Project to Drill Exploration Well

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) = $\frac{\mathrm{Pore\; Pressure }\left(\mathrm{psi}\right)}{\mathrm{TVD }\left(\mathrm{ft}\right)}$

……………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, $13\frac{3}{5}$

  inch and $9\frac{5}{8}$

  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

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
$17\frac{1}{2}$	nil	nil
$12\frac{1}{4}$	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
	$17\frac{1}{2}$	13.375	5,241
	$12\frac{1}{4}$	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
$17\frac{1}{2}$	13.375	5,241	778.12	755.44	3832	19006.7
$12\frac{1}{4}$	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
	$17\frac{1}{2}$	13.375	5,241	10.9
	$12\frac{1}{4}$	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.

2.    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.

3. 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.

4. 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> [20^th 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

${\mathit{P}}_{\mathit{B}}\mathit{=}\mathit{0}\mathit{.}\mathit{875}\frac{\mathit{2}{\mathit{Y}}_{\mathit{p}}\mathit{t}}{\mathit{OD}}\dots \dots \dots ..\mathrm{equation }2\mathrm{ }$

Where:

P_B = burst pressure (psi)

Y_P = Specified minimum yield strength (psi)

t = nominal wall thickness (in)

OD = nominal outside diameter (in)

Moreover, internal diameter was computed through

$\mathit{OD}–\mathit{ID}=2t\dots \dots \dots \dots \dots .\mathit{equation }3$

 

Casing Collapse Pressure

$P_{\mathit{cr}}=2{\sigma }_{\mathit{yield}}\left[\frac{\frac{d_n}{t}–1}{{\left(\frac{d_n}{t}\right)}^2}\right]$

Where:

$P_{\mathit{cr}}$

= Collapse pressure (psi)

${\sigma }_{\mathit{yield}}$

= yield strength (psi)

t = nominal wall thickness (in)

$d_n$

= nominal outside diameter (in)

Casing Axial loads

$F_{\mathit{ten}}=\frac{\pi }{4}{\sigma }_{\mathit{yield}}\left(d_{\mathit{no}}^2–d_{\mathit{ni}}^2\right)$

Where;

$F_{\mathit{ten}}$

= pipe-body tensile strength (lbf)

${\sigma }_{\mathit{yield}}$

=minimum yield strength (psi)

$d_{\mathit{no}}$

= nominal OD of pipe, in

$d_{\mathit{ni}}$

= 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

$\mathit{30}$

inch conductor casing

1. Slurry volume

$\mathit{Slurry\; Volume }\left(\mathit{bbl}\right)=\frac{d_{\mathit{hole}}^2–d_{\mathit{casing}}^2}{1029.4}\times \mathit{depth\; of\; the\; casing }\left(\mathit{ft}\right)$

$\mathit{Slurry\; Volume }\left(\mathit{bbl}\right)=\frac{{36}^2–{30}^2}{1029.4}\times 710=273.13\mathit{ bbl}$

Add 20% excess in open hole

$\mathit{Slurry\; volume}=1.2\times 273.13=327.76\mathit{ bbl }$

$\mathit{ }=327.76\times 5.6146=1840 {\mathit{ft}}^3$

2. Displacement Volume

$\mathit{Displacement\; Volume }\left(\mathit{bbl}\right)=\frac{d_{\mathit{ID}}^2}{1029.4}\times \mathit{depth\; of\; float\; collar }\left(\mathit{ft}\right)$

$=\frac{{28}^2}{1029.4}\times \left(710–70\right)\mathit{ft}=487.43\mathit{ bbl}$

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

3. Number of sacks

$\mathit{Number\; of\; sacks}=\frac{\mathit{Volume\; of\; slurry}}{\mathit{Slurry\; yield}}$

$\mathit{ }=\frac{1840}{1.14}=1614$

sacks

4. Volume of mixed water

$\mathit{Volume\; of\; mixed\; water}=\mathit{number\; of\; sacks }\times 4.96\frac{\mathit{gal}}{\mathit{sack}}$

