1. Summary

The output from this analysis will become the basis of the functional specifications for a Drill String ITT.

The drill string analysis focused on the three most critical sections as follows:

• the 12 ¼” section drilled vertically from 1900m to about 4550m MDBRT;
• the 8 ½” section drilled directionally from 4550m to 5140m MDBRT, with a Kick-off point at 4830m MD/RT in order to get a 8°/30m Dog-Leg Severity;
• the 5 7/8” (or 6”) section drilled as a tangent section from 5140m to 5740m MDBRT at 79° Inclination.

The main objectives of this study are:

• to identify the main factors, which influence the drilling parameters;
• to compare the DP configurations and their responses for each “theoretical” scenario;
• to highlight the best DP configuration able to withstand all scenarios.

• Analysis Summary

Case 1: 5” DP

Basic hydraulics calculations were performed for 5” DP and 5 ½” DP in order to select the optimum DP size.

Case 2: 5 ½” DP – Grade G – 21.9 ppf – FH – No Tortuosity Model – 12 ¼” Rotary BHA

Evaluate the Grade G Torque & Drag safety margin evolution with the drilling operations duration. Calculations run for Class 1 & Class 2 DP. Results analysis conducts to Grade S selection.

Case 3: 5 ½” DP – Grade S – 21.9 ppf – FH – Tortuosity Model – 12 ¼” Rotary BHA

Feasibility Study based on Torque & Drag Analysis for the 12 ¼” phase with tortuosity model introduced into the well profile.

Case 4: 6 5/8” DP – Grade S – 25.2 ppf – Tortuosity Model – 12 ¼” Rotary BHA

Evaluate the benefits of the 6 5/8” DP over the 5 ½” DP based on Torque & Drag and Hydraulics calculations. The well requirements are exceeded by this configuration.

Case 5: 5 ½” DP – Grade S – 21.9 ppf – Tortuosity Model – 8 ½” Steerable BHA

Feasibility study based on Torque & Drag Analysis for the 8 ½” directional phase with a 8°/30m DLS.

Case 6: 5 ½” DP – 21.9 ppf vs. 5 ½” DP – 24.7 ppf for 8 ½” Section

Evaluate the benefits of the 5 ½” DP – 21.9 ppf over the 5 ½” DP – 24.7 ppf based on Torque & Drag and Hydraulics calculations.

Results analysis conducts to Weight Selection. Slight enhancement brought by 24.7 ppf DP in the mechanical responses. Insignificant increase of the internal DP pressure loss does not constitute an issue.

Case 7: 5 ½” DP – 24.7 ppf vs. 5 7/8” DP – 23.4 ppf

Evaluate the benefits of the 5 ½” DP over the 5 7/8” DP based on Torque & Drag and Hydraulics calculations in the base case scenario.

No enhancement brought by 5 7/8” DP in the mechanical responses. Significant Hydraulics improvement is brought with reduced surface stand-pipe pressures for determined flow rates.

Case 8: 3 ½” DP – 13.3 ppf – NC38 x 5 ½” DP – 24.7 ppf – FH for 5 7/8” Section

Feasibility study conducted for a tapered string. No issue raised.

Case 9: 4” DP – 14 ppf – NC40 x 5 ½” DP – 24.7 ppf – FH for 6” Section

Feasibility study conducted for a tapered string. Benefits bought regarding both Mechanical and Hydraulics responses.

Case 10: 4” DP vs. 3 ½” DP for UBD – Casing Injection Purposes    

Feasibility study and benefits evaluation between both 3 ½” & 4” full strings in case of implementation of the casing injection technology for UBD purposes. In this scenario, the 7” liner would be tied back to surface with a slotted liner allowing the nitrogen injection into the 9 5/8” x 7” annulus. For this purpose, a full 7” casing (6” ID) string was designed. The use of a tapered string is no longer allowed due to the upper DP tool joint OD exceeding the 7” liner ID. In this configuration, 4” DP is mandatory based on mechanical and hydraulics benefits and also on severe hydraulics limitations of the 3 ½” DP in this scenario.

