1.1 Objectives
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This well planning and design idea focuses on exploration (wildcat) well. The objectives of drilling this exploration well are to: –
determine the presence of hydrocarbon
obtain data for further exploration activities
drill well by considering safety, costs and environmental conservation.
1.2 Location
The well is located at 60° 30′ 30.65” N and 2° 41′ 20.65” E in Oseberg field with water depth of 108 m. It will be drilled to a depth of 12,090 ft TVD and 12,103 ft MD. Total of 116 days will be used. According to the outstep data, the main reservoir of the area is sandstone of Middle Jurassic age which start at a depth of 10,237 ft.
Prior to the commencement of drilling operation, drilling consents from responsible Norwegian Authorities will be applied (PSA 2019; Hasle et al. 2009). The consent application is governed by the following regulations: –
Resource Regulation of 2017 (section 15) of Norwegian Petroleum Directorate (NPD).
Management Regulations of 2019 (section 25) of Petroleum Safety Authority (PSA).
Pollution Control Act no.6 of 1981 for Norwegian Environment Agency (NEA).
The following steps involved in obtaining drilling consent: –
Applying drilling consent to drill to NEA. This agency will approve application after critically evaluation of the environmental impact assessment.
Then, followed by the application of the consent from PSA.
Finally, application of drilling permit from NPD by filling the registration form of wells and wellbores (NPD 2019).
Once NPD approves the application, drilling permit is granted to the operator.
2.1 Data collection
Outstep data from NPD was used in the design. Data used was based on block 30/6 in the Oseberg field, wellbore number 30/6 – 18.
Subsurface pressure regime evaluation is vital in order to make decision on the methods which can be used to predicting pressure gradients (Emudianughe and Ogagarue 2018). This is because both hydrostatic and formation pressure regime can complicate drilling process and leads to hazards (Sen and Ganguli 2019).
Therefore, using outstep well data, the formation pore pressure was established by using the following formula;
pore pressure gradient (psi/ft) =
Pore Pressure (psi)TVD (ft)
……………Equation 1 (Zhang 2011).
Hence, using the pore pressure data in appendix I, the graph of formation pore pressure against depth was plotted as described in Figure 1. The graph shows the gradually increase in pore pressure from 5,400 ft to 11,200 ft. This situation has been experienced in several wells within this field due to an increase of the background gas (NPD 2019).
Figure 1: Variation of formation pore pressure and depth of the well
The lithology of the area consists of massive sandstone ranging from fine to medium grained and some calcite. Coarse sediment of sands and gravels which provide potential loss of circulation is anticipated in some area of the well. Also, troublesome zones are expected to be encountered between 5400 ft to 11,200 ft depth (Figures 2 and 3). Therefore, the fracture pressure was established based on leak-off test points from the outstep data using equation 2.
Fracture pressure (psi) = Fracture gradient (ppg) x TVD (ft) x 0.052……Equation 2 (Zhang 2011).
The results of the fracture pressures are shown in appendix I while the graphs of fracture pressure and pore pressures versus depth are shown in Figure 2 and Figure 3 respectively. Both graphs show the increasing of pressure down the hole.
Figure 2: The graph of fracture pressure against depth of the well
Figure 3: The graph of pore pressure and fracture pressures against depth
Casing design was done based on the pore pressure and fracture pressure gradients shown in Figure 4. According to Fakhr (2016), safety factor of 0.3 ppg was assumed in order to get trip and kick margins. Also, the depth of casing was set by considering the change of pressure of the well. Having considered all factors, 30” conductor casing, 20” surface casing,
1335
inch and
958
inch intermediate casings were set at a depth of 710 ft, 2100 ft, 5241 ft and 11,195 ft respectively (Figure 5). Two intermediate casings were chosen in order to prevent the well from the troublesome zones between 5400 ft to 11,200 ft.
Furthermore, casing properties shown in Table 1 were calculated because the drilling process may result in radial and axial loads on the casing strings (Hossain and Al-Majed 2015; Bourgoyne et al. 1991). Therefore, casing grades according to API was selected based on the computed casing properties using formulas indicted in Appendix II.
