Th P018
Evaluation of Three Large Scale ASP Flooding
Field Test
Hu Guo* (China University of Petroleum,Beijing), Y. Q. Li (China University
of Petroleum,Beijing), R.C. Ma (China University of Petroleum,Beijing), F.
Y.Wang (China University of Petroleum,Beijing) & Z. Shihu (No.3 Gas
Production Plant, Changqing Oilfield)
SUMMARY
Scaling, emulsion breaking and high cost prevent ASP flooding going laboratory to field. When antiscaling and produced fluid disposal challenges has been gradually solved in China after years of hard
work, the sharp drop oil price makes prospect of ASP flooding dim again. However, ASP flooding is still
very promising and has entered into commercial application in 2014 in Daqing. In 2015, the whole crude
production from ASP flooding in Daqing was 3.509 million ton, 9.14% of the total production of Daqing
oilfield (38.386 million ton). In 2016, there are more than 22 ASP flooding field projects active in Daqing,
and the total ASP flooding oil production is 4.06 million ton, 11.11% of total oil production in Daqing.
One of the three evaluated ASP flooding tests, ASP 1,2,3, is weak alkali (Na2CO3) based, the other two
are both strong alkali (NaOH) based. These three tests shared four slug formulation, which is current
standard practice in Daqing. Surfactants and polymers are all domestic. The total cost consists of
construction investment, injected chemical fees (polymer, surfactant and alkali), operation fees including
maintenance and repair fees, and water disposal fees. These costs are actual spending during ASP flooding
tests. Though the ASP 1 and ASP 2 have the similar incremental oil recovery (30%) and both successful,
the economic performances of weak alkali ASP flooding is much better for lower commuted total cost.
Total cost of ASP 1 and ASP 2 is 28.2 $/bbl and 36.3 $/bbl respectively. The reservoir formation of ASP 1
and ASP 2 has many similarity, thus the difference can reflect alkali effects. ASP 3 has incremental oil
recovery of 20.5% upon waterflooding, while it has much higher cost (49.5 $/bbl) than ASP 1 and ASP 2.
This is attributed to the much higher polymer molecular and concentration injected, but less oil production.
Though higher viscosity helps to overcome the severer heterogeneity as expected, it actually blocked the
relative lower permeability formation. This tests shows that formation contamination is important issue to
be considered. In high oil price era, the incremental oil recover can be regarded as core parameter since the
cost increase can always be compensated by benefits of more oil, while in ultra-low oil price era, the
balance between input and output is vital. Previous large scale ASP flooding field tests and current ASP
flooding in practice shows that ASP flooding is still very promising even under such low oil price.
IOR NORWAY 2017 – 19th European Symposium on Improved Oil Recovery
24-27 April 2017, Stavanger, Norway
Introduction
ASP flooding is very promising technology(Sheng 2014; Olajire 2014). ASP flooding Incremental oil
recoveries vary widely and when properly designed, it ranges between 20% and 30% OOIP following
mature water floods(Pope 2011). Scaling, emulsion breaking and high cost prevent ASP flooding going
laboratory to field (Olajire 2014; Sharma et al. 2015; Fang et al. 2016; Gregersen, Kazempour, and
Alvarado 2013; Zhu, Hou, Jian, et al. 2013; Zhu, Hou, Weng, et al. 2013; Zhu et al. 2012). When antiscaling and produced fluid disposal challenges has been gradually solved in China after years of hard
work(Cheng et al. 2014; Zhu 2015), the sharp drop oil price makes prospect of ASP flooding dim again.