Case 11: Fatigue Calculations in case of shallow side-track

Sensitivity calculation in case of near-surface side-track in the Triassic shales. Focus on the fatigue ratio, less dramatic for 5 7/8” DP than for 5 ½” DP.

• Conclusions

From the results of the analyses and other technical issues raised in this study, we have concluded the following:

• Using 5000 psi surface equipment, the minimum DP specification is 5 ½” OD to reduce internal pressure loss and gain flexibility in the hydraulics for 12 ¼” and 8 ½” sections.
• Due to the fatigue caused by both harsh drilling conditions and extreme temperature variations, S-Grade DP will provide a greater safety margin and should help to prevent any unpredictable failure in case of premature wear.
• No special recommendations regarding the Tool Joint and Connection for the 5 ½” DP. A FH connection is suitable.
• 6-5/8” DP was found to be within spec but not fit-for-purpose for a variety of operational reasons, including; rig equipment modifications, additional critical path time to handle and lay-out at the end of the 12 ¼” hole section, anticipated greater rental and repair costs.
• 5 7/8” DP – Grade S bring some potential improvement only for the hydraulics aspects of the 12 ¼” section. Their mechanical operating properties remain similar to the 5 ½” DP.
• A near-surface sidetrack will generates significant fatigue wear on the DP. The 5 7/8” DP is less sensitive to this fatigue than 5 ½” DP
• 5 7/8” DP should be specified with Grant Prideco XT57 connections. This connection is mechanically overrated for Phase 3 applications but the larger ID will slightly reduce pressure drop, surface pressure requirements, and offer hydraulics flexibility without needing to upgrade the mud pumps and rig surface equipment requirements to a 7500 psi system
• The 3 ½” DP is able to support the Object 3 reservoir drilling. However the clearance in a 5 7/8” hole is not sufficient enough to run a full strength overshot e.g Bowen Series 150 overshot.
• As for the 5 7/8” DP for the upper hole sections, the main benefit of the 4” DP is the pressure loss reduction offering larger working range to optimise hydraulics performance.
• 4” DP will become mandatory in the event that UBD with either N2 injection thru 7” tie-back casing or alternatively through DP due to higher velocity at surface due to the gas volume.
• 4” DP will require the drilling of the reservoir in a 6” size to permit the running of a full strength overshot.

Recommendations

Based on the above conclusions, planned well architecture and range of operating parameters, the following DP specifications are recommended:

Section	Ranking	DP
12 ¼” & 8 ½”	1	5 7/8” OD – Grade S135 – 23.4 ppf with XT57 Tool Joint
	2	5 ½” OD – Grade S135 – 24.7 ppf with FH Tool Joint
5 7/8” or 6”	1	4” OD – Grade S135 – 14.0 ppf with XT39 x 4 7/8” OD Tool Joint
	2	3 ½” OD – Grade 135 – 13.6 ppf – NC38 Tool Joint

 

Comment: Using Grade S DP in a Sour Gas environment

Fatigue cracks are a common occurrence when drilling in a corrosive environment. Most of these failures result from stress corrosion cracking when drilling stresses are excessive and corrosion is not controlled adequately. The corrosion is caused by the acid generated by the sour gas dissolved in the water phase of the mud system. This effect is more drastic for the Grade S DP than the Grade G DP due to the material properties. Because H2S is not miscible with an oil based mud and as the water phase concentration is low (20-40%) and non-continuous, OBM provides a simple mitigation to this corrosion problem. Steel will not corrode when the metal is oil-wet.

In the case of WBM systems, drilling procedures must be implemented to reduce the potential for fatigue cracking to occur. A tapered BHA design should be used with a tapered transition section. A WBM treated to maintain its pH above 10.5 will help reduce stress corrosion fatigue cracking. Adherence to good, established drilling practices also helps minimize the problem. Besides treating the drilling fluid, all possible steps should be taken to keep oxygen out of the drilling fluid system.

The upper hole sections DP (5”, 5 ½”, 5 7/8” or 6 5/8”), as the 3 ½’ or 4” section DP, will be also affected by this corrosion effect due to the tapered string configuration while drilling the H2S/CO2 bearing formations. Prior to implementing these recommendations regarding the mud system (LTOBM or pH-controlled WBM), consult with Town concerning potential for DP corrosion and results of corrosion monitoring for DP currently in use.

