IPR analysis

Current Oil Wells IPR

RAML Field was initially an under-saturated reservoir , once its reservoir pressure dropped

below the reservoir bubble point pressure bP ( 925bP psia from the PVT reports ) , it

would be a saturated reservoir .

For such a reservoir , when it is needed to construct an IPR for a well . We must consider two

cases :

I. The Under-saturated Part of the Reservoir Life :

IPR curve for such case involves a straight line ( of constant slope of Productivity Index; J ) at

the early portion when t b0.0 q q . Note that the flow rate at the bubble point pressure

is denoted as bq .On the other hand; the IPR Curve has a curvature portion at the range of

b t maxq q q .

There are two possible outcomes to the recorded stabilized flow test data that must be considered , as shown schematically in Fig 1

1) Recorded Stabilized wf bP P :

To determine the IPR in this case , the following procedure is followed :

Step 1 . Using the stabilized test data point (oQ and

wfP ) calculate the productivity

index J :

rP

o

wf

QJ

P

Step 2. Calculate the oil flow rate at the bubble-point pressure:

r(P )ob bQ J P

Where obQ is the oil flow rate at bP

Step 3. Generate the IPR values below the bubble-point pressure by assuming different

values of wf bP P and calculating the corresponding oil flow rates by applying the

following relationship: 2

1 0.2 0.81.8

bo ob

JP Pwf PwfQ Q

Pb Pb

The maximum oil flow rate ( o maxQ or AOF ) occurs when the bottomhole

flowing pressure is zero, i.e. wf P 0 , which can be determined from

the above expression as:

o maxQ1.8

bob

JPQ

It should be pointed out that when wf bP P , the IPR is linear and is

described by:

r(P )o wfQ J P

2) The Value of the Recorded Stabilized wf bP P :

When the recorded wfP from the stabilized flow test is below the bubble-point

pressure, as shown in Fig 1, the following procedure for generating the IPR data is proposed: Step 1. Using the stabilized well flow test data and solve for the productivity index J to give:

2

r(P ) 1 0.2 0.81.8

o

b wf wfb

b b

QJ

P P PP

P P

Step 2. Calculate obQ by :

r(P )ob bQ J P

Step 3. Generate the IPR for wf bP P by assuming several values for wfP above the

bubble point pressure and calculating the corresponding oQ from:

r(P )o wfQ J P

Step 4. Calculate oQ at various values of

wfP belowbP , or:

2

1 0.2 0.81.8

bo ob

JP Pwf PwfQ Q

Pb Pb

II. The Saturated Part of the Reservoir Life : When the reservoir pressure equals the bubble-point pressure, the oil reservoir is referred to as a saturated oil reservoir. The computational procedure of applying Vogel’s method in a saturated oil reservoir to generate the IPR curve for a well with a stabilized flow data point,

i.e., a recorded oQ value at

wfP , is summarized below:

Step 1. Using the stabilized flow data, i.e., o wfQ and P , calculate:

o maxQ from :

2

max

r r

( ) / 1 0.2 0.8P P

wf wfo o

P PQ Q

Step 2. Construct the IPR curve by assuming various values for wfP and calculating the

corresponding o Q from:

2

max

r

( ) 1 0.2 0.8P

wf wfo o

r

P PQ Q

P

Prediction of Future IPR of the Oil Wells

There are several methods that are designed to address the problem of how the IPR might shift as the reservoir pressure declines. But here a combination of Fetkovich & Vogel procedures is used for predicting the future IPR. The relationship has the following mathematical form:

3

o max o max r rfQ =(Q ) (P ) / (P )p f p

where the subscripts f and p represent future and present conditions, respectively. The above

equation is intended only to provide a rough estimation of future o max(Q ) .

effect of reservoir pressure on IPR Current IPR for Well #19 The latest available test point is at 21-Nov-09 ; at this point of time the average reservoir

pressure becomes 959.9903 psi (from rP vs. time curve after extrapolating the curve ) .