However, ASP flooding is still very promising and has made great progress in the past ten
years(Jiecheng et al. 2016; Liya, Zhou, and Fu 2016; Jun et al. 2016; Song, Jingang, and Jing 2015;
Jiecheng, Junzheng, and Junqing 2014; Yang Feil et al. 2014; Jiecheng et al. 2014; Jiecheng, Junzheng,
and Di 2013). In 2014, ASP flooding has entered commercial application stage in Daqing
Oilfield(Jiecheng et al. 2014; Jiecheng, Junzheng, and Junqing 2014). In 2015, the whole crude
production from ASP flooding in Daqing was 3.509 million ton, 9.14% of the total production of Daqing
oilfield (38.386 million ton). In 2016, there are more than 22 ASP flooding field projects active in
Daqing, and the total ASP flooding oil production is 4.06 million ton, 11.11% of total production in
Daqing(Xia 2017). Even more and more ASP flooding is implemented in Daqing, few detailed data
about ASP flooding cost is available, especially for researchers outside China. This paper explains why
more and more ASP flooding projects are implemented in Daqing by evaluating three large scale ASP
flooding field tests finished in Daqing. These three field tests (ASP 1, ASP2 and ASP3) are carried out
in second class layer reservoir whose reservoir property is inferior to first class layer in Daqing.
Compared to earlier ASP flooding field tests finished in Daqing(Zhu, Hou, Weng, et al. 2013; Zhu, Hou,
Jian, et al. 2013; Sheng 2014), these three field tests scale is much larger. Based on these field tests,
industrial tests started(Guo et al. 2017). Thus, the finished three tests provides us incomparable chance
to learn about ASP flooding. More importantly, advantage of weak alkali (Na2CO3) ASP flooding over
strong alkali (NaOH) is proven by comparing comprehensive cost of oil production (incremental oil),
although there are increasing consensus that weak alkali ASP flooding is the developing trend (Youyi
et al. 2012; Zhu 2015). It is, to the best of own knowledge, the first time weak alkali ASP flooding
(WASP) and strong alkali ASP flooding(SASP) is compared with detailed cost information.
Petrophysical property
Na2CO3 was used in ASP 1, while NaOH was used in ASP 2 and ASP 3. ASP 1, ASP2 and ASP
3 started ASP injection in March 2009, November 2006, and August 2008. Petrophysical property
of these three field tests are summarized in Table 1. More information about ASP 1 can be
seen in references (Guangxia 2014; Jingcui Wang 2013). As for ASP 2, detailed information can be
found in references(Wang Yan’e 2014; Jiecheng, Junzheng, and Di 2013). The information of
ASP 3 is summarized from references(Chunhong et al. 2015; Jie, Jinfeng, and Mengqu 2015;
Jinfeng, Jie, and Zhang Lijuan 2015; Yuan 2014). In our previous paper(Guo et al. 2016), comparison
between ASP 1 and ASP 2 is made with focus on alkali effect on recovery effect. Central zone
producers number in ASP 1, ASP 2 and ASP 3 is 24,36 and 28. From Table 1, it can be seen that
these three field tests shares many comparable parameters like the same well spacing and well
pattern, similar scale, and permeabilities. The formation of these three blocks are all Class Two
formation blocks in Daqing and the formation physical features are inferior to Class One formation
whose air permeability is defined to be higher than 1800mD by Daqing Oilfield.
Table 1 Reservoir of three field tests blocks
Feature
ASP1
Alkali used
Na2CO3
1.21
Area，km2
Injector/ producer(central well zone)
35/44(24)
Average sandstone thickness per well,m
8.1
Effective thickness,m
6.6
ASP2
ASP3
NaOH
NaOH
1.92
1.42
49/63(36) 45/62(28)
10.6
11.7
7.7
8.8
IOR NORWAY 2017 – 19th European Symposium on Improved Oil Recovery
24-27 April 2017, Stavanger, Norway
Average effective permeability, mD
OOIP, ×104t
Pore volume, 104m3
Well pattern
Well spacing,m
Formation brine type
Formation brine salinity, mg/L
Ca2+，mg/L
Mg2+，mg/L
Target formation
Formation depth,m
Formation Oil viscosity, mPa.s
Dead oil viscosity, mPa.s
Formation temperature,℃
533
116.31
219.21
Five spot
125
NaHCO3
6037
20-40
10-20
SⅡ10- 12
872-883
8.2-10.4
16.6
42.4
670
240.71
505.11
Five spot
125
NaHCO3
5611
35.97
9.44
SⅡ1-9
838-8708.2-9.3
17.55
42.4
676
176.5
341.7
Five spot
120
NaHCO3
7150
34.1*
7.29*
SIII4-10
870-890
10.3
22.9
45
*Data from produced water.