2.       Introduction

The aim of this report is to present the results of a mechanical and hydraulic Drill String Analysis. The methodology used was to establish a base case and then carry out sensitivity analyses. The fit-for-purpose WellPlan software was used, but it has been found to have some limitations and an update of the database is required to be able to extend the analysis to all currently available drill string specifications.

The output from this analysis will form the basis of the functional specifications for a Drill String ITT.

The drill string analysis focused on the two most critical sections as follow:

• the 12 ¼” section drilled vertically from 1900m to about 4550m MDBRT
• the 8 ½” section drilled directionally from 4550m to 5140m MDBRT, with a Kick-off point at 4830m MD/RT in order to get a 8°/30m Dog-Leg Severity
• the 5 7/8” (or 6”) section drilled slant from 5140m to 5740m MDBRT at 79° Inclination

The main objectives of this study are:

• to identify the main factors, which influence the drilling parameters
• to compare the DP configurations and their responses for each “theoretical” scenario
• to highlight the best DP configuration able to withstand all scenarios

The study consists of 7 steps:

• step 1: collation of input data
• step 2: size determination between 5”, 5 ½” and 6 5/8” DP.
• step 3: grade determination between G and S: an analysis for Class 1 and Class 2 DP was conducted in order to simulate the DP life cycle
• step 4: size determination between 3 ½” and 4” DP for the sub-horizontal reservoir section
• step 5: comparison between 5 ½” DP and 5 7/8” DP
• step 6: sensitivity analysis
• step 7: conclusions, discussion and recommendations

Remark 1:

All output values presented in this report must be used with caution, because they reflect the theoretical response of the drill string only. Indeed, for accurate predictions, it is necessary to back-calculate the different parameters (friction factor, mud rheology, etc) from Phase 2M wells data. Furthermore, the drilling and tripping parameters as WOB, overpull, exceed significantly the ones applied in Phase 2M drilling campaign (in well 9806, WOB at 10-15 klbs for 12 ¼” and 8 ½’ sections, max 30-50 klbs overpull while backreaming).

Remark 2:

Some studies were conducted for both Class 1 and Class 2 DP in order to evaluate their responses and their performance over an extended period.

3.       Study Cases Recap

	Phase	DP	Tortuosity Model	Objectives
Case 1	12 ¼”	5”	No	OD determination
Case 2	12 ¼”	5 ½” – Grade G – 21.9 ppf		Grade Determination
Case 3	12 ¼”	5 ½” – Grade S – 21.9 ppf	Yes	Screening Analysis
Case 4	12 ¼”	6 5/8” – Grade S – 25.2 ppf
Case 5	8 ½”	5 ½” – Grade S – 21.9 ppf
Case 6	8 ½”	5 ½” – Grade S – 24.7 ppf
Case 7	12 ¼” – 8 ½”	5 7/8” – Grade S – 23.4 ppf		5 7/8” DP Benefits Evaluation
Case 8	5 7/8”	3 ½” – Grade S – 13.3 ppf		Comparative Analysis
Case 9	6”	4” – Grade S – 14 ppf
Case 10	5 7/8” – 6” UBD	3 ½” vs. 4”		OD Determination
Case 11	12 ¼”	5 ½” vs. 5 7/8”		Fatigue sensitivity analysis in case of near-surface sidetrack

4.       Basis of Study

• Hole Section Editor

12 ¼” Hole Section

Section Type	Depth (m MDBRT)	Length (m)	ID (in)	Drift (in)	Effective Hole Diameter (in)	Friction Factor	Excess	Item Description
Casing	1900	1900	12.415	12.259	12.415	0.25	0	13 3/8” – 68 ppf – T95
Open Hole	4535	2635	12 ¼	N/A	12 ¼	0.30	0	N/A

8 ½” Hole Section

Section Type	Depth (m MDBRT)	Length (m)	ID (in)	Drift (in)	Effective Hole Diameter (in)	Friction Factor	Excess	Item Description
Casing	4535	4535	8 ½	8 ½	8 ½	0.25	0	9 5/8” – 53.5 ppf – P110 – Special Drift
Open Hole	5140	605	8 ½	N/A	8 ½	0.30	0	N/A

 

The production casing string was designed as a full 9 5/8” string, instead of a 10 ¾” x 9 5/8” x 10 ¾” tapered string. As the ID of the 10 ¾” casings to be used in this tapered string is larger than the ID of the 9 5/8” casing, the calculations performed with this configuration was more rigorous in terms of torque and drag. On the other hand, the hydraulics could not be dramatically modified, the pressure loss in the annulus being considered as negligible (the annulus pressure loss being evaluated at 100 psi for 6 ¾” DC and 5” DP inside 9-5/8” casing).

