Subsea Manifold Design and Analysis
The manifold should provide a sufficient amount of piping, valves, and flow controls to, in a safe manner, collect produced fluids or distribute injected fluids such as gas, water, or chemicals. The manifold should have sufficiently sized bores in piping and valves to allow pigging. If wells are to be completed on the template, the manifold should provide for the connection of the Christmas tree.
The manifold may provide for mounting and protection of equipment needed to control and monitor production/injection operations. The manifold may also include a distribution system for hydraulic or electrical supplies for the control system. Where wells are incorporated into the template and manifold, the addition of spare well slots should be considered. If satellite wells are to be tied in, the template and manifold design should provide this capability considering pipeline and umbilical connections, pull-in loads, valving, and pigging capabilities. The initial design considerations should consider the types of accidental damage loads to which the system may be subjected.
A maintenance approach should be considered early in the design of a template/manifold system. Specifically, the following items should be considered:
- Maintenance method;
- Retrievable components;
- Access space for divers, ROVs, or other maintenance equipment;
- Height above seabed for visibility;
- System safety with components removed;
- Identification of failing components.
Manifold design and analyses should address the following issues:
- Steel frame structures and painting design;
- Pipework and valve design;
- Connection equipment and control equipment;
- CP design;
- Flow assurance and hydraulics.
- 1 Steel Frame Structures Design
- 2 Manifold Piping Design
- 3 Pigging Loop
- 4 Padeyes
- 5 Control Systems
- 6 CP Design
- 7 Materials for HP/HT and Corrosion Coating
- 8 Hydrate Prevention and Remediation
- 9 References
Steel Frame Structures Design
The manifold should be designed with the ability to be installed together with the template and as a separate module. Cluster manifolds should be based on an integrated template and protection structure with a separately retrievable manifold.
Structural DesignThe design pressure for a steel manifold piping system or the nominal wall thickness for a given design pressure may be determined according to ASME B31.8. Formulas used for wall thickness design, flexibility analysis, and code stress checksmay be determined from the same documents. For example, the formula from ASME B31.8 is:
The manifold system may include valves, hubs, connectors for pipeline and tree interfaces, chokes for flow control, and through-flowline (TFL) diverters. It may also include control system equipment, such as a distribution system for hydraulic and electrical functions.
Structural Frame The manifold structural frames satisfy the following requirements:
- Be designed to the requirements of API RP2A.
- Be fabricated to requirements of AWS D1.1.
- Provide support and protection for header piping and control tubing.
- Provide the means for guidance and alignment of the manifold onto the pile foundation.
- Consist of a primary structural frame and ancillary protective structures, support structures, alignment and guidance systems, and installation and handling facilities.
- Provide sufficient open space for installing the manifold piping and valves, and be strong enough to resist all anticipated loads and deflections.
- Be designed with the bottom of the frame suitable for supporting the static weight of the manifold on the ground/deck.
- Provide a four-point lift arrangement suitable for a four-legged flexible wire rope sling. The lift points shall be strong enough to support the weight of the manifold in its as-installed configuration. All lift points will be designed in accordance with API 17D.
- Contain all anodes necessary to cathodically protect the manifold system from external corrosion, including any anodes needed to protect the system from external drainage, such as half of the total area of attached jumpers and flying leads.
Interfaces The following interfaces in the design of the manifold are considered:
- Well/flowline jumper interface to manifold hub including spacing for and access to pipeline end connector running tools;
- Pressure cap installation and retrieval;
- ROV access for valve functioning/isolation;
- ROV access to flying lead junction plates;
- Operational interfaces associated with installation, lifting and handling (padeyes, slings, bridles, spreader bars, installation vessel, etc.);
- Pile foundation top.
Manifold Piping DesignThe piping system, header, and branch piping should be designed based on DNV OS-F101/ASME31.8, Chapter VIII, and comprises the entire piping: straight pipes, bends, tees, and reducers on the header and branches.
The following issues should be considered for the piping stress analysis:
- Internal pressure;
- Thermal loads;
- Operating with jumper loads;
- Flowline jumper connection loads;
- Well jumper connection loads;
- Environmental loads;
- External corrosion;
- Internal corrosion/erosion;
- Piping supports to accommodate all anticipated loading, deflections, and vibrations.
Piping system should be designed to satisfy the requirements for internal pressure, thermal loads, hydrostatic collapse, and external operational loads, and fabricated to ASME Section IX requirements. Piping stress analysis should be performed using a finite element software package, such as CAESAR II, Ansys, or Abaqus, to confirm that the manifold piping system is fit for the intended purpose for its entire life span.
section including discontinuities. The bending stress is a component of primary stress proportional to the distance fromthe centroid of a solid section.
