FRACTIONAL FLOW

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Norwegian Crude Oil Reserves And Extraction per 2016

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In this post I present actual Norwegian crude oil extraction and status on the development in discoveries and reserves and what this has now resulted in for expectations for future Norwegian crude oil extraction.

This post is also an update of an earlier post about Norwegian crude oil reserves and production per 2015.

Norwegian crude oil extraction peaked in 2001 at 3.12 Million barrels per day (Mb/d) and in 2016 it was 1.62 Mb/d, growing from 1.57 Mb/d in 2015 and 1,46 Mb/d in 2013 (a growth of 10% since 2013).

The Norwegian Petroleum Directorate’s (NPD) recent forecast expects crude oil extracted from the Norwegian Continental Shelf (NCS) to become 1.60 Mb/d in 2017.

Figure 01: The chart shows the historical extraction (production) of crude oil (by discovery/field) for the Norwegian Continental Shelf (NCS) with data from the Norwegian Petroleum Directorate (NPD) for the years 1970 – 2016. The chart also includes my forecast for crude oil extraction from discoveries/fields towards 2030 based on reviews on individual fields, NPD’s estimates of remaining recoverable reserves, the development/forecast for the R/P ratio as of end 2016.
Further, the chart shows a forecast for total crude oil extraction from sanctioned discoveries/fields (green area, refer also figure 02) and expected contribution from Johan Sverdrup phase I (blue area) [at end 2016 estimated at 1.78 Gb; [Gb, Giga (Billion) barrels, refer also figure 07] and this development phase is now scheduled to start flowing in late 2019.

Sanctioned Developments in Figure 01 represents the total contributions from 7 sanctioned developments of discoveries now scheduled to start to flow between 2017 and 2019.

My forecast for 2017 is 1.51 Mb/d with crude oil from the NCS.

My forecast shown in figure 01 includes all producing and sanctioned developments, but not contingent resources in the fields (business areas). The forecast is subject to revisions as the reserve base becomes revised (as discoveries pass the commercial hurdles) the tail is likely to fatten as from 2022/2023 mainly due to Johan Sverdrup phase II and Johan Castberg (Barents Sea).

My forecast includes about 7% reserve growth (300 Mb) for discoveries in the extraction phase, but does not include the effects from fields/discoveries being plugged and abandoned as these reach the end of their economic life.

Discoveries sanctioned for development and Johan Sverdrup (with an expected start up late 2019) is expected to generally slow down the decline in Norwegian crude oil extraction.

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Norwegian Crude Oil Reserves And Extraction per 2015

In this post I present actual Norwegian crude oil extraction and status on the development in discoveries and reserves and what this has now resulted in for expectations for future Norwegian crude oil extraction.

This post is also an update of an earlier post about Norwegian crude oil reserves and production per 2014.

Norwegian crude oil extraction peaked in 2001 at 3.12 Million barrels per day (Mb/d) and in 2015 it was 1.57 Mb/d, growing from 1.51 Mb/d in 2014.

The Norwegian Petroleum Directorate’s (NPD) recent forecast expects crude oil extraction from the Norwegian Continental Shelf (NCS) will decline to 1.53 Mb/d in 2016.

Figure 01: The chart shows the historical extraction (production) of crude oil (by discovery/field) for the Norwegian Continental Shelf (NCS) with data from the Norwegian Petroleum Directorate (NPD) for the years 1970 - 2015. The chart also includes my forecast for crude oil extraction from discoveries/fields towards 2030 based on reviews on individual fields, NPD’s estimates of remaining recoverable reserves, the development/forecast for the R/P ratio as of end 2015. Further, the chart shows a forecast for total crude oil extraction from sanctioned discoveries/fields (green area, refer also figure 02) and expected contribution from Johan Sverdrup (blue area) [at end 2015 estimated at 1.76 Gb; [Gb, Giga (Billion) barrels, refer also figure 06] and this development phase is now scheduled to start flowing in late 2019.

Figure 01: The chart shows the historical extraction (production) of crude oil (by discovery/field) for the Norwegian Continental Shelf (NCS) with data from the Norwegian Petroleum Directorate (NPD) for the years 1970 – 2015. The chart also includes my forecast for crude oil extraction from discoveries/fields towards 2030 based on reviews on individual fields, NPD’s estimates of remaining recoverable reserves, the development/forecast for the R/P ratio as of end 2015.
Further, the chart shows a forecast for total crude oil extraction from sanctioned discoveries/fields (green area, refer also figure 02) and expected contribution from Johan Sverdrup (blue area) [at end 2015 estimated at 1.76 Gb; [Gb, Giga (Billion) barrels, refer also figure 06] and this development phase is now scheduled to start flowing in late 2019.