Table 1: The specification of casings used in well design
Type of Casing
Casing OD (in)
Casing ID (in)
API Grade
Minimum Yield Strength (psi)
Weight (lb/ft)
Burst (psi)
Collapse (psi)
Axial (lbf)
Conductor
30
28.000
K-55
55,000
310
3,210
1670
5,010,840
Surface
20
18.730
K-55
55,000
133
3,060
1490
2,124,730
Intermediate
13.375
12.347
N-80
80,000
72
5,380
2670
1,661,410
Intermediate
9.625
8.681
N-80
80,000
53
6,870
4760
1,085,790
Figure 4: Casing depth setting for the designed exploration well
Wellhead was selected based on the maximum pore pressure. Since the maximum pore pressure was 6506 psi, wellhead was selected to tolerance the double pressure (13,012 psi). Thus, according to API specifications, wellhead pressure rating of 103.5MPa was chosen (Figure 5) with components shown in Figure 6.
Figure 5: Specification for wellhead and Christmas tree equipment (API 2010).
Figure 6: Typical wellhead components (API 2010)
BOP is important for preventing uncontrolled flow of formation fluids, kick and blowout when primary control of the well fails (Adams and Charrier 1985). For this design, BOP requirements are presented in Table 2. The BOP pressure rating of 103.4 MPa (15,000 psi) was selected because it can withstand twice of the maximum expected pore pressure (6506 psi) that can be encountered during drilling. The selection criteria were done according to API rating pressures as shown in Table 3.
Table 2: BOP requirements (API 2010)
Hole size (inches)
BOP requirement
Rating (psi.)
26
nil
nil
1712
nil
nil
1214
2x rams
1x shear
1x annular
10,000
10,000
5,000
Table 3: BOP Working Pressure Ratings (API 2010)
Cementing is important in order to isolate formations and casings, maintain stability of the casing and the well. For this design, single stage cementing which is the most common in industry will be used. Also, API class G cement has been chosen because of the following reasons detailed by Adam and Charrier (1985).
It can be used under high temperature and pressure,
It is more compatible with many additives,
It can be used for deep wells.
The casing parameters used and the volume obtained are shown in Table 4 and 5 respectively. Formulas used to calculate the cementing requirements are shown in appendix III.
Table 4: Casing parameters required for the cementing program
CEMENT CLASS
HOLE SIZE
(in)
CASING SIZE
(in)
DEPTH FROM THE SURFACE
(ft)
CLASS G with
C3S (52%), C2S (32%), C3A (8%) and C4AF (12%)
36
30
710
26
20
2,100
1712
13.375
5,241
1214
9.625
11,195
Table 5: Required volume of cement in each casing
HOLE SIZE
(in)
CASING SIZE
(in)
DEPTH FROM THE SURFACE
(ft)
CEMENT VOLUME (bbl)
Displacement Volume
(bbl)
Number of sacks
(sacks)
Volume of mixed water
(gal)
36
30
710
327.76
489.43
1614
8005.4
26
20
2,100
675.66
693.7
3328
16,506.88
1712
13.375
5,241
778.12
755.44
3832
19006.7
1214
9.625
11,195
749.4
789.27
3691
18,307.36
Displacement methods
Since the displacement of the cement can impact the whole exercise, the following primary procedures adopted from Hossain and Al-Majed (2015) will be used (Figure 7).
Circulating chemical washers
Inserting bottom plug
Pumping down the spacer
Pumping cement slurry
Inserting top plug
Displacing with displacement fluid until the top plug reach the float collar
Then, pressure testing of the casing is done.
Figure 7: Typical Primary Cementing Procedures (Hossain and Al-Majed 2015:523)
Water-based mud will be used during drilling. This is due to the cost and environmental consideration. Mud weight will be changed according to the subsurface formation of the well (Figure 8). Thus, mud density that will maintain primary well control across the well was calculated by keeping mud hydrostatic pressure equal to the pore pressure using equation 3. The results are attached in appendix IV. The figure shows constant mud weight of 8.6 ppg will be used until depth of 5576 ft because of stable formation. However, mud density will be increased to 10.9 ppg from 5576 ft to TVD. High mud density between 7,872 ft to 10237 ft is because of hard claystone and dolomite formation with 15 m thick of limestone. Mud weight for each casing section are shown in Table 6.
Mud weight (ppg) = Pressure gradient (psi/ft) ÷ 0.052 equation 3.
Figure 8: Variation of mud density during drilling operation.