The manifold piping loop is designed to allow passage of pigs through the main headers to provide round-trip pigging of the flowlines from the production platform. The pigging loop should satisfy the following requirements:
- Is subsea installable and retrievable without guidelines using a suitable spreader beam with rigging?
- Conforms to the same standards as the manifold header piping.
- Has a full-bore gate valve that will allow a pig to pass without hang-ups. This valve should be hydraulically operated.
- Provides facilities to inject chemicals/methanol through two parallel hydraulically operated gate valves with integral check valves mounted to either side of the full-bore gate valve.
- Is of the same material and size as the production manifold pipeline header piping.
- Is insulated to the same requirements as the production manifold pipeline header piping, with the exception of the pipeline end connectors.
- Is constructed with bends having a minimum radius of five times the nominal pipe diameter (5D).
- Mounts on the inlet hubs of the production manifold.
- Is not required to provide anodes for its own cathodic protection. Electrical continuity to the production manifold will be demonstrated.
- Is coated with three-part epoxy paint with the exception of stainless steel tubing, unless otherwise specified.
Pigging loop system design should consider the following:
- Piping size;
- Bend radius;
- Internal protrusions;
- Valve types;
- Pig launcher/receiver;
- Pig location determination.
Padeyes should be designed in accordance with the industry practice using a design safety factor of typically 4 or greater based on minimum specified ultimate material strength at the maximum rated pickup angle during installation. This factor of safety is to be applied to the design lift. The design lift includes the total weight to be lifted multiplied by the dynamic load factor (DAF ¼ 1.33).
The production control system and its components should be designed according to ISO 13628-6 . For polymer-based hoses, material selection should be based on a detailed evaluation of all fluids to be handled, but it should not be used for pure methanol service (with less than 5% water); see API Spec 17E. The annulus bleed system is exposed to a mixture of fluids, such as production fluid, methanol, completion fluid, and pressure-compensating fluid. A hose qualification program should be carried out, including testing of candidate materials in stressed conditions representative of actual working pressures, unless relevant documentation exists.
For umbilicals, the electric cable insulation material should also be qualified for all relevant fluids. The materials selected for the electrical termination should be of similar type, in order to ensure good bonding between different layers. The material selection for metals and polymers in electrical cables in the outer protection (distribution harness) and in connectors in distribution systems should have qualified compatibility with respect to dielectric fluid/pressure-compensation fluid and seawater.
Cathodic protection should be used for all submerged, metallic materials, except for materials that are immune to seawater corrosion. A surface coating should also be used for components with complex geometries and where its use will result in a cost-effective design. Welded anode connections are recommended for subsea applications. Flanged and screwed connections should be avoided where possible. The electrical continuity to the cathodic protection system should be verified by actual measurements for all components and parts not having a welded connection to an anode. Any components permanently exposed to ambient seawater and for which efficient cathodic protection cannot be ensured should be fabricated from seawater-resistant materials. Exceptions are components where corrosion can be tolerated, that is, where pressure containment or structural integrity will not be compromised. Material selection should take into account the probability for, and consequences of, component failure.
The following materials are regarded as corrosion resistant when submerged in seawater at ambient temperature:
- Alloy 625 and other nickel alloys with equal or higher PRE value (PRE ¼ % Cr þ [3.3 % Mo] þ [16 % Ni]);
- Titanium alloys with suitable performance under cathodic protection (should be documented for the relevant operating conditions);
Stainless steels Type 6Mo and Type 25 Cr duplex are borderline cases and not considered as fully seawater resistant for temperatures above 15oC (60oF). These materials should not be used for threaded connectors without cathodic protection. The location and number of CP inspection points for intervention and risk of hydrogen-induced cracking should also be evaluated and determined. Hydrogen-induced stress cracking (HISC) issues should be addresses for duplex stainless steel pipework exposed to cathodic protection. The duplex stainless steels are susceptible to HISC when exposed to elevated stresses in conjunction with cathodic protection potentials lower than typically –850 mV relative to the Ag/AgCl/seawater reference electrode. DNV- RP- F112 should be incorporated into the piping design code when designing duplex stainless steel pipework.
Materials for HP/HT and Corrosion Coating
Materials for HP/HT Manifolds
Materials for HP/HT manifolds should meet these requirements:
- All piping pipe is made of duplex stainless steel alloy.
- All tees, crosses, elbows, and flanges are made of duplex stainless steel alloy.
- The production pipeline end connectors and hubs are made of materials based on their UNS designation (unified numbering system designation).
- The manifold frame is made from carbon steel.
