Field development concepts: surface facilities

Quick refresher

The development concept answers these questions: where to drill from, where to separate and treat the production, where to deliver it, what to inject and how, and where to get power. It is chosen early, and it sets most of the costs for the whole life of the field.
The loads on the facilities change over the life of the field. Oil and gas rates are highest on the plateau. Liquid and injection rates are highest from the middle of the field's life, and the water rate in the last years. The liquid capacity decides how long the plateau lasts. In this lesson's example the liquid capacity is twice the oil plateau rate, and the plateau ends 6.92 years after the start of the project. If the liquid capacity is only a quarter (25%) above the oil plateau rate, the plateau ends after 5.49 years.
Associated gas has to be used at the moment it is produced. In the first years there is a surplus, which must be delivered, processed or injected. By the end of the field's life there is a shortage, even for the field's own power plant.
On land, distances, terrain and climate shape the facilities: well pads, gathering lines, booster stations and a central processing facility. At sea, the facilities depend on water depth, waves and ice, on whether oil can be stored, and on what other facilities are nearby.
Fields are developed in phases. The first phase gives production and data, and the next phases are designed using those data. This is how Tengiz, Karachaganak and Kashagan were developed.
We compare the options by NPV over the whole range of reserves. The top of the “NPV against plateau rate” curve is flat. So we choose a solution that works reasonably well at any reserves in the range, not the best one for a single scenario.

Key relationships

q_o = \min\!\left[Q,\ L\,(1 - \text{WC})\right]

the oil rate is limited by the oil capacity $Q$ (the plateau rate) and by the liquid capacity $L$

R_p = R_{\text{bt}} + (1 - R_{\text{bt}})\left(1 - \frac{Q}{L}\right)^{2}

share of the reserves produced by the end of the plateau, for the water cut curve of this lesson

q_{\text{inj}} = \frac{B_o q_o + B_w q_w}{B_w}

water injection that replaces the withdrawal (the volume of fluid taken out of the reservoir) at reservoir conditions (there is no free gas)

V_{\text{fuel}} = \frac{N}{\eta\,Q_{\text{LHV}}}

fuel gas used by a power plant of power $N$

Common pitfalls

Designing the plant only for the oil plateau and forgetting the water: at the end of the field's life there is several times more liquid than oil.
Treating associated gas as free fuel for the whole life: in the late years there is not enough even for the field's own power plant.
Copying the concept of a neighbouring field without adjusting for the fluid, the water depth, the climate and the infrastructure.
Choosing an option for one average reserves scenario without checking what happens at low and at high reserves.
Assuming that phasing is always more profitable: splitting the project loses economies of scale (the saving that comes with a bigger plant), and late phases give less than they seem to.

After this lesson you can

list the elements of a development concept and follow the production (everything that comes out of the wells) from the wellhead to the point where sales oil and gas are handed over
estimate how the rates of oil, water and gas and the injection volume change over the life of a field, use them to choose the capacities of the facilities, and check the associated gas balance
describe the facilities on land (well pads, gathering lines, booster stations, the central processing facility, the pressure maintenance system) and at sea (platforms, floating units, subsea wells, artificial islands), and the conditions in which each option fits
name the functions of a field platform and of the central processing facility, and explain how the artificial lift method and injection change what facilities are needed
explain why fields are developed in phases, and compare facility options by NPV (net present value) while taking the uncertainty of the reserves into account
show, with the examples of Tengiz, Karachaganak and Kashagan, how the fluid, the water depth, the climate and the infrastructure shaped the facilities

What a development concept consists of

The accumulation (the body of oil and gas in the rock) has been discovered and appraised (confirmed with further wells and tests). The production profile (how the rate changes with time) has been built for several development options (development planning). Now we must decide what equipment will do the producing: which facilities to build, where, and in what order. The answer is made of several linked decisions.

The wells and where they are drilled from. On land, from well pads, with inclined (deviated) and horizontal wellbores (Directional wells: applications and profile, Horizontal wells). At sea, from a platform, from an artificial island, or from subsea wellheads on the seabed.
Gathering the production. On land: flowlines (the pipes from each well), metering units (which measure what each well produces) and gathering pipelines. At sea: subsea pipelines and risers (the vertical sections from the seabed up to the platform) (flowline and gathering network).
Treatment. Separating the production into oil, gas and water, and bringing each stream to the requirements of the buyer, the pipeline or injection (the next section).
Delivery and transport. Oil goes into a main oil pipeline, onto a tanker or into railway tank cars. Gas goes into a gas pipeline, to a processing plant, to the field's own needs or back into the reservoir.
Injection. A source of water or gas, its treatment, and the pumps and compressors that maintain the reservoir pressure (Why water is injected: pressure maintenance and oil displacement, Displacement of oil by gas).
Power and support systems. A power plant or a connection to the grid, fuel gas, a flare system (where unwanted gas is burned off safely), water supply, communications, roads and housing for the staff.

The decisions depend on each other. The number of wells and the plateau rate set the capacity of the plants. The distance to the main pipelines decides whether the field needs its own pipeline or tanker loading. The fluid composition decides the materials, the treatment method and what to do with the gas. So the concept is chosen as a whole. We compare several options from start to finish, from the well to the hand-over of the products.

From the wellhead to the sales products

A well delivers a mixture of oil, gas and water, sometimes with sand, salts, hydrogen sulfide and carbon dioxide. Each component can be sold or used only on its own, and only after treatment. So every treatment system has one task: to split the flow into oil, gas and water and to bring each of them to its own requirements.

The three streams and what is done with them

Stream: Oil
What we need to get: stable oil: with a limited vapour pressure (how readily the oil gives off vapour) and a small content of water, salts and hydrogen sulfide
Main operations: stage separation, dehydration (removing the water), desalting (removing the salts), stabilisation (removing the lightest components so that the oil is safe to store) (Oil treating: separators, dehydration, desalting and stabilisation)

Stream: Gas
What we need to get: gas with no liquid droplets, with low water and hydrocarbon dew points (the temperatures at which water or heavier hydrocarbons start to condense), without hydrogen sulfide, at the required pressure
Main operations: drying, sweetening (removing hydrogen sulfide), recovery of heavier hydrocarbons, compression (Gas processing and compression)

Stream: Water
What we need to get: water that is fit for injection into the reservoir or for disposal
Main operations: removing oil and solid particles, checking compatibility (Produced water: composition, treatment and disposal, Water injection systems)

Stream	What we need to get	Main operations
Oil	stable oil: with a limited vapour pressure (how readily the oil gives off vapour) and a small content of water, salts and hydrogen sulfide	stage separation, dehydration (removing the water), desalting (removing the salts), stabilisation (removing the lightest components so that the oil is safe to store) (Oil treating: separators, dehydration, desalting and stabilisation)
Gas	gas with no liquid droplets, with low water and hydrocarbon dew points (the temperatures at which water or heavier hydrocarbons start to condense), without hydrogen sulfide, at the required pressure	drying, sweetening (removing hydrogen sulfide), recovery of heavier hydrocarbons, compression (Gas processing and compression)
Water	water that is fit for injection into the reservoir or for disposal	removing oil and solid particles, checking compatibility (Produced water: composition, treatment and disposal, Water injection systems)

The exact requirements for sales oil and gas are set by standards and by the acceptance conditions of pipeline companies and buyers. The lessons on treating oil, gas and water explain them.

