Szilas A.P. Production and transport of oil and gas, Gathering and Transportation
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I20
6
GATtlliKING
AND
SEPAKAl'ION
01-
011.
ANI)
(;AS
Later investigations have shown the error of the capacitance-typc BS and
W
meters to be significant, up to
7
percent. This has two main causes: the dielectric
constant of water
will
be affected, first, by its content of clay minerals, cspccially
montmorillonite, and, secondly, by the frequency used
in
the measurement. Scatter
can be reduced considerably by employing a high frequency;
10
mcps seems the best
(Thompson and Nicksic
1970).
The accuracy of the measurement is considerably
influenced by the quality of the emulsion (dropsize and distribution of the water).
IQ
'9
I
10
f
Fig.
6.6-
14.
Hookup
of
RS&W
monitor downstream
of
separator.
after
Wood
(19%)
The
B
and Wmonitor's accuracy is not indifferent to installation and hookup.
Figure
6.6-
14
shows one of the most favourable hookups, immediately
downstream of the separators. Liquid is discharged through line
2
from float-
controlled separator
1.
Once the liquid
in
the separator has risen to the high level,
control
3
supplies power gas taken from the gas-outlet reducer
4
through line
5
above the diaphragm
of
motor valve
6,
which opens the liquid discharge line. Water
content is monitored by capacitance-type monitor
7;
liquid volume is metered by
meter
8.
Bypass line
10
around the metering system can be remotely opened through
remote-controlled motor valve
9.
The chart of the BS and
W
monitor is moved by
the clockwork only when the separator is delivering liquid. The advantage of this
hookup is that
it
provides continuous monitoring; pressure during discharge from
the separator is constant; and the liquid is mixed rapidly and uniformly.
According to Wood, capacitance-type monitoring provides results close those of
sampling from the stock tank, performed by the usual procedures but with the care
befitting a calibration experiment. Samples taken from the flow line at the wellhead
give widely divergent results, owing presumably to the frequent slug-type flow of the
two phases, which tends to discredit this sampling procedure. Calibration of
capacitance type
BS
and Wmonitors is outlined
in
Byers
(1962- 1963,
Part
3).
Beside the above handled devices several other instruments were also used for the
measurement of mass or volume of oil and gas. The practical importance and the
6.7.
011.
AND
GAS
GATHERING
121
relative number of their application is small however.
In
the past decades devices
measuring mass flow rate directly were supposed to face a bright future. Due to their
sophisticated structure and high price, they are used only
in
a very limited rate.
Among the most recent types first of all the vortex meter seems to be promising
(Rabone
1979).
6.7.
Oil
and gas gathering and separation systems
The wellstreams of wells producing crude oil and natural gas are conveyed to
centres located on the oilfield.
A
system comprising piping, pipe fittings and central
facilities permits
us
to separate the liquid from the gas, to measure the quantity of
both, to adjust their properties
so
as to fall
within
sales-contract and/or other
specifications, and to transport them to the consumers or refineries.
In
!he present
chapter we shall follow the journey of gas up to where
it
is discharged from the
separator, and that ofoil to the intake of the pipeline's driver pump station.
It
will
be
assumed throughout that the water produced together with the crude can be
removed by simple settling and that no special measures have to be taken to protect
equipment from corrosion by the wellstream. Gathering and separating systems fall
into three groups.
All
three types of system start at the well and end at the storage
tanks of the oil pipeline or in the intake of the pipeline driver pump. The first group
includes production systems of extremely high-capacity wells. Each well has its own
facilities for separation and metering, possibly also for treatment. This setup is
seldom economical.
A
more frequent type of system involves gathering and
separating facilities permitting the common handling of several wellstreams.
Figure
6.7-
1
shows a so-called well-centre system after Graf
(1957).
Individual wells
I
on
the lease are connected to well centres
2.
Each wellstream is transported to the well
centre in an individual flowline.
At
the well centres, the wellstreams at least of the
Fig.
6.7-
I.
Well-centre gathering syslern, after
Fig.
6.7-
2.
Common-line gathering system,
aftcr
GraC
(1957)
Graf
(I
957)
122
6
GATHFRING AND
YEPARATION
OF
011
AND
(SAY
wells selected for individual testing and metering are kept separate; their oil, gas and
water rates are metered; then either the united wellstreams are transported
as
they
are to the central gathering station
3
of the lease. or the gas separated at each well
centre is introduced into the gas gathering line. whereas the liquid is forwarded to
the central gathering station. In the third group (likewise after Graf
1957)
several
wells produce into a common flowline
(Fig.
