Converge blog

Gauge vs absolute pressure: the 14.7 psi that breaks bubble-point matching

2026-10-15T00:00:00Z

If your lab quotes a bubble point in psig and you type it into a model that works in psia, your bubble point is one atmosphere too low. That's 14.696 psi. At a 2,750 psia bubble point the error is 0.5 %, and you'd shrug it off. At a 360 psia bubble point it's 4.1 %, and it carries through into solution GOR, any regressed gas gravity, and the oil you forecast before gas comes out of solution.

Gauge and absolute

Absolute pressure is measured from a vacuum. Gauge pressure is measured from the local atmosphere:

p_abs = p_gauge + p_atm

A standard atmosphere is 101,325 Pa exactly. One psi is 6,894.757 Pa (NIST SP 811, Appendix B.8). So:

p_atm = 101,325 / 6,894.757 = 14.696 psia

Every PVT correlation, every equation of state and every material-balance equation works in absolute pressure. Gas volume goes as 1/p, and that relation has no meaning on a gauge scale. A separator or wellhead gauge reads relative to the air around it.

NIST's style guide (SP 811, section 7.4) says information shouldn't be attached to the unit symbol at all. It belongs on the quantity: "gauge pressure, 2,435 psi", not "2,435 psig". The industry writes psig anyway, and lab reports mix the two, so read every suffix.

The worked example

Physics regime: a black oil at reservoir temperature, at and below its bubble point. Units are oilfield throughout (psia, °F, scf/STB, rb/STB).

Standing's bubble point

Standing (1947) correlated 105 measured bubble points on 22 California oil-gas mixtures (API Drilling and Production Practice, pp. 275–287):

pb = 18.2 × [ (Rs / γg)^0.83 × 10^a − 1.4 ]      psia
a  = 0.00091 × T − 0.0125 × API                   T in °F

The data range is pb 130–7,000 psia, T 100–258 °F, Rs 20–1,425 scf/STB, API 16.5–63.8 and gas gravity 0.59–0.95. Both cases below sit inside it.

Take the fluid from Converge's sample field: 35 °API, gas gravity 0.75, 200 °F. Then

a    = 0.00091 × 200 − 0.0125 × 35 = 0.182 − 0.4375 = −0.2555
10^a = 0.5553

High bubble point, GOR 650 scf/STB:

Rs/γg        = 650 / 0.75 = 866.67
866.67^0.83  = 274.42
× 0.5553     = 152.38
− 1.4        = 150.98
× 18.2       = 2,747.8 psia   (2,733.1 psig)

Low bubble point, GOR 60 scf/STB:

Rs/γg        = 60 / 0.75 = 80.00
80^0.83      = 37.98
× 0.5553     = 21.09
− 1.4        = 19.69
× 18.2       = 358.3 psia     (343.7 psig)

The 2,747.8 psia result is Converge's benchmark case V1 (2,748 psia by hand). It's on the benchmarks page.

The 14.7 psi slip

Now say the lab reports the bubble point in psig and someone types it in as psia. The offset doesn't change, but its share of pb does:

	GOR 60 scf/STB	GOR 650 scf/STB
True pb	358.3 psia	2,747.8 psia
Gauge value entered as psia	343.7	2,733.1
Bubble-point error	−4.1 %	−0.53 %

The same 14.696 psi is eight times worse at the low bubble point. Shallow reservoirs, heavy and low-GOR oils, and depleted fields with a low current pressure all live at that end.

Where the error lands

I computed every row below with Standing's equations and checked them by running Converge's black-oil engine on the same inputs. Pressures are psia.

Effect	GOR 60 (low pb)	GOR 650 (high pb)
Rs from the correlation at the entered pressure	57.2 vs 60 scf/STB (−4.6 %)	645.9 vs 650 (−0.64 %)
Rs when the entered pb is honoured, at 300 / 2,000 psia	50.9 vs 48.4 scf/STB (+5.1 %)	446.8 vs 443.9 (+0.64 %)
Bo at the same pressures	1.0876 vs 1.0865 rb/STB (+0.1 %)	1.2712 vs 1.2698 (+0.11 %)
Gas gravity regressed to hit the entered pb	0.786 vs 0.75 (+4.8 %)	0.755 vs 0.75 (+0.64 %)
Pressure drop to the bubble point (pi 600 / 3,200 psia)	256.3 vs 241.7 psi (+6.1 %)	466.9 vs 452.2 psi (+3.2 %)
Vogel AOF, J = 1 STB/d/psi, pr 600 / 3,200 psia	447.3 vs 440.7 STB/d (+1.5 %)	1,985.3 vs 1,978.8 (+0.3 %)

Rs and Bo

When you honour a measured bubble point, the saturated Rs curve is stretched so that Rs equals the GOR at that pressure. A pb that's too low pulls the whole curve to the left. At every pressure below pb, the model then holds more gas in solution than the oil really does. That's +5.1 % at 300 psia in the low case.