The main separation uses gravity. It takes place in separators (vessels in which gas, oil and water separate) while the pressure is lowered in steps. Gas comes out of the oil, and free water (water not mixed into the oil) settles (Separator calculations and optimum separator pressure). The higher the wellhead pressure, the more stages we can install, and the more light hydrocarbons stay in the oil. Oil and water form an emulsion (tiny droplets of one liquid held in the other). We break it with heat, chemicals and an electric field. We compress the gas to the pressure of the pipeline or of injection, and we dry it, so that hydrates (ice-like solids made of gas and water) do not form in the pipes (temperature margin).

Where to separate is also part of the concept. We can separate the gas and most of the water close to the wells, at an intermediate station, and send only oil onward. Or we can bring the whole flow to a central facility. At sea we can separate on the platform, or send the multiphase flow (oil, gas and water together) to the shore. It is not worth pumping water over tens of kilometres just to inject it back near the wells. A multiphase flow in a long pipeline also causes large pressure losses, liquid slugs (plugs of liquid that move through the pipe), hydrates and wax.

Hydrogen sulfide changes everything. The steel of pipelines and equipment must resist sulfide stress cracking (cracking of steel caused by hydrogen sulfide), the plants must recover sulfur, and a leak becomes dangerous to life (Composition of reservoir fluids). On the subsalt fields of the Pre-Caspian Basin (fields below a thick layer of salt), sulfur is a significant product for sale. In 2024 Tengiz produced about 2.47 million t of sulfur and Kashagan about 1.42 million t.

Loads on the facilities over the life of the field

The oil production profile goes through three stages: a ramp-up to the plateau as wells are put into production, the plateau, and the decline (production profile in the project model). But the treatment facilities handle the whole flow, not only the oil. The composition of this flow changes over the life of the field more than the oil rate does. In waterflooding (pushing the oil to the wells by injecting water), the injected water reaches the producing wells after some time. The water cut (the share of water in the produced liquid) then rises to 90% and higher.

This gives two limits on capacity. The wells and the oil treatment unit set the oil plateau rate $Q$ . The separators, pumps and water treatment units set the liquid capacity $L$ : how much oil and water together the facilities can take. While there is little water, the first limit applies: we produce $Q$ of oil, and the liquid rate grows. When the liquid reaches $L$ , we can produce only $L(1 - \text{WC})$ of oil. As the water cut rises, the oil rate falls. The plateau is over.

Oil rate under the oil and liquid limits

q_o = \min\!\left[\,Q,\ L\,(1 - \text{WC})\,\right],\qquad q_w = q_o\,\frac{\text{WC}}{1 - \text{WC}}

where:

$q_o,\ q_w$ oil and water rates of the field at standard conditions, m³/d
$Q$ oil plateau rate: how much oil the wells can give and the oil treatment unit can take, m³/d
$L$ liquid capacity of the facilities: oil and water together, m³/d
$\text{WC}$ water cut: the share of water in the produced liquid; it grows with the share of the reserves produced, fraction

Units: any consistent units; volumes at standard conditions

Holds when

The wells can give more liquid than the facilities can take, so the rate is limited by the facilities, not by the reservoir.
The water cut depends only on the share of the reserves already produced, not on the rate of production. This is a simplification: in practice fast production can make the waterflood sweep (the part of the reservoir reached by the water) worse.
In the late years the economic limit also restricts production: when the revenue no longer covers the costs, the field is shut down.

The plateau ends when the water cut reaches $1 - Q/L$ . The larger the margin in liquid capacity, the later this happens. After that the oil rate falls as the water cut rises, while the facilities work at full liquid capacity.

CalculatedCalculated rates of the assumed field for the base facility option: oil plateau rate 6400 m³/d, liquid capacity 12,800 m³/d. The dashed line is the oil rate if the liquid capacity is only 8000 m³/d: the plateau ends sooner, but more oil remains for the late years.

Worked exampleWhat loads the facilities must be designed for

Given (assumed data)

Reserves: oil reserves recoverable under full waterflooding, $N_r = 20$ million m³
Water cut: water breaks through to the producing wells when 20% of the reserves have been produced ( $R_{\text{bt}} = 0.2$ ). After that $\text{WC} = \sqrt{(R - 0.2)/0.8}$ , where $R = N_p/N_r$ is the share of the reserves produced. The curve is assumed; a reservoir model gives a curve of this kind
Facility option: oil plateau rate $Q = 6400$ m³/d, liquid capacity $L = 12{,}800$ m³/d. First oil comes at the start of year 4 of the project, and the ramp-up to the plateau takes a year
Fluids: gas–oil ratio 80 m³/m³ (the reservoir pressure is kept above the bubble point pressure, the pressure at which gas starts to come out of the oil); $B_o = 1.25$ and $B_w = 1.02$ are the formation volume factors of oil and water (the volume that one cubic metre at standard conditions takes in the reservoir); injection replaces the volume withdrawn

Solution

The plateau ends when the facilities fill up with liquid: $\text{WC} = 1 - Q/L = 1 - 6400/12{,}800 = 0.50$ . The share of the reserves produced by that moment is $R_p = 0.2 + 0.8\cdot 0.50^2 = 0.400$ , that is $0.400\cdot 20 = 8.00$ million m³.
During the year of ramp-up, half of a full year's plateau volume is produced: $365\cdot 6400/2 = 1.168$ million m³. The rest is produced at 6400 m³/d, that is 2.336 million m³ a year: $(8.00 - 1.168)/2.336 = 2.92$ years. The plateau ends $3 + 1 + 2.92 = 6.92$ years after the start of the project, in year 7.
Gas is highest on the plateau: $6400\cdot 80 = 512$ thousand m³/d. From year 8 the liquid rate is at the limit $L$ . On average over that year the rates are 5500 m³/d of oil and 7300 m³/d of water.
The injection needed to replace the withdrawal in year 8 is $(1.25\cdot 5500 + 1.02\cdot 7300)/1.02 = 14{,}040$ m³/d. It is more than the liquid capacity, because a cubic metre of oil takes 1.25 m³ in the reservoir.
Water is highest in the last years: in year 20 it is 12,148 m³/d, with oil at 652 m³/d. The water cut is 94.9%.
For comparison, with $L = 8000$ m³/d the plateau would end at $\text{WC} = 1 - 6400/8000 = 0.2$ and $R_p = 0.2 + 0.8\cdot 0.2^2 = 0.232$ . That is already after 5.49 years, and by the end of year 10 11.14 million m³ of oil would be produced instead of 13.05.

