With decades of experience, FMC is a well recognized partner when it comes to Flow Assurance.  Through extensive studies, we analyze the total system over the lifecycle of the field, evaluating Fluid Characterization and running Dynamic Flow Simulations to determine required Paraffin and Hydrate Management, Chemical Injection Systems, and Liquid Slugging Management.  Based on the analyses, further recommendations with regards to Thermal System Design and Topsides Supporting Equipment Design and Specifications are reported and presented.

FMC’s approach to flow assurance is to analyze the production system from the “reservoir to export system” to optimize hydrocarbon recovery over the life of the field.

Integrated Flow Assurance Analysis from “Reservoir to Export”

Flow Assurance Services

To Flow Assurance services targeting all important issues enabling and optimizing flow of oil & gas from reservoir to the topside receiving facilities.

FMC customers will receive excellent and highly competent support to optimize design and operation of the flowing systems.

FMC has performed multiple critical studies for most of our main customers with success. Critical decisions has been made based upon the outcome of these studies.

The flow assurance strategy comprises a combined design and management philosophy for all of the following depending upon fluid properties and operating conditions:

This strategy will be adopted early in the conceptual and planning phase of the project prior to specifying and ordering the key components of the system, such as downhole equipment, trees, flowlines, control system and topsides equipment.  Flow assurance strategy will also be applied during detailed system design, developing operating procedures as well as offshore production operations to maximize profitability of the field development.  Based on the flow assurance analysis results, a design philosophy and functional specifications can be developed for the following elements:

• Sizing of well tubing and completion design
• Sizing of all flowlines, risers and export system including subsea manifolding
• Thermal management (insulation or heating)
• Chemical injection system including the subsea chemical distribution, umbilical, topsides chemical delivery system
• Pigging strategy (subsea or surface launching)

An important step of the design of deepwater subsea facilities is to collect and analyze high quality reservoir fluid samples.  A representative reservoir fluid sample, collected at bottom hole pressure/temperature conditions, is recommended.  Laboratory analysis of this sample will provide quantitative information on the fluid composition (hydrocarbons, non-hydrocarbons and solids), fluid chemistry, physical properties and tendency to form deposits such as wax, asphaltenes and hydrates.  These measurements will assist in developing cost-effective designs for downhole completions, subsea facilities, flowlines, risers, topsides equipment and export system.  Without specific fluids information, large safety factors and potentially unnecessary equipment will likely be specified.

Multiphase flow analysis will be performed to optimize and define the size of downhole tubing, number and size of flowlines and risers, and requirement for manifolding.  The key drivers will be available reservoir energy, well depths, offset distances to the host processing facility, flow rates and fluid compositions.  Flowline and tubing optimization will consider erosional velocity constraints at high rates and the potential for liquid slugging at low rates.

Depending on reservoir drive mechanism, fluid compositions, field layout and other parameters, ways to improve system deliverability (i.e. increase production rate) will be investigated.  Example approaches may include one or several of the following, possibly among others:

• gas lift: downhole, at subsea tree or riser base
• pumping: downhole ESP or subsea multiphase
• injection wells
• separation: 2-phase or 3-phase, and downhole or seabed

FMC Technologies, Inc. has experience and capabilities to incorporate the above flow enhancement approaches in subsea fields to maximize recovery rates and improve project economics.

As a baseline, the API 14E recommended equation (C Factor of 100) can be used to predict the erosional velocity limit and the maximum allowable production rate.  Field experience suggests that this approach may be conservative, especially when very little or no sand is present in the flow stream.  Alternative, more accurate methods are available to predict erosional velocity rates based on sand content, flow compositions and velocities.  The alternative approaches may allow operating at higher velocities without risk of erosion so that the production rate can be increased.

Various types of sand and erosion monitors are available for installation within/on subsea tree and manifold piping.  These devices can be used to monitor erosion and optimize well flow rates, often well above the API 14E recommended limit.

 Most wells produce some water, either condensed or free water, over the life of the field.  Natural gas combined with produced water can form hydrate plugs under combination of low temperatures and high pressures.  Hydrates can form and plug the downhole tubing, tree/manifold piping, flowlines and/or risers.  The likelihood of hydrate formation is greatest during shut-in conditions when the production system is cold and the pressures are high.  Depending on the flowing pressures and temperatures, plugs can also form during flowing conditions.

To prevent and manage hydrate formation, combination of either chemical treatment and/or thermal insulation may be used.

For gas and gas/condensate wells, typically, chemicals such as methanol or ethylene glycol may be injected continuously to inhibit formation of gas hydrates.  For low water production rates, these chemicals may be continuously injected downhole and/or at the subsea tree.  Depending on fluid compositions and system operating conditions, use of kinetic gas hydrate inhibitors can be evaluated.  While these chemicals do not prevent hydrate formation, they prevent agglomeration of crystals into large blockages.  These chemicals can be used in relatively small dosage quantities compared to methanol or glycol so that chemical consumption cost may be reduced.