Bo hardly moves, about 0.1 %. If you only check Bo, you won't see the problem.

Regression

Suppose you tune the correlation to the lab bubble point instead of honouring it directly, and you leave gas gravity free. The fit pushes gas gravity from 0.75 to 0.786. The regression reports a perfect match, so nothing looks wrong. But gas gravity feeds the pseudo-critical properties, the Z-factor and the gas density. You've traded a pressure-label error for a fluid-description error.

Material balance

Above the bubble point, an undersaturated oil produces by expansion alone. The Havlena-Odeh form reduces to F = N·Boi·ce·Δp, so the oil recovered before pb scales with pi − pb. A pb 14.7 psi too low gives you 14.7 psi of extra single-phase depletion. That's +6.1 % on the recovery to the bubble point when pi is 600 psia, and +3.2 % when pi is 3,200 psia.

The relative error depends on pi − pb, not on pb. A high-pressure reservoir sitting just above its bubble point is as exposed as a shallow one.

The same slip in a pressure history hurts more below pb. Gas FVF, Bg = 0.02827·z·T/p (ft³/scf, T in °R, p in psia), goes as 1/p. A reading of 285.3 psig typed as psia gives a Bg 5.2 % too high at constant z. That error goes straight into the (Rp − Rs)·Bg term of the underground withdrawal.

Inflow

Vogel's (1968) composite IPR is the least sensitive result here: +1.5 % on AOF in the low case and +0.3 % in the high case.

What Converge does about it

Engines, saved projects and the API hold pressure in psia only. The interface converts to bara at the display boundary, and pressure labels always carry the basis. Here is what's built:

Measured pb input. The PVT page's "Measured pb" field is labelled absolute. Its hint reads: "Add atmospheric pressure to a gauge reading (psig + 14.7)." The engine rejects a measured bubble point at or below 14.7 psia.
Range and mismatch warnings. The black-oil model warns when inputs, including the bubble point, fall outside the selected correlation's data range. It also warns when a measured pb differs from the correlation's own value by more than 20 %.
Imports. Production and material-balance history headers such as "p (psig)" or "p (barg)" are read and converted with the atmospheric offset. The Data import tab has an "Atmospheric pressure" setting for gauge readings. A bare "psi" header is read as gauge on a wellhead pressure and as absolute on a downhole pressure, and the import preview says which it chose so you can change it.
AI Engineer. Every AI Engineer tool that takes a pressure needs the unit stated: psia, psig, bara, barg, kPa or MPa. Values are converted to psia before any validation or comparison, and the reply lists each conversion. This came out of an audit case where a lab bubble point of 2,435 psig was compared with a model value of 2,435.7 psia and reported as a +0.03 % match. The lab value is 2,449.7 psia, so the real error was −0.57 %.

A short checklist

Read the suffix on every lab pressure: bubble point, CCE, differential liberation and separator stages. Separator pressures are very often gauge.
Convert at the boundary, once. Never convert halfway through a calculation.
Be most careful when pb is below about 1,000 psia, or when pi − pb is a few hundred psi.

Read the black-oil PVT guide for the inputs and correlation ranges, and units for how Converge handles field and metric display.

How Converge validates its engines

2026-10-15T00:00:00Z

Every Converge engine is checked against a number someone else published, with a stated tolerance, in a test that runs on every build. On 15 October 2026 the engine suite was 964 tests in 74 files, and all of them passed. This post describes what those tests compare against, how tight the tolerances are, and what we haven't validated yet.

Three kinds of reference

We use three kinds of reference, in order of preference:

A published solution with a stated answer. For example, SPE1, a textbook example, or NIST property data.
A synthetic case built from a known answer. For example, a tank built from N = 45 MMSTB. The truth is exact, so any error is the engine's.
An independent implementation. Used when no worked example with a stated answer exists, and we say so.