Answer: The facilities are designed for 6400 m³/d of oil and 512 thousand m³/d of gas (the plateau), for 12,800 m³/d of liquid (from year 8), for 14,040 m³/d of injection, and for water up to 12,148 m³/d by year 20, which is almost twice the oil plateau rate.

What it means. The highest loads fall in different years: for oil and gas on the plateau, for liquid and injection in the middle of the field's life, and for water at its end. We design each part of the plant for its own maximum. The liquid capacity is the main decision. If the margin is only a quarter, the plateau ends almost one and a half years earlier, and production over the first 10 years is almost 2 million m³ lower. A margin that is too large does not pay either: the plant is paid for at once, and the extra oil comes late (see the table below). The model is rough. Here the water cut depends only on the share of the reserves produced. In reality it also depends on the production rate, the placement of the wells and how uneven the reservoir is (its heterogeneity). The data in this example are assumed for illustration.

Liquid capacity: oil plateau rate 6400 m³/d, average reserves

Liquid capacity, m³/d: 8000
Plateau ends, years from the start: 5.49
Oil in 10 years, million m³: 11.14
Plant, US$ million: 296.9
NPV at 10%, US$ million: 707.6

Liquid capacity, m³/d: 12,800
Plateau ends, years from the start: 6.92
Oil in 10 years, million m³: 13.05
Plant, US$ million: 393.6
NPV at 10%, US$ million: 788.3

Liquid capacity, m³/d: 19,200
Plateau ends, years from the start: 8.26
Oil in 10 years, million m³: 14.27
Plant, US$ million: 502.0
NPV at 10%, US$ million: 777.3

Liquid capacity, m³/d	Plateau ends, years from the start	Oil in 10 years, million m³	Plant, US$ million	NPV at 10%, US$ million
8000	5.49	11.14	296.9	707.6
12,800	6.92	13.05	393.6	788.3
19,200	8.26	14.27	502.0	777.3

The cost of the plant is proportional to the liquid capacity raised to the power 0.6 (US$450 million at 16,000 m³/d). The other costs and taxes are as in the plateau-choice example below. The gain from extra capacity is large at first and then disappears: going from 12,800 to 19,200 m³/d no longer pays for itself. The data are assumed for illustration.

Gas is more difficult. Oil can be stored in tanks, but associated gas has to be put to use at the same moment it is produced. It can be delivered into a gas pipeline, processed, burned in the field's own power plant, used for gas lift (injecting gas into the well to lighten the liquid column) or injected back into the reservoir. In Kazakhstan it is prohibited to flare raw gas (to burn gas that has not been treated in a flare), except in the cases named in the Subsoil Code: well testing, extended well testing, start-up, commissioning and repair of equipment, and accidents. Producing gas, including associated gas, needs an approved programme for processing or using it. So the concept already decides what happens to the gas, and it does so for the whole life of the field, because the amount of gas differs greatly from year to year.

Fuel gas consumption of a power plant

V_{\text{fuel}} = \frac{N}{\eta\,Q_{\text{LHV}}}

where:

$V_{\text{fuel}}$ fuel gas rate at standard conditions, m³/s
$N$ electric power to be generated, W
$\eta$ efficiency of the power plant: the share of the heat of combustion that becomes electricity, —
$Q_{\text{LHV}}$ lower heating value of the gas per cubic metre at standard conditions (the heat released when it burns), J/m³

Units: SI; to get thousand m³/d, multiply the result by 86.4

Holds when

The efficiency is constant. In gas turbines it falls at part load and in hot weather, and then the fuel consumption is higher.
The heating value of associated gas depends on its composition: the more ethane, propane and butanes, the higher it is.

The power of the pumps that lift the liquid and inject the water grows with the volume of liquid, just when there is less oil and associated gas. So in the late years the field usually does not have enough gas of its own.

Worked exampleIs there enough associated gas for the field's own power plant?

Given (assumed data)

Field and facility option: from the previous example; the electricity comes from the field's own gas turbine power plant
Load: a constant 5 MW (treatment, support systems, the camp); submersible pumps lift the liquid, raising the pressure by 12 MPa at an efficiency of 45%; injection pumps raise the pressure by 15 MPa at an efficiency of 70%
Power plant: gas turbine efficiency 32%; lower heating value of the associated gas 38 MJ/m³

Solution

Year 5, on the plateau: the liquid rate is 6400 m³/d, and the injection is $1.25\cdot 6400/1.02 = 7843$ m³/d. The pump power (hydraulic power, the power the pump gives to the liquid: $q\,\Delta p/86.4$ kW) is, for lifting, $6400\cdot 12/86.4/0.45 = 1975$ kW, and for injection $7843\cdot 15/86.4/0.7 = 1945$ kW. The total is $5 + 1.975 + 1.945 = 8.92$ MW.
Fuel: $8.92\cdot 10^6/(0.32\cdot 38\cdot 10^6) = 0.734$ m³/s, or $0.734\cdot 86.4 = 63.4$ thousand m³/d. That is 12.4% of the associated gas (512 thousand m³/d). The other 449 thousand m³/d must be delivered, processed or injected.
In year 15 the rates are: oil 1439, liquid 12,800 and injection 13,124 m³/d. Power: lifting 3951 kW, injection 3255 kW, total 12.21 MW. Fuel: $12.21/(0.32\cdot 38)\cdot 86.4 = 86.8$ thousand m³/d, while the associated gas is $1439\cdot 80/1000 = 115.1$ thousand m³/d.
The field's own gas runs short when the oil rate falls below $86.8\cdot 1000/80 \approx 1085$ m³/d. In this option that happens from year 17.

Answer: On the plateau the power plant burns about 63.4 thousand m³/d, which is 12.4% of the associated gas, and there is a surplus of gas. By year 15 the fuel takes 75% of the gas, and from year 17 the field's own gas is no longer enough.

What it means. An oil field under waterflooding usually has a surplus of gas in the first years and a shortage in the last years. The pump power grows with the liquid, while the gas falls together with the oil. The concept has to cover both sides: where to deliver the gas in the first years (a gas pipeline, processing, injection) and where to get power in the late years (a connection to the power grid, gas from outside). A pipeline built to deliver gas may carry gas in the opposite direction in the late years. The data in this example are assumed for illustration.

Facilities on land

On land the wells are grouped on well pads. From one pad, crews drill several wells, and sometimes dozens, with inclined (deviated) and horizontal wellbores to different points of the reservoir (well pad). This means fewer roads, power lines and flowlines, easier servicing of the wells and less disturbed land. The area of the accumulation that one pad can cover is limited by the horizontal departure (the sideways distance from the wellhead to the bottom of the well) that directional drilling can reach (Directional wells: applications and profile).