5 7/8” or 6” Hole Section

Section Type	Depth (m MDBRT)	Length (m)	ID (in)	Drift (in)	Effective Hole Diameter (in)	Friction Factor	Excess	Item Description
Casing	4435	4435	8 ½	8 ½	8 ½	0.25	0	9 5/8” – 53.5 ppf – P110 – Special Drift
Casing	5140	705	5 7/8 or 6	6	6	0.25	0	7” Liner – 32 ppf – T95 (Special drift for 6” hole)
Open Hole	5745	605	5 7/8 or 6”	N/A	6”	0.30	0	N/A

 

The friction factors for both casing and open hole are intentionally conservative to evaluate the worst case scenario. A more accurate method, not performed here, requires back-calculation from drilling data gathered from the current Phase 2M (drilling sheets with regular Torque & Drag input). The adjustments of this friction factor should allow a fine tuning in the Torque & Drag prediction and facilitate optimisation of the well design.

For both sections, the formation wash-out is considered as nil (0% of excess) to worsen the Torque & Drag scenario. The annulus pressure loss is negligible compared to that for the Drill String, so no significant surface DP pressure increase is to be expected.

A change in the planned hole size in Object 3 wells from 5 7/8” to 6” is recognized as fundamental as mentioned in the section 5.8 – 3 ½” DP selection but will not negatively impact the planned well design or drilling and completion operations.

• String Editor

The Drill Collars ID had their ID manually modified from 2” to 3 ¼” due to the restricted WellPlan database which contains only 2” ID Drill Collars. With the Tool-Joint Pressure loss option, all the hydraulics calculations indicate a surface Drill String pressure exceeding the Stand Pipe & Mud pumps rated working pressure, set by default at 4500 psi for both of them. This concern was raised in paragraph 5.1 below.

12 ¼” Hole Section

A Rotary Packed Hole BHA with one Full Gauge Near-Bit Stabilizer + two Full Gauge Stabilizers present the worst case scenario in term of Torque & Drag analysis.

Description	Number	Length (m)	OD	ID
5 ½” DP	To surface	4257	5 ½	4.778”
5 ½” HWDP – 58.10 ppf -	15	136.5	5 ½”	3 ¼”
8” Drill Collar	2	18.2	8”	3 ¼”
Hydraulic Jar	1	9.1	8”	3 ¼”
8” Drill Collar	9	81.9	8”	3 ¼”
12 ¼” x 8” Stabilizer	1	1.5	8” x 12 ¼”	3 ¼”
8” Drill Collar	2	18.2	8”	3 ¼”
12 ¼” x 8” Stabilizer	1	1.5	8” x 12 ¼”	3 ¼”
8” Drill Collar	1	9.1	8”	3 ¼”
12 ¼” x 8” Near-Bit Stabilizer	1	1.5	8” x 12 ¼”	3 ¼”
12 ¼” Bit	1	0.5	12 ¼”

 

8 ½” Hole Section

Description	Number	Length (m)	OD	ID
5 ½” DP	To surface	4257	5 ½	4.778”
5 ½” HWDP – 58.10 ppf -	15	136.5	5 ½”	3 ¼”
6 ¾” Drill Collar	2	18.2	6 ¾”	3”
Hydraulic Jar	1	9.1	6 ¼”	2 ¼”
6 ¾” Drill Collar	9	81.9	6 ¾”	3”
8 ½” x 6 ¼” Stabilizer	1	1.5	8 ½” x 6 ¼”	2 813”
6 ¾” Drill Collar	1	9.1	6 ¾”	3”
6 ¾” Triple Combo LWD	1	14.5	6 ¾”	1.92”
8 ½” x 6 ¼” Stabilizer	1	1.5	8 ½” x 6 ¼”	2 813”
6 ¾” PDM	1	9.1	6 ¾”	2 ½”
8 ½” x 6 ½” Near-Bit Stabilizer	1	1.5	8 ½” x 6 ¼”	2.813”
8 ½” Bit	1	0.5	12 ¼”

