Flow Assurance Training Course-1 Underlined(iogpt)

IOGPT Flow Assurance Training

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TRAINING MANUAL ON FLOW ASSURANCE COURSE DESIGN BY :

AJIT KUMAR, GGM(P) C P SINGHAL, GM(P) RAJAN JAIRAM, DGM(P) A K VARMA, DGM(P) S K VIJ, CE(P) RAJEEV BANSAL, SE(P) – CO-ORDINATOR B RAVISHANKAR, SE(P) NANDINI PANDEY,AEE(P) OMPRAKASH PAL, DGM(CHEMISTRY),HEAD TRG VIPUL GARG, CHIEF CHEMIST, I/C TRG

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CONTENTS • • • • • • • • • • •

Introduction Flow assurance issues and standard terminology Fluid properties & Phase determination Fluid flow analysis for single phase & multiphase Surge Analysis Slug prediction & management Hydrate Formation & Prevention Wax formation & Prevention Asphaltene Prediction & remediation Pigging operation Start up & Shut down

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CHAPTER -1 : INTRODUCTION “Flow assurance is the ability to maintain the flow of oil & gas from reservoir to processing facilities (and beyond to sales point) throughout the field life with minimum life cycle costs” Institute of Oil and Gas Production Technology (IOGPT) envisages to develop flow assurance skills of ONGC personnel. The objective of this course is to transfer and exchange knowledge in flow assurance and operability issues encountered during FDP studies for Onshore ans offshore fields including deepwater and ultradeepwater fields. The purpose of this document is to provide an in-depth review of flow assurance and operability issues and how they relate to system design and day to day operation.

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CHAPTER -2 : FLOW ASSURANCE ISSUES AND STANDARD TERMS The following section summarizes a list of flow assurance basic terminology, commonly used within the industry. Active Heating: Term used to describe an actively insulated system, where energy is added in the form of electricity or heat, in order to maintain the thermal energy of the production fluid. Anti-agglomerate (AA): A substance that is used to prevent hydrate crystals from agglomerating to form a blockage. AA’s are a subset of a group of low dosage hydrate inhibitors (LDHIs), which are a relatively new technology designed to treat production fluids. AA’s typically allow small hydrate particles to form, but prevent their accumulation/blockage of the pipeline. AA’s require a hydrocarbon liquid phase to work and are not particularly suitable for low condensate gas systems. Artificial Lift: Means of increasing production rates and/or decreasing line sizes. Artificial lift provides additional ways to decrease the pressure requirements on a system. Gas Lift – Physically injecting gas either downhole (in the wellbore) or at the base of the riser. Gas lift at the base of the riser is typically only possible for vertical riser towers, and not catenary risers, due to fatigue concerns near the touchdown point. Gas lift may decrease arrival temperatures due to the Joule-Thomson cooling of the additional gas added. Multiphase Pumping – Physical apparatus that allows pumping of a multiphase fluid. From a flow assurance perspective, multiphase pumping offers significant benefits by increasing production rates without additional Joule-Thomson cooling (gas lift) or removing the water (subsea separation). Subsea Separation – Physical apparatus that separates gas, hydrocarbon liquid, and water at the seafloor. The gas is typically sent up an un-insulated flowline, while the liquid is sent up another flowline. Water may be re-injected in disposal wells. This enables two smaller, single-phase flowlines than a large, multiphase flowline. However, by removing the water, the hydrocarbon liquid often arrives at a lower temperature. Further, if water is not separated from the gas/water in sufficient quantities to eliminate a hydrate formation risk, hydrates will still pose a problem. Asphaltenes: Asphaltenes are defined by the ASTM D-3279-90 (IP143/90) test as a solid that precipitates when an excess of n-heptane or n-pentane is added to a crude oil. Chemically, asphaltenes are high molecular weight, polynuclear aromatic, polar compounds containing carbon, hydrogen, oxygen, nitrogen, sulphur and some heavy metals such as vanadium and nickel. The diagram gives a representation of an asphaltene molecule; however, asphaltenes do not have a single, unique structure or molecular weight. •

Asphaltenes are dark brown to black solids.

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Unlike waxes, asphaltenes do NOT melt. Consequently, thermal methods such as insulation, hot oiling, etc. do not work to prevent or remediate asphaltene deposition.

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Asphaltenes are believed to be solids suspended by resins as micelles in the crude oil.

The asphaltene flocculation point is the pressure at which asphaltenes first begin to precipitate given a fixed temperature. Typically the "live" sample is reconditioned to reservoir conditions and the sample is slowly depressurized while observing for asphaltene flocculation. The test method may use one of a number of techniques for detecting the asphaltene flocculation including visual observation, light scattering, filter plugging, etc. If a number of these measurements are made over a range of temperatures, then an asphaltene flocculation phase envelope can be generated as shown below.

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The first pass test is to plot the reservoir pressure minus the bubble point against the in-situ density on a de Boer plot. The de Boer plot was published by Shell and is based upon a number of crude oil samples that have been studied. The de Boer Plot simply identifies regions where asphaltenes are likely to pose a problem. Client - Project de Boer Plot - Asphaltene Prediction 11000

Fluid

Reservoir pressure - Saturation pressure (psia)

10000

Severe Problem

Slight Problem

9000 8000 7000 6000 5000 4000 No Problem

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In-situ crude density (kg/m³)

BML: Below Mud Line. Distance given for reservoir/wellbore depths, measured as the distance below the mudline. This is the distance from the bottom of the sea floor below the earth. BOPD: Barrels of oil per day. BWPD: Barrels of water per day. Bare Pipe: Un-insulated pipe that is common of gas/condensate systems. Typical U-values for bare pipe may be 30 BTU/hr-ft2-°F, depending on the burial depth and sea current velocity. Bathymetry: Seafloor topography that defines any dips and undulations along the flowline route. Bathymetry profiles are used to map out the route and may induce terrain slugging.

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Bottom Hole: Traditional term used to refer to the point at which the fluid enters the production wellbore. This is typically the lowest point modeled in Pipesim/OLGA simulations. The bottom hole is located above the reservoir and typically operates at a lower pressure. The difference between the pressure at the reservoir and the bottom hole defines the inflow performance of the reservoir. Bubble Point: Pressure at which the first bubble of gas appears. For black oil systems, this is the lowest pressure at which the fluid will still be right near the edge of the single-phase region on the phase envelope (single phase liquid). The bubble point is typically a critical parameter used to tune reservoir fluid compositions to measured data. Typically, the bubble point measurements are accurate to within a few psi and the tuning parameters should be set accordingly. Bundles: A number of bundled flowline configurations have been or are currently being installed. There are two main types of bundles, passive and actively heated bundles. Both kinds bundle the flowlines, test lines, methanol lines and umbilicals together inside of a larger carrier pipe. Many different bundle configurations have been proposed. The most common is a simple pipe-in-pipe arrangement. Except for the simple pipe-in-pipe, these bundles require very specialized modeling to accurately simulate the heat transfer in the system, particularly for transient operations such as start-up and shutdown. Unsymmetrical geometries are especially difficult to model. Bundles are most commonly used for hydrate prevention and in the process also prevent or reduce wax formation. They may be used for wax prevention but most likely, only in cases where pigging is not possible. Actively Heated Bundles – Include hot water circulation or electrical heating cables (example diagrams) to maintain operating temperatures above hydrate and/or wax formation temperatures during both steady state and transient operations. These are typically more expensive to build and difficult to operate. The advantages are that methanol/glycol are not required except to protect wellheads and manifolds and the system is protected even during shutdown and start-up. Passive Bundles – Provide a much lower overall heat transfer coefficients than can be obtained with single insulated lines primarily because good insulating materials would be crushed if exposed directly to the hydrostatic pressures in deepwater. For many production systems the passive bundles will allow the operating temperatures to be maintained above the hydrate and/or wax formation temperatures under a range of steady state operating conditions. The passive bundles will also provide a much longer cooldown period during shut-in. However, under startup and long shut-in conditions, methanol or glycol will be required until the system is above the hydrate formation temperature.

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When do you need a bundle? • Perform steady state simulations to determine the pressure/temperature profile of the system assuming perfect insulation (i.e., no heat loss to the surroundings). There will still be some temperature drop due to the Joule-Thomson expansion and potential energy changes. •

If the resulting arrival temperature is below the hydrate and/or wax formation temperature then you will need to consider an actively heated bundle to add energy to the system. No amount of insulation alone will keep the system above the hydrate formation temperature.

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If the system can stay above the hydrate formation temperature with perfect insulation, then determine the actual overall heat transfer coefficient required to stay above the hydrate formation temperature plus some conservatism. One should consider the accuracy of the predictions, projected versus actual flow rates and reliability of fluid samples.

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Identify the most technically feasible and cost effective method to achieve the required heat transfer coefficient. If the required heat transfer coefficient is beyond the range of standard insulation applicable for the producing environment then consider a passive bundle to allow the use of materials with higher insulating values.

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When choosing a bundle, keep symmetry in mind, as it will be much easier to model. Find a company with the capability to perform transient modeling on bundles.

C-Factor: The C-Factor is a measure of erosion tendency for a given system, based on the API RP 14E standard. The equation below contains the formula for calculating the C-Factor in multiphase flow: C − Factor = (3.2808 ⋅ ((BE ⋅ VL ) + (G A ⋅ V D ) + ((1 − HOL) ⋅ VG ))) ⋅ 0.0624 ⋅ ((HOL ⋅ ρ L ) + ((1 − HOL) ⋅ ρ G ))

BE: Liquid Film Volume Fraction GA: Liquid Droplet Volume Fraction HOL: Total Liquid Holdup (BE + GA)

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VL: Average Liquid Film Velocity (m/s) VD: Average Liquid Droplet Velocity (m/s) VG: Average Gas Velocity (m/s)

ρL: Liquid Density (kg/m³) ρG: Gas Density (kg/m³) Essentially, the C-Factor equation given above takes an average density and an average velocity for all phases present. Typical C-Factor limits are 150 for carbon steel and 200 for corrosion-resistant alloy. Flexible pipes have been known to exceed 250-300+. The guidelines provided above are to be used unless otherwise specified by the operator. CGR (Condensate/Gas Ratio): For gas/condensate systems, CGR is the ratio of condensate to gas, typically measured at stock tank conditions. The CGR is typically reported in units of bbl/mmscf and are on the order of 0-50. The CGR is highly dependant on the conditions that it is reported at. You should always determine whether the CGR is reported at stock tank conditions or at pipeline conditions. Casing: One of the many physical barriers used in wellbores to set the production tubing. Casings are typically 9-5/8”, 12-1/4”, 13-5/8”, etc. The casing profile is provided with the wellbore and helps determine the overall heat transfer coefficient (U-value). Within OLGA, the entire casing program is built into the simulation and defined in the radial direction from the production tubing.

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Catenary: Geometric shape for riser trajectory that is typical for steel pipes, as well as flexible pipes. The key dimension required for catenary riser shape definition is the ‘touchdown point”, or the point closest to the topsides facility where the riser is still touching the seafloor.

Typical Catenary Profile 600 TOPSIDES

550 500

Vertical Distance (m)

450 400 350 300 250 200 150 100 50

TOUCHDOWN POINT

0 0

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Lazy-S – Modified catenary riser profile where the riser is anchored in the mid-point by a buoy, creating a wave in the riser, or a “Lazy-S” shape. This type of riser is particularly prone to slugging.

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Choke: Any valve that is used to control the flowrate, such as a “subsea choke” or a “topsides choke”. The terminology may also be used to describe the action of controlling the flowrate. Cloud Point (a.k.a. Wax Appearance Temperature, WAT): The cloud point or Wax Appearance Temperature (WAT) is the temperature at which the first waxes crystallize from the crude oil. As soon as the pipe wall temperature drops below the cloud point, wax can deposit on pipe walls even though the bulk fluid temperature is still higher than the cloud point. The cloud point is probably the single most important piece of information for evaluating the waxing potential for a new project. For Gulf of Mexico fluids, the WAT is typically near 100°F. If measured correctly, it can be used along with production profiles and thermal modeling of the production scenarios to determine when and where waxes may cause operational problems.

The WAT is directly proportional to the pressure. Cloud points are pressure dependant, and are typically reported for the dead oil only. For live oils, where the pressure may be much higher, the WAT can be significantly higher; the cloud point increases as the pressure decreases below the bubble point. Coiled Tubing: Device used for hydrate remediation, where a long-reaching wire is inserted down a flowline towards the hydrate blockage. Completion Fluid: Fluid placed within the innermost annulus in the wellbore. Typically, the completion fluid is a brine solution that is defined by weight (salt content). Compositional Models: Approach used to characterize a reservoir fluid for flow assurance analysis. Typically, these are broken down into two primary categories: “black oil model” and “compositional model” Black Oil Model – Simplifies composition into a “gas phase” and “liquid phase” and is most applicable to predominantly oil systems. This approach does a fair job of predicting steady state hydraulics, but the compositional effects on wax/hydrates will not be captured. This is an empirical approach to evaluating the phase splits and transport property generation. Compositional Model – More rigorous fluid characterization approach, whereby the entire composition is used as input to generate the physical/transport properties of the fluid. This is required to better predict the interfacial relationships between the gas/liquid phases, particularly

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in gas/condensate systems, where the liquid holdup is critical. The accuracy of the compositional model is highly dependant on the accuracy of the PVT data (i.e. contamination levels, etc.) Conversion Factors: Gas – Conversion factor that converts MMSCFD to kg/s. The gas conversion factor is typically on the order of 0.25 kg/s/MMSCFD. The conversion factor is strictly a function of the molecular weight of the fluid, and is highly dependant on the conditions (phase, pressure) at which the molecular weight is taken. Liquid – Conversion factor that converts BPD to kg/s. The liquid conversion factor is typically on the order of 1.80-2.20 kg/s/1000 BPD. The conversion factor is a function of the conditions (molecular weight, density, phase fractions) at stock tank conditions. Cooldown Time: The time, following initiation of a shutdown, for the system to cool from normal operating temperatures to hydrate formation temperature at shut-in pressure. Dead Fluid (Dead Oil): Oil that contains no dissolved gas, hydrocarbon fluid that has generally been flashed to stock tank conditions and does not present a hydrate formation issue. Typically, dead oils have been de-gassed and de-watered, containing only the hydrocarbon liquid. Depressurization (Blowdown): Transient operation where the system is reduced to a lower pressure (~30 psi for flare systems) following a shutdown in an effort to get the pressure below hydrate formation conditions. For deepwater developments, depressurization often does not reduce the pressure low enough to keep the system out of the hydrate formation region. Key parameters to be evaluated during depressurization analysis are the minimum flowline pressure, minimum topsides temperature, and outlet gas/liquid flowrates. Dew Point: Pressure at which the first droplet of liquid appears. For gas/condensate systems, this is the lowest pressure at which the fluid will still be right near the edge of the single-phase region on the phase envelope (single phase gas). The dew point is typically a critical parameter used to tune reservoir fluid compositions to measured data. Typically, the dew point measurements are accurate to within a few psi and the tuning parameters should be set accordingly. Displacement (Crude Oil Displacement): Transient operation where de-gassed/de-watered crude oil is circulated throughout the flowline. To utilize displacement, a looped flowline configuration must be in place. This is done in an attempt to preserve the flowline from hydrate formation by replacing the resident fluid with non-hydrate formation fluids. Crude oil displacement must be accomplished prior to reaching the cooldown time. Displacement operations must consider the available crude storage, the time to displace the flowlines, and the pump discharge pressures on the crude oil pumps. Typical displacement rates are 1 m/sec and may be increased slightly if time is of the essence. Downhole: Term used to describe the area below the mudline where chemicals may be injected, typically near the bottom of the wellbore. For example, downhole chemical injection assumes that the chemicals will be delivered near the perforations/bottom hole. Drill Center: Concentrated area where multiple wells may be drilled. A drill center may contain a cluster of wells and potentially multiple manifolds. Each drill center may have unique flow assurance challenges, depending on seafloor bathymetry, flowrate, and tieback length. Emergency Shutdown (ESD): Unplanned shutdown of all operations, possibly triggered by a fire on the host facilities or some other catastrophic event. In the event of an ESD, the production fluids will remain in the flowline and are subject to hydrate formation. ESDs present the most severe operating conditions that must be addressed in the design stages of the flow assurance work. Emulsions: Emulsions are two immiscible fluids, with one of the liquids dispersed in the second liquid. Under normal conditions, the two liquids would naturally settle-out and separate into layers. If an emulsion is formed, the liquids become quite difficult to separate, impacting the transport properties of

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the fluid. Emulsions tend to have high viscosities, which can be an order of magnitude higher than either of the two liquids that comprise the emulsion. FBE: Fusion Bonded Epoxy – Coating material, typically applied to the outside of pipes for protection. FBE is applied in thin layers, particularly to bare pipes, and does generally not provide any significant insulating benefits. FBHP: Flowline Bottom Hole Pressure FBHT: Flowline Bottom Hole Temperature FSO (FPSO): Floating (Production,) Storage and Offloading vessel

FWHP: Flowing Wellhead Pressure FWHT: Flowing Wellhead Temperature Finite Element Modeling (FEM): Specialized computational fluid dynamics that involves thermal and hydraulic analysis of complex geometries. Often, FEM is required for hybrid riser towers to ensure the overall heat transfer coefficient (U-value), for heating medium hydraulics within production bundles, and for thermal analysis of subsea equipment such as manifolds, trees, and jumpers. Flash Calculation: Calculation used to determine thermodynamic and transport properties at a given set of conditions. “Flashing” a fluid to a given set of conditions essentially means instantaneously exposing the fluid to those conditions. Flexible Pipe: Pipe that is constructed of several ancillary layers and is typically used for catenary risers and short subsea tiebacks. Roughness values for flexible pipe are considerably higher than steel pipe. Uvalues are on the order of 1.00-1.50 BTU/hr-ft2-°F. Typically, flexible pipes may not be used in highpressure services. Flow Regime: Type of flow that is defined by fluid properties, velocities, etc.

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Annular (Mist) – Flow regime where gas velocity exceeds that for stratified flow and the liquid forms a complete annular ring around the surface of the pipe. Some liquid is entrained as a mist in the gas core.

Bubble (Dispersed) – Flow regime where the gas velocity is very high and the flow-induced turbulence causes the liquid and gas to become well mixed. The gas phase is distributed more or less uniformly in the form of discrete bubbles in a continuous liquid phase.

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Slug – Flow regime that occurs at low gas velocities. The fluids are ordered as alternate slugs of liquid and bubbles of vapor. This flow regime is highly undesirable, and will be discussed in more detail in a later section.

Stratified – Flow regime characterizes by low gas and liquid velocities where the phases segregate with the liquid flowing along the bottom, and the gas flowing through the upper part of the pipe. The interface between the phases is relatively smooth.

Flowline: Portion of the pipeline that spans from the mudline at the tree/manifold through to the riser. Gas/Condensate: Traditional terminology used for a predominantly gas system. Gas/condensates are traditionally found in the North Sea, as well as the Middle East. Gas/condensate systems are typically produced via un-insulated flowlines and continuous hydrate inhibition is used for cold ambient conditions. Primary areas of concern among gas/condensate systems involve liquids handling during transient conditions such as turndown and ramp-up. Gas Injection: Process of injecting gas in disposal wells, typically for reservoir pressure maintenance or for lack of processing facilities on the host facilities. Gas injection may result in changes in the fluid GOR over time, depending on the proximity of the gas injection wells. Gel Strength: The yield stress (gel strength) is the force required to break down the wax structure developed below the pour point, and it determines the pumping pressure required to restart flow in a line. As with pour points, the effects of sample history, the temperature of the fluids before shutdown, the cooling rates, the time of the shutdown and the final fluid temperature can all be significant. These parameters all influence the amount of precipitated wax, the gel structure, gel strength and consequently the pressure required to break it. In pipelines, when a shutdown occurs, the precise effects will differ for

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crudes in various parts of the line. Following a shutdown, crude will cool from a different temperature and at a different rate, depending upon its position in the pipeline. Yield stress is usually measured using model pipelines or controlled strain rheometers. Laboratory data can be scaled up to full size pipelines using the equation below: Restart pressure (Pa) = (4 x length (m) x yield stress (Pa))/diameter (m) Gelled Fluids: Either a water-based or oil-based fluid that is used especially in dry tree riser annuli for thermal insulation. Gelled fluids may be subject to thermal breakdown where the fluid starts convecting, significantly degrading the overall thermal performance. Typically, water-based gelled fluids have a greater overall thermal mass (+), but a higher thermal conductivity (-); oil-based gelled fluids have a lower overall thermal mass (-), but a lower thermal conductivity (+). Geothermal Gradient: Temperature gradient of the ambient soil below the mudline. Typically, a linear geothermal gradient is assumed between the reservoir temperature and the seabed temperature. GOR (Gas/Oil Ratio): For black oil systems, GOR is the ratio of the gas to oil, typically measured at stock tank conditions. The GOR is obtained by flashing the fluid from reservoir (or other, high-pressure) conditions down to stock tank conditions. The GOR is typically reported in units of scf/stb and are on the order of 500-5000. Over time, the GLR is likely to stay constant or increase due to a decline in oil production. The GOR is path-dependant, meaning that a single-stage flash will provide a different GOR than a multi-stage flash to the same final conditions. You should always determine whether the GOR is reported for a single-stage or multi-stage flash. GLR (Gas/Liquid Ratio): For black oil systems, GLR is the ratio of the gas to liquid, typically measured at stock tank conditions. Similar to the GOR, the GLR includes the oil and the water. Over time, as the water cut increases, the GLR is likely to stay constant or even decrease. GUTS (Grand Unified Thermodynamic Simulator): MSi’s proprietary phase equilibria package. Developed as part of a joint industry project with BP, Conoco, Arco, etc., GUTS provides various phase equilibria calculations, as well as detailed wax, hydrate, and asphaltene predictions. The wax module was developed in conjunction with the University of Tulsa, and the hydrate module was developed in conjunction with the Colorado School of Mines hydrate module. HP/HT System (High Pressure/High Temperature): System where the reservoir fluid is at high pressure (10,000+ psi) and high temperature (250+ °F). HP/HT systems often have Joule-Thomson Heating across the wellbore perforations/subsea choke. Additionally, HP/HT systems have the unique challenge of arriving too hot for the topsides processing facilities, so temperature loss during steady state operation is preferred, while maintaining temperature under transient conditions such as cooldown. Hydrate: Natural gas hydrates (or clatharites) are crystalline compounds formed by water with natural gases and associated liquids. The hydrates are solid ice-like crystals composed of cages of water molecules surrounding ‘guest’ hydrocarbon gas molecules such as methane, ethane, propane, etc. Like pure ice, hydrates can block any type of flowline, production tubing, and pipeline. However, unlike ice, hydrates can form at much higher temperatures than 32ºF. Gas hydrates of interest to the petroleum industry are composed of water and the following eight molecules: methane, ethane, propane, isobutane, normal butane, nitrogen, carbon dioxide and hydrogen sulfide.