SchematicFacilities of an oil field on land (schematic). The production of the wells flows along flowlines to the automated group metering stations (AGMS), and then along a gathering header to the booster pump station (BPS) with a preliminary water removal unit (PWRU). From there the oil goes to the central processing facility and into the oil pipeline. The gas goes to the compressor station. The water goes to the water injection pump station (WIPS) and into the injection wells. AGMS, BPS, PWRU and WIPS are short labels used only in the figure.

The path of the production in an oil field

1
Wells and flowlines
The production of each well goes along its own flowline to a metering station. At the wellhead there are the Christmas tree (the set of valves that controls the well), a choke (a valve that limits the flow) and sensors (why a well needs a choke).
2
Group metering
An automated group metering station sends the flow of one well at a time into a test separator (a separator used only for measuring). It measures the liquid and gas rates of the well and its water cut. The other wells meanwhile flow into the common header.
3
Booster pump station
A booster pump station separates the gas of the first separation stage. It pumps the liquid onward when the wellhead pressure is not enough to bring it to the central facility. Often a preliminary water removal unit stands at the same place. It separates most of the water. This water is injected back into the reservoir nearby, so it does not have to be pumped to the central facility.
4
Central processing facility
At the central processing facility the separation is completed and the oil is dehydrated (the water is removed), desalted (the salts are removed) and stabilised (the lightest components are removed, so that the oil can be stored safely). Then the oil is stored in tanks, its quantity and quality are measured at the custody-transfer metering unit (the unit that measures the oil handed over for sale), and it is handed over to the main oil pipeline.
5
Gas
The separated gas is compressed. Then it is sent to a gas processing plant or into a gas pipeline, burned in the field's own power plant, used for gas lift (the gas lift system on the surface) or injected into the reservoir.
6
Water and injection
The produced water is cleaned. Together with water from other sources, it goes to the water injection pump stations. These pump it into the injection wells of the pressure maintenance system.

In Russian-language practice the gathering system is usually single-pipe and sealed. Oil, gas and water flow from the well along one line in a closed system, with no contact with the atmosphere. This means smaller losses of light hydrocarbons and fewer emissions. The wellhead pressure must then be high enough to bring the flow to the separator. If it is not, we install a booster pump station or move the separation closer to the wells.

Most of Kazakhstan has a sharply continental climate (very cold winters and hot summers), and this adds its own requirements. We insulate and heat the pipelines and equipment, so that waxy oil does not solidify in them in frosts and hydrates do not form. We take the summer heat into account when choosing gas cooling and the power of the gas turbines. The lessons Retrograde condensation, wax, asphaltenes and high-pressure fluids and on the temperature margin explain how high-wax oil and hydrates affect gathering.

Tengiz: oil with a high content of hydrogen sulfide, on land: A field in Atyrau Region, discovered in 1979. The first well produced oil from subsalt deposits at a depth of 4045–4095 m. Oil and gas are treated at the field itself. The integrated process lines (the units that treat the oil and gas) have worked since 1991. The second-generation plant, together with the injection of raw gas into the reservoir, has worked since 2008. The third plant gave first oil in January 2025. The oil is exported mainly through the pipeline of the Caspian Pipeline Consortium (CPC), which has run to the Black Sea since 2001. In 2024 about 27.8 million t of oil and 15.1 billion m³ of associated gas were produced. About 8.7 billion m³ of dry sales gas, 1.2 million t of liquefied petroleum gas and 2.5 million t of sulfur were produced from the gas. Part of the raw gas was injected back (Displacement of oil by gas).
Karachaganak: gas condensate, on land: An oil, gas and condensate field (condensate is a light liquid that comes out of the gas) in West Kazakhstan Region, discovered in 1979, with an area of more than 280 km². It has been developed since 1984. The facilities consist of three linked plants. One stabilises the liquid hydrocarbons and sends them by pipeline towards Atyrau. At another, the gas is separated and raw gas is injected back into the reservoir at a pressure of up to 550 bar (55 MPa). The third partly stabilises the condensate and sends it, together with gas, by pipeline to the gas processing plant in Orenburg. In 2024 about 11.0 million t of liquid hydrocarbons and 23.9 billion m³ of gas were produced. Of this gas, 14.2 billion m³ (about 59%) was injected back into the reservoir.

Facilities at sea

At sea, everything that stands on separate sites on land must fit on a limited deck area. There are strict weight limits, and the equipment stands in wind and waves and sometimes ice. Every tonne of equipment and every person on board is expensive, and cargo deliveries depend on the weather. So the choice of concept at sea depends first of all on the water depth, the sea conditions and whether there are facilities nearby to which the new field can be connected.

Main development concepts at sea

Concept: Artificial island
Water depth (approximate): a few metres
Features: protects the wells and plants from ice and waves; the equipment is as on land

Concept: Gravity-based concrete platform
Water depth (approximate): tens to hundreds of metres
Features: stands on the seabed under its own weight; oil can be stored in the base

Concept: Fixed platform on piles (jacket)
Water depth (approximate): up to several hundred metres
Features: a steel lattice structure fixed to the seabed with piles; the most common type in shallow and medium water

Concept: Tension-leg platform, spar platform (a floating column), semi-submersible platform (a deck on submerged floating hulls)
Water depth (approximate): hundreds of metres to 2–3 km
Features: they float; they are held in place by taut cables (tendons) or by anchors; the wellheads are often on the seabed

Concept: FPSO: a floating production, storage and offloading unit
Water depth (approximate): from tens of metres to 2–3 km
Features: a ship with a treatment plant and tanks; shuttle tankers (ships that carry the oil to the shore) take the oil away

Concept: Subsea wells with a tie-back
Water depth (approximate): any
Features: the wellheads are on the seabed; the production goes by pipeline to a nearby platform, to a floating unit or straight to the shore

Concept	Water depth (approximate)	Features
Artificial island	a few metres	protects the wells and plants from ice and waves; the equipment is as on land
Gravity-based concrete platform	tens to hundreds of metres	stands on the seabed under its own weight; oil can be stored in the base
Fixed platform on piles (jacket)	up to several hundred metres	a steel lattice structure fixed to the seabed with piles; the most common type in shallow and medium water
Tension-leg platform, spar platform (a floating column), semi-submersible platform (a deck on submerged floating hulls)	hundreds of metres to 2–3 km	they float; they are held in place by taut cables (tendons) or by anchors; the wellheads are often on the seabed
FPSO: a floating production, storage and offloading unit	from tens of metres to 2–3 km	a ship with a treatment plant and tanks; shuttle tankers (ships that carry the oil to the shore) take the oil away
Subsea wells with a tie-back	any	the wellheads are on the seabed; the production goes by pipeline to a nearby platform, to a floating unit or straight to the shore

The depth limits are approximate and move as technology develops. Besides depth, the choice depends on waves, ice, the seabed soil, the size of the field and the way the production is taken away.

SchematicDevelopment concepts at sea (schematic, not to scale): from an artificial island in shallow, ice-covered water to floating units and subsea wells in deep water.