6.7-
2).
Oil,
gas and water production
of
individual wells are metered at intervals by means of portable well testers
installed at the well sites.
All
other treatment takes place at the central station. Ofthe
above-named three groups, the well-centre system is the most widespread and we
shall restrict our following discussion
to
that system.
6.7.1.
Viewpoints
for
designing gathering systems
with well-testing centres
In
outlining design principles for finding the most favourable gathering and
separating system for any oil lease, we shall for the time being disregard whether the
system in question is operated under manual control, by means
of local automation,
or
by process control. Discussion shall be production-centred. and the decision as to
which means of control is most efficient and most economical
will
be regarded as a
separate subsequent task. The principles to be observed
in
designing are as follows.
(a) The wellhead pressures of the wells should be as low as feasible. The resulting
main advantages are: longer flowing life; lower specific injection-gas consumption
in
gas-lift wells: higher yield
of
wells produced
with
bottom-hole pumps
in
the last
phase of production.
(b)
The hydrocarbon
loss
of the system should
be
a minimum.
(c) The system should be easy to oversee as far as control and checking are
concerned. This makes for disciplined production, and permits fast intervention
in
times of operating troubles. (d) Metering the individual and common oil, gas and
water production
of
the wells and testing for impurities
in
the liquid produced
should be ensured
to
the necessary accuracy.
(e)
When determining oil storage
volume, the offtake rate
to
be expected is
to
be taken into consideration, together
with interruptions in offtake due
to
breakdowns
to
be expected, as well as the
settling time possibly required for the removal of water and impurities.
(0
Expansion
of facilities made necessary by the bringing in
of
further wells should require the
least possible modifications to the existing installations; said modifications should
be possible to achieve without disturbing the wells already in production. (g)
Specific cost, referred
to
the volume unit
of
oil and/or gas produced, of installing and
operating the system should be as low as possible. (h) Safety prescriptions should be
meticulously observed.
The realization of these principles may raise the following, partly contradictory,
viewpoints.
ad
(a).
(i)
Head
loss
in
the flowline between wellhead and separator should be as
low as possible. Hence, sudden breaks
in
flowline trace and sudden changes in cross-
section should be avoided; flowline size, length and trace should be chosen with a
view
to attaining minimum head loss;
if
the crude is waxy and/or sandy, measures
6.1
OIL
AND
GAS
GATHERING
I23
are to be taken to prevent the formation of bothersome deposits
in
the flowline and
its fittings; in the case of high-viscosity or waxy crudes, reducing head
loss
may be
achieved by heating the crude at the wellhead, heat-insulating the flowline.
or
injecting a friction-reducing chemical;
if
water is readily separated from the
wellstream,
it
is recommended to install a water knockout next to each well.
(ii)
Separator pressure should be as low as possible.
In
order to keep
it
so,
it
is usually
recommended to install separators higher than storage tank level at the well centres
so
as to make the oil flow by gravity from the separators into the tanks. The less the
pressure needed to convey gas from the separator through the gathering line to the
compressor station, the better. This can be achieved primarily by a gathering-line
network of low flow resistance (big size, small aggregate length, efficient liquid
knockout or scrubbing) and by using low-intake-pressure compressors.
ad
(b).
(i)
Wellstreams from flowing wells of high wellhead pressure should be
directed into a high-pressure separator; stage separation is recommended.
(ii)
The
tank system should be closed
if
possible.
(iii)
Evaporation losses of open storage
tanks, and
(iv)
oil and gas leaks should be kept at
a
minimum.
ud
(c). Particularly
in
manually operated systems and those with local
automation, care should be taken to concentrate all the gathering and separation
facilities at the well centre and the central gathering station.
In
remote-controlled
systems, designs ensuring the fast supply of meaningful information should be
strived at. Information should be supplied both to the men working on the lease and
to the remote-control centre.
ad
(d).
(i)
The number of separators enabling individual wells to be tested at the
well centre should be sufficient to permit measuring the oil, gas and water
production of each well at intervals of
4
to
7
days.
