well performance case study – gas well design
DESCRIPTION
pipesims softwareTRANSCRIPT
Presented by :Kelompok 5- Azhar Insan (124.11.023)- Lulut Fitra Fala (124.12.028)- Shilmi ardi (124.12.026)- Yeti Permata Sari (124.12.024)- Yoga Buana Pratama (124.12.029)
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