FRACTIONAL FLOW

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Archive for the ‘break even price’ Category

Is the Red Queen outrunning Bakken LTO extraction?

This post is an update on LTO extraction in Bakken based upon published data from the North Dakota Industrial Commission (NDIC) as per January 2015.

This post also presents a closer look at developments in LTO extracted from the three of the four counties that presently dominates LTO extraction; McKenzie, Mountrail and Williams.

With an oil price below $50/Bbl (WTI) the companies involved in extraction of LTO in Bakken faces two financial challenges;

  1. The decline in the cash flow from operations reduces funding capacities for manufacturing new wells. A lower oil price also lowers the value of the companies’ assets and borrowing capacities.
  2. The “average” well with around 90 kb [90,000 Bbls] of flow in its first year is estimated to have an undiscounted point forward break even (that is a nominal break even with 0% return for the well) at around $65/Bbl (WTI). The break even price increases with increases in the return requirement.


In short, LTO extraction at present prices
($45/Bbl, WTI) makes little commercial sense!

Figure 01: The chart above shows development in Light Tight Oil (LTO) extraction from January 2009 and as of January 2015 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 January 2015 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.

From December 2014 to January 2015 LTO extraction from Bakken(ND) declined from 1.16 Mb/d to 1.13 Mb/d.

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Will the Bakken Red Queen Outrun Growth in Water Cut?

This post presents a closer examination of actual data on Light Tight Oil (LTO) extraction, developments in water cut and Gas Oil Ratio (GOR) for some pools and individual wells in the Middle Bakken and Three Forks formations in North Dakota.

LTO extraction’s primary drive mechanism is (differential) pressure and there are some noticeable trends for LTO extraction from Bakken:

  • LTO productivity (measured as average totals by vintage) in 2014 have increased, most notably from the Middle Bakken formation which has better well productivity than Three Forks.
    There are differences to LTO productivity developments amongst the pools.
  • Water cut; generally increases as the wells ages.
    An indicator for depletion.
  • Water cut; generally increases for newer wells.
    This suggests that the areas with the highest oil saturation has been developed.
  • Gas Oil Ratio (GOR, produced and expressed as Mcf/Bbl); generally increases as the well ages. 
  • What appears to characterize a Bakken sweet spot is the presence of natural fractures (favorable geology), high oil saturation and a pressure above hydrostatic pressure.

Further, this post also has a brief look into well economics and describes how well manufacturing is likely to be affected by the decline in the oil price and what this may entail if a lower oil price ($70/Bbl, WTI) is sustained.

Figure 01: The chart above shows development in the water cut [water cut = [water/(water + LTO)] for the “average” wells by vintage in North  Dakota. Produced water (brine) is transported to dedicated disposal sites. Chart by Enno Peters.

Figure 01: The chart above shows development in the water cut [water cut = [water/(water + LTO)] for the “average” wells by vintage in North Dakota. Produced water (brine) is transported to dedicated disposal sites.
Chart by Enno Peters.

What is fascinating about LTO wells in Bakken is that the individual wells appear to have their own “personality” when it comes to productivity, surrounding rock properties, water/oil saturation and GOR which makes well management (of close to 9,000 “personalities”) a paramount task.

This post contains in total 30 charts that hopefully are self explanatory.

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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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NORWEGIAN CRUDE OIL RESERVES AND PRODUCTION PER 2013

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

This post is also an update of an earlier post about Norwegian crude oil reserves and production per 2012 (in Norwegian).

Norwegian crude oil production peaked in 2001 at 3.12 Million barrels per day (Mb/d) and by 2013 it had declined by more than 50% to 1.46 Mb/d. This has been overshadowed by the fact that the price has increased 4 fold from the level from 2001, which thus and in financial terms more than compensated for the fall in physical extraction.

The Norwegian Petroleum Directorate’s (NPD) recent forecast expects crude oil production from  the Norwegian Continental Shelf (NCS) will become around 1.47 Mb/d in 2014.

Figure 1: The chart shows the historical production (or more precisely extraction) of crude oil (by discovery/field) for the Norwegian Continental Shelf (NCS) with data from the Norwegian Petroleum Directorate (NPD) for the years 1970 - 2013. The chart also includes a forecast for crude oil production 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 2013. Further, the chart shows a forecast for total crude oil production from sanctioned discoveries/fields (green area, refer also Figure 2) and expected contribution from Johan Sverdrup (blue area) [at end 2013 estimated at 2.23 Gb; [Gb, Giga  barrels, refer also figure 3]  which is now scheduled to start flowing late 2019. "Sanctioned Developments" in Figure 1 represents the total contributions from 13 sanctioned developments of discoveries now scheduled to start to flow between 2014 and 2017.

Figure 1: The chart shows the historical production (or more precisely extraction) of crude oil (by discovery/field) for the Norwegian Continental Shelf (NCS) with data from the Norwegian Petroleum Directorate (NPD) for the years 1970 – 2013. The chart also includes a forecast for crude oil production 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 2013.
Further, the chart shows a forecast for total crude oil production from sanctioned discoveries/fields (green area, refer also Figure 2) and expected contribution from Johan Sverdrup (blue area) [at end 2013 estimated at 2.23 Gb; [Gb, Giga barrels, refer also figure 3] which is now scheduled to start flowing late 2019.
“Sanctioned Developments” in Figure 1 represents the total contributions from 13 sanctioned developments of discoveries now scheduled to start to flow between 2014 and 2017.

My forecast for 2014 is for 1.44 Mb/d crude oil from the NCS.