The test point is :

tq 64 BPD

W.H.P 120 PSI Procedure :

First we calculate wfP from WHP using PIPESIM ® . Then ob J and Q values can be calculated

and the IPR can be constructed . Data Given :

resP 959.9903 PSIG

res T 165 F

WHP 120 PSIA

tq 64 BPD

Roughness 0.001 in.

Tbg Depth 4163 ft

Tbg Depth 4163 ft

Tbg ID 2.992 in.

GOR 1000 SCF /STB (Average value from production data)

API 35o W.C 17 %  Gas Specific Gravity 1.115 (from Composition Test , Reservoir Engineering data )

Vertical flow correlation = Beggs and Bill Revised Correlation Calculated Bottom Hole Pressure : (Image from Excel File Called Raml # 19 PWf)

After running the model , it was found that BHP = 578.6 PSIA. The pressure-elevation profile is shown below : Basic Calculations : The test point is :

tq 64 BPD

wf P 553.5267 PSI

The results are summarized below :

Parameter Value Units J 0.188 STB/day/psi

qb 6.578 STB/day

qmax 103.189 STB/day

Current IPR for Raml #19 :

-4500

-4000

-3500

-3000

-2500

-2000

-1500

-1000

-500

0

0 200 400 600 800 1000 1200

Elev

atio

n, f

t

P,psi

Predictive IPR for Raml #19 :

By assuming future values for the reservoir pressure and calculating the corresponding AOF

or maxQ

Pressure (PSIA) AOF (STB/day) 850 71.63

800 59.72

750 49.21

700 40.01

By using Vogel’s correlation , IPR can be constructed . hence the reservoir pressure is below

the bubble point pressure

(Back to Excel named “Predictive Raml #19 for a good image )

0

200

400

600

800

1000

1200

0 20 40 60 80 100 120

Pwf vs. q above Pb

Pwf vs. q below Pb

Current IPR for Raml#21

The latest available test point is at 9-Feb-10 ; at this point of time the average reservoir pressure

becomes 956.2029 psi (from rP vs. time curve after extrapolating the curve ) .

The test point is :

tq 429 BPD

W.H.P 51 PSI

Procedure :

First we calculate wfP from WHP using PIPESIM ® . Then ob J and Q values can be calculated

and the IPR can be constructed . Data Given :

resP 956.2029 PSI

res T 165 F

WHP 51 PSIA

tq 429 BPD

Roughness 0.001 in.

Tbg Depth 4239.92 ft

Tbg ID 2.992 in.

0

100

200

300

400

500

600

700

800

900

0 20 40 60 80

Pwf (Psi)

q (STB/day)

Pres = 850 Psi

Pres = 800 Psi

Pres = 750 Psi

Pres = 700 Psi

GOR 1000 SCF /STB (Average value from production data)

API 35o

W.C 26 %

 Gas Specific Gravity 1.115 (from Composition Test, Reservoir Engineering data )

Vertical flow correlation = Beggs and Bill Revised Correlation

Calculated Bottom Hole Pressure :

After running the model , it was found that BHP = 395.66 PSI. The pressure-elevation profile is shown below : (for better image , open Excel Raml #21 Pwf )

Basic Calculations : The test point is :

tq 429 BPD

wf P 395.66 PSI

The results are summarized below : Parameter Value Units

J 1.007 STB/day/psi

qb 31.418 STB/day qmax 584.876 STB/day

-4500

-4000

-3500

-3000

-2500

-2000

-1500

-1000

-500

0

0 200 400 600 800 1000 1200

Elea

vati

on

,ft

P,psi

Current IPR for Raml #21 : (for better image , check excel current IPR Raml #21)

Predictive IPR for Raml #21:

By assuming future values for the reservoir pressure and calculating the corresponding AOF

or maxQ

Pressure (PSIA) AOF (STB/day)

850 301.34 800 251.23

750 207.01

700 168.31

By using Vogel’s correlation , IPR can be constructed . hence the reservoir pressure is below

the bubble point pressure

0

200

400

600

800

1000

1200

0 100 200 300 400 500 600

Pwf > 925 Psi

Pwf < 925 Psi

Optimum Tubing Size Determination :

Optimum tubing size is determined normally by finding the maximum flow rate results from the

intersection between IPR and various VLP curves of different tubing sizes.

