Candidate Evaluation and Selection
Criteria
There are seventeen Tensleep wells that could be treated with a polymer gel. In order to select the best well for treatment, the following criteria are proposed:
- It should be evident that fractures contribute the water, preventing adequate oil recovery from the matrix. This could be evidenced by high AOF potential, along with increased oil cut with increased drawdown.
- The well should be producing at a low percentage of its absolute open flow potential (AOF).
- There should be adequate oil-in-place to pay out the treatment.
- The candidate well should be an active producer with good baseline production to quantitatively evaluate treatment results and minimize expenditures on production equipment.
Candidate Well Review
In order to obtain the data required to rank the candidate wells, a detailed log analysis study was undertaken on each well. The available electric and porosity logs were digitized through the Tensleep at a one-foot interval. Water saturation was calculated on a per foot basis. Effective porosity was also calculated. Net pay sand was determined using an 8% density porosity cutoff and a 70% water saturation cutoff. Using these porosity, net thickness, and water saturation values, a unit STBO in place per acre was calculated for each well. This number seemed to correlate well with the well's cumulative production, considering the time that the well was drilled and produced.
Existing production data was analyzed to determine the well's absolute open flow potential. This number was compared to the well's current production rate to estimate the degree of draw down for each well.
Table 1. Candidate Well Data
|
Well
|
Casing Size
|
Status
|
BOPD
|
BWPD
|
OOIP Per Acre
|
AOF
|
Current% AOF
|
|
43TpX10
|
7
|
FL 12/99
|
0.4
|
413
|
16,936
|
3,492
|
12
|
|
43-2TpX10
|
7
|
P
|
12
|
1546
|
3,624
|
1,945
|
79
|
|
44-1TpX10
|
5 ½
|
FL 12/99
|
0.5
|
1101
|
14,868
|
6,431
|
17
|
|
46TpX10
|
7
|
SI 7/96
|
6.5
|
4275
|
3,537
|
6,360
|
67
|
|
51TpX10
|
7
|
SI 8/87
|
0.3
|
2230
|
|
3,492
|
64
|
|
52-1TpX10
|
9 5/8
|
TA
|
0.3
|
5500
|
|
6,360
|
86
|
|
53TpX10
|
7
|
SI 6/97
|
13.3
|
1596
|
|
3,492
|
46
|
|
54TpX10
|
7,4½
|
SI 9/99
|
0.2
|
372
|
30,138
|
5,844
|
6
|
|
55TpX10
|
5 ½
|
P
|
13.9
|
2154
|
20,556
|
2,853
|
75
|
|
56TpX10
|
7
|
P
|
12.0
|
4745
|
44,830
|
5,560
|
85
|
|
62TpX10
|
7
|
SI 9/96
|
14.6
|
5490
|
16,614
|
9,825
|
56
|
|
63TpX10
|
7
|
P
|
18.5
|
8834
|
4,298
|
9,799
|
90
|
|
72TpX10
|
7
|
SI 2/00
|
5.5
|
1505
|
6,677
|
3,322
|
45
|
|
73TpX10
|
7
|
P
|
11
|
4600
|
6,996
|
6,124
|
75
|
|
74TpX10
|
7
|
PA
|
|
|
|
|
|
|
75TpX10
|
7
|
P
|
26.7
|
7331
|
|
9,825
|
75
|
|
76TpX10
|
7
|
P
|
18.5
|
7416
|
21,342
|
9,850
|
75
|
Candidate Well Selection
Based on the above data, a rough economic evaluation was performed for each well. It was assumed that the well could produce the oil projected at a pumped off condition and that the water could be reduced by 50%. The cost of the work was estimated to be $60,000 for each well. The wells were assigned points based on their relative rank for each of the selection criteria. Thus, the well with the lowest score is the best candidate for the treatment. The ranked candidates are presented below.
Table 2. Ranking of Candidate Wells
|
Wells
|
Points
|
Net
Present Value
|
Discounted
Payout, Years
|
|
63Tpx10
|
4
|
$1,549,870.00
|
0.1
|
|
76Tpx10
|
9
|
$674,996.00
|
0.3
|
|
53Tpx10
|
12
|
$632,845.00
|
0.3
|
|
55Tpx10
|
19
|
$452,752.00
|
0.5
|
|
62Tpx10
|
22
|
$324,333.00
|
0.4
|
|
43-2Tpx10
|
22
|
$403,366.00
|
0.5
|
|
56Tpx10
|
22
|
$374,600.00
|
0.5
|
|
75Tpx10
|
32
|
$200,617.00
|
0.7
|
|
54Tpx10
|
33
|
$232,904.00
|
0.8
|
|
44-1Tpx10
|
33
|
$97,966.00
|
1.6
|
|
73Tpx10
|
35
|
$172,372.00
|
0.7
|
|
72Tpx10
|
44
|
$47,683.00
|
1.3
|
|
43Tpx10
|
46
|
$60,831.00
|
2
|
|
46Tpx10
|
52
|
($47,824.00)
|
10
|
|
51Tpx10
|
54
|
($51,202.00)
|
10
|
It was initially recommended that the top three wells be treated. Well 63TpX10 was the top ranked candidate well for the shut-off treatment. However, this well was already selected to test a propellant stimulation technology and therefore was not available for the treatment. Due to limitations in available capital, only one well could be treated. Therefore, Well 76TpX10 was selected for the polymer gel water shut-off treatment.
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