Reservoir simulation: SPE1

SPE1 is the first SPE comparative solution project (Odeh, 1981, JPT 33(1), SPE 9723). It's a 10 × 10 × 3 black-oil model with one gas injector and one producer, run for ten years. Converge ships it as a built-in case.

Check	Tolerance	Result
Oil-rate plateau	20,000 STB/d to 1 STB/d	20,000 STB/d
Producer switches from rate to pressure control	Day 800 to 1,300	Day 973
Peak average reservoir pressure	6,100 to 6,700 psia	6,423 psia
Field oil rate against the published reference run, 11 report times	1 %	Pass
Producing GOR	2.5 %	Pass
Producer and injector bottom-hole pressure	2 %	Pass
Block pressures at the injector and producer cells	3 %	Pass
Material-balance error, every time step	Below 10⁻⁶ of pore volume	9.3 × 10⁻⁸ worst step

The reference run is the summary file published with the open SPE1 input deck. The case runs in about 1.7 s on one laptop core.

A 300-cell Buckley-Leverett waterflood must also put its saturation shock within three cells of the analytical front.

Fluids

Black-oil correlations

The audit cases V1 to V9 use two fluids: 35 °API, gas gravity 0.75, 650 scf/STB at 200 °F, and 32 °API, 0.72, 520 scf/STB at 205 °F.

Case	Reference	Tolerance
V1 Standing bubble point	2,748 psia by hand (engine: 2,747.8)	±1.6 psi
V2 Standing bubble point	2,601 psia	±1.6 psi
V3 Standing Bo at pb	1.375 and 1.3037 rb/STB	0.0005 rb/STB
V4 Beggs-Robinson live-oil viscosity at pb	0.4927 and 0.6185 cp	0.1 %
V6 Dranchuk-Abou-Kassem Z with Sutton pseudo-criticals, gas gravity 0.7, 200 °F	0.9215, 0.8883, 0.9999 and 1.4308 at 1,000, 3,000, 5,000 and 10,000 psia	0.05 %
V9 Gas FVF at 3,000 psia	0.000983 rb/scf	10⁻⁶ rb/scf

The other four correlation sets (Vasquez-Beggs, Glasø, Petrosky-Farshad and Al-Marhoun) are each checked against a hand calculation. Each set's bubble point must also invert back to the input GOR.

Equation of state against NIST

Pure-component vapour pressures from Peng-Robinson are compared with NIST Chemistry WebBook saturation data. The cases are methane at 150 K (10.4 bar), ethane at 250 K (13.01 bar), propane at 300 K (9.9742 bar), n-butane at 300 K (2.5838 bar) and CO₂ at 280 K (41.603 bar). Each must be within 3 %.

Peneloux-shifted saturated-liquid propane at 300 K must be within 3 % of NIST's 488.1 kg/m³. For methane viscosity at 300 K, the NIST values at 1, 101 and 201 bar are 0.011136, 0.013795 and 0.019127 cp. The methane reference model and the Pedersen corresponding-states model must each be within 2 % of them. The untuned Lohrenz-Bray-Clark model must be within 5 % at 1 bar and 10 % at the higher pressures.

Saturation pressures and flashes for the SPE5 oil and other mixtures are compared with an independent open-source thermodynamics library. Bubble and dew points must agree within 0.01 %, and vapour fraction and phase compositions within 1 × 10⁻⁵.

Unit constants

The unit layer is tested against NIST SP 811. One psi must equal 6,894.757293168 Pa, and a standard atmosphere must equal 14.695948775513 psia, to 9 and 12 decimal places. On import, 25 barg must convert to exactly 377.29 psia.

Well test

The synthetic build-up is a 48 h drawdown at 800 STB/d, then 72 h shut in, generated from the line-source solution with superposition. The known answer is k = 180 md, skin +4.5 and initial pressure 3,650 psia.

Result	Known	Tolerance
Horner slope	26.43 psi/cycle	3 %
Horner permeability	180 md	3 %
Extrapolated pressure p*	3,650 psia	2 psi
Skin, Horner and log-log	+4.5	±0.3

There's also a printed example. Earlougher (1977), SPE Monograph 5, Example 5.1, gives a 40 psi/cycle slope, k = 12.8 md and skin 8.6. Converge must match k and skin within 5 %.

