OGPSS - The potential for Saudi EOR

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

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

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

Figure 1, Euan’s production estimates from 2007.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

OGPSS - conditions and treatments in North Ghawar

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

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

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

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


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


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

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

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

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

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

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

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

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

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

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

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

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

The OPEC view of world oil in May, 2012

It is interesting to read the viewpoint of OPEC each month, as it relates to global oil supply, and the numbers that they rely on to estimate how much production that will be required.  For 2012, for example, they now see no need to increase production above 30 mbd, (though it averaged 31.62 mbd in April, when NGL and non-conventional sources are included) with adequate production growth to meet demand (some 0.6 mbd) coming from non-OPEC sources that are anticipated to average 53 mbd this year.  At present supply is seen as exceeding demand, hence there has been an increase in global stocks which OPEC has noted. 

Figure 1. Quarterly world oil demand growth (OPEC May MOMR)

 The forecast by region is broken down, as follows:

Figure 2. OPEC Regional consumption forecast for 2012 (OPEC MOMR )

 However, while there appears to be relative stability in the market, this conceals the changes in internal consumption within the Middle East, that collectively effectively reduce the quantity of fuel that is available to the rest of the world, if their production overall remains flat.

Figure 3. Quarterly demand growth in the Middle East y-o-y changes (OPEC MOMR) 

 When sources for supply are examined, OPEC sees that the majority of the increase in supply will come from increases in North America. A further increase in production of some 0.66 mbd is anticipated over the production in 2011.

Figure 4. Anticipated non-OPEC production in 2012 (mbd) (OPEC MOMR) 

 Which, of course, brings up the question of the overall production numbers for OPEC. It is interesting to note that OPEC see that in April Iraq finally surpassed a production of 3 mbd, with a projected target of 6 mbd by 2016, and 10 mbd by 2018. (Iraq has not yet reached the 3.5 mbd levels that it achieved before all the conflict in the region, but hopes to soon surpass the 3.2 mbd that Iran is currently producing.)

Figure 5. OPEC production through April 2012 (OPEC MOMR) Information from secondary sources. 

 Of course, the increasing impact of sanctions on Iran, which is reported to have already cut exports from 2.2 mbd down to 1.7 mbd, contributes to the current drop in Iranian production. Whether those sanctions will toughen or lead to a resolution of the crisis is still one of those hanging questions . . . . Interestingly OPEC puts up two versions of the table shown in Figure 5, that above, which comes from secondary sources, and a second version that is generated from direct communication. The numbers for Iran and Iraq are notably different.

Figure 6. OPEC production through April 2012 (OPEC MOMR) Information from direct communication. 

 Tehran, which provided the information for the latter table, is also now citing it in their press together with claims that they will be able to increase production by 1.5 mbd by 2016. Hmm! Well we will look at Iranian production after finishing the review of Saudi Arabia. Looking at all liquids, OPEC sees the world supply holding relatively steady, while OPEC has been steadily increasing production, a slightly different message from that of the summary at the top of the document.

Figure 7. Contributions of OPEC countries to overall global oil supply (OPEC MOMR ) 

 The impact of the oil sanctions on Iran can be expected to bite with increasing strength over the next two months, and it will be interesting to see how the market responds. There is evidence, cited earlier, that there has been some pre-positioning of additional supplies around the globe to help with offsetting the loss of the Iranian oil, and with the potential to release national reserves to alleviate problems. These are interesting numbers to watch, and so I will continue to monitor them in the months ahead. The decline in overall demand for OPEC oil, which the report sees can be anticipated to be due, in large measure to the increase in production from North America. How accurate that prediction will be over the year is an interesting topic for study.

Figure 8. OPEC view of the crude oil balance between supply and demand for 2012 (OPEC MOMR )

A short break

I will be traveling somewhat extensively over the next few days, and therefore crave your indulgence in that there will be no new posts until after the 21st of May.

I should then be able to rejoin the tale of the Saudi oil production, projections of our future energy supplies and the other topics which you have, from time to time, found of interest.

Best Wishes in the meantime

Dave

OGPSS - a little more detail on hydraulic fracturing

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

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

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

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

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

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

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


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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Flaring and the Siberian temperature profiles

After I had drafted the following post I initially put it on the shelf, since the idea that the gas flares would have an impact over such a large area began to seem a bit of a stretch. But then, in the last week a new paper has been published in Nature and been commented on by both Roger Pielke Snr and Watts Up With That. Simplistically it finds that the actions of the wind turbines in Texas have caused a temperature change of 0.72 degC per decade due to the way in which the turbines modify atmospheric behavior. Wikipedia notes that Texas has an installed capacity of 10,377 MW, nameplate, and generated 6.9% of the electricity in that state in 2011.

 Russia has been flaring up to 50 billion cubic meters of natural gas a year. If a cubic meter of natural gas contains 37 Megajoules of energy and Russia is burning 50,000,000,000/365/24/3600 = 1,585 cu m/sec this is equal to 58,600 MW – six times the size of the nameplate Texas wind farms, recognizing that flaring goes on 24-7 while the wind turbines are much more intermittent. So it seems the topic has more validity than I might have thought, but is there an effect? If one looks at the global temperature maps that are issued by the Goddard Institute for Space Science (GISS) there is a consistent trend in those, which indicates the much higher temperatures that are found in Northern Russia and Siberia. These high temperatures are a significant contributor to the overall analysis that the average global temperature has been rising for the past 40-odd years.

