FEDERAL UNIVERSITY OF
TECHNOLOGY OWERRI
P.M.B. 1526, OWERRI
IMO STATE
A TERM PAPER ON
DESIGN/SIZING OF
OFFSHORE PRODUCTION FACILITIES
500 LEVELS
NWAKPU GERALD EMENIKE
20121796593
SUBMITTED TO
THE PET513 COURSE
COORDINATOR
(OFFSHORE OPERATIONS)
ENGR (DR) DURU .U.I.
DEPARTMENT OF PETROLEUM
ENGINEERING
SCHOOL OF ENGINEERING
AND ENGINEERING TECHNOLOGY (SEET)
IN PARTIAL FULFILLMENT
OF THE REQUIREMENT FOR THE AWARD OF BACHELOR OF ENGINEERING (B.ENG) IN
PETROLEUM ENGINEERING
JULY, 2017
Contents
Introduction
Offshore facilities can be defined as a set of equipment that can
be used to extract, process and export oil and gas in a safe, controlled and
efficient way which are usually located on the surface.
Generally, offshore facilities consist of 2 sections:
·
Substructure: a steel structure to
support the upper part (called topside) including the foundations.
·
Topside: an integral part of steel deck
(can be single or stacked) and all equipment placed on it, supported by a
substructure.
Offshore facilities can be described as;
·
Extraction; Facilities to extract oil
and gas from the reservoir into the surface in a safe and controlled manner.
This function is usually performed by the wellhead platform (WHP).
·
Processing; Facilities to process raw
oil and gas/well “ stream” into “treated” crude oil and/or natural gas as per
customer requirement. This is done by the Central Processing Plants (CPP).
·
Exporting; Facilities to export
treated/processed oil and/or gas to customer receiving point. This is usually
done by Pipeline, F(P)SO, FLNG (Floating Liquefied Natural gas).
For the design of production facilities in the offshore environment,
emphasis will be on the proper design of structures and pipelines to resist the
effect of water and on the requirements to a clean environment. However, the
designers should take time to identify the most profitable development schemes
by optimising the sales product from the field. This will put emphasis on the
transport solution of the products and calls for careful discussions of
alternative transport solutions including pipeline transport and offshore
loading schemes for stable oil and condensate products.
Also, the paper highlights the needs for efficient project
management identifying how the economic importance of a project will
deteriorate if the costs are exceeded or if the schedule for the project for
starting production is missed.
Production platforms and subsea pipelines are essential necessities
for recovery of oil and gas from offshore environments. in addition they
account for the two maximum big categories of physical footprints of oil and
fuel tendencies in marine environments.
As more oil and fuel tendencies have moved regularly into deepwater
sites, and farther from shore, leading-edge technological traits have
emphasised accelerated ruggedness and reliability of subsea equipment and
creation strategies as the most reliable methods to decreasing the bodily
footprints, and consequently the environmental influences, of production of
offshore oil and gas.
Environmental components of platform operations include control of
waste water as well as air emissions. Pipeline operations emphasize leak
avoidance via continuous tracking and faraway manage together with normal
inspection and maintenance. Focal points for similarly progress encompass:
·
Continuous improvement of equipment and
techniques for subsea glide-warranty and separation. The largest,
price-introduced advancements are needed to prolong the working lifetimes and
decrease the maintenance intensity for subsea structures.
·
Wastewater dealing with on offshore systems
consistent with require website online-precise picks amongst more than one,
permitted options; no unmarried waste-disposal technique might be most
beneficial for all situations.
·
Offshore wastewater treatment and
disposal through ongoing improvements in numerous different physical and
chemical technology even as also pursuing techniques to reduce basic volumes of
generated wastewater.
·
Management of air emissions from
offshore systems by reducing the need for venting and flaring via seizure,
subsurface re-injection or other methods available.
·
Increased public awareness, and
enterprise attentiveness, to pipeline locations in order that damages to
pipelines may be averted and environmental threats from leaks thereby
decreased.
Air emissions from offshore production equipment consist of
numerous kinds of combustion, venting, and flaring resources. Those sources
have been discovered to now not notably affect coastal regions but need to
remain monitored to ensure that the favourable non-effect finding does not
alternate. .
Pipelines have demonstrated to be the most secure, most dependable,
least expensive and environmentally favourable way to move oil and gas
throughout Nigeria, together with offshore traits. The getting old of the
pipeline infrastructure shows that continual improvement in system integrity,
monitoring, and leak-detection is necessary.
