176_ASSESSMENT OF FLUID PRESSURE LOSS IN OIL & GAS IN-FIELD PIPELINES A GIS BASED APPROACH.pdf

8/12/2019 176_ASSESSMENT OF FLUID PRESSURE LOSS IN OIL & GAS IN-FIELD PIPELINES A GIS BASED APPROACH.pdf

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ASSESSMENT OF FLUID PRESSURE LOSS IN OIL & GAS IN-FIELD

PIPELINES: A GIS BASED APPROACH

Nicols Metalloa, Antonio Liporace

b

aMechanical Integrity Department, Sinopec Argentina Exploration & Production Inc., Manuela Saenz

323, Buenos Aires, Argentina, [email protected]

b

Mechanical Integrity Department, Sinopec Argentina Exploration & Production Inc., Manuela Saenz323, Buenos Aires, Argentina, [email protected]

Keywords:multiphase flow, GIS, pressure drop, emulsion viscosity, phase inversion.

Abstract: The assessment of fluid pressure loss in pipelines plays a major role in the solution ofproblems of practical interest. Indirect corrosion monitoring as well as pipe size calculations, they bothrely on an accurate calculation of pressure loss. However this is not a trivial task. In this paper wepresent an innovative methodology to calculate and display fluid pressure drop in Oil & Gas pipelines.This methodology addressed all relevant aspects of multi-phase fluid pressure drop such as emulsionkinematic viscosity model and emulsion density model. A solution to readily acquire input parametersto perform pressure drop calculations via Geographic Integration System (GIS) is also presented. The

same system is use to present calculation results. This procedure allows a complete automatization ofthe calculations for an entire pipeline network.


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1 INTRODUCTIONThe assessment of fluid pressure loss in pipelines plays a major role in the solution of

problems of practical interest. Indirect corrosion monitoring as well as pipe size calculations,

they both rely on an accurate calculation of pressure loss. However this is not a trivial task.Fluid flowing from oil wells is a variable mixture of oil, water and gas. There are many

theories to tackle down every related problem but, unfortunately, none of them is of general

application. In addition, the total length, the volumetric flow rate and the topographic

elevation of start and end points of a pipe must be known in order to perform the calculations.

Finding these values can be a demanding task, especially for pipelines that receives fluid from

many wells.

Fluids extracted from Oil wells are a variable mixture of petroleum, gas and water. The

fluid fraction is always prevalent but water to petroleum ratio is highly variable. This is

especially true in regions where secondary oil recovery techniques are implemented, like in

Argentine oil fields. This variability makes the assessment of density and kinematic viscosity

a real challenge. The accurate assessment of these values along with the selection of a suitable

multi-phase flow theory is vital to accurate assessment of fluid pressure loss. In this paper we

analyze multiple models of density, kinematic viscosity and multi-phase flow in order to

select the more suitable ones. This lead to the development of a complete methodology to

determine pressure loss in oil & gas pipelines that addresses, and hopefully overcomes, all the

stated difficulties. We also present a way to readily obtain pipeline total length, volumetric

flow rate and topographic elevations from Geographic Integration System (GIS) corporate

database.

Although many theories to assess fluid pressure loss are already developed, none of them

is a complete one, with wide application to in-field oil and gas pipelines analysis. Moreover

these theories usually overlook density and kinematic viscosity variations leading to resultsthat do not correlate well with experimental and field measurements. GIS integration requires

the development of a well-planned application (ArcObjects) that could be run overnight in

order to process introduced changes in corporate database (such as new volumetric flow rates

of wells).

In the following sections we cover the basis of multi-phase flow theories. Then we revise

most relevant kinematic viscosity and density models and select the most suitable one. After

that, a methodology is proposed and an example calculation is given. Finally, GIS integration

is described both to gather required data and to graphically present calculations results.

2 MULTIPHASE FLOW FUNDAMENTALSIn the oil and gas industry multiphase flow often happens with fluid from well production

and gas and oil flow simultaneously through the pipeline. This is what we know to be two-

phase flow (gas-liquid) but in addition to gas and oil, it is normal to find water flowing also

forming an gas-water emulsion known to be a three-phase fluid flow.

