Overview of artificial lift technology and introduction to esp system

July 2010 G. Moricca 1

Electric Submersible

Pump Systems

-5 days course


Course agenda

Day 1

Overview of Artificial Lift Technology and

Introduction to ESP Systems

Day 2

ESP Basic Design and Operational Factors

Days 3

ESP System Components and their Operational Features

Day 4

ESP System design: step-by-step procedure

Day 5

ESP Installation Monitoring, Optimization, Troubleshooting and Diagnostic


Day 1 Course agenda

Overview of Artificial Lift Technology and

Introduction to ESP Systems

Pressure-Depth Relationship

Oil Composition and PVT Fluid Characterization

Reservoir Deliverability: Inflow Performance

Well Deliverability: Outflow (Tubing) Performance

System Performance Analysis: Nodal Analysis

Fundamental of Artificial Lift

Quick-look of most used Artificial Lift Systems

ESP System: Quick-look of Subsurface Components

ESP Pump Performance Curves

ESP System: Quick-look of Surface Components


Pressure-Depth

Relationship

Main sources: Well Completion Design. Jonathan Bellarby. Elsevier Inc


Pressure-Depth Relationship

At the end of this section, you will be able to…

● Calculate Fluid Gradient given Density

● Calculate the Pressure given Depth and Gradient or Density

● Calculate the equivalent Fluid column when given pressure

and gradient or Density

● Calculate the fluid gradient when given the pressure

differential and the Depth

● Estimate Fluid level or surface pressure when given

pressure at depth and fluid gradient

● Draw a simple pressure-depth plot.


Hydrostatic Pressure-depth relationshipfield units

ΔD=1ft ; ΔP= 0.45 psi

water gradient =

(ΔP/ΔD) = 0.45 psi/ft


oil gradient =



gas gradient =


The Pressure Gradient is the ratio among the Pressure variation (ΔP) from two points at different depth and the vertical distance among them (ΔD)

1 foot water oil gas

Ph = 0.45 psi Ph = 0.08 psiPh = 0.35 psi

Ph = 0 Ph = 0Ph = 0


Hydrostatic Pressure-depth relationshipmetric units

ΔD=1 m ; ΔP= = 1.000 kg/cm2

water gradient =

(ΔP/ΔD) = 1.000 kg/cm2 /10m

ΔD=1 m ; ΔP= = 0.800 kg/cm2

oil gradient =

(ΔP/ΔD) = 0.800 kg/cm2 /10m

ΔD=1m ; ΔP= = 0.017 kg/cm2

gas gradient =

(ΔP/ΔD) = 0.017 kg/cm2 /10m

The Pressure Gradient is the ratio among the Pressure variation (ΔP) from two points at different depth and the vertical distance among them (ΔD)

10 m water oil gas

Ph = 1.000 kg/cm2 Ph = 0.017 kg/cm2Ph = 0.800 kg/cm2

Ph = 0 Ph = 0Ph = 0


Hydrostatic Pressure-depth relationshipfield vs metric units

Units of Length

1ft = 0.3048m

1m = 3.2808ft

Units of Pressure

1psi = 0.0703kg/cm2

1kg/cm2 = 14.2233psi

Pressure Gradient

1psi x ft = (0.0703) kg/cm2 x ft

= (0.0703 x 3.2808) kg/cm2 x 1 m

= 0.2307kg/cm2 x 1 m

= 2.3067kg/cm2 x 10 m

0.4335psi x ft = (0.45 x 2.3067) kg/cm2 x 10 m

= 0.9999kg/cm2 x 10 m

1kg/cm2 x 10 m = 1/2.3067psi x ft

= 0.4335psi x ft


Pressure-Depth RelationshipThe Pressure gradient may be directly measured by downhole

pressure measurement using a formation pressure testing toot RFT

(repeat formation tester) or MDT (modular dynamic tester), or may be

calculated from surface fluid densities if a representative

formation fluid sample is available.

The reservoir fluid gradient (G), expressed in pound per square inch

per foot (psi), may be obtained by dividing the density (ρ) in pounds per

cubic foot by 144 sq in/sq ft.

Example

● Oil specific gravity = 0.850 (water = 1)

● Water density = 62.366 lb/cu ft

● Oil density = 0.850 x 62.366 = 52.955 lb/cu ft

● Oil gradient = 52.955/144 = 0.368 psi/ft

Fluid gradient = Fluid density / 144

and

Fluid density = Fluid Specific Gravity (water = 1) x 62.366

Calculating Pressure Gradient of Producing fluid

Data

● Producing fluid:

― Oil 25 API

― Water Cut (WC) = 80 %

― Formation water Specific Gravity = 1.04

● Density of pure water = 62.3 lb/cu ft

● Specific Gravity of pure water = 1

Calculate Pressure Gradient of Producing fluid

Solution

● Oil Specific Gravity = 141.5 / (131.5 + 25) = 0.904

● Producing fluid Specific Gravity = (SGwater x WC) + [SGoil x (1–WC)]

= (1.04 x 0.8) + [0.904 x (1–0.8)] = 1.013

● Density of produced fluid = 1.013 x 62.3 = 63.1099 lb/cu ft

● Gradient of produced fluid = 63.1099/144 = 0.438 psi/ft

July 2010 10G. Moricca

Calculating Pressure Gradient of Producing fluid

● To find a pressure at a givendepth (D), simply multiply theVERTICAL depth (elevation) by thegiven fluid gradient (G).

P = D x G

● For example, if my depth is 1200ft and gradient is 0.44 psi/ft, thenpressure is 1200 ft x 0.44 psi/ft =528 psi

● Assuming that the fluid isincompressible, this is a linearrelationship.

● We can draw this on a graph thatwe call the pressure-depth plot.

● Obviously, denser fluids, andtherefore higher fluid gradients,result in higher pressure.

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Oil 0.35 psi/ft Fresh water 0.433 psi/ft

Brine 0.50 spi/ft

Pressure = 0 at surface


Pressure – Depth (elevation) Plot



If the pressure at surface isn‟tzero, then the whole line shiftsover according to the surfacepressure.

If the lines maintain the same slope (they are parallel) this means that we are dealing with the same fluid.

Reservoir ASpecific Gravity Oil 0.809 (44°API)

Pore pressure gradient 0.35 spi/ft

Reservoir BSpecific Gravity Oil 0.809 (44°API)


Reservoir CSpecific Gravity Oil 0.809 (44°API)


B CA

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Pore Pressure Gradient 0.35 psi/ft

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Pore pressure Gradient 0.45 psi/ft




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Depleted Reservoir

Fliud Gradient 0.35 psi/ft

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Killed well


If the fluid doesn‟t reach the surface, then there is some „fluid level‟, or depth, where the pressure is zero and then the pressure increases according to the fluid gradient. This can be the result of two totally different situations:― Depleted reservoir or― Killed well


Calculating the Fluid Height or Fluid Column


● Similarly, if we know thepressure and the fluid gradient,we can calculate the equivalentfluid column resulting from thatpressure:

H = P/G

―Measured pressure = 2500 psi―Fluid gradient = 0.25 psi/ft―Equivalent fluid column =

2500/0.25 = 10.000 ft

● Here the effect of increasinggradient is reversed, and adenser fluid results in a shorterfluid column for a given pressure.

● Because oil is lighter than water(responsible of “normal” or“hydrostatic” pressure regime),this is the reason that oil wellsflow naturally !

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Calculating the Fluid Height or Fluid Column

Normal and Abnormal Pressure Regimes


In abnormally pressured reservoir, the continuous pressure-dept relationship is interrupted by a sealing layer, below which the pressure change. In order to maintain underpressure or overpressure, a pressure seal must be present. In hydrocarbon reservoir, there is by definition a seal at the creastof the accumulation, and potential for abnormal pressure regimes therefore exists. The most common causes of abnormally pressured reservoirs are:

Uplift/burial of rock

Thermal effects, causing the expansion or contraction of water

Depletion of a sealed or low-permeability reservoir due to production within the reservoir

Depletion due to production in an adjacent field

Normal and Abnormal Pressure Regimes

Normal Pressure Distribution from Surface through a Reservoir Structure


In the water column, the pressure at any depth can be approximated to:

P = D x Gw

where: D is the vertical depth and Gw is the pressure gradient

P = D x Gw

D = 5000 ft

Gw = 0.45 spi/ft

P = 5000 x 0.45 =

2250 psi

Normal Pressure Distribution from Surface through a Reservoir Structure

Gradient Intercept Technique


Two wells have penetrated the same reservoir sand. The updip well finds the

sand gas bearing, with gas down to (GDA) the base of the sands, whilst the

downdip well finds the same sand to be fully oil bearing, with an oil up to

(OUT) at the top of the sand.

Pressures taken at intervals in each well may be used to predict where the

possible gas-oil contact (PGOC) lies. At gas-oil contact the pressure in the oil

and gas must be equal otherwise a static interface would not exist.

Gradient Intercept Technique


Oil Composition

and

PVT Fluid

Characterization

Main source: Fundamentals of Reservoir Engineering. L. P. Dake. Elsevier Inc


At the end of this section, you will be able to

understand the…

● Hydrocarbon Phase Behaviour

● PVT parameters required to relate surface to reservoir

volumes for an oil reservoir

and…

● Calculate the PVT parameters through Empirical Correlations

● Estimate the PVT Properties from Production Data

Reservoir Fluids Characterisation


understand the…

● Hydrocarbon Phase Behaviour

● PVT parameters required to relate surface to reservoir

volumes for an oil reservoir

and…

● Calculate the PVT parameters through Empirical Correlations

● Estimate the PVT Properties from Production Data




Reservoir fluids are broadly categorised using those properties which are easy to measure, namely oil and gas gravity and producing GOR.