Table 6: Mud weight for maintaining primary well control
Type of Mud
HOLE SIZE
(in)
CASING SIZE
(in)
DEPTH FROM THE SURFACE
(ft)
Mud weight for primary well control (ppg)
Water Based Mud
36
30
710
8.6
26
20
2,100
9.7
1712
13.375
5,241
10.9
1214
9.625
11,195
10.9
Appropriate drilling bit selection requires evaluation of various contributing factors including the cost per depth and rate of penetration (Nabilou 2016). Therefore, based on the subsurface formation of the area which is predominantly consist of interbed of soft sand, claystone, lime and moderately hard layer of limestone, roller cone bits will be used (Figure 9). The reasons behind selection is due to its flexibility and can be used to drill both hard and soft formations. Different bits size based on API standards will be employed according to the required holes for casing layout.
Figure 9: Roller Cones Bits (Hossain and Al-Majed 2015:340)
The following requirements necessary to meet the well objectives will be evaluated: –
Drilling log requirements
In each section of the well, drilling logs will be taken in order to understand formation composition and integrity, types of fluids present and presence of hydrocarbon.
Mud logging requirements:
This will be done in a regular interval in order to monitor the well; prevent losses from the formation; understand lithology and to evaluate hydrocarbon.
Coring requirements:
Core samples will be taken in order to understand variation of formation, the quality of reservoir and the elements of the presence of the hydrocarbon. Factors such as porosity, permeability, water and hydrocarbon saturation will be considered.
Measurement-While-Drilling (MWD) requirements:
MWD will be conducted in order to have a real time downhole survey and get continuous directional information of the well.
The time taken to drill a well is estimated to be 116 days. However, this time considers several mobilization and technical logistics including moving the rig, drilling the well, formation evaluation and abandonment. The estimated drilling time to reach to TVD is expected to be 69 days as shown in Figure 10.
Figure 10: Time distribution for the drilling operations
The Authorization for Expenditure (AFE) is shown in Appendix V. It consists of tangible and non-tangible costs of drilling operations. The estimated cost of the well is approximately $53.74 Million.
Adams, N. and Charrier, T. (1985) Drilling Engineering: A Complete Well Planning Approach. Tulsa, Oklahoma: PennWell Publishing Company.
API (2010) API Specification 6A: Specification for Wellhead and Christmas Tree Equipment (20th
Edition). American Petroleum Institute [online] available at </www.api.org/products-and-services/standards/important-standards-announcements/spec-6a> [20th October 2019]
Bourgoyne, A., Chenevert, M. and Millheim, K. (1991) Applied Drilling Engineering [online] 2nd
edn. Richardson: Society of Petroleum Engineers. available from <https://ebookcentral.proquest.com/lib/coventry/detail.action?docID=3405014> [20th October 2019]
Fakhr, S. (2016) Formation Pressure [online] available from <http://famanchemie.com/Uploads/literature1/Formation%20Pressure.pdf> [10 October 2019]
Hasle, J., Kjellén, U. and Haugerud, O. (2009) ‘Decision on Oil and Gas Exploration in an Arctic Area: Case Study from The Norwegian Barents Sea’. Safety Science 47 (6), 832-842
Hossain, M. and Al-Majed, A. (2015) Fundamentals of Sustainable Drilling Engineering. Hoboken, New Jersey: John Wiley and Sons
JE, E. and DO, O. (2018) ‘Investigating the Subsurface Pressure Regime of Ada-Field in Onshore Niger Delta Basin Nigeria’. Journal of Geology & Geophysics 07 (06)
Nabilou, A. (2016) ‘Effect of Parameters of Selection and Replacement Drilling Bits Based on Geo-
Mechanical Factors: (Case Study: Gas and Oil Reservoir in The Southwest of Iran)’. American Journal of Engineering and Applied Sciences 9 (2), 380-395
Norwegian Petroleum Directorate (2019) Regulations Relating to Resource Management in the Petroleum Activities [online] available from <https://www.npd.no/en/regulations/regulations/resource-management-in-the-petroleum-activities/> [14 October 2019]
Petroleum Safety Authority Norway (2019) Regulations relating to conducting petroleum activities [online] available from < https://www.ptil.no/en/regulations/all acts/?forklift=613> [14 October 2019]
Sen, S. and Ganguli, S.S. (2019) ‘Estimation of Pore Pressure and Fracture Gradient in Volve Field, Norwegian North Sea’. SPE Oil and Gas India Conference and Exhibition: Society of Petroleum Engineers. held 9-11 April 2019 at Mumbai, India.