2.1 Superficial velocitiesIt is possible to find the superficial velocity of each phase (that being gas or liquid) by

dividing the volumetric flow rate of the phase by the cross-sectional area of the pipeline. We

consider the system as if only one phase was flowing through it. We would then have:

(2.1.1)


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(2.1.2)

The liquid phase contains both oil and water:

( ) (2.1.3)Where (oil), (water) and (gas) formation volume factors convert to the prevailing

pressure and temperature conditions in the pipe from standard (or stock tank) conditions.

The gas phase could be treated as a function of pressure:

(2.1.4)In the end, superficial velocities could be rewritten as:

( ) (2.1.5)

( ) (2.1.6)As the cross-sectional area occupied by liquid phase is smaller than that of the entire pipe, we

could find that in-situ velocity (considering liquid hold-up) is then higher than superficial

velocity.

To know the final mixture velocity the following equation shall be considered:

(2.1.7)

2.2 Liquid hold-upWhen two or more phases are present in a pipe, in most cases gas flows faster than the

liquid, that is to say that

. This typically happens for the less dense phase causing a

slip between the two. As a consequence, the in-situ volume fractions of each phase (underflowing conditions) will differ from the input volume fractions of the pipe.

No-Slip Liquid and Gas Holdup ( ): is defined as the ratio of the volume of theliquid in a pipe segment divided by the volume of the pipe segment which would exist if the

gas and liquid travelled at the same velocity (no-slippage). It can be calculated directly from

the known gas and liquid volumetric flow rates from:

(2.2.1)

Liquid and Gas Holdup ( ): is defined as the ratio of the volume of a pipe segmentoccupied by liquid to the volume of the pipe segment. The remainder of the pipe segment is ofcourse occupied by gas, which is referred to as:


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(2.2.2)When slip occurs, then:

2.3 Gas-liquid mixture density and flowing velocityPressure gradients on multiphase lines normally lie in the range 0-1.5 kg/cm2/km but a

more useful way of addressing if flowing conditions are acceptable is to check whether the

velocity of the fluid is in a required threshold.

The actual (not the superficial) liquid velocity

should be greater than 3 m/s to ensure that

sand and water are continuously transported with the liquid and should not accumulate at thebottom of the pipe. The actual liquid velocity is given by:

(2.3.1)At the maximum throughput conditions the mixture velocity should not exceed the

erosional velocity as it would induce a loss of wall thickness that occurs by a process of

erosion/corrosion. This process is accelerated by high fluid velocities, presence of sand,

corrosive contaminants such as , and fittings which disturb the flow path such aselbows.

The following procedure (API 14E) for establishing an erosional velocity can be usedwhere no specific information as to the erosive/corrosive properties of the fluid is available.

(2.3.2)Where:= maximum acceptable mixture velocity to avoid excessive erosion (ft/s)= no-slip mixture density (lb/ft3)C = a constant, given in API R14E as 100 for carbon steel

And can be determined using the following derived equation: (2.3.3)

Where:

P = operating pressure, psia= liquid specific gravity (water = 1) at standard conditionsR = gas-liquid ratio,

at standard conditions

T = operating temperature, R

= gas specific gravity (air = 1) at standard conditionsZ = gas compressibility factor, dimensionless


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2.4 Phase inversionOil and water mixtures in crude oil pipelines interact across their interface and the extent

of this interaction determines the effective properties of the mixture. Two dispersions can be

formed usually: one being water-in-oil (W/O) dispersion formed when the aqueous phase isdispersed in the organic phase and oil-in-water (O/W) dispersion is a dispersion which is

formed when the organic phase is dispersed in the aqueous phase. Phase inversion is the

phenomenon whereby the phases of liquid-liquid dispersion interchange such that the

dispersed phase spontaneously inverts to become the continuous phase and vice versa. This

could be seen illustrated in Figure 2 below and we could then say that the inversion point is

the holdup of the dispersed phase for a system at which the transition occurs i.e. when the

dispersed phase becomes the continuous phase.