Crude oils: U.S. Bureau of Mines Classification


Crude oils are frequently classified by “base or key fraction”:

Paraffin-base, or oils containing predominantly paraffin series hydrocarbons

Asphalt-base, or oils containing predominantly polymethylene or olefin series hydrocarbons

Mixed-base, or oils containing large quantities of both paraffin and polymethyleneseries hydrocarbons

U.S. Bureau of Mines introduced a somewhat more elaborate system of classification which provides for nine possible classifications:

Crude oils: U.S. Bureau of Mines Classification

Crude oils Commercial Classification


West Texas Intermediate (WTI), a very high-quality, sweet, light oil delivered at Cushing, Oklahoma for North American oil

Brent Blend, comprising 15 oils from fields in the Brent and Niniansystems in the East Shetland Basin of the North Sea.

Dubai-Oman, used as benchmark for Middle East sour crude oil flowing to the Asia-Pacific region

Tapis (from Malaysia, used as a reference for light Far East oil)

Minas (from Indonesia, used as a reference for heavy Far East oil)

The OPEC Reference Basket, a weighted average of oil blends from various OPEC

The petroleum industry generally classifies crude oil by the geographic location it is produced in (e.g. West Texas Intermediate, Brent, or Oman), its API gravity and by its sulfur content. Crude oil may be considered light if it has low density or heavy if it has high density; and it may be referred to as sweet if it contains relatively little sulfur or sour if it contains substantial amounts of sulfur.

Hydrocarbon Phase Behaviour


Hydrocarbon reservoir fluid are acomplex mixture of hydrocarbonmolecules, the composition of which is dependent on the source rock, degree of maturation etc….

Phase changes occur when thiscomplex hydrocarbon fluid flow fromhigh temperature and pressure reservoir environment to the cool, low pressure separator conditions.

Hydrocarbon Phase Behaviour


Crude Oil Characteristics


Tank oil differs significantly from reservoir oil because:– Most methane and ethane are released from solution during production

– Sizeable fractions of propane, butanes and pentanes vaporize duringdecompression.

Reservoir fluids can be sampled for identification by:– Subsurface sampling– Surface sampling, to be recombined in proportion to measured GOR at

sampling time.

Full laboratory data is often unavailable

Satisfactory estimates can be made based on empirical correlations using a basic set of field data:– Gravity of tank oil– S.G. of producing gas– Initial producing GOR– Viscosity of tank oil– Reservoir temperature and initial pressure

Data from other wells in same reservoir is applicable. Not always!

Crude Oil PVT Behaviour


Undersatured oil: presence of only one phase (oil) in the reservoir

Satured oil: presence in the reservoir of two phases (oil and gas)

Reservoir pressure above

bubble point

Reservoir pressure below

bubble point

Basic PVT Parameters: Rs and Bo


Rs – The solution (or dissolved) Gas Oil Ratio (GOR), witch is the number of SCF of gas witch will dissolve in one STB of oil when both are taken down to the reservoir at the prevailing reservoir pressure and temperature.Unit: scf gas/stb oil

Bo – The oil formation volume factor, witch is the volume in bbl occupied in the reservoir, at the prevailing pressure and temperature, by one STB of oil plus its dissolved gas. Unit: rb (oil + dissolved gas)/stb oil

Basic PVT Parameters: R and Bg


R – Instantaneous or producing Gas Oil Ratio (GOR) Unit: scf/stb

Bg – The gas formation volume factor, witch is the volume in bbl that one standard cubic foot of gas will occupy as free gas in the reservoir at the prevailing pressure and temperature. Unit: rb (free gas)/scf gas

Rs – The solution (or dissolved) Gas Oil Ratio (GOR), witch is the number of SCF of gas witch will dissolve in one STB of oil when both are taken down to the reservoir at the prevailing reservoir pressure and temperature.Unit: scf gas/stb oil

PVT Parameters: Bo as function of pressure


Above the bubble pressure Bo

increases slightly as the pressure is reduced from initial to the bubble point pressure. This effect is due to liquid expansion and, since the compressibility of the undersatured oil in the reservoir is low, the expansion is relatively small.

Undersatured oil:one phase Satured oil: two phases (oil and gas)

Below the bubble pressure, as the pressure declines, since each reservoir volume of oil contains a smaller amount of dissolved gas, one stb of oil will be obtained from progressively smaller volumes of reservoir oil and Bo steadily declines with the pressure.

PVT Parameters: Bg and E as function of pressure


E – Gas Expansion FactorThe Gas Expansion Factor is the ratio between the volume of n moles of gas at standard condition (Psc =14.7 psia, Tsc = 60 Fahrenheit) and the volume of n moles of gas at reservoir conditions.Unit: vol/vol

From the Fig: The reservoir withdrawal of 1 (one) cubic foot of gas the when the prevailing reservoir pressure is 3300 psia gives about 200 cubic foot of gas at surface conditions.

Bg increases as the pressure declines, simple because (as per its definition) the volume, that one standard cubic foot of gas will occupy as free gas in the reservoir, increases as the reservoir pressure decreases.

The total underground withdrawal of hydrocarbons (oil and gas) associated with the production of one stb of oil is: (Underground withdrawal)/stb = Bo + (R – Rs)Bg

The above relationship shows why the gas formation volume factor has the rather unfortunate units of rb/scf.

PVT Parameters: R and Rs as function of pressure


As the pressure declines below the bubble pressure, more and more gas is liberated from the satured oil and thus Rs, which represents the amount of gas dissolved in a stb at the current reservoir pressure, continually decreases.

A typical plot of R, or more commonly GOR, as a function of reservoir pressure is shown in the figure.

The value of instantaneous or producing gas ratio R (scf/stb) or GOR, can greatly exceed Rsi, the original solution gas oil ratio, since, due to the high velocity of gas flow in comparison to oil, it is quite normal to produce a disproportionate amount of gas.

PVT Empirical Correlations


BgGas Volume Factor : Volume in ft3 that one scf of gas will

occupy at specific P and T conditionft3/scf Bg = 0,02827 TZ/P

Bo

Oil Volume Factor : Volume in bbl occupied by one STB of oil

and its associated solution gas when recombined to a single-

phase liquid at specific P and T condition (Standing)

bbl/STB Bo = Bob exp [co (Pb - P)] ;

R < Rs unsatured oil

Bob Oil Volume Factor at Bubble-point pressure (Standing) bbl/STB Bob = 0,9759 + 12*10-5

Y1,2

; R > Rs satured oil

co Undersatured Oil Compresibility (Vazquez) 1/psi co = 10-5

[- 1433 +5 Rs + 17,2T - 1180γg + 12,61γAPI ] / P

Eg Fraction of the total area occupied by gas dimensionless Eg = (1 -EL)

EL Fraction of the total area occupied by liquid (Liquid holdup) dimensionless EL = 5,645 Bo / [(R - Rs)Bg + 5,615(Bo + Bw Fwo)]

Pb Bubble-point Presure (Standing) psi Pb = 18,2 (W - 1,4)

Rs

Solution Gas/Oil Ratio : Volume of gas (in scf) going into

solution in one STB of oil at given P and T conditions. Rs is the

total volume of gas collected from all stages of separation,

divided the volume of stock-tank oil (case of undersaturated oil

production). Rs is function of P and T (Standing)

scf/STB Rs = γg (1,4 + P/18,2)1,205

10 (0,0151γAPI - 0,0011T)

W Constant W = ( Rs / γg )0,83

10 (0,00091 T - 0,0125 γAPI )

Y Constant Y = 1,25 T + Rs [γg / γo ]1/2

ρL Liquid density lbm/ft3 ρL = [62,4 (γSTO + γw Fwo) + 0,0136 γg R] / (Bo + Bw Fwo)

ρm Mixture (oil water and gas) density lbm/ft3 ρm = ρL EL + ρm (1-EL)

ρm Mixture (oil water and gas) density lbm/ft4 ρm = [62,4 (γSTO + γw Fwo) + 0,0136 γg R] / [Bo + Bw Fwo + (R - Rs)Bg / 5,615

ρo Oil density lbm/ft3 ρo = [62,4 γSTO + 0,0136 γg Rs] / Bo

ρw Water density lbm/ft3 ρw = 62,4 γw / Bw

PVT Properties Estimation from Production Data


Pwf Wellbore flowing pressure 2800 psia

Tw Bottomhole temperature 160 °F

Pwh Wellhead flowing pressure 800 psia

Twh Wellhead flowing temperature 120 °F

Qgsp Separator gas flow rate 96 Mscf/D

QLsp Separator liquid flow rate 265 bbl/D

Bosp Separator/Stock-tank oil volume factor 1,15 bbl/STB

co Undersatured Oil Compressibility psia-1

Bg Gas volume factor ft3/scf

ρo Oil density (at reservoir conditions) lbm/ft3

ρm Mixture density lbm/ft3

Psp Separator presure 200 psia

Tsp Separator temperature 90 °F

Rs sp Separator oil gas/oil ratio (GOR2) 30 scf/STB

γg1 Separator gas gravity 0,69 (air =1)

γg2 Stock-tank vapor (gas) gravity 0,89 (air =1)

γo Stock-tank oil gravity 0,863 (water =1)

γAPI Stock-tank oil gravity 28 API

Fwo Stock-tank water/oil ratio 0,07 STB/STB

Qo Qo = QLsp / [Bosp + Fwo] 217 STB/D

R Total (Producing) Gas/Oil Ratio (GOR) scf/STB

R R = Qgsp / Qo + Rs sp 472 scf/STB

GOR1 GOR1 = Qgsp / Qo 442 scf/STB

GOR2 GOR2 = Rs sp 30 scf/STB

Rs GORt = GOR1 + GOR2 472 scf/STB

γg γg = [GOR1 γg1 + GOR2 γg2] / [GOR1 + GOR2] 0,703 (air = 1)

