Evaluation Study of Electric Submersible Pump (ESP) IND-1000 Pump Model with Analysis of the Flow Rate of Crude Oil in Production Well

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E-mail: [email protected] ISSN: 2580-278X (e) pp : 103-111

Evaluation Study of Electric Submersible Pump (ESP) IND-1000 Pump Model with Analysis of the Flow Rate of Crude Oil in Production Well

Isnani Agriandita

^1*

, Abdul Kamid

¹

, Reza Luthfi Atha Wijaya

¹

1Program Studi D-3 Teknik Perminyakan, Institut Teknologi Petroleum Balongan, Indonesia Jl. Soekarno Hatta Pekandangan, Indramayu, West Java

*Email:[email protected]

Article History

Received: 10 October 2022 Reviewed: 16 December 2022 Accepted: 30 December 2022 Published: 30 December 2022

Key Words

Well production rate; Pump Intake Pressure; Total Dynamic Head; Vogel methods; Range Capacity.

Abstract

ESP is an artificial lift with the principle of a centrifugal pump, where the production fluid that enters through the intake will be thrown by the impeller into the diffuser which will then be directed to the impeller above it so that this process repeats until the production fluid reaches the surface. The longer the production well is produced, the smaller or weakened the Pwf pressure will be, therefore an evaluation is needed in order to produce optimal production. The data needed include: well production rate (Qo), well flow pressure (Pwf), Pump Intake Pressure (PIP), Total Dynamic Head (TDH), Pump type, namely IND-1000 pump, Number of stages, Type of motor, HP motor, motor voltage, Electric current, OD motor, Total voltage, and Total starting voltage. The evaluation methodology used is to determine the optimum production rate through IPR calculations using the vogel method, Pump Intake Pressure (PIP), Total Dynamic Head (TDH), number of stages, and horse power (HHP). From the results of this evaluation, the optimal production rate (Qopt) value was obtained, which was 988.552 BPD. This optimal production rate value is still included in the capacity range, which is between 600-1260 BFPD.

Because the optimal production rate is still within the range capacity, this production well does not require a new pump replacement.

INTRODUCTION

Each production well to be produced is expected to flow naturally under the surface, but the longer the production well is produced the smaller the bottom flow pressure (Pwf) will be.

Pwf is the bottom flow pressure of a well that is closely related to the rate of production flow in the well. If the flow rate of fluid production is in the maximum condition then the Pwf value will be at the point of 0 psi (Ahuluheluw et al., 2020).

This can be interpreted to mean that the well has

not been reproduced because it has reached its maximum production limit.

In making undersurface fluid flow above the surface or optimize the production rate, a tool is needed, and the tool used is an Electric Submersible Pump (ESP) pump. ESP pumps are very suitable for use in offshore wells. The next reason is to facilitate scale countermeasures, the Gas Oil Ratio is low and the viscosity of the well is high, it is one of the reasons why an ESP pump tool was chosen, then the next reason is that the wells that want to be optimized for production

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rates have problems with their paraffins so that they are suitable to use ESP pumps, The last reason for the consideration of choosing an ESP pump is because the optimized well has an oblique or vertical shape.

The way to optimize the production rate is to find the IPR first, after already knowing the IPR, the next step is to optimize it to determine the size of the ESP pump, determine the stage of the pump at the stage of determining the pump stage, determine the Vertical Lift (HD), Fluid Over Pump (FOP), Friction Head (HF), and finally determine the Tubing Head (HT).

Electric Submersible Pump

ESP is a centrifugal pump with multistage (many levels) of which each level of this electric gymnastics pump consists of a moving part (impeller) and a stationary part (diffuser). A simple scheme of the ESP device is shown in Figure 1, where the ESP device is inserted into

the well and left submerged in the well fluid. The ESP motor is in the lowest position so that during operation they will cool the engine by a stream of fluid from the well passing through the outer surface of the motor. The motor is connected to a shield that plays an important role in maintaining the safety of the motor against leaks and the ingress of well fluid into the motor during operation or when not running. At the top of the protective plate, a pump inlet or air separator is installed to allow fluid from the well to enter the pump and at the same time remove part of the volume of dissolved gas in the production fluid (Jayanti et al., 2015). The principle of operation of ESP is to use centrifugal force, where the production fluid entering through the inlet will be discharged through the impeller to the diffuser which will be directed to the upper impeller for this process to repeat again until the liquid is produced to the surface.

Figure 1. ESP component (Takacs, 2007)

The criteria for a suitable production well to be installed ESP pump are (Sugiharto, 2012)

are (1) For production wells or injection wells in water flood

projects; (2)

Very suitable for

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coastal discharged wells; (3) Production fluid with low sand content; (4) To make it easier to overcome scale; (5) For pumping large amounts of liquid; (6) Low Gas Oil Ratio and High Viscosity; (7) For wells that have paraffin

problems; (8)

For inclined or vertical wells.

