SpeakingOilGas

Examples

“Zephyr-1 exploration well tested lower Cretaceous age sands over the interval 4939m–4942.7m using a ½ inch choke. The test recovered 80 barrels of fluid during a three-hour period. The fluid contained 70 barrels of muddy water and 20 barrels of oil/oil-water emulsion. Testing of other zones of interest is continuing.”

This report identifies the reservoir under test is in lower Cretaceous rocks, so knowledge of other wells in the area will help the reader decide whether it is the usual reservoir in the region, or a potentially interesting new zone. However the 3.7 metre test interval gives no indication of the potential net reservoir pay zone.

A ½ inch choke indicates the diameter of the test orifice and a recovery of 80 barrels in three hours indicates the flow, although it does not necessarily translate to 640 barrels a day in practice. The fluid composition indicates there is little oil in that zone, although its presence at all could be noted as encouraging for further tests in other zones in the well.

“Magpie-26, an oil and gas appraisal well located 1km southwest of Magpie-4 and 63km due east of the company’s gas plant, has made a new pool discovery of oil in basal Jurassic sediments. A cased hole test of the interval 1981.8m–1990.0m flowed 46 degrees API gravity oil at 1500 BOPD and gas at 5600 cubic metres a day through a 3/8 inch choke. The well will be completed as an oil producer from this zone. A second zone identified from electric logs in the overlying upper Jurassic sands will be completed at a later date. The proximity of the discovery to adjacent infrastructure means that production from this well can be quickly brought into production.”

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The well number in this report indicates it is some time since the original find was made and makes the discovery of a new pool at this stage something of a surprise. The worth of the well is spelt out by the statement that it will be completed as an oil producer. A cased hole means the well was cased and then perforated in the test zone.

The oil, at 46 degrees API gravity, is a fairly light variety and it flowed at a good rate of 1500 barrels a day. The gas flow at 5600 cubic metres a day is minor.

The reference to a second zone identified by logs and due for completion later, indicates there is a full knowledge of the region from other wells and fields nearby which can be correlated across to the discovery with confidence in its accuracy. However the second zone would be tested before an attempt was made to bring it on stream.

“The Jellyfish-2 well, 0.5km east of Jellyfish-1 discovery has reached a total depth of 2750m KB. Electric logs were run to TD and a wireline test recovered the following samples:

2424m	1.6 cu m gas
	10.0 litres of 38 degree API oil
	3.0 litres water/mud filtrate
2440m	0.2 cu m gas
	0.3 litres oil
	20.0 litres water/mud filtrate
2450m	26.0 litres water/mud filtrate
2430m	1.1 cu m gas
	5.0 litres oil
	10.0 litres mud/water filtrate
2415m	3.5 cu m gas
	0.5 litres 57 degree API condensate

Final electric logs were run prior to abandoning the well.”

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This report identifies Jellyfish-2 as an appraisal or confirmation well that was drilled half a kilometre away from the discovery well to a depth of 2507 metres below the level of the kelly bushing (KB) which is located on the floor of the drilling rig. The KB reference is mostly used in offshore wells, so to work out the depth of the well below the sea bed it is necessary to know the water depth and the height of the drill floor above sea surface.

Wireline tests are small samples collected in a test tool lowered down the well and they represent specific points only. Nevertheless, the tests indicate the presence of a hydrocarbon column or zone in the well with a gross pay of at least 25 metres between 2415 metres and 2440 metres. The column has gas/condensate at the top and oil beneath, plus a water column below.

There is no real indication from these samples of potential flow rates, although pressure data (not given in the report) would help in this regard. The electric logs would indicate whether the reservoir was continuous or whether it was broken by impervious shale zones. The logs would also give some indication of the position of the gas/oil and the oil/water contacts.

If the area is well known from nearby fields, this information may be enough to make a decision about viability. If not, a drill stem test and/or production test would be needed.

The reference to abandoning the well after final logging is not unusual offshore. It does not necessarily mean the discovery is judged non-commercial because often exploration wells are not used as final producers.

More information

Other pieces of information about the economics of a discovery can be gleaned from the more descriptive quarterly and annual reports.

•Discoveries on land generally have lower production and operating costs than those offshore (especially in deep water).

•Discoveries close to existing infrastructure enhance the economics of development.

•Shallow reservoirs are usually less costly to develop than deeper reservoirs because of the need for less drill pipe and casing, and the shorter time required for drilling development wells.

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•Higher production costs are usually associated with high temperature and high pressure reservoirs.

•Low permeability reservoirs can be more expensive to produce because they require artificial stimulation to increase permeability.