 

5 7/8” Hole Section with 3 ½” DP –design as used in well 9806 – Phase 2M drilling campaign

As the WellPlan software database does not include any 4 ¾” M/LWD tools, the BHA was designed to simulate the M/LWD stiffness for Torque and Drag calculations purposes. As MWD – LWD tool are longer than a simple MWD tool, it was replaced by two 4 ¾” DCs. The two additional DCs are non-magnetic. With regards to the hydraulics, a 300 psi pressure loss generated by a completed MWD-LWD tools set-up may be anticipated (as examples, 120 psi pressure drop for the MWD Survey tool + 40 psi for Sonic Tool + 40 psi for Neutron Density + 60 psi for compensated Sonic – all data coming from Pathfinder Technical Spreadsheets). As indicated in the cases 8, 9 and 10, this additional pressure loss was not an issue and did not modify the analyses and the conclusions.

Description	Number	Length (m)	OD	ID
5 ½” DP	To surface	4328.8	5 ½	4.778”
3 ½” DP – 13.3 ppf	90	819	3 ½”	2.764”
3 ½” HWDP – 25.9 ppf	11	100.1	3 ½”	2.063”
4 ¾” Hydraulic Jar	1	9.7	4 ¾”	2 ¼”
3 ½” HWDP – 25.9 ppf	21	191.1	3 ½”	2.063”
3 ½” DP – 13.3 ppf	24	218.4	3 ½”	2.764”
3 ½” HWDP – 25.9 ppf	1	9.1	3 ½”	2.063”
4 ¾” Hydraulic Jar	1	9.7	4 ¾”	2 ¼”
3 ½” HWDP – 25.9 ppf	1	9.1	3 ½”	2.063”
4 ¾” Drill Collars	4	36.4	4 ¾”	2.813”
4 ¾” PDM	1	8.3	4 ¾”	2”
5 7/8” Bit	1	0.3	5 7/8”

 

6” Hole Section with 4” DP

The 6” BHA is similar to the 5 7/8” BHA, except the DP size is changed from 3 ½” to 4”.

Description	Number	Length (m)	OD	ID
5 ½” DP	To surface	4328.8	5 ½	4.778”
4” DP – 14 ppf	90	819	4”	3.34”
4” HWDP – 31.9 ppf	11	100.1	4”	2.563”
4 ¾” Hydraulic Jar	1	9.7	4 ¾”	2 ¼”
4” HWDP – 31.9 ppf	21	191.1	4”	2.563”
4” DP – 14 ppf	24	218.4	4”	3.34”
4” HWDP – 31.9 ppf	1	9.1	4”	2.563”
4 ¾” Hydraulic Jar	1	9.7	4 ¾”	2 ¼”
4” HWDP – 31.9 ppf	1	9.1	4”	2.563”
4 ¾” Drill Collars	4	36.4	4 ¾”	2.813”
4 ¾” PDM	1	8.3	4 ¾”	2”
6” Bit	1	0.3	5 7/8”

• Well path

MD (m BRT)	Inclination (°)	Azimuth (°)	TVD (m BRT)	DLS (°/30m)
0	0	0	0	0
4830	0	0	4830	Kick-Off Point
5140	79	350	5050	7.65
5740	79	350	5146	0

• Fluid Editor

Hole Section	Mud Type	Rheology Model	Rheology Data	Temp.	Press.	Mud Weight	PV	YP
12 ¼”	Water	Bingham Plastic	PV & YP	21°C	1 bar	1.60 SG	36	32
8 ½”						1.20 SG	30	24
5 7/8” / 6”						1.10 SG	8	12

The drilling fluids base and properties were gathered from Phase 2M Daily Drilling Reports.

