Paper Esp New Design.docx

NEW ELECTRIC SUBMERSIBLE PUMP DESIGN FOR ZUG-10 OFFSHORE NORTH WEST JAVA Larasati Kris Sadewi STEM Akamigas Cepu [email protected]

Abstract PHE Offshore North West Java (ONWJ) is a mature field that located at North West Java Sea. Currently is producing 32500 bopd and 110 mmcfd. Most of oil well already depleted and requires artificial lift to produce oil to surface. Ten percent is using ESP (Electric Submersible Pump) as artificial lift, and the other ninety percent is using gas lift. ESP is currently installed only in Zulu and Papa Field, due to no gas source available (for gas lift), and the surface facility was designed for ESP since the begining of field life. This paper presents how to design Electric Submersible Pump and how to make selection for each part of Electric Submersible Pump that match with the well conditions, in this case is for one of Zulu well, ZUG-10. This well is deviated well and has a high water cut. There are four require parameters to consider what types of pump are possible and effective for the well: target rate, casing size, Total Dynamic Head (TDH) and frequency. This paper shows comparison of pump performance curves that possible for the well. Rate that close to minimum recommended operating range will have high risk of down thrust, in the other hand, if the rate close to the maximum recommended operating range it will high risk of up thrust. ESP that run in either down thrust or up thrust may result in pump damage, and may cause motor burnt out. The paper also present how much pressure required to lift the fluid to surface by calculating Total Dynamic Head before selecting Electric Submersible Pump.

I. Introduction

can be used for directional well and vertical well

In the early of an oil well live usually flow

until 15,000 ft of depth(1). The base to design an

naturally to the surface due to the high reservoir

ESP is in its pump performance curve. Pump

pressure, it is called “Natural Flowing Well”. As

performance curve is a technical data section of

time goes by, the reservoir pressure will

the ESP. This curve contains every information

decrease. In this condition, the reservoir pressure

necessary to make the pump is suitable for an

can not lift the fluid to surface, and an artificial lift

application. A typical pump performance curve

method is necessary. One of the artificial lift

has two columns. The left column shows pump

methods that mostly use in oil well is Electric

head that generated for each rate in the curve.

Submersible Pump (ESP). ESP is an artificial lift

The right column shows horse power and pump

method especially for producing large volume

efficiency

fluid. It can produce 100 bfpd – 60,000 bfpd, also

Recommended

for

each

rate

operating

in range

the

curve.

in

pump

performance curve must be considered when

will be calculated in barrel per day per psi. Here

selecting ESP because it shows the minimum

is the PI calculation:

and maximum flow rate that can produced by the pump.

From

pump

performance

"𝑃𝐼 = 𝑄/(𝑃𝑟) − 𝑃𝑤𝑓”

curve,

horsepower, head and pump efficiency can be known. There is another important parameter for selecting an ESP it is Best Efficiency Point (BEP). BEP is optimum point for its pump, it shows the most optimum flow rate which the pump can lift.

PI

= Productivity Index (barrel per day/psi)

Q

= Liquid rates (barrel fluid per day)

Pr

= Reservoir Pressure (psi)

Pwf = Well flowing pressure (psi)

Selecting every part of the ESP must consider the efficiency which will lead to lower operational cost.

The equation states that liquid flow in a well is directly proportional to drawdown pressure. It plots as a straight line on a pressure vs liquid flow rate

II. Data and ESP Selection Methods

diagram.

Offshore North West Java needed a new Electric Submersible Pump design for its field well. The new Electric Submersible Pump design is needed to lift a new target rate for one of their wells, ZUG-10. This well is deviated well and it has a high water cut (90%). ZUG-10 produced 1470 bfpd in 9th September 2017 and the ESP is still operating until now. However, since the ESP has been running for 1600 days and may fail in the future, PHE ONWJ need new ESP design for the replacement. The new target rate is 1600 bfpd, and need a new ESP design that efficient for the well. So, here is the steps to select every part of ESP that match with the well conditions. The proper design of artificial lift system requires a knowledge of the fluid rates that can be produced

