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Globalshift employs a consistent approach to analysis. Fixed and precise definitions are applied to all technical terms used in the oil, gas and other energy industries
Volumes of fossil liquid hydrocarbons produced from a buried reservoir through wells (or rarely by mining) to the surface. Here they can exist as a liquid at surface temperatures and pressures without processing. They can be transported, before or after refining, in liquid form and are used, before or after refining, as fuels and/or in the chemical industry. The hydrocarbons include; all oils and condensates extracted from oil, oil and gas, and/or gas fields, as well as from dispersed reservoirs; all natural gas liquids; all drilled shale oils from shale reservoirs; and extra-heavy oils (including bitumens) used for energy before or after conversion to syncrude.
Are fossil hydrocarbon liquids extracted through wells from a field with a porous and permeable reservoir that can exist naturally as a liquid at the wellhead. They may also be called conventional oils.
Shale/Tight Oils (STOs)
Fossil hydrocarbon liquids extracted through wells from tight (shales, as well as sandstones or carbonates) non-field dispersed reservoirs before or after fracturing these reservoirs underground. They are not to be confused with Mined Shale Oils.
Oils from Oil Sands
Extra-heavy oils (bitumens) extracted from shallow sands (also known as tar sands) through wells (usually with steam) or by mining. They are often converted to syncrude by chemical processes, making them more convenient to transport and burn.
Natural Gas Liquids (NGLs)
Light oils recovered from associated/free gas in a processing plant, stable at normal temperatures. Liquefied Petroleum Gases (LPGs) are NGLs which comprise synthesised propane and butane that need pressurised containers for storage. The dividing line between condensates (included in field oils) and NGLs can be uncertain and some plant output may be assigned to either category.
Manufactured synthetic liquid hydrocarbons (not including syncrude made from oils from oil sands), with the same characteristics and used for the same purpose as fossil liquid hydrocarbons. They are oils created through chemical conversion processes from gas, from coal, from shale, and from biomass (bioethanol and biodiesel).
Created in a refinery by converting natural gas or other gaseous hydrocarbons into longer-chain gasoline or diesel fuel either via direct conversion or via syngas as an intermediate. The Fischer-Tropsch and Mobil processes are the most commonly used methods.
Created by coal liquefaction mainly using the Fischer-Tropsch process. Coal is gasified to make syngas and Fischer-Tropsch catalysts are used to convert the syngas into light hydrocarbons which are further processed into gasoline and diesel.
Mined Shale Oils (Retorted)
Created by heating and processing mined shale rock in a surface plant; not to be confused with Light Tight Oils.
Liquid hydrocarbons made from plant materials rather than petroleum products. They do not include biomass solids which are agricultural crops and residue, wood and wood waste, animal waste, aquatic plants and the organic components of municipal and industrial wastes. Biodiesel BTLs are created when plant oils are combined with alcohol in the presence of a catalyst to form ethyl or methyl ester. Ethanol BTLs are formed during sugar fermentation by yeast of plants, including cellusosic ethanol which is created directly from woody biomass.
Liquid hydrocarbons, with the same characteristics and used for the same purpose as fossil liquid hydrocarbons, created during refining and known as refinery gains. They represent the increase in volume of refined products compared to an input volume of crude. The processing of oil and the associated chemical changes increase the volume by a few percent, depending on the input oil and the selected refinery output.
The American Petroleum Institute (API) standard term to express the specific weight of oils, computed as (141.5/specific gravity) - 131.5, where the specific gravity of the oil is set at 60°F. The lower the specific gravity value, the higher the API gravity will be.
Have an API gravity of over 22° and a viscosity of less than 100 centipoise (cp).
Dense, viscous oils with asphaltene, usually containing impurities such as sulphur, heavy metals, waxes and carbon residue that must be removed before refining. The upper limit for heavy oils is taken as 22° API gravity. The lower normal heavy oil limit is 10° API gravity.
The portion of heavy oils having an API gravity of less than 10° (including bitumens), which are dense and viscous with a viscosity greater than 10,000 cp. Negligible extra-heavy oil is produced offshore.
NATURAL GASES (SALES)
Surface volumes of fossil gas hydrocarbons produced from any buried reservoir through wells to the surface. After extraction of liquids these are sold for use as a direct energy source or for conversion to Liquefied Natural Gas (LNG) or to electricity or for use in the chemicals industry. Production may be from oil, oil and gas, and gas fields, with porous and permeable or tight reservoirs (shales, as well as sandstones or carbonates) or from coal seams (CBM). Unsold vented, flared, and re-injected gases as well as gases used on site are not included.
Oils and gases produced by any means and sold to refineries or other end user and measured as a volume per time period. Production includes from 'currently producing fields and those in development' (all oil from existing fields and from fields that have operator-announced plans for their development), from 'discovered fields which will be developed' (all oil from potentially commercial drilled fields and may include appraised undeveloped extensions to existing fields - these are partly speculative volumes) and from 'yet-to-find (undiscovered) fields which will be developed' (all oil from potentially commercial undrilled areas - these are speculative volumes).
