production facility ii
TRANSCRIPT
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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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