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Hydrates can form in gas, gas-condensate and black oil systems.

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One cubic foot of hydrates can contain 180 standard cubic feet of gas.

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Hydrate blockages can occur very rapidly. Transient operations such as start-up, shutdown, and blowdown are very susceptible to hydrate blockages because this is when the production system is likely to drop into the hydrate formation region.

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Hydrate formation temperatures are very dependent upon the gas composition. Richer gases (those with higher propane and butane concentrations) will tend to form hydrates at higher temperatures and lower pressures.

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Hydrate formation temperatures are inhibited by brine concentrations.

Hydrate Curves: Temperature/pressure relationships at which hydrates will or will not form. Hydrate formation is exacerbated at high pressure and low temperatures. When presented with a hydrate formation curve, any area to the left of the curve falls within the hydrate formation region, while any area to the right of the curve falls outside of the hydrate formation region.

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Hydrate Dissociation: The process by which hydrates may be remediated through natural dissociation. By reducing the pressure below the hydrate formation pressure at ambient temperature, the hydrate will be in equilibrium with the hydrate formation conditions. Hydrate Formation Conditions 300 280 260 240

AMBIENT TEMPERATURE

220

Pressure (psia)

200 180 160 140 120 100 80 60 40 HYDRATE EQUILIBRIUM TEMPERATURE

20 0 -30

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-10

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Temperature (°F)

In doing so, the ambient seabed temperature will be warmer than the hydrate equilibrium temperature so heat will be added to the system. The rate of heat transfer is highly dependant on the U-value of the flowline, as well as the temperature gradient. Hydrate dissociation may be a very time-consuming process, taking on the order of weeks, or longer. Hydrate Inhibitors: Chemicals that inhibit hydrate formation by permanently reducing the temperature at which hydrates will form by changing the thermodynamics. This is the same as adding anti-freeze to water to lower the freezing point. Conventional hydrate inhibitors are methanol and glycols. The hydrate inhibition rates will determine how fast a system may be restarted, as well as the “Light-Touch” time required to treat multiple wells during a shutdown. Hydrate inhibition rates must take into account loses to the vapor phase. Typical hydrate inhibitor rates for methanol are 0.5 BBL MeOH/BBL H2O.

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Hydrate Propensity: Measure of the likelihood for hydrates to form. The difference between the actual temperature and the hydrate formation temperature at operating pressure is calculated. If the actual temperature is above the hydrate formation temperature, then the hydrate propensity is above zero and hydrate formation will not occur. If the actual temperature is below the hydrate formation temperature, then hydrate formation may occur and the amount of sub-cooling is the hydrate propensity. Joule-Thomson Effect: Isenthalpic expansion of a fluid. The result of a Joule-Thomson expansion (JTexpansion) is either an increase or decrease in temperature. The nature of the temperature change is strictly defined by the enthalpy behavior of the fluid over a range of operating conditions. •

A loss in temperature is referred to as “Joule-Thomson Cooling” and often occurs at low pressures (< 6000 psia). The lower the pressure, the more pronounced the impact of the JouleThomson effect. This often occurs as the fluid travels up the riser and loses pressure, or as the fluid is let down to separator pressure across the topsides valve.

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A gain in temperature is referred to as “Joule-Thomson Heating” and often occurs at high pressures (6000+ psia). For deepwater developments, or HP/HT systems, any pressure drop taken across the wellbore perforations or across the subsea choke may result in a slight increase in temperature.

Jumper: Pipe work that links either the tree to the manifold or from the manifold to the flowline. The jumper is often insulated to a much lesser degree than the flowline and may be subject to more stringent hydrate formation criteria. Kick-off Point (KOP): Point below mudline in the wellbore where the well deviates from a strictly vertical trajectory and starts to extend outwards in a sidetrack direction. Kinetic Hydrate Inhibitors: Hydrate inhibitor that does not thermodynamically lower the hydrate formation temperature. What they do is prevent crystals from forming (i.e., they prevent nucleation) and thereby temporarily allow the fluids to be supercooled (cooled below the actual freezing point without crystallization). Typically a kinetic inhibitor will allow 10ºC of supercooling. Margin technology for hydrate control. Kinetic inhibitors prevent hydrate crystal nucleation and growth without emulsifying water into the hydrocarbon phase and thereby temporarily allow the fluids to be supercooled (cooled below the actual freezing point without crystallization). Prevention of nucleation prevents hydrate crystals from growing to a critical radius. Growth inhibition maintains hydrates as small crystals, inhibiting progress to larger crystals. Hydrate inhibitor that does not thermodynamically lower the hydrate formation temperature. Typically the measure of the effectiveness of the kinetic inhibitor is the degree of subcooling a system can operate without forming hydrates. Subcooling (∆T) is the measure of the lowest temperature that the system can be operated relative to the hydrate formation temperature at a given pressure. Typically a kinetic inhibitor will allow 10ºC of supercooling. Marginal technology for hydrate control. “Light-Touch” Time: The time interval, starting at the conclusion of the “No-Touch” Time, where the only actions required to prevent hydrate formation do not impact a subsequent restart. Generally, wells/trees, jumpers, and manifolds are spot treated with thermodynamic inhibitor in this time interval. The “Light-Touch” time requirements are dictated by the number of wells to treat, as well as the chemical deliverability constraints. Line Pack: Line pack is the excess gas stored in a pipeline during normal operation due to operating pressures beyond the minimum required. This is typically done by closing the topsides outlet valve and allowing the reservoir to continue to produce. The pressure will rise in the system due to the additional mass added to the system, combined with the compressibility of the gas.

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Liquid Holdup: Measure of the amount of liquid in the flowline. Liquid holdup may be given as a volume fraction of the pipeline, with 0 equating to no liquid and 1 equating to a liquid-filled pipeline. Additionally, the liquid holdup may refer to the volumetric amount of liquid in the pipeline. For black oil systems, the liquid holdup is relatively insensitive to flowrate. However, for gas/condensate systems, the liquid holdup is a strong function of flowrate. The figure below illustrates a typical liquid holdup profile for a gas/condensate system. Live Fluid (Live Oil): Oil with dissolved gas present, hydrocarbon fluid at elevated pressure/temperature, or other typical conditions that the fluid may be exposed to while in the production system. Live fluids may be prone to hydrate formation. Liquid Holdup vs. Flow Rate 50

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Flow Rate (MMSCFD)

Low-Dosage Hydrate Inhibitor (LDHI): Hydrate inhibitor that is injected at a very low concentration, relative to traditional hydrate inhibitors such as methanol. Typical dosage levels are approximately 1/10 that of methanol, but are highly dependant on the maximum degree of subcooling below the hydrate formation region. LDHIs are often very viscous, requiring greater pump discharge pressures. Additionally, LDHIs may not be stable for extended periods of time if left resident in the chemical delivery lines. Manifold: Apparatus, located on the seafloor, which provides a gathering point for multiple wells/trees. A cluster of trees is often linked together, via well jumpers, and all production is routed to the manifold and then directed through the flowline. The manifold is often un-insulated and subject to rapid cooldown during a cooldown.

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Measured Depth (MD): Actual depth below mudline, surface, etc. The measured depth accurately represents the flowing length along which the fluid will traverse. The MD is used in combination with the TVD to accurately define the routing profile. Methanol: Hydrate inhibitor used in most black oil systems. Typical injection rates are up to 25 gpm per well. Mitigation Time: The time interval, starting at the conclusion of the “Light-Touch” Time and ending at the Cooldown Time, where actions are required to prevent hydrate formation throughout the system in a long-term shutdown. Typical example operations are depressurization and fluid displacement. Monoethylene Glycol (MEG): Hydrate inhibitor typically used in gas/condensate services. Mudline (a.k.a. Seafloor): Place where land meets the water. The wellbore is located below the mudline and the seawater is located above the mudline. “No-Touch” Time: The time, following initiation of a shutdown, where no action is required to prevent hydrate formation in a long-term shutdown. No touch times may be different for different components such as trees and flowlines. Typical “No-Touch” times range from 2-4 hours, depending on the number of wells and chemical deliverability. Operating Envelope: Range of flowrates, water cuts, and gas lift rates that can be delivered and do not undergo severe slugging, wax deposition, hydrate formation, or other detrimental operational procedures. PVT Report: Compositional analysis of the reservoir fluids, provided by sampling laboratories such as Oilphase or Corelabs. The PVT report typically contains the reservoir fluid composition, pseudocomponent properties (if any), viscosity, API gravity, GOR, and bubble point. The PVT report may be the single-most critical piece of information required for a proper flow assurance analysis. The fluid properties will significantly impact the overall thermal and hydraulic performance of a proposed design. Perforations: Point in the system where the production tubing in the wellbore “perforates” the reservoir sands. Pipe-in-Pipe: Insulation system where an inner production pipe is surrounding by an outer pipe and the annulus is filled with insulation. The insulation must be protected from the seawater (“dry insulation”), thus the reason for the outer pipe. Typically, the outer pipe must be 2 line sizes larger than the inner pipe (6” x 10”, 8” x 12”) and the U-value is 0.2 BTU/hr-ft2-°F.

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Pigging: Transient operation where a pig is inserted into the flowline and circulated for liquid control in gas/condensate systems or for wax removal in black oil systems. Key parameters to evaluate during pigging operation are the backpressure requirements to prevent gas breakout behind the pig, pump discharge pressures, and pig velocities. Pig: Small, sphere or disc apparatus that is used to sweep a flowline. Primary reasons for pigging may be (1) line cleaning (commissioning, debris cleaning), (2) line management (liquid removal, corrosion inhibitor dispersal, and wax removal), and (3) line inspection (intelligent pigging). A “scraper” type pig may be used for wax removal from the pipe walls, whereas a “foam” type pig may be used to simply clean a flowline and remove any liquids. The drive fluid, or the fluid that forces the pig around, may either be the live production fluid, oil, or gas. For pigging with gas, pig velocity control is a significant challenge.

Pig Launcher: Process equipment that launches a pig Pig Receiver: Process equipment that receives a pig Platform: Collective term given to a host facility that is anchored to the seabed, rather then tethered from a vessel such as an FPSO.

Pour Point: The pour point is defined as the lowest temperature at which the crude oil can be poured under force of gravity. When an oil is at a temperature significantly below its cloud point or Wax Appearance Temperature (WAT), wax crystals can interact to form a matrix structure. Under static conditions, the structure may eventually extend throughout the entire sample, gelling the crude oil. Once this occurs, the crude is said to be below its pour point. However, if a pipeline is shutdown and the fluids in it cool to below the pour point, a semi-solid gel will form which requires an initial yield force to be applied before the gel structure breaks and the fluid begins to flow.

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Productivity Index (PI): Measure of the reservoir performance and is defined by the flowrate achievable for a given pressure drop across the reservoir perforations. As the PI increases, the achievable flowrate increases. Typical PIs for black oil reservoirs range anywhere from 2 bbl/psi to 100 bbl/psi. RKB (Rotary Kelly Bushing): Term given to the point where most measurements are taken from. MD/TVD measurements are often reported as the distance from RKB. Typically, the RKB is located approximately 80 feet above the sea level, so this distance must be subtracted from any measurements to get the true depth subsea or below mudline. Ramp-up: Terminology used to describe the process of increasing the flowrate Reservoir: Location of the hydrocarbon reserves. Reservoir Fluid: Multi-component mixture which is to be produced from the reservoir. Typically, the reservoir fluid composition is the starting point for all flow assurance analysis. The reservoir fluid composition may be defined in a PVT report, supplied by the various testing laboratories. It is useful to categorize fluids into broad categories in order to quickly identify some of the key flow assurance concerns that are likely to occur: Dry gas: Primarily methane gas, which is typically solely gas under all temperature/pressure conditions. In general, no hydrocarbon liquids are formed from the gas (water condensation can occur). In general, gas hydrates are the typical flow assurance concern for dry gas fluids. Wet gas: Similar to dry gas, but containing heavier components. The fluid may be single-phase gas at reservoir conditions. However, a hydrocarbon liquid phase is typically present at pipeline temperature/pressures. As the pressure drops in the system, liquid condensate occurs. Hydrate formation and liquid holdup management are the primary concerns. Depending on the level of condensate, wax may be an issue. Liquid loadings are defined by the condensate/gas ratio (CGR), which typically range from 1 – 50 bbl liquid/mmscf gas Retrograde condensate: Similar to wet gas, but generally containing higher liquid loadings. At high pressures, a pressure drop tends to induce hydrocarbon liquid dropout. At low pressures, the liquid may re-dissolve into the gas phase, resulting in lower liquid loadings. The magnitude of the liquid dropout is highly dependant on the fluid phase envelope and path of production (temperature/pressure profiles). Condensates are generally low molecular weight systems, with methane concentrations still in excess of ~70 mole%. Volatile oil: A fluid that exhibits both gas/condensate behavior and black oil behavior. Volatile oils contain more heavy components than condensates, but have a low enough molecular weight to not necessarily be considered black oils. Fluid conditions at the reservoir are often near the critical point, which may induce two-phase flow from the reservoir as the pressure is decreased.

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Volatile oils may start out as single-phase oils in early-life, but can become multiphase mixtures as the reservoir pressure declines. Black oil: Common term for a predominantly liquid-filled system. Black oil is a generic term that encompasses a wide range of heaver molecular weight fluids. As the pressure drops along the pipeline, gas is released from the liquid and forms a gas phase. Black oils are typically characterized by their gas/oil ratio (GOR), which may range from <100 scf/stb for heavy oils to ~3000 scf/stb for near-volatile oils. Black oils may pose hydrate formation risks, along with wax deposition and gel formation issues. For deepwater systems, the pressure drop in the vertical riser column for black oils is a significant flow assurance challenge. Restart: Transient operation where the system is brought back on-line following a shutdown. The rate of restart is often determined by physical constraints on the wellbore and by hydrate inhibition delivery rates. Even if the system has been inhibited from hydrates, the live fluid from the wellbore may need to be inhibited if the shutdown has allowed the fluid to cool significantly. Typical deliverables are the time to warm-up above hydrate formation conditions, overall chemical consumption used, and restart slugging (if any). Cold Restart – Restart following a prolonged shutdown. Either the flowline or the wellbore + flowline has been allowed to cool to ambient conditions. Typically, the wellbore may take several weeks to reach ambient conditions, so a completely cold restart is a rare occurrence. Warm Restart – Restart following a short-term shutdown. Warm restarts are evaluated to determine whether or not the system can be brought back on-line without requiring any hydrate inhibition. The cooldown time allowed for a warm restart is typically set by the “No-Touch” and “Light-Touch” times, and it must occur prior to the Mitigation Time. Riser: Term given to portion of a tieback that begins the vertical riser from the seafloor to the surface. Dynamic Riser – Portion of a catenary riser that is suspended above the seafloor. This is the portion directly downstream of the “touchdown point”. Static Riser – Portion of a catenary riser that is connected to the flowline and still laying on the seafloor. This riser occupies the portion upstream of the “touchdown point”. Concentric Offset Riser (COR) – Riser type with a concentric production riser located within a larger-diameter carrier pipe.

Hybrid Riser Tower – Riser type, where multiple individual risers are bundled together within a single carrier pipe. Extremely complex heat transfer predictions.

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Single Leg Offset Riser (SLOR) – Riser type, very similar to the COR Dry Tree Riser – Riser type that consists of a vertical riser running directly from the wellbore up to the platform. The only controls are located at the surface.

Roughness: Measure of the friction factor within a pipe and directly impacts the frictional pressure drop. Typical values are: Steel Pipe – 0.0018” Tubing – 0.0006” Flexible Pipe (mm) – Pipe ID (mm)/250 SCR (Steel Catenary Riser): Common riser profile used for most systems where a riser tower is not in service.

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SCSSV (Surface Controlled Subsurface Safety Valve): Valve located in the wellbore and used as a last resort for isolation of the reservoir. The SCSSV is typically always operated fully open, with the exception of dry tree risers when the SCSSV may be closed during depressurization. SCSSV setting depths are determined by the hydrate formation conditions and the geothermal temperature gradient. SPAR: – Production platform type Sail Angle: Angle of the wellbore, defined as the deviation from the vertical that spans from the kick-off point to the perforations. Scale: Scale is a deposit of the inorganic mineral components of water. This is in contrast with wax and asphaltenes that deposit from the crude oil. Oilfield scale is generally inorganic salt such as carbonates and sulfates of the metals calcium, strontium and barium. Scale may also be the complex salt of iron such as sulfides, hydrous oxides and carbonates.

The major forms of oilfield scale can form in one of two ways: 1. As a brine (e.g. formation water) undergoes a temperature or pressure change during production, the solubility of some of the inorganic constituents will decrease and result in the salts precipitating. Scales formed under these conditions are generally calcium/magnesium carbonate scales.

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2. When two incompatible waters (such as formation water rich in calcium, strontium and barium and sea water rich in sulfate) are mixed. Scales formed under these conditions are generally sulfate scales. Separator: Vessel that separates the gas from the hydrocarbon liquid (and possibly the water). The separator typically sits on the host facilities and represents the end point. If a slug catcher is not provided, the separator must be sized large enough to handle any additional surge volume during slugging operation. HP Separator – High Pressure Separator IP Separator – Intermediate Pressure Separator LP Separator – Low Pressure Separator Shutdown: Transient operation where the topsides (and potentially subsea) valves are closed and production is stopped. During a shutdown, the fluids may be subject to hydrate formation if they have not been inhibited prior to the shut-in. Packed Shutdown – Shutdown where the topsides valve is closed, but the subsea valves are left open for a set amount of time. During this time, additional mass is added to the flowline, increasing the pressure. Packed shutdowns may occur due to long closing times on the subsea valves, or may be done intentionally to increase the thermal mass of the flowline which prolongs the cooldown time. Planned Shutdown – Shutdown where hydrate inhibition is added to the live production fluid before the system is shut-in. As such, the fluids that remain in the flowline are inhibited from hydrate formation. Un-packed Shutdown – Shutdown where the topsides and subsea valves are closed simultaneously. Un-packed shutdowns keep the shut-in pressure low, but may result in shorter cooldown times. Un-planned Shutdown – Shutdown where hydrate inhibition is not added to the live production fluid before the system is shut-in. As such, the fluids that remain in the flowline are not inhibited from hydrate formation. Un-planned shutdowns are often referred to as ‘Emergency Shutdowns’ or ‘ESDs’. Slugging: Terminology used to describe the physical behavior of a multiphase system operating within the “slug flow” regime. Slug flow operation creates significant operational problems, both for topsides processing facilities, as well as for fatigue life of risers. Hydrodynamic Slugging –High frequency slugging that may be a result of low velocities or terrain changes. The flowrate oscillates about a defined pseudo-steady state flowrate, with a relatively small change in gas/liquid flow rates. Typically, hydrodynamic slugging does not pose a significant challenge for the topsides facilities, namely the separator/slug catcher, in terms of surge volume requirements.

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Hydrodynamic Slugging Gas Outlet Flow 7

6

5

4

3

2

1

0 1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

5.5

6.0

Time (hours)

Ramp-up Slugging – Slugging that is common within gas/condensate systems relating to the change in liquid holdup that occurs as the flowrate is increased. Since the liquid holdup is a strong function of flowrate, ramping up the flowrate results in a much lower liquid accumulation in the flowline. As such, there is a significant amount of liquid that is expelled from the flowline and must be processed topsides. Start-up Slugging – Slugging that is results from starting up a flowline following a shutdown. The impact of start-up slugging is highly dependant on the seabed bathymetry and the location of any liquid that has settled throughout the flowline Terrain Slugging – Terrain slugging is characterized by prolonged periods of no flow, followed by short periods of very high gas/liquid flow. Terrain slugging is often caused by changes in the seabed bathymetry, especially downsloping flowlines leading into a riser. Typically, this severe form of slugging is often seen at low flowrates (low velocities) and high water cuts (high fluid density). Terrain slugging may cause significant problems for the topsides facilities in terms of surge volume requirements. Terrain Slugging Liquid Outlet Flow 80000

70000

60000

50000

40000

30000

20000

10000

0 1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0

5.5

6.0

Time (hours)

Slug Catcher: Vessel installed to dampen the liquid inlet flowrates that are generated by slug flow operation. Slug catchers are sized to provide sufficient volume for slug flow operation.