Profiles are the shape of the production curve between two times. Profiles are created based on past production histories and output models for onshore and offshore areas.
Comes from onshore wells including wells drilled within lakes and swamps; regardless of their subsurface location, even when such wells are drilled from piers and/or deviated to locations beneath the sea.
Comes from offshore wells; including those drilled from fixed platforms in shallow waters and from artificial islands unconnected to the mainland (not including wells drilled on mainland piers or located in freshwater inland areas). For fields overlapping on and offshore areas and water depth intervals the allocation is estimated. It is assumed that the location of the wellhead defines the water depth of an individual well.
Very Shallow waters
Defined as areas of oil and/or gas output from reservoirs beneath marine water depths ranging from greater than 0 metres down to 100 metres.
Medium Shallow Waters
Defined as areas of oil and/or gas output from reservoirs beneath marine water depths ranging from greater than 100 meters down to 500 meters.
Medium Deep Waters
Defined as areas of oil and/or gas output from reservoirs beneath marine water depths ranging from greater than 500 metres down to 1000 metres.
Very Deep Waters
Defined as areas of oil and/or gas output from reservoirs beneath marine water depths ranging from greater than 1000 metres down to 2000 metres.
Ultra Deep Waters
Defined as areas of oil and/or gas output from reservoirs beneath marine water depths ranging from greater than 2000 metres.
The term reserves is misunderstood and misused in the oil and gas industry and media. It may have multiple meanings. Reserves are considered here as ‘Cumulative Production’ plus ‘Remaining Production’ (see below). Proved, probable and possible reserves (P+P+P) are also not used in Globalshift in this context. These represent the concept of 90% (proved reserves are subject to a 0.9 success risk), 50% (probable reserves are subject to a 0.5 success risk) and 10% (possible reserves are subject to a 0.1 success risk). Note that Globalshift ‘remaining production’, by definition, should be more than proved reserves and could roughly be equated to P+P (2P) reserves.
Is the total volume of oil and/or sales gas up to a given year that has been produced (in Globalshift this is to the current year minus one).
Equates to most likely remaining recoverable resources of oil or sales gas that have not yet been produced but will be recovered under economic conditions that could exist in the future. This assumes the world remains a stable, comfortable place to live with a price regime that satisfies demand whilst demand changes in manageable steps and fossil fuels retain market share. They are summed output values over a future period (in Globalshift this is to the year 2100). Remaining production volumes are not statistically derived and are best thought of as one interpretation of ‘most likely’ numbers. There are 3 categories of ‘Remaining.’
That part of Remaining Production that represents all current producing fields that have entered production but have not yet been abandoned and will continue to produce. It is an estimate based on objective analysis of past production and depletion rates to assess future production through history matching. It does not include new oil and gas from old fields extracted through new methods or step-out drilling.
Speculative Undeveloped Remaining (also known as potential additional resources)
That part of Remaining Production that represents parts of current producing fields and all field discoveries and field extensions that have not yet entered production but will be developed. It is a speculative estimate based on subjective (but educated) examination of the relevant area. The term ‘Reserves Growth’ (not used by Globalshift) has often been used to define these volumes. ‘Reserves growth’ is a confused term with multiple definitions, including undeveloped fields (or fallow fields) and the use of improved technology to access hitherto un-producible volumes.
Speculative Undiscovered Remaining (also known as yet-to-find)
That part of Remaining Production that represents all potential field discoveries which have not yet been discovered but will be found and developed. It is a speculative estimate based on subjective (but educated) examination of the relevant area.
Ultimate produced volumes are the sum of ‘Cumulative Production’ (volume of oil and/or gas up to a given year that has been produced) and ‘Remaining Production’ (the volume of oil and/or gas up to a given year that will be produced).
Peak production is the year of maximum output of oil, gas or other hydrocarbons. The peak year will be determined by a combination of actual supply, available capacity, supply restrictions if any, prevailing demand at the current price, and demand restrictions if any.
Resources are all the oils (or gases) that exist in the earth from any source, including developed, undeveloped and undiscovered that, if produced (extracted from the subsurface), could be used for fuel or in the chemical industry. Undeveloped and undiscovered volumes and profiles are estimated based on geology, engineering and economics in each sedimentary basin, allied to past exploration and production histories in the area. Resources are not critical to the forecast production profiles in Globalshift since a substantial portion of estimated resources will either be produced far in the future, when the world must no longer be dependent on fossil fuels, or will never be produced due to unfavourable economic and/or technological circumstances.
The oil and gas used each year by each country. Historically this generally equates to demand. In projections desired demand may be higher or lower, with consumption representing the volume used at the prevailing oil price that sets demand. Note that different oils in particular have different energy contents so there is potential for great discrepancy in supply and demand when only volumes are considered.
The difference between the indigenous oil or sales gas supply of a country in a given year and the reported or projected consumption of oil or gas by that country in that year.
