A Seminar on Thermal Recovery Technology by CNPC.pptx

1
A Seminar on Thermal Recovery
Technology by CNPC
Lecturer : DuanZong Chen
June,2007

2
Thermal Recovery Technology in China
and Feasibility in FNE Field, Block 6

3
OUTLINE
1. Thermal Recovery Technology overview in CNPC
2. Case study
3. Preliminary Study on Thermal Recovery for FNE
Field, in Block 6
4. Preliminary Study on Drilling and Oil Production
Engineering for Thermal Recovery in FNE Field

4
Part-1 Thermal Recovery Technology
overview in CNPC
1. Status of Heavy Oil Development in China
2. Thermal Recovery Technology in CNPC

5
1.1 Status of Heavy Oil Development in China
• UNITAR Definition of Heavy Oil
– Heavy crude oil has a gas-free viscosity from
100 to 10,000 cp at original reservoir
temperature or a gravity from 200 to 100 API
– Bitumen (Tar Sand) has a gas-free viscosity
greater than 10,000 cp at original reservoir
temperature or a gravity less than 100 API

6
Note：The viscosity marked with * is measure under reservoir conditions, and
others are measured at reservoir temperature, dead oil
• Definition of Heavy Oil
CNPC Classification Criteria of Heavy Oil
Classification Viscosity Density
（cp） 0API@20℃
Conventional
heavy oil
Ⅰ 50*(or100~10,000) 17.5<API<22.0
Sub-
class
Ⅰ－1 50* ~ 150*
Ⅰ－2 150*~10,000
Extra-heavy oil Ⅱ 10,000~50,000 12.9<API<17.5
Super-heavy oil Ⅲ 50,000 <12.9

7
Y More than 70 oil fields developed in 12 basins
Y 4 Major heavy oil fields: Liaohe, Xinjiang, Shengli, and Henan
Y Recently, deep heavy oil resources ( 2200m-- 5000m) have been
found in Tuha and Tarim oil fields
•
Karamay •
•
Shengli
•
Liaohe
Henan
Tarim
Tuha

8
Y Heavy oil has played an important role in China’s oil industry.
Y Since the first Cyclic Steam Stimulation pilot test succeeded in
1982, the thermal technology has been widely applied in China.
Y From 1995, heavy oil production has been over 250×103 BOPD,
accounting for over 10% of the total of CNPC.
0
3 0 0
2 5 0
2 0 0
1 5 0
1 0 0
5 0
1 9 9 2 1 9 9 4 1 9 9 6 1 9 9 8 2 0 0 0 2 0 0 2 2 0 0 4
Daily
oil
rate（MBBL）
Heavy oil Production in China

9
D Techniques in commercial application
• Cyclic Steam Stimulation (CSS)
• Steam flooding
• Horizontal and multi-lateral wells
• Hot water flooding
D Techniques in field test
• Steam Assisted Gravity Drainage (SAGD)
• Water flooding with N2 and chemical agents
• Cold heavy oil production with sand (CHOPS)
• In-situ combustion
1.2 Thermal Recovery Technology in CNPC

10
D Cyclic Steam Stimulation (CSS)
Also known as steam soak, or steam huff and puff
Production mechanisms
（1）V
Viscosity reduction
（2）Blocking removal
（3）Thermal expansion
of liquid and rock
（4）Formation
compaction 2000~4000t(CWE)
10~15days
2~7days Several months

11
Steam zone
Hot water zone
Cold oil zone
team Inj
S Soak ection
Oil Production
Process of CSS
D Cyclic Steam Stimulation (CSS)

12
Y Depth
Y Net pay
Y Oil viscosity
Y Net to gross ratio
Y Porosity
Y Permeability
Y Original oil saturation
≤1,700 m
≥5 m
≤100,000 cp
≥0.40
≥20 %
≥200 md
≥50%
D Cyclic Steam Stimulation
Screening Criteria for CSS

13
Main Mechanisms
(
(1
1)
) Viscosity Reduction
(2) Steam Distillation
(3) Thermal Expansion
(4) Steam drive
(5) others
D Steamflooding Process
Steamflooding is based on well patterns. Steam is
injected from injectors and oil is produced from
producers continuously. The steam functions are to heat
the reservoir and to provide the reservoir energy for
viscosity reduction and oil enhancement.
Production
Fluid

14
Steam zone
Hot water Cold oil
The process of Steam Flooding
Injector Producer
Producer
D Steam flooding Process

15
Contribution of Steam flooding Mechanisms to Oil Recovery

16
Screening Criteria for Steam flooding
Item parameter
Depth, m <1,400
Net Pay, m 7～60
Net to gross Ratio > 0.5
Permeability, md > 200
Porosity, ％ > 20
Oil saturation ％ > 45
Viscosity, cp <10,000
Pressure, psi <725

17
CSS vs Steam Flooding
• Advantages
– Immediate Production Response
– Quick Payout
– Relatively Inexpensive
– Fewer Facilities
• Disadvantage
– Lower Recovery factor (15~25% vs 50~60%)

18
D The technique package applied in steam injection
1. Geological study and reservoir description
2. Reservoir engineering study and Injection/production
parameter optimization
3. High-efficiency steam injection
4. Separate layer injection/production in multi-layer
reservoirs
5. Artificial lifting (high temp., heating, chemicals)
6. Sand control under high temperatures ( up to 350℃)
7. Performance monitoring and testing

