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Well Performance Case Study – Gas Well Design

Perencanaan Teknik Migas I

For Vertical Well•Develop a fluid model (Task 1)•Calculated well deliverability (Task 2)•Select a tubing size for the production string (Task 3)•Determine choke size (Task 4)•Determine well head future performance (task 5)•Determine a Critical gas rate to prevent well loading (Task 7)

Overview

For Horizontal Well•Constructing the well model (Task 8)•Find optimum horizontal well length (Task 9)•Design horizontal well length (Task 10)

Cont’d

Vertical Well – Gas Reservoir

Develop a fluid model (Task 1)

formulae Component Moles

C1 Methane 75

C2 Ethane 6

C3 Propane 3

iC4 Isobutane 1

C4 Butane 1

iC5 Isopentane 1

C5 Pentane 0.5

C6 Hexane 0.5

C7+ Heptane plus 12

Formulae Aqueous (%bbl/bbl)

H20 Water 10

Input data Setup CompositionalFormulae Boiling point (oF) Molecular weight Spesific gravity Moles

C7+ 214 115 0.683 12

Phase envelop

Hydrate region

Non

-hyd

rate

regi

on

Gas kondesatTc < Tres < Tcricondenterm

Pres = 4600 psiaTres = 280 oF

Apakah hydrate dapat terbentuk pada case tersebut?

Dengan cara memutus salah satu rantai pembentukan hidrat.

Mencegah terjadinya hydrate ?

Hydrate

Hydrocarbon

water

High pressure,

low temperature

Minimum temperature,(MT) = 31.709 oFAmbient temperature, (AT) = 30 oF

MT > AT (hydrate region)MT < AT (Non-hydrate region)

In case

Vertical Well – Gas Reservoir

Calculated well deliverability (Task 2)

• Using Back pressure equation (after IPR calibrated)• Using well PI equation (before IPR calibrated)

Input data vert. completion

Input data Tubing

Cont’d

Pressure / temperature profile

Using Back pressure equation (after IPR calibrated)Using well PI equation (before IPR calibrated)

Cont’d

Reservoir Condition (before IPR calibrated) (after IPR calibrated)

%H2O saturation 1.8363 1.8363

@wellhead pressure = 900 psia

Gas rate, (mmscf/d) 17.145 14.168

Bottom Hole Pressure, (psia) 2003.8 1826.6

Bottom Hole Temperature, (oF) 253.98 251.59

Wellhead Temperature, (oF) 186

Flow correlations vertical flow (multiphase) : Gray (Modified)

C = 7.9489 x 10-7 mmscf/d/psia2(Flow coefficienct)n = 1 (non-darcy exponent)

Cont’d

Vertical Well – Gas Reservoir

Select a tubing size for the production string (Task 3)

Pressure / temperature profile

Screening to select tubing size :• Flow rate (High)• Erosion velocity ratio < 1• Cost (generally increases with size)

Flow rate (High)

ID tubing (inch) Flow rate (mmscf/d) Bottom hole pressure (Psia)

2.992 13.148 2149.4

4.892 15.111 1466.4

6.184 15.249 1405.6

Erosion velocity ratio (EVR)

ID tubing (inch) Erosion velocity ratio max Status

2.992 1.253 X

4.892 0.534 √

6.184 0.334 √

Tubing ID (inch) :2.992 < 4.892 < 6.184

Cost (generally increases with size) & conclusion

ID tubing (inch) Erosion velocity ratio max Flow rate (mmscf/d) Cost Status

2.992 1.253 13.148 standard X

4.892 0.534 15.111 Expensive √

6.184 0.334 15.249 >> Expensive x

Tubing ID : 4.892 inch

Cont’d

Outlet Pressure = 900 psia

Gas rate, (mmscf/d) 15.111

Bottom Hole Pressure, (psia) 1466.4

Bottom Hole Temperature, (oF) 245.63

Wellhead Temperature, (oF) 174

Max. Erosional velocity ratio 0.534

Tubing ID : 4.982 inch

Vertical Well – Gas Reservoir

Determine choke size (Task 4)

Set a number ID tubing : 4.982 inch

Input data Choke

Input data Flowline

Cont’d

Pressure / temperature profile

Output file

Cont’d

Po = 710 psia

Choke size 1.315543

Pressure losses across system

ΔP Reservoir (Pws – Pwf) 3133.7 psia

ΔP Tubing (Pwf - WHP) 566.31 psia

ΔP Choke (WHP - Choke) 188.7 psia

ΔP Flow-line (Choke - Flowline@300 ft) 1.04 psia

Tubing ID : 4.982 inch

Vertical Well – Gas Reservoir

Determine well head future performance (task 5)

Deactivate Choke and Flowline

Operations System analysis

Cont’d

Pressure (Psia) Gas rate (mmscf/d)

4600 15.1105

4000 11.0921

3500 8.1484

3000 5.5568

Vertical Well – Gas Reservoir

Determine a Critical gas rate to prevent well loading (Task 7)

• suatu akumulasi cairan dalam sumur gas sebagai akibat dari penurunan kecepatan gas sehingga fasa gas tidak mampu mentransportasikan droplet liquid ke permukaan dan menimbulkan back pressure ke formasi.