Figure 1: Phase inversin ocurrence. (Arirachakaran 1989)

Factors that may influence phase inversion are among others: two-phase density, viscosity,

interfacial tension, and other physical properties and operation conditions. At the same time,

temperature, oil-water system formation, and mixture container wettability also play an

impact. The inversion point aims to provide a probable range of distinguishment between

continuous and disperse phase where Decarre and Fabre (Eq. 2.4.1) and Arirachakaran et al.

(Eq. 2.4.2) equations are introduced:

(2.4.1)

(2.4.2)The viscosity increase that happens with the variation of the water fraction was found to

had a peak at the inversion between W/O and O/W emulsions. This mixture viscosity was

found to increase initially as the fraction of the dispersed phase (water) increased up to a point

where it would then decrease. This can be seen in Figure 3.


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Figure 2: Mixture viscosity as it evolves with input water fraction (Arirachakaran 1989)

Various models for calculating the viscosity of liquid-liquid dispersions can generally be

grouped into three main categories, namely linear, exponential and power function models.

Table 2.4.1: Mixture viscosity of oil-water emulsions (Ngan 2011)


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Based on results obtained and easiness of application, it is recommended the usage of any

of the power functions such as the one developed by Brinkman/Roscoe or the following by

Barnea & Mizrahi which showed great results:

(2.4.3)The phase inversion range is shifted to lower water fractions in a plastic pipe compared to

a steel one and also by increasing flow velocity, the inversion region width decreases as the

dispersion becomes more homogeneous. Normally from the point obtained there exist a +-

10% of uncertainty in which the inversion point could develop (Ngan 2011).

To address the issue of the sudden change of mixture viscosity along the lines of the

continuous and disperse phases, an emulsification index is introduced as looking at existing

methods, we identify two extremes of possibilities. Power functions (that is Brinkman or

Barnea as well) correlations represents one extreme in which there is total emulsification,giving very high emulsion viscosities up to the inversion point. And on the other side, the

weighted-average method assumes no interfacial interaction between the dispersed and the

continuous phases, that is, there is total absence of emulsification. In practice, the truth is

somewhere in between. A formal definition of emulsification index would be as follows:

Emulsification index (Ei) is the extent to which the viscosity of a water-in-oil emulsion is

determined by power functions correlations.

Emulsification index will conventionally be taken as ranging from 0 to 1. For a fully

emulsified mixture, . Total absence of emulsification means . This is equivalent tothe weighted-mean assumption. Viscosity of an emulsion is then calculated as comprising

partly of the value given by power functions, and partly by the weighted average. For

simplification purposes, would be considered 1 when above the Inversion Point and 0below.

Mixture viscosity calculated as the weighted average:

(2.1.15)What the final equation may look like:

(2.1.16)

2.5 Viscosity measurements normalization.As a way of addressing the issue of having a normalized viscosity per area we used the

ASTM D341 standard to convert viscosity at different temperatures. Given two known

kinematic viscosities at two temperatures this standard gives means to ascertain kinematic

viscosity of a petroleum oil or liquid hydrocarbon at any temperature within a limited range.

(2.5.1)And Z is the result of:


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(2.5.2)Where,

2.6 Friction factor (no-slip)

As a way to calculate the no-slip friction factor (Darcy-Weisbach) what is normally used is

the Colebrooks equation. The downside is that as it is an implicit equation is not easy to

calculate and so many approximations were covered. We recommend the use of Haaland

equation as it provides reasonably good statistical parameters and required few hand

calculations.

{ [ ] }

(2.6.1)

3 LINE SIZING AND PRESSURE DROPTo begin designing it is required to set the specifications of the line size to meet the

required capacity with the pressure constraints available. And although it is important to size a

line to meet pressure requirements one has to ensure that flowing conditions provide good

operating conditions.

The total pressure drop to which our pipeline shall be sized, is given by the followingequation:

(3.1)

The recommended pressure drop method is the Beggs & Brill correlation (Beggs and

Brill 1973) as it is considered one of the most reliable one among the most widely used as it is

also capable of working properly along different pipeline inclinations. It normally over-

predicts pressure drop by between 0-30%, and by doing so it provides a mean of conservation.