Storage and export. Gas is exported from offshore fields by pipeline. Liquefaction on a floating plant (cooling the gas until it becomes a liquid) is justified only for very large volumes. Oil goes by pipeline or by tanker. If there is no pipeline nearby, the oil is stored in the base of a gravity-based platform, in a separate floating storage vessel or on an FPSO. From time to time it is loaded onto a shuttle tanker. The spare capacity of nearby pipelines and platforms often decides whether a small field will pay back at all.

Subsea wells. A small field next to a working platform is best connected to it (a subsea tie-back: subsea wells connected to an existing facility). The wellheads and a manifold (a node where the flows of several wells are collected) stand on the seabed. The production goes by pipeline to another operator's treatment plant, and the field pays a tariff for this service (Cash flow model of an oil and gas project). Gas can be sent over long distances. The Snøhvit field in the Barents Sea has operated since 2007 with no surface structures at all: the flow from the subsea wells goes through a 143 km pipeline to a gas liquefaction plant on the shore. The price of this saving is the losses of pressure and heat in the long line, hydrates and liquid slugs. Also, repairing a subsea well needs a special vessel.

Shallow water with ice. In the northern Caspian the sea depth at the Kashagan field is 3–4 m, and for about five months of the year the sea is covered with ice. In water this shallow, neither a floating unit nor an ordinary supply vessel can operate, and drifting ice would destroy light supports. So the wells and plants were placed on artificial islands protected from ice. For comparison, in the Pechora Sea, in water about 20 m deep, an ice-resistant fixed platform has worked since 2013. It drills, produces, stores and offloads oil by itself.

Kashagan: sea, shallow water, ice, hydrogen sulfide: A field on the shelf of the northern Caspian, about 75–80 km from Atyrau. The reservoir lies deeper than 4 km, the reservoir pressure is above 70 MPa, and there is a lot of hydrogen sulfide in the oil and gas. The wells and plants of the first phase are placed on several artificial islands, and the main production complex is on island D. Oil and gas go by pipeline to the shore, to the Bolashak plant, which prepares the oil for export. Part of the raw gas is injected back into the reservoir at high pressure. Production started in 2013 and was stopped a few weeks later because of leaks in a pipeline. Both pipelines were replaced, and the field has worked since 2016 (Geological and technical uncertainty of a project). In 2024 about 17.4 million t of oil and 11.3 billion m³ of gas were produced. Of this gas, 5.5 billion m³ (about 49%) was injected back.

Functions of a platform and of a central facility

A field platform and a central facility on land perform the same functions. On land they are spread over separate sites. At sea they are put together on one platform (an integrated platform) or on several platforms linked by bridges, which makes it easier to keep the hazardous blocks away from the living quarters.

Functions of a field facility and how they are placed

Function: Wells and drilling
What it includes: wellheads, a drilling rig or a place for one, equipment for repairing wells (workovers)
How it is placed: hazardous area: gas releases are possible

Function: Treatment of the production
What it includes: separators, heaters, oil, gas and water treatment units, pumps and compressors
How it is placed: hazardous area, near the wells

Function: Injection and gas lift
What it includes: water injection pumps, gas lift and gas injection compressors
How it is placed: next to the treatment plant, where the water and gas are taken from

Function: Power and support systems
What it includes: gas turbines or a grid connection, standby diesel generators, water, air, nitrogen, fuel
How it is placed: a separate block, away from the hazardous areas

Function: Control and metering
What it includes: the control room, emergency shutdown systems, gas and fire detection, custody-transfer metering units
How it is placed: in a safe area, with backup

Function: Pressure relief
What it includes: a flare system for emergency and process release of gas
How it is placed: at a distance or on a flare boom (a long arm that holds the flare away from the deck), downwind of the living quarters

Function: People
What it includes: living quarters, a helideck or a jetty, lifesaving equipment
How it is placed: as far as possible from the wells and the flare, behind fire-resistant barriers

Function	What it includes	How it is placed
Wells and drilling	wellheads, a drilling rig or a place for one, equipment for repairing wells (workovers)	hazardous area: gas releases are possible
Treatment of the production	separators, heaters, oil, gas and water treatment units, pumps and compressors	hazardous area, near the wells
Injection and gas lift	water injection pumps, gas lift and gas injection compressors	next to the treatment plant, where the water and gas are taken from
Power and support systems	gas turbines or a grid connection, standby diesel generators, water, air, nitrogen, fuel	a separate block, away from the hazardous areas
Control and metering	the control room, emergency shutdown systems, gas and fire detection, custody-transfer metering units	in a safe area, with backup
Pressure relief	a flare system for emergency and process release of gas	at a distance or on a flare boom (a long arm that holds the flare away from the deck), downwind of the living quarters
People	living quarters, a helideck or a jetty, lifesaving equipment	as far as possible from the wells and the flare, behind fire-resistant barriers

Small offshore platforms are built normally unattended, that is, without a permanent crew. They are operated remotely from the shore or from a neighbouring platform, and the staff come only for servicing. This saves on living quarters and on transporting people, but it needs reliable automation and communications. Large blocks are assembled on the shore in modules and installed whole: the greater the lifting capacity of cranes and vessels, the less work has to be done on site.

The method of production and injection changes the set of facilities a lot. Gas lift needs compressors and a high-pressure gas distribution system (gas lift system). Electric submersible pumps (pumps that work down in the well) need a power plant and a distribution network (Electric submersible pumps (ESP)). Waterflooding needs a water intake, water treatment and high-pressure pumps (Water injection systems). Gas injection needs compressors working at tens of megapascals, as at Karachaganak. Thermal methods (heating the reservoir with steam) need steam generators. So we choose the artificial lift method (the way of lifting oil that does not flow to the surface by itself) together with the development concept (Artificial lift: when it is needed and how to choose the method).

Phased start-up

A large field is seldom developed all at once. The first phase gives production and money earlier and, most importantly, data: how the wells work, how the reservoir pressure behaves, when water arrives. The next phases are designed using these data. The price is the loss of economies of scale (two plants of half the capacity cost more than one full plant), the need to bring the contractors to the site again and work on an operating facility.

Extended well testing: production from the first wells during appraisal, under a separate project, often with temporary facilities. Its data are needed for the field development project (project documents in Kazakhstan).
Phases by capacity: first a plant for part of the plateau, then a second line or a second plant. New wells are drilled as the capacity is added.
Phases by area: first the better-studied part of the accumulation, then the other areas, which are connected to the facilities that already exist.
Debottlenecking: raising the capacity of operating facilities with small changes, such as an extra pump, new internal parts in the separators or a new line. The changes remove the narrowest points that limit the flow.
Adapting to depletion: when the pressure in the reservoir and at the wellhead falls as oil is produced, booster compressors, pumps and artificial lift are added. When the water cut rises, water handling capacity is added.