ASP scheme
It is widely accepted that three slug should be used in ASP flooding. Three slug schematic diagram is
available in reference(Zerpa et al. 2005). Based on previous field test result and experience, four slugs
are have been used in all ASP flooding field tests in Daqing except some earlier ones. In Daqing, ASP
slug is divided into ASP dominating slug and ASP auxiliary slug. Planned ASP injection schemes can
be seen in Table 2. The average viscosity of ASP is designed 3-4 times of oil formation viscosity. The
viscosity of polymer is typically 35 to 40 cP (Wang et al. 2009). The viscosity of ASP is typically 40
cP. Idea of mobility control technique of ASP flooding can be seen in literature(Wang et al. 2008). And
the pre-slug, ASP dominating slug, ASP auxiliary slug, post polymer slug size is 0.0375PV, 0.3PV,
0.15PV and 0.2PV respectively. This slug size is almost common practice in Daqing. As for ASP 3, the
heterogeneity is more serious with the Dykstra-Parsons coefficient of permeability variation of 0.73,
while in Daqing Oilfield this value varies from 0.4 to 0.7(Wang et al. 2009). Designed viscosity in ASP
3 was increased from 40 cp to 80 cP and the pre-slug size was increased from 0.0375PV to 0.075PV.
Polymer molecular weight planned and actually used in ASP 1 was both 25 million Daltons. Three
molecular weight (15,19 and 25 million Daltons )polymers were planned and actually used in ASP 2.
Planned polymer molecular weight in four slug in ASP 3 is 19 million Daltons, while the actual polymer
molecular weight used is 25 million Daltons(Chunhong et al. 2015). However, 25 million Daltons
polymer was used in ASP3. Detailed slug size and chemical system viscosity in three field tests can be
seen in Table 2, Table 3 and Table 4(Jie, Jinfeng, and Mengqu 2015). From Table 3 we can see that the
viscosity ASP 3 is far higher than ASP 1 and ASP 2, and the 200 cP polymer slug is used as profile
control slug(Yanchang 2016). The high viscosity has obvious effect on reducing water cut, and water
cut decrease in ASP 3 is largest than all other industrial field tests, the high viscosity also resulted in
serious side effects(Chunhong et al. 2015).
Table 2 Planned ASP scheme of three field tests
Pre-slug
concentration
(mg/L)
0.0375 PV
ASP dominating slug
ASP auxiliary slug
0.3 PV
0.15 PV
A
S
P
A
S
P
（%）
（%）
(mg/L)
（%）
（%）
(mg/L)
Post
slug
(mg/L)
0.2 PV
Injection
rate，
PV/a
Incremental
recover
predicted,%
ASP1
1350
1.6
0.3
1800
1.4
0.1
1800
1350
0.2
22.2
ASP2
1300
1.2
0.3
2000
1
0.1
1800
1000
0.2
21.7
ASP3
1300
(0.075PV)
1.2
0.3
2500
1.2
0.1
1800
1000
0.2
21.0
IOR NORWAY 2017 – 19th European Symposium on Improved Oil Recovery
24-27 April 2017, Stavanger, Norway
Table 3 Actual ASP scheme of three field tests
Pre-slug
Field
ASP dominating slug
ASP auxiliary slug
Post slug
Size
P
Size
A
S
P
Size
A
S
P
Size
P
(PV)
(mg/L)
（%）
（%）
（%）
（%）
(mg/L)
1350
1.2
0.3
0.2203
1.0
0.1
(mg/L)
1940
1980
(PV)
0.0801
(mg/L)
1750
1980
PV
ASP1
(PV)
0.4284
（0.3501）
0.25
1500
ASP2
0.054
1300
0.351
1.2
0.3
2000
0.285
1
0.8
0.2
0.1
2000
0.233
1500
ASP3
0.082
2210
0.363
1.2
0.3
2230
0.181
1.1
0.2
1680
0.238
1400
Table 4 Actual viscosity of chemicals injected in three field tests
Field tests
ASP1
ASP2
ASP3
Pre-slug
22
30
200
ASP dominating slug
58
31,65,77
110
ASP auxiliary slug
60
72,48
50
Post slug
69
52-63
40
EOR effects
Core parameter of ASP flooding is incremental oil recovery. Figure 1 and Figure 2 is the enhanced oil