• Liquid loading umumnya terjadi pada sumur gas yang menghasilkan minyak kondesat saat terjadinya penurunan tekanan di bawah tekanan saturasinya. Untuk mencegah terjadinya liquid loading kita harus mengetahui critical gas rate pada sumur, nilai tersebut berupa titik minimum gas rate agar dapat mengangkat droplet liquid ke permukaan.

Liquid loading

Decrease gas rate

Operations nodal analysis

Cont’d

Critical gas rate = 2.944 mmscf/d

Beberapa metode untuk menanggulangi sumur gas yang sebelum terjadinya loading liquid :• Shut in, Metode ini dilakukan dengan cara menutup sumur gas sementara waktu untuk mem- build up sumur

dan kemudian memproduksikannya kembali.

• Small Tubing String : Tujuan penggunaan rangkaian tubing kecil ini adalah mengurangi daerah alir sehingga meningkatkan velocity gas dan liquid terangkat ke permukaan.

• Selecting of the choke size, ukuran choke yang akan digunakan berpengaruh terhadap laju alir yang ada dipermukaan. Untuk mencegah slugging pada tubing biasanya kita menggunakan ukuran choke yang sangat kecil namun dapat berdampak terhadap laju alirnya yang semakin besar.

• Swabbing : Metode ini dilakukan dengan cara memasang alat penyedot ke bawah permukaan dan mengangkat fluida ke permukaan. Tujuan dari metode ini hanya mengangkat cairan dari lubang sumur sampai energi reservoir mampu menanggulangi head hidrostatik yang tersisa sehingga dapat mengalir dengan sendirinya.

Cara menanggulangi liquid loading

Horizontal Well – Gas Reservoir

Constructing the well model (Task 8)

Import fluid model composition

Input data completion

Input data tubing

Constructing the well model

Horizontal Well – Gas Reservoir

Find optimum horizontal well length (Task 9)

Operations Optimum horizontal well length

Optimum horizontal length = 3,000 ftStock-tank gas at outlet = 24.68 mmscf/dEconomic limit (slope) = > 0.001 mmscf/d-ft

Horizontal Well – Gas Reservoir

Design horizontal well length (Task 10)

Constructing the well model

Input Data completion wellbore

Input Data Flowline

Input Data

Dengan cara yang sama menginput data berikut :

Name Inner diameter (inch) Temperature (oF) Horizontal length (ft)

Completion1 2.992 200 500

Flowline1 2.992 200 400

Completion2 2.992 200 400

Flowline2 2.992 200 400

Completion3 2.992 200 400

Flowline3 2.992 200 400

Completion4 2.992 200 500

Cont’d

Pressure / temperature profile

Cont’d

@ wellhead pressure = 900 psia

Gas rate (mmscf/d) 20.3478

Bottom hole pressure (Psia) 3062

Conclusion

Task 1• Berdasarkan komposisi fluid model yang di dapat, jenis fluida reservoir adalah gas

kondesat.• (Pres & Tres) single phase berupa gas di kondisi reservoir.• Hidrat terbentuk pada kondisi temperatur minimum sebesar 31.7 oF• Jika terjadi hidrat dapat menanggulanginya dengan memberikan bahan pelapis

berupa isolator pada pipa sehingga panas yang ada di pipa tersebut tidak mudah berpindah dan faktor temperatur diluar pipa tidak terlalu berpengaruh.

• Pada kondisi permukaan dapat menggunakan heater treater di surface facilities.Task 2Terdapat 3 faktor yang mempengaruhi perhitungan flow coefficient (C), yaitu :• Reservoir rock properties• Fluid properties• Reservoir flow geometry

Task 3

Task 4

ID tubing (inch) Erosion velocity ratio max Flow rate (mmscf/d) Cost Status

2.992 1.253 13.148 standard X

4.892 0.534 15.111 Expensive √

6.184 0.334 15.249 >> Expensive x

Tubing ID : 4.892 inch

Po = 710 psia

Choke size 1.315543 (maks. EVR = 0.534)

Pressure losses across system

ΔP Reservoir (Pws – Pwf) 3133.7 psia

ΔP Tubing (Pwf - WHP) 566.31 psia

ΔP Choke (WHP - Choke) 188.7 psia

ΔP Flow-line (Choke - Flowline@300 ft) 1.04 psia

Tubing ID : 4.982 inch

Task 5

Task 7

Pressure (Psia) Gas rate (mmscf/d)

4600 15.1105

4000 11.0921

3500 8.1484

3000 5.5568

High gas rate Droplet liquid slugLiquid loading

(no production)

Discussion & question