Project to Drill Exploration Well

16701 words (67 pages) Essay

18th May 2020 Geography Reference this

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1.0 DEFINING WELL OBJECTIVES

1.1 Objectives

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.

2.0 OBTAINING CONSENT TO DRILL FROM THE AUTHORITIES

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: –

  1. Applying drilling consent to drill to NEA. This agency will approve application after critically evaluation of the environmental impact assessment.
  2. Then, followed by the application of the consent from PSA.
  3. Finally, application of drilling permit from NPD by filling the registration form of wells and wellbores (NPD 2019).
  4. 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.

3.0 ESTABLISHMENT OF SUBSURFACE PRESSURE REGIMES

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

4.0 Establishment of formation fracture gradients

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

5.0 Casing design and selecting the casing seats

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.

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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

6.0 Wellhead

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)

7.0 BOP requirements

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)

8.0 CEMENTING PROGRAM

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)

9.0 MUD PROGRAM

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

10.0 Bit programme

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)

11.0 Evaluation requirements

The following requirements necessary to meet the well objectives will be evaluated: –

  1. 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.

  1.    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.

  1. 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.

  1. 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.

12.0 Operational procedures and time depth graph construction

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

13.0 Authorization for expenditure

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.

REFERENCES

  • 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

ODID=2t.equation 3

 

Casing Collapse Pressure

Pcr=2σyielddnt1dnt2

Where:

Pcr

= Collapse pressure (psi)

σyield

= yield strength (psi)

t = nominal wall thickness (in)

dn

= nominal outside diameter (in)

Casing Axial loads

Ften=π4σyielddno2dni2

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: –

  1. Slurry density is 15.9 ppg
  2. Yield per sack is 1.14 ft3 per sack
  3. Water mixed per sack is 4.96 gal/sack
  4. Type G cement composed of D13R (retarder) of 0.2% and friction reducer (D65) of 1%
  5. The collar and Rathole distance are 60ft and 10 ft respectively
  6. 20% excess shall be considered in open hole.
  7. Volume per stroke is 0.138 bbl

30

inch conductor casing

  1. Slurry volume

Slurry Volume bbl=dhole2dcasing21029.4×depth of the casing (ft)

Slurry Volume bbl=3623021029.4×710=273.13 bbl

Add 20% excess in open hole

Slurry volume=1.2×273.13=327.76 bbl 

                                  =327.76×5.6146=1840 ft3

  1. Displacement Volume

Displacement Volume bbl=dID21029.4×depth of float collar ft

=2821029.4×71070ft=487.43 bbl

Add 2 bbl as a factor to be very certain, Therefore, Displacement volume is 489.43 bbl.

  1. Number of sacks

Number of sacks=Volume of slurrySlurry yield

                                                                                       =18401.14=1614

sacks

  1. Volume of mixed water

Volume of mixed water=number of sacks ×4.96galsack

                                                 =1614×4.96 gal=8005.4 gal

  1. Amount of additives

Retarder=0.2100×1614×94lbsack=303.43 lb

Retarder=1100×1614×94lbsack=1517.16 lb

  1. Number of strokes

Number of strokes= Displacement volume0.138

                                                                             =489.430.138=3546 strokes

20

inch surface casing

  1. Slurry volume

Slurry Volume bbl=dhole2dcasing21029.4×depth of the casing (ft)

Slurry Volume bbl=2622021029.4×2100=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

  1. Displacement Volume

Displacement Volume bbl=dID21029.4×depth of float collar ft

=18.72821029.4×210070ft

=691.7 bbl 

Add 2 bbl as a factor to be very certain, Therefore, Displacement volume is 693.7 bbl.

  1. Number of sacks

Number of sacks=Volume of slurrySlurry yield

                                                                                      =3793.561.14=3328 

sacks

  1. Volume of mixed water

Volume of mixed water=number of sacks ×4.96galsack

                                                                 =3328×4.96 gal=16,506.88 gal

  1. Amount of additives

Retarder=0.2100×3328×94lbsack=625.66 lb

Retarder=1100×3328×94lbsack=3128.32 lb

  1. Number of strokes

Number of strokes= Displacement volume0.138

                                                                             =693.70.138=5027 strokes

1338

inch intermediate casing

  1. Slurry volume

Slurry Volume bbl=dhole2dcasing21029.4×depth of the casing (ft)

Slurry Volume bbl=17.5213.37521029.4×5241=648.43 bbl

Add 20% excess in open hole

Slurry volume=1.2×648.43=778.12 bbl 

                                  =778.12×5.6146=4369 ft3

  1. Displacement Volume

Displacement Volume bbl=dID21029.4×depth of float collar ft

                                    =12.24721029.4×524170ft

            =753.44 bbl 

Add 2 bbl as a factor to be very certain, Therefore, Displacement volume is 755.44 bbl.

  1. Number of sacks

Number of sacks=Volume of slurrySlurry yield

                                                                                        =43691.14=3832

sacks

  1. Volume of mixed water

Volume of mixed water=number of sacks ×4.96galsack

                                                    =3832×4.96 gal=19006.7 gal

  1. Amount of additives

Retarder=0.2100×3832×94lbsack=720 lb

Retarder=1100×3832×94lbsack=3602.08 lb

  1. Number of strokes

Number of strokes= Displacement volume0.138

                                                                            =755.440.138=5474 strokes

958

inch Intermediate casing

  1. Slurry volume

Slurry Volume bbl=12.2529.62521029.4×11,195=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

  1. Displacement Volume

Displacement Volume bbl=dID21029.4×depth of float collar ft

                                     =8.53521029.4×11,19570ft

          =787.27 bbl 

Add 2 bbl as a factor to be very certain, Therefore, Displacement volume is 789.27 bbl.

  1. Number of sacks

Number of sacks=Volume of slurrySlurry yield

                                                                                        =4207.581.14=3691

sacks

  1. Volume of mixed water

Volume of mixed water=number of sacks ×4.96galsack

                                                       =3691×4.96 gal=18,307.36 gal

  1. Amount of additives

Retarder=0.2100×3691×94lbsack=693.9 lb

Retarder=1100×3691×94lbsack=3469.5 lb

  1. 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

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