Globalshift Limited - email@example.com Globalshift.co.uk is as up-to-date as possible but some information may not be the most recent available
Globalshift’s forecasts* are evidence-based, validated using geological, engineering, investment and other (environmental, political, economic and social) criteria and insights - unbiased by political or business interests
Globalshift provides a bottom-up forecast* of many time-dependent variables related to oil and gas production founded on:
Analysis depends on the historic hydrocarbon flow behaviour of oil and gas wells, fields, countries and regions and the historic numbers of wells and items of associated equipment required to explore for, and to exploit, this oil and gas.
Oil and gas production is the fundamental variable. All forecasts are based on geoscientific and engineering principles of field discovery, exploitation and depletion under commercial constraints. The projections rely on two, empirically proven, observations:
1. Supply from a single well grows to a maximum, has a short plateau and then declines. This is the basic process that an engineer (in the oil and gas industry) relies on to forecast output from individual wells and, for a given number of wells, fields.
2. Real world production and other profiles are heavily influenced by non-technical (economic, commercial and geographic) effects and these are accounted for by history matching and general evaluation.
All longer term future numbers assume oil output is dependent on the availability of underground supplies under the technological and economic conditions of the day and will otherwise only be constrained by the macro effects of the global economy, including OPEC members' (and affiliates) attempts (or not) to support oil prices when demand flags.
Meanwhile petroleum technology is assumed to continue to improve in terms of; better imaging of the subsurface; engineering advances in accessing new output; and containment of costs in increasingly challenging areas.
Process of modelling production
Spreadsheets (onshore and offshore, at selected water depths) have been created for every country in the world. These list, wherever possible, historic oil and/or gas output every year of every oil and/or gas field that has produced and/or is producing and also by name every known field discovered but, as yet, undeveloped.
Future field total outputs are constrained by reported reserves and resources of each field (where numbers have been announced) after investigating the validity of reports (depending on their provenance).
Spreadsheet yearly totals are constrained by considering sums that match reported total country yearly production using estimates defined as ‘balancing volumes’ corresponding to fields, field complexes and sedimentary basins that have no individual data reported.
Where only limited information is available or full data sets have not yet been analysed, estimates are made (by interpolation or extrapolation) in as much detail as possible using any numbers that can be obtained.
Also included in the spreadsheets, as far as possible, are all field discoveries which have not yet entered production (but will be developed - called ‘speculative undeveloped’). Many of these will have published estimates of volumes and future profiles, otherwise volume and maximum output numbers are estimated based on analogy with neighbouring fields.
Based on these volumes, a ‘speculative undeveloped’ component is added to the production forecast (using a model to create a production profile in which the undeveloped fields are sequentially developed; the largest fields first).
A ‘speculative undiscovered’ component is also added to the production forecast (estimated by examining the exploration history and general geological potential of each area) using the same model to create a production profile.
The volumes and maximum output of ‘speculative undiscovered’ are determined through subjective evaluation of how much exploration acreage remains to be explored in an area, how successful exploration has been in the past, how new technology is allowing access to new resources, and how historic exploration and development has been restricted due to political events.
Different oils are considered in different ways; for example the future output of natural gas liquids is estimated based on past volumes as a constant ratio to total gas production forecasts. Oil sands output is project-based.
Updates are carried out whenever new information appears (which may be daily). Full reviews to ensure that global interpretations are consistent and match the economic circumstances of the time are carried out in January and July each year.
All spreadsheets are collated into a single folder (E-shift) and compared graphically with actual consumption figures to ensure global supply and demand will match in future. The model is supply-driven with demand (and oil prices) moving to match available supply, which may be constrained by all or any of OPEC, geology and varied political and economic events.
Basis to modelling production
In a finite hydrocarbon system, extraction rates go up, then go down over an extended period. This has been demonstrated many thousands of times in wells and fields and also in sedimentary basins and countries.
When a successful well is completed and produced it delivers oil (and/or gas) at a rate that rises rapidly to a brief plateau. It then declines over a period of time - largely due to pressure decline in the reservoir along with water and/or gas encroachment - until it is abandoned. Globalshift calls this ‘Growth, then decline’.
‘Growth, then decline’ has happened since the first well was drilled. When a collection of wells are completed in a discrete accumulation - called a field - production rises and falls in the same fashion. When a collection of fields are developed in a sedimentary basin (with generally the biggest and best found and developed first) total production must rise and fall too.
Of course the same is true for collections of basins in a country; countries in a region; and, ultimately, all regions in the world.
The question for the industry and policy makers is when growth ceases and decline begins on a well, field, country and global scale, how fast it will happen and what, if anything, should be done about it? A comprehensive data-driven supply model has been developed by Globalshift to help define the timing and magnitude of ‘growth, then decline’, for fields, basins, countries, regions and the world.