(ii)
The number of common
separators handling the wellstreams that are not separately metered should be
composed of uniform units for each stage. The number of separators required is then
determined by
unit
capacity.
(iii)
In
on-lease gas metering, the accuracy of
+(I
-2)
percent of the orifice meter is adequate. The quantity of gas fed into a sales line or a
transmission pipeline should be determined more accurately,
if
possible.
(iv)
If
the
liquid output is measured
in
the storage tanks at the well centres, then the number of
so-called test tanks metering the liquid production of individual wells should agree
with the number of test separators. Common tanks metering the production
of
the
remaining wells should number at least two per centre.
(v)
For
accounting
within
the
lease it is usually sufficient to meter liquid at an accuracy of about
0.5
percent.
It
is
desirable to meter oil delivered outside the lease at an accuracy of at least
0.2
percent.
ad
(e). Optimum storage-tank volume may differ widely depending on the nature
of the gathering, separation and transmission facilities.
It
is recommended in the
usual case to have storage capacity for two-three days’ production.
ad
(0.
Well centres are to be designed
so
that bringing wells in or
off,
and changing
separator, tank
or
metering capacities might be achieved without affecting the
equipment
in
operation.
All
the equipment and fittings of well centres within a lease
124
6.
GATHERING AND SEPARATION
OF
OIL
AND GAS
should be uniformed; fittings should be transportable to the well centre ready for
installation, and
it
should be possible to install them without welding.
ad
(g).
(i)
The mechanical production equipment of wells should be chosen, and
phased during the productive life of the wells,
so
as to minimize specific production
cost over the entire life of the lease.
(ii)
Gas from wells having a high wellhead
pressure should be led at the lowest possible pressure
loss
into the compressor
station. One and possibly two compressor stages may thus be saved temporarily.
(iii)
The number and location of well centres, as well as the location of the central
gathering station, should be chosen
so
as to minimize total cost.
(iv)
Temporary
piping should be joined by couplings.
(v)
Well-testing centres, usually hand-
operated early in the life of the lease, should be devised
so
as to require the least
possible modification when converting to automation. It is usually preferable to
install an LACT (Lease Automatic Custody Transfer) system rather than a central
gathering station early in lease life.
6.7.2.
Hand-operated well-testing centres
When choosing the most suitable well centre design, several types may enter into
consideration depending
(i)
on the nature of the wellstream to be handled,
(ii)
on the
role to be assigned to the central gathering station,
(iii)
on the climatic conditions at
the selected location.
Figure
6.7-3(a)
shows a type of tank station or well centre
suitable for the handling of low-viscosity gaseous crudes containing no sand. Oil
and gas separated from the crude are conveyed through flow lines
I
and
fill
lines
2
into test separators
3
or
production separator
4.
Oil
flows through line
5
into
Fig.
6.7-
3.
Well centre for handling
low-viscosity
gaseous sand-free crude
metering tanks
6
or storage tanks
7,
which may be drained through lines
8.
Lines
Y
serve for water drain. Tanks are upright cylindrical, so-called open sheet steel tanks.
Separators discharge gas through lines
10
and orifice meter
run
11
into gas
gathering line
12. Gas may also be vented or flared through line
1.1.
f’iyurr
6.7
-3(b)
shows a schematic diagram of a ‘closed’ tank station or well centre. The
separator-side layout is the same as above. Liquid discharged from the separators
flows through line%
1
and orifice liquid meter run
2
into horizontal cylindrical closed
tanks
3.
Hydrocarbon vapours enter through line
4
into the gas gathering line. Tank
outlets
arc
4
for
gas, 5 for oil and
6
for water.
Well fluid entering the separator is often heated
in
order to promote easier
separation of gas and water and to prevent the formation of gas hydrate plugs
in
the
separators and at the meters. Heating is by hot water or steam through a heat
exchanger.
Figure
6.7-4
is a detail of a well centre upstream
of
the tanks, used for the
handling
of
low-viscosity sandless crudes, with two-stage separation and the
evaporation
loss
to be expected
in
the open tanks reduced by vacuum stabilization
(Scott
1965).
The wellstreams enter the well centre through flowlines
1.
One
wellstream is introduced into second-stage test separator
2,
of about
70
kN/m2
Fig.
6.7-4.
Vacuum
stabilization
at well centre, after Scott
(1965)
pressure, whereas the remaining wellstreams enter production separator
3.
