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# Project to Drill Exploration Well

Info: 16729 words (67 pages) Essay
Published: 18th May 2020

## 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;

……………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).

## 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.

## 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

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.

## 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

## 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
 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.

## 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.

## 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.

## 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

Burst pressure, collapse pressure and axial load of the casing were calculated using the following formula (Bourgoyne et al. 1985).

Casing Burst Pressure

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

Casing Collapse Pressure

Where:

${P}_{\mathit{cr}}$

= Collapse pressure (psi)

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

= yield strength (psi)

t = nominal wall thickness (in)

${d}_{n}$

= nominal outside diameter (in)

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

$\mathbit{30}$

inch conductor casing

1. Slurry volume

Add 20% excess in open hole

1. Displacement Volume

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

1. Number of sacks

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

sacks

1. Volume of mixed water

1. Number of strokes

$\mathbit{20}$

inch surface casing

1. Slurry volume

Add 20% excess in open hole

1. Displacement Volume

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

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

1. Number of sacks

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

sacks

1. Volume of mixed water

1. Number of strokes

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

inch intermediate casing

1. Slurry volume

Add 20% excess in open hole

1. Displacement Volume

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

1. Number of sacks

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

sacks

1. Volume of mixed water

1. Number of strokes

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

inch Intermediate casing

1. Slurry volume

Add 20% excess in open hole

1. Displacement Volume

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

1. Number of sacks

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

sacks

1. Volume of mixed water

1. Number of 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

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