Complexities of modelling production
Comprehensive global production forecasts should not only take account of ‘below-ground’ geological/engineering factors but also ‘above-ground’ commercial/political factors.
Demand is as important as supply when supplies are tight and external events (political, climatic and fiscal) can influence the shape of production profiles. In fact peak demand, driven by higher oil prices, will eventually create the conditions necessary for an “Energy Transition”.
Whether such a transition is smooth or not depends on the response today to the production and activity forecasts presented by Globalshift. The Globalshift supply forecast has thus been modified by qualitative assumptions related to most likely government policies, oil prices and oil demand:
1. Most non-OPEC governments will allow investing companies to find and produce oil as fast as possible using the technologies available for profitable sale at the prevailing oil price.
2. OPEC governments and some non-OPEC governments may or may not act to support price by restricting output. In the event that OPEC restricts output it will be to create a price level that erodes supply of higher cost oil but maintains demand for lower cost oil. Thus OPEC countries in the Middle East with lower cost oil supplies will drive the decision to act during a down swing in price. Other Governments may attempt to actively control price but only in support of OPEC.
3. As long as energy from the combustion of fossil fuels is cheaper than from renewables, fossil fuels will be used (until the effects of global warming become unbearable). Oil and gas demand will thus be driven by price alone (under prevailing local and global economic conditions).
4. There is political will but little economic will to further subsidise fuel substitution. A carbon tax could ultimately increase price and slow the use of these fuels, making renewables more competitive. However this is unlikely to happen on a large scale due to the economic dislocations it would cause. In the long term the cost of renewable energy is likely to continue to fall and other sources of non-polluting energy may also be discovered. Thus a slow movement away from fossil fuels will be achieved, in part driven by environmental concerns.
There are a number of countries where output growth will proceed sufficiently fast to offset declines elsewhere - particularly (but not exclusively) Brazil; the OPEC countries of Iran, Iraq and Angola; NGLs from Qatar; heavy oils from Colombia and possibly Venezuela; syncrude from Canada; and, especially, oil from shales in the USA and elsewhere.
During this period Globalshift assumes that Saudi Arabia, and to a lesser extent other OPEC and a scattering of non-OPEC countries, will, if necessary, restrict output into existing infrastructure to try to prop up oil price and maintain supply at a level to match 2% to 3% a year demand growth but only after higher cost oil supplies from non-OPEC countries have been reduced by commercial necessity.
Eventually all countries will ramp up supply as fast as they can whilst the oil price escalates (and demand declines) naturally. There will now be room (and economic pressure) for more biofuels; CTLs; GTLs; determined fuel substitution; and new conservation methods.
The true shape of the production curve during a period of plateau production depends on volatility in demand. This is influenced by the fluctuating state of a global economy in a period of spiking oil prices (up or down) and whether large scale fuel substitution can be successful.
The on-going balance of these issues will make the curve bumpier than depicted by a simple supply model. However, analysis of the magnitude and timing of plateau output is realistic, as is a future decline rate (of around 2% per year).
The length of a period of plateau production affects drilling forecasts. Drilling activity in the relevant areas will follow a pattern consistent with the model.
Process of modelling drilled well numbers
Well number spreadsheets (onshore and offshore, at selected water depths) have been created for every country in the world. These list, wherever possible, the numbers of actual historic exploration, appraisal and development wells drilled in each country each year from 1930 to the present day.
Estimates are made where sparse data has been released, such as in former Soviet bloc countries. A cumulative number is determined for each country where wells (all onshore) were drilled prior to 1930.
Sense checking of published and estimated numbers is carried out by comparing known operating rig numbers and any other information that can be obtained on activity levels.
Number forecasts from the present are then created for each well type (E, A and D) in each water depth category. These are determined empirically, modelled or both:
Short term (from last year over the next 2 or 3 years):
Forecasts are derived from announced exploratory and development plans in each country by current operators and potential winners of licensing rounds. Inevitably there will be omissions and general reviews of current exploration and development licenses, production forecasts and exploratory plans are used to help quantify the numbers of wells required to explore for and exploit this production.
Medium and long term (the subsequent 3 or 4 years and up to 2050):
Estimates are based on a qualitative view of future activity levels in the medium term combined with quantitative analysis of the historic numbers of wells required to develop actual volumes of oil and gas in the medium and long term.
For each country, for each year, a calculation is made of the number of development wells divided by the volume of produced oil plus gas in that year. The number of development wells required to produce forecast volumes each year up to 2050 is then determined using the same ratio (with some country specific modifications).
