it loose with water, you have to use soap.”

The 2004 test confirmed this prediction and now initial results from the 2006 test seem to reconfirm it. “It means we got the physics right,” said Hovorka. It also means she and her colleagues can predict the CO2-trapping ability of other sites before injection begins, a powerful and necessary tool for carbon sequestration to become a common practice.

Polish trials have looked at displacing natural gas with CO2 in a program that has been going on for over 12 years Part of the process at the Borzecin site was to inject the gas into the underlying aquifer beneath the natural gas pocket. The CO2 dissolves into the water and so the migration to the gas pocket occurs only very slowly, the gas is at 1,500 psi (just above the critical pressure) when it enters the reservoir). The gas displaces natural gas that had previously been dissolved in the aquifer, yielding about 60% of the injected volume of CO2, as natural gas from the production wells.

One event that this test showed, which perhaps Professor Economides had not considered is that the dissolved CO2 appears to have interacted with the water, over time, to form a carbonic acid, that ate into the carbonate rock, and increased the permeability of the formation, lowering the pressure required for injection, rather than, as he had anticipated, having it rise. The site has now accepted more than 1.4 million scm.

CO2 has also been tested as a means of displacing methane from unmined coal seams. The initial project was completed in 2005
During the project 203 tonnes of CO2 were supplied to the site and stored in tankers. The CO2 is taken from the tankers where it is already stored under pressure and then injected at the injection well (MS-3 well). The injection well was a new well drilled down to a depth of 1120m for the purpose of this pilot project. The target seams were thin coal layers that were bounded (above and below) by highly impermeable shales. The pre-existing coal bed methane (CBM) production well (MS-4) is 150m from the injection well. A tank by the production well stores the saline water which is a by-product. This is emptied and disposed of on a weekly basis. The produced gas (naturally - 97% methane, 2% CO2) is flared. Since December 2004 there has been a gradual rise in CO2 content of the produced gas, the latest figure is 8% which may represent breakthrough of injected CO2 at the production well.
Modeling of the process is not yet fully functional, and in contrast to the more conventional reservoirs for oil and natural gas, the large fracture patterns in coal, known as cleat, play a greater part in the performance of the coal beds and must be included in the analysis.

Nevertheless the tests of the different methods for storage, and use of CO2 injected into the ground have been successful. The most widely recognized, however, is that carried out by Statoil, with Sleipnir the most documented. By 2004 Sleipnir had been injecting CO2, which is produced at an unacceptable 9% in the natural gas extracted at the site, at a level of a million tons a year, since 1996. Because of the length of time that the injection had occurred it has been possible to map the migration of the CO2 over that time. The initial injection is at a depth of 1,000 m below sea level.


Pattern of CO2 injected flows from the injection well at Sleipnir after 3 years

If I read the plots correctly the injection point is aligned with the deepest point in the picture and the flow path is about 2 miles long on its greatest extent.

The site continues to be monitored, as injection continues, with migration being downward under the containment of the cap rock.

Seismic surveys of CO2 migration at Sleipnir

It is expected that the CO2 will slowly dissolve into the brine (over hundreds of years). The scale of the above is exaggerated vertically since the height of the plume is around 600 ft.

The success of the program has led to the Snohvit Project which again takes the CO2 from a natural gas supply (in this case at 5% CO2) and stores it underground.

The success of these projects, and the changes in conditions from the simple models initially assumed to the more complex considerations that have had to be undertaken as the storage has continued to accept high levels of CO2 in some cases, and only high injection rates in others, nevertheless combine to suggest that Professor Economides models may be overly conservative.

Read more!
Posted by Heading Out at 2:23 PM 2 comments
Labels: , , , , , , , , , ,

Monday, December 14, 2009

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.

Read more!
Posted by Heading Out at 4:00 PM 8 comments
Labels: , , , , , ,

Wednesday, April 8, 2009

2009 Energy Conference - Meeting the growing demand for liquids

The third session of the conference dealt with either electrical power generation or transportation fluids. In reality that meant, for the second topic, that the topic was crude oil. Moderated by Glen Sweetnam the panel included Eduardo Gonzalez-Pier of PEMEX, DavidKnapp of the Energy Intelligence Group and Fareed Mohamedi of PFC Energy.

The panel moved around the world looking at the prospects for increasing production from the major producers of oil, dividing them into those whose production can be anticipated to increase, and those who are known to be declining in production. The list of those increasing included the USA, Saudi Arabia, Brazil, Canada, Algeria, Nigeria Iraq and Kuwait. For those who are wondering if time has moved backwards, or question whether the world has changed enough that this site is no longer dealing with a real concern – the anticipated increase in production in the United States is relatively small and transient. It is coming from the increase in production that is being achieved by the rigs in the deep water of the Gulf, and is sadly not going to take us back to the days when the country produced more than anyone else. The panel also looked at the change in the nature of production since IOCs were replaced in the scale of greatest production by NOCs. The panel did not seem to feel that this would, in itself, make much difference since, in the end, as oil fields decline the NOCs would have to engage with the IOCs in order to acquire the technology (see closing story at the end of the post) that would allow them to enhance recovery from their remaining reserve.