Sizing and design of offshore wellhead
The wellhead is the equipment at the surface that provides support
for the tubular inside the well, a pressured seal between the tubulars and a
means of controlling production from the well. A wellhead consists of a casing
head for each casing string of pipe in the well, casing or tubing, some means
of support and pressure sealing must be provided.
The flow rate from either an oil well or a gas well can easily be
estimated from the wellhead pressure if the wellhead pressure is atleast twice
the flowline pressure. For an oil well,the Gilbert (1954) equation is commonly
used;
q = (Ptf S2)/(600√R)----------------------------
1
Where
q =gross liquid flow rate (bbls/day)
Ptf = flowing tubing head pressure (psia)
R = gas to liquid ratio (MSCF/bbls)
S=choke size (1/64 in.)
For a gas well, the following equation is used:
q = 390[(d2Ptf)/
(√GT)]------------------------2
where
q = gas flow rate (MSCF/day)
Ptf = flowing tubing head pressure (psia)
d = choke size (in.)
G=gas specific gravity
T = wellhead (0R)
Offshore
separator Designs/Sizing
Offshore Separators are typically sized by the droplet settling
theory or retention time for the liquid phase. For illustration purpose, a general
procedure based on retention time appraoch is as follows:
1. Estimate overall volume based on the retention time and expected
separation performance for each phase, and the major factors needed to be
considered include: Expected perforamance Overall through put Composition of
incoming fluids Intensity of emulsion Retention time of each individal phase
Types of vessel and internals levels and alarms
2. Determination of gas
cross-sectional area based on settling theory or empirical correlations, and the
other factors include Expected liquid carry-over rate Avialable mist eliminator
Mean velocity of gas flow
3. Determine oil cross-sectional area based on settling theory or
empirical correlations by following similar procedure in Steps 1 and 2.
4. Determine water cross-sectional area based on settling theory or
empirical correlations by following similar procedure in Steps 1 and 2.
5. Determine vessel diameter based on cross-sectional area for each
phase
6. Determine vessel length to meet the required retention time for
all phases
7. Select inlet device and iterate.
8. Evaluation of separation
performance for a specific applocation. .
Settling theory
In gravity settling, the dispersed drops/bubbles will settle at a
velocity determined by equating the gravity force on the drop/bubble with the
drag force caused by its motion relative to the continuous phase. In horizontal
vessels, a simple ballistic model can be used to determine a relationship
between vessel length and diameter. In vertical vessels, settling theory
results in a relation for the vessel diameter.
Horizontal
separators
Droplet settling theory, using a ballistic model, results in the
relationship shown in Eq. 1. For liquid drops in gas phase
(Leffd2Fg)/hg =
421*(TZQg/P)*[( ρg/ρl-ρg )*CD/dm]1/2
-----------------------3
d = vessel internal diameter, in.
dm = drop diameter, μm
hg = gas-phase space height,
in.
Fg = fractional gas cross-sectional area
Leff = effective length of
the vessel where separation occurs, ft
T = operating temperature, °R
Qg = gas flow rate, MMscf/D
P = operating pressure, psia
Z = gas compressibility
ρl = liquid density, lbm/ft3
ρg = gas density, lbm/ft3
CD = drag coefficient. (See below for calculation)
For bubbles or liquid drops in liquid phase:
hc = 0.00129trc(Δϒ)dm2/µc --------------------------------------4
where
trc = continuous-phase retention time, minutes
μc = continuous-phase
dynamic viscosity, cp
Δγ = specific gravity
difference (heavy/light) of continuous and dispersed phases.
Vertica vessels
Settling theory results in
the following relationship. For liquid drops in gas phase,
d2 = 5054*(TZQg/P)*[( ρg/ρl-ρg
)*CD/dm]1/2
------------------------5
assuming low Reynolds number flow.the equ can be further reduced to
d2= 6663* Qc μc/( Δγ) dm2 ------------------------------------------6
Retention time
Horizontal
vessels
The relationship of vessel
diameter and length is given by;
D2Leff=(tr0Q0+
trwQw)/1.4Fl --------------------------------------------7
where tro = oil retention
time, minutes
trw =
water-retention time, minutes
Qo = oil flow
rate, B/D
Qw = water flow rate, B/D
Fl = fraction of vessel
cross-sectional area filled by liquid
Vertical vessels
D2(h0+hw)=(tr0Q0+trwQw)/0.12
------------------------------8
Where
ho = oil pad height, in.
hw = water pad
height, in.
