Flow Assurance
Muayad Al Faour
Muayad Al Faour
Flow assurance, by definition, focuses on the whole engineering and production life cycle from the reservoir through refining, to ensure with high confidence that the reservoir fluids can be moved from the reservoir to the refinery smoothly and without interruption.
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Introduction
In its virgin reservoir state, the hydrocarbon and formation water are in equilibrium with its environment for millions of years. During production, this equilibrium is abruptly disturbed as the hydrocarbon and water flow out of the reservoir into the production system. As the fluids try to reach new equilibrium with the changing environments, phase changes will likely occur, for example, gas breaking out from oil, liquid hydrocarbon condensing from gas, solids forming in the hydrocarbon or produced water phases, etc. A typical flow assurance diagram of a black oil is included to the right. These phenomena pose threat to smooth operation of the production facilities. Flow assurance is about understanding these threats and develop the appropriate engineering, design, and chemical methods to combat or remediate them.
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Why is Flow Assurance Important?
Flow assurance is essential to the sustained operability of production facilities. Flow assurance failures often result in production shut-down and costly interventions. What operating environments does flow assurance typically pose a challenge? Almost all, but some are worse than others. Indeed, when Petrobras introduced "Garantia de Fluxo", it was intended for deepwater developments, which often have high pressure and low temperature conditions. The high capital costs and restricted accessibility of deepwater facilities and flowlines made it critical to understand and prevent the various phenomena that could hamper production, particularly hydrates and multiphase flowphenomena. With the move to ever increasing water depths, the flow assurance challenges have only amplified. Another area that flow assurance plays a critical role is arctic environments, such as Sakhalin, Alaska, etc. In these environments, temperatures can be much lower than the oil and water freezing points.
Flow Assurance Workflow Process
Flow assurance workflow process with surveillance incorporated
Flow assurance studies are fundamental to the development of oil and gas discoveries, especially in deep water. In all cases, integrated flow assurance analysis is a key driver of field development, from reservoir to export system and must be addressed early in the design process for offshore production systems[2][3]. Flow assurance risk assessment includes:
•Interface with other disciplines, from reservoir engineering to topsides.
1.The process starts in the exploration and appraisal phase where both in-situ fluid property data are measured and selected fluid samples are retrieved for more detailed laboratory analysis.
2.Specific flow assurance related studies may be run on the fluid samples in the laboratory. The scope and type of these analyses will depend on the anticipated problems.
3.The laboratory data is then used in a series of engineering software tools to model various scenarios for the production system.
4.From that process, each system and its appropriate flow assurance management strategy is defined.
5.Once the selected system is designed and installed, the flow assurance management processes should be monitored and optimized. Recognizing that the initial design of these strategies was most likely conservative there is typically good opportunities to optimize the process and reduce OPEX. However, the large cost of failure requires a careful monitoring of the system to catch potential problems before they result in a catastrophic failure like a blocked flowline.
6.In surveillance, system data like temperatures, pressures and flow rates are collected from sensors at various points. Models that used fluid property data obtained in the design phase are conditioned to the measured system data. These models can now be used to determine the current state of the system and to optimize the system through a series of what if runs.
Lab analysis
PVT Analysis
PVT information is crucial for understanding the flow behaviour of the production fluids and it is key to both flow assurance and reservoir modelling. Under reservoir condition, the hydrocarbon fluid is typically a homogeneous single phase. As the fluids are produced and pressure and temperature change, the fluid may split into different phases, particularly liquid and gas phases. It is of utmost importance to know and understand how much liquid and gas phase will be produced and what the compositions and properties are. IThis description is called the PVT (Pressure, Volume, Temperature) behavior of the fluid.
PVT analysis typically includes reservoir composition, single or multi-stage flash, flashed gas and oil compositions, GOR, gas and oil gravity, viscosity under reservoir conditions, bubble points, etc.
Water composition
Proper water composition analysis is critical to hydrate and scale risk assessments. Typical cation components are typically easy to analyze with ICP, but great care must be taken for bicarbonate and sulphate analyses, both of which are prone to error and key to scale assessment.