3.1 Frictional pressure lossThe frictional pressure gradient shall be given by the following equation:

(3.1.1)


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Where:

two-phase friction factor

acceleration due to gravity (9.81 m/s2

) height increment (m) mixture density (kg/m3)3.2 Hydrostatic pressure loss

When the liquid hold-up is known it is possible to calculate the hydrostatic pressureloss by the following equation:

(3.2.1)Where:

hydrostatic pressure loss (N/m2) acceleration due to gravity (9.81 m/s2) height increment (m) mixture density (kg/m3)3.3 Kinetic pressure loss

In the extent of this paper

will be considered to be small enough to be neglected as it

only becomes significant for high velocity flows approaching critical conditions.

3.4 Flow regime and pattern mapAs there is little contribution by potential energy in horizontal flow, the pressure drop is

not affected in such a way by flow regimes as it is in vertical flow. Shown below in Figure 3

we can see the different flow regimes in horizontal gas-liquid flow. We could sum this in

three types of regimes (Beggs and Brill 1991): segregated flows, in which the two phases are

separated; intermittent flows, in which gas and liquid are alternating; and distributive flows,

in which one phase is dispersed in the other phase.

Figure 3: Mixture viscosity of oil-water emulsions (ref here)


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Segregated flow could be further classified as being stratified smooth, stratified wavy

(ripple flow), or annular. At higher gas rates, the interface becomes wavy, and stratified wavy

flow results. Annular flow occurs at high gas rates and relatively high liquid rates and consists

of an annulus of liquid coating the wall of the pipe and a central core of gas flow, with liquiddroplets entrained in the gas.

The intermittent flow regimes are slug flow and plug (also called elongated bubble) flow.

Slug flow consists of large liquid slugs alternating with high-velocity bubbles of gas that fill

almost the entire pipe. In plug flow, large gas bubbles flow along the top of the pipe.

Distributive flow regimes include bubble, mist, and froth flow.

Figure 4: Flow pattern map (Gas Lift Manual 2005)

3.5 Liquid hold-up calculationThere exists a single liquid holdup formula for the three basic horizontal flow patterns

(Beggs and Brill 1973). After the holdup for the horizontal case is found, a correction is

applied to calculate its value at the given inclination angle. It has been proved by

experimental data that liquid holdup varies with the inclination angle in such a way that a

maximum and a minimum is found at the inclination angles of approximately +50 and -50,

respectively. In summary, follow these steps:

1. Find the holdup that would exist when the pipe is horizontal2. Correct the value for the actual inclination angle

The horizontal liquid holdup is found for all three basic flow patterns from the followingformula, where the coefficients vary according to the flow pattern:

(3.5.1)Where: liquid hold-up Froude number

(3.5.2)


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The coefficients a, b and c are given in Table 3.5.1, and the calculated hold-up is restricted

to Flow Pattern a b cSegregated 0.980 0.4846 0.0868

Intermittent 0.845 0.5351 0.0173

Distributed 1.065 0.5824 0.0609

Table 3.5.1: Liquid hold-up coefficients (Beggs & Brill 1973).

Based on its value for the horizontal case, holdup for the actual inclination angle is

calculated from the following equation:

(3.5.3)The holdup correcting factor (), for the effect of pipe inclination is given by:

(3.5.4)Where is the actual angle of the pipe from horizontal. C is:

( ) (3.5.5)The values of parameters, e, f, g and h are shown for each flow regimes in this Table:

Flow Pattern e f g h

Segregated uphill 0.011 -3.768 3.539 -1.614Intermittent uphill 2.96 0.305 -0.4473 0.0978

Distributed uphill No correction C = 0 , = 1

All patterns downhill 4.70 -0.3692 0.1244 -0.5056

Table 3.5.2: Liquid hold-up coefficients (Beggs & Brill 1973).