19
1) Geological study and
reservoir description
Top of structure

20
Layer
1
Layer
3
Layer
5
Layer 7 Layer 9 Layer 11
Temperature distribution for Steam flooding
2) Reservoir engineering study and Injection/production parameter
optimization

(xs=50%) (xs=70%) (xs=80%)
steam chamber development in a horizontal well
21
2) Reservoir engineering study and Injection /production parameter
optimization

22
Funnel heat loss
Steam
3) High-efficiency steam injection technology
Steam generator
Surface heat loss
Fuel burning
Y The steam generator is
automatically controlled.
Y The fuel can be saved 18%
and thermal efficiency
increased by 3-4%

We have got new insulating
materials as the jacket of the
surface pipelines for steam
injection to reduce heat loss.
The field tests showed that the
new insulating material can
reduce heat loss by 8% for
1000m of pipeline, and increase
wellhead steam quality by 14%
23.

24
Equal Steam Quality Allocation System

25
--Thermal wellhead for
steam injection
Used in steam injectors,
capable of realizing
non-killing operation.
Technical specifications:
rated work pressure：3045psi
failure pressure： 6090psi
work temperature： ≤350 ℃
nominated drift： Φ80mm
connection mode： flange

26
Thermal conductivity of the vacuum insulating
tubing is only 0.007 W/m. ℃. It can reduce heat
loss in wellbore and maintain higher steam
quality downhole.
Formation
Vacuum
insulating tubing
Expansion
joint
Thermal
packer
Vacuum
insulating tubing
Heat insulating technology in wellbore
K331 heat-sensitive
metal expandable
packer
Vacuum heat insulating
tubing

27
Formation 1
Bull plug
4) Separate Steam injection for a multi-zone reservoir
Insulated tubing
Extension joint
Thermal packer
Formation 2
Formation 1
Formation 2

Pottery
pu
28
mp
5) Lift techniques with Hi-temp.,
corrosion-resistant pump
Annular type pump：≤140℃
Metalic pump ：140～180℃
pottery pump ： ≥180℃
Suitable for different stages of
thermal recovery with longer
service life
Annular type
pnmp
Metaiic
pump

29
6) Series of sand control
v"Inside gravel pack
v"Downhole filters
v"High temp. precoated sand
v"Combined sand control

7) On line testing technique for steam
injection
•Steam injection profile testing
• Downhole steam sampling
•High-temp. soaking pressure-drop
testing
•High-temp. fluid production profile
testing
• High temp. long-term testing
•Capillary separate layer pressure
testing
• Gas tracer monitoring
30

D Thermal recovery technology mainly includes cyclic steam
stimulation, steam flooding, hot water flooding, Steam Assisted
Gravity Drainage (SAGD) and in-situ combustion.
D The technique package applied in steaming process are
composed of high efficiency steam injection, Hi-temp. artificial
lifting, Hi-temp. online testing, and Hi-temp. sand control, etc.
D Thermal recovery technology has been commercially applied in
different heavy oil reservoirs, and has become the
predominated one for heavy oil production in China.
31
Summary

32
OUTLINE
2. Case study
Field, in Block 6

33
2.1 Cases for CSS
D Block Gao3
D Block Du66
Thick massive reservoir , China
laminated reservoir , China
2. Cases for CSS + Steam Flooding
D Block Qi40, Liaohe Oilfield, China
D Block 9, Kalamay oilfiled, China
3. Cases for Steam Flooding
D K e r n River, U.S.A
D Duri Oilfield, Indonesia
Part-2 Case Study

• Original pressure: 2320 psi
• Original temprature: 53.5 ℃
• Oil viscosity@ reservoir condition：518 cp
34
D Case 1: Block Gao3 , Liaohe Oilfield
• Thick massive reservoir with gas cap and bottom water
• Depth：1500－1650m
2.1 Cases For Cyclic Steam Stimulation
• Net pay：68.9m
• Porosity：24.0％
• Permeability：2364 md
• GOR: 131 scf/b
Crosse Section of Gao3

35
• Primary development: 1977 ~ 1982
• Primary & CSS : 1983 ~ 1985
• CSS : 1986 ~ Now
• Well Spacing: 210m, infilled to 150m 105m
This reservoir is the first thermal producing area in China.
It started with cyclic steam injection in 1982.
Development Results
• RF of Primary development: 4.5%
• RF of CSS: 18.3%
• Total RF (Primary + CSS): 22.8%
• OSR of CSS: 0. 91

5.0
0.0
1986 1987 1988 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000
36
Time (Year)
19.3
21.1 21.0
15.0
15.9
11.8
11.1
10.1 9.7 9.6
9.0 9.2
8.5 8.8
7.7
10.0
15.0
20.0
25.0
Daily
oil
rate
(MBOPD)
Production history of Gao 3

37
Cyclic oil production vs cycles
0.0
5000.0
10000.0
15000.0
20000.0
25000.0
1 2 3 4 5 6 7 8
Cycle
Cycle
Oil
product
ion
（BBl）