W ( Rs / γg )0,83

10 (0,00091 T - 0,0125 γAPI )

(2.21) 138,7

Pb 18,2 (W - 1,4) (1.20) 2499 psia

Y 1,25 T + Rs [γg / γo ]1/2

(1.25) 626

Bob 0,9759 + 12*10-5

Y1,2

(1.24) 1,248 bbl/STB

co 10-5

[- 1433 +5 Rs + 17,2T - 1180γg + 12,61γAPI ] / Pb (1.23) 1,28E-05 1/psi

Bo Bob exp [co (Pb - P)] ;

case R < Rs unsatured oil 1 bbl/STB

Qo wb Qo Bo ; Oil rate at well bore condition 270 bbl/D

Bg 0,02827 TZ/P ; Z = 0,887 (1.14) 0,0182 ft3/scf

ρo [62,4 γSTO + 0,0136 γg Rs] / Bo (at reservoir conditions) 46,9 lbm/ft3

ρm [62,4 (γSTO + γw Fwo) + 0,0136 γg R] / [Bo + Bw Fwo + (R - Rs)Bg / 5,615] 47,8 lbm/ft3

Calculated PVT Properties

Production Test Data

Calculated parameters

Oil Gravity Conversion


API 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30

kg/l 0,966 0,959 0,953 0,946 0,940 0,934 0,928 0,922 0,916 0,910 0,904 0,898 0,893 0,887 0,882 0,876

API 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 50

kg/l 0,871 0,865 0,860 0,855 0,850 0,845 0,840 0,835 0,830 0,825 0,820 0,816 0,811 0,806 0,802 0,780

kg/l 0,990 0,985 0,980 0,975 0,970 0,965 0,960 0,955 0,950 0,945 0,940 0,935 0,930 0,925 0,920 0,915

API 11,4 12,2 12,9 13,6 14,4 15,1 15,9 16,7 17,4 18,2 19,0 19,8 20,7 21,5 22,3 23,1

kg/l 0,910 0,905 0,900 0,895 0,890 0,885 0,880 0,875 0,870 0,865 0,860 0,855 0,850 0,845 0,840 0,800

API 24,0 24,9 25,7 26,6 27,5 28,4 29,3 30,2 31,1 32,1 33,0 34,0 35,0 36,0 37,0 45,4

γo = 141,5 / (131,5 + γAPI )

γAPI = (141,5 / γo) - 131,5


ReservoirDeliverability:

Inflow Performance-

Pseudo-Steady-State Flow

Productivity Index

Vogel’s equation

Main source: Well Performance . M. Golan /C. H. Whitson. Prentice Hall Inc


Reservoir deliverability


● Calculate Outflow Pressure/Fluid Rate for a given set of

conditions using:

― Pseudo-Steady-State Flow

― Productivity Index

― Vogel‟s equation

● Calculate the absolute open flow (AOF)

● Generate an Inflow Performance Relationship (IPR)



Reservoir deliverability is defined as the oil or gas production rate achievable from reservoir at a given bottom-hole pressure.

Reservoir deliverability depend on several factors including the following:

● Reservoir pressure● Pay zone thickness and permeability● Reservoir boundary type and distance● Well radius● Reservoir fluid properties● Near well bare condition● Reservoir relative permeability

Symbolsp = average reservoir pressure, psiapwf = flowing bottom-hole pressure, psiaq = oil production rate, stb/dayµo = viscosity of oil, cpk = effective horizontal permeability to oil, mDh = reservoir thickness, ftr = reservoir boundary radius, ftrw = wellbore radius to the sand face, ftS = skin factor



The reservoir deliverability can be mathematically modelled on the basis of flow regimes such as:● Transient flow● Pseudo-steady-state flow● Steady state flow

An analytical relation between bottom-hole pressure and production rate can be formulated for a given flow regime.

The relation is called Inflow Performance Relationship IPR.

The discussion will be focused on:● Pseudo-Steady-State Flow● Productivity Index (PI)● Straight-line IPR● Vogel‟s IPR

Pseudo-Steady-State Flow

July 2010 G. Moricca39

Pseudo-Steady-State flow is defined as a flow regime where the pressure at any point in the reservoir declines at the same constant rate over time.

This flow condition prevails after the pressure funnel shown in fig. 3.1 has propagated to all no-flow boundaries.

A no-flow boundary can be a sealing fault, pinch-out of pay zone, or boundaries of drainage areas of production wells.

Qo = { Kh (p - pwf) } / {141,2 μo Bo [ln (re / rw ) - 0,75 + S] }

Reservoir deliverability vs Skin effect


The reservoir deliverability can be drastically reduced by the presence of positive skin.

S 0 5 10 20 50 100

Qo Oil rate STB/D 760 453 323 205 98 52

PI Productivity Index BOPD/spi 3,0 1,8 1,3 0,8 0,4 0,2

P Average reservoir pressure psi 3500 3500 3500 3500 3500 3500

Pwf Flowing bottomhole pressure psi 3250 3250 3250 3250 3250 3250

∆P Pressure Drawdown psi 250 250 250 250 250 250

K Average Formation Permeability mD 20 20 20 20 20 20

h Total net pay thickness ft 100 100 100 100 100 100

Kh Transmissibility mDft 2.000 2.000 2.000 2.000 2.000 2.000

μo Oil Viscosity cp 0,45 0,45 0,45 0,45 0,45 0,45

Bo Oil Volume Factor bbl/STB 1,4 1,4 1,4 1,4 1,4 1,4

re Drainage radius ft 1000 1000 1000 1000 1000 1000

rw Wellbore radius ft 0,29 0,29 0,29 0,29 0,29 0,29

S Skin dim.less 0 5 10 20 50 100

Pseudo-steady-state flow

Qo = Kh (∆P) / 141,2 μo Bo [ln (re / rw ) - 0,75 + S]

Sensitivity

Productivity Index and Inflow Performance Relationship


The expression Inflow Performance Relationship

(IPR) customarily is used to define the relation

between surface oil rate and wellbore flowing

pressure.

Perhaps the simplest and most widely used IPR

equations is the straight-line IPR,which states that

rate is directly proportional to pressure drawdown in

the reservoir.

The constant of proportionality is called the

Productivity Index, J, defined as the ratio of rate to

pressure drop in the reservoir.

The straight-line IPR is only used for undersaturated

oil, so we can write the equation as:

Qo = J(PR – Pwf)where:

PR is the average pressure in the volume of the

reservoir being drained by the well, and

Pwf is the bottom-hole flowing pressure.

Productivity Index


Productivity Index: J = Qo / (PR – Pwf)

Oil rate: Qo = J(PR – Pwf)

Pressure Drawdown: ΔP = (PR – Pwf)

● By convention, the dependent variable rate defines the x axis and the independent

variable, wellbore flowing pressure, defines the y axis.

● When wellbore flowing pressure equals average reservoir pressure (sometimes

referred to as static pressure), rate is zero and no flow enters the wellbore due to the

absence of any pressure drawdown.

● Maximum rate of flow , Qmax, or absolute open flow, AOF, corresponds to wellbore

flowing pressure equal to zero.

● The slope of straight line equals the reciprocal of the productivity index (slope = 1/J).

Example: Straight line IPR Calculation


ProblemThe well Lamar 1 was tested for eight hours at a rate of about 1800 STB/D. Wellbore flowing pressure was calculated to be 850 psia, based on acoustic liquid level measurement.After shutting the well in for 24 hours, the bottom-hole pressure reached a static value of 1125 psia, also based on acoustic level reading.The ESP pump used on this well is considered undersized, and a larger pump can be expected to reduce wellbore flowing pressure to a level near 350 psia (just above the bubble-point pressure).

Data:Qo = 1800 STB/DPwf = 850 psiaPR = 1125 psia

Calculate the following:1. Productivity index2. Absolute open flow based on constant productivity index3. Oil rate for a wellbore flowing pressure of 350psia4. Wellbore flowing pressure required to produce 60 STB/D

cont/...


Solution

1. Productivity Index

J = Qo / (PR – Pwf) = 1800/(1125 – 850) = 6.55 STB/D/psi

2. Absolute open flow

AOP = Qomax = (J) x (Pr) = (6.55) x (1125) = 7364 STB/D

3. Expected oil rate from a flowing wellbore pressure of 350 psia

Qo = J x (PR – Pwf) = 6.55 x (1125 – 350) = 5073 STB/D

4. The wellbore flowing pressure required to produce 3000 STB/D is

― Pressure Drawdown: ΔP = (PR – Pwf) = Qo / J = 3000 / 6.55= 458 psia

― Wellbore flowing pressure Pwf = (PR – ΔP) = 1125 – 852.3 = 667 psia

Example: Straight line IPR Calculation

Two-phase Flow IPR


Actual Qmax

Straight-line IPRpredicted Qmax

A limitation on the straight-line IPR is the assumption that oil is undersaturated, that is, only slightly compressible.

Obviously, this condition does not apply to gases or saturated oil wells which evolve considerable amount of gas, both of which are highly compressible.

The rate pressure relation shows curvature pronounced at higher rates.

Several equation have been suggested to represent the nonlinear IPR resulting from gas and two-phase flow.

An IPR equation traditionally used to describe oilwell performance in saturated reservoir is the Vogel (1968) equation.

Vogel’s equation


Vogel used a mathematical reservoir model to calculate the IPR for oil wells, producing from several hypothetical saturated reservoirs with widely differing oil characteristics, relative permeability, and well spacing.

After plotting dimensionless IPR curves for all cases considered, Vogel proposed an empirical relationship for Saturated, dissolved-gas-drive reservoirs.

2

max

8.02.01R

wf

R

wf

o

o

P

P

P

P

Q

Q

where qomax is the maximum oil rate (AOF) when wellbore flowing pressure pwf equal zero.