Productivity Index (PI)

Productivity Index is an index used to express the ability of a formation to produce at a certain pressure difference (Pranondo et al., 2020) or is a comparison between the production rate produced by the productive formation at the drawdown which is the difference in the bottom pressure of the well during the state condition and when the flow occurs.

Productivity Index (PI) can be determined in equation (1).

PI = J = ^𝑄

Ps − Pwf STB / day / Psi (1) Q is the flow rate of petroleum production or commonly referred to as the production rate in Barrel Per Day (BPD).

Inflow Performance Relationship ( IPR ) Inflow Performance Relationship (IPR) is a description of the reservoir's

ability to produce

oil. IPR is given as a graph which is the relationship between the flow pressure of the wellbed (Pwf) and the fluid flow rate (Q) which also comes from the flow of oil and water (single phase) and oil, water, gas (two phase) (Pranondo et al., 2020). Reservoir pressure (Pr) or writable (Ps), bubble point

pressure

(Pb), and Pwf affect the shape of the IPR curve. The shape of the IPR curve is straight if the Pr condition > Pb and Pwf

> Pb, while for the Pr > Pb and Pwf < Pb

conditions

the shape of the IPR curve is curved according to the pressure drop (Pranondo et al., 2020)(Guo et al., 2017).

In the calculation of the Vogel IPR curve can be done in the calculation as equation (2) (Sugiharto, 2012)(Wahono et al., 2015).

Qt = ^Qtmax

1− 0,2 (^𝑃𝑤𝑓

Ps) − 0,8 (^Pwf

Ps)² (2)

The calculation of the petroleum production rate uses the Vogel method because the type of fluid is a two-phase fluid.

Number of Stage Pumps

The basis for calculating the determination of the pump stage is the price of the Total Dynamic Head (TDH), which is the total pressure at which the pump works, which is expressed as the head or height of the liquid column (ft) (Nataliana et al., 2018; Sari et al., 2016; Wahono et al., 2015). The steps for the basic calculations begin with determine Number of pump stages (SN) as describe in equation (3).

The next step is to get Total Dynamic Head (TDH) (equation (4)). Then

SN = ^TDH

HSP (3) TDH = HD + HF + HT (4) SG_f= ( (1 − WC ) SG_o + WC X SG_w) (5) 𝐺𝑓 = 𝑆𝐺𝑓 𝑋 0,433 ( 𝑃𝑆𝑖 / 𝐹𝑡 ) (6) Pump Intake Pressure (PIP)

PIP = P_wf− (Depth Differences x G_f (7) Depth Difference

Depth Differences = Mid Perforasi-pump setting depth (8)

Fluid Over Pump ( FOP )

FOP = PIP / G_f (9) Vertical Lift (HD)

HD = pump setting depth − FOP (10) Head Friction (HF)

HF =

Friction loss per 1000 ft x pump setting depth / 1000 (11)

Tubing Head (HT)

HT = P_wh / G_f (12)

Friction Loss F = 2,083 x (¹¹⁰

C )^1,85 x ⁽

Q 34,3)^1,85

(ID)^4,8655 (13) Horse Power (HHP) is define as equation (14).

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HHP = (stage p𝑜𝑚𝑝𝑎 x_stage^Hp x SGf) + 5 (14)

Description:

SN = Number of pump stages SGf = Specific Gravity of Fluid SGo = Specific Gravity of Oil

WC = Watercut, the percentage of water in the production well

TDH = Total dynamic head, ft HSP = Head per stage pump HD = Vertical lift, ft

HF = Distance of pressure loss due to friction loss in tubing, ft

HT = Pressure loss distance along the tubing, ft

F = Friction Loss HHP = Horse Power

Submersible Electric Pump Size Selection The selection of the size of the submersible electric pump should correspond to the magnitude of the production rate expected on the appropriate head. Besides , casing size is also a decisive factor in choosing an effective source power pump size, usually by choosing the highest series that has the largest diameter as long as the casing size is possible. (Wahono et al., 2015)

In choosing the size of the source electric pump to be used, in addition to having to be

adjusted to the expected production rate, the production rate must also be within the recommended optimum range so that efficiency is obtained as recommended.

METHOD

The data processing used in this study is secondary data that had been taken from petroleum production wells.

The data used in the data processing process is Inside Diameter casing, tubing, top perforation, depth mid perforation, bottom perforation, pump setting depth, pr, pwf, p tubing, p casing, fluid production rate test (Qt), oil production rate (Qo), actual fluid production rate (Qaktual), water cut (WC), pump type, frequency, stage, API, specific gravity oil (Sgo), specific gravity water (Sgw).

After the data are collected, in evaluating the flow rate of production fluid with ESP, it is necessary to calculate the Productivity Index (PI), Inflow Performance Relationship (IPR), determine the expected flow rate, calculate the number of pump stages or SN, calculate the Total Dynamic Head (TDH), determine pump intake pressure (PIP), Total Dynamic Head (TDH), number of stages and determine horse power (HHP) (see Figure.2)

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Figure 2. Research flow chart RESULTANDDISCUSSION

The secondary data are used in this evaluation study are pump data consist of well data also (see Tabel 1).