38
1.60
Oil/steam ratio(OSR) vs cycles
1.40
1.20
1.00
0.80
0.60
0.40
0.20
8
Cycles
0.00
0 2 4 6 10
OSR
– OSR = Oil Produced/ Steam Injected , That means how many bbls of
oil can be produced by 1bbl of steam injected

39
• Reservoir depth 875-1150 m
• Original reservoir pressure 9.4MPa
• Original reservoir temperature 51.2 ℃
• Net pay 26.4 m
• Net to gross ratio 0.442
• Porosity 26.9％
• Permeability 882 md
• Original oil saturation 68％
• Dead oil viscosity @reservoir T 2000 cp
• Oil density 17.4 API
D Case 2: Block Du66 , Liaohe Oilfield

13 40
1 2 3 4 5 6 7 8 9 10 11 12
Cycles
Cyclic
oil
pr
od.(B)
14000
12000
10000
8000
6000
4000
2000
0
16000
Cyclic oil production vs cycles

6 7 8
Soak time: 3~10d 41
Cycle time vs cycles
400
300
200
100
0
500
0 1 2
Cycle time: 220~390d
3 4 5
Cycles
Cycle
time
(days)
Injection time: 10~15d

42
OSR
10
Cycle
1.40
1.20
1.00
0.80
0.60
0.40
0.20
0.00
0 2 4 6 8 12 14

43
• CSS : 1986 ~ Now ( not finished yet )
• Well Spacing: 200m, infilled to 140m 100
m
• RF of CSS
• OSR of CSS
20.1
%
0.68
CSS Development Results

44
Block 6 Block 9
Karamay
Steam flood is
Successful in Block 9
D Case 1: Block 9, Karamay oilfield (Shallow Reservoir)
2.2 Cases For CSS+SF

Reservoir Parameters of Qigu Formation in Block 9
Reservoir Depth, m 240
Net pay m 13.9
Porosity, Fraction 0.30
Permeability, md 2630
Oil Density, API 17.5
Dead Oil Viscosity , cp 3000~10000
Reservoir Pressure, psi 360
Reservoir Temperature, ℃ 19
45

46
Production history
1984 ~ 1991：CSS period，recovery factor 18% ~ 25%.
1991 ~ 1996：Steam flood period at initial well pattern, well spacing
100×140m. recovery factor 3.6%
1996 ~ 1998：Infilled drilling wells
1998~Now： Steam flood period with well spacing of 70×100m

47
Steam flooding results in Block 9
Block Cum Oil
production
（MMB）
RF of CSS
（%）
Cum-OSR RF of
Steamflood
（%）
Cum-recovery
（%）
91-1 2.77 21.39 0.27 24.59 45.98
91-2 4.72 20.64 0.24 19.25 39.86
92 5.79 20.54 0.27 18.32 28.86
93 5.60 12.81 0.15 12.87 25.68
94 8.18 15.66 0.19 13.20 28.86
95 4.47 32.42 0.28 9.02 41.44
96 4.59 24.19 0.13 4.96 29.15
Average 19.69 14.4 34.09

48
• From Aug.1991 to Dec.2005, more than 600 well
groups converted to steam flooding, oil production
reached to 20×103 bopd
• Steam flooding has got commercial application in
shallow heavy oil reservoirs in China.

49
D Case 2: Block Qi40 , Liaohe Oilfield
• Middle to thick multi-layer reservoir
• D e p t h：625~1050m (850m)
• Net pay ：37.7m
• Net to gross ratio：0.58
• Porosity：30.0％
• Permeability：2060 md
• Original oil saturation: 70%
• Dead oil viscosity(@50℃)：3127 cp
W-E cross section

50
2 . 6
1 1 . 5
1 0 . 5
7 . 8
1 6 . 4
8 . 0
1 3 . 5
1 2 . 2
1 2 . 3
1 5 . 0
1 4 . 8
1 4 . 7
1 5 . 6
1 2 . 8
1 6 . 8
1 3 . 3
1 0 . 2
1 1 . 3
0.0
2.0
4.0
8.0
6.0
10.0
12.0
14.0
20.0
18.0
16.0
1 9 8 7 1 9 8 9 1 9 9 1 1 9 9 3 1 9 9 5 1 9 9 7 1 9 9 9
T im e (year)
2 0 0 1 2 0 0 3
Daily
oil
rate
(MBBL)
Production history of CSS in Qi40
Y CSS started in 1987: well spacing 200m
Y Infilled in 1990: well spacing 141m
Y Infilled again in 1994: well spacing 100m

51
Oil production vs cycles
Y The oil rate per well was only 57bbl/d with conventional cold
recovery
Y For CSS, the average oil rate increased to 189bbl/d, and the cyclic
production could be as high as 35,450 bbl in early cycles.
40000 200
0
5000
10000
15000
20000
25000
30000
35000
1 2 3 4 5 Cycle6
0
40
80
120
160
C yclic production
O il rate

Soak time: 3~10d
52
Cycle time vs cycles
0
100
200
300
400
1 2 3 4
Cycle time: 180~360d
5 6 7 8 9
Injection time: 10~15d
10 1
1 12
C
ycles
C
y
c
l
e
ti
m
e
(d
a
y
s
)

53
1.87
1.56
1.50
1.18
0.88
0.55
0.50
0.00
2.50
2.06
1.00
2.00
1 2 3 4 5 6
Cycle
OS
R