Flow assurance property characterization
The list of relevant fluid properties will vary depending on the type of fluid and the expected system operating conditions.
•For wax, the following are measured on a dead oil: the normal paraffin distribution, using high temperature gas chromatography (HTGC), wax appearance temperature, viscosity and pour point. If these parameters indicate potential wax deposition, elevated viscosity or gelling problems, a more thorough analysis program including measurements made under live oil line conditions and chemical evaluation is needed[8][9].
•For asphaltenes, dead oil characterization data including SARA (Saturate Aromatic Resin Asphaltene) and paraffinic solvent (typically n-pentane or n-heptane) titration endpoint are used as screens for fluid stability. Because asphaltene screening and modeling capability is less well developed than those for wax, it is common to measure at least one live oil asphaltene precipitation pressure as well[10]. If an asphaltene issue is identified, additional studies are defined to map out the Asphaltene phase diagram as a function of temperature and to evaluate the effectiveness of chemicals or coatings as prevention strategies[11].
•For gas hydrates, composition from a standard PVT or validation study and produced water composition are used in a thermodynamic model to generate the expected hydrate formation boundary. If the compositional data are unusual or the pressure and temperature conditions are outside the range of validity of the model, direct measurement of hydrate formation conditions may be performed. If hydrate formation is a potential risk to the production system, a combination of modelling and experimental tests with representative fluids are conducted to evaluate the performance of thermodynamic inhibitors and/or low dosage hydrate inhibitors (LDHI) (which includes both kinetic hydrate inhibitors and anti-agglomerants).
•For inorganic scales, formation water compositions are used to evaluate scaling potential in various production scenarios. As the measured water composition may not be representative of its composition under reservoir condition because some solids may have dropped out during the sampling and measurement process, it is important to reconstitute its reservoir composition based on the field specific petrophysical rock properties. If scaling risk indicated, capillary tube blocking test can be conducted to evaluate the risk experimentally and screen for scale inhibitors that work for this fluid.
Previous research indicated that these potential solid deposits can influence each others' behavior[12], it is important to take that into consideration during flow assurance property characterization and chemical selection.
Thermal hydraulic modelling
Thermal hydraulic analysis is key to the overall system design and operation. It incorporates all the relevant information, such as fluid composition, system components and dimension, topography, etc. to give the overall picture of what the production will look like.
Steady state analysis
Steady state analysis is done for system during normal operation, typically with tools such as PIPESIM or UNISIM. It gives the flowing pressure and temperature profiles during steady state with different production rates and system designs. Results from the steady state analysis help narrow down the design options and specifications and what additional steps need to be taken to ensure smooth operation. For example, decisions on flowline size and pressure rating, tree pressure and temperature rating, choke location, and thermal insulation requirements partially come from the steady state analysis.
Transient analysis
Transient analysis is to study how the system behave during start-up and shut-down operations. It is typically done with OLGA. Key outcomes from the transient analysis include cool down time, warm up time, slugging, chilly choke effect, hot oil circulation, etc.
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Flow Assurance Strategy
Flow assurance strategy is fundamentally about system operability, which is about how to design and operate the system to avoid and mitigate all the relevant flow assurance risks.
System design
System designs for flow assurance consideration are typically (or should be) incorporated during early stage of the project, which include subsea layout, flowline sizing and insulation, flowline burial, pigging loop, hot oiling capability, chemical delivery requirement, separator sizing, choke location, riser base gas lift, etc. If these considerations are integrated into the system design, operators will have a much easier time managing flow assurance risks once the system comes online.
Operation
This part involves what operational procedures the operators should follow to manage flow assurance risks. For example, the production may need to be maintained at certain rate, beyond which slugging becomes a severe problem. Other instances include when to conduct flowline blowdown or dead oil displacement after shut down, how the wells should be ramped up during startup to avoid hydrate blockage, hot-oiling to warm up the flowline, flow diversion/combination to avoid slugging, etc.
Chemicals
Chemicals are typically available to mitigate/remediate almost all solid deposits, but may be with varied efficiencies. For example, asphaltene inhibitor and paraffin inhibitor are not expected to be 100% (in fact, 50-60% is more reasonable) effective in preventing solid buildup. On the other hand, thermal dynamic hydrate inhibitors can provide full protection against hydrate formation if dosed at the recommended rate.