Vogel‟s equation may be solved directly for Pw as follows:

18081125.0

maxQ

QPP Rw

Use of Vogel’s IPR equation


1. Required test data to be used as input data:● Average reservoir pressure PR (psi)● Measured oil rate Qo (STB/D)● Measured bottomhole flowing pressure Pwf (psi)

2.Calculate Qomax using the rearranged Vogel’s equation

3. Using the already calculated Qomax calculate several rates atspecific drawdown (to have enough points to plot the IPR) by theVogel‟s equation

2max0

8.02.01R

wf

R

wf

o

P

P

P

P

QQ test data

2

max0 8.02.01R

wf

R

wf

oP

P

P

PQQ Selected bottom-hole

flowing pressure


WorkshopSession

-Vogel’s IPR

Workshop: Vogel’s IPR


Problem

A discovery well was tested at a rate of 200 STB/D with a bottom-hole

flowing pressure of 3220 psia. Bubble-point pressure was calculated with a

correlation using surface data measured when the well was producing at a low

rate. The estimated bubble point of 3980 psia indicates that the well is

draining saturated oil, since initial reservoir pressure was measured at

4000 psia.

Plot the IPR using Vogel equation.

2max0

8.02.01R

wf

R

wf

o

P

P

P

P

QQ

2

max0 8.02.01R

wf

R

wf

oP

P

P

PQQ


Test data● Average reservoir pressure PR 4000 psi● Measured oil rate Qo 200 STB/D● Measured bottom-hole flowing pressure Pwf 3220 psi

Solution1. Qomax = 200/[1 – 0.2(3220/4000) – 0.8(3220/4000)2] = 624 STB/D

2. If Pwf = 3000 psiQo = 624[1-0.2(3000/4000) – 0.8(3000/4000)2] = 250 STB/D

3. If Pwf = 2000 psi Qo = 437 STB/D



Workshop: Vogel’s IPR

0

500

1000

1500

2000

2500

3000

3500

4000

4500

0 200 400 600 800Bott

om

-ho

le p

ressu

re

-p

si

Oil rate - bpd

Vogel's IPR

Reservoir Inflow Performance: Summary


Inflow Performance Relationship (IPR ) is routinely measured using bottom hole pressure gauges at regular intervals as part of the field monitoring programme.

● Well Producing undersaturatedoil (no gas at the wellbore) or water have a straight line IPR

● PI is a useful tool for comparing wells since it combines all the relevant rock, fluid and geometry properties into a single value to describe (relative) inflow performance.

● AOF : Absolute Open hole Factor is the flow rate at zero (bottom hole) wellbore flowing pressure.

● AOF is useful parameter when comparing wells within a field since it combines PI and reservoir pressure in one number representative of well inflow potential.

cont/...

Reservoir Inflow Performance: Summary


● Straight line IPR are not applicable to when two phase inflow is taking place

(saturated oil is being produced )

● On saturated, dissolved-gas-drive reservoirs, Vogel IPR can be used

● When multi rates test data is available, the normalized equation q/qomax = [1-

(Pwf/Pr) ² ]n , is preferred since it includes high rate effect.

● The compressible natural of gas results in the IPR no longer being a straight line.

However, the extension of this steady state relationship derived from Darcy‟s Law,

using an average value for the properties of the gas between the reservoir and

wellbore leads to q = C ( Pr ² - Pwf ² ) valid at low flow rate.

● At high rate, non-Darcy ( or turbulent ) flow effects begin to be observed. This can

be account for by use of the “ Bureau of Mine” equation that was developed from

field observations: q = C ( Pr ² - Pwf ² )n; where 0.5<n<1.0.

−A log-log plot of q versus ( Pr ² - Pwf ² ) yields a straight line of slope n and

intercept C

− Standard practice for testing gas wells is to measure the bottom hole flowing

wellbore pressure ( Pwf ) at four production rate


Well

Deliverability-

Outflowor

Tubing Performance



● Calculate Friction Pressure losses assuming NO gas.

● Calculate the Outflow Pressure for a given set of conditions.

● Calculate the Outflow pressure against variable flow rates: Tubing

intake Curve.

● Plot the Outflow Curve or Tubing Performance Relationship (TPR).

● Use of the Kermit E. Brown‟s Vertical Flowing Pressure Gradient

working graphs to estimate the tubing intake pressure .

● Understand the effect on the TPR and the Pressure Traverse of the

pressure-loss components: Well-head Back Pressure (THP);

Hydrostatic, and Friction.

● Understand the different behavior of single-phase fluid, dry gas and

multiphase mixture, in terms of TPR and Pressure Traverse.

Well DeliverabilityOutflow or Tubing Performance


The well deliverability is governed by the behaviour of two basic factors:

1. the capacity of a reservoir to pass fluids against down-hole conditions: the Inflow Performance

2. the ability of the produced fluids to flow through the well conduit to surface: Outflow or Tubing Performance

The two factors are closely linked, because the final condition of the inflow performance is the starting point of the Outflow or Tubing Performance.

The Outflow or Tubing Performance depend on:● properties of fluids being produced● geometries of the production string

The performance analysis of the entire System, Reservoir and Production system (well and surface production system) is performed through the Nodal Analysis.

Well Deliverability


Well Deliverability

OPERATINGPOINT

QACTUALP

AC

TU

AL

NATURAL FLOWING WELLDEAD WELL

Flow rate Q

Pressu

re P

Outflow(TPR)

Inflow(IPR)


Well Deliverability

TPR

PI1 < PI2 < PI3


Well Deliverability

TPR



The effect on the TPR of the three main components:

THP – Hydrostatic - Friction

Single-phase−Friction losses are rate-dependent.−At low rates the flow is laminar and the pressure gradient changes linearly with rate.

−At high rates the flow is turbulent and the pressure gradient increases more than linearly with increasing rate.

Multiphase−Friction and hydrostatic pressure losses vary with rate in much more complicated manner.

− Increasing rate may change the governing pressure loss mechanism from predominantly gravitational to predominantly friction.

− The result of this shift is a change of trend in the TPR curve.

Gas well−Friction losses are rate-dependent.

−The Hydrostatic component increases (slightly) as the rate increase as consequence of higher pressure.


Tubing (Outflow) Performance

In terms the number of factors that determine the outflow

behaviour, outflow is more complicated than inflow.

The factors that affect outflow are:

● Tubing Wellhead Pressure

● Vertical Depth

● Flowing Fluid Properties (WC, GOR, oil density, fluid viscosity)

● Geometry (well deviation)

● Flow regime:

− single phase (laminar or turbulent),

− multiphase, (slug flow, annular flow, etc.)

● Tubing size, weight, and surface roughness

● Flow Rate



Tubing (Outflow) Performance

The outflow or Tubing Performance Relationship (TPR) gives the

relation among the fluid rate and pressure (Pout) required to

move the fluid from the entry point to the surface.

Pout = PTHP + Pgravity + Pfr

where:

PTHP is the Tubing Wellhead Pressure

Pgravity is the Hydrostatic (gravity) pressure

Pfr is the Friction component



Pressure losses in the tubing:Hydrostatic (gravity) pressure component

● Pgravity is simply determined by the vertical depth (elevation)

and the average fluid gradient (Fluid gradient = Fluid

density /144, in field units) of the fluid in the tubing.

● To find a pressure (Pgravity) at a given depth (D), simplymultiply the VERTICAL depth (elevation) by the given fluidaverage gradient (Gavg).

Pgravity = D x Gavg



Pressure losses in the tubing:Frictional pressure losses component

● Friction is quite more complicated than the other two Pressure losses

components.

● As noted above, friction depends on „everything else‟. This means that the

fluid phases, flow regime, well deviation and profile, fluid viscosity,

and tubing size all determine friction.

● Even without gas, there are several possible ways to estimate the friction in

a pipe due to flow. Examples are the Darcy-Weisbach equation and the

Moody diagram.

● One of the most used is the Hazen-Williams formula for friction losses in

water pipes.

● The Hazen–Williams equation is an empirical formula which relates the flow

of water in a pipe with the physical properties of the pipe and the pressure

drop caused by friction.

● The Hazen–Williams equation has the advantage that is not a function of the

Reynolds number, but it has the disadvantage that it is only valid for water,

NO gas.




Laminar Flow

Laminar flow, sometimes known as

stream-line flow, occurs when a fluid

flows in parallel layers, with no

disruption between the layers.

The dimensionless Reynolds number is

an important parameter in the equations

that describe whether flow conditions

lead to laminar or turbulent flow.

In the case of flow through a straight

pipe with a circular cross-section,

Reynolds numbers of less than 2300

are generally considered to be of a

laminar type; however, the Reynolds

number upon which laminar flows

become turbulent is dependent upon the

flow geometry.

http://upload.wikimedia.org/wikipedia/commons/a/ae/Stokes_sphere.svg



Turbulent Flow

In fluid dynamics, turbulence or turbulent flow is a fluid regime characterized

by chaotic, stochastic property changes.

For pipe flow, a Reynolds number above about 4000 will most likely

correspond to turbulent flow

Examples of turbulence

Smoke rising from a cigarette:

for the first few centimeters,

the flow remains laminar,

and then becomes unstable

and turbulent as the rising hot

air accelerates upwards.

http://upload.wikimedia.org/wikipedia/commons/c/cb/Humphrey_Bogart_by_Karsh_(Library_and_Archives_Canada).jpg



Reynolds NumberThe Reynolds Number is a non dimensional parameter defined by the

ratio of inertial forces (resistant to change or motion) to viscous

forces (heavy and gluey).

Pressure drops

through pipes can

be predicted using

the Moody

diagram which

plots the friction

factor f against

Reynolds

number Re and

relative

roughness ε / D.



