case study for insulation selection for a deepwater development

Case Study for Insulation

Selection for a Deepwater

Development

Mustafa Mahmood, Flow Assurance Manager

Kuala Lumpur, 3rd October 2012

Contents

1. Introduction / Project Background

2. Concept Selection

3. Flow Assurance

4. Conclusions

Case Study for Insulation Selection for

Deepwater Development

Introduction / Project Background

The Case Study presented is for a deepwater oil

production system, tied-back to an existing FPSO.

Project Data

• Water Depth 1400 m

• Three production centres (P1,P2,P3) / manifolds

• 20 km subsea tie-back to an existing FPSO

• 2x7” flexible risers design

• Two 8” production flowlines in a piggable loop





Fluid Data

Crude production from the subsea wells will come pre-

dominantly from 4 different reservoirs. The fluidproperties available for the 4 reservoirs are presented

in the table below.

Reservoir Reservoir

Temp

(oC)

GOR

(SCF/STB)

APIo Dead Oil

WAT

(oC)

Live Oil

WAT

(oC)

Dead Oil

Pour

Point

(oC)

Live Oil

Pour

Point

(oC)

1 44– 53 655-782 33.4– 37.6

2 47–54 802-813 35.3-35.7 2 to 12

3 57-64 672-773 31.5-32.1 18 to 29 12 to 15 < 0

4 61-65 560-709 28.5-31.7 17 to 31 26 to 28 12 to 18 < 0



Hydrate Curve

Ambient

Temp



Main flow assurance challenges being :

• hydrate,

• wax

• gel management.

For this Case Study:

Dead Oil WAT = 31 deg.C, (Steady State Conditions)

Dead Oil Pour Point = 18 deg.C (Cooldown Conditions)

Hydrates at 18 deg.C or less. (Cooldown Conditions)

Dead Oil Gel Strength = 250 Pa



Concept SelectionConcept Screening Workshop narrowed the number of concepts to two

concepts.

a)Dual Pipe in Pipe (PIP) flowlines in piggable loop configuration.

b)Dual glass flake syntactic polyurethane (GSPU) Insulated

flowlines

Insulated Flexibles risers were considered for both options.

A piggable loop pipeline configuration employed to cater for turndown

flowrates, hot oil flushing ,the provision for depressuring either side of a

hydrate blockage and inspection pigging etc.

Only initial concern was Reel-Lay for the PIP option with regional based

installation contractors.



Flow Assurance – Steady State

The Dual Flowlines options considered with PIP (U=1.2 W/m2.K)

production flowlines or 3” GPSU (U=2.9 W/m2.K) insulated

flowlines and insulated flexible risers (U=2.6 W/m2.K).

The P3 to P2 section was considered to be the most critical from a

steady state point of view since it would experience the lowest

flowrates

Flowrates from P3 could be low enough to justify operation of only

a single flowline from P3 with the other section remaining diesel

filled.

The steady state results for Single and Dual flowlines operating for

the P3 to P2 sections of the flow loop are presented below for the

PIP and GSPU flowline insulation options.



PIP Single / Dual Flowlines Outlet Temperatures at P2

P3 to P2



GSPU Single / Dual Flowlines Outlet Temperatures at P2



P3 to P2

GSPU Single Flowline Temperature Profile

.P3 P2 P1



Flow Assurance P3 to P-2 Steady State

A single PIP flowline operating from P3 to P2 operating PIP

maintains fluid temperatures above WAT = 31 deg.C.

For Dual PIP flowlines operating, fluid temperatures fall below

31 deg.C for years 15 to 20 and will require wax inhibition.

Dual GSPU production flowlines cannot maintain fluid

temperatures above WAT = 31 deg.C and will require wax

inhibition continuously from year 1.

For a single GSPU flowline operating from P3 to P2 fluid

temperatures fall below 31 deg.C for years 15 to 20 and would

require wax inhibition.

The riser section for years 1 & 2 fall below 31 deg.C and thus

chemical injection would also be required in these years.



Flow Assurance - Operating / Insulation Philosophy

Under upset conditions such as unplanned shutdowns, the insulation

is to provide sufficient cooldown time to flush the production flowline

system with diesel/stabilized inhibited crude. This then mitigates any

gel or hydrate risk in the flowlines during shutdowns.

Flush existing system prior to flushing new development.

Use existing flushing pumps or propose new flushing rate.

Cooldown times of 22.5 hrs or 11.1 hrs are required for flushing rates

of 100m3/hr (existing) or 200m3/hr .



Flow Assurance - Cooldown Analysis

Cooldown plots presented for:

• GSPU flowline (single flowline in operation between P3 to P2)

• PIP flowline (single flowline in operation between P3 to P2)

• PIP flowline (dual flowline in operation between P3 to P2)

• PIP flowline (dual flowline in operation between P3 to P2) +

Detailed Riser




Year 1 GSPU flowline (single flowline in operation between P3 to P2)

P3 to P2 P2 to P1 P1 to Riser




PIP flowline (single flowline in operation between P3 to P2)





PIP flowline (dual flowline in operation between P3 to P2)





PIP flowline (dual flowline in operation between P3 to P2) + Detailed Riser




Case Study Conclusions

• PIP system provides a robust solution and steady state operatingconditions which do not require wax inhibition until Year 15 onwards forthe dual flowlines operating between P3 and P2.

• This option was recommended.

• GSPU option requires steady state single flowline operation between P3and P2 and continuous wax inhibition for Yrs 1 & 2 & 15 to 20.

• Flushing rate should be increased from 100m3/hr to 200m3/hr to provide amore acceptable cooldown requirement.

• The PIP can comfortably meet cooldown requirements however the GSPUcan just meet cooldown requirements with flushing operations.

• For GSPU option flushing operations of the diesel filled section betweenP3 and P2 result in short periods (1 to 2 hours) of operation in the hydrateand gelation region which is normally unacceptable.

• Riser cooldown also meets flushing requirements



case study for insulation selection for a deepwater development

Documents