For any chemical strategy, the following are important considerations:
•Performance evaluation has to be representative to field conditions.
•Injection point is ideally upstream of the expected trouble spot.
•Deliverability
•They don't inadvertently cause other negative consequences.
•Compatibility, including chemical-chemical, chemical-production fluid, chemical-material compatibilities.
Flow Assurance Remediation Strategy
Flow assurance remediation strategy can be designed into the system early on, for example, a mechanism to deliver solvents into the well or flowline, methods for flowline depressurization.
If deposits/blockages do occur, depending on the types of solids,
•chemical solvents can be used to dissolve or loosen the deposits
•temperature can be raised to melt the solids if they are wax or hydrate, through either local external heating or hot oiling
•depressurization to dissociate hydrates
•mechanical intervention and scrapping
Flow Assurance:
Flow assurance analysis is performed after determination of the preliminary routing, but before material selection and mechanical and thermal design.The flow assurance analysis:
•Identifies pipe sizes and thermal insulating requirements to meet operational needs.
•Specifies a min. level of operating conditions.
•Specifies the chemical injection requirements such as corrosion inhibitors and Hydrate inhibiation etc.
Steady state analysis consists of the following steps:
•Initially the required data is reviewed, any missing data is identified or appropriate assumptions are made and confirmed prior to the start of the analysis.
•Preliminary system operating conditions are established.
•The fluid for both steady state and transient analysis is characterized and steady state modeling is performed using industry accepted software.
•Required preliminary pipe sizes are determined from the models based on the required throughput, and arrival pressure and temperature conditions.
•Thermal insulation requirements are evaluated based on the wax appearance temperature.
•After preliminary hydraulic simulations, a flow assurance network model is developed to study different pipeline options.
The final results of the steady state analysis are:
•Optimized pipe sizes.
•The insulation requirements on all components of the proposed system.
•Pressure and Temperature profiles versus flow rates.
•Velocities along the pipeline route.
•Flow regime, slug lengths and volumes as in Two Phase Flow.
Steady State Analysis:
Transient Analysis:
Transient analysis is used to assess system response and limitations for the following operations:
•Surge analysis relevant to opening/closing of ON/OFF Valves, pumps start-up (one pump first, then the second and so on).
•Initial production start-up.
•Restart from shut-down (warm up).
•Planned and unplanned shutdown (cool down).
•Flow rate variations (ramp up and turndown).
•Depressurization (blow-down).
OLGA / PIPESIM /TGNET/TLNET are some of the widely accepted software used for Flow Assurance - Steady state and Transient analysis of pipelines.
The following table outline major parameter to be assessed while performing flow assurance.f
Flow Assurance:
Flow assurance analysis is performed after determination of the preliminary routing, but before material selection and mechanical and thermal design.The flow assurance analysis:
•Identifies pipe sizes and thermal insulating requirements to meet operational needs.
•Specifies a min. level of operating conditions.
•Specifies the chemical injection requirements such as corrosion inhibitors and Hydrate inhibiation etc.
Steady State Analysis:
Steady state analysis consists of the following steps:
•Initially the required data is reviewed, any missing data is identified or appropriate assumptions are made and confirmed prior to the start of the analysis.
•Preliminary system operating conditions are established.
•The fluid for both steady state and transient analysis is characterized and steady state modeling is performed using industry accepted software.
•Required preliminary pipe sizes are determined from the models based on the required throughput, and arrival pressure and temperature conditions.
•Thermal insulation requirements are evaluated based on the wax appearance temperature.
•After preliminary hydraulic simulations, a flow assurance network model is developed to study different pipeline options.
The final results of the steady state analysis are:
•Optimized pipe sizes.
•The insulation requirements on all components of the proposed system.
•Pressure and Temperature profiles versus flow rates.
•Velocities along the pipeline route.
•Flow regime, slug lengths and volumes as in Two Phase Flow.
Transient Analysis:
Transient analysis is used to assess system response and limitations for the following operations:
•Surge analysis relevant to opening/closing of ON/OFF Valves, pumps start-up (one pump first, then the second and so on).