54
Steam flooding Pilot Test in Block Qi40
D 4 Well patterns for Steam flooding
– Inverted 9-spot well pattern with well
space of 70m
– Total wells: 27
D Before steam flooding：
– CSS started in 1987
– OSR (oil steam ratio): 1.1
– Oil Recovery Factor of CSS: 24.0%
– Oil Saturation before SF: 0.53
• Injectors: 4
• Producers: 21
• Observation wells: 2

2005 2006
55
10
100
1000
Steam
Breakthrough
Preheat Steam Drive Steam
Breakthrough
1997 1998 1999 2000 2001 2002 2003 2004
Oil
Rate,bbl/d
68
6800
Liquid Rate
Flooding
Oil Rate
Production performance curve of pilot area in Qi40

56
Steam flooding Pilot Test Results
Steam Flooding 1998.1—2006.12
– Cum. Oil Production：1.5 MMB
– Cum. Liquid Production：7.16 MMB
– Cum. Steam injection：8.62 MMB
– Cum. OSR：0.18
– Recovery Factor (SF)：28.0%
– Total Recovery Factor (CSS + SF)：52.0%

57
Development
results
• RF of CSS 28.5%
• Total RF of pilot test (CSS+SF) 52.0%
• Predicted RF of SF 24.7%
• Total RF predicted (CSS+SF) 53.2%
• OSR of CSS: 0.68

58
Main parameters of Kern River
Case1：Kern River, U.S.A
2.3 Cases For Steamflooding
Reservoir Parameters Average
Depth, m 275
Temperature，℃ 32
Thickness, m 18
porosity, % 31
permeability, md 2,000
Viscocity@32℃, cp 4,500
Oil Saturation before SF , % 45
Pressure before SF, psi 51
Pattern area: 2.5 acre
Producers： 8340
Injectors： 1220
Obser. wells： 660

59
0
60,000
40,000
20,000
80,000
100,000
120,000
140,000
160,000
1900 1910 1920 1930 1940 1950 1960 1970 1980 1990 2000
Primary
Exploitation
CSS
SF
SF performance of Kern River
RF of Primary & CSS: 8%
Daily Oil Production：
Total Recovery Factor：
Final Recovery Factor：
100 MB
>70%(2003)
80％
D Case1：Kern River, U.S.A

60
D Case2：Duri Oilfield, Indonesia
Main parameters of Duri Oilfield
• Many pilot tests such as
alkali waterflooding, in-situ
combustion, steam
flooding were conducted,
and finally steam flooding
was selected.
• RF of primary: 8%
Reservoir Parameters Average
Depth, m 150
Temperature，℃ 38
Net pay, m 37
Porosity , % 34
Permeability, md 1,500
Viscosity@38℃, cp 150~500
Oil Saturation before SF, % 60
Pressure before SF, psi 101

61
D Case 2：Duri Oilfield, Indonesia
OOIP： 5661 MMBBL
Total Blocks : 13
Steam flooding :10 Blocks
Well Pattern:
Well spacing:
Producers：
Injectors：
Inverted 7& 9-spot
120~130 m
3400
1600
Observation Wells： 300
Oil Rate ：
OSR ：
203.47 MB/d
0.19
Recovery Factor： 60％

62
OUTLINE
2. Case study
Field, in Block 6

63
1. Reservoir Characteristics of FNE
2. Thermal Recovery Tentative Plan for FNE
3. Suggestions for CSS Pilot Test
4. Plan forward for Thermal Recovery
5. Conclusions and recommendation
Part 3 Preliminary Study on Thermal
Recovery for Block FNE

64
3.1 Reservoir Characteristics of FNE
Reservoir parameters of Bentiu Formation
Reservoir Parameters Bentiu
Area 10.12 km2
Depth 502~678 m
Net Pay 30 m
Porosity 32.0 %
Permeability 350~6050(4000) md
Oil Saturation 70 %
Density 15.9~17.9 ºAPI
Pressure 595 psi
Temperature 43.5 ℃
Dead oil Viscosity 2160 cp@43.5℃
OOIP 224.80MMB
Note Bottom Water

65
D Compaction: fair to good , indicating point to point , and
concavo-convex contacts
D Sand cementation : poorly consolidated and unconsolidated,
fewer siderite, calcite and iron oxide cements

66
D Clay composition: kaolinite, chlorite, Illite and
smectite. (total content 15%- 40%)
Clay mineral composition from well Fula NE-2
Sample
Depth (m)
Clay Minerals %
Kaolinite Smectite Illite Chlorite Illite/
smectite
521.0 89.40 2.20 5.10 2.10 1.20
526.5 15.7 74.9 6.95 2.36 0.00
579.4 90.9 0.00 0.00 4.12 4.92
Average 65.3 25.7 4.02 2.86 2.04

67
30
25
20
15
10
5
0
Grain size,mm
Well FNE-2 sieve analysis (579.4m)
Weight,
%
grain size,mm
Well FNE-2 sieve analysis(579.4m)
100
80
60
40
20
0
10.00 1.00 0.01
0.10
cumulative,
%
50
40
30
20
10
0
Grain size,mm
Well FNE-2 sieve analysis (521m)
weigh,%
100
80
60
40
20
0
0.01
0.1
grain size,mm
1
10
cumulative
weight,%
d50=0.150mm
d50=0.436mm
Well FNE-2 sieve analysis(521m)
D Grain-size analysis: mainly in range of (0.09 mm-1.00mm) and fewer fine
grains (< 0.063mm) .