Deconvolution after von Schroeter, Hollaender and Gringarten (2004) must recover a known unit-rate response within 5 %. With 0.05 psi of gauge noise the limit is 10 %.

Decline

A 36-month synthetic well is built from qi = 3,500 STB/d, Di = 60 %/yr and b = 0.70. On exact data the Arps (1945) fit must return all three parameters to three decimal places. With 3 % noise, qi must be within 5 %. The EUR to a 30-year cap must be 4.78 MMSTB within 0.005 MMSTB. The exponential and harmonic EURs must match their closed forms, 1,980 STB within 0.5 STB and 9,210 STB within 5 STB.

The bootstrap P90–P10 band must contain the true EUR in at least 80 % of synthetic wells. On the 12-well set it contains it in 10, and we report that as marginal.

Material balance

For Havlena and Odeh (1963), a volumetric tank built from N = 45 MMSTB must give 45 MMSTB within 1 %. The engine gives 45.03 MMSTB.

Run the same history with an aquifer it doesn't have, and the fit must be blocked, not reported.

Ahmed (2006), Example 11-1, a volumetric undersaturated oil, is reproduced row by row. Underground withdrawal F must match the printed table to 0.01 Mbbl. A least-squares line through the origin gives N = 282.8 MMSTB, which we confirmed with independent Python. The book reads 257 MMSTB off a hand-drawn line, and the test records that difference rather than hiding it.

The van Everdingen-Hurst dimensionless influx is checked against Ahmed's Tables 10-1 and 10-2. In Example 10-4, an infinite radial aquifer, the influx at 6 and 12 months must be within 0.5 %.

Economics

The simplest case is one you can check by hand: −100, then 30 a year for five years, end-of-period discounting at 10 %. NPV must be 12.476 within 10⁻³, and IRR must be 15.24 % within 10⁻⁹.

A production-sharing case is checked line by line against a hand sheet. Each row must match to 10⁻⁶: cost oil, contractor and government profit oil, tax paid on behalf, bonuses and net cash flow. The Nigeria PIA template is screening values and is not part of the benchmark.

The audit

On 15 October 2026 an independent reviewer recomputed 30 Converge results by hand or with separate code, and 25 passed first time. The five failures were in reference points and defaults, not core physics: the pressure taken as the start of shut-in for skin, a default aquifer left on, two uncertainty bands that missed the truth, and network gas accounting with gas lift. Each is now a named test. Four are fixed; the decline bootstrap is the marginal one above.

What isn't validated yet

These are open, and the product doesn't claim them:

The full EOS phase envelope against an independent PVT package.
The surface network and the integrated forecast against independent tools. Mass balance closes, but no external comparison has been made.
SPE9 matches only partly: oil rate tracks the reference and water production doesn't. SPE3 hasn't been attempted.
Gas rate-transient type curves, wax and asphaltene models, and several printed well-test examples.

Run them yourself

Every case on the benchmarks page can be rerun from your own account. Use the scripting editor under Integrations or the REST API; see the scripting SDK guide. The sample field's fluid is the V1 fluid, so its PVT page shows the 2,748 psia bubble point straight away.

Nigeria's Petroleum Industry Act 2021: fiscal terms for field economics

2026-10-15T00:00:00Z

Under the Petroleum Industry Act 2021 (PIA), a Nigerian oil field pays royalty on volume and on price, hydrocarbon tax on crude profit (onshore and shallow water only), and companies income tax. It also contributes to a host community trust. This guide gives the screening values for each term and the section or schedule of the Act it comes from. It also says which terms Converge's economics module computes.

Section references are to the gazetted Act (Act No. 6 of 2021, Official Gazette No. 142, Vol. 108, 27 August 2021), as held on FAOLEX, the UN Food and Agriculture Organization's legal database. The Nigerian Upstream Petroleum Regulatory Commission (NUPRC), set up by s.4, collects royalty and issues the regulations.

What applies where

Term	Onshore	Shallow water (≤ 200 m)	Deep offshore (> 200 m)	Frontier
Royalty by production	Yes	Yes	Yes	Yes
Royalty by price	Yes	Yes	Yes	No (7th Sch. para 11(2))
Hydrocarbon tax	Yes	Yes	No (s.260(3))	No, until reclassified (s.260(3))
Companies income tax	Yes	Yes	Yes	Yes
Host community trust	Yes	Yes	Yes	Yes

Royalty by production

Royalty by production is charged on the chargeable volume of crude oil and condensate, field by field, each month (Seventh Schedule, para 10). For royalty, condensate counts as crude oil and natural gas liquids count as gas (s.260(4)).