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 overall decline in Norwegian crude oil production.

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TIGHT OIL AND OIL SAND VERSUS SMALL DEEP WATER DEVELOPMENTS, SOME OBSERVATIONS

This post which is based on results from earlier research and analytic work posted on The Oil Drum, Fractional Flow and not least in recent (private) discussions with other international acknowledged experts present some facts and observations about developments of tight oil (which to some extent also applies to oil sands) versus small deep water discoveries*.

*Small deep water discoveries are here meant discoveries with Estimated Ultimate Recovery (EUR) below 100 Million Barrels of Oil Equivalents (MBOE).

Figure 1: Chart above shows relative developments in annualized yield curves (lh scale) of oil for so-called elephants (Norwegian deep water discoveries estimated to hold ultimate recoverable reserves (EUR) above 1,000 million barrels with crude oil [red lines]). Small discoveries (Norwegian deep water discoveries estimated to hold ultimate recoverable reserves (EUR) below 100 million barrels with crude oil, [green lines]). The reference tight oil well for Bakken [violet lines]. The cumulative versus time is plotted against the rh scale.  Note also the short high flow life cycles of small deep water developments and tight oil.

Figure 1: Chart above shows relative developments in annualized yield curves (lh scale) of oil for so-called elephants (Norwegian deep water discoveries estimated to hold ultimate recoverable reserves (EUR) above 1,000 million barrels with crude oil [red lines]).
Small discoveries (Norwegian deep water discoveries estimated to hold ultimate recoverable reserves (EUR) below 100 million barrels with crude oil, [green lines]).
The reference tight oil well for Bakken [violet lines].
The cumulative versus time is plotted against the rh scale.
Note also the short high flow life cycles of small deep water developments and tight oil.

One big takeaway from the chart above is that both developed small deep water discoveries and tight oil wells have steep decline rates and short high flow life cycles. These are now the major sources that offset declines from the bigger, heavily depleted legacy fields (with long productive life cycles) and provide any growth in global oil supplies.

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A CLOSER LOOK AT SOME RECENT DEVELOPMENTS OFFSHORE NORWAY

In this post I present a closer look at 4 developed discoveries (of a total of 10) that started to flow as from 2012 and their production as of September 2013 as these have been reported by the Norwegian Petroleum Directorate (NPD).

A common feature for several of the recent developments offshore Norway is that they have estimated recoverable reserves ranging from 10 – 100 Million Barrels of Oil Equivalents (MBOE) and are expensive to develop and generally developed with sub sea completed wells flowing back to an existing (host) installation for processing. The host installation normally provides for essential services for the operations of these sub sea installations. These discoveries typically annual flow are 15 – 25% of estimated recoverable reserves at some kind of plateau and enter into steep declines as they become 50 – 60% depleted. Normally these developments reach expected plateau a few months after they start to flow.

Several of the recent smaller developments* on the Norwegian Continental Shelf (NCS) have so far under-performed with regard to expected production. So far these have resulted that some companies have taken some write downs, and others will have to accept considerably lower returns on their investments.

The presented 4 developments were now expected to flow a total of 90 – 100,000 BOE/d. Actual data from NPD show that these 4 developments had an average total flow of 13,000 BOE/d for August and September 2013.

*) By smaller developments are here meant discoveries with estimated recoverable reserves  below 100 Million Barrels Oil Equivalents (MBOE).

This is worrisome for several reasons:

  • Write downs and lowered returns impact the companies’ financial abilities to develop future capacities and to carry through planned exploration activities.
  • Write downs destroy shareholder value.
  • If there is a general trend with weakened profitability and/or losses from smaller developed discoveries (which for some time has been dominant on NCS), this may lead to future revisions of the criteria the companies use for commercialization of these. In other words more experiences confirming the uncertainties surrounding smaller discoveries could push the commercial break even price lower, thus deferring developments of such discoveries that already are within the companies’ portfolios.
    This may fly under the radar coverage with the euphemism “targeting financial performance”.
  • To finance these developments, the companies took advantage of their debt carrying capacities and took on more debt. The companies thus bet their future on households and sovereigns (already overstretching their debt carrying capacities) being able to continue to take on more debt to pay for more expensive oil and natural gas so that the companies can retire their debts as these mature.
  • Apart from price, production flows have a considerable impact on companies cash flows and profitability. In the short to mid term it is more about the flows and less about the stocks.
  • The developments of these smaller discoveries have so far reduced the decline in total production from the legacy installations on the NCS as can be seen in figure 1. For some time these smaller developments also hid the “The Red Queen” effect from NCS discoveries brought to flow since 2002, refer also figure 2.
  • A more reserved attitude of the companies towards future developments of the discoveries made (and to be made) due to financial considerations, sets up the potential for a near term further acceleration of the decline in total NCS crude oil production.

This also illustrates that future developments now appear to be at the crossroads with what price the oil companies need for development of discoveries with what the consumers will continue to afford.

Figure 1: Development in crude oil production from the Norwegian Continental Shelf (NCS), split on fields flowing prior to January 1st 2002 (green) and discoveries developed to flow as from 2002.

Figure 1: Development in crude oil production from the Norwegian Continental Shelf (NCS), split on fields flowing prior to January 1st 2002 (green) and discoveries developed to flow as from 2002.

The new developments have now reduced the annualized total decline in crude oil production from NCS to just above 7%, refer also to figure 2. Discoveries/fields flowing prior to 2002 has seen a decline in their total crude oil production of more than 70% since 2002.

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