recovery and water cut comparison between three field tests(Jiecheng, Junzheng, and Junqing 2014). It
is obvious in Figure 1 that ASP 3 incremental recovery is lower than ASP 1 and ASP 2. The final
incremental oil recovery of ASP 1 and ASP 2 is almost the same, nearly 30%. These two ASP flooding
field tests has the highest incremental oil recovery than any other previous field tests. Our previous
paper (Guo et al. 2017; Guo et al. 2016)compared the performance of these two tests. It is the
unexpected huge success of WASP field tests of ASP1 that makes Daqing Oilfield turn to WASP instead
of SASP, although SASP has given far more attention and efforts in previous studies. Previous ASP
flooding field tests in Daqing was seen incremental oil recovery of about 20%, which is much lower
than that in ASP 1 and ASP 2. Improved surfactant quality and dynamic regulation together with antiscaling technology progress are attributed to the huge success. Another less mentioned reason is that
the CO2 content in ASP2 is high and injected NaOH converted into Na2CO3, which avoided the side
effect of SASP. Scaling difference between ASP 2 and ASP 3 well supported this conclusion(Jiecheng,
Junzheng, and Di 2013). The lower incremental recovery of ASP 3 compared to ASP 1 and ASP 2.
Water cut decrease in Figure 2 of ASP 3 is larger that of ASP 1 and ASP2, indicating that profile control
technique in pre-slug do work and enlarged the sweep volume. Water cut in Figure 2 and recovery in
Figure 1 both verified that SASP takes effect earlier than WASP. Table 5 is statistics of three ASP
flooding field tests (Jie, Jinfeng, and Mengqu 2015; Jinfeng, Jie, and Zhang Lijuan 2015; Chunhong et
al. 2015). From this table, we can see that the water cut before chemical injection in ASP 1 is higher
than ASP 2 and ASP 3, and the stage recovery in ASP 1 (45.2%) is much larger than that in ASP 2
(36.9% ) and ASP3(36.5%). As we know, higher recovery leads to scatter residual oil and fewer
remaining oil, and in turn more difficult to enhance oil recovery. It may be too bold to say that WASP
has better recovery than SASP, since previous field tests indicated that SASP makes higher incremental
oil recovery, however, it is obvious that WASP has the same ability to enhance oil recovery. This
conclusion was well supported in our recent paper. And we have written two paper to make more and
deep discussion on this issue.
IOR NORWAY 2017 – 19th European Symposium on Improved Oil Recovery
24-27 April 2017, Stavanger, Norway
30
ASP1
25
ASP2
ASP3
EOR ,OOIP%
20
15
10
5
0
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
Injection Volume, PV
Figure 1 Comparison of EOR vs PV
100
Watercut,%
95
90
85
ASP1
80
ASP2
ASP3
75
70
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
0.9
1.0
1.1
1.2
Injection Volume, PV
Figure 2 Comparison of Watercut vs PV
Table 5 Development effect comparison of three ASP field tests (Chunhong et al. 2015; Jie, Jinfeng,
and Mengqu 2015)
Field tests
fw1,%
Δfw1,%
fw2,%
ASP1
ASP2
ASP3
98.45
96.70
96.5
17.17
13.00
22.0
98.76
96.20
96.80
Δfw2,%
19.06
17.50
25.40
Rf,%
45.2
36.9
36.5
Chemical
injection, PV
0.910
0.937
0.864
Incremental
recovery,%
29.4
30.0
20.3
In Table 5, fw1 and fw2 refer to water cut of all test areas and central well zone before chemical flooding
respectively, Δfw1 andΔfw2, refer to water cut decrease in all test areas and central well zone producers
respectively. Rf refers to test block recovery before chemical flooding.