In cases where the water production rate is very high, such as in many oil wells, continuous hydrate inhibitor injection is prohibitively expensive.  In these cases, the flowlines and risers can be thermally insulated to maintain the flowing temperatures above the hydrate formation temperature.  Thermal insulation can be designed to prevent rapid cool-down below the hydrate formation temperature during a shut down. 

The cool-down time can be designed to be sufficient for the operator to take remedial action.  Remedial action may include flowline/riser pressure blow-down to reduce the flowline pressure below the critical hydrate formation pressure.  However, in deepwater flowlines, even after bleeding the pressure off from a riser, the hydrostatic head of the liquids (oil and water) in the riser and flowline may be sufficient to accommodate hydrates.  To prevent hydrates, the flowlines and risers can be pigged and displaced with an inhibited fluid.

Corrosion inhibition philosophy depends primarily on the produced fluid composition (mainly CO2 or H2S), water chemistry, operating pressures and temperatures, and to some extent the flow regime.  The recommended solution may be either the use of carbon steel flowlines combined with continuous corrosion inhibitor injection or the use of corrosion resistant alloys.  For low CO2 concentrations, typically carbon steel flowlines may be used.  Empirical models can be used to predict the corrosion rate with and without the chemical inhibitor to develop an appropriate design.  A corrosion allowance is generally included in the pipe wall thickness specification to account for the corrosion rate and to provide a margin in case of a temporary failure in the chemical injection system.

Depending on the oil’s cloud point temperature and paraffin content, paraffin may deposit on the walls of the tubing, flowline and risers.  Depending on the deposition rate, the paraffin deposit may eventually completely block the flow passage. An important element of the paraffin management process is to collect a representative reservoir fluid sample for laboratory analysis.  Laboratory analysis is required to measure the oil’s cloud point temperature and paraffin.

Based on the laboratory measurements, multiphase flow and thermal simulations of the production system, the potential severity of paraffin deposition in the production system can be evaluated.

Both initial and late life conditions should be evaluated to assess the potential for paraffin deposition.  To prevent and manage paraffin deposition, combination of thermal insulation, chemical treatment and pigging may be used.  A cost/benefit analysis of these solutions should be conducted before final selection of a paraffin management strategy is made.

At low flowing velocities, depending on fluid composition and line size, the liquid can accumulate in the line and form liquid slugs.  Both hydrodynamically-induced and terrain-induced slugs can form and potentially arrive at the host facility.  Depending on slug volumes and frequency, the liquid slugs can potentially “overload” the topside processing system and result in frequent process upsets and shut downs.  One remedy is to install large slug catchers at the topsides.  Other options include using smaller diameter lines, riser-base gas lift, subsea separation, flow and pressure control via surface chokes, etc.  Transient, dynamic analysis of the flowline and risers must be conducted to evaluate the potential severity of liquid slugging.  Based on this type of analysis, an appropriate strategy to control slugging can be developed.  This can be performed with transient, multiphase simulation tools such as PLAC or OLGA.  FMC currently has a license for PLAC.

Depending on fluid characteristics and system materials, a wide range of chemicals maybe injected into the subsea wells and the flowline.  The following parameters should be defined to design the chemical injection system:

• produced fluid and flow assurance analysis to define the need for various chemicals such as hydrates, wax, asphaltene, scale, corrosion, etc.
• compatibility of various chemical mixtures
• injection rate for each chemical
• injection schedule for start-up/shut down and normal flowing

Based on the above information, the chemical injection system can be defined, which consists of the following components:

• injection ports in the downhole tubing and at the tree
• appropriate materials for conduits in the umbilical
• chemical compatibility with the umbilical conduits
• topsides chemical injection pumps

In a typical subsea development, to simplify the design, a dedicated line is used to deliver each chemical mixture from the topsides to individual wells.  This approach can become expensive for long offset distances and for large number of wells.  One option is to consider a subsea chemical distribution system to minimize the number of tubes in the umbilical.

An important element of a subsea development typically includes a flowline between the subsea facilities and the host.  The design of the flowlines must consider several design factors such as the following:

• pipeline materials selection
• internal and external corrosion control philosophy
• wall thickness designed for internal pressure, collapse from external hydrostatic pressure, installation loads, fabrication tolerances, corrosion allowance, etc.
• on-bottom stability
• thermal expansion and its effect on both ends of the pipeline
• pipeline burial, if required
• thermal insulation, if required
• span corrections and potential pipeline crossings
• installation method and selection of installation vessel
• subsea flowline connections and sleds, and
• riser configuration

Depending on the flow assurance requirements, the flowline may require thermal insulation.  Some of the thermal insulation options include:

• external coating with polypropylene foam, syntactic foam or syntactic polyurethane
• pipe-in-pipe with polyurethane foam in the annulus
• flowline bundles to accommodate hot fluid circulation lines
• electrically heated flowlines (new technology)

Design of thermally insulated flowlines is generally more complex and requires a detailed evaluation of the following factors:

• thermal insulation efficiency
• thermal expansion
• mechanical properties of the insulation
• field joint design
• installation mechanics and loads
• cost and technical risk