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Finger-Type Slug Catcher

Vessel-Type Slug Catcher Steady State: Normal operating conditions. Steady state issues are typically wax/hydrate formation and slug flow operation; in all cases these are generally exacerbated at low flowrates. Stock Tank Conditions: Similar to “standard conditions” in the chemical industry, stock tank conditions in the oil/gas industry are typically 14.7 psia and 60°F. Nearly all flowrate measurements provided in the oil industry refer to the rates at stock tank conditions. Stroke Time: Time required for a valve to go from fully open to fully closed. Subsea: Term referred to the piping and equipment located below the sea level. Surge Volume: Additional volume required, above normal operating requirements, that directly relates to the liquid arrival rates due to slug flow operation or from restart operation. THP: Top Hole Pressure, typically used in conjunction with dry tree risers to define the pressure upstream of the separator TLP: Tension Leg Platform vessel Thermal Mass: The thermal mass is a function of the density and heat capacity of the various materials, along with the thickness of each material, and is a measure of a system’s ability to retain/store heat. As the thermal mass increases, the amount of cooldown time increases. Conversely, the amount of time required to warm-up a system also increase for high thermal mass fluids. Three-Phase Systems: Systems that are gas, hydrocarbon liquid, and water. For black oil systems, three-phase modeling should be assumed only when complex operations such as crude oil displacement are being modeled, with the crude oil incorporated as the 3rd phase. For gas/condensate systems, threephase modeling should generally be used, with the water as the 3rd phase. There is often a very distinct operating range where the relative slip differential between the water and hydrocarbon liquid phase

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produces water accumulation volumes that are significantly different than the hydrocarbon liquid holdups. Thus, discrete modeling of each phase is required. Touchdown Point: Point at which the riser “touches down” on the seafloor. Beyond the touchdown point, the riser continues upward to the host facility. The touchdown point is highly susceptible to fatigue due to movement on the seafloor, causing stress and erosion. The touchdown point is required in order to define the catenary riser profile. Topsides: Term referred to the piping and equipment located at the host facilities. Transient Operation: Operations that are defined as being deviations from the expected, steady state operations. Transient operations are time-dependant and are often dictating facility design, especially for deepwater systems. Typical transient operations are: •

Cooldown/Shutdown

•

Crude Oil Displacement

•

Depressurization

•

Pigging

•

Restart

•

Slugging

•

Wax Deposition

Tree: Physical piece of equipment, typically supplied by ABB, Cameron, or FMC, that is located at the top of the wellbore and contains the controls for flowrate control, as well as other isolation valves. Trees are typically not modeled within OLGA, as they are very small pieces of pipework, relative to the overall development option. However, they often represent cold points in the system subject to rapid cooling in the event of a shutdown. Dry Tree – Tree is located at the surface only, above the water (hence the name “dry tree”). Wet Tree – Tree is located on the seafloor. Production from the tree may be routed to a manifold, or directly to the main flowline for subsea tieback back to the host facility.

True Vertical Depth (TVD): Vertical depth below mudline, surface, etc. The true vertical depth is a measure of how deep a particular component is located and does not account for any deviations from the vertical direction. The TVD is used in combination with the MD to accurately define the routing profile.

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Tubing: Piping that is typically located within the wellbore. Production tubing has roughness values different than standard pipe, as well as different line sizes. It is imperative to use a tubing string sizing chart, rather than a traditional pipe-sizing chart, when reading diameters. Typical tubing sizes are 3-1/2”, 4-1/2”, or 5-1/2”. Turndown: Terminology used to describe the process of decreasing the flowrate. The minimum flowrate at which operation is feasible (maximum turndown rate) is often dictated by the resulting surge volumes during ramp-up for gas/condensate systems. Terminology for turndown rates may be 3:1 turndown, which relates to reducing the flowrate to 1/3 of the steady state design rate. Additionally, the minimum turndown rate for a black oil system is dictated by the Wax Appearance Temperature/hydrate formation temperature. Two-Phase Systems: Systems which are gas and hydrocarbon liquid only. For black oil systems, twophase modeling should be assumed, with the water incorporated into the oil phase and average properties of the mixture assumed. For gas/condensate systems, two-phase modeling should only be used when no water is present. U-value: Overall heat transfer coefficient. The U-value is critical in evaluating the steady state thermal performance, and has a large impact on the transient thermal performance (along with the thermal mass). In most cases, the U-value is reported based on the piping ID, but can be based on the OD. It must be clearly defined what the basis for the U-value calculation is (i.e. ID-based or OD-based). Typical Uvalues for various insulation configurations are: Bare Pipe – 30 BTU/hr-ft2-°F Flexible Pipe – 1.00-1.50 BTU/hr-ft2-°F Wet Insulation – 0.50-0.80 BTU/hr-ft2-°F Pipe-in-Pipe – 0.20-0.25 BTU/hr-ft2-°F Micro-porous – 0.09 BTU/hr-ft2-°F Umbilical: Service line that runs from the topsides down to the trees/manifolds to deliver chemicals (hydrate inhibitor, scale inhibitor, paraffin inhibitor, etc.) and power (if required). The umbilical line is typically constructed of several, smaller bundled lines that may range from 3/8” to 3” in diameter. VIT (Vacuum Insulated Tubing): Specialized tubing that results in very low heat loss under steady state conditions. Typical applications for VIT are within the wellbore or in dry tree risers. WGR (Water/Gas Ratio): For gas/condensate systems, WGR is the ratio of water to gas, typically measured at stock tank conditions. The WGR is typically reported in units of bbl/mmscf and are on the order of 0-50. Water Depth: Measured depth from the seafloor to the surface. Water Hammer: Phenomenon that occurs when a sudden valve closure occurs while the flowrate has not been stopped. The instantaneous stopping in flow velocity is translated into a pressure wave that propagates throughout the system, potentially subjecting the system to pressures in excess of the design limits. Water Injection: Process of injecting water in disposal wells, typically for reservoir pressure maintenance or for lack of processing facilities on the host facilities. Water injection may result in changes in the fluid GOR/GLR over time, depending on the proximity of the water injection wells. Additionally, the injection of water may result in cooling of the reservoir temperature over time. Water Salinity: Salt content of any water that may be produced back through the production system. Water salinity has an impact on the density of the fluid and can impact the hydraulics for considerably

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saline waters. In addition, the water salinity has a pronounced effect on hydrate formation conditions. As the water salinity increases, hydrate formation conditions become less severe. Hydrate Formation Conditions 9000 Pure Water (0 mg/l) 8000 Sea Water (35.4 mg/l) 7000 Produced Water (60 mg/l)

Pressure (psia)

6000 5000 4000 3000 2000 1000 0 40

45

50

55

60

65

70

75

80

Temperature (°F)

Wax: Wax is not a single compound but rather a wide range of high molecular weight paraffins that solidify from crude oil primarily due to a decrease in the crude oil temperature. Waxes may consist of straight chain, normal paraffins or may be branched or cyclic paraffins.

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High molecular weight compounds are only minutely soluble in crude oil at reservoir conditions. As the temperature of the crude oil drops during production, these compounds begin to crystallize. The temperature where the first crystals occur is called the cloud point or Wax Appearance Temperature (WAT) of the crude oil. At the cloud point only a tiny fraction of waxes crystallize; however, as the temperature continues to drop, more and more waxes crystallize. While temperature is the primary factor affecting wax crystallization, pressure also plays a role. Light ends (which act as solvent for waxes) are at the highest concentration in the crude oil at the bubble or saturation point; consequently, the cloud point is lowest at the bubble point. Above the bubble point, no additional light ends are dissolved in the crude oil; however, the pressure continues to increase which causes the cloud point to increase. Below the bubble point, light ends are removed from the crude oil as the pressure drops; therefore, the cloud point increases as the pressure decreases below the bubble point. Wax can precipitate on surfaces such as tubulars and pipe walls. Over time, the build-up of the solid deposit will reduce the internal diameter and eventually block the line. A second effect, which will likely cause operational problems much earlier, is that the solid deposit increases the surface roughness of the pipe wall. This causes an increase in the pressure drop that can result in higher pumping costs or reduced throughput. Wax build-up on tubulars and tiebacks can effectively choke back the wells and can kill a well even though the line is not totally blocked. Total blockages of flowlines and pipelines due to wax build-up have occurred, but are still rare. However, blockages can occur due to crude oil gelling or because of other types of deposits. The cloud point or Wax Appearance Temperature is a critical property since wax deposition can begin whenever the temperature of any surface in contact with the crude oil drops below the cloud point.

Wax Deposition: Transient operation where the rate of wax deposition is determined. Wax deposition rates are modeled external to OLGA and are a function of the diffusion coefficient, the WAT, and the temperature profile. In order to perform wax deposition modeling, and extended n-paraffin analysis is required. Wax deposition rates are used to determine pigging frequencies.

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Typical pigging frequencies are set once the wax deposition thickness reaches 1-4 mm. Slow deposition rates are very hard to remove, so pigging must be done once the thickness reaches 1 mm to avoid the risk of the pig becoming stuck. For fast deposition rates, the deposits are much softer and easier to remove, so the deposition thickness may be allowed to reach 4 mm. Wax Propensity: Measure of the likelihood for wax to deposit. The difference between the actual temperature and the Wax Appearance Temperature (WAT) at operating pressure is calculated. If the actual temperature is above the WAT, then the wax propensity is above zero and wax deposition will not occur. If the actual temperature is below the WAT, then wax deposition may occur and the amount of sub-cooling is the wax propensity. Wellbore: Piping below the mudline, between the reservoir and the production trees. The wellbore typically has a U-value of 2.0 BTU/hr-ft2-°F (4-1/2” OD) and consists of the “production tubing” and casings. Well Testing: Process of testing individual wells in order to accurately determine flowrate, composition, etc. In many cases, separate flowlines called “testlines” are installed to flow a single well through to a “test separator”. In other cases, where a testline is not installed, multiple wells may be flowed in a single flowline and a given well may be added or subtracted. Then, the change in flowrate/composition can be measured and the specific properties of a given well can be determined by addition/subtraction. Wet Insulation: Insulation system where insulation is applied on the outside of a single production pipe. Typically, the thickness of insulation is limited to approximately 2-3 inches and the U-value is 0.5-0.8 BTU/hr-ft2-°F. Wing Valve: Valve located subsea that is typically only used in the event of a shutdown. The wing valve is not used for flow control and is a fast-acting valve that may close in 2-3 seconds in the event of an emergency shutdown.

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Chapter 3: Fluid properties & Phase determination The single-most critical parameter for any flow assurance study is the fluid properties. All hydraulic and thermal calculations are based on the fluid properties. An incorrect fluid characterization can lead to a flow assurance design that does not address the needs of the actual system once production has started. Thus, it is critical to ensure that the fluid properties are well defined at the outset of a project.

3.1

Gas Condensate Systems The following sections deal with fluid characterizations for gas condensate system and the required data for any flow assurance study to be performed for such a system.

3.1.1

HYDROCARBON COMPOSITION

The composition of the fluid should be provided from the appropriate source. If it is desired to model the system from the reservoir, then the full PVT report for the gas should be provided. If it is desired to model the fluid from the platform/compressor outlet, then a representative composition should be provided, either from the PVT report or the output from a process model (i.e. HYSYS). Fluid composition should be provided out to at least C7+. Depending on the actual fluid composition and the liquid loading, additional compositional data above C7 may be required. Typically, for gas/condensate systems, the large majority of the composition is C7 or lighter. It is imperative that any fluid contamination in the fluid sample be accounted for. Drilling fluid contamination is often present, which can lead to an incorrect fluid characterization. Drilling fluids typically appear in the PVT reports at carbon numbers from C14 – C20. Table 0-1 below illustrates a fluid composition taken from a PVT report. Table 0-1:

Sample Hydrocarbon Composition

Component

Base

N2 CO2 H2S C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8 C9 C10 C11 C12 C13 C14 C15 C16

0.390 0.079 0.000 98.959 0.162 0.045 0.015 0.006 0.009 0.005 0.016 0.020 0.027 0.017 0.006 0.004 0.004 0.005 0.014 0.018 0.112

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Component

Base

C17 C18 C19 C20 C21 – C29 C30+ Total

0.020 0.054 0.006 0.002 0.003 0.002 100.000

Note that the mole percent for C16 and C18 appear to be quite high, relative to the other values. This is as a result of the drilling fluid composition, which can often appear in the PVT report grouped with the hydrocarbon composition. If the composition above is used to define the fluid properties, then the high carbon components will result in an over-prediction of the amount of liquid in the system. This can lead to an overly conservative system design, large slug catchers, and other operational issues. For the example above, the condensate/gas ratio (CGR) for the fluid composition in the table is ~4.5 bbl/mmscf. For the un-contaminated case (removing the contamination from the C14, C16, and C18 components), the CGR is reduced to <0.5 bbl/mmscf. At a desired production rate of 150 MMSCFD, this changes the liquid processing requirements from 4500 bbl/day to <500 bbl/day. Contamination removal can be done by either averaging the existing composition vs. carbon number and re-normalizing OR, if the drilling fluid composition is provided, a detailed mass balance can be used to subtract the contaminated concentration from the base hydrocarbon fluids. Accounting for contamination in gas/condensate samples is critical to accurately develop a liquid management strategy.

3.1.2

PHASE EQUILIBRIA

Once the fluid composition is finalized, the next step is to characterize the fluid using an Equation-ofState (EOS) model. Fluid characterization is used to generate the phase envelope and transport properties. Typical EOS models are Peng-Robinson (PR) or Soave-Redlich-Kwon (SRK). Commercially available software are typically used for fluid property definition, with the EOS being selected either from the PVT report EOS (if provided) or should be selected to best match the PVT report tuning parameters. The EOS model should be tuned to match the key fluid properties defined in the PVT report. The two most critical parameters are the dew point and the condensate/gas ratio. The dew point is often provided at reservoir conditions in the PVT report and is useful in tuning the phase envelope to predict the correct conditions where liquid dropout is expected. For all gas/condensate projects, the phase envelope should be generated to visually inspect whether or not the system will operate in the single-phase (dense phase) region, two phase region, or a combination of both. Figure 0-1 illustrates a sample phase envelop for a gas/condensate system. Note that if the expected ambient temperature profile and pressure profiles are plotted against the phase envelope, an initial assessment of the liquid handling issues can be ascertained. For example, if the delivery pressure is maintained very high, the system may operate in the single-phase region (i.e. 100 bara). A decrease in pressure (i.e. below ~95 bara at 10°C) indicates that liquids are expected. However, if the delivery pressure is decreased further (i.e. below ~15 bara at 10°C), then the phase equilibria indicates that no liquids will be received at the pipeline outlet, although liquid drop-out is expected along the pipeline profile.

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150 140 130 120 110

Pressure (bara)

100 90 80 70 60 50

50 BAR - 1.63 bbl/mmscf

40 30 20 10 8 BAR - NO LIQUIDS

0 0

2

4

6

8

10

12

14

16

18

20

22

24

26

28

30

Temperature (°C)

Figure 0-1:

Phase Equilibria

The phase envelop itself cannot be used to predict the amount of liquid in the system, but it can serve as a guide to indicate potential problems, as well as to provide a quality assurance check against the results obtained from the hydraulic/thermal modeling of the fluid. NOTE: Caution should be taken if the operating range is near the critical point of the fluid. Small changes in the temperature/pressure of the system can lead to rather significant changes in the phase equilibrium of the fluid. If the expected operating region is near the critical point of the fluid, additional certainty is required in the fluid composition to help ensure validity of the phase equilibrium. Additional over-design margins may be required as well, to account for the situation where the fluid behavior in the field is not the same as that in the laboratory/EOS model. Fluid properties should be defined over the range of expected operating conditions, both steady state and transient events. This is typically defined by the following: •

Temperature range:

Pipe material limit (MINIMUM) – reservoir temperature (MAXIMUM)

•

Pressure range:

Flare pressure (MINIMUM) – reservoir pressure (MAXIMUM)

3.1.3

CONDENSATE/GAS RATIO (CGR)

The second of the two critical hydrocarbon characterization parameters is the CGR. The CGR defines the amount of liquid expected on a gas-volumetric basis (at a given pressure). Relatively dry gases or processed gas from an offshore platform may have a CGR < 1 bbl/mmscf, whereas high liquid-loaded systems may have a CGR of 100 bbl/mmscf. As the CGR increases (as well as the WGR), multiphase flow transport becomes increasingly difficult, as the additional liquid in the system can serve to increase liquid hold-up, increase pressure drop, and potentially increase slugging tendency. Because the CGR is temperature/pressure-specific, the basis for the CGR should be explicitly defined at the start of a project. If the CGR is not provided in the PVT report, it may be predicted from the hydrocarbon phase equilibrium at a given condition using an EOS model. For most projects, the CGR is defined either at stock tank conditions (1 bara/15°C) or at delivery conditions (separator pressure/ambient temperature). Table 0-2 contains the CGR for an example gas/condensate fluid over a range of conditions.

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Table 0-2: Temperature (°C) 40 40 20 20 15 10 10 10 4 4

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Condensate/Gas Ratio Summary Pressure (bara) 120 80 60 40 40 40 20 10 20 10

CGR (bbl/mmscf) Single Phase Single Phase 0.201 0.351 1.038 1.642 1.005 Single Phase 1.743 0.605

As the table shows, the actual CGR may increase or decrease with changes in field conditions, depending on the phase equilibria. Pressure decreases may result in more or less liquid input into the pipeline and associated liquid accumulation, again depending on the pressure regime where the changes are taking place. Thus, dynamic operational issues such as separator fluctuations or flowrate changes can impact the pressure profile and the resulting liquid holdup. In addition, seasonal temperature changes can impact the liquid loading as well. The CGR may change over the life of the field, but also many change depending on the time of year. For onshore systems, the time of day can impact the liquid loading due to cooler temperatures at night. It is critical to understand the phase behavior and resulting liquid loading as a function of the operational conditions envisioned.

3.1.4

WATER/GAS RATIO (WGR)

The water/gas ratio (WGR) is defined as the total amount of water present on a gas-volumetric basis. Unlike the CGR, the WGR is relatively constant over the range of operating conditions (temperature/pressure). The WGR should be defined over time, to account for the impact of increased water production in late-life, if expected. Even for “dry” systems (i.e. WGR = 0 bbl/mmscf), as good practice saturated water is assumed. This is typically defined by the amount of water required to saturate the hydrocarbon at reservoir conditions. When predicting fluid properties, particularly hydrate inhibitor requirement, the actual WGR value is very important. All hydrate-related properties are typically based on pure water, as this is the most conservative. All transport-related properties, particularly those used for hydraulic modeling, should be based on produced water. Especially for high salinity samples, the density of the water phase can be quite a bit higher than pure water (~1000 km/m3). For deepwater developments or for systems with a very small tolerance for pressure increases, the hydrostatic effects of the water phase can be critical. Thus, it is important to identify the produced water composition expected for the development.

3.1.5

HYDRATE INHIBITOR

If hydrate formation is an issue, based on ambient temperatures, it is common practice to continuously inhibit the gas with hydrate inhibitor. It may be possible to insulate the system to maintain temperature if the reservoir temperature is quite high, or it may be possible to utilize an actively-heated system design (i.e. electrical heating) to maintain the temperatures outside of the hydrate formation region. However, this document will focus on the industry-standard approach of continuous hydrate inhibition for hydrate management.

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Hydrate inhibition rates for gas/condensate systems should be determined early-on in the project lifecycle, as the rates can impact system hydraulics, liquid holdup, etc. Typically, hydrate inhibition rates are taken at the maximum pipeline pressure and ambient temperature. Maximum pipeline pressures can be difficult to estimate prior to the hydraulic modeling, but an early indication of maximum allowable operating pressure (MAOP), maximum shut-in tubing pressure (SITP), or other pressure limitation can be used as a guide for a first-pass at the hydrate inhibition requirements. Hydrate inhibition is required at the pipeline inlet (i.e. subsea wellhead or offshore platform) and may be either (1) thermodynamic inhibitors such as methanol or glycols, (2) low dosage hydrate inhibitors such as AAs or KHIs or (3) a cocktail of both. For thermodynamic inhibitors, the dosage rates are a function of the fluid composition, the WGR, and the shut-in conditions. Depending on the system, concentrations as high as 50 wt% (based on water rates) may be required. This equates to ~1-2 bbl inhibitor/bbl water, which quickly doubles (or triples) the amount of liquid in the system. Thus, the total volume of liquid moving through the system, including condensate, water, and hydrate inhibitor must be considered. LDHIs have very low dosages, typically ~1-2 vol.% of the water phase, so their overall contribution to the overall liquid holdup is quite small. When developing the fluid properties and hydraulic model, it is necessary to provide for the hydrate inhibitor rates. The hydrate inhibitor will affect (1) the liquid outlet rates, (2) the total liquid holdup in the pipeline, and (3) the hydrostatic component of pressure drop in the system. For deepwater systems, the hydrostatic component is quite critical. In particular, mono-ethylene glycol (MEG) has a specific gravity of ~1.14, and can impose a higher backpressure than methanol which has a specific gravity of ~0.79. Table 0-3 illustrates the hydrostatic pressure contribution for various water depths for a methanol-inhibited and MEG-inhibited system. Table 0-3:

Hydrostatic Pressure Impacts Option 1

Option 2

Option 3

Property Total Liquid Volume, BBL Liquid Column Height, m Pressure at Column Base, bar Difference, bar

MEG

MeOH

MEG

MeOH

MEG

MeOH

100 387.4 39.9

100 387.4 34.2

200 774.8 79.8

200 774.8 68.4

500 1937 199.5

500 1937 171.0

5.6

11.4

28.5

The table shows that the MEG system can increase the pressure drop by 5-30 bar, depending on water depth. If the MEG phase is not accounted for, then the system design may not properly evaluate the true hydraulic capacity.