The number of exploratory wells is forecast by considering the historic numbers of E and A wells drilled over past years relative to the historic numbers of development wells drilled. This ratio is used to extrapolate forward (with some country specific modifications) as a proportion of the yearly forecast of development well numbers.
The same method is used to break exploratory wells down into exploration and appraisal wells.
Note that longer term forecasts can be very speculative as they are dependent on the quality of the production forecasts as well as consistent drilling patterns. However they can be a useful guide to overall activity. Nearly all capital spending is founded on drilling.
The “Energy Shift” and controversy of ‘peak oil’ (also called ‘peak demand’)
Volatile oil prices since 2005 arose after the onset of another period of ‘peak oil’ (a peak in oil production driven by supply, demand or both). Peak oil has since controlled the focus and magnitude of oil and gas exploration and development activity. At first tight supplies as a result of a diminishing pot of conventional resources led to significant oil price rises and then a deep recession that was due, in part, to higher energy prices.
This was followed by a dramatic increase in the exploitation of unconventional resources (oil sands, oil and gas shales, natural gas liquids and briefly biofuels) and then a sharp fall in the oil price in the latter half of 2014. Super-imposed on this volatility has been the impact of increasing environmental concerns about global warming.
With such a tight balance, price volatility is here to stay until an “Energy Shift” occurs. The impact of ‘peak oil’ is to spur development of alternatives (where these exist). However, peak oil (and the more constrained peak demand) are poorly defined (and misunderstood) terms. Globalshift instead uses the term “Energy Shift” to encompass all that peak oil was once used to describe. It is hoped that the “Energy Shift” will cause as little disruption to global economic activity as possible.
The three things that an “Energy Shift” is not:
An “Energy Shift” is not a signal of the end of exploration and discovery of oil and gas (or the end of drilling). The world finds new reserves every year however it may not find and produce enough to fully offset the decline in output from older finds.
An “Energy Shift” is not the same as running out of, or abandoning, fossil fuels. We will not do this for a long time. The rate of oil (and then gas) production will simply cease to rise, plateau for a period and then begin a slow and erratic decline.
An “Energy Shift” is not necessarily a disaster for the fossil fuel industries. There are regular appearances of new opportunities in for example; deep waters, oil sands, fractured shales, and manufactured alternatives, while conventional oil and gas types become more challenging and expensive to find and exploit. But ignoring it will cause more disruption than preparing for it (by investing in alternatives) especially as most alternatives have a lower power density.
No one source is treated as perfect - numbers are sense-checked and adapted as deemed reasonable.
Extrapolation, interpolation, and judgement are used to complete spreadsheets where a full data stream is required or desirable.
Profiles are created from a variety of:
Other written or verbal sources
Specific selected sources:
Oil and Gas Journal
World Oil Magazine
BP Statistical Review
World Energy Council
UK Energy Institute
ENI Oil & Gas Review
* All numbers are historical estimates and forecasts. There is no guarantee that such estimates or forecasts will prove accurate.
The key difference between a forecast and a projection is the nature of the assumptions. In a forecast, the assumptions represent expectations of actual future events.
A projection is when the input assumptions are not necessarily the most likely (the "what if?"scenario).
In the absence of calibration data it is assumed that 10% of the exploration wells drilled, 60% of appraisal wells drilled and 90% of the development wells drilled each year are completed as producers or injectors to become part of the “active well stock”.
The attrition rate for active wells is between 2% and 5% each year. Thus every year 2% to 5% of the active well stock are abandoned whilst 10%/60%/90% of the E/A/D drilled wells are added to the existing years active well stock.
Where calibration numbers are available in the public domain numbers are amended within reasonable limits of this model, including rapid changes as a result of non-routine surface events (e.g. OPEC restriction of output).
In the absence of calibration data, for surface-completed wells, it is assumed that all of the appropriate development wells drilled each year are completed as producers or injectors to become part of the “active well stock”.
The attrition rate for active wells is 2% each year. Thus every year 2% of the active well stock are abandoned whilst all of the development wells drilled are added to the preceding years active well stock.
For subsea-completed wells, it is assumed that all of the appropriate development wells drilled each year are completed as producers or injectors to become part of the “active well stock”.
Shallow and deep water subsea wells are expected to have an 8- and 10-year active life respectively before being abandoned. Thus every year all wells drilled 8 (or 10 years) previously are abandoned whilst all of the development wells drilled are added to the preceding years active well stock.
Where calibration numbers are available in the public domain the numbers are amended within reasonable limits of this model, including rapid changes as a result of non-routine surface events (e.g. OPEC restriction of output).
Note that all published numbers are highly variable, have different definitions (often unstated) and lack consistency.