Sanctioned Developments in Figure 01 represents the total contributions from 7 sanctioned developments of discoveries now scheduled to start to flow between 2016 and 2019.

My forecast for 2016 is 1.50 Mb/d with crude oil from the NCS.

My forecast shown in figure 01 includes all sanctioned developments and not discoveries (refer also figure 08) and contingent resources in the fields. The forecast is subject to revisions as the reserve base becomes revised (as discoveries pass the commercial hurdles) which likely will fatten the tail of the presented forecast post 2020.

My forecast assumes some reserve growth, but does not include the effects from fields/discoveries being plugged and abandoned as these reach the end of their economic life.

Discoveries sanctioned for development and Johan Sverdrup (with an expected start up late 2019) is expected to slow down the decline in Norwegian crude oil extraction.

Read the rest of this entry »

Norwegian Crude Oil Reserves And Extraction per 2014

In this post I present actual Norwegian crude oil extraction and status on the development in discoveries and reserves and what this has now resulted in for expectations for future Norwegian crude oil extraction.

This post is also an update of an earlier post about Norwegian crude oil reserves and production per 2013.

Norwegian crude oil extraction peaked in 2001 at 3.12 Million barrels per day (Mb/d) and in 2014 it was 1.52 Mb/d.

The Norwegian Petroleum Directorate’s (NPD) recent forecast expects crude oil extraction from  the Norwegian Continental Shelf (NCS) will become around 1.49 Mb/d in 2015.

Figure 01: The chart shows the historical extraction (production) of crude oil (by discovery/field) for the Norwegian Continental Shelf (NCS) with data from the Norwegian Petroleum Directorate (NPD) for the years 1970 - 2014. The chart also includes a forecast for crude oil extraction from discoveries/fields towards 2040 based on reviews on individual fields, NPD’s estimates of remaining recoverable reserves, the development/forecast for the R/P ratio etc. as of end 2014. Further, the chart shows a forecast for total crude oil extraction from sanctioned discoveries/fields (green area, refer also figure 02) and expected contribution from Johan Sverdrup (blue area) [at end 2014 estimated at 2.22 Gb; [Gb, Giga  (Billion) barrels, refer also figure 05]  which is now scheduled to start flowing in late 2019.

Figure 01: The chart shows the historical extraction (production) of crude oil (by discovery/field) for the Norwegian Continental Shelf (NCS) with data from the Norwegian Petroleum Directorate (NPD) for the years 1970 – 2014. The chart also includes a forecast for crude oil extraction from discoveries/fields towards 2040 based on reviews on individual fields, NPD’s estimates of remaining recoverable reserves, the development/forecast for the R/P ratio etc. as of end 2014.
Further, the chart shows a forecast for total crude oil extraction from sanctioned discoveries/fields (green area, refer also figure 02) and expected contribution from Johan Sverdrup (blue area) [at end 2014 estimated at 2.22 Gb; [Gb, Giga (Billion) barrels, refer also figure 05] which is now scheduled to start flowing in late 2019.

“Sanctioned Developments” in Figure 01 represents the total contributions from 8 sanctioned developments of discoveries now scheduled to start to flow between 2015 and 2017.

My forecast for 2015 is 1.47 Mb/d with crude oil from the NCS.

My forecast shown in figure 01 includes all sanctioned developments and not discoveries (refer also figure 07) and contingent resources in the fields. The forecast is subject to revisions as the reserve base becomes revised (as discoveries pass the commercial hurdles) which likely will fatten the tail post 2020 of the presented forecast.

My forecast assumes some reserve growth, but does not include the effects from fields/discoveries being plugged and abandoned as these reach the end of their economic life.

Discoveries sanctioned for development and Johan Sverdrup (with an expected start up late 2019) is expected to slow down the decline in Norwegian crude oil extraction.

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Are Mountrail’s Sweet Spots Past Their Prime?

This post is an update on total Light Tight Oil (LTO) extraction from Bakken in North Dakota based upon actual data as of October 2014 from North Dakota Industrial Commission (NDIC). It further presents a statistical analysis on developments of well productivity with a detailed look at developments in Parshall, Reunion Bay and Sanish.