Terrain	Rate	Low-volume tranches
Onshore	15 %	First 5,000 bopd at 5 %, next 5,000 bopd at 7.5 %, above 10,000 bopd at 15 % (para 10(4))
Shallow water, up to 200 m	12.5 %	First 5,000 bopd at 5 %, next 5,000 bopd at 7.5 %, above 10,000 bopd at 12.5 %
Deep offshore, over 200 m	7.5 %	First 50,000 bopd at 5 %, the rest at 7.5 % (para 10(3))
Frontier basins	7.5 %	None
Natural gas and NGLs	5 %	2.5 % for gas produced and used in Nigeria (para 10(6))

The tranches are incremental, so each slice of daily production pays its own rate. Effective crude royalty rates:

Field rate	Onshore	Shallow water	Deep offshore
8,000 bopd	5.94 %	5.94 %	5.00 %
20,000 bopd	10.63 %	9.38 %	5.00 %
80,000 bopd	13.91 %	11.72 %	5.94 %

Royalty by price

On top of royalty by production, onshore, shallow-water and deep-offshore crude and condensate pay a royalty by price (Seventh Schedule, para 11). The rate is 0 % below US$50/bbl, 5 % at US$100/bbl and 10 % above US$150/bbl, interpolated linearly in between. The price levels were set for 2020 and rise 2 % at the start of each calendar year. The Act's own example is US$75/bbl in 2020, which gives 2.5 %. Royalty by price is credited to the Nigerian Sovereign Investment Authority (para 11(3)).

Year	0 % below	5 % at	10 % above	Rate at US$75/bbl
2020	US$50.00	US$100.00	US$150.00	2.50 %
2026	US$56.31	US$112.62	US$168.92	1.66 %

The 2026 levels are the 2020 levels times 1.02⁶.

Hydrocarbon tax

Hydrocarbon tax (HT) is charged on profit from crude oil, field condensate and liquid NGLs from associated gas, measured upstream of the measurement point (s.260(1)(a)). It doesn't apply to gas, to deep offshore, or to frontier acreage until it is reclassified (s.260(1)(b), s.260(3)).

Item	Screening value	Source
HT rate, petroleum mining lease (PML)	30 % of crude profit	s.267(a)
HT rate, petroleum prospecting licence (PPL)	15 % of crude profit	s.267(b)
Associated-gas costs upstream of the measurement point	Allocated to crude oil	s.260(2)
Deductible	Rents, royalties, opex, decommissioning-fund contributions, levies, host community trust, NDDC and similar contributions	s.263(1)
Not deductible	Gas-flare fees and penalties, finance costs, head-office costs, among others	s.264
Losses	Carried forward	s.265

Production allowance

The production allowance is deducted from HT profit per barrel (Sixth Schedule, para 1).

Lease	Allowance	Cumulative limit for the higher rate
New lease, onshore	Lower of US$8.00/bbl and 20 % of fiscal oil price, then the lower of US$4.00/bbl and 20 %	50 MMbbl
New lease, shallow water	Same	100 MMbbl
New lease, deep offshore and frontier	Same	500 MMbbl
Converted oil mining lease	Lower of US$2.50/bbl and 20 % of fiscal oil price	None

Cost price ratio

The cost price ratio (CPR) caps the HT costs you can deduct in a year at 65 % of gross revenue at the measurement point (Sixth Schedule, para 2(1)). Rents, royalties and the s.263(1)(h) contributions sit outside the cap. Costs above the cap carry forward. Any still unrelieved when crude operations end are lost (para 2(2)(c)).

Capital allowances

Qualifying plant, pipeline, building and drilling expenditure is written down at 20 %, 20 %, 20 %, 20 % and 19 % over five years, with 1 % kept until disposal (Fifth Schedule, para 17). The first exploration well and the first two appraisal wells in a field are deducted when incurred (s.263(1)(d)).

Companies income tax and the development levy

Upstream operations also pay companies income tax (s.260(5), s.302). HT isn't deductible for it. EY reports that under the Nigeria Tax Act 2025, effective 1 January 2026, companies other than small companies pay 30 %. The same Act brings in a single 4 % development levy on assessable profit, which replaces earmarked taxes such as the Tertiary Education Tax.

