pvt _ flow assurance

18/03/2015 PVT|FlowAssurance

http://flowassurance.blog.com/flowassurancetopics/ 1/10

Flow Assurance in Oil and Gas IndustriesPVT

Contents:

1. Introduction2. PVT CharacterisationExperiments

A. Waxesi. Waxy crude characterisation experimentsii. Wax Inhibitors

iii. Viscosity of Wax Oil SuspensionsB. Asphaltenes

i. Experimental Techniques to study Asphaltene Precipitationa. Quantification of Amount of Asphaltenesb. Detection of Asphaltene Onset Pressures (AOP)

3. Design (Black oil or Compositional?)4. Flow Assurance Phase Envelope

==============================================================================1. IntroductionFlow assurance is amulti-disciplineprocess involving sampling, laboratoryanalysis, productionand facilitiesengineering to ensure uninterruptedoptimum well productivity. Laboratorytestingprovides necessary data to assessthe flow assurance risk because it definesphase behavior andthe properties of the waxes, asphaltenes, and hydrates known to be principal causes offlowproblems.

Sampling points:

1. The reservoir Fluid sampling2. The surface sampling3. In the case of emulsion problem, sample should be taken at the inlet to separator,

downstream of any control valves etc.

==============================================================================

2. PVT Characterisation Experiments:

A. Waxes

i. Waxy crude characterisation experiments:



Wax Content: HTGC (High Temperature Gas Chromatography)Wax Appearance Temp. (WAT): High Pressure Cross Polar Microscopy (HP-CPM)Upper and Lower Pour Point: Live oil pour point apparatus (ASTM D5853)Gel Strength: Model Pipeline Test (MPT)Rheology and Viscosity: Controlled Stress RheometryWax Solubility: Bulk Filtration

When assessing a waxy crude productionor transport situation, relying solelyon conventionaldead crude wax tests, including wax content and wax appearance temperaturemeasurements, canbe misleading. Stock-tank oil tests areinsufficiently representative of fieldsituations because reservoir pressure and solution gas have a strong influence on waxsolubility. Laboratory-scale tests must account for the actual thermophysical situation in thefield if they are to be applicable.

The wax appearance temperature (WAT) is the temperature below which a solidwax phaseforms within a hydrocarbon fluid at a given pressure. Below the WAT, significant viscosityincreases, deposition, and gelling are possible. The pour point is the temperature, at a givenpressure, below which the staticfluid may form a gel. For a system cooledbelow its pour point,restarting flow maybe difficult or impossible.

ii. Wax Inhibitors:

Basically, three groups of wax inhibitor chemicals are used.

Wax crystal modifiersDetergentsDispersants

The last two groups are surface-active agents as, for example, polyesters and amineethoxylates.These act by keeping the crystals dispersed as separate particles, thereby reducingtheir tendencyto interact and adhere to solid surfaces.

Crystal modifiers are substances capable of building into wax crystals and altering thegrowthand surface characteristics of the crystal. The crystal modifiers will lower the pour pointas wellas the viscosity. The name pour point depressant is also used for this class of chemicals.The acetate group(CH3COO) contained in the inhibitor is very unlike the paraffinic branchesand will disturb furtherstructuring of the paraffinic molecules.



iii. Viscosity of Wax Oil Suspensions:Oil containing solid wax particles may exhibit non-Newtonian flow behavior. This means that theviscosity varies with shear rate (dvx/dy). At temperatures above the WAT, the oilbehaves in aNewtonian manner (viscosity independent of shear rate). Below the WAT, the viscosity variesdepending on shear rate.

The apparent oil viscosity below the WAT may be calculated from (Pedersen and Rnningsen,2000)

B. Asphaltenes:

Asphaltenes is a component class that may precipitate from petroleum reservoir fluids as ahighlyviscous and sticky material that is likely to cause deposition problems in production wellsand pipelines. Asphaltenes are defined as the constituents of an oil mixture that, at roomtemperature,are practically insoluble in n-pentane and n-heptane, but soluble in benzeneand toluene (Unlike resins which are soluble in n-pentane and insoluble in liquid butane orpropane). Because a major part of reservoir fluidsconsists of paraffins, asphaltene precipitationproblems are quite frequent. Unlike wax precipitation, asphaltene precipitation is not limited tolow temperatures. Precipitation may occur in the reservoir, in the production well, duringpipeline transportation, and inprocess plants. Gas is often injected into an oil reservoir to obtain



an enhanced oil recovery.Because natural gas essentially consists of paraffins, gas injection willtend to worsen precipitationproblems.

Also there are different opinions about the solubility properties of already precipitatedasphaltenes. Just a few years back, it was the general opinion that already precipitatedasphaltenes wouldnever go back into solution again. Supporters of this idea saw asphaltenesdissolved in an oilmixture as aggregates, only staying in solution because of an outer protectivelayer consisting of resins. Removal of this protective layer would make the asphaltenes formeven larger aggregates that would precipitate and become insoluble, because it would beimpossible to regenerate the protective resin layer. Resins form another solubility class.resinsare soluble in n-heptane. They can be adsorbed on silica or alumina from an n-heptanesolution, from which state they can be extracted using a methanolbenzene solution. Theunderstanding ofasphaltene precipitation as a nonreversible process was essentially based onexperimental observationsof asphaltenes precipitated from stabilized oils by addition of largequantities of either n-pentane or n-heptane. This precipitation technique gives asphaltenes inalmost pure form, andthe cohesion between the individual asphaltene molecules in this formmay be so high that itbecomes almost impossible to dissolve the asphaltenes again.

