(Repeats Jan. 13 column with no changes. John Kemp is a Reuters market analyst. The views expressed are his own)
By John Kemp
LONDON, Jan 13 (Reuters) - How low must oil prices fall before production starts to level off and even decline to rebalance the market?
There is no straightforward answer because it depends on so many factors most of which are uncertain or not observable.
These include the depth and duration of price falls; expectations about the extent and timing of any future price recovery; drilling and completion costs; wellhead prices and hedging programmes.
But any discussion about the outlook for production needs to start with an understanding of the lifecycle of an oilfield and the distinction between breakeven and shut-in prices.
Shut-in prices refer to the minimum wellhead price operators need to continue producing from a hole which has already been drilled and completed and is in production.
Prices at the wellhead must be sufficient to cover the ongoing costs of operation and maintenance, including pumping and artificial lift, as well as water, gas and steam flooding and other stimulation measures for older reservoirs.
Shut-in prices are as low as $15 per barrel in North Dakota’s Bakken, according to North Dakota’s Department of Mineral Resources. Elsewhere, however, operating costs and corresponding shut in prices are much higher.
For example, across the United States there are around 400,000 stripper wells each producing less than 10 barrels of oil per day (the average is 1.8 barrels). But in total they produced three quarters of a million barrels per day in 2012, according to the Interstate Oil and Gas Compact Commission.
Most of these stripper wells rely on surface pumps (the famous nodding donkeys) or more modern downhole submersible pumps. In addition they require surface separation facilities to remove water, dirt and gases from the oil before it can be sold, all of which cost money to run.
Stripper wells are not the only expensive form of oil. California’s aging fields require the injection of massive amounts of water, gas and steam to maintain their pressure and push the remaining oil deposits towards the wells. The crude must then be separated from enormous amounts of water.
In 2009, California’s operators injected 500 million barrels of steam and almost 1.4 billion barrels of water into declining fields to produce 230 million barrels of oil.
To make matters worse, more than half of the state’s production is heavy oil (with an API gravity of less than 20 degrees). Heavy crude sells for much less than light-oil markers such as WTI and Brent.
Oil sands in Canada and enhanced oil recovery schemes in Texas and Louisiana also have high operating costs linked to their need for steam or carbon dioxide injection.
All these high-cost forms of oil production are increasingly vulnerable to being shut in as wellhead prices in the United States tumble below $50 per barrel (and in some cases now below $40 per barrel).
Shut-in prices are only relevant for existing wells. New wells must cover their full life-cycle costs, including drilling, completion and operating costs, plus an acceptable rate of return, before a production company will authorise drilling.
Breakeven prices are typically much higher because the cost of drilling and completing a well is enormous. Drilling a hole thousands of feet into the ground can cost from $2 million to $12 million per well, depending on depth, horizontal length and geology, with fracturing and other completion costs on top.
North Dakota’s Department of Mineral Resources put breakeven prices at between $30 and $75 in different parts of the Bakken in a presentation to state lawmakers. These are the prices producers must expect to receive at the wellhead before they will authorise drilling.
There are no precise measures for wellhead prices. The Department of Mineral Resources estimates wellhead prices by averaging WTI futures (which is the very best operators could hope to receive ignoring all transport costs) and posted prices (the worst operators would receive for spot sales on their property).
On this average measure, the approximate wellhead price for North Dakota’s oil producers was just $38 per barrel on Jan. 12, making production in all peripheral areas of the Bakken play uneconomic and only marginally profitable in three core counties (Dunn, McKenzie and Williams).
For the first time, wellhead prices were no longer high enough to support new drilling in Mountrail, one of the four counties at the heart of the Bakken play.
Breakeven prices are also relatively high in the Permian Basin in Texas as well as in more peripheral shale plays with difficult geology like the Anadarko Basin.
New drilling in many parts of the Bakken, Permian, Eagle Ford and Anadarko plays will therefore stop unless wellhead prices recover.
The number of rigs drilling for all has already declined by 12 percent since mid-October, according to oilfield services company Baker Hughes, and it will drop further as existing work programmes are completed.
Breakeven rates are critical because production from existing wells is not stable. Output declines over time in a fairly predictable way, a phenomenon known as the decline curve.
Output from existing fields around the world would decline around 9 percent per year in the absence of new drilling or other capital expenditure to increase recovery, according to the International Energy Agency’s World Energy Outlook 2013.
The IEA’s average 9 percent decline rate was calculated by analysing output from more than 1,600 conventional oilfields around the globe. Shale wells, however, exhibit much faster decline rates.
North Dakota’s Department of Mineral Resources estimates output from a typical Bakken well falls 65 percent by the end of the first year, another 35 percent by the end of the second, 15 percent more by the end of the third, and 10 percent per year thereafter.
In a world where the marginal barrel of oil is supplied by shale, rather than conventional fields, breakeven rates are critical to sustaining output levels even in the short term because the industry must keep drilling new wells simply to reduce the rapidly falling output from existing holes.
Production from an individual well or field does not decline because the oil runs out. Conventional fields leave behind more than half of the oil originally in place. In the case of shale plays the proportion is even higher.
Petroleum geologists talk about oil in “reservoirs” or “pools” which can mislead outsiders into imagining that oil occurs in giant caverns underground.
In fact, oilfields are like a sponge made from rock. Oil is trapped in the microscopic pores between the individual grains of sand, shell fragments and silt that make up sandstone, limestone, mudstone or shale.
The oil occurs in combination with water and gases, including methane (natural gas), propane, butane, nitrogen, carbon dioxide, hydrogen sulphide and helium, all of which are trapped in the same pore spaces.
Reservoirs are under tremendous pressure from the thousands of feet of rock above them, which coupled with the buoyancy of the gases, means they have what geologists call “natural energy”. When the reservoir is initially punctured by a well, this natural energy drives oil, gas and water to the surface.
Flow rates from a well in its first 30 or 60 days of production are typically high. But as the pressure falls and gas comes out of solution the reservoir’s natural energy is dissipated and flow rates decline. Eventually, field operators have to resort to pumping to bring the oil to the surface.
Other techniques to keep wells flowing include re-injecting gases to maintain pressure in the reservoir; water and/or gas flooding to maintain pressure and sweep remaining oil towards the wells; and injecting carbon dioxide, polymers or steam to make the oil remnants flow more easily and push them towards the wells.
In the primary recovery phase, oil is extracted utilising only the reservoir’s natural energy. In the secondary and tertiary recovery phases, producers resort to pumping, waterflooding and more exotic techniques.
Secondary and tertiary recovery are expensive but unless capital is spent on field development output will inevitably decline as natural energy is exhausted.
To sustain, let alone grow, output, prices must be high enough to cover the costs of drilling replacement wells or implementing secondary and tertiary recovery programmes, otherwise natural decline rates will take over and production will fall. (Editing by David Evans)