How the largest projects of Kazakhstan developed (by year)

Project: Tengiz
Stages: 1991: first integrated process lines. 2001: fifth line and start of the CPC pipeline. 2008: second-generation plant and raw gas injection. 2024: wells moved to low wellhead pressure with booster compressors. January 2025: first oil of the third plant

Project: Karachaganak
Stages: 1984: start of development. 2011: fourth line for stabilising liquid hydrocarbons. September 2024: fifth compressor for injecting gas back. In 2024 a gas processing plant for 4.5 billion m³ a year was at the stage of choosing the concept

Project: Kashagan
Stages: 2013: start of production and shutdown. 2016: restart after the pipelines were replaced. According to the plans at the end of 2024, the capacity of the next phase should start operating in 2029–2030

Project	Stages
Tengiz	1991: first integrated process lines. 2001: fifth line and start of the CPC pipeline. 2008: second-generation plant and raw gas injection. 2024: wells moved to low wellhead pressure with booster compressors. January 2025: first oil of the third plant
Karachaganak	1984: start of development. 2011: fourth line for stabilising liquid hydrocarbons. September 2024: fifth compressor for injecting gas back. In 2024 a gas processing plant for 4.5 billion m³ a year was at the stage of choosing the concept
Kashagan	2013: start of production and shutdown. 2016: restart after the pipelines were replaced. According to the plans at the end of 2024, the capacity of the next phase should start operating in 2029–2030

The dates and the state of the projects are as reported by the operators and the national company from the end of 2024 to 2026. Plans may change.

Tengiz shows clearly how facilities are adapted to depletion. While the reservoir pressure is high, the wells deliver the production to the plants under their own pressure. When the pressure fell, wells began to be switched to low wellhead pressure in 2024. Booster compressors now raise the pressure of the production to the pressure that the plants need, and the plants keep working at full capacity. Such projects do not add reserves. They keep the plants that are already built fully loaded, when the reservoir can no longer do this on its own.

How the concept is chosen

We choose the concept in steps. First we draw up a broad list of options and drop the ones that are clearly unworkable or too expensive. Then we work out the few that remain to a similar level of accuracy, so that they can be compared, and choose one. This one is then designed in detail. Between the steps, management decides whether to continue and how much to spend on the next step. The further we go, the more expensive it is to change the choice. So we try to take the uncertainty into account before the decision becomes irreversible (Geological and technical uncertainty of a project, Decision trees and the value of information).

What decides the development concept

Criterion: Site conditions
What affects it: land or sea, water depth, waves, ice, soil, climate
Example: shallow water with ice: islands; deep water: floating units

Criterion: Accumulation and wells
What affects it: reserves and their uncertainty, area, depth, the number of wells needed and their rates
Example: a large area: several pads or islands; a small one: a connection to a neighbouring facility

Criterion: Fluid
What affects it: oil, gas or condensate, gas–oil ratio, hydrogen sulfide and carbon dioxide, wax, sand, pressure
Example: hydrogen sulfide: resistant materials, sulfur recovery, gas injection

Criterion: Infrastructure and market
What affects it: pipelines, spare capacity of nearby facilities, the power grid, roads, gas consumers
Example: a main pipeline nearby: the field's own pipeline is short; none nearby: tankers or storage

Criterion: Environmental protection and rules
What affects it: protected areas, the ban on gas flaring, discharge requirements, in-country value (the share of work and goods that must come from Kazakhstan)
Example: gas may not be flared: processing or injection from the first day

Criterion: Schedule and feasibility
What affects it: where to build, how to deliver, how many people are needed on site
Example: modules assembled on the shore, or building on site

Criterion	What affects it	Example
Site conditions	land or sea, water depth, waves, ice, soil, climate	shallow water with ice: islands; deep water: floating units
Accumulation and wells	reserves and their uncertainty, area, depth, the number of wells needed and their rates	a large area: several pads or islands; a small one: a connection to a neighbouring facility
Fluid	oil, gas or condensate, gas–oil ratio, hydrogen sulfide and carbon dioxide, wax, sand, pressure	hydrogen sulfide: resistant materials, sulfur recovery, gas injection
Infrastructure and market	pipelines, spare capacity of nearby facilities, the power grid, roads, gas consumers	a main pipeline nearby: the field's own pipeline is short; none nearby: tankers or storage
Environmental protection and rules	protected areas, the ban on gas flaring, discharge requirements, in-country value (the share of work and goods that must come from Kazakhstan)	gas may not be flared: processing or injection from the first day
Schedule and feasibility	where to build, how to deliver, how many people are needed on site	modules assembled on the shore, or building on site

We compare the options on economics. Net present value (NPV: the total of all future income and costs, converted to today's money) is the main criterion. To it we add the unit cost per barrel (Unit costs per barrel), the capital cost converted to annual payments (Annual capital charge), and an analysis of what each step from one option to another brings (Acceleration projects and incremental analysis). It is important to compare the options not at a single forecast but over the whole range of reserves and rates: the option that is best for the average forecast can lose a lot at low reserves.

CalculatedNPV at a discount rate of 10% against the oil plateau rate, for three estimates of the reserves of an assumed field (the liquid capacity is twice the plateau rate). The best plateau rates on a grid with a step of 50 m³/d are marked: 3650, 6600, 9650 m³/d. That is from 11.1 to 12.6% of their own reserves per year. The calculation uses the teaching model of this lesson.

Worked exampleWhich plateau rate to choose when the reserves are known only roughly

Given (assumed data)

Reserves: low 12, average 20 or high 28 million m³, with probabilities 0.3, 0.4 and 0.3 (the estimate after exploration)
Options: oil plateau rate 4000, 6400 or 8800 m³/d; liquid capacity twice the plateau rate; water cut as in the first example
Wells: one producing well for every 80 m³/d of the plateau rate, one injection well for two producing wells; the number of wells is not rounded to a whole number; a well costs US$4 million
Facilities: the plant costs US$450 million at 16,000 m³/d of liquid, and the cost is proportional to the capacity raised to the power 0.6; the pipeline, roads, power lines and camp cost US$150 million; the capital spending in the first three years is 25%, 45% and 30% of the total
Costs and taxes: each year 5% of the cost of the plant and infrastructure and US$0.15 million per well; US$5 per barrel of oil and US$0.5 per cubic metre of water; the price, the payment on revenue (royalty), the income tax and the depreciation are as in the library's example project; discount rate 10%; the calculation covers 30 years. Production stops at the economic limit or at the end of year 30. In the following year, but not later than year 30, the cost of abandonment (closing the field down) is paid: US$0.30 million per well and 10% of the cost of the plant