3.2

Black Oil Systems

The key parameters that must be clearly defined for oil systems are described in this section.

3.2.1

HYDROCARBON COMPOSITION

The full PVT report for the oil should be preferred. If the reservoir fluid composition is not available, then a recombined separator gas/liquid composition, mixed in the appropriate gas/oil ratio, is used. Depending on the fluid type, the fluid composition should be provided out to at least C30+. Heavier fluids may require additional fluid characterization (i.e. C36+). Providing limited compositional data will result in a large “plus fraction” component (i.e. C10+), which introduces error/uncertainty in the calculations. This can have a significant impact on the fluid phase equilibria (bubble point) and other physical properties (i.e. viscosity, API gravity, etc.)

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It is imperative that any fluid contamination in the fluid sample be accounted for. Drilling fluid contamination is often present, which can lead to an incorrect fluid characterization. Drilling fluids typically appear in the PVT reports at carbon numbers from C14 – C20. The following Table 0-4 illustrates a fluid composition taken from a PVT report. Table 0-4: Component N2 CO2 H2S C1 C2 C3 iC4 nC4 iC5 nC5 C6 C7 C8 C9 C10 C11 C12 C13 C14 C15 C16 C17 C18 C19 C20 C21 C22 C23 C24 C25 C26 C27 C28 C29 C30+ Total

Sample Hydrocarbon Composition Base 0.141 0.115 0.000 25.658 8.191 7.547 1.393 4.329 1.701 2.394 4.771 4.434 4.103 2.915 3.157 2.578 2.106 1.994 2.022 1.730 2.173 1.712 1.496 1.047 0.866 1.207 0.705 0.731 0.572 0.524 0.486 0.463 0.485 0.368 5.890 100.000

Note that the mole percent for C14, C16, and C18 appear slightly higher than the general decay with increasing carbon number. This is as a result of the drilling fluid composition, which can often appear in the PVT report grouped with the hydrocarbon composition. If the composition above is used to define the fluid properties, then the high carbon components can result in an incorrect gas/oil ratio (GOR) or bubble point. Contamination removal can be done by either averaging the existing composition vs. carbon

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number and re-normalizing OR, if the drilling fluid composition is provided, a detailed mass balance can be used to subtract the contaminated concentration from the base hydrocarbon fluids. Accounting for contamination in oil samples is critical to accurately predict the multiphase flow properties.

3.2.2

PHASE EQUILIBRIA

Once the fluid composition is finalized, the next step is to characterize the fluid using an Equation-ofState (EOS) model. Fluid characterization is used to generate the phase envelope, and transport properties. Typical EOS models are Peng-Robinson (PR) or Soave-Redlich-Kwon (SRK). Commercially available software are typically used for fluid property definition, with the EOS being selected either from the PVT report EOS (if provided) or should be selected to best match the PVT report tuning parameters. The EOS model should be tuned to match the key fluid properties defined in the PVT report. The most critical parameters are the bubble point, gas/oil ratio (GOR), API gravity, and fluid viscosity. The bubble point is often provided at reservoir conditions in the PVT report and is useful in tuning the phase envelope to predict the correct conditions where gas breakout is expected. For all oil projects, the phase envelope should be generated to visually inspect whether or not the system will operate in the singlephase region, two-phase region, or a combination of both. Figure 0-2 illustrates a sample phase envelop for an oil system. Note that if the expected ambient temperature profile and pressure profiles are plotted against the phase envelope, an initial assessment of the likelihood for single phase or multiphase operation can be ascertained, particularly when in field life the system may be two-phase in the reservoir and at what separator pressure gas breakout may be expected. Unlike gas/condensate systems, a reduction in pressure is nearly always accompanied by an increase in the gas fraction. 200 190 180 170 160 150 140

Pressure (bara)

130 120 110 100 90 80 70 60 50 40 30 20 10 0 0

50

100

150

200

250

300

350

400

450

500

550

600

Temperature (°C)

Figure 0-2:

Phase Equilibria

The phase envelop itself cannot be used to predict the amount of gas in the system, but it can serve as a guide to indicate potential problems, as well as to provide a quality assurance check against the results obtained from the hydraulic/thermal modeling of the fluid. NOTE: Caution should be taken if the operating range is near the critical point of the fluid. Small changes in the temperature/pressure of the system can lead to rather significant changes in the phase

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equilibrium of the fluid. If the expected operating region is near the critical point of the fluid, additional certainty is required in the fluid composition to help ensure validity of the phase equilibrium. Additional over-design margins may be required as well, to account for the situation where the fluid behavior in the field is not the same as that in the laboratory/EOS model. With respect to the degrees of freedom that are typically available to tune the phase equilibria to match the expected PVT data, the most common are: •

EOS:

EOS should be selected to best reflect tuning parameters used in PVT analysis. Ensure that all fluid properties, hydrate predictions, and other properties use the same EOS model throughout the flow assurance study.

•

Plus Fraction:

By defining a “plus fraction” (i.e. C30+), there is some degree of freedom in tuning the exact molecular weight and specific gravity of the “plus fraction”. This can be used to tune bubble point/GOR, but has limited effect as the “plus fraction” value decreases.

•

Pseudo Components:

By defining pseudo-components, specific properties for heavy-end components can be used to tune the phase equilibria in lieu of lumping the properties together in a “plus fraction”. When defining pseudo-components, the following variables can be defined: • • • • • • • • •

Binary Interaction Parameters (KIJ Factors) Molecular Weight Specific Gravity Boiling Point Critical Temperature Critical Pressure Critical Volume Accentric Factor Volume Shift Factor

By defining the pseudo-components, the degrees of freedom are removed and, typically, the resulting bubble point, GOR, API gravity, etc cannot be further tuned. Fluid properties should be defined over the range of expected operating conditions, both steady state and transient events. This is typically defined by the following: •

Temperature range:

Pipe material limit (MINIMUM) – reservoir temperature (MAXIMUM)

•

Pressure range:

Flare pressure (MINIMUM) – reservoir pressure (MAXIMUM)

3.2.3

N-PARAFFIN COMPOSITION (WAX DEPOSITION MODELING ONLY) If wax deposition modeling is required, the n-paraffin composition must be defined. The n-paraffin composition is obtained typically from high-temperature GC analysis. It is important that weight percent of n-paraffin is explicitly defined in the characterization, rather than just a simple carbon number weight percent of the paraffins and olefins. N-paraffin analysis should be performed out to C100, or to as high a

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carbon number as can be detected to a sensitivity of ~1 ppm. Typical input format for an n-paraffin composition is given in the following Table 0-5. Table 0-5:

N-Paraffin Composition

n-Paraffin Carbon #

Weight Fraction

n-Paraffin Carbon #

Weight Fraction

n-Paraffin Carbon #

Weight Fraction

17

0.007098

32

0.001087

47

0.000028

18

0.007166

33

0.001167

48

0.000022

19

0.006640

34

0.000655

49

0.000015

20

0.005886

35

0.000517

50

0.000015

21

0.005326

36

0.000306

51

0.000011

22

0.004336

37

0.000244

52

0.000008

23

0.003901

38

0.000199

53

0.000007

24

0.003366

39

0.000173

54

0.000006

25

0.003182

40

0.000173

55

0.000005

26

0.002758

41

0.000100

56

0.000004

27

0.002467

42

0.000094

57

0.000004

28

0.002030

43

0.000072

58

0.000003

29

0.001614

44

0.000066

59

0.000002

30

0.001640

45

0.000046

31

0.002382

46

0.000045

TOTAL

0.064866

N-paraffin compositions are typically provided on dead oil samples (stock tank conditions). For wax deposition modeling of production systems (live fluids), the stock tank n-paraffin composition must be scaled to match the reservoir fluid, based on the liquid fraction at stock tank conditions for the live fluid.

3.2.4

DENSITY/API GRAVITY

A key parameter, particularly for deepwater projects, is the fluid density/API gravity. The density plays a big part in the overall system hydraulics. The hydrostatic pressure losses in the riser can contribute up to 90% of the overall system pressure drop. Thus, accurate prediction of the fluid density is critical.

3.2.5

VISCOSITY

Viscosity values have a significant impact on system hydraulics (pressure drop), as well as potential impacts on the rates of wax deposition. Thus, defining the fluid property behavior with respect to viscosity is critical, both for live production fluids, as well as dead oil/stock tank fluids that may be used during displacement and export operation. If non-Newtonian behavior exists at operation below the Wax Appearance Temperature (WAT), wax deposition modeling should be coupled with the basic fluid hydraulics in order to determine the true hydraulic impact on the system. For those cases where chemicals will be injected continuously for wax/gel control, their impact on viscosity should be clearly defined. In addition, for those cases where emulsions are an issue, the effective viscosity for a range of water cuts should be defined.

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3.2.6

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GAS/OIL RATIO (GOR)

The gas/oil ratio (GOR) defines the amount of gas expected for a given volume of oil. Relatively low GOR fluids may have values of 100 scf/stb, whereas more volatile oils may have GORs ranging from 2000-3000 scf/stb. As the GOR increases, the total mass through the system increases for a constant oil rate, increasing the overall frictional pressure drop, but potentially reducing the hydrostatic component. In addition, the higher GOR fluids have increasing erosion concerns due to the higher velocities. Also, higher GOR fluids typically have more thermal challenges due to the expansion cooling of the gas (JouleThomson effect). Conversely, higher GOR fluids typically have higher velocities, which help to mitigate slugging concerns.

3.2.7

WATER CUT

In addition to the GOR, the amount of free water present in the system should also be defined. The water cut is defined as the volume of water present vs. the total amount of fluid. Water cut is expressed as a percentage, with 0% being no free water and 100% representing an all-water system. Typically, water cut increases over time due to either water break-through or water addition due to water injection (for reservoir pressure maintenance). From a flow assurance perspective, increasing water cut over time serves multiple purposes. First, if the oil rates are decreasing and the water rates are increasing, the total fluid volume may stay relatively constant. This helps to ensure that the line size is not too big, mitigating slugging. Also, the relatively high heat capacity of water helps to maintain temperature in late-life, helping to reduce wax/hydrate formation concerns under steady state operation. Unlike gas/condensate systems, the actual amount of water used in hydrate predictions is not as critical. Sufficient water should be added to the system to ensure that water is not the limiting reactant, but the hydrate conditions typically show little sensitivity to water volumes. Produced water chemistry should be input into all fluid property calculations. Hydrate predictions are typically based on pure water, as this is the most conservative. All transport-related properties, particularly those used for hydraulic modeling, should be based on produced water. Especially for high salinity samples, the density of the water phase can be quite a bit higher than ~1000 kg/m3. For deepwater developments or for systems with a very small tolerance for pressure increases, the hydrostatic effects of the water phase can be critical. Thus, it is important to identify the produced water composition expected for the development. This is often overlooked, as the focus of exploratory efforts is to find oil and gas; the water is often ignored.

3.2.8

WAX PROPERTIES

Discussed in more detail in the wax section to follow, the following wax-related properties should be identified at the outset of any oil system flow assurance study. Depending on the fluid properties, additional testing/modeling may be required. •

Wax Appearance Temperature (Dead Oil and Live Oil, if available)

•

Wax Melting Temperature

•

Wax Content – Carbon number analysis

•

Diffusion Coefficient

•

Pour Point (Dead Oil and Live Oil, if available)

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3.2.9

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HYDRATE INHIBITOR

For most oil systems, continuous hydrate inhibition is not economically feasible and it is not typically required during normal steady state operation. However, hydrate formation conditions should be evaluated in order to predict the operating envelopes for the fluid where hydrate formation is favorable and where hydrate formation is unlikely in order to define the operational procedures. Hydrate inhibitor will often be used for startup (cold temperature period) and for treating stagnant liquids in the tree, wellbore, jumpers, manifolds after a shutdown.

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Chapter – 4: Fluid flow analysis for single phase & multiphase A detailed pipeline profile is used in the hydraulic model for fluid flow analysis. The pipeline route and terrain is captured in the simulation model to predict the flow behavior as accurately as possible. For subsea systems, accurate ambient water temperature and water velocity should be input into the model along the riser length. Modeling of process equipment within the hydraulic simulations for the wells, pipelines, and risers is generally not required. A constant pressure at the outlet can be used to represent the separator in steady state operation. For transient operations, a constant pressure at the outlet can be used in most cases. Inclusion of portions of the separation, control, and compression facilities may be necessary for severe slugging systems. For all hydraulic models, it is critical to define the desired flowrate in relation to a given set of conditions.

4.1

STEADY STATE FLOW HYDRAULICS

The primary goal of the steady state analysis is to define the line size required to meet the desired production rates throughout field life.This involves optimizing the line size to meet production rates, limiting erosion, maintaining sufficient velocities for corrosion management, preventing severe slugging at turndown rates, and preventing excessive liquid holdup that can cause severe operational upsets during transient operations. Error! Reference source not found. provides a logic diagram that may be used for steady state – hydraulic pipeline design. Each question should be addressed (as defined in the subsequent sections) in order to ensure the flow assurance engineer that the line size selected is correct. CONSIDER DUAL FLOWLINES

Select line size

Sufficient inlet Pressure?

YES

NO INCREASE LINE SIZE

Acceptable C-Factors? YES

NO

NO INCREASE LINE SIZE

Liquid holdup manageable?

NO DECREASE LINE SIZE

YES

Figure 3-3:

4.1.1

Hydraulic Pipeline Design – Logic Diagram

PRESSURE DROP

Delivery of the desired production rates constrains the minimum line size. Deliverability constraints can typically be evaluated using a steady state simulation, although the liquid holdup volumes should be properly defined in the software at low flowrates in order to ensure that the pipeline hydraulics is correct. The overall pressure drop in the system is comprised of the following:

IOGPT Flow Assurance Training

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•

Frictional pressure drop

•

Hydrostatic pressure drop

•

Restriction-induced pressure drop

Pressure drop generally increases with increasing flowrate due to friction effects, which is typically the dominant effect on system hydraulics. Error! Reference source not found. illustrates a typical pressure drop vs. flowrate trend. As the flowrate increases, pressure drop increases. Wellhead Pressure vs. Flowrate 1200 10" Line

1100 12" Line

1000 14" Line

Wellhead Pressure (psia)

900 16" Line

800 700 600 500 400 300 200 30

40

50

60

70

80

90

100

110

120

Gas Flowrate (MMSCFD)

Figure 0-4:

Pressure Drop vs. Flowrate (High Velocity)

However, for existing fields, particularly large trunklines with declining production, the flowrate may be sufficiently low enough such that the frictional pressure loss term is quite small. Instead, the hydrostatic component (for subsea systems) becomes increasingly dominant if the pipeline outlet is at a higher elevation than the pipeline inlet. Liquid may accumulate in the system, inducing a pressure drop term even when the frictional pressure drop contribution is almost negligible. Error! Reference source not found. illustrates the pressure trends for a different system, this time at very low flowrates for a large pipeline. As the graph shows, for high flowrates, the pressure drop increases with flowrate. At very low rates, the pressure drop starts to increase at very low rates, due to hydrostatic effects of the increased liquid holdup in the system.

IOGPT Flow Assurance Training

Figure 0-5:

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Pressure Drop vs. Flowrate (Low Velocity)

When evaluating pressure drop constraints, a range of flowrates are evaluated and cross-plots generated. This provides useful information over the life of the field, as well as providing a quality assurance measure to ensure that any single calculation is correct. Multiphase flow calculations can be somewhat inconsistent, depending on the system, which is why it is always a good idea to run multiple scenarios to ensure that all values are consistent. Pressure drop vs. flowrate relationships can also prove to be valuable in detecting any potential pipeline blockages (i.e. hydrate formation, solid accumulation, etc.). Field data can be compared against model predictions over time to understand whether the hydraulic capacity of the system is performing as expected or if additional pressure drop is occurring, which may be limiting flowrate.

4.1.2

EROSION/MAXIMUM VELOCITY

Erosion rates are directly related to fluid velocity. Once the pressure drop relationships are defined, the minimum pipeline size to meet desired production rates is defined. Erosion constraints may further limit the minimum pipeline size if the velocities are too high. Erosion is typically defined for multiphase flow systems by the API RP 14E specification. This standard defines the maximum velocity allowable, based on an empirical relationship with the density. In recent years a great deal of work has been done to better characterize erosion rates. 14E is no longer considered the state-or-the-art approach to erosion management. See Section Error! Reference source not found. for a discussion of erosion management.

Ve = where: VE

= fluid velocity (ft/sec)

C

= empirical constant (“C-Factor”)

ρMIX

= fluid density (lbs/ft³)

C

ρ MIX

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C-Factor limits are somewhat arbitrary and vary between operators. In general, the following C-Factor guidelines may be used: •

Solids-free, continuous services:

100

•

Solids-free, intermittent service:

125

•

Solids-free, non-corrosive services:

150 – 200

•

CRA, CRA Clad or lined pipe:

150 – 200

•

Flexible pipe:

Vendor-specific (values may range as high as 200 – 250)

In all cases, the C-Factor assumes sand-free production. If sand is detected, the C-Factor “rules of thumb” are not applicable and some other form of erosion prediction should be considered. In general, the C-Factor represents a good guideline for erosion risk. However, in all cases, if there is concern that the operation may potentially put the material integrity at risk, more detailed erosion modeling should be undertaken. Whereas the equation tends to be conservative for liquid systems, it can be nonconservative for gas systems. High velocity gas systems are inherently more erosive than liquid systems.

4.1.3

MINIMUM VELOCITY

There are no direct minimum velocity constraints on line sizes. The following criteria is used: •

In general, a bulk velocity of ~3-5 ft/sec is required for adequate water sweep. Operating at velocities lower than this will result in liquid accumulation in the pipeline, which may lead to liquid handling concerns, as well as localized areas prone to corrosion.

•

At low velocities that result in a flow regime change between stratified and annular mist flow, corrosion inhibitor distribution becomes critical. Annular mist flow ensures that all areas of the pipe wall are exposed to the same fluids (uniform corrosion rates). Additionally, all surfaces of the pipe circumference are equally wetted by the produced fluids.

•

Operation at very low flowrates/velocities will reduce the frictional pressure drop term and may cause the hydrostatic pressure losses to dominate, increasing overall system pressure drop.

•

A minimum velocity is required to prevent slugging.

•

A minimum velocity is required to push a sphere/pig and prevent the sphere from becoming stuck

4.1.4

LIQUID HOLDUP

Perhaps the single-most important factor to consider for multiphase gas/condensate systems is the liquid holdup within the pipeline. Due to “slippage” between the gas and liquid phases, whereby the liquid is “pulled” along the pipeline by the gas, the liquid phase is transported at a lower velocity than the gas phase. Moreover, the aqueous phase is transported at a lower velocity than the hydrocarbon (condensate) phase. At high velocities, most of the liquid is transported with the gas, resulting in very little liquid accumulation in the pipeline. As velocity decreases, more liquid drop out is observed, resulting in higher liquid holdups. Error! Reference source not found. illustrates the liquid holdup vs. flowrate curve for various pipe diameters. As expected, for the same flowrate, the liquid holdup is higher for the larger line sizes (lower velocities).

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5000 6 " F lo w lin e

4500 8 " F lo w lin e

4000 1 0 " F lo w lin e

Liquid Holdup (bbl)

3500 3000 2500 2000 1500 1000 500 0 0

10

20

30

40

50

60

70

80

90

100

F lo w ra te (M M S C F D )

Figure 0-6:

Liquid Holdup vs. Flowrate (Line Size)

In general, the liquid holdup is a velocity-driven phenomenon, along with the phase equilibria. The relative fluid CGRs and WGRs play a role in how fast the liquid may build up, but the steady state equilibrium liquid holdup is typically within the same order of magnitude for various liquid loadings. Error! Reference source not found. illustrates the liquid holdup for various liquid loadings. Note that while the total amount of liquid is slightly different, the difference is relatively small between the lowest and highest loading values. 200000 WC 5, CGR 2 WC 10, CGR 2

180000

WC 15, CGR 2 WC 20, CGR 2 WC 5, CGR 4

160000

WC 10, CGR 4 WC 15, CGR 4 WC 20, CGR 4

Total Liquid Holdup (BBL)

140000

120000

100000

80000

60000

40000

20000 50

100

150

200

250

300

350

400

450

500

Gas Flowrate (MMSCFD)

Figure 0-7:

Liquid Holdup vs. Flowrate (CGR/WGR)

At high flowrates, near the “horizontal” portion of the holdup curve, the total liquid holdup is dominated by the condensate phase. At very low flowrates, the aqueous phase becomes dominant and the liquid holdup starts to increase exponentially. It is strongly advised to avoid operating within this exponential region of the liquid holdup curve. Error! Reference source not found. illustrates water, condensate, and

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total liquid holdup profiles as a function of flowrate. The total liquid holdup vs. flowrate curve is critical for all gas/condensate projects. 140000 Total Liquid Oil Water

120000

Liquid Holdup (BBL)

100000

80000

60000

40000

20000

0 0

200

400

600

800

1000

1200

1400

1600

1800

2000

Gas Flowrate (MMSCFD)

Figure 0-8:

Liquid Holdup vs. Flowrate

The liquid holdup curves provide an early indication of the severity of any liquid handling issues during transient operations. For example, during ramp-up from a turndown condition, the difference in liquid holdup between the initial and final liquid holdup will be expelled from the pipeline. The downstream process equipment will be required to handle this volume of liquid over some time. Using this total volume to size processing equipment (i.e. slug catchers) may lead to very large vessels and increase overall project economics. Transient simulation should be used to confirm the actual liquid outlet rate profile over time, rather than design for the difference between the initial and final pipeline holdups. As the decision logic diagram in Section Error! Reference source not found. indicates, it may be advisable to utilize multiple pipelines, rather than a single large-diameter pipeline, in order to limit liquid holdup within the pipeline. For example, dual lines offer the advantage of operational flexibility in terms of routing wells, lower liquid holdup for the same total flowrate as a single line, and can be used for round-trip sphering or double-sided depressurization for hydrate plug remediation. In addition, multiphase software typically is more accurate with respect to liquid holdup (and pressure drop) predictions for smaller-diameter pipelines, as more benchmarking has been completed. The disadvantage of the multiple lines is typically cost. NOTE: When performing steady state liquid holdup calculations, ensure that the aqueous phase AND the condensate phase have reached an equilibrium value. Multiphase software models may be slow to predict the true liquid holdup with a single iteration. Software such as OLGA2000 should be run in dynamic/transient mode, particularly for low flowrate systems, in order to ensure that the total amount of liquid is predicted. Trend plots (liquid holdup vs. time) should be generated for each case analyzed, in order to ensure the simulation has converged on the equilibrium values.