$\mathit{ }=1614\times 4.96\mathit{ gal}=8005.4\mathit{ gal}$

5. Amount of additives

$\mathit{Retarder}=\left(\frac{0.2}{100}\right)\times 1614\times 94\frac{\mathit{lb}}{\mathit{sack}}=303.43\mathit{ lb}$

$\mathit{Retarder}=\left(\frac{1}{100}\right)\times 1614\times 94\frac{\mathit{lb}}{\mathit{sack}}=1517.16\mathit{ lb}$

6. Number of strokes

$\mathit{Number\; of\; strokes}= \frac{\mathit{Displacement\; volume}}{0.138}$

$\mathit{ }=\frac{489.43}{0.138}=3546\mathit{ strokes}$

$\mathit{20}$

inch surface casing

1. Slurry volume

$\mathit{Slurry\; Volume }\left(\mathit{bbl}\right)=\frac{d_{\mathit{hole}}^2–d_{\mathit{casing}}^2}{1029.4}\times \mathit{depth\; of\; the\; casing }\left(\mathit{ft}\right)$

$\mathit{Slurry\; Volume }\left(\mathit{bbl}\right)=\frac{{26}^2–{20}^2}{1029.4}\times 2100=563.05\mathit{ bbl}$

Add 20% excess in open hole

$\mathit{Slurry\; volume}=1.2\times 563.05=675.66\mathit{ bbl }$

$\mathit{ }=675.66\times 5.6146=3793.56 {\mathit{ft}}^3$

2. Displacement Volume

$\mathit{Displacement\; Volume }\left(\mathit{bbl}\right)=\frac{d_{\mathit{ID}}^2}{1029.4}\times \mathit{depth\; of\; float\; collar }\left(\mathit{ft}\right)$

$=\frac{{18.728}^2}{1029.4}\times \left(2100–70\right)\mathit{ft}$

$=691.7\mathit{ bbl }$

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

3. Number of sacks

$\mathit{Number\; of\; sacks}=\frac{\mathit{Volume\; of\; slurry}}{\mathit{Slurry\; yield}}$

$\mathit{ }=\frac{3793.56}{1.14}=3328$

sacks

4. Volume of mixed water

$\mathit{Volume\; of\; mixed\; water}=\mathit{number\; of\; sacks }\times 4.96\frac{\mathit{gal}}{\mathit{sack}}$

$\mathit{ }=3328\times 4.96\mathit{ gal}=16,506.88\mathit{ gal}$

5. Amount of additives

$\mathit{Retarder}=\left(\frac{0.2}{100}\right)\times 3328\times 94\frac{\mathit{lb}}{\mathit{sack}}=625.66\mathit{ lb}$

$\mathit{Retarder}=\left(\frac{1}{100}\right)\times 3328\times 94\frac{\mathit{lb}}{\mathit{sack}}=3128.32\mathit{ lb}$

6. Number of strokes

$\mathit{Number\; of\; strokes}= \frac{\mathit{Displacement\; volume}}{0.138}$

$\mathit{ }=\frac{693.7}{0.138}=5027\mathit{ strokes}$

$\mathbf{13}\frac{\mathbf{3}}{\mathbf{8}}$

inch intermediate casing

1. Slurry volume

$\mathit{Slurry\; Volume }\left(\mathit{bbl}\right)=\frac{d_{\mathit{hole}}^2–d_{\mathit{casing}}^2}{1029.4}\times \mathit{depth\; of\; the\; casing }\left(\mathit{ft}\right)$

$\mathit{Slurry\; Volume }\left(\mathit{bbl}\right)=\frac{{17.5}^2–{13.375}^2}{1029.4}\times 5241=648.43\mathit{ bbl}$