For an oil of a fixed composition, asphaltene precipitation is most likely to take place right atthebubble point. At the bubble point, the oil has the highest content of dissolved gas. Theparaffinic gas components (C1, C2, etc.) are bad solventsfor the asphaltenes; this is what makesasphaltene precipitation likely to take place. If the pressureis lowered, some gas will evaporate,and the gas concentration in the liquid phase will decrease.This makes the asphaltenes moresoluble in the liquid. The asphaltene phase will slowly dissolve and possibly disappear. Thepressure at which the last asphaltenes go into solution is called the lower asphaltene onsetpressure (lower AOP). Increasing the pressure from the bubble point will also make theasphaltene phase dissolve. Though paraffins are generally poor solvents for theasphaltenes, thesolubility of asphaltenes in paraffins increases with pressure, and, at a sufficientlyhigh pressure,the upper asphaltene onset pressure (upper AOP), the asphaltene phase will disappear.

APO: Asphaltene Precipitation Onset



i. Experimental Techniques to study Asphaltene Precipitation:Quantification of Amount of Asphaltenes:

The n-C5 or n-C7 precipitation technique (e.g., Burke et al., 1990) is used to determinethe asphaltene content in a stabilized oil mixture. The n-paraffin is injected in largequantities (e.g., 40/1 n-C5/oil on a volume basis), which forces the asphaltenes to precipitate.Theprecipitate is filtered and washed to purify the asphaltenes.

Asphaltene content measurement as a heptane insoluble fraction: IP 143

Asphaltene content measurement as a pentane insoluble fraction: ASTM D893

Detection of Asphaltene Onset Pressures (AOP):Gravimetric TechniqueAcoustic Resonance TechniqueLight-Scattering TechniqueFiltration and Other Experimental Techniques

===============================================================================3. Black Oil or Compositional Model? (in Design)

Black Oil:

A black oil model assumes that the fluids consist of a liquid phase and a gas phase only. Theamount of gas that dissolves in the oil is dependent on pressure andtemperature.



Black oil models should only be used in steady state simulations in which the API gravity is lessthan 45 and the GOR is less than 14000 standard m3/m3 of stock tank oil (2 500 scf/stb).

The following minimum data shall be used to set up a black oil model:

1. Oil SG. 2. Gas SG. 3. GOR 4. Water cut

This data should be obtained from a laboratory multistage flash analysis (normally 3 stages). Thesum of the gases evolved from each of the laboratory flash stages is known as the producingGOR. The density of the oil produced from the final flash stage is defined as the stock tank oildensity. The gas SG is based upon the weighted average gravity from each stage.

This analysis should be performed at conditions that closely match field operating conditionsi.e.:

1. The 1st and 2nd stage pressure and temperature conditions in the test should closely matchthe 1st and 2nd stage separators in the field.

2. The 3rd and final stage of separation is performed at stock tank conditions, 1,01 bar, 15C(14,7 psia, 60F).

3. Even if the field operation only has a single stage of separation, the laboratory test shall alsoinclude a second stage at stock tank conditions.

Using the GOR, oil SG, gas SG data, and standard black oil correlations the physical propertyinformation required for a multiphase flow analysis can beevaluated.

Physical property correlations should be tuned to match laboratory data at the bubble pointcondition and the 1st stage separator. Solution GOR and volume formation factor informationis available from the multiphase flash data at these 2 conditions.

Live oil viscosity data that is generally available at the bubble point condition should be used totune the oil viscosity correlation.

Compositional Model:

A compositional model shall be used for any fluids that lie close to the critical point, such ashighly volatile oils, as well as for gas-condensate systems.

The industry standard, transient multiphase simulator, OLGA, currently only works withcompositional descriptions of the fluids.

Compositional modelling should be used for systems in which the GOR is > 2500 or the API



gravity is > 45.

Detailed fluid analysis, as provided from the process design, shall be used. A compositionalmodel requires a detailed analysis of the fluids. However, attempting to model the fluids interms of the components e.g. C10, C11, does not produce an adequate characterisation of thefluid, rather the heavy end components beyond approximately C7 require a full characterisationin terms of their normal boiling point (NBP), molecular weight (MW), and SG. Reservoir engineersoften have available heavy end component characterisation in terms of critical pressures andtemperatures; however these can be manipulated using standard routines to provide thecharacterisation in terms of NBP, MW, and SG. The characterised fluid data can be used either togenerate tables of properties,within which design software packages have to interpolate, or toenable some software programs to calculate the required properties at any temperatureandpressure, directly.

Fluid viscosity values shall be obtained from laboratory analysis if fluid samples are available fortesting.

If fluid samples are not available, PVT package generated viscosity values may be used.Historically PVT package determined viscosity values have proven to be significantlyunderestimated.Current BP preferences for PVT packages are:

PVTsim from CalSepMultiFlash from InfoChem

Whichever package is selected, the equation of state used to characterise the fluid shall bematched to as much laboratory data as possible before any design work is undertaken.Validation exercises have shown that BWRS is the most accurate method for predicting a rangeof fluid properties. However the BWRS method is not supported by many PVT packages.

If the PVT package does not support BWRS methodology, either the Peng-Robinson or SRKmethods should be used. With either of these methods, both liquid and gas property predictionsare significantly improved if Peneloux shift parameters are applied.



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4. Flow Assurance Phase Envelope:

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