Test
separator
2
discharges gas through line
4
into the gas gathering line
5,
and liquid
through line6 into stabilizer
7,
which is under a vacuum ofabout
4
kN/m2. The first-
stage separator
3
discharges the common liquid production into second-stage
separators
8
and
9.
These discharge oil into the stabilizer, and gas into line
5.
Gas
separating in the stabilizer is fed by compressor
12
at the required pressure into gas
line
5.
Pump 10 transports oil at an excess pressure of about
70
kN/m2 through line
I1
into
the storage tank. Gas takeoff from the stabilizer column is continuous,
whereas
oil
offtake is batchwise, because pump
10
(in a manner not shown
in
the
Figure) circulates oil in the stabilizer until the liquid level in the vessel attains a
predetermined height. Reflux is then stopped and discharge into line
I1
is initiated.
126
6
GATIILKING
AND
SL
I’AKATION
01
011
ANI)
(>AS
This goes on until the liquid level drops to a predetermined height. The economy
of
this installation is revealed by the fact that,
in
the case discussed by Scott, the
stabilizer paid itself out
in
160
days. Economy is impaired by higher gas gathering
line pressure, as this increases the power cost
of
gas compression.
In a Soviet type tank station used to handle gaseous, cut and sandy crudes
(Fig.
6.7-5), wellstreams enter through flowlines
I
and
fill
lines
2
and
4
into production
separator
3 or test separator
5.
Separators discharge liquid through vacuum
separator 6 into cone-bottom storage tank 7. Weighted float
X
at the oil-water
2
r-
r
.I
12
Fig.
6.7-5.
Soviet
well centre
design
Tor
handling sandy crude
interface operates valve
9
which serves
for
the automatic drain
of
water and sand
from the tank through line
10. Pure oil is discharged through line
11.
Separators 3,5
and 6 deliver gas through line I2 and meter runs to the gas gathering line. The settled
muddy sand can be slurried up
with
water introduced through pipe 13.
The schematic layout
of
a
tank station for handling waxy crudes low in gas and
sand is shown as
Fig.
6.7-6. Wellstreams enter through heated flowlines and
distributors
2
into the test and production separators
3
and
4.
Oil
is discharged
through line
5,
the low gas production through 6. The water drain is not shown
i.1
the Figure. Flowlines are usually heated with steam conveyed
in
internal
or
external,
coaxial piping. Lines among tanks are conducted
in
covered concrete ducts sunk
into the ground (dashed lines) that can be heated by the piping steam.
-
This design
is suited also for handling high-viscosity oil low
in
gas and sand, whose pour point is
lower than the ambient temperature. Heating the lines
in
these cases may not always
be necessary.
Figure
6.7- 7 shows a gathering and separating system designed by Gidrovos-
tokneft Institute
of
the
USSR
and employed
in
the Soviet Union. This system has
127
Fig.
6.7
--
6. Well centre
for
handling low-gas
high-viscosiIL
crude
7
”
-
-----------
4
Fig.
6.7
-
7. Gathering and separating system
of
Gidrovostokneft
(VNIIOEHG
1969)
the peculiarity that well centres perform first-stage separation only. The
com-
paratively dry gas furnished by the separators is discharged into
a
gas gathering
line; the liquid, which still contains significant quantities
of gas, is conveyed to the
central gathering station which is some
100
km away. This is where another two
or,
if
the stock tank is also counted, three stages of separation take place. The main
advantage
of
this system is that is permits centralization
of
a significant portion of
the gathering and separating equipment
for
production spread over a vast area.
In
the solution shown in the Figure, flow lines
1
deliver wellstreams through metering
units
2
into first-stage separator
3.
In the upper part of the Figure, separator
pressure is sufficient to convey the liquid effluent to the faraway second-stage
separator
6.
In the lower variant (with metering equipment not shown), pressure
of
separator
3
is insufficient to deliver the liquid to separator
6,
so
that pump
4
and
128
h
GATHERING AND SEPARATION
OF
OIL
AND
GAS
tank
5
have been added at the well centre. Separator
6
delivers liquid to elevated
third-stage separator
7
which in turn discharges into storage tanks
8.
Gas from each
separator stage enters the gathering line
of
the gasoline recovery station through
lines
9,
10
and
11.
