production facility ii

7/27/2019 Production Facility II

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Presented by

Prof. K. V. RaoAcademic Advisor

Petroleum Courses

JNTUK


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Reservoir

Hydrocarbon accumulations in geological traps can be classifiedas reservoir, field, and pool.

A reservoiris a porous and permeable underground formation

containing an individual bank of hydrocarbons confined by

impermeable rock or water barriers and is characterized by asingle natural pressure system.

A field is an area that consists of one or more reservoirs all

related to the same structural feature. A poolcontains one or

more reservoirs in isolated structures.


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Hydrocarbon accumulations are classified as oil, gas condensate, and gas

reservoirs.

An oil that is at a pressure above its bubble-point pressure is called anundersaturated oil because it can dissolve more gas at the given

temperature.

An oil that is at its bubble-point pressure is called a saturatedoil

because it can dissolve no more gas at the given temperature.

Single (liquid)-phase flow prevails in an undersaturated oil reservoir,

whereas two-phase (liquid oil and free gas) flow exists in a saturated

oil reservoir.

Hydrocarbon reservoir in which conditions of temperature andpressure have resulted in the condensation of the heavier

hydrocarbon constituents from the reservoir gas.

Hydrocarbon reservoir in which conditions of temperature and

pressure are such that no heavier components are present in gas.


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Wells

Wells in the same reservoir can fall into categories of oil, condensate, and gas

wells depending on the producing gasoil ratio (GOR).

Gas wells are wells with producing GOR being greater than 100,000

scf/stb;

condensate wells are those with producing GOR being less than 100,000

scf/stb but greater than 5,000 scf/stb;

and wells with producing GOR being less than 5,000 scf/stb are classified

as oil wells.

Oil reservoirs can be classified on the basis of boundary type, which determinesdriving mechanism, and which are as follows:

Water-drive reservoir

Gas-cap drive reservoir

Dissolved-gas drive reservoir


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In water-drive reservoirs, the oil zone is connected by a continuouspath to the surface groundwater system (aquifer). The pressure caused by

the columnof water to the surface forces the oil (and gas) to the top of

the reservoir against the impermeable barrier that restricts the oil and gas

(the trap boundary).

This pressure will force the oil and gas toward the wellbore. With the same

oil production, reservoir pressure will be maintained longer (relative to

other mechanisms of drive) when there is an active water drive.

Edgewater drive reservoir is the most preferable type of reservoir

compared to bottom-water drive. The reservoir pressure can remain at its

initial value above bubble-point pressure so that single-phase liquid flow

exists in the reservoir for maximum well productivity. Edge water occurs

off the flanks of the structure at the edge of the oil.

A steady-state flow condition can prevail in a edge-water drive reservoir

for a long time before water breakthrough into the well. Bottom-water

drive reservoir (Fig. 1.3) is less preferable because of water-coning

problems that can affect oil production economics due to water treatmentand disposal issues.


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In a gas-cap drive

reservoir, gas-cap drive is

the drive mechanism wherethe gas in the reservoir has

come out of solution and

rises to the top of the

reservoir to form a gas cap

(Fig. 1.4). Thus, the oil belowthe gas cap can be produced.

If the gas in the gas cap is

taken out of the reservoir

early in the production

process, the reservoir

pressure will decrease

rapidly. Sometimes an oil

reservoir is subjected to

both water and gas-cap

drive.


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A dissolved-gas drive reservoir (Fig. 1.5) is also called a solution-gasdrive reservoirand volumetricreservoir.

The oil reservoir has a fixed oil volume surrounded by no flow boundaries

(faults or pinch-outs). Dissolved-gas drive is the drive mechanism where

the reservoir gas is held in solution in the oil (and water).

The reservoir gas is actually in a liquid form in a dissolved solution with the

liquids (at atmospheric conditions) from the reservoir.

Compared to the water- and gas-drive reservoirs, expansion of solution

(dissolved) gas in the oil provides a weak driving mechanism in a

volumetric reservoir.

In the regions where the oil pressure drops to below the bubble-point

pressure, gas escapes from the oil and oilgas two-phase flow exists. To

improve oil recovery in the solution-gas reservoir, early pressure

maintenance is usually preferred.


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Well

Oil and gas wells are drilled like an upside-down telescope. The large-diameter

borehole section is at the top of the well. Each section is cased to the surface,

or a liner is placed in the well that laps over the last casing in the well. Each

casing or liner is cemented into the well (usually up to at least where the

cement overlaps the previous cement job).

The last casing in the well is the production casing (or production liner). Once

the production casing has been cemented into the well, the production tubing

is run into the well.

Usually a packer is used near the bottom of the tubing to isolate the annulus

between the outside of the tubing and the inside of the casing. Thus, the

produced fluids are forced to move out of the perforation into the bottom of

the well and then into the inside of the tubing. Packers can be actuated byeither mechanical or hydraulic mechanisms.

The production tubing is often (particularly during initial well flow) provided

with a bottom-hole choke to control the initial well flow (i.e., to restrict

overproduction and loss of reservoir pressure).


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Figure 1.6 shows a

typical flowing oil well,

defined as a well

producing solely

because of the natural

pressure of the

reservoir. It is

composed of casings,

tubing, packers, down-hole chokes (optional),

wellhead, Christmas

tree, and surface

chokes.