from

the reservoir

and the

The new ESP pump design should deliver discharge pressure that will overcome the sum of friction losses along the flow path, net vertical lift, and wellhead pressure at the fluid production rate. In designing ESP it is called Total Dynamic Head (TDH). TDH is the important parameter for designing ESP. It will be used to determine the required number of pump stages a later phase of the design procedure. TDH is the sum of the following components, all expressed in length units: • The wellhead pressure at the given liquid production rate (convert from psi to ft) • The net hydrostatic pressure acting on the pump (Net Vertical Lift) • The friction loss that occurs in the tubing string at the given liquid rate

performance of the well. There is two parameters to describe the fluid rates that can be produced from the reservoir and the performance of the well. Those parameters show the formation productivity or the capability of the well to flow the fluid to surface. There are Productivity Index (PI) and Inflow Performance Relationship (IPR). Productivity Index (PI) is index that will show the

1. Wellhead Pressure Wellhead pressure is the pressure at the discharge of the tubing from the well. It is the resistance at the surface that the pump must overcome. For TDH calculation, the wellhead pressure will be converted dirrectly from psi to ft since all the calculation will be in ft unit.

capability of the reservoir to produce the fluid in barrel fluid per day at various well flowing pressure (Pwf) and it is called draw down. The method for this case will use Well Inflow Performance with The Constant PI Concept. PI

WHP (ft) =

WHP (psi) psi O. 433 ( ) x SG𝑐𝑜𝑚𝑝𝑜𝑠𝑖𝑡𝑒 ft

Pwf WHP (psi)

= Well flowing pressure (psi)

= Wellhead pressure at the given

liquid rate in psi

All the components in the Net Vertical Lift

SG composite = The weighted average of oil and

(NVL) calculation will be calculate in ft. So

water spesific gravity

the TDH calculation is the sum of NVL, Friction Loss and Wellhead Pressure.

2. Friction Loss TDH = NVL + FL + WHP

Friction loss is an energy loss caused by the flowing fluid through the tubing string until the surface. There are correlations that

TDH

= Total Dynamic Head (ft)

calculate the relationship between the pipe

NVL

= Net Vertical Lift (ft)

diameter and the friction loss itself. In this

FL

= Friction loss (ft)

case,

WHP

= Wellhead pressure in ft

Hazen

Williams

friction

loss

correlation is use for the calculation. All length in measured depth (MD).

ESP Design From the TDH it can be known every

F=

2.083 (

100 1.85 Q 1.85 ) x( ) C 34.3 ID4.8655

part of the ESP that will be selected from the catalog. There are steps for selecting ESP pump. Before do the ESP selection, it must

F

consider the well conditions. So we can

= Friction loss (Ft/1000 ft)

C = 120 (constanta given)

choose the best ESP for the well. Here is

Q = Liquid rates (bfpd)

the ZUG-10 well data: • Deviated well

ID = ID Tubing

• BHT

= 169 F

• Pr

= 700 psi

factors that will affect frictional pressure

• Pwf

= 90 psi

loss. First is pipe diameter. When the pipe

• SGwater

= 1.05

diameter increases, the frictional pressure

• °API

= 17

loss will decrease drastically. Second is

• PIP from well test = 623 psi

liquid rate. When the rate increase then the

• New Target Rate

friction loss will increase too

• Liquid Rate from well test = 1470 bfpd

From the formula there are two major

3.

Net Vertical Lift Net Vertical Lift is the vertical distance

= 1600 bfpd

• Water Cut

= 90%

• Step up tranformer

= 1100 V-

2800 V

from the expected fluid level to the surface

• Casing size

= 7”

that which need to be calculated so that the

• Tubing size

= 2 7/8”

fluid can be lifted to the surface. All depth

• Frequency

= 60 Hz

must be in TVD (True Vertical Depth) With the new target rate, ZUG-10 need a NVL = WFL = Perfo depth − (

Pwf ) 0.433 𝑥 1.04

new ESP design for its well. The well need an ESP which can produce 1600 bfpd in 7” of casing and 2 7/8” tubing. There are

NVL

= Net Vertical Lif (TVD-ft)

some guidlines for selecting every part of

Perfo depth

= Perforation Depth (TVD-ft)

the ESP.