Figure 1. GISS reported temperature anomalies for Feb 2012.

 Being as I am a curious person, I looked at the temperature record that GISS reports for Khanty-Mansiysk, (K-M) which became a city some 40-years ago, with the growth of the oil industry in the neighboring Samotlor oil field. The city is found at 61 deg N 69 deg E, with an elevation of 190 ft. (According to Google Earth). GISS has the town named as Hanty-Mansijs and gives the temperature history as:

Figure 2. Temperatures for Khanty-Mansiysk as reported by GISS.

 I will forego for now the adjustments that are made by GISS to the original data. In these regions this was recently covered by Paul Homewood at WUWT and I have written similarly on the adjustments that GISS consistently makes to individual state temperatures in those posts listed to the right hand side of this page. However this got me a little curious, given that the rise in temperature shown occurs in a region where there has been a considerable amount of gas flared, as I have commented earlier. The amount is in the range of 24 billion cubic meters a year in the region of Khanty-Mansiysk alone (half the Russian total), and I have used this illustration from the world bank of the thermal plumes that they generate.

  Figure 3. Thermal plumes from gas flares in Siberia

In more recent times there are new fields being developed in Eastern Siberia and up in the Yamal, many of whom cannot as yet pipe their natural gas away. As a result it is still being flared, and I have become curious if we could correlate any of the increase in Siberian temperatures with the increase in Russian flaring of natural gas. So, in a way reminiscent of the work I did on US state temperatures, I have downloaded the data from GISS on the 32 stations that lie within a thousand kilometers of Kanty-Mansiysk to see what they show, Some stations have incomplete data, and so I don’t know what I will find as this post starts to look into the data set. First, just out of curiosity I took the average value for the stations over the years, and plotted it against time.

Figure 4. Overall average temperature for the GISS reported stations within a thousand km of Kanty-Mansiysk 

 While there is a relatively constant range until about 1960 it seems (just by eyeball) that the temperature starts to pick up thereafter. Which is where it is important to note that this was about the time that oil production in the region began to pick up. To re-iterate that plot from the discussion of Western Siberian production.

Figure 5. The oil and gas fields of Western Siberia (after Grace – Russian Oil Supply) 

 Thus, just about the time that the temperatures in the region began to pick up, so the wells were being sunk, and the gas flared, from the production. So there is a little bit of a coincidental timing here. But that does not necessarily mean that there is any interaction other than co-incidence at this point in the story. But what it allows me to do, for the moment, is to truncate the data sets that I am looking at and confine them to post-1970. And, just for curiosity, I am going to use a 2nd order polynomial for the trend line for the overall data – to see what it might be doing other than just increasing.

Figure 6. Average Western Siberian temperature – post 1970 

 Now what is interesting about this is that there is a little bit of a fall-off as suggested by the trendline. This could very well be because of the sun output changing, or a variation in GHG levels – though those have continued to increase. Alternately it could also be because of the campaign by the World Bank and the Russian Government, which is causing the Russian oil companies to increasingly capture the gas and either re-inject it or pipe it to a commercial source, rather than just flaring it. (And though the number of wells is increasing as the supply diminishes the effect on gas flared is not absolutely defined). 

 So how do we proceed from here? Well if the cause is the flaring, then it should be more of an impact down-wind of the fields rather than up-wind (as the GISS plot would suggest it is). So for each of the stations I am going to (as a simplified test) put a linear trend line through the post-1970 data and determine the slope. Then I am going to plot the slopes as a function of latitude, and longitude, with the location of Khanty-Mansiysk marked on the plots. For example, here is the data for K-M:

Figure 7. Average post-1970 temperatures for KM as reported by GISS 

 The slope of the temperature curve is 3.42 degC per century, so let me get all the data and see what it says:

Figure 8. Average station temperatures (blue over the full record, red post 1970) as a function of Longitude with K-M located at the blue line. 

 Not sure that this tells a whole lot, so let’s look at the average temperature rate of increase for those stations, post 1970:

Figure 9. Average rate of temperature change as a function of longitude – post 1970 and with K-M marked at the blue line. 

 Well apart from two stations there does not appear to have been much change as a function of longitude. How about latitude?

Figure 10. Average station temperatures (blue over the full record, red post 1970) as a function of Latitude with K-M located at the blue line. 

 Interesting in that the average temperatures seem higher at lower latitudes than higher - which would seem to argue against the GISS graph at the start of this piece, and there is the thought that the values that I am using are post-adjustment by GISS so they may have corrected for something I have missed.

 But then there is the plot of rate of temperature increase as a function of latitude:

Figure 11. Average rate of temperature change as a function of Latitude – post 1970 and with K-M marked at the blue line. 

 Hmm! Apart from the increase in the station almost immediately north of K-M and the slight increase in slope as one moves further North past K-M, which may or may not be significant, there is not a lot of immediately obvious answers in the data. Ah, well not every conjecture works out, though I would still like to compare the raw data instead of the modified. And there is still that very dark red plume down-wind of K-M to explain . . . . .