•Friable reservoir rock can crumble easily and hence require special completion tubing to stop sand clogging the well perforations.

•The thicker the reservoir sands, the better the likely reservoir pressure and flow rate. In addition, thin reservoirs often require more difficult and expensive horizontal drilling techniques.

•Oil discoveries are generally preferred because oil can always be sold on the world market. Gas is most valuable when the discovery is close to a potential market or existing infrastructure. Isolated gas discoveries, unless huge, can be virtually worthless.

•Light crudes are preferred to heavy crudes. The heavy crudes are often more viscous than lighter crudes and are harder to produce. Heavy crudes usually require more extensive refining and attract lower prices in the market place.

•Sour crudes (containing hydrogen sulphide) are more difficult to produce in an operational sense. They are toxic and corrosive and require extra equipment and increase the costs of development.

•Similarly, operational difficulties and costs are increased if the crude or the natural gas discovery contains high levels of inert gases like carbon dioxide and nitrogen which must be removed during processing.

•Condensate associated with a gas discovery can be sold at an attractive margin, hence the higher the volume of natural gas liquids recovered with the gas, the better the economics of a field.

•High oil prices improve the viability of even the most technically difficult discoveries, whereas discoveries made in, say, very deep water are likely to be marginal or uneconomic in times of low oil prices.

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Chapter 7. TAXATION, PRICING & MARKETING

Taxation

There are numerous types and rates of taxation on petroleum around the world, but the basic principle is to try and reconcile two objectives that often appear to be in conflict. The tax system is an attempt to maximise a government’s revenue from a depletable resource and yet preserve an appropriate (but not excessive) incentive for an explorer to find and develop those resources.

Usually a government owns the rights to the resources and relies on the private sector for discovery and development. So when setting tax rates, the government must understand the effect of after-tax incentives as perceived by private-sector explorers. On the one hand, under-taxation

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is not a good way to promote development because excessive incentives will mean the government gains unnecessarily low revenues. Conversely, over-taxation can be even less efficient because governments may lose oil and revenues from small and/or marginal fields. Equally, over-taxation may gratuitously increase geological risk so that wildcatting and other exploration is discouraged altogether.

Petroleum taxes are levied in addition to the normal business company taxes and apply to crude oil, natural gas and natural gas liquids like LPG as well as to refined products. They come in various forms, but the main fiscal regimes around the world include one or more of the following:

•Royalties — these are paid to the owner of the petroleum rights, usually a government, but can be private owners in onshore USA. Royalties are a percentage of the gross wellhead value of production and are usually charged at a fixed rate (typically 10 per cent–12.5 per cent). However sometimes they can be calculated on a sliding scale depending on the world oil price.

•Excise — this is a tax levied as a percentage of price, the rate set as a volume-weighted average realised price. For instance an annual production rate of up to 500 million litres (3.146 million barrels) of crude oil may be levied at, say, three per cent excise. A higher annual production of more than 800 million litres (5.034 million barrels) may be levied at a rate of 35 per cent excise. There will be other rates set for volumes of production in between these values.

Sometimes, as an incentive to develop smaller fields, low production rates (or production of a nominated volume) will be granted excise-free status. In other regimes condensate production marketed separately from crude oil may be granted an excise exemption.

Aseparate excise can be levied on both imports and domestic production of petroleum products like petrol, diesel and aviation fuel.

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•Petroleum Resource Rent Tax (PRRT) — this is a tax on oil company profits arising from crude oil and natural gas production. It is usually levied before normal company taxation, but PRRT payments are allowed as a deduction for company tax purposes.

Generally the tax is applied separately to each individual production project and not to aggregate company results. However companies are allowed to deduct development expenditure for their projects as well as their exploration costs incurred from all activities in a country’s PRRT regime areas.

The threshold to trigger the tax is usually related to some well-known rate such as a government bond rate. The tax itself is set at a fixed amount. In Australia, for instance it is 40 per cent. This rate is applied to net cash flows after returns on project outlays (determined by reference to actual expenditures) that exceed the threshold level.

•Production Sharing Contracts — this type of fiscal regime is now the most common around the world, but the applicable rates and percentages vary considerably from country to country. The effective tax rates are embedded within the regime although sometimes a separate royalty payment applies as well. An average PSC has a term of 30 years, usually with a termination upon request after about six years if no discovery has been made and an automatic termination after about 10 years without a find.