Reynolds number: Laminar flow vs Turbulent Flow



Moody Diagram: Friction Factor vs Reynolds Number

Please note that

being Reynolds

Number

proportional to the

velocity (fluid rate)

and, in turn, the

fluid rate is

proportional to the

Friction factor, a

trial an error

calculation process

is required to

identify the friction

factor f.

Well DeliverabilityMultiphase Flow in Vertical Tubing


Flow pattern of Multiphase Flow

When the wellbore flowing pressure is greater than the bubble point

pressure, single phase oil is entering the well. Single phase flow

will continue until the pressure reduce sufficiently that the

bubble point is reached.

The flow patterns in the tubing that will result from this gas bubble

formation is a function of:

● Gas and Liquid flow rate

● Pipe angle of inclination

● Pipe diameter

● Phase density



Flow Pattern in Vertical Tubing

At Pb, the first gas bubble appear theFluid mixture‟s velocity in the tubingincrease and the average fluiddensity decrease.

1. The initially formed bubbles willbe widely disperse within the liquid,with the pressure decline in thetubing which increased the bubblenumber, while still dispersed in acontinuous liquid phase: Bubble flow

2. The increasing tubing volume fraction occupied by the gas allows bubblecoalescence to occur to such an extent that they fill the entire pipe crosssection and form a slug

3. Velocity increases, associated with continued expansion of the available gasand further volume increase of the gas, eventually result in the large gas slugbreaking up into a wider range of gasbubble sizes ( semi annular )

cont/...


4. Further upward fluid flow continues the gasliberation and expansion processes so thatthe phases separate into a central, highvelocity core of gas with a continuous filmof liquid on the tubing wall – The annularflow regime.

5. Shear at the gas/liquid interface resultingfrom continually increasing gas velocitieswill eventually destroy the annular ring ofliquid on the tubing wall and disperse it asa mist of small droplet – the Mist flowregime.



Hazen-Williams Formula for friction loss estimation

Basic Hazen-Williams formula is given by:

where:

f = friction loss rate (ft/1000-ft of measured tubing length)

C = Hazen-Williams roughness constant

- Typically 120 for most steel tubing applications

- Can be less for highly corroded tubing – 90 to 110.

Q = Flow rate (bpd)

ID = Inside diameter of pipe (in.)

Limitations:

The Hazen-Williams formula should be used for turbulent flow

(Reynolds's number > 105) with mono-phase fluids (NO free gas)


8655.4

852.1

3.34

100083.2

ID

C

Qf


Hazen-Williams Formula for friction loss estimation

We have traditionally presented this friction loss rate on a log-log

plot for various tubing diameters. See next page for the plot.

● To find the total friction HEAD (in distance), multiply the friction

factor (f ) by the total measured length of the tubing:

Hfr = f x Ltbg

● To find the friction pressure, convert the friction head to pressure

using the average producing fluid gradient:

Pfr = Hfr x GAVG


Well DeliverabilityHazen-Williams friction loss Graph



WorkshopSession

-Outflow or Tubing

Performance

WorkshopOutflow or Tubing Performance


Outflow Example

Data

― THP = 200 psi

― Vertical Depth = 3450 ft

― Measured Depth = 3700 ft

― Avg. Fluid SG = 0.95

― Tubing Size = 2-7/8-in. 6.5 PPF

― Flow = 2100 bpd

Calculate the Outflow Pressure (Pout) at the bottom of the

tubing (tubing intake)


Outflow Example - Solution

Pout = PTHP + Pgravity + Pfr

1. PTHP = 200 psi

2. Pgravity = Fluid Gradient x Elevation

Fluid Gradient = Fluid density / 144

Fluid density = Fluid Specific Gravity (water =1) x 62.3

Fluid Gradient = (Fluid SG x 62.3)/144 =

= (0.95 x 62.3)/144 = 0.411 psi/ft

Pgravity = 0.411 x 3450 = 1418 psi

Remember that 62.3 is the water density in lb/cu ft; 1 in2 = 144 ft2 and

therefore:

cont/....

ft

psi

inft

lb

in

ft

ft

lb433.0433.0

144

13.62

222

2

3



3. ID vs OD tubing

The tubing ID of 2.875 in OD - 6.5 PPF is: 2.441 in

4. Unitary friction factor (f)

The unitary friction factor (f) for tubing ID 2.441 in at 2100 bpd is:

5. Friction factor (F)

F = unitary friction factor (f) x measured depth

F = 39 (ft/1000 ft) x (3.7 thousand ft) = 144 ft

6. Pfr = F x Gavg = 144 ft x 0.411 psi/ft = 59 psi

Therefore : Pout = PTHP + Pgrvt + Pfr = 200 + 1418 + 59 = 1677 psi

ft

ft

x

xf

100039)441.2(

1203.34

2100100083.2 8655.4

852.1

Once again: For this specific setting, the pressure require to move the fluid from

the entry point (tubing intake) to the surface is: 1677 psi.

This pressure energy is provided, entirely or partially , by reservoir pressure

regime or by our intervention through an artificial lift system.



Outflow -Tubing Intake Curve

If we consider our previous example, but instead of one flow rate

we look at a set of flow rates…

− we can make a table with the components that determine Pout

− PTHP will not change with Flow Rate

− Pgrvt will not change with flow rate

− f, F, and Pfr will change with flow rate.

Q PTHP Pgravity f F Pfriction Pout

bpd psi 1418 ft/1000 ft ft psi psi

0 200 1418 0 0 0 1618

1000 200 1418 10 37 15 1633

2000 200 1418 36 132 54 1672

3000 200 1418 76 280 115 1733

4000 200 1418 129 477 196 1814

5000 200 1418 195 720 296 1914



Tubing Intake orTubing Performance Relationship (TPR)

0

500

1000

1500

2000

2500

0 1000 2000 3000 4000 5000 6000

Tu

bin

g I

nta

ke P

ressu

re (

psi)

Flow rate (bpd)

Tubing Intake Curve

Outflo (TPR)

Friction

Hydrostatic

THP




Vertical Flowing Pressure Gradient orPressure Traverse

For a given flow rate, well-head pressure and tubing size, there is

a particular pressure distribution along the tubing, starting its

traverse at the well-head pressure and increasing downward

toward the intake to the tubing.

The pressure-depth profile is called a Vertical Flowing Pressure

Gradient or Pressure Traverse.

The tubing intake pressure can be also estimated by use of the

Vertical Flowing Pressure Gradient working graphs.

In the next pages the step-by-step procedure to obtain the

bottom-hole flowing pressure (intake pressure) from the well-

head flowing pressure (and vice versa), by use of Kermit E.

Brown‟s working graphs will be illustrated.

Well DeliverabilityVertical Flowing Pressure Gradient


The Intake pressure can be estimated using the Kermit E. Brown Vertical Flowing Pressure Gradient working graphs.

The graph to be used must reflect the specific situation to be analysed:― Type of fluid: oil, gas, water or brines― Fluid properties: API gravity for

liquid, Specific Gravity for gas― Producing rate― Average flowing temperature― Tubing ID

The available commercial software are very useful tool for Vertical Flowing Pressure Gradient calculation.

Nevertheless, to familiarise with calculation procedure to obtain the bottom-hole flowing pressure from the wellhead flowing pressure (and vice versa), the use of the Vertical Flowing Pressure Gradient charts is strongly recommended.







In single-phase both gravitational and friction pressure gradients are constant along the tubing and therefore the pressure traverse is linear with depth.

In gas, it is very nearly linear even though the friction and hydrostatic pressure gradients vary significantly with depth.

In multiphase mixtures there is general trend of increasing pressure gradient with depth.Unfortunately, we do not have analytical equations or simple procedures for calculating the pressure traverse of multiphase mixtures

Well Deliverability


Summary

The outflow pressure drop is the pressure energy required to lift a fluid from the perforations to the wellhead and then to the separator.

The parameters which contribute to the pressure at the bottom (entry point or tubing intake) of the well are :

● Back pressure at the well head

● Hydrostatic head between the wellbore and wellhead, which is a function of the change in:

− elevation between the wellhead and the wellbore and the− average density of the fluid in tubing

● Pressure loss required to overcome friction losses due to viscous drag this depends on:

− fluid‟s flow rate− flow regime − viscous properties− length− diameter and− roughness of the tubing.

Magnitude of Outflow pressurecomponents:● Elevation 85 – 98 %● Friction 2 – 15 %


SystemPerformance

Analysis-

Nodal Analysis


System deliverability


● Understand the effect on the overall System deliverability

of the following parameters:

― Productivity Index

― Reservoir Pressure

― Skin effect

― Water cut

― Tubing ID

― Well-head flowing pressure

Nodal Analysis


To simulate the fluid flow in the system, it is necessary to “break” the system into discrete nodes that separate system elements.

Nodal analysis is performed on the principle of pressure continuity, that is, there is only one unique pressure value at a given node regardless of whether the pressure is evaluated from the performance of upstream equipment or downstream equipment.

To simulate the fluid flow in the system, it is necessary to “break” the system into discrete nodes that separate system elements.

Nodal analysis is performed on the principle of pressure continuity, that is, there is only one unique pressure value at a given node regardless of whether the pressure is evaluated from the performance of upstream equipment or downstream equipment.

The performance curve (pressure-rate relation) of upstream equipment is called inflow performance curve; the performance curve of downstream equipment is called out flow performance curve.

The intersection of the two performance curves define the operating point, that is, operating flow rate and pressure, at the specified node.

For the convenience of using pressure data measured normally at either the bottom-hole or the wellhead, Nodal analysis is usually conducted using the bottom-hole or the wellhead as the solution node.