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Most wells produce oil through tubing strings, mainly because a tubing

string provides good sealing performance and allows the use of gas expansionto lift oil.

The American Petroleum Institute (API) defines tubing size using nominal

diameter and weight (per foot). The nominal diameter is based on the

internal diameter of the tubing body.

The weight of tubing determines the tubing outer diameter. Steel grades of

tubing are designated H-40, J-55, C-75, L-80, N-80, C-90, and P-105, where the

digits represent the minimum yield strength in 1,000 psi.


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The wellhead

is defined as

the surface

equipment set

below the

master valve.

As we can see

in Fig. 1.7, it

includes casing

heads and a

tubing head.

The casing

head

(lowermost) is

threaded onto

the surfacecasing. This can

also be a

flanged or

studded

connection.


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A casing head is a

mechanical assembly

used for hanging a casing

string (Fig. 1.8).

Depending on casing

programs in well drilling,

several casing heads can

be installed during wellconstruction. The casing

head has a bowl that

supports the casing

hanger.


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This casing hanger is threaded onto the top of the production casing (or

uses friction grips to hold the casing). As in the case of the production

tubing, the production casing is landed in tension so that the casinghanger actually supports the production casing (down to the freeze

point).

In a similar manner, the intermediate casing(s) are supported by their

respective casing hangers (and bowls). All of these casing headarrangements are supported by the surface casing, which is in

compression and cemented to the surface.

A well completed with three casing strings has two casing heads. The

uppermost casing head supports the production casing. The lowermost

casing head sits on the surface casing (threaded to the top of the

surface casing).


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Most flowing wells are

produced through a

string of tubing run

inside the production

casing string. At the

surface, the tubing is

supported by the tubing

head (i.e., the tubing

head is used for hanging

tubing string on the

production casing head

[Fig. 1.9]). The tubing

head supports the tubing

string at the surface (thistubing is landed on the

tubing head so that it is

in tension all the way

down to the packer).


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The equipment

at the top of

the producing

wellhead iscalled a

Christmas

tree(Fig. 1.10)

and it is used to

control flow.The Christmas

tree is

installed above

the tubing

head. An

adaptor is a

piece of

equipment

used to join the

two.


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The Christmastreemay have one flow outlet (a tee) or two

flow outlets (a cross). The master valve is installed below the

tee or cross. To replace a master valve, the tubing must be

plugged. A Christmas tree consists of a main valve, wing

valves, and a needle valve.

These valves are used for closing the well when needed. At

the top of the tee structure (on the top of the Christmas

tree),there is a pressure gauge that indicates the pressure in

the tubing.


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The wing valves and

their gauges allow

access (for pressure

measurements and

gas or liquid flow) to

the annulus spaces

(Fig. 1.11).


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Surfacechoke (i.e.,

a restriction in the

flowline) is a piece of

equipment used to

control the flow rate

(Fig. 1.12).


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In most flowing wells, the oil production rate is altered by adjusting the

choke size. The choke causes back-pressure in the line. The back-pressure

(caused by the chokes or other restrictions in the flowline) increases the

bottomhole flowing pressure.

Increasing the bottom-hole flowing pressure decreases the pressure

drop from the reservoir to the wellbore (pressure drawdown). Thus,

increasing the back-pressure in the wellbore decreases the flow rate

from the reservoir.

In some wells, chokes are installed in the lower section of tubing

strings. This choke arrangement reduces wellhead pressure and

enhances oil production rate as a result of gas expansion in the tubing

string.

For gas wells, use of down-hole chokes minimizes the gas hydrate

problem in the well stream. A major disadvantage of using down-hole

chokes is that replacing a choke is costly.


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Certain procedures must be followed to open or close a well.

Before opening, check all the surface equipment such as safety

valves, fittings, and so on. The burner of a line heater must be lit

before the well is opened.

This is necessary because the pressure drop across a choke cools

the fluid and may cause gas hydrates or paraffin to deposit out. A

gas burner keeps the involved fluid (usually water) hot. Fluid from

the well is carried through a coil of piping.

The choke is installed in the heater. Well fluid is heated both

before and after it flows through the choke. The upstream heating

helps melt any solids that may be present in the producing fluid.The downstream heating prevents hydrates and paraffins from

forming at the choke.


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Surface vessels should be open and clear before the well is allowed to

flow. All valves that are in the master valve and other downstream

valves are closed. Then follow the following procedure to open a well:

1. The operator barely opens the master valve (just a crack), andescaping fluid makes a hissing sound. When the fluid no longer

hisses through the valve, the pressure has been equalized, and

then the master valve is opened wide.

2. If there are no oil leaks, the operator cracks the next downstreamvalve that is closed. Usually, this will be either the second (backup)

master valve or a wing valve. Again, when the hissing sound stops,

the valve is opened wide.

3. The operator opens the other downstream valves the same way.

4. To read the tubing pressure gauge, the operator must open the

needle valve at the top of the Christmas tree. After reading and

recording the pressure, the operator may close the valve again to

protect the gauge.


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The procedure for shutting-in a well is the opposite of the

procedure for opening a well. In shutting-in the well, the

master valve is closed last. Valves are closed rather rapidly to

avoid wearing of the valve (to prevent erosion). At least twovalves must be closed.


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production facility ii

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