•Initial production start-up.
•Restart from shut-down (warm up).
•Planned and unplanned shutdown (cool down).
•Flow rate variations (ramp up and turndown).
•Depressurization (blow-down).
OLGA / PIPESIM /TGNET/TLNET are some of the widely accepted software used for Flow Assurance - Steady state and Transient analysis of pipelines.
Outline
1. Introduction to flow control
2. Multi-phase flow with emphasis on slug flow
3. Stabilization of flow in Oil/Gas wells and pipelines
4. Examples of flow control for selected oil and gas fields
5. Conclusions
Trends and Facts in Oil and Gas Production
• Few new ‘giant’ oil and gas fields are likely to be discovered
• More than a quarter of the world’s oil and more than 15%
of its natural gas lies offshore
of its natural gas lies offshore
• Most of the new discoveries are expected to occur offshore
• New large fields are probable in deep waters
• Develop new and cost effective solutions for small fields
• Multiphase transport directly to shore
• Tie-in of well stream from sub sea installation to platform
Flow Control
The ability to actively or passively manipulate a flow field in order to effect a beneficial change.
(Gad-el-Hak, 1989)
Flow assurance
The ability to produce hydrocarbon fluids economically from the reservoir to export over the life of a field in any environment.
(Forsdyke 1997)
Challenges:
Hydrates
Wax/paraffin deposition Fluid control
Scale
Emulsions
Slugging Flow control
Sand
Flow control: emulsion viscosity
Oil-water mixtures:
Increase in viscosity close
to inversion point
Sand Control
•Sand will follow the oil and gas from the reservoir
•Sand can deposit in the pipeline and process equipment
•Oscillating pressure and well production will increase sand production
Outline
1. Introduction to flow control
2. Multi-phase flow with emphasis on slug flow
3. Stabilization of flow in Oil/Gas wells and pipelines
4. Examples of flow control for selected oil and gas fields
5. Conclusions
Multiphase Transport
•Flow with one or several components in more than one phase
–Gas-liquid flows
–Gas-solid flows
–Liquid-solid flows
–Three-phase flows (e.g. gas-oil-water)
•Simulation tools
–Industry standard: OLGA (two fluid model)
–PETRA objectoriented implementation in C++
Flow Control in Oil/Gas Wells and Pipelines
Horizontal Two-Phase Flow
•Segregated flow
–Stratified
–Annular
–Wavy
•Intermittent
–Slug flow
–Plug flow
•Distributive flow
–Bubble/mist flow
–Froth flow
Example – horizontal slug flow
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Inclined flow
•Waves!
Horizontal Flow Map
•Flow pattern map for horizontal flow
•Often specified in terms of superficial velocity of the phases
Vertical flow
•Bubble flow
–Continuous liquid phase with dispersed bubbles of gas
•Slug flow
–Large gas bubbles
–Slugs of liquid (with small bubbles) inbetween
•Churn flow
–Bubbles start to coalesce
–Up and down motion of liquid
•Annular flow
–Gas becomes the continuous phase
–Droplets in the gas phase
•Partly dependent on upstream geometry
Vertical Flow Map
Slug Flow
-
A fascinating but unwanted and damaging flow pattern
-
A fascinating but unwanted and damaging flow pattern
Consequences of Slugging
•Variations in flowrate to stage separator
–Shutdowns, bad separation, level variations
–Pressure pulses, vibrations and tearing onequipment
–Flow rate measurement problems
•Variations in gasflow
–Pressure variations
–Liquid entrainment in gas outlet
–Flaring
–Flow rate measurement problems
Slug Flow Classification
•”Normal” steady slugs – Hydrodynamic slugging
–Unaffected by compressibility
–Incompressible gas (high pressure) or high liquid rate
–Normally not an operational problem
–Short period
•Slugs generated by compressibility effects
–Severe slugging in a riser system (riser induced)
–Hilly terrain slugs (terrain induced)
–Other transient compressible effects
–Long period
•Transient slugs
–Generated while changing inlet rate
•Reservoir induced slug flow
Special considerations
Pressure support consideration
It is necessary for sufficient pressure to be available to transport the hydrocarbons at the required flow rates from the reservoir to the processing unit. Matters that require consideration in this regard include:
•Pressure loss in flowlines
•Separator pressure setpoint
•Pressure loss in wells
•Remote multiphase boosting
•Drag reduction
•Slugging in horizontal wells
•Interaction with reservoir performance
Component and system design consideration