Nodal Analysis: Schematic of Production System


Nodal Analysis: Locations of nodes


System Analysis consists of:

Selecting a point or node within the production system (well and surface facilities)

Equations for the relationship between flow rate and pressure drop are then developed for the well components both upstream of the node (inflow) and downstream (outflow)

The flow rate and pressure at the node can be calculated since: –Flow into the node equals flow out of the node.–Only one pressure can exist at the node

System Deliverability vs Productivity Index


System Deliverability vs Reservoir Pressure


System Deliverability vs Skin


System Liquid Deliverability vsWater Cut


System Oil Deliverability vs Water Cut


System Deliverability vs TGB ID



Fundamental

of

Artificial Lift

Main source: Well Performance. M. Golan /C. H. Whitson. Prentice Hall Inc




understand the basic of:

― Gas Lift

― Electrical Submersible Pump (ESP)

― Hydraulic Submersible Pump (HSP)

― Jet Pump

― Progressive Cavity Pump (PCP)

― Beam or Sucker Rod Pump



When reservoir pressure is insufficient to sustain the flow of oil to

the surface at adequate rates, natural flow must be aided by

artificial lift.

The rate-pressure relationship of a well is used for:

● Investigating the need to introduce artificial lift

● Selecting the most suitable lift system

● Determining its size and capacity

Three artificial lift systems are widely used:

● Positive displacement pumps (PCP, Sucker Rod, Reciprocating

Hydraulic pump)

● Dynamic displacement pumps (ESP, HSP and Jet pump)

● Gas lift

Approximately 50% of wells worldwide need artificial lift systems.

Methods of Artificial Lift


There are two basic forms of continuous artificial lift:● Downhole pump● Gas lift

Downhole pumps boost the transfer of liquid from the bottom-hole to the wellhead eliminating backpressure caused by the fluid flowing in the tubing.

Injection of gas into the production string aerates the flowing fluid reducing the pressure gradient and lowering backpressure at the formation.

For both lift methods, the production rate is increased by reducing wellbore flowing pressure.

The understanding of relationships among the pressure gradient

(backpressure) and bottom-hole flow condition to make possible the

flow is a fundamental step to design the Artificial Lift System and

select the proper action for its optimization.

Pressure Gradient Plot


Pressure Gradient Plot Analysis


● The IPR curve relates the wellbore flowing pressure Pwf to flow rate at the surface.

● The pressure traverse curve, at given wellhead pressure, determines the tubing intake backpressure Pin at a particular flow rate.

● Stable production can only exist if these two pressure Pwf

and Pin are equal.

In the pumping well, the pump provides the pressure

difference (Pin ― Pwf ) needed to overcome tubing

backpressure and sustain stable flow

Pressure Gradient Plot Analysis


The Pressure Gradient Plot indicates the limit on production rate achievable by each lifting method:

● Down-hole pumps may withdraw reservoir fluid at rate approaching the absolute open flow (AOF).

● In gas lift backpressure exerted by the flowing fluid column limits the reduction of wellbore flowing pressure and thus limits production to a rate significantly less than the AOF.

An important observation in the pressure diagram is that there exists a relationship between the:

― wellbore flowing pressure― liquid level in the annulus― casing backpressure

This relationship plays a significant role in determining the pump setting depth and its allowable pumping rate.

In pumping well, it is mandatory to settle the pump below the free gas-liquid contact. The free gas is intentionally segregated from the liquid before fluid enters the pump, being vented to the surface through the tubing/casing annulus. Eliminating free gas in pumps is a fundamental requirement for efficient pumping.

Quick-look of Artificial Lift

Systems


Main sources:

‒ Well Completion Design. Jonathan Bellarby. Elsevier Inc

‒ Schlumberger Oilfield Review

‒ Electrical Submersible Pumps Manual. Gabor Takacs. Elsevier Inc

Quick-look of Artificial Lift Systems


The basic information (concept, application, positive and negative

features) concerning the following Artificial Systems will be

provided:

Gas Lift

Electrical Submersible Pump (ESP)

Hydraulic Submersible Pump (HSP)

Jet Pump

Progressive Cavity Pump (PCP)

Beam or Sucker Rod Pump

Gas Lift


Gas lift consist of injecting high pressure gas from the surface to apredetermined tubing string depth to decrease fluid density in wellboretherefore reducing the hydrostatic load on formations which will allowreservoir energy to cause inflow and commercial hydrocarbon volumes canbe boosted or displaced to the Surface.

The gas injected through the operating valve in the tubing string enables the well to resume or increase production by:

● reducing the average fluid density above the injection point

● some of the injected gas dissolvinginto the produced fluids(undersaturated ) and the remainingin form of bubbles will expand as thefluid rise up the tubing string


Advantages

● Preferred method for wells with:– High gas oil ratio– High productivity index– Relatively high bottom hole pressure

● Suitable for medium rate

● Suitable for water drive reservoirs withhigh bottom-hole pressure

● Provides full bore tubing string access

● Low operational and maintenance cost

● Flexibility: can handle rates from 10 to 20.000 bpd

● Can handle (tolerate) produced solids

● Low surface profile, importantfor offshore / Urban locations

Disadvantages

● Gas has to be available

● Possible high installation cost– Compressor installation– Modifications to existing platforms

● Gas lifting of viscous crude (<15 API )is difficult and less efficient

● Difficult restart after shut down

● Wax precipitation problem may increase due to cooling effect from gas injection & subsequent expansion

● Hydrate blocking surface gas injection lines can occur if gas inadequately dried

● Limited by reservoir pressure and bottom hole flowing pressure.

Gas Lift

Electrical Submersible Pump


● The Electric Submersible Pump(ESP) is a multistage centrifugalpump driven by a downholeelectric motor.

● The pump unit consists of astacked series of rotatingcentrifugal impellers running on acentral drive shaft inside a stack ofstationary diffusers, it isessentially a series of smallturbines.

● Centrifugal pumps do notdisplace a fixed amount of fluidas do positive displacement pumps,but rather create a relativelyconstant amount of pressureincrease to the flow stream.

● The flow rate through thepump will thus vary dependingon the back pressure held on thesystem.


● The necessary rate and pressure to lift liquidsto surface are determined by the type andnumber of pump stages.

● The ESP is run in hole suspended to theproduction tubing. Therefore, if the downholeunit should fail, the tubing and pump should bepulled out together for repairs.

● Electric power is supplied to the motor by aprotected round or, in the case of limitedspace, flat cable unrolled along the outside ofthe tubing.


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http://images.google.it/imgres?imgurl=http://www.made-in-china.com/image/2f0j00rvbQmFoGHRzlM/Electrical-Submersible-Pump-Cable-QYPNY-.jpg&imgrefurl=http://www.made-in-china.com/showroom/liping1472/product-detailreVnFyhGgTUD/China-Electrical-Submersible-Pump-Cable-QYPNY-.html&usg=__O_UGS31E4aKy8a7W4f4TYybeio8=&h=750&w=1000&sz=63&hl=it&start=16&um=1&itbs=1&tbnid=ULfd25MWaOx3lM:&tbnh=112&tbnw=149&prev=/images?q=Electrical+Submersible+Pump&hl=it&rlz=1T4SUNA_itIT330IT330&sa=N&um=1


Advantages

● Preferred method for wells with:– Low gas oil ratio– High productivity index

● High water cut is not a restriction

● Can lift extremely high volume

● Flexibility: can handle rates from50 to 60.000 bpd

● Controllable production rate

● Comprehensive down-hole measurement

● Real time pump and well performance monitoring

● Can pump against high flow-tubinghead pressure

● Quick restart after shut down

● Long run pump life possible

Disadvantages

● Not applicable in case of:– High GOR– Sand production

● Tubing has to be pulled to replace the pump

● High cost for repairs, especially offshore

● High voltage (1000 V) electrical poweris required

● Susceptible to damage during completion

● No suitable for low volume wells: <150 BPD

● Power cable requires penetration of head and packer integrity

● Viscous crude reduce pump efficiency

● High temperature can degrade the electrical motor


Hydraulic Submersible Pump


Hydraulic pumps use a high pressure power fluid

pumped from the surface which :

● Drives a downhole, positive displacement pumps

● Powers a centrifugal or turbine pump

● Creates a reduced pressure by passage through

a venturi or nozzle where pressure energy is

converted into velocity

–This high velocity/low pressure flow of

the power fluid commingles with the

production flow in the throat of the pump.

–A diffuser reduces the velocity, increasing

the fluid pressure and allowing the

combined fluid to flow to surface

– The power fluid consists of oil or

production water

– The power fluid is supplied to the

downhole equipment via a separate

injection tubing

● The majority of installations commingle

the exhaust fluid with the production fluid through

the casing-tubing annulus


Advantages

● Range of application opportunities:― Small diameter wells not suited to

other Artificial lift methods― Tough retrofit completion and tough

liquid applications― As good alternative to the ESP

● The pump operate at higher speedthan an ESP (around three-four timeshigher revolution/min) therefore theyrequire few stages and are smaller

● No electrical connections or down-holeelectronics

● Flexibility: can handle rates from50 to 20.000 bpd

● Simple to operate: speed control by thevariation of supplied power fluid

● The power source can be remote from the wellhead giving a low wellhead profile attractive for offshore locations

● The power fluid can be commingled or returned in a separate conduit or disposed of down-hole

Disadvantages

● Pumps with moving parts have a short run life when supplied with poor quality power fluid. Solid-free power fluid is mandatory

● Commingle power-produced fluid imply:― power-produced fluids compatibility― power-produced fluids separation

● High GOR represent gas handling problems

● Viscous crude reduce pump efficiency

Hydraulic Submersible Pump

Jet Pump


Jet pumps are the only form of artificiallift that require no downholemoving parts.

Jet pump is an ejector-type dynamic-displacement pump operated by astream of high-pressure power fluidthat converges into a jet in the nozzleof the pump.

Downstream from the nozzle, thehigh-velocity, low-pressure jet ismixed with well‟s fluid.