Zhang, J. (2011) ‘Pore Pressure Prediction from Well Logs: Methods, Modifications, And New Approaches’. Earth-Science Reviews 108 (1-2), 50-63
APPENDICES
Appendix I: Table of Pore Pressure, Pore Pressure gradient, Fracture Pressure and gradient computation
Depth (ft)
Pore Pressure Gr (psi/ft)
Pore Pressure (psi)
Fr Gradient (psi/ft)
Fracture Pressure (psi)
Trip Margin (ppg)
Trip Margin (psi/ft)
Kick Margin (ppg)
Kick Margin (psi/ft)
436
0.447
194.8
0.651
284.0
8.90
0.463
12.22
0.635
718
0.447
320.6
0.651
467.4
8.90
0.463
12.22
0.635
1722
0.447
768.9
0.651
1120.9
8.90
0.463
12.22
0.635
2110
0.447
942.1
0.651
1373.4
8.90
0.463
12.22
0.635
2145
0.447
957.8
0.651
1396.3
8.90
0.463
12.22
0.635
2893
0.447
1291.7
0.651
1883.1
8.90
0.463
12.22
0.635
4205
0.447
1877.5
0.651
2737.1
8.90
0.463
12.22
0.635
4900
0.447
2188.0
0.651
3189.7
8.90
0.463
12.22
0.635
5241
0.447
2340.1
0.651
3411.4
8.90
0.463
12.22
0.635
5291
0.447
2362.3
0.777
4109.5
8.90
0.463
14.64
0.761
5412
0.447
2416.5
0.777
4203.8
8.90
0.463
14.64
0.761
5576
0.464
2586.4
0.777
4331.2
9.23
0.480
14.64
0.761
5904
0.490
2892.1
0.777
4585.9
9.73
0.506
14.64
0.761
6232
0.520
3241.9
0.777
4840.7
10.31
0.536
14.64
0.761
6560
0.538
3526.3
0.777
5095.5
10.65
0.554
14.64
0.761
6888
0.551
3792.2
0.777
5350.3
10.90
0.567
14.64
0.761
7085
0.555
3931.2
0.777
5503.1
10.98
0.571
14.64
0.761
7216
0.559
4035.3
0.777
5605.0
11.07
0.575
14.64
0.761
7544
0.564
4251.4
0.777
5859.8
11.15
0.580
14.64
0.761
7872
0.568
4470.4
0.777
6114.6
11.23
0.584
14.64
0.761
8069
0.568
4582.2
0.777
6267.5
11.23
0.584
14.64
0.761
8561
0.568
4861.5
0.777
6649.6
11.23
0.584
14.64
0.761
9381
0.568
5327.2
0.777
7286.6
11.23
0.584
14.64
0.761
9545
0.568
5420.3
0.777
7413.9
11.23
0.584
14.64
0.761
9906
0.555
5496.4
0.777
7694.2
10.98
0.571
14.64
0.761
10070
0.546
5500.1
0.777
7821.6
10.81
0.562
14.64
0.761
10237
0.542
5547.1
0.777
7951.5
10.73
0.558
14.64
0.761
10562
0.538
5677.3
0.777
8203.8
10.65
0.554
14.64
0.761
10988
0.542
5954.1
0.777
8535.0
10.73
0.558
14.64
0.761
11195
0.542
6066.3
0.764
8550.0
10.73
0.558
14.39
0.748
11349
0.538
6100.4
0.764
8667.5
10.65
0.554
14.39
0.748
12103
0.538
6506.0
0.764
9243.6
10.65
0.554
14.39
0.748
Appendix II: Formulas used to calculate casings properties
Burst pressure, collapse pressure and axial load of the casing were calculated using the following formula (Bourgoyne et al. 1985).