68
D Well test data
Well test result of FNE-1
Test
interval
(Bentiu)
m
Test
method
Test
date
(2005)
Daily production Survey
depth
(m)
conclusion
Choke
(mm)
Oil
b/d
wc Sand
cut
Flowing
press.
(psi)
536.0-544.0 PCP+
memory
gauge
04.27-
05.09
PCP/
72rpm
102 2% 0.02% / 540.67 Oil
Test interval
(Bentiu)
m
Test
method
Test
date
(2005)
Daily production Survey
depth
(m)
Test
conc.
Choke
(mm)
Oil
b/d
wc Sand
cut
Flowing
press.
(psi)
541-562m
Net pay of
10.1m
PCP 08.28-
09.04
/ 106 1% 0.01% / / Oil

69
D Well test data
Date &Time Duration
(hr)
PCP
Speed
(rpm)
Tubing
Press
(MPa)
Production Rate Oil
Density
(API)
Sand
Cut
(%)
Water
Cut
(%)
Avg.
Flowing
Pressure
(psia)
Oil
(bbl/d)
Water
(bbl/d)
Mar.06, 2007-
Mar.18, 2007
294.0 160 0.5 351.35 0 15.9 2.0-
1.0
0 416.67
.Mar.29, 2007-
Apr.04, 2007
155.5 200 0.5 388.78 0 15.9 2.6-
1.0
0 386.63

70
3.2 Thermal Recovery Tentative Plan for FNE
D Feasibility of Thermal Recovery on Block FNE
– The formation and oil properties of FNE are
suitable for CSS and SF process.
Parameter Comparison
Item CSS
Criteria
SF
criteria
FNE
Depth, m ≤1,700 <1,400 550
Net pay, m ≥5 7～60 20～30
Net Gross Ratio ≥0.4 >0.5 0.6
Permeability, md ≥200 >200 4000
Porosity, ％ ≥20 >20 32
Oil Saturation, ％ ≥50 >45 70
Viscosity, cp < 100,000 <10,000 2160
Pressure, psi <725 595

71
– Properties of FNE are similar to those of Block
Qi40
Parameters Comparison
Item Qi40 Kern River Duri FNE
Depth m 850 275 150 550
Net pay m 37.7 18 37 30
Permeability md 2060 2000 1,500 4000
Porosity ％ 30 31 34 32
Oil Saturation ％ 75 45 60 70
Viscosity cp 3,127 4,500 150~500 2,160
Temperature ℃ 37 32 38 43
Pressure psi 1232 51 101 595

72
– Properties of FNE are similar to those of Block Qi40
Results Comparison
Item Qi40 Kern River Duri
Well Pattern Inverted 9-spot 5-spot Inverted
7& 9-spot
Well Spacing m 70100 70 120~130
Oil Rate bopd 2060 2000 1,500
RF of primary % / 8.0 8.0
RF of CSS % 24.0 /
RF of SF % 31.0 >72.0 52.0
Total RF % 55 80 60

73
D Feasibility of Thermal Recovery on FNE field
– Low production rate with cold recovery, because of
high oil viscosity , formation damage;
• Drilling horizontal wells and applying thermal process
– Water channeling and water coning by vertical
wells, because of bottom water
• Drilling horizontal wells in the upper part of the zone

D Thermal recovery tentative plan for FNE
– Supposed that 85% of the oil bearing area will be
developed by horizontal wells with 85% of OOIP
– Well spacing 100m
• 6 drilling platforms
• 36 horizontal wells
• horizontal sections: 500m for 28 wells; 300m for the
other 8 wells
74

75
◆ Using CSS process in horizontal wells
Horizontal section
• Steam Injection
300～500m
6000～10000m3/cycle
• The oil rate of a horizontal well will be 950～1260b/d
predicted by JOSHI formula
◆ Using CSS in vertical wells
• Perforated interval
• Steam Injection
• The oil rate predicted
25m 2000～
3000m3/cycle 350 ～
500 b/d

76
0
5000
10000
15000
The Production Profile for Thermal Recovery
25000
CSS SF
20000
1 2 3 4 5 6 7 8 9 10 11 12 13
Time,Year
D CSS: 4 years with RF of 10.8% , Oil Rate: 9000~18000b/d
D SF: 10 years with RF of 33.3% , Oil Rate: 8700~21000b/d
D Total RF: 44.1%
14
Oil
Rate,bbl/d

77
Economic Evaluation on Thermal Recovery by
Horizontal Wells
Basic Parameters for Economic Evaluation
item value
Oil Price US$ 25.0/bbl or US$ 38.0/bbl
Discount Rate 12%
Transportation Cost US$ 4.0/bbl
Operation Cost US$ 4.0 /bbl
Drilling Cost Vertical Well： US$ 780 M /well
Horizontal Well: US$2.00 MM/well
Surface Facility Cost US$ 780 M/well
Boiler Cost US$ 2.00 MM
Insulation Tubing Cost US$ 100 M /well
Steam Cost US$ 15/m3