The stream of the mixture is thenexpanded in a diffuser, and as theflow velocity drops, pressure is builtup.

They find wide application, generally inlow to moderate-rate wells.

Jet Pump well configuration


Jet Pump


Advantages

● No down-hole moving parts

● Compact and reliable

● Easily installed and retrieved bywireline

● No electrical connections or down-holeelectronics

● Simple to operate: Ideal for remote areas

● Power fluid does not to be so clean asfor hydraulic piston pumping

Disadvantages

● Less efficient than other pump systems

● Require large volume of power fluid

● Power fluid and reservoir fluids mast mix, so a key issues is the selection of an appropriate power fluid.This disadvantage can be turned into an advantage in heavy oil application

● Requires at least 20% submergence to approach the best lift efficiency.

● Very sensitive to any change in backpressure

Progressive Cavity Pump


Progressive cavity pumps (PCPs) are acommon form of artificial lift for low tomoderate rate wells, especiallyonshore and for heavy (and solidladen) fluids.

PCPs are positive displacement pumps,unlike Jet pumps, ESPs and HSPs.

Their operation involves the rotation of ametal spiral rotor inside either a metalor an elastomeric spiral stator.

Rotation causes the displacement of aconstant volume cavity formed by therotor and the stator.

The area and the axial speed of thiscavity determine the “no-slip” productionrate.

The pump in normally driven by anelectric motor.


Advantages

● Simple design

● Quick pump unit repaired by replacingrotor and stator as a complete unit

● High volumetric efficiency, in absence of gas

● High energy efficiency: above 80%

● Emulsion not formed due to low shearpumping action – ESP and HSP pumps

promote emulsion formation due to high pump speeds

● Capable of pumping viscous crude oil– Diluents mixed as required with crude

oil if extreme viscosities to be pumped– Water-like behavior observed at high

water cuts when oil becomes theinternal phase

● Performances:― Oil rate: up to 6000 BOPD ― Pressure: up to 3000 psi

● Long live with no abrasive fluid

● Compact and reliable

● Simple to operate: Ideal for remote areas

Disadvantages

● High starting Torque

● Short live with abrasive fluid

● The presence of the Elastomeric seal is the Achilles hell of PCP pump

Progressive Cavity Pump



● The Beam Pump is the oldest andmost common artificial liftmethod, simple in design and stillwidely used over the world. It is veryeconomical in low productionwells in shallow to middle depth oilfields.

● The system uses a verticalpositive-displacement pumpconsisting of a barrel with a checkvalve at its bottom (Standing Valve)and a Plunger fitted with anothercheck valve (Traveling Valve).

● The downhole Plunger ismechanically connected to a surfacewalking beam by Sucker rods string.

● The pump is rocked up and down bythe movement of the walking beamdriven by an electric or reciprocatingmotor.


● During the plunger's

upstroke, the standing valve

opens, the traveling valve

closes and the barrel fills with

fluid.

● During the down stroke,

the traveling valve opens, the

standing valve closes and the

fluid in the barrel is displaced

in the tubing.

● The pumping capacity of

the Beam Pump is governed

by several factors including

pumping speed, stroke

length, plunger type and size

and pump efficiency.



Advantages

● Most wide spread Artificial liftsystem, relatively simple, cheapand best known by field personnel

● Low rate: less than 100 bpd

● Low intake pressure

● Rod pumps are mechanically simpleto operate and easy to repair, maintain and replace.

● Readily accommodates volumechanges, flexible operation

● Viscous oil can be pumped

● Rather low operating expenses

Disadvantages

● Sensitive to gas

● Maximum capacity decreasing rapidly with depth

● Sensitive to solids (wax/scale/sand)

● Sucker rods susceptible to corrosion

● Equipment to heavy for offshore

● No suitable for highly deviated wells


Artificial Lift System Selection


The selection of the optimum artificial lift method is a process of balancing

the artificial lift capabilities and constraints against the production rate with

the ultimate goal of maximizing ultimate profits


The main factors governing selection of artificial lift methods are:1. Production rate to be achieved2. Down-hole flowing pressure3. Gas-liquid ratio4. PVT producing fluid characteristics

The other factors to be considered are:

● Operating conditions― Casing size limitation― Well depth― Intake capabilities ( minimum bottom hole flowing pressure)― Flexibility of the artificial lift system― Surveillance― Testing, and time cycle or pump off controllers

● Well conditions― Corrosion/ scale-handling ability― Solids/sand handling ability― Temperature limitation― High-viscosity fluid handling― High and low –volume lift capabilities.

Cont/…



● Situation (new field discovery , new well , existing well ):― Many choices may be available for a new field discovery, for which

constraints can be minimized by the production facilities and well design.

― A new well in an exiting field is constrained by the existinginfrastructure: choices become limited.

― An existing well has many fixed constraints (completion, well integrity, location accessibility, etc) that minimize lift selection possibilities.

The original field development plan should address all known constraints and consider future changes (depletion, GOR, water cut) to the lift method.

As a result of the above considerations, the type of artificial lift system should be selected:1. Positive displacement pumps (PCP, Sucker Rod, Reciprocating Hydraulic

pump)2. Dynamic displacement pumps (ESP, HSP, Jet pump)3. Gas lift

Cont/...



Based on reservoir production performance analysis, two different approaches

should be investigated:

Long term

Short term

Long term

This frequently leads to the installation of oversized equipment in the

anticipation of ultimately producing large quantities of water. As a result, the

equipment may have operated at poor efficiency due to under-loading over a

significant portion of its total life.

Short term

Essentially, to design for what the well is producing today and not worry

about tomorrow. This can lead to many changes in the type of lift

equipment installed during the well‟s production life. Low cost operations may

result in the short term, but large sum of money will have to be spent later

on to change the artificial lift equipment and /or the completion.


ESP System

-

Quick-look of

Subsurface Components



Electric Submersible CentrifugalPump System


understand the basic of ESP System Subsurface main

components:

Electric motor

Protector

Pump Intake

Pump

Cable


Electric submersible

system uses multiple

pump stages mounted

in series within a

housing, mated closely

to submersible electric

motor on the end of

tubing and connected to

surface controls and

electric power by an

armor protected cable.

Electric Submersible CentrifugalPump System


• The Electric Submersible Pump(ESP) is a multistage centrifugalpump driven by a downhole electricmotor using numerous stages ofimpellers and diffusers to createthe necessary rate and pressure(head) to lift liquids to surface.

• The main components of ESP are:motor, protector, and pump.

● Power is supplied to the motor viaspecially protected round or, in thecase of limited space, flat cablethat is run along the outside of theproduction tubing.

Quick-look of Subsurface components

motor

pump

protector

intake

Fluidlevel


Quick-look of Subsurface Components

ESP

Electric

Motor

● ESP‟s motor is a two-pole,

three-phase, squirrel-cage

induction type

● Submersible motors run at

3500 rpm, 60 Hz. (2917 rpm

and 50 Hz); unless

controlled by VSD.

● Currents range between

14 and 147 amps

● Voltages range between

280 and 4250 volts

● Horsepower range

between 7.5 and 450 HP


ESP’s Motor

● The motor is filled with refined

mineral oil that provides high

dielectric strength and lubrication.

● Heat generated by motor

operation is transferred to the well

fluid as it is flows past the motor

housing.

● A minimum fluid velocity of 1

ft/second is recommended to

provide adequate cooling

● Because the motor relies on the

flow of well fluid for cooling, a

standard ESP should never be set at

or below the well perforations or

producing zone unless the motor is

shrouded.


ESP’s Motor

Cable

Pump

Intake

Protector

Motor

Shroud


Seal

Mo

tor

Pu

mp

Shroud jacket

Shroud hanger

Fluid entryMotor shroud Designed to provide cooling to the motor when fluid velocities are below minimum.

Always used when perforations are above the intake.

ESP with Shroud


ESP’sMotor

Protector


The protector

is the piece

of equipment

that is

typically

placed above

the motor.

ESP’s Protector

The protector performs the following

basic functions:

● Connects the pump to the motor

● Provides the thrust bearing that

carries the pump thrust load.

● Prevents entry of well fluids into the

motor.

● Equalizes pressures between the

motor and the wellbore.

● Allows thermal expansion of the

motor oil resulting from operating heat

and motor oil contraction after

shutdown.


ESP’s Motor Protector

Mechanical

seal

Thrust

bearing

component


ESP’s Pump Intake

-Standard Intake

and

Gas Separator Intake


Bolt-on Intake

The intake is the entry point

of produced fluid into the

pump.

A standard intake does not

separate gas. Some gas

separation might occur with a

standard intake, but it will

only be natural separation due

to some of the gas not turning

and going into the intake

when the rest of the fluid

does.

ESP’s Standard Intake


ESP’s Gas Separator

A Gas Separator intake is used when the gas/liquid ratio (GLR) is greater than can be handled by the pump.

If the gas remains in solution, the pump will perform normally.Once the free gas increases, the pump will eventually “gas lock” which drastically reduces fluid production and in extreme cases can damage the pump.

There are two types of gas separator:● Static● Rotary

Staticseparator

Dynamicseparator


Bolt-on Intake

As producing fluid enters the gas

separator it is forced to change

direction. Some of the gas

bubbles continue to rise instead of

turn or rise inside of the gas

separator, exit the housing and

continue to rise.

Since this type of gas separator

does no real "work" on the fluid, it

is also called a "static" gas

separator.

ESP’s Gas Separator


ESP’s Rotary Gas Separator

The rotary gas separator design

works in a similar fashion to a

centrifuge. The centrifuge

"paddles" spinning at 3500 rpm

cause the heavier fluids to be

forced to the outside, through

the crossover and up into the

pump, while the lighter fluid

(vapor) stays toward the

center, and exits through the

crossover and discharge ports

back into the well.