Casing Burst Pressure
PB=0.8752YptOD………..equation 2
Where:
PB = burst pressure (psi)
YP = Specified minimum yield strength (psi)
t = nominal wall thickness (in)
OD = nominal outside diameter (in)
Moreover, internal diameter was computed through
OD–ID=2t…………….equation 3
Casing Collapse Pressure
Pcr=2σyielddnt–1dnt2
Where:
Pcr
= Collapse pressure (psi)
σyield
= yield strength (psi)
t = nominal wall thickness (in)
dn
= nominal outside diameter (in)
Casing Axial loads
Ften=π4σyielddno2–dni2
Where;
Ften
= pipe-body tensile strength (lbf)
σyield
=minimum yield strength (psi)
dno
= nominal OD of pipe, in
dni
= nominal ID of pipe, in
Appendix III: Formulas and Computation used to calculate the volume of cements
Assumptions were used for designing the cementing program: –
Slurry density is 15.9 ppg
Yield per sack is 1.14 ft3 per sack
Water mixed per sack is 4.96 gal/sack
Type G cement composed of D13R (retarder) of 0.2% and friction reducer (D65) of 1%
The collar and Rathole distance are 60ft and 10 ft respectively
20% excess shall be considered in open hole.
Volume per stroke is 0.138 bbl
30
inch conductor casing
Slurry volume
Slurry Volume bbl=dhole2–dcasing21029.4×depth of the casing (ft)
Slurry Volume bbl=362–3021029.4×710=273.13 bbl
Add 20% excess in open hole
Slurry volume=1.2×273.13=327.76 bbl
=327.76×5.6146=1840 ft3
Displacement Volume
Displacement Volume bbl=dID21029.4×depth of float collar ft
=2821029.4×710–70ft=487.43 bbl
Add 2 bbl as a factor to be very certain, Therefore, Displacement volume is 489.43 bbl.
Number of sacks
Number of sacks=Volume of slurrySlurry yield
=18401.14=1614
sacks
Volume of mixed water
Volume of mixed water=number of sacks ×4.96galsack
=1614×4.96 gal=8005.4 gal
Amount of additives
Retarder=0.2100×1614×94lbsack=303.43 lb
Retarder=1100×1614×94lbsack=1517.16 lb
Number of strokes
Number of strokes= Displacement volume0.138
=489.430.138=3546 strokes
20
inch surface casing
Slurry volume
Slurry Volume bbl=dhole2–dcasing21029.4×depth of the casing (ft)
Slurry Volume bbl=262–2021029.4×2100=563.05 bbl
Add 20% excess in open hole
Slurry volume=1.2×563.05=675.66 bbl
=675.66×5.6146=3793.56 ft3
Displacement Volume
Displacement Volume bbl=dID21029.4×depth of float collar ft
=18.72821029.4×2100–70ft
=691.7 bbl
Add 2 bbl as a factor to be very certain, Therefore, Displacement volume is 693.7 bbl.
Number of sacks
Number of sacks=Volume of slurrySlurry yield
=3793.561.14=3328
sacks
Volume of mixed water
Volume of mixed water=number of sacks ×4.96galsack
=3328×4.96 gal=16,506.88 gal
Amount of additives
Retarder=0.2100×3328×94lbsack=625.66 lb
Retarder=1100×3328×94lbsack=3128.32 lb
Number of strokes
Number of strokes= Displacement volume0.138
=693.70.138=5027 strokes
1338
inch intermediate casing
Slurry volume
Slurry Volume bbl=dhole2–dcasing21029.4×depth of the casing (ft)
Slurry Volume bbl=17.52–13.37521029.4×5241=648.43 bbl
Add 20% excess in open hole
Slurry volume=1.2×648.43=778.12 bbl
=778.12×5.6146=4369 ft3
Displacement Volume
Displacement Volume bbl=dID21029.4×depth of float collar ft
=12.24721029.4×5241–70ft
=753.44 bbl
Add 2 bbl as a factor to be very certain, Therefore, Displacement volume is 755.44 bbl.
Number of sacks
Number of sacks=Volume of slurrySlurry yield
=43691.14=3832
sacks
Volume of mixed water
Volume of mixed water=number of sacks ×4.96galsack
=3832×4.96 gal=19006.7 gal
Amount of additives
Retarder=0.2100×3832×94lbsack=720 lb
Retarder=1100×3832×94lbsack=3602.08 lb
Number of strokes
Number of strokes= Displacement volume0.138
=755.440.138=5474 strokes
958
inch Intermediate casing
Slurry volume
Slurry Volume bbl=12.252–9.62521029.4×11,195=624.5 bbl
Add 20% excess in open hole
Slurry volume=1.2×624.5=749.4 bbl
=749.4×5.6146=4207.58 ft3
Displacement Volume
Displacement Volume bbl=dID21029.4×depth of float collar ft
=8.53521029.4×11,195–70ft
=787.27 bbl
Add 2 bbl as a factor to be very certain, Therefore, Displacement volume is 789.27 bbl.