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4.2

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THERMAL

For the majority of gas/condensate systems, thermal management is not required since it is quite difficult to ensure fluid temperatures reach the pipeline outlet above hydrate/wax conditions. The low ‘thermal capacity’ of the gas and the high rate of expansion cooling results in the temperature profile reaching ambient conditions some distance from the pipeline inlet, regardless of insulation type. Error! Reference source not found. illustrates a typical temperature profile along the length of the pipeline. Temperature Profiles 60 INLET FLOWRATE = 60 MMSCFD

55 50 45

Temperature (C)

40 35 30 25 20

MIDLINE TIE-IN = 50 MMSCFD

15 10 5 0 0

2

4

6

8

10

12

14

16

18

20

22

24

26

28

30

Distance (kilometers)

Figure 0-9:

Temperature Profile

Typically, gas/condensate pipelines are left un-insulated and/or buried, without requiring insulation. Continuous hydrate inhibition protects the system from hydrate formation during steady state and transient operations. Insulation may be used if the gas/condensate has a high Wax Appearance Temperature (WAT) or if the system is a high-temperature service with limited hydrate inhibitor capabilities.

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Chapter 5 : SLUGGING - PREDICTION AND MANAGEMENT 5.1 Slugging It is a multiphase flow phenomenon that is characterized by alternating liquid plugs and gas pockets moving along a pipe. Slug flow operation creates significant operational problems, both for topsides processing facilities, as well as for fatigue life of risers. Transient modeling is carried out for Slug Prediction and devising the management strategy. Slugging could be Hydrodynamic Slugging, Ramp-up Slugging, Start-up Slugging, Terrain slugging. The “Slug Flow” regime is common at low liquid and gas velocities, as illustrated in Error! Reference source not found.. Low velocities may occur as a result of declining production or for an “over-sized” pipeline.

Figure 0-10:

Flow Regime Map

Depending on the severity of the slugging, a wide variety of operational issues must be addressed, including: •

Process facility upsets

•

Wellbore instability/dynamic well-kill

•

Inefficient inhibitor transport

•

Mechanical/fatigue issues

•

5.2

SLUG TYPES

Slugging can be broken down into two primary categories – hydrodynamic and severe (terrain).

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5.2.1

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Hydrodynamic Slugging

Hydrodynamic slugging is high frequency slugging, characterized by gas/liquid rates that oscillate near an average steady state value. Hydrodynamic slugging is often experienced in operations, but generally without severe consequence, as the instantaneous liquid volumes are typically low. Error! Reference source not found. below illustrates an example of hydrodynamic slugging. 25000

Liquid Outlet Flowrate (B/d)

20000

15000

10000

5000

0 3.0

3.5

4.0

4.5

5.0

5.5

6.0

6.5

7.0

7.5

8.0

Time (hours)

Figure 0-11:

Hydrodynamic Slugging Example

In order to predict actual slug sizes, transient simulations are required. The accuracy of OLGA to predict general hydrodynamic slugging trends is acceptable, but the accuracy/ability to predict individual slug characteristics (i.e. length, volume, etc.) is poor – with potential errors in slug sizes of +/- 100%. There is a wide range of data scatter within the industry literature on hydrodynamic slug sizes. Intensive calculations to accurately define the individual slug properties are not warranted, since the size of an individual slug is typically inconsequential. Rather, the flowrate boundary between the hydrodynamic and the severe (terrain) region is the more critical operational parameter. In general, steady state multiphase simulation packages cannot predict hydrodynamic slugging, particularly with any resolution on the slug sizes.

5.2.2

Severe (Terrain) Slugging

Severe (terrain) slugging is periodic oscillation of gas and liquid rates which can be quite detrimental to operations, causing flooding of process equipment, dynamic kill of wells due to pressure surges, and mechanical/fatigue issues. Severe (terrain) slugging is less of an issue for gas/condensate systems than for black oil systems, where the gas velocities are lower. Severe (terrain) slugging is characterized by periods of no liquid outlet rates, followed by short-term, high rates of gas/liquid. Error! Reference source not found. below illustrates an example of terrain slugging.

IOGPT Flow Assurance Training

Figure 0-12:

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Terrain Slugging Example

The terrain slugging cycle typically consists of four distinct phases – slug formation, slug production, blowout, and liquid fallback that occur in cycles. During the first phase, the liquid at the base of the riser starts building up, thus preventing the gas from flowing since the gas does not have sufficient head to push the liquid. Once the gas has built up enough pressure, it rapidly discharges the liquid into the topsides and this is classified as the slug production phase. After the liquid exits, the gas then surges into the topsides and, once the gas is discharged, the pressure in the pipeline has reduced such that it is unable to deliver the liquid and hence the liquid starts falling back to the base of the riser and thus cycle is repeated. Error! Reference source not found. illustrates an example.

Figure 0-13: Terrain Slugging Cycles Terrain slugging is most commonly seen in the riser. For deepwater riser systems, accurate slug prediction is much more difficult, as there is limited work to accurately predict the decay of slugs in the vertical direction. Typically, riser-induced slugging can only occur if: •

Downward sections with stratified flow are present just upstream of an upward section

IOGPT Flow Assurance Training

•

Growth of slug is possible in the upward section

•

Flow is unstable in the upward section

•

There is no annular flow in the upward section

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If all conditions are met, then the slugs can grow locally in each upward facing section, but they could also dissipate as they flow along the vertical plane. However, if all conditions are met at the base of the riser, then slugging will occur in the riser. From a topsides process standpoint, the behavior and accurate prediction of slugging in the riser is most critical, as this directly impacts the ability to predict the liquid arrival rates into the separator. Terrain slugging can be characterized to some extent using steady state calculations, but more rigorous definition is obtained through the use of transient multiphase flow software. Steady state codes are primarily based on empirical correlations and recently have started incorporating mechanistic models that are more accurate in predictions as well. While steady state simulators are quite handy for simulating steady state scenarios, they are not quite accurate when it comes to slug flow. This is because these models depend on established slugging maps, based on experimental data obtained from small diameter test beds, and also because steady state codes have no mechanism to store historical effects, which are particularly relevant for slug propagation. In order to predict slug flow, transient simulators are a better option.

IOGPT Flow Assurance Training

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CHAPTER -6 : SURGE ANALYSIS 6.1 Surge analysis for oil systems, typically crude oil export pipelines and water injection systems, considers the effect of sudden interruptions in the process flow (i.e. spurious valve closure, pump trip, etc.). Sudden valve closures, either at the platform or at the wellhead, depending on flow direction, can create a high-pressure pulse, the magnitude of which depends on the time it takes to close the valve. This pulse will propagate through the system and, depending on the valve closing sequence, can potentially be significant enough to increase pressures in the pipeline above the design pressure, causing failure of the pipeline. As such, it is necessary to evaluate various shutdown scenarios and calculate the transient pressure fluctuations in the flowline. The magnitude of any pressure change is highly dependant on the fluid properties, particularly the fluid compressibility and the wave celerity (speed of sound in fluid - ~1500 m/s for crudes, ~2000 m/s for water). With respect to compressibility, highly compressible fluids such as gases show almost no propensity for wave propagation. Crude oils, which have some compressibility, will absorb the energy from the pressure pulse to some extent. Water, which is essentially incompressible, does not dissipate any energy, resulting in large pressure swings (i.e. “water hammer effect”). The worst-case scenario for a pressure increase would be to assume a sudden, instantaneous valve closure for an incompressible fluid. Essentially, the velocity would go from the steady state flowline velocity down to zero immediately. From a simple energy balance, this change in kinetic energy must be transferred into another form of energy that, in this case, is the form of a high-pressure pulse. Jukowsky’s law, which governs the maximum pressure rise in a rigid pipe for an instantaneous valve closure:

c ∆P =   • v o g ∆P: c: g: vo:

Maximum Pressure Rise Speed of Sound in Fluid Gravitational Constant Fluid Velocity prior to Valve Closure

Software simulation should be used to perform a proper transient analysis with respect to surge, taking into account such factors as compressibility, valve closure time, pump curve behavior, pipe elasticity, etc. For example, as the valve closure time increases, the fluid velocity starts to decrease, limiting the magnitude of any pressure pulse. Similarly, depending on the pump curve, the flowrate will not necessarily remain constant throughout the transient event.

6.2

WATER INJECTION Error! Reference source not found. illustrates an example water injection system, where sudden closing of the subsea valve can induce pressure surge events back to the pump discharge on the platform. Key variables to consider are the stroke time on the valve, pump curve, and the high-pressure alarm set point on the pump.

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P HIGH PRESSURE ALARM = ?

STROKE TIME = ?

STROKE TIME = ?

Figure 0-1:

Schematic (Water Injection – Surge Analysis)

Error! Reference source not found. and Error! Reference source not found. illustrate example transient pressure plots for a surge analysis through the water injection system, while Error! Reference source not found. summarizes example results. 900 800 700

Pressure (bara)

600 500 400 300 200 100 0 0

30

60

90

120

150

180

210

240

270

Time (seconds) Instantaneous: 210 bar Trip

1 Minute: No Trip

1 Minute: 210 bar Trip

3 Minute: 210 bar Trip

3 Minute: 345 bar Trip

5 Minute: 210 bar Trip

Figure 0-2:

1 Minute: 345 bar Trip

Pressure vs. Alarm Set-Point (Water Injection – Surge Analysis)

300

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350 325 300 275 250

Pressure (bara)

225 200 175 150 125 100 Outlet

75 50

Discharge

25 0 0

30

60

90

120

150

180

210

240

270

300

Time (seconds)

Figure 0-3:

Pressure Wave Propagation (Water Injection – Surge Analysis)

Table 0-1:

Maximum Pressures (Water Injection – Surge Analysis)

Maximum Pressure High Pressure (bara) Set-Point (bara) Topsides Subsea Topsides Subsea 0 205 254 320 1 1 1 NONE 725 792 1 205 250 319 1 1 345 388 454 1 3 205 210 276 1 3 345 385 452 1 5 345 205 265 1 The tables and figures are provided to show sample output from a surge study on a water injection system, as well as to show the relative impact of various parameters on the overall system hydraulics Valve Closing Time (min)

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Chapter – 7 : Hydrate formation and prevention 7.1

HYDRATES Gas hydrates (or clatharites, from the Latin word for ‘cages’) are ice-like structures that are formed by water and light hydrocarbons. The hydrocarbons are encaged in structures that rapidly grow and may agglomerate to sizes that can block pipelines. Four key factors are required for hydrate formation: 1. Light hydrocarbons 2. Water 3. High pressure 4. Low temperature Hydrates typically form at the hydrocarbon-water interface, in a ratio of ~85 mole% water to 15 mole% hydrocarbon. On a volume basis, 1 m3 of hydrates typically contains ~ 5m3 of gas. Hydrate formation is an endothermic reaction, giving rise to low temperatures during hydrate formation.

Hydrate formation is a kinetic process, typically driven by water condensation on the pipe walls. Hydrates may form in small particles that can agglomerate and block the pipeline. Or, hydrates may form in a thin film along the pipe wall, increasing in thickness and forming a flow-path restriction by reducing the cross-sectional area for flow. The second type is much easier to monitor (i.e. increasing pressure drop) to attempt to predict hydrate formation. Hydrates are somewhat porous and have the ability to transmit some degree of pressure. Aside from blocking flow-paths, hydrates can cause pipeline ruptures and projectile motion dangers while being remediated. The following sections address some of the specific risks, testing required to quantify hydrate formation/dissociation, and prevention/remediation techniques.

7.1.1

Risk The following are some common risks associated with hydrate formation: •

Under flowing conditions (particularly gas systems), hydrates can form at ambient conditions if the air/water temperature is low enough.

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•

Hydrate formation in subsea equipment (tress, manifolds, valves, jumpers) is particularly problematic if components are left un-insulated.

•

During cold well start-up, hydrates will form until the well has warmed sufficiently from production. Chemical injection is often required until the well is above hydrate forming conditions.

•

During transient operations such as depressurization, hydrate particles may form in downstream process equipment as a result of expansion cooling of the fluids (Joule-Thomson effect).

•

In gas lift systems, hydrate formation can occur at the inlet valve if back-flow into the gas lift line is observed.

•

For gas export systems, hydrate formation can occur if the water dehydration system goes offspec and water is allowed to be injected into the pipeline.

•

In water injectors, hydrate formation can occur during back-flow scenarios.

•

In long-distance pipelines, hydrate formation risks increase and remediation becomes more difficult due to accurate prediction of water holdup locations. Hydrate plug formation is most common along low spots, where water is allowed to accumulate.

•

Hydrates may be transferred to process separation systems, resulting in cooler than expected operating conditions, particularly if anti-agglomerating hydrate inhibitors are used.

•

Hydrate inhibitors, particularly methanol, present an uncertain risk to the operating performance of drying systems in processing plants. Molecular sieve drying systems are can become overloaded by the adsorbtion of hydrate inhibitor (i.e. methanol).

•

Procurement and supply chain management for large volumes of hydrate inhibitor required are expected to present significant management challenge and overhead.

•

During depressurization (hydrate remediation), hydrate plugs may act as projectiles and exit pipelines at high velocities when they become dislodged. Serious injury and even death has resulted from hydrate projectile motion.

•

Pipeline rupture may occur due to trapped pressure between multiple hydrate plugs

7.1.2

Prevention

Hydrate prevention is typically accomplished through one of two methods: •

Thermal control – this includes providing sufficient insulation to keep steady state operation above hydrate formation conditions, while also providing sufficient cooldown time in the event of an unplanned shutdown to treat the system. Thermal control can also be maintained via active heating through hot fluid circulation (bundles) or electrical heating.

•

Inhibitors – typical for gas/condensate systems, chemicals can be injected continuously to prevent the growth of hydrate particles and/or shift the phase equilibria of the hydrocarbon to result in less severe hydrate formation conditions. Through the use of inhibitors, no actions are typically required in the event of an unplanned shutdown.

7.1.3

Prediction/Testing

For systems that will operate in the hydrate formation region, or for systems that require large chemical volumes for inhibition, hydrate testing is recommended. Commercially available software packages offer satisfactory prediction of the hydrate conditions for most hydrocarbon systems. Additionally, the software can also be used to predict inhibitor requirements for thermodynamic inhibitors such as

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methanol and glycol. For low dosage hydrate inhibitors (LDHIs) such as Anti-Agglomerates (AAs) or Kinetic Hydrate Inhibitors (KHIs), specific laboratory tests are required. 7.1.3.1

Formation/Dissociation Curves

The key to understanding hydrate risk is to identify the hydrate formation conditions. Commercially available software packages offer equation-of-state models to predict hydrate dissociation conditions. Hydrate dissociation conditions are the conditions at which hydrates will dissociate. This forms the basis for most hydrate prevention systems and is somewhat conservative. As hydrate formation is a kinetic process, operation inside of the hydrate dissociation region is permitted to some extent. However, the degree of sub-cooling into the hydrate region, as well as the time within this region, is not a wellunderstood phenomenon. Figure 0-4 illustrates an example hydrate formation/dissociation curve.

PRESSURE (bar)

Hydrate Dissociation Curve or Hydrate Equilibrium Curve

HYDRATE ZONE

Hydrate Formation Curve

HYDRATE RISK ZONE

HYDRATE FREE ZONE

TEMP (° (°C) Figure 0-4:

Hydrate Formation/Dissociation Conditions

The extent of the ‘hydrate risk zone’ is typically unknown, as hydrate formation is a kinetic event. The extent to which the operating conditions fall below the hydrate dissociation conditions is termed the amount of “sub-cooling”. Figure 0-5 defines sub-cooling for a system, which is a measure of how many degrees into the hydrate region the system is operating.

PRESSURE (bar)

IOGPT Flow Assurance Training

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HYDRATE ZONE

6°C Subcooling

30

HYDRATE FREE ZONE

Figure 0-5:

TEMP (° (°C)

10

4

Hydrate Conditions – Sub Cooling

In most cases, additional laboratory testing is not required to define the hydrate dissociation conditions. Figure 0-6 illustrates an example of field data vs. predicted conditions for three four different fluid samples. 500 Field 1, Measured Field 1, Predicted

450

Field 2, Measured Field 2, Predicted

400

Field 3, Measured Field 3, Predicted

Pressure (bara)

350

300

250

200

150

100

50

0 4

6

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20

22

24

26

Temperature (C)

Figure 0-6: Hydrate Conditions – Actual vs. Predicted Predictions should be compared on a temperature-basis (+/- °C), and NOT on a pressure-basis (+/- bar). Model predictions vs. actual laboratory experiments may be within 1-2°C. However, for high-pressure operations, laboratory testing is recommended, since the data used to tune the commercially available models is limited.

IOGPT Flow Assurance Training

7.1.3.2

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Water Impacts

As noted above, one of the key requirements for hydrate formation is the presence of water. There are two main issues with respect to water. First, the water salinity has an impact on hydrate conditions. The more saline the produced water, the less severe the hydrate conditions. The salts act to inhibit the hydrate formation process. Figure 0-7 below illustrates the effect of produced water salinity on the hydrate curves. 150 Pure Water

140

Seawater 130 Produced Water 120 110

Pressure (bara)

100 90 80 70 60 50 40 30 20 10 0 4

5

6

7

8

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Temperature (C)

Figure 0-7: Hydrate Conditions – Water Salinity In general, using pure water (no salt) is the most conservative approach and forms the basis for hydrate prevention design. However, if the salt content is high and produced water is expected throughout field life, use of the less severe hydrate conditions may result in an overall cost savings to the project development. Second, the amount of water is critical to the hydrate formation. For gas systems, the hydrate formation conditions can be altered if insufficient water is present. It is important to predict the hydrate conditions using a realistic water loading value. For gas export systems, the dehydration specification is based on the hydrate conditions. Figure 0-8 illustrates the hydrate formation pressure as a function of water content (lb/mmscf). As the graph shows, the hydrate formation pressure is sensitive to the water loading. The dehydration specification should be based on the maximum amount of water that can lead to hydrate formation at operating conditions. For example, if the operating pressure of the system in the figure is 300 bar, then the maximum amount of water allowable would be ~5 lb/mmscf.

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600

Hydrate Formation Pressure (bara)

500

400

300

200

100

0 0

2

4

6

8

10

12

14

16

18

20

Water Content (lb/MMSCF)

Figure 0-8:

Dehydration Specifications

For oil systems, there is a “minimum threshold” water cut that is required before hydrates can form and block a pipeline. This water cut varies from project to project, but recent experience has shown that hydrate blockage at water cuts less than 10% may not occur. 7.1.3.3

Thermodynamic Inhibitors

Thermodynamic inhibitors include chemicals such as methanol and glycol (mono-ethylene glycol, diethylene glycol, tri-ethylene glycol). These inhibitors may be added on a continuous basis (gas/condensate systems) or on an intermittent basis to assist with shutdown/start-up operations (oil systems). The inhibitors tend to “shift” the hydrate conditions, making them less severe. For continuous inhibition, the goal is to add sufficient inhibitor to “shift” the hydrate conditions out of the operating region (steady state and shutdown). Figure 0-9 illustrates the effect on the hydrate conditions that various levels of inhibition have.

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350 Pure Water 10% MeOH 300

20% MeOH 30% MeOH

Pressure (bara)

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0 4

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Temperature (C)

Figure 0-9:

Hydrate Conditions – Thermodynamic Inhibitor Effects

Figure 0-10 below illustrates the effect of the hydrate inhibitor on the hydrate conditions at various inhibitor concentrations. Note that the actual laboratory measurements (vs. EOS software predictions) tend to vary widely at the elevated concentrations.

IOGPT Flow Assurance Training

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600 Experiemental - Pure Prediction - Pure Experiemental - 25wt% MeOH

500

Prediction - 25wt% MeOH Experiemental - 35wt% MeOH

Pressure (bara)

400

Prediction - 35wt% MeOH

300

200

100

0 0

5

Figure 0-10:

10

15 Temperature (ºC)

20

25

30

Hydrate Conditions – Thermodynamic Inhibitor Effects

As noted in the graph above, it is highly recommended that hydrate inhibitor testing be carried out for high-pressure systems. If sufficient fluid samples are available and software models predict high inhibitor concentration requirements, hydrate testing should be considered. Hydrate testing for methanol and/or glycol can be carried out using the following methodologies: •

Autoclave – evaluates hydrate formation at a single temperature/pressure, whereby the conditions are held within the hydrate formation region for a long period of time. Temperature/pressure response is monitored to note when gas is taken up from the sample into the hydrate particle.