IOR NORWAY 2017 – 19th European Symposium on Improved Oil Recovery
24-27 April 2017, Stavanger, Norway
Analysis and discussion
These three field test were carried out in the same period and followed the same screen standard,
although some dynamic regulations were adopted in the process. If judge by petrophysical properties
in Table 1, these three field tests have the most comparable parameters like reservoir temperature,
well pattern, well spacing, oil viscosity in formation. The average permeabilities of ASP 2 and
ASP 2 is higher than ASP 1, and the effective formation thickness is larger two. The Dykstra-Parsons
coefficient of permeability variation of ASP 3 is 0.73, larger than that of ASP 1and ASP 2, which is
about 0.67. In other words, formation in ASP 3 is more heterogeneous than ASP1 and ASP2. It is not
easy to say the heterogeneity difference effect on recovery. Considering the heterogeneity in ASP3,
the viscosity of ASP was increased from 40 cP to 80 cP (Yuan 2014), and high concentration
polymer (2210mg/L) with viscosity of 200 cP was injected in pre-slug(Chunhong et al. 2015), thus
the concentration and viscosity is much larger than the other two field tests, seen in Table 4. The
higher viscosity in pre-slug contributes to the larger water cut decrease in ASP3 compared to ASP 1
and ASP2(Yuan 2014). The high pre-slug viscosity idea was perhaps in line with high concentration
polymer flooding field tests (Yang et al. 2015; Liu et al. 2013)carried out in Daqing recently,
however, recovery performance of ASP 3 indicated that single molecular weight (25 million Daltons)
was injected in all layers in ASP 3 may damage the low permeability layer. In ASP 3 practice, 2000
mg/L polymer (25 million Daltons) was injected in 35 injectors whose permeability is lower than
800mD, and 2500 mg/L polymer (25 million Daltons) was injected in 9 injectors whose
permeability is higher than 800 mD (Chunhong et al. 2015). General injection without
considering polymer compatibility issue in different permeability layer. Though higher viscosity
helps to overcome the severer heterogeneity as expected, it actually blocked the relative lower
permeability formation. Figure 3(Jie, Jinfeng, and Mengqu 2015; Chunhong et al. 2015) is the Hall
curves in ASP flooding field tests. ASP 1 and ASP 2 shared the similar curve trend due to similar
viscosity injected, however, Hall curve slope of ASP 3 is much larger than ASP 1 and ASP2,
indicating injection difficulty. The much larger fluid production loss in pre-slug stage in ASP 3 than
ASP2 verified that the injection scheme is not compatible with layers (Jie, Jinfeng, and Mengqu
2015). Polymer retention rate, as can be seen in Figure4, in ASP 3 is much higher than ASP 1 and
ASP2(Jie, Jinfeng, and Mengqu 2015). Too high polymer retention rate lead to more fluid
productivity loss, which in turn result in less oil produced. If emulsification and scaling is taken into
consideration in SASP(Guo et al. 2017), situation may be worse. These tests showed that high
concentration polymer injection should be carefully evaluated and designed. Personalized polymer
injection scheme should be used instead of general injection when heterogeneity is taken into
consideration.
Cumulative Injection Pressure, GPa
0.4
ASP1
ASP2
ASP3
0.3
0.2
0.1
0
0
10
20
30
40
50
60
Cumulative Injection, 104m3
Figure 3 Comparison of Hall curves in ASP flooding field tests (Jie, Jinfeng, and Mengqu 2015;
Chunhong et al. 2015)
IOR NORWAY 2017 – 19th European Symposium on Improved Oil Recovery
24-27 April 2017, Stavanger, Norway
Polymer Retention ,%
100
ASP1
90
ASP2
80
ASP3
70
60
50
40
0.0
0.1
0.2
0.3
0.4
0.5
0.6
0.7
0.8
PV
Figure 4 Comparison of polymer retention rate in ASP flooding field tests (Jie, Jinfeng, and Mengqu
2015)
Cost analysis
Cost analysis is a good way to evaluate the feasibility of a project or technology scheme. Economic
benefit analysis usually contains total investment estimation, sensitivity analysis and economy
evaluation, which includes income calculation, cost estimation and profitability analysis. In ASP
flooding, the most important two parameters of factors affecting the economic benefits is oil production
volume and oil price, if the total investment is considered as a fixed parameter. In previous ASP flooding
field tests in Daqing Oilfield, the core parameter is increment oil recovery. Though different field tests
have different goals and emphasis, incremental oil recovery after water flooding is consider the core
parameter. For instance, the expected incremental oil recovery factor of ASP 1 and ASP 2 is 18% and
19.5% respectively. When crude oil price is high or increasing, higher incremental oil production means
more oil and benefit. When oil price is low, the balance between input and output is vital since more
production may result in more deficit or cost. Detailed economic data of most projects is top secret for
many companies, thus sometimes we have to compare and analyze projects by limited data. Since ASP
flooding has entered into commercial application stage in 2014, the cost of ASP flooding attracted more
and more attention. In our previous study(Guo et al. 2016), economic parameters like input-output ratio
and Financial Internal Rate of Return (FIRR) about ASP 1 and ASP 2 is compared briefly. FIRR of
ASP1 and ASP 2 are both higher than the oil industry critical value 12%, while FIRR in ASP 3 is lower
than 12%(Jing 2014). However, these parameters are highly dependent on oil price which is drastically
changing recently. In this study, we use actual cost to evaluate ASP flooding field tests.