Components and systems should be designed and operated to ensure that flowrate targets are achieved and that flow is continuous. Issues to be taken into account include:
•Sand and solids transport
•Erosion
•Interaction of slugging and pipe fittings
•Interaction of slugging and risers
•Relief and blow-down
•Pigging
•Liquid inventory management
•Well shut-in pressure
Multiphase flow considerations
For multiphase flowlines, it is necessary for the process to be able to handle the fluid delivery, and consideration should be given to a number of issues including
•Interaction with facilities performance
•Slugging (steady state)
•Slugging (transient)
•Slug-catcher design
•Severe slugging prevention
•Effect of flow rate change
•Temperature loss prediction
•Piping layout
•Remote multiphase metering
•Gas and dense phase export
•Oil and condensate export
•Separator performance
Technology development
The need for well testing and overall production system optimization contributes to flow assurance issues. Significant advances have been made in this field. Flow assurance will continue to remain critical technology as deepwater developments progress and as longer tiebacks from subsea wellhead systems are considered.
Pipeline pigging
Pipeline pigs are devices that are placed inside the pipe and traverse the pipeline.
Hydrostatic testing
Pigs are used during hydrostatic testing operations to allow the pipeline to be filled with water, or other test medium, without entrapping air. The pig is inserted ahead of the fill point, and water is pumped behind the pig to keep the pipe full of water and force air out ahead of the pig. Pigs are then used to remove the test waters and to dry the pipeline.
Pipeline cleanup
Operations may conduct pigging on a regular basis to clean solids, scale, wax buildup (paraffin), and other debris from the pipe wall to keep the pipeline flow efficiency high. In addition to general cleaning, natural-gas pipelines use pigs to manage liquid accumulation and keep the pipe free of liquids. Water and natural-gas liquids can condense out of the gas stream as it cools and contacts the pipe wall and pocket in low places, which affects flow efficiency and can lead to enhanced corrosion.
Batch transportation
Pigs are used in product pipelines to physically separate, or “batch,” the variety of hydrocarbons that are transported through the line. Product pipelines may simultaneously transport gasoline, diesel fuel, fuel oils, and other products, which are kept separated by batching pigs.
Prevention of solid accumulation and corrosion
Crude-oil pipelines are sometimes pigged to keep water and solids from accumulating in low spots and creating corrosion cells. This can be especially necessary when flow velocities are less than 3 ft/sec. Multiphase pipelines may have to be pigged frequently to limit liquid holdup and minimize the slug volumes of liquid which can be generated by the system.
Coating
Pigs may be used to apply internal pipe coatings, such as epoxy coating materials, in operating pipelines. Pigs may also be used with corrosion inhibitors to distribute and coat the entire internal wetted perimeter.
Inspection
Pigs are being used more frequently as inspection tools. Gauging or sizing pigs are typically run following the completion of new construction or line repair to determine if there are any internal obstructions, bends, or buckles in the pipe. Pigs can also be equipped with cameras to allow viewing of the pipe internals. Electronic intelligent, or smart, “pigs” that use magnetic and ultrasonic systems have been developed and refined that locate and measure internal and external corrosion pitting, dents, buckles, and any other anomalies in the pipe wall.
Intelligent pigs
The accuracy of location and measurement of anomalies by the intelligent pigs has continued to improve. Initially, the electronics and power systems were so large that intelligent pigs could be used only in lines 30 in. and greater in size. The continued sophistication and miniaturization of the electronic systems used in the intelligent pigs has allowed the development of smaller pigs that can be used in small-diameter pipelines. Newly enacted DOT pipeline-integrity regulations and rules acknowledge the effectiveness of the intelligent pigs and incorporate their use in the pipeline-integrity testing process.
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