  • There were general improvements in LTO well productivity in Bakken during 2013.
  • Present trends in LTO well productivity for Mountrail’s sweet spots (Alger, Parshall, Reunion Bay, Sanish and Van Hook) suggests these are past their prime.
  • Figure 29 in this post show development in well productivity for Alger and Van Hook and figures 06, 08 and 10 for Parshall, Reunion Bay and Sanish. A common feature for Parshall, Reunion Bay, Sanish, and Van Hook is that these reached new highs in well productivity for wells started in 2013.
    Alger has been in general decline since 2011.
  • LTO extraction in recent years may be viewed as a source for global swing production for oil.

Figure 01: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of October 2014 in Bakken North Dakota [green area, right hand scale]. The top black line is the price of Western Texas Intermediate (WTI), red middle line the Bakken LTO price (sweet) as published by the Director for NDIC and bottom orange line the spread between WTI and Bakken LTO wellhead all left hand scale.

Figure 01: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of October 2014 in Bakken North Dakota [green area, right hand scale]. The top black line is the price of Western Texas Intermediate (WTI), red middle line the Bakken LTO price (sweet) as published by the Director for NDIC and bottom orange line the spread between WTI and Bakken LTO wellhead all left hand scale.

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Written by Rune Likvern

Friday, 9 January, 2015 at 20:40

Growth in Global Total Debt sustained a High Oil Price and delayed the Bakken “Red Queen”

The saying is that hindsight (always) provides 20/20 vision.

In this post I present a retrospective look at my prediction from 2012 published on The Oil Drum (The “Red Queen” series) where I predicted that Light Tight Oil (LTO) extraction from Bakken in North Dakota would not move much above 0.7 Mb/d.

  • Profitable drilling in Bakken for LTO extraction has been, is and will continue to be dependent on an oil price above a certain threshold, now about $68/Bbl at the wellhead (or around $80/Bbl [WTI]) on a point forward basis.
    (The profitability threshold depends on the individual well’s productivity and companies’ return requirements.)
  • Complete analysis of developments to LTO extraction should encompass the resilience of the oil companies’ balance sheets and their return requirements.

Figure 01: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of August 2014 in Bakken North Dakota [green area, right hand scale]. The top black line is the price of Western Texas Intermediate (WTI), red middle line the Bakken LTO price (sweet) as published by the Director for NDIC and bottom orange line the spread between WTI and Bakken LTO wellhead all left hand scale. The spread between WTI and Bakken wellhead has widened in the recent months.

Figure 01: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of August 2014 in Bakken North Dakota [green area, right hand scale]. The top black line is the price of Western Texas Intermediate (WTI), red middle line the Bakken LTO price (sweet) as published by the Director for NDIC and bottom orange line the spread between WTI and Bakken LTO wellhead all left hand scale. The spread between WTI and Bakken wellhead has widened in the recent months.

What makes extraction from source rock in Bakken attractive (as in profitable) is/was the high oil price and cheap debt (low interest rates). The Bakken formation has been known for decades and fracking is not a new technology, though it has seen and is likely to see lots of improvements.

LTO extraction in Bakken (and in other plays like Eagle Ford) happened due to a higher oil price as it involves the deployment of expensive technologies which again is at the mercy of:

  • Consumers affordability, that is their ability to continue to pay for more expensive oil
  • Changes in global total debt levels (credit expansion), like the recent years rapid credit expansion in emerging economies, primarily China.
  • Central banks’ policies, like the recent years’ expansions of their balance sheets and low interest rate policies
    • Credit/debt is a vehicle for consumers to pay (create demand) for a product/service
    • Credit/debt is also used by companies to generate supplies to meet changes to demand
    • What companies in reality do is to use expectations of future cash flows (from consumers’ abilities to take on more debt) as collateral to themselves go deeper into debt.
    • Credit/debt, thus works both sides of the supply/demand equation
  • How OPEC shapes their policies as responses to declines in the oil price
    Will OPEC establish and defend a price floor for the oil price?

I have recently and repeatedly pointed out;

  • Any forecasts of oil (and gas) demand/supplies and oil price trajectories are NOT very helpful if they do not incorporate forecasts for changes to total global credit/debt, interest rates and developments to consumers’/societies’ affordability.

Oil is a global commodity which price is determined in the global marketplace.

Added liquidity and low interest rates provided by the world’s dominant central bank, the Fed, has also played some role in the developments in LTO extraction from the Bakken formation in North America.

As numerous people repeatedly have said; “Never bet against the Fed!” to which I will add “…and China’s determination to expand credit”.

Let me be clear, I do not believe that the Fed’s policies have been aimed at supporting developments in Bakken (or other petroleum developments) this is in my opinion unintended consequences.