ASP flooding field tests cost includes facility cost, chemicals (surfactant, polymer, alkali) cost,
operation cost and water disposal agents cost(Qingsheng and Xiaohui 2015). Facility cost is based on
construction investment, including new well drilling and surface facility investment. The majority of
investment is on facility and more than 50% investment in ASP flooding field tests is construction
investment. In ASP 1, due to less investment in injected chemicals, construction investment rate to total
investment is more than 60%. The single well investment in ASP flooding including downhole and
surface facility in ASP flooding is between 4-4.5 million Yuan(Qingsheng and Xiaohui 2015), and
surface facility invest per well is between 2.5-2.8 million Yuan. This value is much higher than the high
concentration polymer flooding single well surface facility which is about 2 million Yuan, and the
injection system and produced water treatment system cost accounted for the surface facility cost
increase compared to polymer flooding. The construction investment of ASP 3 is much lower than ASP
2 because some current facility is used. In Table 6 it is obvious that construction investment per well in
ASP 1 is lower than ASP 2 and ASP3. Chemical investment is actual chemicals used and all polymers,
IOR NORWAY 2017 – 19th European Symposium on Improved Oil Recovery
24-27 April 2017, Stavanger, Norway
surfactants and alkali are produced in China. Chemical investment is the other big part in ASP flooding.
The average ASP flooding chemical cost is 2.5 times of polymer flooding, which is about 250 Yuan per
ton oil(5.34 $/bbl) (Qingsheng and Xiaohui 2015). This polymer cost (5.34 $/bbl) in Daqing is higher
than the value (1.50 USD/bbl to 3 USD/bbl) given by Pope in 2011 (Pope 2011) In this paper, 1 ton
Daqing crude oil equals 7.31 bbl and the Exchange Rate between China Yuan to US Dollar used is 6.40.
Chemicals cost of ASP 1, ASP2 and ASP3 are 6.9,12.1, and 16.6 US$/bbl, close to the ASP chemical
cost value 10 US$/bb (Pope 2011). From Table 6, we can also see that chemical investment is as high
as construction investment in ASP 2 and ASP3. Chemical cost in ASP1 is much lower than ASP 2 and
ASP3, which shows the advantages of weak alkali (Na2CO3) over strong alkali (NaOH). In Table 6,
cumulative oil production is given to calculate cost. The data is collected from references(Qingsheng
and Xiaohui 2015; Jing 2014). The incremental oil in ASP 2 is much lower than ASP1 and ASP3,
resulting the much higher chemical cost. As discussed before, the injected chemicals in ASP 3 are
incompatible with the formation. In ASP flooding, the produced fluid is hard to process, which adds the
treatment cost. Added fluid disposal agents cost can be seen in Table 7 and Table 8. According to the
data in reference(Qingsheng and Xiaohui 2015), we calculate that comprehensive produced fluid
disposal cost is 4 times of that in polymer flooding. Another major cost in ASP flooding is operation
fees. According to statistics from Daqing Oilfield, average operation fees in water flooding, polymer
flooding and ASP flooding is 400-450,500-550, 650-850 Yuan/ ton oil(Qingsheng and Xiaohui 2015).
