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.