project notes.docx
TRANSCRIPT
ESTIMATING NOMINAL DIAMETER
Case 1 maximum inside diameter to avoid slippage
This corresponds to the minimum speed required (0.2 m/s) when producing 1000 bpd of liquid in
storage condition.
Specific gravity of light oil will be taken as 0.8
Specific gravity of gas will be taken as 1.1
GOR=200sm3/m3
From Temperature: 24°C + 35°C/1000m
Reservoir temperature at 3088m, TR=24+ 351000
x3088=1320C
Determine oil formation volume ratio, Bo from the chart, saturated oil volume factor"
Bo =1.82
Calculate flow rate at the bottom that gives 1000bpd with 50% water cut
QBH=BOQ0+BW BW
QBH=12(BOQO+BWQW )
QBH=12(1.82 x 1000+1 X1000)
QBH=1410bpd=0.002595m3
From bottom flow rate determine the required tubing ID (maximum)
Vmin=0.2m/s, Q=VXA
0.002595=0.2X πx ID2/4
IDmax=0,1285m=5.06 ¿
Case 2 minimum diameter to limit friction losses
Curves "BHP versus ID (inside diameter)" when producing 5000 bpd of liquid in storage condition
for the cases "WC = 0" & "WC = 50%" and for WHP = 20 bar are drawn referring to the charts
"Flowing pressure gradients" for a 3" ID tubing
1 2 3 4 5 60
500
1000
1500
2000
2500
3000
3500
f(x) = 33.7500000000001 x² − 361.107142857143 x + 3407
f(x) = 32.8571428571429 x² − 416.857142857143 x + 2784
BHP&WC=50%Trend LineBHP&WC=0%Trend Line
BHP versus TBG IDWHP=20bar
Depth=3088mBHP:PSI
ID:INCH
Flowing BHP w/ 0% WC
1700psi
From the chart;
Below 3” we risk to have high friction losses
Above 5” we risk to have problems of slippage
An ID of 3.548 was thus selected. Considering the 50% water cut curve, moving from 3.5” to 4”,
there is little benefit to reduce the bottom hole pressure. Considering the costs 3.548” was thus
chosen.
Nominal diameter
From 3.548”, internal diameter, select 4” nominal diameter.
Select L80 for preliminary study, for its low cost and H2S resistance.
Nominal weight, 9.50Ib/ft
Thread type, VAM top 100% connection&collar efficiency and gas tighted
PACKER SELECTION
Permanent packer (wire line set) will be used: FB-1(set packer in CSG, bigger seal is needed in
case of running through packer to liner)
Simple design
Easy to mill out
High strength and durability
Can be set accurately at a given depth
Packer will be set in 9 5/8 casing as to;
Minimise risks of liner cement failure
Easy to handle in 9 5/8 casing due to bigger ID
Easy to change especially in the depleted period
TUBING FORCES
Pressure testing tubing when running the tubing
Consider tubing full of gas plus 35bar for bull heading
WHP=(PR+BHM )−PH tbg
WHP=1.1 X308810.2
+35−0.3X308810.2
=277 bars
Forces when producing
With 0% water cut, from BHP versus ID charts, BHP when producing =118bars
Dynamic gradient
Geothermal gradient=350C/1000m=1.920F/100ft
Maximum dynamic gradient occurs at 5000bdp flow rate
Chart for flowing temperature gradient is given for 2 1/2 “tubing
For 3 ½ tubing multiply the actual flow rate by 1/3, which gives 1667bpd
From the chart dynamic temperature=0.890F/100ft=14.60C/1000m
Injection
Use frac pressure gradient of 1.8kg/l determined from leak off test carried out on Guasiporo,
(offset well)
Reservoir pressure gradient =1.1kg/l
Take equivalent density of 1.6kg/l for injection (between 1.1 and 1.8kg/l)
CONFIRMATION
Tubing parameters chosen
Collapse Pressure: 454bar
Burst Pressure: 545bar
Tension (pipe body yield): 954kNaN
Tubing pressure and force required from calculation:
Tension on top: 93 kNaN, Connection efficiency 100%
Burst pressure calculated: 305bar
Collapse pressure:307bar
So all the tubing parameters from chosen tubing can satisfy all the condition during life of
production and work over.