For vertical flow, i.e. =90 the correction function is simplified to:

(3.5.6)If in the transition flow pattern, liquid holdup is calculated from a weighted average of its

values valid in the segregated and intermittent flow patterns:

(3.5.7)Where:

(3.5.7)

3.6 Friction factor determinationThe two-phase friction factoris given by the following equation:


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(3.6.1)Where:

no-slip friction factor (Darcy-Weisbach) based on homogeneous two-phase flow a dimensionless two-phase multiplier used to account for slippage between phases (3.6.2)

Where:

(3.6.3)

(3.6.4)

The parameter S can be calculated as follows:

For For y=0, then S=0 (to ensure that the expression is reduced to single-phase liquid)

(3.6.5) (3.6.6)

4 DATA INTEGRATION AND COMPUTER SIMULATIONOnce we have set our boundary conditions and also the calculation model we proceed to

the actual simulation of the

4.1 GIS data acquisition applicationThe main purpose of this application is to integrate available data and represent it in a way

that can be employed to performed fluid pressure drop calculations. As this will be an over-

night run application so data related to every pipeline in the network is analyzed.

Pipeline network information is stored in a GIS corporate database, mainly by the usage of

proprietary software by ESRI. Data is held in ArcSDE geodatabase which are a collection ofvarious types of GIS datasets held as tables in a relational database. ArcSDE geodatabase

storage for all DBMSs uses the OGC and ISO standards for an SQL spatial data type. This

provides full geodatabase support and access as well as an SQL interface to feature class

geometry. This enables you to write SQL applications to your DBMS which you can use to

access feature class geometry and perform SQL operations and queries. The spatial type for

SQL.

The first task of this application is the subdivision of the entire network into pipeline units.

A point called "node" is artificially created along pipeline network at the following locations

Oil-Wells In-field manifolds Battery manifolds Treatment Plants


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Two or more pipelines junction Pipeline material change point Pipeline diameter change point

Each pipeline segment between nodes is treated as an individual unit. Later on, fluid

pressure drop will be calculated for each of these units.

Total length is calculated adding up the lengths of the segments between nodes.

Topographic elevations of start and end nodes are determined by matching them to the

Digital Elevation Model (DEM).

Finally, volumetric flow rate is calculated by adding up flow rates from all pipelines

converging to the one under analysis.

4.2 Computational simulationWith an established mathematical model and all input parameters determined we can

proceed to the actual simulation.

For the computational simulation we will use standard office software (namely Microsoft

Excel) which can easily create a dynamic link between the database and data tables. For

calculation purposes we recommend avoiding over complex VBA programming and the use

of array formulas particularly if they are nested inside IF statements. We also do not

recommend the usage of VLOOKUP or INDEX+MATCH functions over large data tables.

We recommend the usage of multi-variable data tables found inside the Excel API; the use of

these tables could reduce end processing time by more than 2 orders of magnitude.

Calculated data is then automatically exported to a csv (coma separated values) file which

is then joined with the data already held in the geodatabase and is to be displayed on a map.

Figure 5: Results being showed on ArcMap (ESRI)


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5 CONCLUSIONSIn this paper we presented an innovative methodology to calculate and display fluid

pressure drop in Oil & Gas pipelines.

A complete mathematical model to estimate fluid pressure drop is presented. Theaforementioned model holds adequate results when used to solve Oil & Gas industry related

problems. This model addressed multiphase pressure drop calculations as well as kinematic

viscosity and mixture density prediction.

We also presented a solution to readily acquire input parameters required to perform the

above stated calculations and to graphically present their results, using GIS database and

system. This does not require the use of any software that is not already available in most Oil

& Gas companies so the level of required investment to implement this calculation is really

low.

We tested our simulations against real data on the field and, on average, the model

overestimated pressure drop in around 10 to 30%. This shows that error is on the safe side and

that it is small enough to be practically applicable.

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Ngan, K.H., 2011, Phase inversion in dispersed liquid-liquid pipe flow (Doctoral thesis),University College London

Takcs, G., 2005, Gas Lift Manual, 1stedition, PennWell Books

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176_ASSESSMENT OF FLUID PRESSURE LOSS IN OIL & GAS IN-FIELD PIPELINES A GIS BASED APPROACH.pdf