For the materials used in subsea structures, manifolds, piping, and other components having importance for the safety and operability of the subsea production system, the following factors apply to the materials selection:
- Materials with good market availability and documented fabrication and service performance;
- Design life;
- Operating conditions;
- Mass reduction;
- Experience with materials and corrosion protection methods from conditions with similar corrosivity;
- System availability requirements;
- Minimization of the number of different material types considering costs, interchangeability, and availability of relevant spare parts;
- Inspection and corrosion-monitoring possibilities;
- Effect of external and internal environment, including compatibility of different materials;
- Evaluation of failure probabilities, failure modes, criticalities, and consequences;
- Environmental issues related to corrosion inhibition and other chemical treatments.
The materials to be used should normally fulfill the following requirements:
- The material should be listed by the relevant design code for use.
- The material should be standardized by recognized national and international standardization bodies.
- The material should be readily available on the market.
- The material should be readily weldable, if welding is relevant.
- The material preferably has a past experience record for the particular application.
Corrosivity Evaluation in Hydrocarbon Systems
Evaluation of corrosivity should include at the least:
- CO2 content;
- H2S content;
- Oxygen content and content of other oxidizing agents;
- Operating temperature and pressure;
- Acidity, pH;
- Halogenide concentration/water chemistry;
The evaluation of CO2 corrosion should be based on an agreed-on corrosion prediction model or previous experience from the same field. Risk for “sour” conditions during the lifetime should be evaluated. Requirements for corrosion-resistant alloys in sour service should comply with ANSI/NACE MR 0175, Sulfide Stress Cracking Resistant Metallic Materials for Oil Field Equipment, with amendments given in this part of ISO 13628.
Corrosivity Evaluation in Water Injection Systems Water injection systems are used for injection of deaerated seawater, raw untreated seawater, and produced water including aquifer water. Corrosivity evaluations for deaerated injection seawater should be based on the maximum operating temperature appropriate for the given geographical area. For carbon steel submarine injection flowlines used for low corrosive services, the minimum corrosion allowance should be 3 mm (0.12 in.). All components that may contact injection water should be resistant against well-treatment chemicals or well-stimulation chemicals if backflow situations can occur. For carbon steel piping, the maximum flow velocity should be evaluated considering the corrosivity and erosivity of the system.
Hydrate Prevention and Remediation
As subsea field development expands into deepwater environments, operators need to consider the potential risk of gas hydrate formation in wellbores, subsea pipelines, and subsea equipment during both drilling and production operations. Hydrates can also form in certain sections of subsea equipment exposed to stagnant fluids under normal or transient flow conditions. The hydrate management philosophy for subsea systems is as follows:
- No continuous inhibition of the subsea system is required in flowing conditions.
- No part of the fluid system is allowed to enter the hydrate formation domain during flowing and shutdown conditions.
- During start-up operations, the cold production fluid released by the well is inhibited at the wellhead until the production temperature reaches a temperature high enough to ensure sufficient cooldown time if another shutdown occurs.
Remediation of hydrate plugs in subsea equipment can be difficult or impossible. In shallow-water field developments, the pipeline and subsea equipment could potentially be depressurized to allow a hydrate plug to dissociate. In deepwater, the hydrostatic head of liquids in the pipeline may be generally high enough to keep the hydrates stable. While the pipelinecould be displaced, the tree piping, jumper piping, and manifold branch valves are typically not designed for pigging or circulation. One of the challenges is to apply thermal insulation to subsea equipment in optimal locations to achieve the most benefits. To design thermal insulation for subsea equipment with complex geometries, thermal finite element analysis (FEA) is typically performed. Although a certain minimum thermal insulation thickness is required to achieve the required cooldown time, it is sometimes not practical to insulate all of the surfaces due to access, manufacturing assembly process, equipment testing requirement, contingency procedures for disassembly and repair, etc.
Subsea gate valves have a complex internal geometry and flat exterior surfaces unlike the typically round cross section of upstream and downstream piping. Areas that trap fluids inside the valve cavity are prone to hydrate blockage if the valve is not properly insulated. Furthermore, the valve actuators are not typically insulated to avoid overheating the actuator sealing elements and the hydraulic fluid. The actuator behaves like a large fin and dissipates a lot of heat unless the valve assembly is properly analyzed. Three-dimensional thermal FEA is useful for understanding the heat flow and, hence, designing the insulation around the valve body shows the results of temperature distribution in a group of valves in a manifold.
The insulation on any part of a manifold piping system is usually of sufficient thickness to meet the cooldown time required for hydrate management. This insulation coupled with high fluid temperatures may exceed the qualification temperature of the electronic components for instruments. Care should be taken to select the proper instruments and determine the insulation thickness around those electronic components. Either the electronics for the components should be requalified at a higher temperature or sections of the insulation have to be cut away to provide the cooling for the electronics. The connecting jumpers between the tree and manifold, and between the manifold and flowline, would appear to be reasonably straightforward to insulate, and do not suffer from the potential cold spots at the manifold due to valves.
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