1. Pump Selection

3. AGH Selection

The first step we need to do when

AGH (Advanced Gas Handler) is

designing an ESP is choosing the pump.

located at the top of VGSA (or standard

Before make a selection, target rate,

intake). Its function is to minimize gas

casing size, Total Dynamic Head (TDH)

locking in ESP pump. In the available

and frequency must be calculated. There

catalog there are CR Thrust, Head and

will be several pumps which possible for

Pressure information in the application

the liquid rates. Consider what type of

guidlines column.

pump which effective for the liquid rates that wanted to produce. After get the most

4. Protector Selection

effective pump, review the pump curve for

Protector is one of the important parts in

knowing the capability of the pump, such

ESP. It is used for preventing the motor

as recommended operating range, the HP

from the well fluids. The motor can be burnt

of the pump, the Head which needed for

if contaminated by well fluids. There are

lifting the fluid, and the pump efficiency.

some options in the protector catalog and it

When make a pump selection, the number

shows different conditions of the well. So

of stages required for lifting the fluid must

choosing the protector must consider the

will be determined by the TDH that has

conditions of the well. In protector, there are

been calculated.

three

types

of

protector

chambers,

labyrinth, bag and bellow with different 2. VGSA (or standard intake) Selection

model and different step of preventing the

VGSA is an intake of the pump that has

fluids. A protector mostly has multiple

capability to separate gas from the liquid

chambers.

These

chambers

can

be

before entering the pump. There are some

connected in series (designated with S) or

categories for choosing the proper intake

paralel (designated with P). In some

for the pump. In the pump catalog there is

standard applications, a protector can have

column that shows the series of the pump.

up to three-chambers and for extreme

When selecting a VGSA the series between

situation it may use up to four-chambers or

VGSA and the motor must be same or

even more.

bigger, but it is not recommended to choose the VGSA bigger than the motor. In the

5. Motor Selection

available VGSA catalog there are three

From the previous steps we know the

columns that show different information of

required HP of pump, VGSA, AGH and

the

physical

Protector. Then we must select a motor

spesifications that shows such as diameter,

horsepower base on these data. The

shaft size, make-up length and weight. The

motor series must be the same or bigger

other is the effective rates column, it shows

with the series of the pump, VGSA and

minimum and maximum effective rates that

AGH. Depends on the availability, the

overcome with the VGSA. And the last is an

motor may be made up in single or

application guidlines column, it shows a

tandem by looking at the catalog.

VGSA.

There

are,

shaft strength and power requirement of the VGSA.

6. Cable Selection Cable is one of the most important

2. SGcomposite SGcomposite = (fo x SGoil) + (fw x

parts in ESP. Inappropriate cable design

SGwater)

may result in cable burnt out. First the well

SGcomposite = (0,1 x 0,95) + (0,9 x 1,05)

temperature is needed for choosing one of

SGcomposite = 1,04

cable types. We can get the best cable size from the ampacity graph. There are

3. Wellhead pressure (ft)

graph and make a line up until it touches

WHP (psi) psi O. 433( ) x SG𝑐𝑜𝑚𝑝𝑜𝑠𝑖𝑡𝑒 ft 90 WHP (ft) = O. 433 x 1,04

the first size of the cable. After that make

WHP (ft) = 200 𝑓𝑡

several cable sizes in the ampacity graph (#1AWG, #2AWG, #3AWG, #4AWG, and #6AWG). Plot the temperature first on the

WHP (ft) =

the line left from that spot so we get the current at the temperature and the size of

From the calculation we get 200 ft for

the cable. Then it is important to make

Wellhead pressure.

sure this current is bigger than motor nameplate current, because if it too close

The second calculation is Friction Loss Calculation.

from the motor nameplate current it can burn the motor. After choose the right cable size for the ESP, calculate the Cable

F=

2.083 (

Voltage Drop to determine Required Voltage at surface and KVA.

Result and Discussion

F=

2.083 (

100 1.85 Q 1.85 ) x( ) C 34.3 4.8655 ID

100 1.85 1600 1.85 ) x( ) 120 34.3 (2.441)4.8655

F = 23.64 𝑓𝑡/1000𝑓𝑡

The first step to design an ESP is to calculate the TDH. From the well data, the first step that we can do is convert the Wellhead pressure from psi to ft.