Solution

Capital cost of the 6400 m³/d option: $6400/80 = 80$ producing and 40 injection wells, which cost $120\cdot 4 = 480$ million dollars; the plant costs $450\cdot(12{,}800/16{,}000)^{0.6} = 393.6$ million dollars; together with the infrastructure the total is 1023.6 million dollars.
With the cash flow model (Cash flow model of an oil and gas project) we find the NPV for each option and each estimate of the reserves (the table below). At average reserves the best of the three is 6400 m³/d, with an NPV of 788.3 million dollars.
Expected NPV (the average of the three NPVs, weighted by their probabilities): for 6400 m³/d it is $0.3\cdot 278.4 + 0.4\cdot 788.3 + 0.3\cdot 1168.4 = 749.4$ million dollars; for 4000 it is 669.5 and for 8800 it is 717.7 (expected monetary value).
The cost of a wrong choice: at low reserves the best plateau rate is about 3650 m³/d with an NPV of 352.5 million dollars, and the 6400 option falls short by 74.1 million dollars. At high reserves the best is about 9650 m³/d (1244.6 million dollars), and the shortfall is 76.2 million dollars.
A plateau rate of 6400 m³/d is $365\cdot 6400/(20\cdot 10^6)\cdot 100 = 11.7$ % of the average reserves per year. The best plateau rates for the three estimates are from 11.1 to 12.6% of their own reserves per year.

Answer: Choose a plateau rate of about 6400 m³/d. It has the highest expected NPV of the three options (749.4 million dollars), and at low or high reserves it loses to the best solution for them by only 74.1–76.2 million dollars.

What it means. The top of the NPV curve is flat, and an option close to the best for average reserves stays acceptable over the whole range. The model fixes the position of the top only roughly. As the plateau rate grows, the last year of production sometimes moves one year earlier. The abandonment payment then also comes earlier, so the NPV changes by a small jump of 0.5–1.5 million dollars. That is why we look for the best plateau rates only on a grid with a step of 50 m³/d. A more exact search makes no sense. The extremes are more dangerous: a plateau rate of 8800 m³/d at low reserves loses more than half of the NPV, and a plateau rate of 4000 at high reserves falls short by almost 310 million dollars. The reserves themselves affect the result much more than the choice of the plateau rate: for the same option the NPV ranges from 278.4 to 1168.4 million dollars. So appraisal work that narrows this range is often worth more than fine optimisation of the facilities. The model is for teaching: here the production rate does not affect the recovery factor (the share of the oil in place that is produced), the costs are assumed, and the taxes are simplified. The data in this example are assumed for illustration.

NPV at 10%, million dollars: three plateau rate options and three estimates of the reserves

Plateau rate, m³/d: 4000
12 million m³ (0.3): 351.2
20 million m³ (0.4): 708.9
28 million m³ (0.3): 935.1
Expected: 669.5

Plateau rate, m³/d: 6400
12 million m³ (0.3): 278.4
20 million m³ (0.4): 788.3
28 million m³ (0.3): 1168.4
Expected: 749.4

Plateau rate, m³/d: 8800
12 million m³ (0.3): 144.3
20 million m³ (0.4): 755.6
28 million m³ (0.3): 1240.5
Expected: 717.7

Plateau rate, m³/d	12 million m³ (0.3)	20 million m³ (0.4)	28 million m³ (0.3)	Expected
4000	351.2	708.9	935.1	669.5
6400	278.4	788.3	1168.4	749.4
8800	144.3	755.6	1240.5	717.7

The probabilities of the estimates are in brackets. The expected NPV is calculated from unrounded values and may differ by 0.1 from the sum of the rounded ones. On a grid with a step of 50 m³/d, the best option by expected NPV is about 6550 m³/d (750.0 million dollars). The data are assumed for illustration.

Terms and symbols

Development concept: The basic decision on the wells, gathering, treatment, export of the production, injection and power supply of a field.
Oil plateau rate and liquid capacity: The oil plateau rate is how much oil the wells can give and the plants can take. The liquid capacity is how much oil and water together the facilities can take.
Well pad: A site from which several inclined (deviated) and horizontal wells are drilled.
Group metering station, booster pump station, preliminary water removal unit: Three stages between the wells and the central facility. The automated group metering station measures the wells one at a time. The booster pump station separates the first-stage gas and pumps the liquid onward. The preliminary water removal unit takes out most of the water early.
Central processing facility: The central facility for gathering and treating oil. It completes the treatment, stores the oil, measures it for sale and hands it over.
Subsea tie-back: Subsea wells whose production goes by pipeline to a nearby platform, a floating unit or the shore.
FPSO: A floating unit for producing, storing and offloading oil.
Artificial island: A man-made base of fill for wells and plants in shallow water. It protects them from ice and waves.
Phased start-up: Development of a field in stages: each next phase is designed using the data of the previous one.

Common mistakes and misconceptions

Wrong

“We will design the plant for the oil plateau rate; there is little water in the first years anyway.”

In fact

There is most water in the late years: in this lesson's example, by year 20 the water rate is almost twice the oil plateau rate. If the liquid capacity is only a quarter above the plateau rate, the plateau ends 1.4 years earlier than with a liquid capacity twice the plateau rate, and the NPV is 81 million dollars smaller.

Wrong

“Associated gas is free fuel for the whole life.”

In fact

On the plateau there is a surplus of gas, but the pumps need more and more energy while there is less and less gas. In this lesson's example the field's own gas runs short from year 17. So the concept must plan the source of energy for the late years from the start.

Wrong

“In shallow water the simplest thing is to put up an ordinary platform.”

In fact

In water a few metres deep, neither floating units nor ordinary supply vessels can work, and drifting ice destroys light supports. So artificial islands are built in the northern Caspian, and massive ice-resistant platforms in deeper seas that freeze.

Wrong

“The most profitable option is the one with the higher NPV at the average forecast.”

In fact

We compare options over the whole range of reserves. In this lesson's example, the plateau rate that is best for average reserves loses only a little at low and high reserves. A higher plateau rate loses more than half of the NPV at low reserves.

Wrong

“Phasing is always more profitable: there is less risk.”

In fact

Phases give data and early money, but they lose economies of scale and time. Phases by area and an expansion made early are worth it. Capacity added late, when the reservoir is already watered out (most of the production is water), gives little.

In depth: advanced detail

Profile with fully loaded facilities: the exact solution

When the facilities are full of liquid, the oil rate is $q_o = L(1 - \text{WC})$ , and the water cut depends on the share of the reserves produced, $R$ . For this lesson's curve it helps to introduce $u = \text{WC} = \sqrt{x}$ , where $x = (R - R_{\text{bt}})/(1 - R_{\text{bt}})$ . Producing oil increases $R$ : $N_r\,\dd R/\dd t = 365\,L\,(1 - u)$ , and $\dd R = (1 - R_{\text{bt}})\,2u\,\dd u$ . This gives an equation with separable variables (the variables can be moved to opposite sides):

Time in which the water cut grows from

u_p

u

t - t_p = \frac{2}{a}\left[(u_p - u) + \ln\frac{1 - u_p}{1 - u}\right],\qquad a = \frac{365\,L}{N_r\,(1 - R_{\text{bt}})}

where:

$t_p$ time when the plateau ends, years
$u_p$ water cut at the end of the plateau, $1 - Q/L$ , —
$u$ water cut at time $t$ , —
$a$ rate of withdrawal: the annual liquid capacity divided by the oil reserves that stay mobile after the water breakthrough, 1/year

Units: time in years; $L$ in m³/d, $N_r$ in m³

Holds when

The water cut follows this lesson's curve $\text{WC} = \sqrt{(R - R_{\text{bt}})/(1 - R_{\text{bt}})}$ . The facilities are full of liquid all the time.