Add 20% excess in open hole

$\mathit{Slurry\; volume}=1.2\times 648.43=778.12\mathit{ bbl }$

$\mathit{ }=778.12\times 5.6146=4369 {\mathit{ft}}^3$

2. Displacement Volume

$\mathit{Displacement\; Volume }\left(\mathit{bbl}\right)=\frac{d_{\mathit{ID}}^2}{1029.4}\times \mathit{depth\; of\; float\; collar }\left(\mathit{ft}\right)$

$\mathit{ }=\frac{{12.247}^2}{1029.4}\times \left(5241–70\right)\mathit{ft}$

$\mathit{ }=753.44\mathit{ bbl }$

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

3. Number of sacks

$\mathit{Number\; of\; sacks}=\frac{\mathit{Volume\; of\; slurry}}{\mathit{Slurry\; yield}}$

$\mathit{ }=\frac{4369}{1.14}=3832$

sacks

4. Volume of mixed water

$\mathit{Volume\; of\; mixed\; water}=\mathit{number\; of\; sacks }\times 4.96\frac{\mathit{gal}}{\mathit{sack}}$

$\mathit{ }=3832\times 4.96\mathit{ gal}=19006.7\mathit{ gal}$

5. Amount of additives

$\mathit{Retarder}=\left(\frac{0.2}{100}\right)\times 3832\times 94\frac{\mathit{lb}}{\mathit{sack}}=720\mathit{ lb}$

$\mathit{Retarder}=\left(\frac{1}{100}\right)\times 3832\times 94\frac{\mathit{lb}}{\mathit{sack}}=3602.08\mathit{ lb}$

6. Number of strokes

$\mathit{Number\; of\; strokes}= \frac{\mathit{Displacement\; volume}}{0.138}$

$\mathit{ }=\frac{755.44}{0.138}=5474\mathit{ strokes}$

$\mathbf{9}\frac{\mathit{5}}{\mathbf{8}}$

inch Intermediate casing

1. Slurry volume

$\mathit{Slurry\; Volume }\left(\mathit{bbl}\right)=\frac{{12.25}^2–{9.625}^2}{1029.4}\times 11,195=624.5\mathit{ bbl}$

Add 20% excess in open hole

$\mathit{Slurry\; volume}=1.2\times 624.5=749.4\mathit{ bbl }$

$\mathit{ }=749.4\times 5.6146=4207.58 {\mathit{ft}}^3$

2. Displacement Volume

$\mathit{Displacement\; Volume }\left(\mathit{bbl}\right)=\frac{d_{\mathit{ID}}^2}{1029.4}\times \mathit{depth\; of\; float\; collar }\left(\mathit{ft}\right)$

$\mathit{ }=\frac{{8.535}^2}{1029.4}\times \left(11,195–70\right)\mathit{ft}$

$\mathit{ }=787.27\mathit{ bbl }$

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

3. Number of sacks

$\mathit{Number\; of\; sacks}=\frac{\mathit{Volume\; of\; slurry}}{\mathit{Slurry\; yield}}$

$\mathit{ }=\frac{4207.58}{1.14}=3691$

sacks

4. Volume of mixed water

$\mathit{Volume\; of\; mixed\; water}=\mathit{number\; of\; sacks }\times 4.96\frac{\mathit{gal}}{\mathit{sack}}$

$\mathit{ }=3691\times 4.96\mathit{ gal}=18,307.36\mathit{ gal}$

5. Amount of additives

$\mathit{Retarder}=\left(\frac{0.2}{100}\right)\times 3691\times 94\frac{\mathit{lb}}{\mathit{sack}}=693.9\mathit{ lb}$

$\mathit{Retarder}=\left(\frac{1}{100}\right)\times 3691\times 94\frac{\mathit{lb}}{\mathit{sack}}=3469.5\mathit{ lb}$

6. Number of strokes

$\mathit{Number\; of\; strokes}= \frac{\mathit{Displacement\; volume}}{0.138}$

$\mathit{ }=\frac{789.27}{0.138}=5719\mathit{ strokes}$

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