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Gas Inlet & Pressure monitor Boroscope / videocam Pressurised test gas Sapphire window

PRT probe Constant temperature jacket

Pressure vessel

Fluid Magnetic follower

•

Coolant inlet

Hydrate wheel – evaluates hydrate formation at a single temperature/pressure, through the use of a rotating wheel system. This is much less common than the autoclave tests

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Typically, methanol is the inhibitor of choice for most developments. However, due to volatility issues, as well as downstream crude contamination issues, glycols are being considered more often. Table 0-2 below presents a comparison between methanol and mono-ethylene glycol (MEG) with respect to some common parameters. Table 0-2: Property Cost (approximate $USD/gallon) Density (kg/m3) Viscosity (cP) Flash Point (°C) Vapor pressure (bara) Vapor phase losses (lb/MMSCF) Typical dosage requirements Salt precipitation risk Under-dose hydrate risk Downstream contamination risk Topsides recovery

Methanol vs. Glycol Comparison Methanol (MeOH) $0.65 790 0.75 11 0.31 ~1 Lower Lower Higher Higher Lower

Ethylene Glycol (MEG) $2.00 1145 48 30 0.01 ~0.002 Higher Higher Lower Lower Higher

Thermodynamic Requirements: Methanol is classified as a vapor-phase inhibitor. The relatively low vapor pressure of methanol allows the chemical to partition to the vapor and liquid phases. This is the reason that the inhibition rates are higher for methanol, relative to MEG, since these “vapor phase losses” must be accounted for. By vaporizing into the gas phase, the methanol is allowed to condense out of the gas phase in conjunction with the free water, effectively preventing hydrate formation as the fluid cools and travels away from the injection point. The ability to have inhibitor present in both liquid and gas phases makes it an acceptable choice for use in both restarts and shut-ins. MEG is a liquid-phase inhibitor, which will work best when the MEG can be injected and mixed directly with the free water. On advantage of MEG is that under-injection (injection below the required dosage rate) does not have any negative impacts upon the hydrate formation temperature. On the other hand, under-injection with methanol may actually increase the hydrate formation temperature and make conditions worse than not injecting any inhibitor at all. There is also a concern in regulating the methanol injection rates properly, lest saline waters start to precipitate salts if the injection rate is not properly set. Figure 0-11 and Figure 0-12 illustrate typical inhibitor requirements for methanol/glycol in both an oil system and a gas system, respectively. For oil systems, methanol requirements are typically lower than glycol. For gas systems, methanol requirements are also lower, but only at low pressures. As the pressure increases, the glycol requirements increase at a much slower rate. Thus, for high-pressure systems, glycol may be the preferred inhibitor in terms of volume requirements.

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1.00 MeOH

0.90 MEG

Inhibitor (BBL Inhibitor/MMSCF)

0.80

0.70

0.60

0.50

0.40

0.30

0.20

0.10

0.00 65

90

115

140

165

190

215

240

265

290

315

340

365

390

415

Pressure (bara)

Figure 0-11:

Methanol vs. Glycol Requirements (Oil System)

2.50 MeOH 2.25 MEG 2.00

Inhibitor (BBL Inhibitor/MMSCF)

1.75

1.50

1.25

1.00

0.75

0.50

0.25

0.00 0

50

100

150

200

250

300

350

400

450

500

550

600

650

Pressure (bara)

Figure 0-12:

Methanol vs. Glycol Requirements (Gas System)

700

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Fluid Properties: Relative to methanol, MEG has a higher density/viscosity. With respect to umbilical design, the MEG system might have a marginally larger tubing size requirement due to the increased frictional pressure drop at a given flowrate. However, the flowrate requirements for methanol are also slightly higher than those for MEG. Thus, these two effects are likely essentially offset one another and not require the use of a larger tube size. Aside from umbilical design issues for the two chemicals, the higher density MEG will induce a higher shut-in pressure due to the increased hydrostatic head of the fluid during shutdown/restart. In general, the flowline routings are quite gradual in the area downstream of the manifold. Thus, liquid settle-out during shutdown is likely to be along the flowline route and not all concentrated at the wellhead. The key area for liquid holdup issues during restart will be when the liquid column enters the riser. In addition, the late-life operation of an MEG-based system may result in transport difficulties as the gas velocity drops. For methanol, the increased solubility in the liquid/gas phases will enable the inhibitor to be effectively transported topsides. For MEG, which will remain essentially in the liquid phase, the MEG may start to accumulate in the flowline at a much faster rate than even the water, resulting in an even more pronounced liquid holdup at turndown rates. One final fluid property of the MEG that is advantageous, relative to the methanol, is the decreased flash point. This makes storage and handling much safer. Chemical Recovery: The major advantage that MEG has over methanol is the low volatility in the gas and condensate phase, which makes recovery easier. The efficient recovery from the production fluids means that MEG will not be in sufficient quantities to reduce the price of the sales gas, which may not be the case with the use of methanol as an inhibitor choice. Overall operating costs of a MEG recovery system is less than a methanol recovery system because of the reduced losses to the condensate phase, gas phase and mechanical carryover within the recovery process. The recovery process is also less complex, with fewer components and a smaller required footprint than the methanol recovery process, which reduces the capitol costs maximizes the space available topsides.

IOGPT Flow Assurance Training

7.1.3.4

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Low Dosage Inhibitors

Increasing in popularity in recent years, low dosage hydrate inhibitors (LDHIs) can provide a lowervolume alternative to conventional thermodynamic inhibitors. LDHIs work at dosage rates which are ~1/10 that of methanol/glycol, or ~1-2 vol.% of the water phase, as a rule-of-thumb. Per-unit costs for LDHIs are much higher than thermodynamic inhibitors, but the lower volume requirements make them an economically viable alternative for many projects. LDHIs may be commingled with methanol for ease of transport, particularly over long-distances. LDHIs are typically tailored for a specific fluid, so fluid testing is essential. Since the actual mechanisms for how LDHIs work are not well established, enabling a-priori prediction in software models, similar to thermodynamic inhibitors, is not available. The two primary LDHI classifications are: •

Anti-Agglomerates (AAs) – surfactants that cause the water phase to be suspended as small droplets in the oil or condensate. AAs do require a liquid phase, which may preclude their use in very dry gas systems. Suspended droplet are converted to hydrates, but are transported without blockage. AAs have a typical maximum water cut limit of ~50% and sub-cooling limits of 2025°C, with a typical dosage rate of 1%-2% (based on water phase). Fluid testing for AAs is typically carried out in a rocking cell (shown below), which evaluates hydrate formation at a single temperature/pressure by visual inspection of a pellet which rocks back-and-forth over time until hydrate formation is observed, stopping the pellet movement.

•

Kinetic Hydrate Inhibitors – low molecular weight polymers dissolved in a carrier solvent. Bonding to hydrate surface and prevent nucleation growth for a period of time. Typical carrier times are 48-72 hours, after which the chemical becomes inactive. KHIs have typical sub-cooling limits of 10-12°C (although this is improving over time), with typical dosage rates of 0.5% - 3.5% (based on water phase). Fluid testing for KHIs is typically carried out in an autoclave (previously discussed).

IOGPT Flow Assurance Training

7.1.4

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Mitigation

In the event hydrates have formed and block the flowpath, a number of means are available for removing the blockage. When remediating plugs, multiple hydrate plugs should always be assumed. Trapped pressure may be present between the plugs may result in high-velocity hydrate particle movement and/or pipeline rupture. Typical means of hydrate remediation are: •

Depressurization – the most common form of hydrate mitigation is depressurization. As discussed, hydrate formation requires high pressures. If the pressure can be reduced from the system, then the hydrate may naturally dissociate. For deepwater operations or long-distance tiebacks, removing sufficient pressure may not be feasible. In deepwater service, hydrate formation conditions at seabed temperatures are typically ~10-15 bara. Sufficient liquids often remain in the system, even after depressurization, to maintain a backpressure greater than 15 bara o

In the event that depressurization is a viable option, it is always preferred to depressurize on both sides of the plug. Since multiple plugs may be present, single-sided depressurization presents a safety risk if the plug becomes dislodged and rapidly exits the pipeline. Dual lines are often utilized in deepwater designs to allow for this dual-sided depressurization. If a single line exits, depressurization through the tree via the umbilical line or other accessible conduit may be required.

o

Typical hydrate dissociation is thought to occur in the radial direction, whereby heat is input from the pipe walls, melting the hydrate plug form the outside and reducing the area. Thus, the actual length of the plug is not a significant factor. Once sufficient communication is available across the plug, typically near the pipe walls, the plug may start to move. Figure 0-13 below illustrates an example radial dissociation of a hydrate plug. 1-hour

2-hours

Figure 0-13: o

3-hours

Radial Hydrate Dissociation

The entire hydrate plug does not have to be dissociated to see pressure response across the plug and to achieve particle movement. The factors impacting the rate of radial dissociation are:



Hydrate conditions – as the pressure is decreased, the hydrate temperature will remain in equilibrium with the hydrate pressure. As indicated in the graph below, at very low pressures, the hydrate temperature will reach very cold temperatures, often times sub-ambient. The lower the pressure, the colder the temperature. Figure 0-14 illustrates the hydrate dissociation conditions at low temperatures/low pressures. For a seabed temperature of ~4°C, the pressure would have to be reduced below ~12 bar to allow for dissociation. If the pressure can be reduced further, say 5 bar, the equilibrium hydrate temperature would be ~-5°C.

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300 Pure Water 275

Sea Water Produced Water

250 225

SEABED TEMPERATURE = 4° 4°C Pressure (bara)

200 175 150 125 100 75 50 25 0 -25

-20

-15

-10

-5

0

5

10

15

20

Temperature (C)

Figure 0-14:

Hydrate Dissociation Conditions – Low Pressure

Temperature gradient – the difference between the ambient temperature and the equilibrium hydrate temperature will impact the amount of heat added to the system. The larger the temperature gradient, the greater the driving force for hydrate dissociation. As the previous figure indicates, the hydrate temperature may be some 10-20°C colder than the ambient, thus allowing the “warm” ambient conditions to melt the hydrate Pipeline U-value – the U-value defines the rate of heat addition to the system. For low U-value systems (i.e. pipe-in-pipe), the rate of heat transfer is quite slow, prolonging dissociation times. For high U-value systems (i.e. bare pipe), the rate of heat transfer between the ambient and the hydrate is quite high, decreasing dissociation times. The figure below defines some typical dissociation times as a function of reduction in cross-sectional area. For highly insulated systems, hydrate plug dissociation may take weeks! Figure 0-15 illustrates the % dissociation vs. time for various insulation types. The graph shows that the low U-value system dissociates much slower than the higher U-value system.

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400 P ip e -in -P ip e W e t In s u la tio n

350

B a re P ip e 300

Time (hours)

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0 0%

10%

20%

30%

40%

50%

60%

70%

80%

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% R a d ia l D is s o c ia tio n (% )

Figure 0-15: Hydrate Dissociation – U-value Impacts Plug porosity – most dissociation assumptions are based on a generalized term for the heat of fusion required to melt a plug. In reality, the porosity of the plug will play an important role in dissociation times. The plug porosity is difficult to estimate for a given condition, hence its general exclusion from dissociation models. •

Plug wall friction/minimum differential pressure requirement – similar to porosity, the frictional coefficient between the hydrate and the pipe wall plays a role in defining the mobility of the plug. The greater the wall friction, the more heat is required to melt the hydrate and allow movement. In addition, once the plug starts to dissociate, there is a minimum amount of pressure required to induce movement. Both of these terms are still relatively unknown within the industry, so they are often omitted from classic dissociation models.

•

Active heating (direct/indirect) – electrically induced heat is applied to the pipeline area surrounding the hydrate plug (if location is known). Over-pressure concerns during the heating process should be taken into account and caution is to be exercised. This is typically only an option if an electrically heated pipeline has been designed, as localized heat input is difficult for conventional systems, particularly in subsea environments. Other heat-input systems (i.e. Petrobras’ SGN exothermic reaction systems) are available for more specific remediation requirements.

•

Chemical addition – methanol can be delivered to the hydrate plug location (if known) and slowly act to dissociate the hydrate. Similar to heating, this technique may be impossible in subsea systems with long-distance tiebacks and/or deepwater environments

•

Coiled tubing – physical remediation via coiled tubing can be accomplished, provided the coiled tubing can access the plug. Coiled tubing effective lengths are increasing within the industry, capable of 1-5 miles, depending on the application/geometry

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Chapter 8 : Wax formation and prevention 8.1

PARAFFIN/WAX FORMATION Wax is a solid that precipitates from the production oil/condensate and consists of a wide range of high molecular weight straight chain, normal paraffins and/or branched or cyclic paraffins. The temperature where the first crystals occur is called the cloud point or Wax Appearance Temperature (WAT). The primary flow assurance challenges that can result from wax formation are wax deposition and gel formation. This section will focus on wax deposition and Section 8.2 will focus on gel formation.

In general terms, wax deposition occurs at a rate given by the following equation:

DepositionRate = D *

dC dT * dT dr

D: Diffusion Coefficient dC/dT: Wax concentration gradient versus temperature dT/dr: Temperature gradient in the radial direction Various correlations currently exist for the diffusion coefficient term listed in the equation above, but the Hayduk-Minhas equation has been found in the University of Tulsa Paraffin Deposition JIP to be most applicable to n-paraffins in alkane solvents. The Hayduk-Minhas diffusion coefficient correlation is as follows:

D= A: Tw: µ: VA: D:

A * Tw1.47 * µ γ 10.2 ,γ = − 0.791 0.71 VA VA

Diffusion Parameter (default value is 13.3 E-8) Pipe Wall Temperature (K) Viscosity (cP) Molar Volume of the Paraffin (cm3/gmol) Diffusion Coefficient (cm²/s)

As reflected in the equations listed above, four key factors are required for wax deposition to occur: 1. WAT > ambient temperature 2. Fluid temperature < WAT 3. Positive heat flux (wax deposition does not occur when the fluid temperature is ambient)

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4. Shear (wax deposition does not occur without fluid movement) Wax can deposit on surfaces such as tubulars and pipe walls. Over time, the build-up of the solid deposit will reduce the internal diameter and may eventually block the line. A second effect, which will likely cause operational problems much earlier, is that the solid deposit increases the surface roughness of the pipe wall. This causes an increase in the pressure drop that can result in higher pumping costs or reduced throughput. Wax build-up on tubulars and tiebacks can effectively choke back the wells and can kill a well even though the line is not totally blocked. Total blockages of flowlines and pipelines due to wax build-up have occurred, but are still rare. The following sections address some of the specific risks, testing required to quantify wax deposition, and prevention/remediation techniques.

8.1.1

Risk

The following are some common risks associated with paraffin/wax formation: •

Waxes will deposit on various segments of the subsea system (wellbores, flowlines, production risers, surface processing facilities). If the temperature of the pipe wall drops to the WAT, wax will start to form and some of the crystals will stick to the pipe walls. The wax deposit can build up and if not addressed can lead to blockage and loss of serviceability of the subsea system.

•

Wax will potentially appear in lumps in the processing systems, upsetting separator controls and interfering with processing.

•

Wax will arrive in potentially large quantities in pipeline pig traps on pigging and will present a blockage and disposal problem.

•

Wax will present oil export and transportation concerns, and sales transportation planning, valuation and marketing will need to recognize these concerns.

8.1.2

Testing Unlike available hydrate prediction models that will accurately predict hydrate dissociation conditions for a given fluid; the currently available WAT/wax deposition prediction methods have a large degree of uncertainty without supporting laboratory data. Therefore, quality laboratory measurements are required to understand the degree to which a fluid may have a waxing potential problem. Several measurements are available, which can determine the conditions in which wax deposition will occur and what the general rates of deposition are for a given fluid. For any waxing potential tests that are completed, quality samples are essential to ensure quality laboratory data is obtained. In general, DST (drill stem test) samples are preferred for waxing potential analyses because they are less likely to contain drilling mud contamination than other types of samples. Fluid samples should also be taken from the production zones that are likely to be produced and there should be an understanding as to the heterogeneity of the reservoir and therefore the representativeness of the samples. Additionally, when sampling in the field, the fluid samples should be taken above the WAT of the fluid to ensure that the wax hasn’t been depleted from the sample at the time of sampling. When transferring samples from the field to the laboratory, care should be taken to ensure that the samples are homogeneous and no wax is removed from the samples during the process of transfer. Lastly, the pre-treatment procedure used by the laboratory should ensure that the fluids are pre-treated to approximately 80°C and the sample transfers should minimize light-ends loss in the samples as much as possible, in order to provide representative conditions what match expected production fluids.

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8.1.2.1

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Wax Appearance Temperature (WAT)

Of all of the measurements that can be completed to determine the waxing potential of a given fluid, the most important measurement is the cloud point or Wax Appearance Temperature (WAT) of the fluid. The WAT is a critical property since wax deposition can begin whenever the temperature of any surface in contact with the crude oil drops below the cloud point. WAT measurements are typically completed at stock tank oil conditions but they can also be completed at live conditions as well. A summary of the various commercially available laboratory techniques for WAT is illustrated in Table 0-3. The measured WATs from the various laboratory techniques can vary by ±15°C and in some instances, it has been seen that the measured WATs can vary by as much as 30°C from technique to technique and from laboratory to laboratory. The sample volumes required to complete the measurements vary from technique to technique and should be verified by the laboratories completing the analyses. As a point of reference, 10 to 20 mL of dead oil/condensate is required for a WAT measurement by crosspolarized microscopy (CPM). Table 0-3: Test Method Cross-Polarized Microscopy (CPM)

WAT Measurement Techniques

Advantages Detection of first wax crystal and subsequent detection of growth rates and morphology.

Disadvantages Difficult to use at high pressure.

Detects phase change. Quick, easy, reliable. Can infer solid phase content.

Filter plugging

Can be used for highpressure tests. Simple equipment.

Recommended method for WAT measurement. Widely used reliable method with high sensitivity.

Small sample size required.

Differential Scanning Calorimetry (DSC)

Recommendation

Requires low cooling rates and high quality samples. Fast, unrealistic cooling rates required for good sensitivity. Can give low values (typically ~5°C lower than CPM measurements) Very fine filters required for accurate determination of WAT.

Widely used, generally repeatable method. Requires good sample quality. Sensitivity can be poor for low wax contents. Somewhat subjective method that shouldn’t be used as primary WAT measurement. May be confused by precipitation of other solids.

Viscosity

Large sample size adds to representiveness. Can use high-pressure viscometer.

Subjective interpretation Does not work for low wax content fluids.

Possibly recommended for live crudes with marked WAT, but should be used with caution.

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The WAT of the fluid is effectively a thermodynamic property that describes the temperature at which solids will begin to precipitate out of solution. As illustrated in the table, the cross-polarized microscopy (CPM) method is the most sensitive method for measuring WAT. Therefore, the WAT measurement is a kinetic measurement that measures the crystal growth of the fluid and is thus time and energy dependent. Consequently, the measured WAT is dependent on the way in which the sample is handled prior to the measurement, and the cooling rate used in the laboratory. It is recommended that a cooling rate of 0.05 to 0.1°C/minute be used to obtain the most accurate WAT measurements. The photos below illustrate photos from a CPM measurement for a gas/condensate fluid at ambient conditions (after the fluid has cooled significantly below the WAT).

As discussed in Section 8.1.2, quality of samples is critical in measuring the correct WAT of a fluid. In particular, oil based mud sample contamination can significantly impact the WAT measurements. Because the most sensitive WAT measurement technique (CPM) relies on visual inspection of a magnified sample as it is cooled, any contamination of the sample clouds the field of vision and reduces the precision of the measurement. The pictures below illustrate a heavily contaminated sample significantly above the WAT and 20°C below the WAT (at ambient seabed temperature).

As illustrated in the pictures, if a sample is heavily contaminated, it can be difficult to differentiate between oil based mud contamination and the exact point at which wax crystal formation begins to occur. Therefore, for highly contaminated samples, more than one type of WAT measurement is recommended to determine the true WAT of the sample. While temperature is the primary factor affecting wax crystallization, pressure also plays a role. Light ends (which act as solvent for waxes) are at the highest concentration in the crude oil at the bubble or saturation point; consequently, the WAT is lowest at the bubble point. Above the bubble point, no additional light ends are dissolved in the crude oil; however, the pressure continues to increase which causes the WAT to increase. Below the bubble point, light ends are removed from the crude oil as the pressure drops; therefore, the WAT increases as the pressure decreases below the bubble point. The effect of light end dissolution on the WAT is illustrated in Figure 0-16 and Figure 0-17. In Figure 0-16, the WAT of the live production fluid decreases with increasing pressure up until the bubble point of the fluid and then begins increasing with increasing pressure. Figure 0-17, the dead fluid is essentially at the bubble point at stock tank conditions and therefore the WAT of the dead fluid will always increase with increasing pressure.