Subsurface

Electrical

Centrifugal Pump


ESP

Pump

ESP System: Subsurface

Components and their Operational

Features


Centrifugal Pump Basic Concept

A centrifugal pump is a piece of

equipment that converts energy

of a prime mover (a electric motor

or turbine) first into velocity or

kinetic energy and then into

pressure energy of a fluid that is

being pumped. The energy

changes occur by virtue of two

main parts of the pump, the

impeller and the volute or diffuser.

The impeller is the rotating part

that converts driver energy into

the kinetic energy. The volute or

diffuser is the stationary part

that converts the kinetic energy

into pressure energy. TYPICAL STAGE

impeller diffuser

ESP’s Impeller


As liquid leaves the eye of the impeller a low-pressure area is created causing more liquid to flow toward the inlet. Because the impeller blades are curved, the fluid is pushed in a tangential and radial direction by the centrifugal force.

This force acting inside the pump is the same one that keeps water inside a bucket that is rotating at the end of a string.

The liquid enters into center (eye) of a revolving device (impeller). When the impeller rotates, it spins the liquid outward and provides centrifugal acceleration.

ESP’s Diffuser


The kinetic energy of a liquid coming out of an impeller is harnessed into diffuser creating a resistance to the flow. The resistance is created by the pump volute (Diffuser) that catches the liquid and slows it down. The liquid decelerates and its velocity is converted to pressure according to Bernoulli’s principle.



Each "stage" consists

of an impeller and a

diffuser. Again, the

impeller takes the fluid

and imparts kinetic

energy to it. The

diffuser converts this

kinetic energy into

potential energy

(head).



Radial and Mixed Flow ESP Pump



Radial Flow ESP Pump

Radial flow pumps have

low specific speed

and develop their head

mostly due to the

conversion of centrifugal

forces.

The specific speed is defined as: The rotational speed (RPM) required to produce a liquid rate of 1 gallon per minute against 1 ft of head.



Mixed Flow ESP Pump

Mixed flow pumps have high

specific speed and operate

only partially on centrifugal

force and more and more of

the total head is developed by

the lifting action of the

impellers.



The centrifugal pump is a multistage

pump, containing a selected number

(application dependent) of impellers

equipped with vanes, inside a closely

fitted diffuser, located in series an

axial shaft, driven by the electrical

motor.

One fact that must always be

remembered: centifugal pump

does not create pressure, it only

provides flow. Pressure is a just

an indication of the amount of

resistance to flow.


ESP’sPower Cable

ESP’s Power Cable


● Electrical power cable is used to transmit the power from the surface to the submersible motor.

● Power Cable consists of three copper conductor wires extending from the top of the motor flat cable lead to the wellhead.

● Power Cable consists of three copper conductor wires extending from the top of the motor flat cable lead to the wellhead.

● The size of the cable selected is based on amperage and voltage drop.

● Bottom hole temperature is critical for the selection of cable.

● The electrical cable has been refined over the years to be used specifically for oilwell applications.


● The conductor - electrical properties

● Insulation material - protects and covers the

conductor wire

● Barrier Jacket - protects and covers the

insulation.

● Jacket Material - rubber compound designed for

temperature, chemical, and gas considerations.

● The exterior armor - the outer shield that holds it

all together

The main components of the power cable include:

ESP’s Power Cable

ESP System

-

ESP Pump

Performance

Curves



Electric Submersible CentrifugalPump

At the end of this section, you will be able to:

― Understand the ESP Performance curves:

− pumping Head

− pumping Power

− pump Efficiency

― Use the ESP Performance curves

ESP Pump Performance Curve


The characteristic of

centrifugal pumps

(generally referred to

one single or 100

stages) are reported

in a standard form as

a graph (Pump

Performance Curve)

displaying curves of:

−pumping Head

−motor Load (BHP)

−pump Efficiency

versus the pump

rate.

HorsepowerMotor Load

(BHP)

Head

Pump Efficacy

These test curves are obtained by running a pump in water at constant speed

and varying its throughput by throttling the discharge side of the pump



Pumping HeadPumping head is the discharge pressure, expressed as a column of the pumped fluid liquid:

31.231.2

433.0

HP

PPPH

where:

ρ is density of pumped fluid in lb/ft3

γ is specific gravity of pumped fluid

(water=1)

The discharge pressure developed in a centrifugal pump increases with increasing liquid density.

When expressed in term of head, however, a given centrifugal pump develops the same head with various fluid having different density.

As a results, a single rate-head relationship developed with water is valid for other liquids with different densities.

Adjustments in the curve are required only when the viscosity of pumped fluid varies significantly from water viscosity.

Head


July 2010 G. Moricca159

Horsepower or Motor Load

The motor load curve gives the relationship among the mechanical

power (hhp) required to drive the pump (when pumping water) and the

flow rate.

HorsepowerMotor Load

(BHP)

The customary unit of

power for combustion

engines is horsepower

(HP) and for electrical

motors is the kilowatt

(kw).

The two power units are

related by: 1HP =

0.746 kw



The Pump efficiency (E) indicates

the efficiency of converting

mechanical power into a product of

rate and pressure (hydraulic power)

and then is defined as:

Pump efficiency sharply

decreases at low and high rate

Each pump has its maximum pump

efficiency range (yellow area) that

is the recommended capacity

range

powermechanical

powerhydraulicE

PumpEfficacy

Pump EfficiencyThe pump converts the mechanical energy in hydraulic power. The

hydraulic power is the energy provided by the pump in terms of fluid rate and

pressure.



From the

Pump Performance Curves

the following information

can be drawn.....



If the motor

of DN13000

ESP is fed at

60Hz, it run at

constant rate

of 3500 RPM,

regarding-less

the pump fluid

rate and the

corresponding

head.


One single stage

can provide

1000 bpd and

23 ft head per

stage or higher

rate (1600 bpd)

and lower head

(13 ft/stage).



At optimum flow regime (max

pump efficiency) one single

stage can provide 1300 bpd

and 20 ft head.

If 4000 ft head are needed,

200 stages are required.

If an oil 0.80 SG is produced,

the corresponding ΔP

provided by pump is:

(4000x0.80)/2.31 = 1385 psi

31.2

HP



At optimum flow

regime (max

pump efficiency)

the pump

provides the

maximum

pumping power

and......



...consequently the

maximum pump

efficiency is

achieved: more than

60%.



ESP System

-

Quick-look of Surface

Components


ESP System Surface Components


understand the basic of ESP System Surface main

components:

Transformer

Switchboard/Motor Control devise

Junction box

Variable Speed Drive System


Quick-look of Surface Components

Perforations.

Protector

Pump intake

Pump

Joint Tubing

Check valveDrain valve

Casing

MotorPothead

Motor flat cable

Primary cable

Production

WellheadJunction

box

Motor

controller

Transformers


Transformers generally are required because primary line voltage does not meet the downhole motor voltage requirements.

Normally, three individual transformers are connected together, in various configurations.

Transformer

Oil-immersed self-cooled (OISC) transformers are used in land-base applications.

Dry type transformers are used in offshore applications.

A single-phase transformer generally appears similar to the figure shown.


Switchboard/Motor Controller

The switchboard is basically a motor control device.

Voltage capability ranges from 600 to 4.900 Volt on standard switchboards.

The switchboards range in complexity from a simple motor starter/disconnect switch to an extremely sophisticated monitoring/control device.

The purpose of motor controller is to protect the down-hole unit by sensing abnormal power service and shutting down the power supply.

The monitoring function applies to both overload and under-load conditions.

It can be programmed to automatically restart the down-hole motor following a user-selected time delay if the fault condition is caused by an under-load.

Overload condition shut-down must be restarted manually.This should be done only after the fault condition has been identified and corrected.

The controller also provides the capability to monitor the Production system with the use of a recording instrument.


Variable-Speed Drive

The variable-speed drive (VSD) is a highly sophisticated switchboard-motor controller. A VSD performs three distinct functions:

● It varies the capacity of the ESP, varying the motor speed by varying the voltage frequency. Thus, well production can be optimised by balancing inflow performance with pump performance. This may eliminate the need to change the pump (workover) to match changing well conditions

● Protects down-hole components from power transients. The DSV is relatively insensitive to coming power balance.

● Provide a “soft-start” capability. Slowly ramping a pump up to operating speed may avoid pump damage.


Junction Box● A junction box connects the power cable from the switchboard to

the well power cable.

● Allows for any gas to vent that may have migrated through to

the power cable. This prevents accumulation of gas in the

switchboard that can result in an explosive and unsafe operating

condition. A junction box is required on all ESP installations.

● Provides easy accessible test point for electrically checking downhole equipment.


Wellhead

The Wellhead is the equipment that is installed at the surface of the wellbore. It‟s purpose is to:

● suspend the tubing string

● provide a pressure tight pack-off around the tubing and power cable.


ESP SystemsAbout 15 to 20 percent of almost one million wells worldwide

are pumped with some form of artificial lift employing electric

submersible pumps.

ESP systems are the fastest growing form of artificial lift pumping

technology. They are often considered high volume and depth

champions among oil field lift systems.

ESP systems can be used in casing as small as 4.5-in outside

diameter and can be engineered to handle contaminants commonly

found in oil-aggressive corrosive fluids such as H2S and CO2,

abrasive contaminants such as sand, exceptionally high

downhole temperatures and high levels of gas production.

Increasing water cut has been shown to have no significant

detrimental effect on ESP performance.

ESPs have been deployed in vertical, deviated and horizontal wells,

but they should be located in a straight section of casing for optimum

run life performance


ESP Artificial Lift Application Summary

1st day ESP course end

thanks for the attention


Mr. Aramais Arutunoffinventor of ESP (1919) and founder of REDA

Date post:	22-Jan-2018
Category:	Technology
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