• Circulating System

Surface Equipment Rated Working Pressure: 4500 psi (5000 psi minus 10% for pop-off valve set-up)

Specified Surface Equipment Pressure Loss: 300 psi

Comment:

The HP circulating system on a rig is sometimes constrained by having surface pipework rated to 5000 psi WP only. In the heavy rig ITT, a 7500 psi circulating system was specified. From the manufacturers’ data, both 12-P-160 and 14-P-220 triplex mud pumps are rated to 7500 psi max working pressure using 4 ½” liners. This configuration will not meet the minimum required flowrate in the 12 ¼” section, even with three pumps online. With 2 mud pumps operating and one as backup, the minimum liner size required is 6” and the mud pumps output pressure is limited to 4670 psi for the 12-P-160 and to 6285 psi for the 14-P-220.    

• Geothermal Gradient

Surface ambient Temperature	Temperature at 5050m TVDBRT	Calculated Geothermal Gradient
15°C	83°C	1.35°C/100m

• Pore Pressure – Frac Gradient (PPFG)

Torque & Drag Modules – Normal Analysis

12 ¼” and 8 ½” Set-Up Data

Hook-Load / Weight Indicator Correction
Travelling Assembly Weight including TDS	35 kLbs
Enable Sheave Friction Correction	Yes
Lines Strung	12
Mechanical Efficiency (single sheave)	97%
Analytical Methods
Use Bending Stress Magnification	Yes
Use “Stiff String” Model	Yes
Contact Force Normalization Length set by default (specify the length that the reported contact forces are wanted)	9.14
Mechanical Limitations
Block rating (Hoisting System)	No
Torque rating (rotating equipment) (not used in any calculation and can be included on certain plots as a reference)	35 kLbs.ft
Maximum WOB Rotating (no sinusoidal buckling)	Yes
Maximum WOB Rotating (no helical buckling)	Yes
Maximum Overpull using % of Yield	90%

12 ¼” Mode Data

Drilling
Parameters	WOB / Overpull	Torque at Bit
Rotating on bottom	40 kLbs	6 kLbs.ft
Sliding	N/A	N/A
Backreaming	80 kLbs	15 kLbs.ft
Rotating off bottom	N/A	N/A
Tripping
Parameters	Speed	RPM
Tripping In	18.29 m/min	0
Tripping Out	18.29 m/min	0
Friction Factor
Parameters	Casing	Open Hole
Rotating on Bottom	0.25	0.30
Slide Drilling	N/A	N/A
Backreaming	0.25	0.30
Rotating Off Bottom	0.25	0.30
Tripping In	0.25	0.30
Tripping Out	0.25	0.30

8 ½” Mode Data

Drilling
Parameters	WOB / Overpull	Torque at Bit (limited by PDM)
Rotating on bottom	30 kLbs	6 kLbs.ft
Sliding	30 kLbs	6 kLbs.ft
Backreaming	60 kLbs	6 kLbs.ft
Rotating off bottom	N/A	N/A
Tripping
Parameters	Speed	RPM
Tripping In	18.29 m/min	0
Tripping Out	18.29 m/min	0
Friction Factor
Parameters	Casing	Open Hole
Rotating on Bottom	0.25	0.30
Slide Drilling	N/A	N/A
Backreaming	0.25	0.30
Rotating Off Bottom	0.25	0.30
Tripping In	0.25	0.30
Tripping Out	0.25	0.30

•   Hydraulics Module – Pressure : Pump Rate Range

12 ¼” Hole Parameters

Pump Rates
Minimum Pump Rate	2100 l/min
Increment Pump Rate	200 l/min
Maximum Pump Rate	3500 l/min
Pumping Constraints
Maximum System Pressure	5000 psi
Maximum Pump Power	2 x 1600 = 3200 HHP
Options
Include Tool Joint Pressure Losses	No
Include Cuttings Loading	Yes
Rate of Penetration	10 m/hr
Rotary Speed	90
Pump rate	3000 l/min
Cuttings Diameter	0.125”
Cuttings Density	2.5 SG
Bed Porosity	36%
MD Calculation Interval	30.48m
Use String Editor Bit Nozzles	Yes
Nozzles Sizes	3 x 22/32” – 1.114 in2 TFA to assume an HSI value of 2.47 at 3000 lpm