The oil rate at every moment is $q_o = L(1 - u)$ . The time is proportional to $1/a$ : it grows with the reserves and shortens with the liquid capacity. The logarithm explains the long “tail”: the last few per cent of the oil take years to produce, at a water cut above 95%.

Example: for the base option $u_p = 0.5$ , $a = 365\cdot 12{,}800/(20\cdot 10^6\cdot 0.8) = 0.292$ per year, and a water cut of 90% is reached $\frac{2}{0.292}\left[(0.5 - 0.9) + \ln\frac{0.5}{0.1}\right] = 8.28$ years after the end of the plateau, that is 15.2 years after the start of the project. A numerical calculation with this lesson's model gives the same result.

What it is worth to know the reserves in advance

If the reserves were known exactly before the plateau rate was chosen, we would take the best plateau rate for each estimate, and the expected NPV would be $0.3\cdot 352.5 + 0.4\cdot 789.1 + 0.3\cdot 1244.6 = 794.8$ million dollars. Without this knowledge the best we can do is a plateau rate of about 6550 m³/d with an expected NPV of 750.0 million dollars (both searches use a grid with a step of 50 m³/d). The difference, about 44.8 million dollars, is the expected value of perfect information about the reserves for this decision (Decision trees and the value of information).

This is small compared with the NPV itself: the flat top of the curve makes the choice of the plateau rate insensitive to an error in the reserves. But the value of information depends on the decision. For the decision “whether to develop at all” or “whether a separate plant for gas is needed”, the same uncertainty can be worth much more. So we build the appraisal programme around the decisions that it can change.

Connections to other topics

Reservoir engineering: tasks across the life of a field — the stages of a field's life and the place of development planning in them.
Cash flow model of an oil and gas project — the cash flow of a project, on which the facility options are compared, and the lease of facilities.
Why water is injected: pressure maintenance and oil displacement — waterflooding and voidage replacement: where the injection volumes come from.
Separator calculations and optimum separator pressure — stage separation in the field.
Chokes, surface pressure losses and well temperature — chokes, flowlines and the gathering network, flow temperature, hydrates and wax.
Gas lift: principles and choice of operating conditions — the gas lift system on the surface: compressors and gas distribution.
Artificial lift: when it is needed and how to choose the method — choosing the lift method together with the development concept.
Displacement of oil by gas — injection of gas back into the reservoir at Tengiz and Karachaganak.
Decision trees and the value of information — the value of information and decisions under uncertainty.
Unit costs per barrel — unit cost as an additional criterion for comparing options.

Check yourself

1
Why do operators of an oil field try to separate most of the water near the wells and not at the central processing facility?
1. A.Because without water the oil freezes more easily in the pipes
2. B.Because only offshore development requires it
3. C.Because water damages the separators of the central facility
4. D.To avoid pumping water for tens of kilometres when it will later be injected back near the wells
Show the answer
Correct answer: D. To avoid pumping water for tens of kilometres when it will later be injected back near the wells
In the late years there is several times more water than oil in the production. Pumping it to the central facility needs wider pipes and pump energy, and then the water is returned to the reservoir anyway, in the same field. Removing the water early at the booster pump station and injecting it nearby saves both capital and operating costs.
2
The facilities are designed for 5000 m³/d of oil and 9000 m³/d of liquid. At what water cut does the plateau end, and how much oil will the field give at a water cut of 80%?
Show the answer
The plateau holds as long as $L(1 - \text{WC}) \ge Q$ , that is up to $\text{WC} = 1 - 5000/9000 \approx 0.44$ . After that the oil rate is $9000\cdot(1 - 0.8) = 1800$ m³/d. The facilities are fully loaded with liquid, and every percentage point of water cut takes away 90 m³/d of oil.
3
The power plant of a field needs 15 MW. The efficiency of the gas turbines is 0.30, the lower heating value of the gas is 40 MJ/m³, and the gas–oil ratio is 100 m³/m³. At what oil rate will the associated gas stop being enough for the power plant?
Show the answer
Fuel consumption is $15\cdot 10^6/(0.30\cdot 40\cdot 10^6) = 1.25$ m³/s, that is $1.25\cdot 86.4 = 108$ thousand m³/d. This much gas is produced with $108{,}000/100 = 1080$ m³/d of oil. Below this oil rate the field must buy gas or switch to electricity from the grid.
4
An oil field lies under 4 m of sea water, and the sea is covered with ice for about five months of the year. Which development concept is the most likely?
1. A.A floating unit with storage (FPSO)
2. B.Subsea wells with no surface structures
3. C.A tension-leg platform
4. D.Artificial islands with wells and plants
Show the answer
Correct answer: D. Artificial islands with wells and plants
Floating units and ordinary vessels need depth. Subsea equipment in such shallow water would be swept away by ice floes that plough the seabed with their underwater edges (keels), and drifting ice destroys light supports. Artificial islands made of fill withstand ice and waves and allow the equipment to be placed almost as on land. This is how Kashagan was developed.
5
An offshore field can be developed in one of two ways. The first is a stand-alone floating unit: the capital cost is 600 million dollars and NPV $= -600 + 40N_r$ . The second is a tie-back to a neighbouring platform: the capital cost is 150 million dollars and there is a tariff for treatment, so NPV $= -150 + 25N_r$ ( $N_r$ is the recoverable reserves in million m³, NPV in million dollars). At what reserves is stand-alone development better?
Show the answer
The options are equal when $-600 + 40N_r = -150 + 25N_r$ , that is at $N_r = 30$ million m³. At smaller reserves the tie-back is better: it is cheaper at the start, and the tariff is proportional to the production. At larger reserves stand-alone development is better: the tariff on every cubic metre outweighs the difference in capital cost. The tie-back already pays for itself at $N_r > 6$ million m³, and the stand-alone option only at $N_r > 15$ . In practice the tie-back is also limited by the spare capacity of the host platform.
6
Why does liquid capacity added 8–10 years after the start of waterflooding usually give less than the same capacity built at once?
Show the answer
By that time the water cut is high, and each extra cubic metre of liquid is mostly water: it adds little oil. Also, the extra oil comes in the late years and counts for little after discounting, and the cost of expanding an operating facility is higher than the cost of extra capacity at construction. So we build the liquid capacity with a margin at the start, or expand it early.

Updated: 19 October 2026