Number of sacks
Number of sacks=Volume of slurrySlurry yield
=4207.581.14=3691
sacks
Volume of mixed water
Volume of mixed water=number of sacks ×4.96galsack
=3691×4.96 gal=18,307.36 gal
Amount of additives
Retarder=0.2100×3691×94lbsack=693.9 lb
Retarder=1100×3691×94lbsack=3469.5 lb
Number of strokes
Number of strokes= Displacement volume0.138
=789.270.138=5719 strokes
Appendix IV: Table of Mud weight required to maintain primary well control
Depth (ft)
Pore Pressure Gr (psi/ft)
Mud Weight (ppg)
Fracture Pressure Gradient (ppg)
0
0.447
8.6
12.52
436
0.447
8.6
12.52
718
0.447
8.6
12.52
1722
0.447
8.6
12.52
2110
0.447
8.6
12.52
2145
0.447
8.6
12.52
2893
0.447
8.6
12.52
4205
0.447
8.6
12.52
4900
0.447
8.6
12.52
5241
0.447
8.6
14.94
5291
0.447
8.6
14.94
5412
0.447
8.6
14.94
5576
0.464
8.9
14.94
5904
0.490
9.4
14.94
6232
0.520
10.0
14.94
6560
0.538
10.3
14.94
6888
0.551
10.6
14.94
7084.8
0.555
10.7
14.94
7216
0.559
10.8
14.94
7544
0.564
10.8
14.94
7872
0.568
10.9
14.94
8069
0.568
10.9
14.94
8561
0.568
10.9
14.94
9381
0.568
10.9
14.94
9545
0.568
10.9
14.94
9906
0.555
10.7
14.94
10070
0.546
10.5
14.94
10237
0.542
10.4
14.94
10562
0.538
10.3
14.94
10988
0.542
10.4
14.69
11195
0.542
10.4
14.69
11349
0.538
10.3
14.69
12103
0.538
10.3
12.52
Appendix V: Authority of Expenditure for planned well (estimated costs)
Dry Hole COST (USD)
Completion COST (USD)
TOTAL (USD)
INTANGIBLE COSTS
Surveys and location clean up
200,000
–
200,000
Drilling Cost
11,600,000
–
11,600,000
Transportation (helicopter + Boats)
3,000,000
500,000
3,500,000
Rig Cost
13,920,000
–
13,920,000
Consultant cost
250,000
250,000
500,000
Equipment Renting
552,000
250,000
802,000
Drilling Bits
726,000
–
726,000
Casing crew
200,000
200,000
400,000
Drilling fluids & mud services
400,000
250,000
650,000
Cement & cementing services
540,000
400,000
940,000
Completion rig cost
–
600,000
600,000
Insurance
100,000
100,000
200,000
Testing tools & Services
260,000
–
260,000
Drill-pipe cost
850,000
–
850,000
General labour charges and supervision
1,000,000
500,000
1,500,000
SUB TOTAL
33,598,000
3,050,000
36,648,000
CONTINGENCIES (15%)
5,039,700
457,500
5,497,200
TOTAL INTANGIBLE COSTS
38,637,700
3,507,500
42,145,200
TANGIBLE COSTS
Casings (conductor, surface, intermediate)
600,000
–
600,000
Casing equipment & service
280,000
–
280,000
WELL HEAD & EQUIPMENT
3,000,000
–
3,000,000
Christmas tree
2,000,000
–
2,000,000
BOP cost & Equipment
3,000,000
3,000,000
Completion equipment
–
1,200,000
1,200,000
SUB TOTAL
8,880,000
1,200,000
10,080,000
CONTINGENCIES (15%)
1,332,000.00
180,000.00
1,512,000.00
TOTAL TANGIBLE COSTS
10,212,000.00
1,380,000.00
11,592,000.00
TOTAL COST
48,849,700.00
4,887,500.00
53,737,200.00
NOTE: Source of some equipment’s price retrieved from https://www.alibaba.com/trade/search?fsb=y&IndexArea=product_en&CatId=131008&SearchText=casing+pipes