Economic evaluation result
Item Oil price：
US$ 25.0/bbl
Oil price：
US$ 38.0/bbl
Total Investment MM$ 176 176
Total cost MM$ 1194 1194
Payback period Year 2.6 1.0
Cum. cash flow MM$ 49.2 138
NPV MM$ 21.8 67.6
IRR ％ 19.2 39.7
Operation cost $/b 14.2 14.2 78

79
3.3 Suggestion for CSS Pilot Test
D Objectives of CSS Pilot Test
– Extended study on reservoir, confirming feasibility
of thermal recovery
– Checking adaptability of injection and production
techniques and improving them
– Providing preliminary results for optimization of
steam injection design

80
D 2 wells recommended for CSS pilot test
– Drilling a new vertical well, using thermal completion.
– Drilling a new horizontal well, completed by using sand
control screen.
D Make a comparison of adaptability , productivity
between the horizontal well and vertical well in CSS
to provide basis for the whole block development by
thermal process.

81
D Selecting proper well
locations for CSS test
– A new vertical & a
horizontal well will be
drilled near well FNE-8
to conduct CSS.

82
Log Interpretation Result of FNE-8
FNE-8：Net Pay of 51.8m，Net Gross Ratio：0.73，
7.0m of Claystone between pay zone and water zone.
BOTTO THICK GRO
M NESS SS NET VCL
m m m m %
473.5 2.5 2.5 2.5
15
519.5 4.5 4.5 4.5 10
563.5 42.0 42.0 42.0 5
566.5 1.5 1.5 1.5 12
585.5 18.1 18.1 3.8 13
609.5 17.0 3.6 0.0 10
625.0 10.1 9.1 0.0 15
629.9 4.1 4.1 0.0 35
635.5 4.5 3.5 0.0 25
648 7.6 6.8 0.0 10
656.5 4.7 3.7 0.0 30
672.3 5.1 4.6 0.0 40
Formati
on
Aradeib
NO. TOP POR Sw Result
m % %
a 17 471.0 27 50 oil
Bentiu 18 515.0 32 35 oil
19 521.5 34 20 oil
20 565.0 33 25 oil
21 567.4 33 55 oil
22 592.5 30 75 water
23 614.9 30 80 water
24 625.8 23 100 water
25 631 25 90 water
26 640.4 33 100 water
27 651.8 25 100 water
28 667.2 23 100 water

83
D Requirement for CSS Pilot Test
– Using thermal recovery completion, TOC to the
ground
– Vacuum heat insulated tubing is used for steam
injection both in vertical and horizontal wells
– Steam amount Injected to the vertical well 2000～
3000m3/cycle
– Steam Injection for the horizontal well 6000～
10000m3/cycle
– Using a skid-mounted boiler (23 t/h) ，with outlet
steam quality > 80％

84
D Monitoring Requirement for CSS pilot test
– Steam injection parameters such as injection rate ,
pressure, temperature and steam quality must be
monitored during the whole CSS.
– Measuring daily oil rate and water cut
– Measuring bottom hole pressure periodically. After 3
cycles, if possible, do a pressure build-up test .

D Field Data Collection
– Selecting appraisal wells to make zone-by-zone extended
production test，to determine the energy of bottom water
D Lab Experiment
– Oil displacement efficiency of water at different
temperatures
– Oil displacement efficiency of steam
– Thermal properties of formation rocks
D Make a Design for Thermal Recovery
– Reservoir description
– Analysis and evaluation on CSS test
– Reservoir engineering study on Thermal Recovery
– Steam injection and production engineering research
– Optimization of Steam injection
85
3.4 Plan forward for Thermal Recovery

D FNE field is suitable for CSS and SF
D A good recovery performance can be obtained
– CSS: 4 years with RF of 10.8%
– SF: 10 years with RF of 33.3%
– Oil production: 8700~22000b/d
– Total RF: 44.1% (not including the primary phase)
D Recommend to conduct CSS tests with vertical
and horizontal wells to identify the productivity
D Make a design for thermal recovery based on CSS
test results
86
3.5 Conclusions and recommendation

87
OUTLINE
2. Case study
Field, in Block 6
4. Preliminary Study on Drilling and Oil
Production Engineering for Thermal Recovery
in FNE Field

88
1. Basic strategy of the reservoir development
2. Drilling technology for horizontal wells in
shallow reservoirs
3. PCP lift technology for horizontal wells
4. Sand control technology
5. Conclusions and suggestion
Part-4 Preliminary Study on Drilling and Oil
Production Engineering for Thermal Recovery

4.1.1 Difficulties and solutions in drilling and production
engineering
Y Low production rate with cold recovery ,because of high oil
viscosity , formation damage, and quite lower formation temp.
• Employing thermal recovery method
• Employing horizontal wells to enhance production ,to relieve sanding,
and water coning
Y Severe formation damage caused by drilling, because of very low
reservoir pressure, and clay mineral composition
• Developing a proper drilling fluid system with low density and good
inhibition
• Designing advanced cement slurry and cementing program
Y Water channeling and water coning in vertical wells, because of
abundant bottom water
• Drilling horizontal wells in the upper part of the pay zone
89
4.1 Basic strategy of the reservoir development