Seam To seam Length
The seam-to-seam length, Lss, for the horizontal vessel should be
determined from the geometry once a diameter and effective length have been
determined. Length must be allotted for inlet devices, gas demisters, and
coalescers. For screening purposes, the following approximations can be used.
Lss =Leff
+ d/12
(gas)----------------------------------------9
Lss=(4/3 )Leff (oil)------------------------------------------10
The ratio of length to
diameter is typically in the 3 to 5 range.
Vertical vessels
The seam-to-seam length of
the vertical vessel should be determined from the geometry, once a diameter and
height of liquid volume are known. Allowance must be made for:
·
the inlet nozzle
·
space above the liquid level
·
gas separation section
·
mist extractor
·
for any space below the water outlet
For screening purposes, the
following approximations can be used, where d is the vessel diameter.
Lss = (h + nozzle
ID + demister height+54)/12 -------------------------------11
0r Lss =( h + nozzle
ID + d + demister height+18)/12 -----------------------12
Offshore
Pipeline Design and Sizing
The considerations and
standards guiding pipeline design insures stability and integrity in the
industry.
Selecting pipe
wall thickness
The fluid flow equations and
formulas presented thus far enable the engineer to initiate the design of a
piping or pipeline system, where the pressure drop available governs the
selection of pipe size. (In addition, there may be velocity constraints that
might dictate a larger pipe diameter. This is discussed below in the section on
velocity considerations for pipelines.
Once the inner diameter (ID) of the piping
segment has been determined, the pipe wall thickness must be calculated. There
are many factors that affect the pipe-wall-thickness requirement, which
include:
·
The maximum and working pressures
·
Maximum and working temperatures
·
Chemical properties of the fluid
·
The fluid velocity
·
The pipe material and grade
·
The safety factor or code design
application
If there are no codes or standards that
specifically apply to the oil and gas production facilities, the design
engineer may select one of the industry codes or standards as the basis of
design. The design and operation of gathering, transmission, and distribution
pipeline systems are usually governed by codes, standards, and regulations. The
basic formula for determining pipe wall thickness is the general hoop stress
formula for thin-wall cylinders, which is stated as;
t = Pd0/2(Hs+P)
-------------------------------13
where
HS =hoop stress in
pipe wall, psi,
GeoStudio 2016 Download a
free 30-day trial of the leading Getechnical software.
geo-slope.com
t =pipe wall thickness, in.,
L =length of pipe, ft,
P =internal pressure of the pipe, psi, and
dO =outside
diameter of pipe, in.
Velocity Considerations
In choosing a line diameter, consideration also has to be given to
maximum and minimum velocities. The line should be sized such that the maximum
velocity of the fluid does not cause erosion, excess noise, or water hammer.
The line should be sized such that the minimum velocity of the fluid prevents
surging and keeps the line swept clear of entrained solids and liquids.
Liquid Line sizing
V=0.012 QL/d --------------------------------------14
where
QL =fluid-flow rate, B/D and
d =pipe ID, in.
In piping systems where solids might be present or where water
could settle out and create corrosion zones in low spots, a minimum velocity of
3 ft/sec is normally used. A maximum velocity of 15 ft/sec is often used to
minimize the possibility of erosion by solids and water hammer caused by
quickly closing a valve.
Gas line sizing
Gas velocity is expressed as
Vg= 60 QgTZ/d2P
---------------------------15
where
Vg =gas velocity, ft/sec,
Qg =gas-flow rate, MMscf/D,
T =gas flowing temperature, °R,
P =flowing pressure, psia,
Z =compressibility factor,
dimensionless, and
d =pipe ID in.
Multiphase line
sizing
Ve=C/ρM1/2
-----------------------------------16
where C = empirical constant.
ρM is the average density of the mixture at flowing conditions. It can be
calculated from
ρM=[(12049)(SG)P+(2.7)RSP]/[(198.7)]
-----------------------------17
Where
SG =specific gravity of the
liquid (relative to water), and S =specific gravity of the gas relative to air.
Industry experience to date indicates that for solids-free fluids,
values of C = 100 for continuous service and C = 125 for intermittent service
are conservative. For solids-free fluids where corrosion is not anticipated or
when corrosion is controlled by inhibition or by employing corrosion resistant
alloys, values of C = 150 to 200 may be used for continuous service; values up
to 250 have been used successfully for intermittent service. If solids
production is anticipated, fluid velocities should be significantly reduced.
