Page 95 - Handbook Of Multiphase Flow Assurance

90 4. Hydraulic and thermal analysis

Single line tieback concepts may be considered for early production systems.
Technologies which could be considered in formulating a conceptual hydraulic design of a
field development include the following:
• Slug catcher or separator vessel(s)
• Periodic scraping
• Onshore or subsea compressors or booster pumps
• Onshore or subsea multiphase pumps
• Gas separator to minimize hydraulic loss or to reduce hydrate risk
• Water separator to minimize hydraulic loss or to reduce hydrate risk
• Downhole, wellhead and/or riser base gas lift
• Caisson gas separator if subsea reservoir is insufficiently strong
• Drag reducing agent chemical
• Multiphase flow meter or virtual flow meter
• Erosional limits for line sizing
• Water injection pump pressure limits per rock fracture gradient

Designs specific to subsea in the United States may refer to the following API technical
reports:
Avoidance of Blockages in Production Control Systems, API 17TR5;
Attributes of Production Chemicals in Subsea Production Systems, API 17TR6;
High-Pressure High-Temperature (HPHT) Design Guidelines, API 17TR8;
HIPPS for subsea, API 17TR13, section 10.8, and API 17O.

Water injection management
Multiphase flow assurance specialist may consult with topsides process, completion, and
reservoir engineers to design an effective system for water injection. Produced water injec-
tion system should be separate from sea water injection system if produced water overboard
discharge is not permitted.
Injection water should be treated seawater and not produced water. Produced water injec-
tion wells are subject to faster degradation of injectivity than seawater injection wells.
The injection water pump sizing and discharge pressure should take into account rock
fracture gradient. Injection pump design should include flexibility for injection at or above
the reservoir fracture pressure if injection above the reservoir fracture pressure is permitted.
The water injection pipe line minimum flow velocity in turndown case should be over 5 ft/s.
Project may consider placing water injection pump and filtration equipment on seabed to
reduce the number of risers.
Water hammer effects shall be accounted for in the design of all process control for valves
and automation operation.
Injection water quality relies on not mixing produced water and seawater in the injection
system. Even with very high injection water quality, operations may need to clean the wells
periodically.
Injection wells should be isolated when not in service so that no cross-flow hap-
pens between injection wells on shut-in if several injection wells are fed from the same
manifold.