Improved Production With Mineralogy-Based Acid Designs
Improved Production With Mineralogy-Based Acid Designs
Improved Production With Mineralogy-Based Acid Designs
Abstract
This paper presents a case history on new sandstone acidizing
technology using a nonhydrofluoric formulation to
successfully treat a high carbonaceous sandstone formation.
The improved understanding of the chemical complications of
hydrofluoric (HF) on dirty sandstones led to the design of a
nonhydrofluoric treatment on the high carbonate content
(dirty) sandstone formation.
Previous treatments using various formulations of HF acid
failed to remove the high skin associated with several wells in
this formation. A new approach was taken to identify the
damage mechanism and evaluate damage removal options
based on the formation mineralogy. This approach analyzed
the potential chemistry risks associated with using HF type
treatments in the presence of particular mineralogies
and temperatures.
The new approach also used logging and reservoir
modeling technology to forecast the estimated production
profile of the complex multilayered formation. Candidate
wells were identified by comparing the forecast production
profile potentials to the surveyed production profiles based on
production logging (PLT) of the prescreening candidates. The
final treatment candidate was then selected for the trial of the
new treatment formulation. The treatment was specifically
tailored based on the identified mineralogy and encompassed
the damage prevention strategies. The result was a 40%
increase in oil production for the well, but a 2-fold to 10-fold
increase for the treated zone, depending on pretreatment
production assumptions.
Introduction
XJG oilfields are located offshore in the South China Sea
around 130 km southeast of Hong Kong.1 The fields are
composed of three geological structures named XJG 1, XJG 2
and XJG 3, the first one being discovered in 1984 and
SPE 86519
Treatment
1/6/1996
5/19/1996
7/21/1996
7/31/1996
7/7/1997
12/1/1997
Placement
Bullhead
CTU
Bullhead
Bullhead
CTU
CTU
Diverter
None
Foam
Foam
Foam
Foam
None
Stages
1
3
3
3
3
1
Acid Blend
13.5% HCl, 1.5% HF
13.5% HCl, 1.5% HF
13.5% HCl, 1.5% HF
13.5% HCl, 1.5% HF
Slow reacting HF
Slow reacting HF
SPE 86519
X3
X5
X4
X1A
Before treatment:
After treatment:
Before treatment:
After treatment:
X4
X7
Total Fluid
Oil
(BFPD)
(BOPD)
1996 Acid Treatments
3,228
2,582
3,248
2,663
3,965
3,172
8,805
5,371
10,187
5,739
11,033
4,082
9,937
5,813
10,119
6,122
1997 Acid Treatments
9,914
3,073
5,373
900
3,401
2,976
1,464
1,098
Increased Oil
(bbl, %)
Water-Cut
(%)
Choke*
20
18
20
39
56
63
42
39
46
46
50
68
41
38
35
36
69
83
12
25
38
43
47
52
81, 3%
2,199, 69%
-1657, -29%
309, 5%
-2173, -71%
-1878, -63%
th
*Choke as 64 s of an in.
Permeability
(md)
2970
1688
1446
1240
Height
(ft)
59
13
15
46
k-h
(md-ft)
174,000
22,000
21,000
57,000
k-h Contribution
(%)
63%
8%
8%
21%
SPE 86519
SPE 86519
SPE 86519
k-h Expectation
(%)
1996 PLT
(%)
2001 PLT
(%)
Zonal Water-Cut
(%)
X10B
X10C/X11
X13
63
16
21
82
8
10
74
16
10
8
56
14
SPE 86519
SPE 86519
SPE 86519
10
Production Results
The production response from the acid treatment on Well XB9
is reported in Fig. 6. The acid treatment provided an
immediate improvement of 600 BOPD, even on a smaller
choke size of 42 (64ths) and at a higher wellhead pressure of
700 psi (600 psi higher than the previous 6 months).
Furthermore, the increase in oil production was provided
without an increase in water production. The immediate postacid treatment water-cut for the well was 81%.
Assigning production contributions to various zones in a
complex reservoir with complex completions is a serious
challenge. The challenge was particularly acute in this
operation because PLTs were not available for the changes in
production during 2002. However, some assumptions can be
made that at least provide some limiting cases. The biggest
challenge was in understanding the change in water-cut that
occurred in March 2002 when the well was drawn down
harder. The increase in water production, without a
proportional increase in oil production, indicates that the water
cut for each zone had increased. On a historical basis, the
water-cut for Well XB9 had increased from 70% in February
2001 to 86% in March 2002. If the water in each zone
increased proportionally and held constant to the same oil
contribution, then the water cut for each zone had increased
from 80, 56, and 14% to 91, 77, and 30% for X10B,
X10C/X11, and X13, respectively. However, it is even more
likely that the water-cut for X13 had increased to 50%
water-cut. Using these modified water-cuts for the four zones,
and assuming that oil production for the top three zones after
March 2002 was unchanged, the decline in oil production
SPE 86519
November
Oil (BOPD)
X10B
910
910
910
X10C/X11
435
435
435
X13*
305
55
55
Total
1,650
1,400
1,400
*Assumes water-cut for Zone X13 increased
from 14% to 50%.
SPE 86519
11
Oil
(BOPD)
Water
(BWPD)
Implied Zonal
Water-Cut
(%)
X10B
910 (44%)
6,830 (77%)
88
X10C/X11
435 (21%)
1,310 (15%)
75
X13
735 (35%)
735 (8%)
5
Total
2,080
8,875 (81% water-cut)
*Assumes all production improvement came from acidized zone, X13.
The decline slope for Well XB9 since the treatment suggests
that the well continues to experience a production induced
damage. It is quite possible that the damage mechanism
continues to be carbonate scaling, though the decline slope is
not as steep as in early 2002. Acidizing is an effective method
to remove carbonate scale, but does not prevent carbonate
scaling. Another acid treatment may be required soon for this
well, but should be followed by a scale inhibitor squeeze
treatment. It would be preferred that the acid treatment be
returned to the surface before performing the squeeze
treatment so that released debris and diversion effects can
be removed.
The complexities of candidate selection and verifying acid
treatment success are readily illustrated by this case history.
The uncertainties of zonal contributions of both water and oil
can make a full understanding difficult. However, it becomes
very clear that a combination of technologies must be used if
cost-effective decisions are to be made about improving
production on these types of fields.
Conclusions
Based on the findings of this study, the following conclusions
can be made.
Identification of stimulation candidates in complex oil
reservoirs with complex completions that produce both oil
and water can be accomplished with a combination of
production logging and geophysical analysis techniques
coupled with reservoir simulation.
Candidate selection alone is insufficient for treatment
success and must also involve proper identification of the
relevant damage mechanisms and mineralogy driven
remediation options.
Sandstone formations with an average carbonate content
of 20% are simply too high to be good HF acidizing
candidates because of severe secondary and tertiary
precipitations that can cause matrix damage that can
reduce production.
The X13 zone of the XB9 well was probably damaged
most by carbonate scaling that was effectively removed
with organic acid without causing clay decomposition, as
would be expected with HCl at the BHST of 240F.