In Bakken two factors helped grow and sustain a high number of well additions (well manufacturing);

  • A high(er) oil price
  • Growing use of cheap external funding (primarily debt)

In the summer of 2012 I found it hard to comprehend what would sustain the oil price above $80/Bbl (WTI).

The mechanisms that supported the high oil price was well understood, what lacked was documentation from authoritative sources about the scale of the continued accommodative policies from major central banks’ (balance sheet expansions [QE] and low interest rate policies) and as important; global total credit expansion, which in recent years was driven by China and other emerging economies.

I have described more about this in my post World Crude Oil Production and the Oil Price.

 

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World Crude Oil Production and the Oil Price

In April 2012 I published this post about World Crude Oil Production and the Oil Price (in Norwegian) which was an attempt to describe the developments in the sources of crude oils (including condensates), tranches of total life cycle costs (that is [CAPEX {inclusive returns} + OPEX] per barrel  of oil) and something about the drivers for the formation of the oil price.

Rereading the post and as time passed, I learnt more and therefore thought it appropriate to revisit and update the post as it in my opinion contains some topics from what I have observed, learned and discussed that have been given poor attention and appears poorly understood.

I will continue to pound the message that oil prices are also subject to the reality of;

  • “Demand is what the consumers can pay for!”

Figure 1: The chart above shows the developments in the oil price [Brent spot] and the time of central banks’ announcements/deployments of available tools to support the global financial markets which the economy heavily relies upon. The financial system is virtual and thus highly responsive. The chart suggests causation between FED policies and movements to the oil price.

Figure 1: The chart above shows the developments in the oil price [Brent spot] and the time of central banks’ announcements/deployments of available tools to support the global financial markets which the economy heavily relies upon. The financial system is virtual and thus highly responsive.
The chart suggests causation between FED policies and movements to the oil price.

The four big central banks, BoE, BoJ, ECB and the Fed expanded their balance sheets with $6 – 7 Trillion following the Lehman collapse in the fall of 2008. These liquidity injections are about to end.

Since 2008 most of the advanced economies’ credit expansions originated from the central banks, the lenders of last resort. Central banks are collateral constrained.

The consensus about the oil price collapse during the recent weeks is attributed to waning global demand and growth in  supplies.

All eyes are now on OPEC.

  • Any forecasts of oil (and gas) demand/supplies and oil price trajectories are NOT very helpful if they do not incorporate forecasts for changes to total global credit/debt, interest rates and developments to consumers’/societies’ affordability.

For more than a decade, I have carefully studied the forecasts (and been involved in numerous fruitful [private] discussions) from authoritative sources like the Energy Information Administration (EIA) and the International Energy Agency (IEA) including the annual outlooks from several of the major oil companies and I did NOT find that any of these takes into consideration changes to global credit/debt [growth/deleveraging], levels of total global credit/debt and interest rates.

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IN BAKKEN (ND) IT IS NOW MOSTLY ABOUT MCKENZIE COUNTY

In this post I present an update to my previous posts over at The Oil Drum (The Red Queen series) on developments in tight oil production from the Bakken formation in North Dakota with some additional estimates, mainly presented in charts. The expansion is much about the differences between wells capable of producing, actual producing wells and idle wells (here defined as the difference between the number of wells capable of producing and the number of actual producing wells).

Figure 01: The chart above shows monthly net additions of producing wells (green columns plotted against the rh scale) and development in oil production from Bakken (ND) (thick dark blue line, lh scale) as of January 2000 and as of October 2013. The 12 Month Moving Average (12 MMA) is also plotted (thick dotted dark red line, lh scale).

Figure 01: The chart above shows monthly net additions of producing wells (green columns plotted against the rh scale) and development in oil production from Bakken (ND) (thick dark blue line, lh scale) as of January 2000 and as of October 2013. The 12 Month Moving Average (12 MMA) is also plotted (thick dotted dark red line, lh scale).

There is still noticeable growth in tight oil production from an accelerated additions of producing wells.

  • For October 2013 North Dakota Industrial Commission (NDIC) reported a production of 877 kb/d from Bakken/Three Forks.
  • In October 2013YTD production from Bakken/Three Forks (ND) was 775 kb/d.
    (It is now expected that average daily production for all 2013 from Bakken (ND) will become around 800 kb/d.
  • The cash flow analysis now suggests less use of debt for manufacturing wells for 2013.
    Major funding for new wells now appears to come mainly from from net cash flows.

kb; kilo barrels = 1,000 barrels

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