Different values of C may be used where specific application studies have shown
them to be appropriate.
Where solids and/or corrosive contaminants are present or where c
values higher than 100 for continuous service are used, periodic surveys to
assess pipe wall thickness should be considered. The design of any piping
system where solids are anticipated should consider the installation of sand
probes, cushion flow tees, and a minimum of 3 ft of straight piping downstream
of choke outlets.
Once a design velocity is chosen, to determine the pipe size,
d ={[(11.9+ZRT/16.7P)QL]/1000V}
------------------------------18
where
d =pipe ID, in., Z =compressibility factor, dimensionless, R
=gas/liquid ratio, ft3/bbl, P=flowing pressure,
psia, T =gas/liquid flowing temperature, °R, V =maximum allowable velocity,
ft/sec, and QL =liquid-flow rate, B/D.
Conclusions
Offshore
production platforms and subsea pipelines account for the two most significant
categories of physical footprints of oil and gas developments in marine
environments. Alteration of the seafloor
is unavoidable during construction of subsea pipelines although constructors
have endeavoured to make the pipelines as operationally reliable and
environmentally compatible as current technology allows. Construction of platforms disturbs the
seafloor to different degrees depending on whether the platform is designed to
float or to rest on the seafloor; design and construction of an individual
platform depends on many factors that include water depth and whether ice could
be an operational hazard. Environmental
aspects of platform operations include management of wastewater as well as air
emissions. Pipeline operations emphasize
leak avoidance through continuous monitoring and remote control along with
regular inspection and maintenance.
References
Beggs,H.D 1991.Production Optimization Using Nodal Analysis,
123-127. Tulsa, Oklahoma : OGCI Publications.
Gilbert,W.E. 1954. Flowing and Gas-lift well performance. Drill
& Prod. Prac.,126-157. Dallas Texas: API
Ros, N.C.J. 1960. An Analysis of Critical Simultaneous Gas/Liquid
Flow Through a Restriction and its Application to Flowmetering. Applied
Scientific Research 9 (series A):
ANSI/ASME Standard B31.1, Standard for Power Piping. 2004. New York
City: ANSI/ASME.
2.0 2.1 2.2 2.3 2.4 2.5 ANSI/ASME Standard B31.3, Standard for
Chemical Plant and Petroleum Refinery Piping. 2002. New York City: ANSI/ASME.
ANSI/ASME Standard B31.4, Standard for Liquid Transportation
Systems for Hydrocarbons, Liquid Petroleum Gas, Anhydrous Ammonia, and
Alcohols. 2002. New York City: ANSI/ASME.
ANSI/ASME Standard B31.8,
Standard for Gas Transmission and Distribution Piping Systems. 1999. New York
City: ANSI/ASME.
5.0 5.1 5.2 5.3 API RP14E, Recommended Practice for the Design and
Installation of Offshore Production Platform Systems. 1991. Washington, DC:
API.
6.0 6.1 ANSI/ASME Standard B16.5, Standard for Steel Pipe Flanges
and Flanged Fittings NPS 1/2 through NPS 24 Metric/Inch. 2003. New York City:
ANSI/ASME.
API Spec. 6A, Specification for Wellhead and Christmas Tree
Equipment, nineteenth edition. 2004. Washington, DC: API.
ANSI/ASME Standard B16.11, Standard for Forged Steel Fittings,
Socket Welding, and Threaded. 2001. New York City: ANSI/ASME.
NACE Standard MR-01-75, Standard Material Requirements—Metals for
Sulfide Stress Cracking and Stress Corrosion Cracking Resistance in Sour
Oilfield Environments for Sulfide Stress Cracking Resistant Metallic Material
for Oilfield Equipment, Sec. 3 and 5. 2003. Houston, Texas: NACE.
10.0 10.1 The 2004 ASME Boiler and Pressure Vessel Code, Section
IX: Welding and Brazing Qualifications. 2004. Fairfield, New Jersey: ASME.
API Spec. 6F, Technical Report on Performance of API and ANSI End
Connections in a Fire Test According to API Specification 6F, third edition.
1999. Washington, DC: API.
API Spec. 6FA, Specification for Fire Testing Valves, third
edition. 1999. Washington, DC:
please like us or share in facebook