The sharing process begins with a given percentage of any production (say 10 per cent) being designated ‘first tranche petroleum’. This percentage rises (say, to 20 per cent) after a set period of production (perhaps five years). First tranche petroleum is shared by the contractor (oil company) and the host government or its designated authority, such as the national energy company, at ratios that vary with production rates. In this example it effectively means a flat royalty of between five per cent and seven per cent is paid to the host government during the first five years of production and between 10 per cent and 14 per cent after that.

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Once this figure has been calculated, contractors are allowed to recover investment credits equalling the quantity of production equivalent to say, 127 per cent of the exploration and capital costs incurred in each calendar year. Upon recovery of all these costs, the remaining petroleum production is shared so that the host government receives a percentage (say 50 per cent) of flows between, say, 0 and 50,000 barrels a day; maybe 60 per cent of flows between, say, 50,000 and 150,000 barrels a day; and an even higher percentage, perhaps 70 per cent, of flows greater than 150,000 barrels a day.

•Signature bonus — in some countries a company must pay the government a flat one-off amount known as a signature bonus fee to secure an exploration permit. Other countries apply what is known as an area fee which is calculated at a rate per square kilometre of the area of a company’s production permit. Such fees are effectively a front-end non-refundable tax.

•Refinery throughput tax — this is a downstream tax that is calculated at a given value per barrel of crude oil that is processed in the refinery.

•Carbon tax — a relatively new tax, this has the backing of the environmental lobby and is gaining acceptance in a number of countries, particularly in Europe, following the Kyoto Protocol and the ongoing debate about curbing greenhouse gas emissions. Not confined to the petroleum industry, the tax is levied on emissions of carbon dioxide and calculated per standard cubic metre of gas burned or released directly into the air from production facilities and transportation of raw material and product.

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Pricing and Marketing

Crude oil and condensate

Pricing and marketing of crude oil and condensate has two broad components — assaying and trading.

No two crude oils or condensates are exactly the same and the first thing a producer wants to know about a new discovery is the composition of the oil — in case there are any toxic components that need to be countered as part of a company’s health and safety program — and its value in the market place. The preliminary step is an elemental analysis which is carried out in a laboratory and is known as an assay.

It involves a miniature form of the refinery distillation process where the crude oil or condensate sample (usually 5–20 litres) is heated and the various fractions are separated out at their different boiling points. A note is taken of the percentage volume of each fraction within the sample before they undergo individual testing. The analyses are performed to determine such physical properties as freeze and pour points, smoke points and flash points.

Assays can be of varying complexity, but are usually one of three types

— mini, intermediate and marketing.

•Amini assay is usually done on a new discovery at the exploration phase prior to any production plans. This test provides a broad indication of the type and quality of the crude.

•The intermediate assay involves sufficient testing of the fractions to indicate the quality and quantity of products contained in the sample. For a new crude or condensate, this assay gives the marketers an idea of which refiners might find the feedstock a suitable input for their particular refineries. Sometimes the intermediate assay is also done on crudes that have been on stream for a while as a check to see if the composition has changed since production began.

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•A full marketing assay provides a very detailed analysis and involves a large number of boiling point fractions. The assay sets out all the detail a prospective buyer needs to determine whether the crude or condensate will match a particular refinery configuration.

The crude oil/condensate assay has become a vital basis for sales promotion. Competition is strong, particularly in the realm of light, low sulphur (sweet) crudes as many are vying for the same markets where the accent is on obtaining feedstocks suitable for maximising the yield of transport fuels. Hence producers ask the assay laboratories to look for the fractions and characteristics within their crudes and condensates that refiners value highly. The information also indicates the potential for blending various feedstocks to provide optimum qualities.

In many cases, samples of a new crude or condensate will also be given to prospective buyers so they can perform their own assays to confirm suitability.

Trading of crude and condensate is done at prices commercially negotiated between buyers and sellers. Crudes and condensates are generally priced in relation to what is known as a marker crude, which is a representative type for a particular region. It is picked because of its characteristics and because it has a significant volume of production traded on the international market. Malaysian Tapis crude is the marker for the Southeast Asian/Australasian region, while UK Brent crude is the usual marker for the North Sea/European region. Other markers include Dubai crude for the Middle East and West Texas Intermediate for the USA.

As an example, Tapis crude contains a more or less equal quantity of naphtha, jet/kerosene, gas, oil and residue fractions i.e. 25 per cent of each. The crude has a gross product worth (GPW) which is calculated by multiplying the weighted average of each product by that product’s price. Other crude oils, by comparison, contain varying amounts of these products and therefore have different GPWs. Crude oils which yield large amounts of the premium products (middle distillates like jet fuel and diesel fuel) have a greater GPW and are valued higher in the market than crudes

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