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Figure 0-16:

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Live WAT for Production Fluid

Figure 0-17: Live WAT: Production Fluid vs. Dead Fluid In addition to laboratory tests to measure WAT, thermodynamic packages can predict the WAT of the fluid based upon the standard fluid composition and extended n-paraffin composition (to be discussed in Section 8.1.2.2). These models provide acceptable information to verify that the laboratory measured WATs is consistent with the other measured fluid properties. However, the WAT predictions cannot be

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used for design as they can vary from the measured WATs by 5 to 15°C. Additionally, if the n-paraffin composition of the fluid is unknown and/or the samples are heavily contaminated, the accuracy of the WAT predictions reduces even further. For design purposes, WAT is the critical factor that is used to evaluate the potential of the production fluid to cause wax problems in the system. Yet if wax deposition does occur, it is important to note that there is a significant difference between the point at which wax will begin to form, and the temperature required to completely melt the wax. In general, the melting point of wax will be 10 to 20°C above the WAT of the fluid and if the wax has been allowed to deposit over a long period of time (causing a hard deposit), the melting point of the wax can be as high as 40°C or more above the WAT of the fluid. However, to remove a wax deposit in the system after it forms, the temperature does not need to be increased above the melting point of the wax. Wax will re-dissolve into solution at temperatures greater than the WAT and below the wax melting point. A slurry of wax particles will then be transported in the bulk fluid and the majority of the wax deposit will eventually be removed. Note, however, that this slurry of wax particles may be highly viscous and impact the hydraulic performance of the system. 8.1.2.2

N-Paraffin Composition/Wax Content

The n-paraffin composition (or wax content) of the fluid is another parameter that helps to determine the waxing potential of the fluid. The n-paraffin composition of the fluid is important as it influences the thermodynamic properties of the fluid (such as WAT) that are predicted by thermodynamic models. It dictates the calculated concentration gradient of wax in the fluid vs. temperature As was discussed in Section 0, the rate of wax deposition is effectively a function of the diffusion coefficient of the fluid, the concentration gradient of wax in the fluid versus temperature, and the temperature gradient of the fluid in the radial direction. Two primary laboratory analyses are currently available to measure the wax content in the fluid: 1. Precipitation Method 2. High Temperature Gas Chromatography (HTGC) The precipitation method effectively removes asphaltenes from the sample, chills the sample to approximately -32°C, filters the solid from the sample, and then reports the wax content as the wt.% of the filtered solid in relation to the total mass of the original sample. In contrast, the HTGC method (or extended n-paraffin analysis) is a compositional method that determines the n-paraffin composition of all n-paraffin components between approximately C15 and C100. As a standard GC analysis only provides high-resolution data up to approximately C30, a separate high temperature GC analysis is required to obtain high-resolution data at carbon numbers approximately above C30. An example extended n-paraffin distribution from an HTGC analysis is illustrated in Figure 0-18. The sample volume required for an HTGC analysis will vary from laboratory to laboratory, but as a point of reference is approximately 5 to 10 mL.

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Figure 0-18: Extended n-paraffin distribution As shown in Figure 0-18, the wax content of the fluid is heavily influenced by the n-paraffin components at relatively low carbon numbers (between C15 and C30). However, the WAT of the fluid and the deposition potential of the fluid can be heavily dictated by the n-paraffin distribution at much higher carbon numbers. This is also illustrated in Figure 0-19 for two example fluids that have relatively similar wax contents (C20+ n-paraffin contents of 9.6 versus 9.4 wt.%), but have very different WATs (27°C compared to 54°C). Therefore, in comparison to an HTGC analyses, wax content measurements from precipitation methods provide a quick screening method to determine the amount of wax in the sample, but they should be used with caution, as they do not provide any information regarding the n-paraffin distribution of the sample.

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Figure 0-19: 8.1.2.3

Wax Content vs. WAT

Viscosity

The viscosity of the fluid is important in terms of waxing potential because the viscosity significantly influences how rapidly the wax diffuses through the fluid to form a deposit. This is illustrated in the Hayduk-Minhas correlation in Section 0, in which the rate of wax deposition is inversely proportional to the viscosity of the fluid. In other words, the lower the viscosity of the fluid, the higher the rate of deposition in the system, and vice versa. The fluid viscosity is also important as it provides a general indication of the WAT of the fluid. In order to obtain useful viscosity data, viscosities should be measured by shearing the samples at a constant rate and by cooling the sample at a constant rate from above the WAT to the minimum ambient temperature expected in the field. As was discussed with WAT measurements, care should be taken to ensure the fluids are properly handled prior to starting the measurements, a reasonable cooling rate should be used for the measurements (it is recommended that a cooling rate of 0.5°C/minute be used to obtain the most accurate viscosity data), and a sealed viscometer should be used to minimize light-ends loss in the sample. Example stock tank oil viscosity data versus temperature and shear rate is illustrated in Figure 0-20. The sample volume required for stock tank viscosity measurements will vary from laboratory to laboratory, but as a point of reference is typically 200 mL or less for each shear rate evaluated.

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Figure 0-20: Stock Tank Viscosities vs. Temperature As illustrated in Figure 0-20, the viscosities of the example stock tank fluid inflect significantly (on a logarithmic basis) at temperature of 17°C. This inflection is evidence that enough paraffin has precipitated out of solution at 17°C that it is impacting the viscosity of the fluid. As discussed in 8.1.2.1, viscosity measurements can be used to determine the WAT of the fluid. However, this method of determining WAT is not recommended as a significant amount of paraffin has to drop out of solution before it will impact the viscosity of the fluid (for the fluid presented in Figure 0-20, the WAT measured by CPM was 24°C while the inflection point of the viscosities occurs at 17°C). In addition to laboratory tests to measure the fluid viscosities, thermodynamic packages can predict the viscosities of the fluid at temperatures above the WAT. However, because thermodynamic packages assume that the fluids act as Newtonian fluids, the models do not correctly predict the fluid viscosities below the WAT of the fluid. Additionally, because fluid viscosities have a large impact on the rates of deposition that will be predicted by any wax deposition model, thermodynamic models should be tuned to match the experimental laboratory data as closely as possible in order to ensure the most accurate wax deposition rates possible. Lastly, it should be noted that if an emulsion forms, it will likely impact the rates of deposition that will occur for a given fluid. Currently, limited data is available regarding this topic, but because emulsions increase viscosities so dramatically, the rates of wax deposition will decrease in a similar fashion. It is also speculated that at very high water cuts (likely at the inversion point of the emulsion), wax deposition will cease entirely. Studies are currently ongoing at the various paraffin JIPs to validate this assertion. 8.1.2.4

Wax Deposition Rates

Other than WAT measurements, determining wax deposition rates is the second most important waxing potential laboratory measurement. The results of these measurements provide a general understanding of the expected fluid wax deposition rates and (of greater value to system design) can provide further data as input into a wax deposition model. A wax deposition model allows for the modeling of the expected rates of deposition in an actual or proposed production system. Two primary laboratory analyses are currently available to measure the wax deposition rates of the fluid:

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1. Cold finger – this apparatus consists of a test tube-shaped metal finger cooled by flowing chilled fluid through the finger, and a heated stirred container for an oil sample. After the test is completed, the finger can be removed and the wax deposit can be visually inspected and weighed to estimate the deposition rate during the test. The primary advantages for this measurement are that it allows for direct quantitative and qualitative measurements of the wax deposit, it requires a small sample size, and allows for better temperature control than the flow loop test. However, the disadvantages of this type of measurement are that it is unable to match turbulent flow conditions (which would be expected in the field), it doesn’t directly match the shear and flow conditions expected in the field, and the wax deposition rates have a large degree of uncertainty because they are estimated after the measurements are completed. Because the rates are estimated after the measurement is complete (by weighing the total deposit that occurs on the cold finger), the cold finger measurement does not take into account wax deposition rate changes over time which are highly likely in the test because the small sample size will likely deplete over time.

2. Flow loop – a flow loop is a pipe in pipe heat exchanger in which the cold fluid is pumped through the shell side and the oil is heated and pumped through the tube side. The wax deposition rate is calculated by measuring the pressure drop increase across the tube side and by correlating the pressure drop to wax deposition volume increase. The primary advantages for this measurement are that it more closely matches shear and flow conditions in the field, it can achieve turbulent flow conditions if the diameter is large enough, and based upon correlations, it can determine the wax deposition rates versus time (and is therefore less susceptible than the cold finger to sample depletion). The disadvantage of this type of measurement is that it requires a large sample size (as a point of reference, 2 liters of sample or more for the entire analysis), and it can be difficult to directly quantify/qualify the deposit (only possible by “pigging” flowloop at end of test to validate the correlations used to estimate wax deposition thickness over time).

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Both methods for measuring wax deposition rate provide the opportunity to directly compare the deposition rates found in the measurements to the deposition rates previously measured for other samples (giving a general indication as to the qualitative level of wax deposition expected for the fluid). However, as mentioned previously, the real value of these measurements is the ability to correlate the experimental laboratory data to a diffusion coefficient that is specific for the given fluid. This diffusion coefficient can then be used in wax deposition modeling to predict the rates of deposition in an actual production system. Using the wax deposition rate equation and the Hayduk-Minhas diffusion coefficient correlation discussed in Section 0, the rates of wax deposition can be predicted for a series of flow loop measurements. Figure 0-21 illustrates an example of the experimentally measured mass fluxes (similar to the deposition rates) versus the predicted mass fluxes assuming the default Hayduk-Minhas correlation (‘A’ value equal to 13.3E-8).

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1.8E-05 Measured 170 1/s Predicted 170 1/s

1.6E-05

Measured 511 1/s Predicted 511 1/s

Mass Flux at Wall (kg/m2-s)

1.4E-05

1.2E-05

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Figure 0-21: Measured vs. Predicted Mass Fluxes (13.3E-8 Diffusion Parameter) As illustrated in Figure 0-21, the predicted mass fluxes using the default Hayduk-Minhas correlation (‘A’ value equal to 13.3E-8), greatly over predict the wax deposition rates that are measured in the laboratory for the example fluid. Therefore, the diffusion parameter (or ‘A’ value) in the equation has to be fit to more accurately predict the wax deposition rates that were measured in the laboratory. Figure 0-22 illustrates the predicted mass fluxes when the diffusion parameter is fit to a value that is consistent with the laboratory measurements (‘A’ value equal to 6.65E-8). 1.0E-05

Measured 170 1/s Predicted 170 1/s (c=0) Measured 511 1/s Predicted 511 1/s (c=0)

9.0E-06

8.0E-06

Mass Flux Wall (kg/m2-s)

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Figure 0-22: Measured vs. Predicted Mass Fluxes (6.65E-8 Diffusion Parameter) Using this methodology, the experimentally calculated diffusion parameter (‘A’ value equal to 6.65E-8) can then be used to perform wax deposition modeling. Based upon the deposition rate equation discussed in Section 0, the wax deposition model uses the following pieces of information to predict the deposition rates in the system:

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1. Parameters from the actual system configuration (geometry, U-value, etc.) 2. Steady state data from the system configuration (system temperatures, pressures, flowrates, holdups, etc.) 3. Fluid properties from either experimental measurements or predictions (diffusion coefficient, viscosities, wax concentration gradients, etc.) An example set of results from a wax deposition model is illustrated in Figure 0-23 for a case with a wet insulated flowline and riser. 3.0

2.5

Wax Thickness (mm)

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0 days

10 days

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Figure 0-23:

Example Wax Deposition Modeling Case

9

10

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Based upon the results from the wax deposition modeling, an expected pigging frequency can be estimated for a range of production cases and system configurations. The various criteria that can be used to estimate pigging frequency are as follows: 1. Limit pressure drop across pig (3.5 to 7.0 bar) 2. Limit total wax in front of pig (50 bbls) 3. Limit wax thickness vs. cross-sectional area (10%) 4. Limit absolute wax thickness a. 1 mm for slow/hard deposits (consistent with high levels of insulation) b. 4 mm for fast/soft deposits (consistent with low levels of insulation) It is important to note that the currently available wax deposition models have several areas of uncertainty that need to be understood in order to provide proper perspective on the wax deposition modeling results. The primary area of uncertainty in the models is that most of the industry data is available for singlephase systems operating in the laminar flow regime at near-ambient pressure. This data is then scaled to actual subsea systems that are typically operating in multiphase flow, in the turbulent flow regime at pressures significantly higher than ambient. Because of this, most wax deposition models are typically conservative and contain a reasonable amount of uncertainty in the results. Other areas of uncertainty in the models include the effect of water cut, the amount of wax vs. liquids in the deposits, and the effect (if any) of wax “sloughing” on the deposition rate. In terms of the water cut, it is currently assumed that wax deposition will cease to occur at very high water cuts. However, the point at which the water cut forces wax deposition to stop is currently unknown and the data that currently exists regarding this phenomenon is inclusive. In terms of the wax/liquid ratio in the deposit, this is currently one of the biggest areas of uncertainty in terms of wax deposition predictions. In general, it is assumed that for systems that do not deposit for a long period of time, the deposit is made up of 20% wax and 80% liquid for black oil systems and 50% wax and 50% liquid for gas condensate systems. However, experimental data suggests that the wax contents can vary greatly from fluid to fluid and depending upon the conditions used to create the deposits (the wax content in the deposit will increase over time, which will impact deposition rates over a long period of time). Lastly, the effect of “sloughing” (or the deposit removal from the wall at high fluid velocities) is uncertain as to how it occurs or even whether or not it does occur. 8.1.2.5

Paraffin Inhibitors

If a fluid is shown to have a high waxing potential, continuous paraffin inhibition can be used to slow the rate of wax deposition in a subsea system. However, none of the currently available paraffin inhibitors eliminate wax deposition altogether. Therefore, once an appreciable level of wax has deposited, an additional remediation method (such as pigging, hot oil circulation, etc.) will be required to remove wax from subsea system. Additionally, unlike hydrate inhibitors whose effectiveness is relatively independent from the fluid properties (only the dosage rates will change from production fluid to production fluid), laboratory testing must be completed to determine whether or not a paraffin inhibitor will be effective and the required dosage rate for the recommended chemical. Lastly, paraffin inhibitors should be added to the production fluid at temperatures ~10°C above the WAT of the fluid to ensure maximum inhibitor efficiency. Currently available paraffin inhibitors are as follows (note that these chemicals are similar in structure for both paraffin inhibitors and pour point depressants): 1. Crystal Modifiers – these inhibitors are very large molecules of paraffinic nature and as the oil cools and paraffin crystals start to form, the inhibitor will co-crystallize within the paraffin structure, disrupting the structure and hindering further growth.

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2. Wax Dispersants – these inhibitors penetrate and bind to the paraffin crystals, restricting further growth of the paraffin crystals and dispersing them into the liquid phase. In order to test the effectiveness of the paraffin inhibitors, chemical vendors will usually perform several screening level laboratory tests to determine an optimum inhibitors and dosage rates (these tests typically consist of cold finger and flow loop testing). To ensure the effectiveness of the paraffin inhibitor relative to the un-inhibited fluid, it is recommended that multiple laboratories select paraffin inhibitors for the production fluid, and then independent laboratory testing is completed to determine the effectiveness of the paraffin inhibitor. For example, if a suite of waxing potential measurements is completed on the inhibited and un-inhibited fluids, these test results could then be used in wax deposition modeling to provide a better understanding of the effect of paraffin inhibitor on the pigging frequency in the system. It is important to note that similar inhibitors are used to reduce wax deposition rates and to reduce the gelling potential of the fluid (the gelling potential of the fluid will be discussed in more detail in Section 8.2). However, the same chemical may not necessarily meet these two objectives. For example, a pour point depressant may reduce the pour point below ambient temperature by reducing the viscosities in the system. From a wax deposition perspective, however, reduced viscosities may actually increase the rates of wax deposition in the system (recall from Section 8.1.2.3 that wax deposition rate is inversely proportional to viscosity). Therefore, if the production fluid in question has both a wax deposition and a gel formation problem, the recommended paraffin inhibitor from the chemical vendors should ensure that both issues are addressed.

8.1.3

Prevention

Wax deposition prevention is typically accomplished through thermal control of the system. This includes providing sufficient insulation to keep steady state operation above the WAT. Thermal control can also be maintained via active heating through hot fluid circulation (bundles) or electrical heating.

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8.1.4

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Mitigation

In the event wax deposition has occurred in the system, a number of means are available for removing the wax deposit from the wax wall. Typical means of wax deposition remediation are: •

Pigging – this method involves pigging the entire length of the looped subsea tiebacks (which may require shutting down the system). This is the most common remediation method for deepwater systems after wax deposition has occurred. This is because pigging removes the wax faster than chemicals can dissolve the deposits and may be more economical than active heating. Nonetheless, if pigging is used to remediate a wax deposit, additional topsides equipment will be required and there may be topsides liquids handling problems when the pig returns to the host facility. Additionally, temporary loss of production or drop in production is a potential drawback of using routine pigging to remediate wax deposits.

•

Hot oil circulation – this method involves circulating hot condensate at a temperature sufficient to melt the wax deposit (which may require shutting down production). The melting point of the wax deposit will vary depending how long deposition has occurred, but the melting point of the fluid is typically at least 10°C higher than the WAT of the fluid. Therefore, the discharge temperature has to be warm enough and the flowrate fast enough to ensure that the circulating fluid arrives above the melting point of the deposit. Hot oil circulation works best for systems with a reasonable level of passive insulation and relatively short subsea tiebacks. If the levels of insulation on the tiebacks are too low or the tieback distances are too long, significant topsides equipment (heaters, pumps, etc.) will be required to ensure the “hot oil” returns above the melting point of the wax deposit.

•

Chemical addition – the use of continuous paraffin inhibition (either downhole or at the wellhead tree) to reduce the rate of wax deposition in the subsea tiebacks. Paraffin inhibition is discussed in more detail in Section 8.1.2.5.

•

Active heating (direct/indirect) – electrically induced heat is applied to the area surrounding the wax deposit (if location is known). This is typically only an option if an electrically heated pipeline has been designed, as localized heat input is difficult for conventional systems, particularly in subsea environments. Other heat-input systems (i.e. Petrobras’ SGN exothermic reaction systems) are available for more specific remediation requirements.

•

Coiled tubing – physical remediation via coiled tubing can be accomplished, provided the coiled tubing can access the deposit. Coiled tubing is used to inject a chemical solution (either toluene or xylene) into the tieback to dissolve the wax deposit. Coiled tubing effective lengths are increasing within the industry, capable of 1-5 miles, depending on the application/geometry

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8.2

page 92

WAX GELATION

In addition to wax deposition, wax gelation is another flow assurance challenge caused by highly paraffinic fluids. Gel formation occurs when oil or condensate is at a temperature below its WAT (known as the pour point) and wax crystals interact to form a matrix structure that may extend throughout the entire fluid.

From a flow assurance perspective, the primary concern with wax gelation is not whether or not the fluid falls below the pour point and gel formation occurs, but whether or not the resulting gel can flow during normal operation (in other words, if the viscosity of the fluid becomes excessive) or if the gel can be “broken” after a shutdown. If the fluid is left to cool to seabed conditions during shutdown, the fluid gel strength may be such that allowing the fluid to gel may result in the complete loss of various parts of the subsea system. The gel strength of the fluid can be scaled up to the required restart pressure of full size pipelines using the simplified equation below (which assumes the gel strength is constant throughout the gel plug and the entire plug will yield simultaneously):

∆P = 4τL/D where:

τ: L: D: ∆P:

Yield Strength (Pa) flowline length (m) flowline ID (m) restart pressure (Pa)

The following sections address some of the specific risks, testing required to quantify wax gelation, and prevention/remediation techniques.

IOGPT Flow Assurance Training

8.2.1

page 93

Risk

The following are some common risks associated with paraffin wax gelation: •

Production fluid may gel if allowed to cool in wells and flowlines. However, the presence of light ends in the production fluid has a dramatic effect on reducing the pour point/yield strength. Additionally, a significant cross section of the well/flowline has to be filled with oil/condensate in order for gel formation to block the well/flowline.

•

If production fluid cools in the well/flowlines and gels it will have to be mechanically removed, and this presents risks of well /flowline loss.

•

Gel will potentially occur in topsides oil/condensate storage areas, interfering with processing and potentially requiring additional topsides equipment.

•

Production fluid may gel if allowed to cool in export pipelines. This gelling behavior may be practically irreversible, and can lead to loss of the export pipeline.

•

Dead fluid displacement during shutdown may interfere as a hydrate prevention means because the required pressure during restart may be excessive due to gel formation. Therefore, diesel or water may be required to displace the lines during shutdown, which may lead to additional topsides equipment/cost.

8.2.2

Testing There currently are no quality commercially available models available to predict the pour point and gel strength of the production fluid. Therefore, as was the case with wax deposition, quality laboratory measurements are required to understand the degree to which a fluid may have a gel formation problem. When performing gel formation measurements, the field sampling and laboratory handling precautions discussed for waxing potential measurements should be followed to ensure quality gel formation results. In addition, because gel formation is typically a problem during shutdown, the laboratory measurements performed should try to match the conditions in the field as closely as possible. Because the gel formation measurements can vary significantly depending upon the pre-treatment method used to perform the laboratory testing, this means that the following parts of the laboratory tests should match field conditions as closely as possible: 1. Pre-treatment temperature of 80°C to erase the “thermal history” of the sample and make it more representative of reservoir conditions 2. Shear rate/temperature prior to cooling down the fluid 3. Cooldown rate during shutdown 4. Ambient temperature hold time prior to test There are currently two primary laboratory tests that are performed to evaluate the gel formation of the fluid: pour point (Section 8.2.2.1) and gel strength (Section 8.2.2.2).