1.Difficulties and solutions in drilling and production
engineering
YSerious sanding problem due to poorly consolidated , high oil
viscosity and greater pressure drawdown
•Using horizontal wells to reduce the drawdown
• Steam injection to reduce oil viscosity
• Optimizing sand control methods for different d50
YSerious wearing problem between rods and tubing and high temp.
problem in PCP for shallow horizontal wells
•Optimal design for centralizer and selecting glass lining tubing to
reduce friction and wearing
• Developing a new type of centralizer and cardan joint
• Selecting metal to metal PCP with large volume rate at lower RPM
90

91
4.1.2 Strategy summary
D The shallow reservoir in Block 6 is supposed to be
developed by horizontal wells
D Applying steam injection for higher production rate
D Optimizing PCP and rod/tubing structure to lift
heavy oil with sand and to reduce wearing
D Determining and executing sand control to keep
stable production for long run

4.2.1 Key technologies in drilling
Drilling technology for horizontal wells in shallow layers includes
the following:
Optimum casing program &well profile plan
Hole t
tr
ra
ajje
ec
ct
to
or
ry
y c
co
on
nt
tr
ro
olllliin
ng
g &
&g
ge
eo
o-
-
-s
s
st
t
te
e
ee
e
er
r
ri
i
in
n
ng
g t
te
ec
ch
hn
no
ollo
og
gy
y
Water based, low solid drilling fluid for reservoir protection
Drag and friction reduction technology
Shallow horizontal well completion technology
92
4.2 Drilling technology for horizontal wells in shallow layers

Well bore trajectory schem
93 atic
KOP:
Below 120m（170-230m）
Wellbore profile ：
Single-circular arc for build-
up section and angle- holding
to the reservoir top
186
A
B
221
60º
221
260.
5m
280
540.5m
6
6º
24º
2
7.
5
4.2.2 Optimum casing program &well profile plan

b. Improved casing program without
intermediate casing by drag-analyzing
and checkout
94
Surf. 273mm×150m
Bit 393mm×151m
a. Initial casing program with
intermediate casing ,used in the early
3 wells
4.2.2 Optimum casing program &well profile plan
TOP:surface
Prod. 139.7mm×927m
Bit 215mm×929m
Surf. 339.7mm×70m
Bit 445mm×71m
Interm. 244.5mm×445m,Dev. 60o
Bit 311mm ×446m Prod. 139.7mm
Bit 215mm
TOC 200m

95
4.2.3 Drilling fluid technology
• Mud system
Bentonite mud during the 1st spud
Low solid phase polymer drilling fluid system in the 2nd spud
• Drilling fluid property
4-grade solid control system
Solid content < 13%
Lubricant content >3%
Adding XC to the mud to enhance shearing force with good cutting-
carrying ability for cleaning up the wellbore effectively
Lubricant content & Lower solid content to decrease drag friction
coefficient to less than 0.1,meeting the requirement for drilling.

Screen completion
96
Perforating completion for thermal
recovery of heavy oil
4.2.4 Well completion technology
Completion modes
Bit 393.7mm×Surf.273.1mm×150m
Build up rate
8~10o/30m
TOC : surface
Bit 241mm×Prod. 177.8mm×point B
A B
TOC:surface
Bit 393.7mm×Surf.273.1mm×150m
Prod. 177.8mm×Point A
Build up rate 8~10o/30m
Screen hanger 177.8mm
Screen 177.8mm from A to B
Bit 241.3mm×B
Horizon. Sec. 200-300m

97
Low-filtrate micro-expanding slurry performance
（1）Filtrate：＜ 50ml (30min,@7MPa, 51℃)
（2）Good fluidity ：＞ 220mm；
（3）Micro-expansion rate＞ 0.02% (24h,@51℃,0.1MPa)
（4）Compressive strength ( required for fracturing )：＞14MPa
(24h,@51℃, 0.1MPa)
4.2.4 well completion technology----- cementing
Slurry structure optimizing
Head slurry ( for vertical and build-up sections) ,
Tail slurry (micro-expansion & low loss for horizontal and higher-
angle sections）
Application in the field
• 54 wells has been successfully operated
• With a up-to-standard rate of almost 100% (54 wells)
• High quality rate of 94.4% (51 wells)

98
4.2.5 Typical, shallow horizontal wells
Stepped horizontal well developing two thin oil
layers —— well FP10
A stepped horizontal well developing two thin oil layers
Pay zone 1
VD 435m
Pay zone 2
VD 438m
Wellbore configuration schematic of well FP10

99
-100
0
100
200
300
400
Well FP 12 an
50
d
0
429.97
a(30)
436.37
b(30)
460.37
fc(
13
20)
9
ew 21.6m.
fp13
a(30)
b(30)
c(30)
fp12new
z14-054
z14-54
a(30)
b(30)
c(30)
d(30)
fp13
FP 13 well profile schematic
Vertical projection
Horizon.
projection
4.2.5 Typical,shallow horizontal wells
Shallow triaxial extended reach well
Cluster drilling
on the same
platform, for
respectively
developing quite
a lot of layers.
The minimal
distance is less
than 15m with
the max.
displacement of
Well No. TMD m Max. TVD
m
KOP m Max Dev.ang.
deg.
Horiz.disp.
m
Horiz.Sect.
m
Disp./ TVD
FP12 1242 460.22 190 95.54 921.6 673 2.00
FP13 1142.73 420.5 210 89.3 865.81 615.59 2.06

100
6. Application summary
• 54 horizontal wells in shallow layers successfully drilled
and completed in a similar oil field in China from 2004 to
2006
• VD 388.8-476.8m and MD 766-1245m
• Maximal horizontal displacement 921.6m（well FP12）
• Maximal horizontal section 673m（well FP 12 ）
• Water-base drilling fluid employed
• Common drilling rigs used (ZJ15、truck-mounted 20）
• Average drilling cycle of 9.2d，and well cycle of 13.06d
• Up-to-standard rate of Wellbore quality close to 100%
• Horizontal well production rate 3-5 times of that in adjacent
vertical wells.