In other words, operation cost of ASP flooding in Daqing Oilfield is 13.9-18.2 US$/bbl. In Table 7 and
Table 8, operation cost is estimated from reference(Jiecheng, Junzheng, and Di 2013; Guangxia 2014).
In Table 7 and Table 8, disposal agents cost in ASP 1 is estimated indirectly from reference(Wenjie
2013). It should be noticed that the cumulative oil produced is used to calculate comprehensive cost of
every barrel, and no declined oil is considered. If the decline is considered, the total cost will be lower.
Comprehensive total cost in ASP 1, ASP2 and ASP3 is 28.2 36.3 and 49.5$/bbl. With improved
management, larger application scale, and optimized technology, the cost can be further reduced. Recent
reports showed that well drilling cost in ASP flooding can be reduced by 30% and chemical cost can be
reduced by 10%(Yunpu 2016). Cost analysis indicates that ASP flooding could make profit even when
oil price drops to 30 $/bbl. Cost comparison between three finished large scale ASP flooding field tests
verifies that weak alkali ASP is better than strong alkali ASP flooding.
Table 6 Investment of three field tests
Produ
Cumulative
Construction
Construction Chemical
cers/In
oil
Investment
Field jecors
investment,
investment,
production,
per
well,
Tests
Alkali
104Yuan
104Yuan
104 ton
104Yuan
ASP 1 35/44 Na2CO3
45.71
24381.14
15823.00
308.62
ASP 2 63/49 NaOH
75.53
44431.5
42616.02
396.71
ASP 3 62/44 NaOH
46.01
36786.52
35777.62
347.04
Table7 Comprehensive cost of produced oil from ASP flooding test (Unit: Yuan/ton)
Alkali
Field
Tests
ASP 1
ASP2
ASP3
Na2CO3
NaOH
NaOH
Facility
,Yuan/ton
533
588.2
799.5
Chemical
, Yuan/ton
325
564.2
777.6
Operation
, Yuan/ton
418
477
660
Disposal
Agents
, Yuan/ton
45
68.8
78.3
Total
cost,
Yuan/ton
1321
1698.2
2315.4
Table 8 Cost analysis of three field tests (Unit: $/bbl)
Field
Tests
Alkali
ASP 1
ASP 2
ASP 3
Na2CO3
NaOH
NaOH
Oil Pro.,
Million bbl
Facility
Cost
Chemical
Cost
Operation
Cost
334.14
552.12
336.33
11.4
12.6
17.1
6.9
12.1
16.6
8.9
10.2
14.1
Disposal Total
Agents Cost
Cost
1.0
28.2
1.5
36.3
1.7
49.5
IOR NORWAY 2017 – 19th European Symposium on Improved Oil Recovery
24-27 April 2017, Stavanger, Norway
Conclusions
Large scale ASP flooding field tests in Daqing showed that incremental oil recovery can be 30% OOIP
with proper design. Incremental oil recovery of WASP can be as high as that of SASP, which helps to
change the previous idea that WASP is inferior to SASP on recovery. Personalized polymer injection
scheme should be used instead of general injection when heterogeneity is taken into consideration.
Though ASP flooding can be technically very successful, economical success highly relies on total cost
when oil price is low. The total oil cost of three large ASP flooding field tests is between 28.2 -49.5$/bbl.
WASP is better than SASP because with almost the same incremental oil recovery, total oil production
cost of WASP is much lower than SASP. Economic performance rather than incremental recovery or
oil production should be the key evaluation criteria of ASP flooding. Previous ASP flooding field tests
and current ASP flooding in practice shows that ASP flooding is still very promising even under such
low oil price.
Acknowledgement
This work was financially supported by the Scientific Research Foundation of China University of
Petroleum, Beijing (No.2462013YJRC033), National Key Special Subjects(ZX20160158,
ZX20160110) National Natural Science Foundation Project (No.51374221; No.51604285), and Beijing
Natural Science Foundation (No.316404).
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