Discussion

From the data obtained in table 1 with a production rate (Qo) of 960 BPD, reservoir pressure (Pr) of 1066 Psi, and well flow pressure (Pwf) of 430 Psi, a productivity index (PI) of 1.5

09 STB / day / Psi and a maximum and optimum production rate through the IPR curve with the vogel method in figure 3 and the IPR table in Table 2 is 1216.49 BPD and BPD with an optimum Pwf of 416.155 Psi. The optimum production rate value obtained from 80% x maximum production rate 973,19 𝐵𝑃𝐷 (Jaya et al., 2014; Wahono et al., 2015).

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Tabel 1 Pump Data ESP

Qo 960 BPD

Pr 1066 Psi

Pwf 430 Psi

Pwh 80 Psi

Spesific Gravity Oil 0,9111

Spesific Gravity Water 1,015

Spesific Gravity Gas 0,746

Pump Setting Depth 7491,9 Ft

Water cut 90 %

Types of pumps IND 1000

Tubing (OD)

31 2

Inch Tubing (ID)

23 4

Inch

Range capacity 600 - 1260 BPD

Case size 7 inch

Number of stages 187 stage

Mid perforasi 7596 ft

Bottom perforasi 7611 ft

Top perforasi 7581 ft

Types of motors Seri 540

HP motor 240 HP

Motor voltage 1710 volt

Correction Factor 110

Figure 3. IPR curve, Q vs Pwf

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The curve in Figure 3 is obtained from curve data results of IPR in Tabel 2.

Tabel 2 Curve Data Results IPR

Pwf ass Qgross ass

0 1216,49

50 1202,94

150 1162,99

250 1105,91

350 1031,70

416,155 973,19

450 940,36

550 831,90

650 706,30

750 563,58

850 403,73

950 226,75

1050 32,65

1066 0,00

Figure 4 ESP IND 1000 Pump Performance Curve. The blue line is the Qoptimum value, the green line is the Efficiency Pump

value

, the red line is the head/stage value, and the yellow line is the HP

value

(PT. Epsindo Jaya Pratama, 2006).

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Tabel 3 ESP Pump Result

Data

before Evaluation and After Evaluation

No Parameter Symbol Before After

1 Laju Produksi Qopt 960 BPD 973.19 BPD

2 Pump Setting Depth PSD 7492 ft 7492 ft

3 Pump Intake Pressure PIP 37.4 psi 394.3738 psi

4 Total Dynamic Head TDH 6747.62 ft 6845.36 ft

5 Type of Pumps - IND1000 IND1000

6 Stage S 187 stage 324 stage

7 Type of Motor - Seri 540 Seri 540

9 HP Motors - 240 HP 96 HP

10 Motor Voltage Vmotor 1710 Volt 1710 Volt

Calculation of the number of stages

After the IPR chart is known, a pump evaluation is carried out by calculating the determination of pump intake pressure (PIP), total dynamic head (TDH), number of stages and determination of horse power (HHP) through Figure 4. Pump performance curve is the pump performance standart from the oil company consisted of the variation of the pump, optimum production rate interval, efficiency pump value, head/stage value, and horse power (HP) value).

So that the results of the evaluation of the esp installed pump can be obtained which can be seen in Table 3.

From the head / stage value in figure 4 of the IND 1000 pump performance curve is 22.2 ft , the number of stages is obtained 307 stages, because the pump does not provide 307 stages, a pump stage that is close to the total stages is selected, namely 324 stages with horse power (HHP) obtained 96 HP.

From the results of the analysis that has been carried out on the production

well

, it can be seen that

the

results of the evaluation of the ESP pump attached to the well produce an optimal production rate of 973.19 BPD but after an evaluation there is no need to replace the pump on the well because it is still in

the

cappacity range, which is 600 – 1260 BPD (see Figure 4).

CONCLUSION

Based on the results of the evaluation that has been carried out regarding the oil production rate in the well installed Electric Submersible Pump (ESP) model IND-1000, it can be concluded that the maximum and optimum production rate through the IPR curve with the

vogel method is 1216.49 BPD and 973.19 BPD with an optimum Pwf of 416.155 Psi.

The results of the evaluation of the optimum production rate that is still included in the range capacity of an ESP pump model IND-1000, so in this production well there is no need to change pumps.

ACKNOWLEDGEMENT

The Authors are giving credit or appreciation to the student Reza Luthfi Artha Wijaya and Institut Teknologi Petroleum Balongan (ITPB) that already support this research and publication.

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Evaluation Study of Electric Submersible Pump (ESP) IND-1000 Pump Model with Analysis of the Flow Rate of Crude Oil in Production Well