TDH Calculation WHP (psi) WHP (ft) = psi O. 433 ( )x SG𝑐𝑜𝑚𝑝𝑜𝑠𝑖𝑡𝑒 ft

We need to multiply the value with the Pump Setting Depth (PSD) in MD (Measure Depth) for getting the friction loss in ft unit. 𝑓𝑡 F=F ( ) x PSD 1000𝑓𝑡 F = 23.64

𝑓𝑡 𝑥 2580 𝑓𝑡 1000𝑓𝑡

F = 61.01 𝑓𝑡

*Before do the WHP calculation, SG

From the calculation we get 61.01 ft friction

composite must be calculated first.

loss through the pipe.

Here is the SGcomposite formula: IPR Straight Line Calculation 1. SGoil = SGoil =

141.5

The next calculation for getting the TDH

131.5+ °API

141.5 131.5 + 17

SGoil = 0,95

is Net Vertical Lift calculation (NVL). Before calculate the NVL, we need the value of Pwf and PI of the well. Pwf in liquid rates from the well test of ZUG-10 we can get with

Pump Intake Pressure (PIP) calculation.

The next step is calculate the NVL all that in this

The value of PIP is given from the well test

calculation must be use in TVD (True Vertical

data.

Depth) Pwf NVL = WFL = Perfo depth − ( ) 0.433 𝑥 1.04 677.7 NVL = WFL = 2713 − ( ) 0.433 𝑥 1.04

PIP = Pwf − (Middle perfo − PSD) x Gf 623 = Pwf − (2706 − 2580) x 0,45 623 = Pwf − 56,7 Pwf = 679,7 𝑝𝑠𝑖

NVL = 1210 𝑓𝑡

In liquid rates from well test data we get

We get the NVL for this well. So we can

679,7 psi Pwf. So, we can calculate the PI

calculate the TDH that is need for the ESP

with the value of the Pwf at the liquid rates

to lift the target rates to the surface.

from well test data. IPR type in this case is straight line IPR.

TDH = NVL + FL + WHP TDH = 1210 + 61.01 + 200

Q PI = Pr − Pwf 1470 PI = 700 − 679,7

The pump needs 1417 ft to lift the target rate

PI = 72 𝑏𝑓𝑝𝑑/𝑓𝑡

to the surface.

TDH = 1471 𝑓𝑡

0

The next step is determine the Pwf at liquid rates target with PI formula.

500

Q Pr − Pwf 1600 72 = 700 − Pwf

1000 1500 2000

Pwf = 677,7 𝑝𝑠𝑖

2500

From the PI calculation we get the 677,7 psi

3000

Pwf at liquid rates target. The IPR Straight

Figure 2. Pressure and Depth Correlation

Line Calculation is shown in Figure 1. Pump Selection

IPR Straight Line

800

Pwf

From the well data, the new target rate is 1600 bfpd. So we need to design a pump

600

with enough stages to produce 1471 ft of head and 1600 bfpd for the target rate in 7”

400

casing size. There are several pumps that 200

possible for the target rate. But, after review the pump curves in the catalog the closest

0 0

10000 20000 30000 40000 50000

Q Figure 1. IPR ZUG-10

1500

Static Gradient Drawdown Perfo depth-PSD TDH

500

PI =

1000

0

pump is GN 1600 – 540 Series. From the GN1600 Pump Performance Curve we get: GN1600 – 540 Series HP

: 0.9 hp / stages

Head

: 44 ft / stages

Efficiency

: 60%

ROR

: 1000 – 2150 bfpd

It is a little different between VGSA Selection and AGH Selection. From the

From the review we can calculate number

catalog the best AGH for the pump is 540

of stages that needed for the pump

Series AGH G20-40 that require 37.5 HP.

TDH Head 1471 ft Stages = 44 ft/stages Stages =

Stages = 33 stages We also can calculate HP that are needed for one stage of the pump HP = HP x Stages HP = 0.9 x 33 HP = 30 HP The next is calculate available stages counting for the pump. From the catalog GN1600 will require one pump 1 EA 43 stages – 4.9 ft long. The pump performance curve GN1600 – 540 Series is shown in Figure 3.

With application ranges 2000 bfpd – 4000 bfpd.