IOGPT Flow Assurance Training

8.2.2.1

page 94

Pour Point

The pour point is defined as the lowest temperature at which the crude oil can be poured under force of gravity. The industry standard pour point measurement is defined by the IP 15 or ASTM D97 methods, which requires approximately 40 mL of sample and should be completed with two samples in parallel. These methods are very simple and follow the following basic procedure: 1. The sample is warmed to temperatures above the pour point (the standard method calls for a pretreatment temperature of 45°C, but a pre-treatment temperature of 80°C should be used as discussed in Section 8.2.2). 2. When the fluid temperature is cooled down to 45°C, the sample is transferred to a clear sample cylinder that is then placed into a 24°C temperature bath. The sample is then allowed to rapidly cool and a thermometer placed in the sample cylinder monitors the fluid temperature. 3. As the fluid temperature decreases, the sample cylinder is removed from the temperature bath in 3°C increments. Each time the sample is removed from the bath, it is “turned horizontal” to visually inspect if the fluid has stopped moving. 4. The pour point is defined as 3°C above the point in which the fluid visually stops moving when it is removed from the temperature bath. 5. If the pour point of the fluid hasn’t been reached by the time the fluid temperature drops to 27°C, the sample is then moved to a 0°C bath. If the pour point of the fluid hasn’t been reached when the fluid temperature drops to 9°C, the sample is then moved to a –18°C bath. Clearly, the procedure to measure the pour point of the fluid is a crude method that may or may not match field conditions (the published accuracy of the measurement is ±3°F). Therefore, the results from a standard pour point measurement should be used with extreme caution. If the results from the measurement indicate that the pour point of the fluid will be greater than ambient temperature, additional testing which more closely reflects actual system operating conditions (including the parameters listed in Section 8.2.2) should be completed to determine the extent of the problem. If the standard pour point measurement indicates that the dead oil pour point will be greater than ambient seabed temperatures, live oil pour point measurements should be completed over the range of pressures expected in the system (live oil pour point measurements can either be completed in a modified PVT cell or a pressurized viscometer). Similar to the WAT, the pour point will reduce as pressure is added to the system and additional light ends are dissolved into solution. The effect of light end dissolution on the pour point is illustrated in Figure 0-24. In this example case, the ambient seabed temperature is approximately 4°C. Therefore, when the pressure in the system is greater than 200 bara, the pour point of the fluid will be less than ambient seabed temperature (assumed to be the minimum temperature throughout the system). Depending upon the operating and shut-in pressures in the system, gel formation in this case may be avoided by simply keeping the system at elevated pressure.

IOGPT Flow Assurance Training

Figure 0-24: 8.2.2.2

page 95

Live Pour Point for Production Fluid

Yield Strength

If pour point measurements indicate that gel formation is likely for the production fluid at temperatures above the minimum ambient seabed temperature, yield strength (also referred to gel strength) measurements are required to determine the extent of the gel formation problem. Yield strength measurements can be completed by either a viscometer or a flowloop, but the basic procedure calls for allowing gel formation to occur and then breaking the gel to determine its yield strength. Before the gel is broken in the measurement, the following general procedure is followed: 1. The fluid is sheared at temperatures above the pour point (to reflect steady state operation in the system). 2. After shearing, the fluid is cooled from an elevated temperature to ambient seabed temperature. The cooling rate in the measurement matches the cooling rate estimated in the field (based upon the likely heat transfer properties of the system). 3. After the fluid is cooled to ambient seabed temperature, the fluid is held at constant temperature for a specified amount of time. The longer the fluid is held at constant temperature, the higher the yield strength of the fluid will be. 4. At the desired time, the gel is broken by either rotating a vane in a viscometer or by pumping fluid through the flowloop. Note that the result from the measurement will vary greatly depending upon how quickly the gel is broken. Therefore, the rate at which the gel is broken should be agreed upon with the laboratory prior to the completion of the measurement. Because yield strength measurements must match actual system operating conditions as closely as possible and must also ensure that the gel matrix is not disturbed during the process of the measurement, these measurements can be very complicated. To ensure the highest quality results, the procedures used to perform the measurements should be clearly understood prior to starting the measurements. As

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discussed in Section 8.2.2, the results of the measurements can vary significantly depending upon the steps used to complete the measurements so care should be taken in the measurements and the results should be used with caution. Additionally, the design criteria to ensure gel formation does not occur should be taken into consideration prior to completing the measurement. For example, if the subsea system is going to be designed assuming the production flowlines can always be restarted after a shutdown duration of 48 hours, then the yield strength measurements should be completed after a hold time of 48 hours to ensure the laboratory measurements provide the most stringent restart pressure requirements. In general, it is preferred that gel strength measurement be completed in flowloops because the results more accurately correlate with field conditions, are generally less conservative than viscometer measurements, and some flowloops can accommodate live conditions. However, flowloop yield strength measurements typically require large sample volumes (~2 liters or more per test depending upon the diameter of the flowloops), whereas viscometer measurements require significantly less sample volume (~50 mL or more per test, depending upon the specific viscometer used in the analysis). As a point of reference, an example flowloop used for gel strength measurements is illustrated in the picture below.

If flowloop yield strength measurements are completed, the results from the measurement will look similar to Figure 0-25. In the case illustrated, the restart pressure associated with the flowloop was 0.41 bara, which corresponded to a yield strength for the fluid of 89 Pa (based upon the equation previously presented in Section 8.2).

IOGPT Flow Assurance Training

page 97

0.45

Peak ∆P = 0.41 bara (ττ = 89 Pa) 0.4

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Figure 0-25:

Yield Strength for Production Fluid

As is the case with other waxing potential measurements, the majority of yield strength measurements are completed at stock tank conditions, but the measurements can also be completed at live conditions (in a flowloop apparatus only) to illustrate the impact of light-end dissolution on the yield strength of the fluid. Example live yield strength measurements are illustrated in Figure 0-26 in which the yield strength of the fluid reduces from 40 Pa at stock tank conditions to 5 Pa at 100 bara. In general, live gel strength measurements provide a more realistic understanding of the actual gel strengths at system operating conditions. However, the disadvantage of live measurements is that it can be difficult to maintain a homogeneous pressurized sample for the duration of time that is required to complete the measurement.

IOGPT Flow Assurance Training

page 98

45

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Figure 0-26: Live Yield Strength for Production Fluid As noted in previous sections, the important issue with gel formation is not whether or not gel formation occurs, but whether or not the system can be restarted after gel formation occurs. Therefore, the reported yield strength can be correlated to actual operating conditions based upon the same restart pressure equation that was presented in Section 8.2. As a point of reference, the yield strength of the fluid exactly at the pour point is approximately 0.1 Pa. As discussed previously, the restart pressure equation is conservative in that it assumes: 1. A completely oil/condensate filled line 2. The gel strength is constant throughout the gel plug 3. The entire plug will yield simultaneously As most subsea production lines are operating multiphase rather than single phase, the restart pressure calculation can significantly over predict the required restart pressure in the system. For example, Figure 0-27 illustrates a case in which a subsea system has been shutdown and the fluid temperatures in the flowline are cooling down to the pour point. As illustrated in the liquid holdup curve that is included on the plot (the solid blue line), a relatively small portion of the flowline is liquid-filled and will require gel “breaking” upon restart. Unless the line is completely liquid filled, the production fluids during restart will likely flow over the sections of line that are partially liquid filled (gradually warming up the gel), rather than have to “break” them. Thus, when performing restart pressure calculations, only the portions of the system that are completely liquid filled should be taken into consideration or the restart pressure will greatly over predict the pressure required to restart the system.

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Figure 0-27:

page 99

Cooldown to Gel Formation

Another important feature illustrated in Figure 0-27 is how to define the cooldown time to gel formation conditions. In the case illustrated, if the cooldown time to gel formation conditions is defined as the point in which any portion of the flowline drops below the pour point of the fluid, the cooldown time would be defined as 16 hours. However, the sections that cool most quickly are completely gas-filled and will therefore not form a gel when those sections of the flowline cool below the pour point. Therefore, a more accurate representation of the cooldown time to gel formation conditions is the time for the sections that are mostly liquid filled (50% liquid or greater) to cooldown to the pour point, which in this case is 24+ hours.

IOGPT Flow Assurance Training

8.2.2.3

page 100

Pour Point Depressants (PPD)/Paraffin Inhibitors

If gel formation is expected to occur in the system, continuous inhibition with Pour Point Depressants (PPDs) may ensure that gel formation does not occur in the system during normal operation or during shutdown. However, as the chemical structure of PPDs is effectively the same as paraffin inhibitors, laboratory testing will need to be completed to evaluate the effectiveness and required dosage rate for the vendor recommended chemical. As discussed in Section 8.1.2.5, two basic types of paraffin inhibitors exist (crystal modifiers and wax dispersants) and these inhibitors should be injected above the WAT of the fluid to ensure wax crystal formation has started to occur which would interfere with the wax crystal inhibition. As also discussed in Section 8.1.2.5, the inhibitors recommended by the chemical vendors should be tested independently to verify their effectiveness (using either the pour point or gel strength test). Additionally, the interaction between the reduction of the pour point/gel strength and the impact on wax deposition should be carefully evaluated in the laboratory to ensure that the selected chemical reduces both the pour point/gel strength and wax deposition rates in the system. Lastly, as noted in Section 3.3.2, it is worth noting that care should be taken to ensure that all gel formation laboratory testing matches the conditions in the field as closely as possible. For example, if the gel strength of the fluid is measured with and without inhibitor, the shut-in duration of the test should be carefully considered to reflect the range of realistic shut-in times expected for the system. This is a critical parameter as the gel strength of the fluid will vary somewhat over time and may increase dramatically depending on which paraffin inhibitor is used in the system. This is illustrated in Figure 0-28 for a case in which the gel strength of the fluid remained relatively constant between 1 and 60 days for one vendor’s recommended paraffin inhibitor, while the gel strength increased by approximately 15 times between 1 and 60 days for another vendor’s recommended paraffin inhibitor. 9 Chemical #1 - Recommended Dosage Rate 8 Chemical #2 - Recommended Dosage Rate 7

Chemical #1 - 2 X Recommended Dosage Rate

Yield Stress (Pa)

6 5 4 3 2 1 0 0

10

Figure 0-28:

8.2.3

20

30 Elapsed Days

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Yield (Gel) Strength vs. Time (Different Inhibitors)

Prevention

The prevention of gel formation is typically accomplished through one of three options: •

Thermal control – this includes providing sufficient insulation to keep steady state operation above the pour point, while also providing sufficient cooldown time in the event of an unplanned

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shutdown to displace the fluids from the system. Thermal control can also be maintained via active heating through hot fluid circulation (bundles) or electrical heating. •

Pressure control – this includes maintaining sufficient pressure in the system to ensure the live fluid pour point/gel strength is acceptable at the minimum ambient temperature. However, this method may not be desirable as it may conflict with the hydrate management strategy for the system (which will likely aim to have the lowest possible pressures rather than high pressures).

•

Inhibitors (PPDs) – depending upon the specific fluid properties of the production fluid, chemicals may be injected continuously to reduce the gel strength of the fluid to acceptable levels. Provided the chemicals are injected at the required injection rate, through the use of inhibitors, no actions should be required in the event of an unplanned shutdown.

8.2.4

Mitigation

In the event gel formation has occurred in the system, typical means of gel formation remediation are: •

Pressurization - slowly increase the pressure to the maximum line safety limit. This may require additional pumping capacity. Given sufficient time, the fluid will move; however, sufficient time may range from a few hours to an infinite amount of time. If line taps are added at various points along the lines, additional pressure can be added to the system in order to break the gel.

•

Active heating (direct/indirect) – electrically induced heat is applied to the area surrounding the gel plug (if location is known). This is typically only an option if an electrically heated pipeline has been designed, as localized heat input is difficult for conventional systems, particularly in subsea environments. Other heat-input systems (i.e. Petrobras’ SGN exothermic reaction systems) are available for more specific remediation requirements.

•

Coiled tubing – physical remediation via coiled tubing can be accomplished, provided the coiled tubing can access the deposit. Coiled tubing effective lengths are increasing within the industry, capable of 1-5 miles, depending on the application/geometry

IOGPT Flow Assurance Training

page 102

CHAPTER 9 : ASPHALTENE PREDICTION AND REMEDIATION 9.1

ASPHALTENES Asphaltenes are a high molecular weight compound made up of polyaromatic and heterocyclic aromatic rings, which are typically present in black oil systems. Asphaltenes are relatively insoluble in solvents such as n-heptane and n-pentane. In most cases, the asphaltenes are stable in the crude oils. However, the flow assurance risk arises when the asphaltenes become unstable. Asphaltene stability is typically driven by pressure effects (i.e. de-stabilization may occur in areas where a large pressure drop is taken – wellbore, choke, etc.), but may also become unstable with the addition of certain chemicals (acids, completion fluids, etc). Asphaltenes are responsible for adding most of the color to crude oils. Black oils usually contain the highest asphaltene concentrations. All oils contain asphaltenes, but asphaltenes do not deposit from all oils. Deposition occurs when the colloidal suspension is disrupted. This can occur as a result several phenomena. The asphaltene molecules (A) are at the center surrounded by resins (R). The resins are surrounded by aromatics (a), and the complex is surrounded by the bulk fluid composed mainly of saturates (S). Figure 0-29 illustrates an example of the SARA structure for asphaltene suspension

S a R A

Figure 0-29: Asphaltenes – Suspension Structure The key issue with asphaltenes is more related to deposition, rather than the molecules being unstable. When asphaltenes reach the “flocculation point”, the molecules will come out of solution. These tar-like molecules are often transported with the bulk fluid and will not likely cause any operational upsets. If sufficient molecules are present in restricted flowpath areas (i.e. wellhead, choke, etc), then there is a risk that the molecules will deposit and block the line, restricting production. Asphaltenes tend to be sticky in nature, making them difficult to remove from surfaces. Asphaltenes also tend to stabilize emulsions, making oil/water separation at the processing facilities more difficult. Asphaltene deposition can occur as a result of: •

Pressure change

•

Mixing incompatible crudes (if a stream rich in asphaltenes, but also containing sufficient resins to keep the asphaltenes in solution is mixed with a stream very low in resin content, asphaltenes may deposit)

•

Gas lift (decreases solubility of asphaltenes in remaining oil)

•

Temperature increase (stabilizing effect of resins occurs through polar interactions. This mechanism is weakened by heat in the same way that emulsions are weakened by heating.)

•

Stripping of liquids carried over into compressors

•

Acidizing

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•

CO2 flooding

•

Shear effects (SARA complexes that hold asphaltenes in suspension are large and bulky and can be disrupted by shear forces)

Asphaltene solutions are stabilized by higher pressures. Asphaltene typically deposits between the reservoir pressure and the bubble point. The explanation for this behavior is that the density of light saturates changes more rapidly as a function of pressure than does the density of resins. As a result the concentration of resins is effectively reduced as the pressure decrease. Once the bubble point is reached, these light saturates preferentially flash and the concentration of resin in the liquid rises. Hence, below the bubble point the stability of asphaltene suspensions increase. Overall system modeling from the reservoir to the separator should be done to determine the pressure profiles along the flowpath of the fluid. If the fluid crosses over the bubble point in the wellbore or at the subsea equipment, then additional analysis/measurements may be required to assess the severity of any asphaltene-related issues.

9.1.1

Risk

With the exception of some very heavy tar sands in Canada, asphaltene problems in most offshore developments are relatively rare. Some of the risks associated with asphaltene flocculation/deposition are: •

Deposition in wellbore tubing, reducing hydraulic capacity of the well

•

Erosion/wear on subsea components, especially chokes

•

Emulsion stability increase, making oil/water separation more difficult

•

Reservoir impairment (permeability loss)

•

Fouling of compressors and other system in gas service (due to oil carryover in separators)

•

Unknown effect on wax deposition/gel formation, with a likely increase in wax deposition due to formation of nucleation points

The primary risk associated with asphaltenes is that flocculation is not reversible. The deposition of asphaltenes is typically not reversible. For instance, if a pressure drop causes asphaltenes to deposit, repressurizing the system will not typically result in the asphaltene being re-suspended in the bulk fluid. Unlike waxes, which crystallize out of solution and can usually be melted with heat, asphaltenes have no melting point and cannot typically be remediated via heating.

9.1.2

Testing Testing cannot be any more accurate that the quality of the sampling supports. The sample must be obtained at reservoir or wellbore conditions. Samples obtained at the surface may already have deposited asphaltenes. Sampling should be performed upstream of the expected problem area. Since deposition often occurs above the bubble point sampling must often be done at reservoir conditions. The sample must be maintained above the bubble point; phase change prior to testing must be avoided. This requires special sampling systems. A sample obtained at reservoir temperature and pressure will usually cool when raised to the surface. Cooling results in a decrease in pressure. Check containers for lost deposited solids after testing. Account for asphaltenes deposited in the sample container. There are no standard design/testing methods to address asphaltenes. Current research work is focused on improving screening studies to look at the likelihood of asphaltene-related problems. From the PVT analysis, SARA screening tests will often determine the amount of asphaltene components presents (wt %). This test in itself does not determine asphaltene-related risk, but it can be an early indication of problems.

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Various tests are available to determine asphaltene content, including IP-143, ASTM D-893, ASTM D2007, and UOP 99. These involve extracting asphaltenes from the oil via use of a solvent such as heptane or pentane. The asphaltene composition of a stream is not reliable indication of deposition tendency. Streams high in asphaltene composition may not yield deposits. Typically, if asphaltenes are present in the SARA analysis, a lower value is poses a higher risk than a higher value. The higher asphaltene contents tend to be more stable than the lower concentrations. If the SARA analysis indicates likelihood for asphaltenes, additional screening tests should be considered. The most basic screening tool available is the deBoer Plot. Generated by Shell, the deBoer plot quickly allows the operator to determine, based on the in-situ crude oil density and the degree of under-saturation in the reservoir, the likelihood of asphaltene flocculation. Figure 0-30 gives an example of the deBoer Plot. 10000 Sample 1 9000

Sample 2

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Figure 0-30:

Asphaltenes – deBoer Plot

The deBoer plot shows that fluids which exist in the reservoir at pressures much higher than the bubble point are at a much higher risk for asphaltene-related problems than those that are closer to the bubble point in the reservoir. If the deBoer plot indicates that the asphaltene region is falls into one of the ‘Risk’ categories, additional fluid testing is recommended. A more detailed laboratory test would be to determine the asphaltene onset pressure (AOP), based on a controlled pressure (isothermal) reduction to monitor asphaltene propensity. This test requires a live oil sample obtained above the bubble point. Using visual inspection, the amount of light transmitted through a test cell is measured. As the pressure is reduced, asphaltenes will reach a point where they come out of solution, greatly reducing the light transmittance. This point is defined as the Asphaltene Onset Pressure (AOP). Figure 0-31 illustrates a laboratory example of the test results.

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3.5E-05 3.0E-05 4000 ps i

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Figure 0-31: Asphaltenes – AOP Test Results There are no industry-wide accepted asphaltene deposition models that allow prediction of deposition rate as a function of system pressure. However, work is currently being done at the university level to incorporate research efforts into commercially available software codes (i.e. InfoChem’s Multiflash program)

9.1.3

Prevention/Mitigation Asphaltene flocculation/deposition cannot be controlled by thermal means. Thus, flowline insulation or other common flow assurance-related techniques are not applicable. The majority of feasible asphaltene prevention/mitigation alternatives involve chemical inhibition. These may include: •

Asphaltene dispersant injected continuously in the wellbore, typically downhole o

Provision for periodic aromatic solvent (xylene) soak in the wellbore

o

Provision for coiled tubing intervention in the wellbore

•

Ensure chemical compatibility amongst all chemicals injected into the reservoir and/or tubing

•

Minimizing agitation and shear forces in susceptible areas

•

For onshore systems, physical remediation via wellbore drill-out or regular cleaning programs is typical. However, for subsea wells, this would prove to be inefficient and economically unviable.

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CHAPTER 10 : PIGGING 10.

PIGGING

In gas/condensate systems, there are three primary reasons for sphering (pigging) operations: •

Batch corrosion inhibitor mixing

•

Liquid management

•

Wax removal

Due to the compressibility of the gas, the sphere is prone to periods of “starting and stopping” along the pipeline route, depending on gas velocity, topography, and liquid holdup. Dynamic simulations should be conducted to ensure that the pig does not become “stuck” in the pipeline. Typical factors to consider when performing sphering calculations are: •

Sphere velocity (must consider physical limitations/integrity of sphere)

•

Sphere by-pass impacts (will determine liquid outlet rates)

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Inlet pressure (impacted by velocity, liquid holdup, by-pass)

•

Gas/liquid arrival rates (typically, liquid arrives as a large slug, posing liquid handling issues)

•

Surge volume requirements at pipeline outlet

Figure 10-1 through Figure 10-4 illustrate sphering results from dynamic simulations. The plots illustrate the pressure impact at the inlet, the pig velocity, and liquid outlet rate. Again, the liquid tends to arrive as a single large slug, rather than several smaller slugs, due to the compressibility of the gas in the pipeline. 1170

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Inlet Pressure vs. Time (Sphering)

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Liquid Outlet Flowrate vs. Time (Sphering) Liquid Holdup

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Liquid Holdup vs. Time (Sphering)

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Figure 10-4:

Sphere Velocity vs. Time (Sphering)

Note from the liquid outlet rates that the liquid rate will likely drop to zero immediately following receipt of the sphere. This is due to the fact that the pipeline is operating in a non-equilibrium state in terms of liquid inventory. After sphering, the liquid will accumulate in the pipeline, rather than be carried to the pipeline outlet, until an equilibrium condition is reached. Once reached, liquid will once again flow from the pipeline outlet. If the liquid arrival rates at the pipeline outlet are too high, the sphering frequency may need to be increased. By increasing sphering frequency, the amount of liquid accumulation between sphering runs decreases, reducing liquid arrival rates. Or, use of a by-pass sphere may be required. By-pass spheres allow some portion of the liquid to “slip” by the sphere, thus not removing the entire liquid inventory. Pigging specifications should be verified with the pig vendor in terms of maximum allowable velocity. For batch corrosion inhibitor operations, a slower velocity (1-2 m/s) is recommended to ensure efficient mixing/contact. For sphering operations, the pig velocity will be dictated by the production rate, but may need to be limited due to mechanical constraints on the pig itself. For wax removal, typical pig velocities of ~1 m/s are recommended for efficient wax scraping. For wax removal operations consideration should be given to using a liquid, such as MEG or dead condensate, to drive the pig. This gives much better control of the pig, especially should the pig become stuck and significant differential pressure is need to unstuck it.