Here we obtain our VLP curves from PIPESIM ® ,and then the tubing size yields the maximum

flow rate is chosen to be the optimum.

For Raml # 19 :

VLP for various commercial tubing sizes is summarized below (PIPESIM® output):

ID =1.751 '' ID = 1.992'' ID =2.441 '' ID =2.992 ''

q(STB/d) Pwf (psi) q(STB/d) Pwf(psi) q(STB/D) Pwf(psi) q(STB/d) Pwf(psi)

0.18 1434.17 0.18 1430.73 0.18 1425.95 0.18 1422.16

19.85 607.16 19.85 758.93 19.85 1054.78 19.85 1257.53

39.71 512.81 39.71 479.26 39.71 580.76 39.71 879.22

59.56 535.77 59.56 498.80 59.56 453.51 59.56 592.68

79.41 553.69 79.41 512.86 79.41 462.85 79.41 462.60

99.26 568.57 99.26 524.26 99.26 470.35 99.26 431.31

119.12 581.60 119.12 533.86 119.12 477.71 119.12 434.84

138.97 593.03 138.97 542.59 138.97 484.02 138.97 438.91

158.82 603.52 158.82 550.68 158.82 489.66 158.82 443.32

0

100

200

300

400

500

600

700

800

900

0 100 200 300 400

Pw

f,P

si

q, STB/day

Pres = 850 psi

Pres = 800 psi

Pres = 750 psi

Pres = 700 psi

178.67 613.47 178.67 558.33 178.67 494.82 178.67 447.18

The optimum tubing size for Raml # 19 is 2.992’’ , and the intersection point is 100 BPD flow

rate and bottom hole pressure of 420 PSIA

For Raml # 21 :

VLP for various commercial tubing sizes is summarized below (PIPESIM® output):

ID =1.751 '' ID = 1.992'' ID =2.441 '' ID =2.992 ''

q(STB/d) Pwf (psi) q(STB/d) Pwf(psi) q(STB/D) Pwf(psi) q(STB/d) Pwf(psi)

0.01 1412.22 0.01 1412.16 0.01 1412.24 0.01 1412.29

666.68 791.61 666.68 660.13 666.68 519.70 666.68 437.34

1333.34 1137.80 1333.34 898.66 1333.34 654.21 1333.34 510.19

2000.01 1512.40 2000.01 1154.94 2000.01 795.66 2000.01 586.32

2666.67 1912.06 2666.67 1428.05 2666.67 942.90 2666.67 667.63

3333.34 2338.16 3333.34 1715.83 3333.34 1097.28 3333.34 751.01

4000.01 2800.61 4000.01 2016.89 4000.01 1259.89 4000.01 838.22

4666.67 3312.67 4666.67 2331.12 4666.67 1429.64 4666.67 928.30

5333.34 3883.08 5333.34 2663.24 5333.34 1604.90 5333.34 1021.52

0

200

400

600

800

1000

1200

1400

1600

0 50 100 150 200

IPR

ID = 1.751"

ID = 1.992"

ID = 2.441"

ID = 2.992"

6000.00 4515.01 6000.00 3017.35 6000.00 1785.03 6000.00 1117.70

The optimum tubing size for Raml # 12 is 2.992’’ , and the intersection point is 1120 BPD flow

rate and bottom hole pressure of 402 PSI (Assuming Productivity Index = 2 STB/D/Psi) ,

because it was found that using PI = 1 STB/D/Psi results in a well which can’t produce naturally

0

500

1000

1500

2000

2500

0 500 1000 1500 2000 2500 3000

IPR

ID = 1.751"

ID = 1.992"

ID = 2.441"

ID = 2.992"