I started out in the other panel (which was talking about transmission lines) and did not come into the room until they were talking about Mexican production. I did not initially know the background of the speaker, (it was Eduardo) who, shortly after I arrived, commented that Pemex expected to stabilize production at existing levels for the next several years. He and the other two speakers talked about the increase in production from KMZ that would offset the Cantarell decline, and that there would be the longer term production from Chicontepec that would continue this stable production for the next few years. Somehow my concentration wandered after this, and so my reporting on this session (that occurred just after a brisk walk and lunch) may be a little less that all that was said.

The panel opinion on Venezuela was not promising (pessimistic was the word used) with significant questions on sustainability, although there is the hope that the majors would be reinvited back with renegotiations to bring production back to a more reasonable level. (Taken with the discussion on Mexico this also encouraged me to enter a dream-like state).
They generally viewed Brazil, and Petrobras, as a success. Nigeria was described as a failed state, though there were some attempts to distinguish the success of some of the production from the troubles that were occurring because of the insurrection in the country. Looking at Algeria the debate focused on the natural gas business and there was some debate on the hydrocarbon law in that country.

Libya is a different case. Having grown accustomed to a lack of external funds and lower levels of income, the country is quite able to weather the current cut back in oil prices and the Government has enough revenue at the moment and thus is not under pressure to export more. Because of a lack of investment over the past decades, the opportunities to increase production, particularly through secondary and tertiary recovery is considered gigantic, and thus the overall view of Libyan production has to be optimistic. (It is interesting to note that China is reported to be going after the Canadian interests in Libya).

Looking at the countries of the Middle East, Iraq and Kuwait can be expected to remain relatively stable in production, though with some potential for increase. However, as with a countries in the region, the questionability of the reserve values quoted keeps coming up. (In a later question the panel felt no compunction in accepting Saudi figures for their reserves and had no concern that the values had not changed over the years. They did recognize, however, that in contrast to other countries in the Middle East they counted proved and probable in reserves, not just proved). Kuwait is “muddling through.” The damage done to the Burgan field by the Iraqi army in their retreat after the first Gulf War did more damage to the field than was at first realized. Instead of this being a field that produced under its own pressure, pressure now has to be supplied to the field to get the production out, and this has opened a need for new technology that has not yet been realized. Kuwait can, however, live on $20 oil prices.

But once one has gone through these producers, with their limited capacities to increase production, then all the other countries that were considered are in decline. They were, for example, somewhat more pessimistic than I expected about future Russian production. They felt that the inability to develop in a timely fashion some of their Eastern fields was now hurting, though their recent willingness to work again with the majors (for example Shell in their recent production) may denote a change in attitude. There is just not much happening in Central Eastern Siberia, and while they just shipped (April 1) the first LNG cargo from Sakhalin Island, it is a bit of a stretch to see overall production increasing given the declines in some of the mature fields. Although they were reassured that Statoil is going to be working with Shtokman overall they felt that the atmosphere over there was still somewhat poor for investment. Financial pressures may also act as a lever to induce change, but with the example of Gazprom held up before us, there was not a lot of optimism.

China was considered to be an interesting case, since all the news of developments from the west has gone silent, and the thought is that perhaps there are some problems with the geology in those fields, and the group would be surprised if grown was reprised in that area of the country. There was some optimism expressed, however for the chance of improving the natural gas position, particularly perhaps with coal bed methane (CBM).

Looking at Kazakhstan, this may be a country with some potential for the future, but with pipelines taking that future to China and Russia and the country having borrowed a great deal when oil prices were higher, that promise is likely to end up in one of those two countries. There is apparently some problem between the Kazakhs and the Russians.

The volumes of additional gas that have become available through the technologies that are being applied in the Barnett Haynesville and the other US gas shale deposits may also change the reserves in other countries. The panel felt that there should be some production become available in China and in Europe as a result of such fields, but the size of that gain is not yet evident, since no-one has probably yet gone and looked.

The longer term outlook for Saudi Arabia is difficult to tell, since it all depends on the succession to the king, and that is a bit of a worry, but there is so much geopolitical froth in the air, that it is hard to see the actual current situation.

In developments since the paper, and relative to the need to find new technology, I notice that PEMEX is talking of a new technology to get some additional production from Cantarell. In this idea a foam will be injected into the formation and will displace any remaining oil, with the hope of recovering an additional 3 billion barrels from the reservoir. It is a technology being developed at CSM, Stanford, the U of Texas and the University of Houston. While injecting carbon dioxide reduces viscocity and adhesion of the oil, it does not work well in providing a mechanism to move the released to to the well, and the original mechanisms have been weakened due to the water flood. In this technique the foam acts to provide that sweep mechanism.


Read more!
Posted by Heading Out at 11:17 PM 2 comments
Labels: , , , , , , , , , ,
Subscribe to: Comments (Atom)