101
PCP Application Range
* Requires Special Analysis
Typical Range Maximum*
Operating Depth
1,000’ – 5,000’ TVD
330 – 1,550 m TVD
9,800’ TVD
3,000 m TVD
Operating Volume
5 – 2,500 BPD
1 – 400 m3/day
5,000 BPD
800 m3/day
WeOh
pe
a
ra
v
tie
ng got rod pump75
a–
n
1
d
70P
°C
F P
Temperature 24 – 77 °C
752 °F
400°C
hi
W
g
eh
llbo
s
re
aD
n
ed
viat
c
io
u
nt and high N
p
/A
rod.
Dogleg Severity less
than 15°/100 feet
15°/30m
Colri
rf
ot
sio
h
ne
H
a
an
v
dy
ling
oil with sand
Ex
!cellent (regarding pump)
Gas Handling Good
Solids Handling Excellent
Fluid Gravity
Below 45 °API (highly dependable on aromatics
content)
Servicing and Repair Requires Workover or Pulling Rig
Prime Mover Type Electric Motor or Internal Combustion Engine
Offshore Application Good
System Efficiency 50% to 75% (up to 90%)
4.3 PCP lift technology for horizontal wells
for lifting heavy oil. Because of
Rate, PCP is the best choice to

102
Challenges and solutions in PCP applied for thermal
recovery in FNE field
Y High temperature in thermal process
PCM has developed a revolutionary all-metal pump to
withstand a temp. as high as 400℃( 7500F) ,which has
been successfully used in CSS and SAGD processes.
Y High wearing rate problem in horizontal wells
• Design optimization for pump type, rpm, the
centralizer quantity and space out by a computer
program.
• Employing new type of centralizer and cardon
joint.
• Selecting a kind of glass-lining tubing.

103
Conventional centralizer
with vertical slots
Rotation centralizer
with vertical slots
Disadvantage：
Suffering a unilateral wearing,
greater flow resistance
new type of centralizer
rib
New rotational type of centralizer
lining
Rotational centralizers
with low friction lining
1、Selecting a low friction material with a
10-time service life of conventional nylon
centralizer.
2、With spiral slots to keep equal gap
between the tubing and centralizer ribs for
uniform wearing.

of rods when
104
Relieving bending stress of rods,
moment resistance and tangent wearing
reducing the bending
rotating in highly deviated sections.
Bending
moment
resistance
a new type of cardan joint

Great difference existed between using and no using centralizers. The
wearing rate without centralizers is as 5 times as that with centralizers.
105
6
5
4
3
2
1
0
0 100 200 300 400 500
35
30
25
20
15
10
5
0
dogleg
centr.
Dev.
Centralizer distribution in well E32-251
Typical well examples (well E32-251)
50
40
30
20
10
0
0
3
7
6
7
1
1
3
1
4
3
1
7
4
2
1
2
2
5
0
2
8
8
MD,m
W
e
a
r
i
n
g
r
a
t
e
,
%
/
a
with
without
Wearing rate comparison
with/without using centralizers

106
Application scale and result
Since April, 2004, among the total 564 PCP wells,
the longest production time has been up to more
than 700 days ,and the maximum deviation angle at
pump location is up to 60 deg.
field name FU MT XM YT tota
l
deviated
or
horizont
al
484 39 39 2 564

107
Main sand control methods
Gravel pack Sand filters
4.4 Sand control technology
tubin
cross.
sub
packer
holes
Firing
head
gun
g
Combined perf.
Chemical
Frac & pack

108
Sand filter for steaming horizontal wells
Sand control schematic for steaming horizontal wells
4.4 Sand control technology
Casing Prod. packer Steam packer Metal fiber filter Bull plug
Fish top Perfs. Arti. bottom

109
4.5 Conclusions and suggestion
1. Drilling technologies for shallow horizontal wells are successfully
applied in quite a few oil fields in China
2. PCP technology can be effectively used by selecting high
temperature, large volume rate pump at lower RPM, designing the
optimal parameters, using a new type of centralizer and cardan
joint to control wearing rate
3. It is sure that sanding problems would happen, so sand control
completion should be taken for most oil wells, and downhole filter
should be one of the important candidates for most horizontal
wells
4. In order to fully develop the heavy oil reservoir in Sudan, it is
suggested that all the technologies mentioned above should be
pilot tested first in selected well groups, especially with a couple
of horizontal wells

110
technology will be successfully
applied in heavy oil reservoirs in
Sudan!
Thank you !
We hope that the thermal recovery

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