Graf (1957) describes a simplified system in which no gas line emerges from well
centres.
Only
the wellstream of the well being tested is being separated; the gas thus
produced is vented
or
flared. The
full
output of the producing wells is conveyed by
means of a screw pump to the central station. Any further separation and metering
takes place at that station.
6.7.3.
The
automated system
Oilfield automation is a process that started a long time ago. The elementary
tasks of oil production, gathering and separation have been handled for many a
decade by equipment demanding no human intervention (liquid level controls
in
separators; gas pressure regulators, etc.). Early
in
the nineteen-fifties. a new wave
of
automation brought about the relatively rapid development of an automatic system
termed LACT (Lease Automatic Custody Transfer), taking care of central oil
gathering, treatment, metering and transmission (Resen 1957).
as
well as the
development of automatic well testers (Saye 1958). The devices composing these
systems were at first controlled by local automatisms. but connected systems were
soon developed where metering results and the main situation parameters of
peripheral units could be read off and recorded at a central control station. Even this
system permitted substantial savings to be achieved. According to Wiess
(Oil
and
Gas
Journal
1964)
the Gulf Coast Division of
Sun
Oil Company introduced
centralized automation at this level on 19 leases. some of which were offshore. Some
of the leases were already
in
production at the time, while the rest awaited
development. The total cost of staggered automation was estimated at USA
$
500,000. This expenditure was balanced by three factors:
(i)
savings on investment
(as against conventional equipment),
(ii)
increased sales income, and
(iii)
reduction
of maintenance cost
(Tuhle
6.7-
I).
The Table shows that the increased income and
the reduced maintenance cost together totalled
USA
8
375,000
per
year. Adding to
this the difference
in
annual depreciation attributable to the reduction
in
investment
cost we see that the investment of $500,00 paid itself out
in
slightly more than one
year. By the late sixties, LACT had become
so
widespread that
60
-
70 percent of
oil
produced
in
the USA was treated and transferred to transport lines by this method.
This phase of automation was followed early in the sixties by a second wave,
represented by Computer Production Control (CPC).
The central computer acquires, records and processes all production, situation
and safety data concerning the lease. In this off-line system,
it
is
the dispatcher who,
in
the possession of the information presented by the computer, will intervene
if
necessary. Intervention will usually be by push-button-actuated remote control. As
a stage of further development, on-line computer control was developed, where even
intervention by remote control is initiated by the computer. Late in the sixties, after
6.7.
OIL
AND GAS GATHERING
I77
48
16
10
129
71
19
6
4
Table 6.7-
I.
Savings due
to
automation
of
an oilfield
Reduction in first cost
I
s
I
"0
Tanks
Piping and fittings
Other surface equipment
OlTshore platform
Total
303
36
I37
I28
604
50
6
23
21
loo
Annual increase in sales income
I
I
Reduction
of
oil
gravity
More elficient
use
of
equipment
Sale
of
tank vapours
Saving in gas power
Total
I
Annual reduction in maintenance cost
1
Payroll
\.lainteniince items
Transportation
Miscellaneous
the advent
of
third-generation computers employing integrated circuits, there were
as many as
40
CPC systems operative on the various oil and gas fields of the world
(Graf
1970).
Production control by computer is considered a highly significant
advance, "the biggest thing since rotary drilling
in
hydrocarbon production"
(Pearson
1969).
Its
main advantages are reduced operating costs, reduced
production downtime due to operating trouble, a more elastic and versatile
optimization of production, and faster intervention in critical situations.
All
tasks
that can
be
uniquely defined
in
the possession ofall relevant information, and can be
performed by the intermediary of remote-control-effectors, are set to CPC. This
liberates most of the lease operators for tasks inaccessible to CPC; e.g. the operator
opening and closing wellhead valves or handling scraping operations, or the gauger
gauging liquid levels
in
tanks will become redundant, but the tasks
of
mechanics
performing repairs and maintenance on production equipment will become more
sophisticated and possibly more rewarding. No clerks recording production data
and writing periodic ieports will
be
required, but production experts and systems
analysts analyzing the production processes recorded and giving instructions for
new production targets will. Automatic operation will become much more flexible
under the direction
of
computer programs than of local automatisms, as programs
permit flexible adaptation to changes in requirements facing production without
changing peripheral units. The Humble Oil and Refining Co. possesses. for instance,
9