Host communities development trust

Each settlor pays 3 % of its actual operating expenditure for the preceding financial year into the host communities development trust fund (s.240(2)). The settlor is the licensee or lessee, paying through the operator where there is one. The contribution is deductible for HT (s.263(1)(h)).

Funds outside field cash flow

Fund	What the Act says	In a field model?
Frontier Exploration Fund (s.9(4)–(5))	30 % of NNPC Limited's profit oil and profit gas under production sharing, profit sharing and risk service contracts	No: paid out of NNPC's share, not by the field
Midstream and Downstream Gas Infrastructure Fund (s.52(7))	0.5 % of the wholesale price of petroleum products and natural gas sold in Nigeria, collected from wholesale customers. Also gets grants and gas-flare penalty money	Only if you model domestic gas sales at the wholesale point
Environmental remediation (s.103)	Financial contribution for remediation of environmental damage	Model it if your licence sets an amount. We give no screening value

For new acreage, a PSC has a 70 % cost limit on total oil production (Seventh Schedule, para 14(4)). Conversion contracts have 60 % (para 14(9)). The minimum government profit oil rises with cumulative field production: 5 %, 10 %, 15 %, 25 %, 35 % and 45 %, at thresholds of 50, 100, 350, 750 and 1,500 MMbbl.

What Converge models

In Economics, choose Nigeria PIA 2021 under Fiscal regime on the Fiscal tab. Then set Terrain, Licence (PML or PPL) and Lease (granted after the Act, or converted).

Term	Converge	Default
Royalty by production, with tranches	Yes, from terrain and the period-average oil rate	Statutory rates above
Royalty by price, with the 2 %/yr escalation	Yes; none for frontier	On
Gas and NGL royalty	Yes	5 %, or 2.5 % for gas used in Nigeria
Hydrocarbon tax	Yes, onshore and shallow water only	30 % PML, 15 % PPL
Production allowance	Yes, including the split when cumulative production crosses the threshold	New lease
Cost price ratio	Yes, with carry-forward and a warning for costs lost at the end	65 %
Fifth Schedule capital allowances	Yes, or each capex item's own method	Fifth Schedule
Companies income tax	Yes	30 %
Development levy	Yes, on assessable profit	4 %; set 3 % to model the Tertiary Education Tax for years before 2026
NDDC levy (NDDC Act, not the PIA)	Yes, approximated as 3 % of opex plus capex	3 %
Host community trust	Yes, 3 % of the previous period's opex	3 %
PSC cost limit and minimum profit-oil scale	Yes: choose the PSC regime and click Apply PIA 2021 PSC minimum terms	70 % cost limit
Gas flare penalty	Yes, on the Carbon tab, not deductible	Off
Frontier Exploration Fund, gas infrastructure levy, remediation fund	No	–

Converge simplifies in four ways. The first three are stated in the warnings on the results:

Royalty tranches are monthly in the Act. Converge applies them to the period-average daily rate.
NGLs are treated as gas for royalty and kept out of the HT base.
HT and CIT are computed on the field alone (ring-fenced). Multi-field consolidation isn't modelled.
The fiscal oil price is your price deck net of the differential.

The PIA is excluded from Converge's benchmarks. The royalty, tax, NPV and IRR arithmetic is checked against hand calculations there, but the fiscal template isn't. See the economics guide for the full input list.

Converge blog

Gauge vs absolute pressure: the 14.7 psi that breaks bubble-point matching

Gauge and absolute

The worked example

Standing's bubble point

The 14.7 psi slip

Where the error lands

Rs and Bo

Regression

Material balance

Inflow

What Converge does about it

A short checklist

How Converge validates its engines

Three kinds of reference

Reservoir simulation: SPE1

Fluids

Black-oil correlations

Equation of state against NIST

Unit constants

Well test

Decline

Material balance

Economics

The audit

What isn't validated yet

Run them yourself

Nigeria's Petroleum Industry Act 2021: fiscal terms for field economics

What applies where

Royalty by production

Royalty by price

Hydrocarbon tax

Production allowance

Cost price ratio

Capital allowances

Companies income tax and the development levy

Host communities development trust

Funds outside field cash flow

Production sharing contracts

What Converge models