Protector Selection When selecting protector for the pump, we need to review the conditions of the well. ZUG-10 has high water cut, medium temperature, deviated well, and has 17 °API. Also there is no chemical issue. From the conditions we should choose the best protector for that conditions. In the catalog the protector chamber which match with the conditions is Labyrinths and Bags. To avoid an extreme conditions of the well, the protector that will choose is BPBSL. Why we need to put the Labyrinth next to the motor is to avoid a possible vacuum for a bag that becomes collapsed. And the Series of the protector is NTB 2550 lbf – 540 Series – 1HP – BPBSL.

Motor Selection Before choose the motor we need to calculate total HP that will needed for the motor. Total HP is the sum from Pump HP, VGSA HP, AGH HP, and Protector HP. Figure 3. GN1600 Pump Performance Curve

VGSA Selection The series of the pump is 540 Series. So, we would need the series of VGSA that

Total HP = Pump HP + VGSA HP + AGH HP + Protector HP Total HP = 30 + 6 + 37.5 + 1 Total HP = 74,5 HP

is bigger or the same series with the pump. And after review the catalog, we choose 540 Series – VGSA S20-90 that require 6 HP. Because the target rates is close with the Effective Rates in VGSA Catalog (2000 bfpd – 9000 bfpd).

AGH Selection

To avoid the worst condition, there is a safety factor for the motor, as rule of thumb it is devided by 80%. Total HP 80% 74.5 Required motor HP = 80%

Required motor HP =

Required motor HP = 93.125 HP From Required Motor HP Calculation we can

This figure show Voltage Drop per 1000 ft.

choose the motor. So, from the catalog we

From the previous motor selection, we get

choose 562 series maximus motor – 113 HP

motor nameplate current 30.6 A. In the

– 2248 V – 30.6 A – S-GRB.

graph we put this number and draw straight line up to #4AWG curve. Then we draw again straight line to the left and finally we

Cable Selection When choosing the cable we need to check

got the result 15 for Voltage Drop per 1000

the well temperature. It is shown in Figure 4.

ft of Cable.

From the chart we have 160°F as the well temperature and we get 140 A for the

Cable Voltage Drop

maximum current in #4AWG. Meanwhile our

Cable Voltage Drop

motor nameplate current is 30.6 A which is

= (PSD + 100 ft) 𝑥 (𝑉𝑜𝑙𝑡𝑎𝑔𝑒 𝑑𝑟𝑜𝑝 𝑝𝑒𝑟 1000 ft)

much lower than the

Cable Voltage Drop = (2580 + 100) 𝑥 (15)

cable maximum

amperage that can handled (140 A). Thus it

Cable Voltage Drop = 40.2 V

is safe to use this cable size. From the catalog we choose Reda Max 400 Round - #4AWG for the cable. After

Required Surface Voltage Required Surface Voltage

choosing the cable, we need to calculate

= Motor Voltage + Cable Voltage

Cable Voltage Drop, Required Surface

Required Surface Voltage = 2248 + 40.2

Voltage and KVA.

Required Surface Voltage = 2288.2 V

KVA KVA =

Surface Voltage x Motor Ampere x 1.732 1000 2288.2 x 30.6 x 1.732 KVA = 1000 KVA = 121.3 KVA

Conclusion 1. The new Electric Submersible Pump design is needed to lift a new target rate Figure 4. Ampacity Chart

of ZUG-10 well. 2. TDH is the important parameter for designing ESP. It will be used to determine the required number of pump stages a later phase of the design procedure. TDH is the sum of the following components (Friction Loss, Net

Vertical

Lift

and

Wellhead

Pressure) all expressed in length units. 3. The

following

equipment

and

spesifications are a new ESP design for Figure 4. Surface Equipment Selection

ZUG-10 well that will deliver 1600 bfpd rate: 1. Pump: 540 Series, GN1600, 43 stages, 4.9 long 2.

VGSA: 540 Series, S20-90, 6 HP

3.

AGH: 540 Series, S20-40, 37.5 HP

4.

Protector: 540 Series, BPBSL,

NTB 2550 lbf, 1HP 5.

Motor: 562 Series Maximus Motor,

113 HP, 2248 V, 30.6 A 6.

Cable: Reda Max 400 Round

#4AWG

References 1. Diktat

Artificial

Lift

Design,

ESP,

Pusdiklat Migas, Cepu. 2. Gabor Takacs, Gulf Equipment Guides, Electric Submersible Pumps Manual: Design, Operations, and Maintenance, 1947.