Drilled by drilling rigs of any type with the intent to locate and/or exploit oil and/or gas resources. They are allocated to the year in which spudding takes place, except for pre-spudded development wells which are allocated to the year of return to the hole. Sidetracks are drilled from existing well bores. They are defined as drilled wells if the original well has seen its rig stand down and the intent is to acquire new data and/or production.
Drilled Wells (Onshore)
Includes all Drilled Wells that are not defined as Drilled Wells (Offshore)
Drilled Wells (Offshore)
Are wells drilled with rigs in marine environments, including land rigs, such as platform rigs, erected on platforms and artificial islands. They do not include wells drilled from shallow water barges in lakes and swamps and wells drilled from onshore sites to tap offshore accumulations.
Drilled Wells (Very Shallow waters)
Defined as having a seabed location beneath marine water depths ranging from greater than 0 meters down to 100 meters. If a mobile rig is used these wells are usually drilled with jackups.
Drilled Wells (Medium Shallow Waters)
Defined as having a seabed location beneath marine water depths ranging from greater than 100 meters down to 500 meters. If a mobile rig is used these wells are usually drilled with floaters (semisubs and drillships) although a few may be drilled with advanced jackups.
Drilled Wells (Medium Deep Waters)
Defined as having a seabed location beneath marine water depths ranging from greater than 500 meters down to 1000 meters. Floaters are used to drill nearly all wells in deep waters although in rare cases fixed rigs on platforms can be used.
Drilled Wells (Very Deep Waters)
Defined as having a seabed location beneath marine water depths ranging from greater than 1000 meters down to 2000 meters.
Drilled Wells (Ultra Deep Waters)
Defined as having a seabed location beneath marine water depths ranging from greater than 2000 meters.
The descriptor given to a drilled well when it is planned.
Drilled where a field is suspected (called a prospect), to determine the presence of hydrocarbons and collect data to assess the merit of a prospect. Also known as new-field wildcats or new-pool wildcats.
Drilled after an exploration well has been evaluated and a decision to go ahead with appraisal of a project has been made. Also known as delineation, offset, step-out or outpost wells. If a well has a dual or triple purpose it is defined as an appraisal.
The sum of exploration and appraisal wells.
Drilled to produce a field once volumes have been proven by exploratory wells; most are producers but some may be designated injectors used to pump fluids into the reservoir for pressure support and to conserve gas.
Surface-Completed Wells (offshore only)
On fixed platforms the valve set (Christmas Tree) can be above sea level (dry); such a well is designated as surface-completed.
Subsea-Completed Wells (offshore only)
On most floating platforms the Christmas Tree is located on the sea floor (wet) and a tube (called a riser) runs from the well or group of wells to the production platform; such a well is designated as subsea-completed.
All active wells that have been drilled into an oil or oil and gas reservoir and are used to produce oil and gas from that reservoir including wells that are used for injection of fluids.
Producing Wells (Oil)
Include all active wells that have been drilled into an oil or oil and gas reservoir and are used to produce oil (and any associated gas) from that reservoir, including wells that are used for injection of fluids.
Producing Wells (Gas)
Include all active wells that have been drilled into a gas reservoir without associated liquids that are used to produce only gas from that field, including wells that are used for injection of fluids.
Stripper Wells (USA)
A stripper well is defined as any well whose maximum daily oil production does not exceed 15 bbls, or gas production does not exceed 90 mcf during a 12-month period.
Marginal Wells (USA)
A producing well that is unable to operate at a lower price per unit of oil or gas because of low production rates and/or high production costs and/or high co-production of associated water and non-combustible gases.
The forecasts in Globalshift are considered within three time bands and one transition (the ‘Energy Shift’):
A period of 5 years from the present. Short Term is represented by numbers that can be formulated from actual plans, strategies, policies and [oil and gas] discoveries and the expected responses by companies and governments.
A period of 15 years from the end of Short Term. Medium Term is represented by numbers that must be estimated with a higher degree of uncertainty based on trends and assessments of geology, developments in technology, and a view on local and global economic issues.
Any time after the end of Medium Term. It is represented by numbers that must be estimated with a high degree of uncertainty based on past trends as well as Globalshift’s overall assessment on how the world will respond to declining oil and gas supplies, declining demand for fossil fuels and increasing impact from environmental problems. If no oil and gas has been forecast to have been produced in a country, territory or sedimentary basin prior to commencement of Long Term, it is assumed that no production will ever materialise as it will be after the transition known as the ‘Energy Shift’.
The ‘Energy Shift’
A term used to replace the broad concept of ‘Peak Oil’ and the poorly defined ‘Peak Demand’ (which ignores supply constraints) both of which have been used by polarised commentators without proper definitions and often as political tools. The ‘Energy Shift’ will be driven by all the inter-related and competing factors that can cause a reduction in fossil fuel use in the future such as; supply; demand; price; technology; and environment. See Modelling for more information.