8 ½” Hole Parameters

Pump Rates
Minimum Pump Rate	1500 l/min
Increment Pump Rate	200 l/min
Maximum Pump Rate	2500 l/min
Pumping Constraints
Maximum System Pressure	5000 psi
Maximum Pump Power	2 x 1600 = 3200 HHP
Options
Include Tool Joint Pressure Losses	No (see section 5.1 – Hydraulics Comments paragraph)
Include Cuttings Loading	Yes
Rate of Penetration	10 m/hr
Rotary Speed	90
Pump rate	2500 l/min
Cuttings Diameter	0.125”
Cuttings Density	2.5 SG
Bed Porosity	36%
MD Calculation Interval	30.48m
Use String Editor Bit Nozzles	Yes
Nozzles Sizes	1 x 20/32” + 2 x 18/32” – 0.804 in2 TFA to assume an HSI value of 2.19 at 2000 lpm

 

5 7/8” & 6” Hole Parameters

Pump Rates
Minimum Pump Rate	500 l/min
Increment Pump Rate	200 l/min
Maximum Pump Rate	1500 l/min
Pumping Constraints
Maximum System Pressure	5000 psi
Maximum Pump Power	2 x 1600 = 3200 HHP
Options
Include Tool Joint Pressure Losses	No
Include Cuttings Loading	No
Rate of Penetration	N/A (refer to remark below)
Rotary Speed
Pump rate
Cuttings Diameter
Cuttings Density
Bed Porosity
MD Calculation Interval
Use String Editor Bit Nozzles	Yes
Nozzles Sizes	3 x 16/32” – 0.589 in2 TFA to assume an HSI value of 0.94 at 1000 lpm

Remark – “Include Cutting Loading” Option

With the options and parameters chosen to simulate the previous cases, the primary hydraulics calculations issued some spurious results regarding the annulus pressure losses for flowrates in the range 600-900 lpm, which could not be explained by the transition from laminar flow to turbulent flow. Landmark software support was requested and they advised that the “Include Cutting Loading” option should not be used in the analyses.

• “Sine Wave” Tortuosity Model

To generate efficient calculations, hypotheses were included to simulate the wellbore tortuosity, which allows more realistic predictions of torque and drag. The “Sine Wave” method, which was applied for the simulation, modifies the inclination and azimuth of the wellpath point based on the concept of a sine wave shaped ripple running along the wellbore. The parameters are presented below:

Tortuosity Period
Angle Change Period	400 m
Interpolation
Depth Interval	9.14 m
Tortuosity Magnitudes
MD to (m)	Magnitude (°)
500	0.5
1500	0.5
3000	0.5
3700	0.5
4300	0.5
5000	0.5

 

Compared to the other tortuosity models available in the WellPlan software as “Random Inclination and Azimuth” Model or “Random Inclination Dependent Model”, the simulated surface torque is largely higher. It should be noted that the main purpose of the study is not to predict the “real” drilling parameters and their related “real” drilling conditions, but to perform a comparative study to determine the optimum the Drill String design using conservative input parameters.

5.       Analysis

• Case 1: 5” DP

Prior to completing a full study, a basic hydraulics analysis was performed to evaluate feasibility to run a 5” DP string in the 12 ¼” section, which represents the most demanding section.

As the surface equipment is rated to 5000 psi working pressure, a 10% safety is applied for the pop-off valve set-up. The maximum allowable surface pressure is then 4500 psi (not used in any calculation and can be included on certain plots as a reference).

Based on the parameters and input detailed above, the graph 1 below presents the Pressure Loss vs. Pump Rate graph.

The calculations give a maximum achievable pump rate of about 2100 l/min (550 gpm) for a Packed Hole BHA without Downhole Motor or MWD.

The cutting transportation is not a concern due to the mud properties (Mud Weight and the significant YP value) as indicated in the Graph above:

The 5” DP String configuration does not offer a satisfactory solution. Indeed, the following major concerns can be spotlighted:

• no ROP optimisation due to a limited available horsepower at bit (HSI calculated at 0.85) and an implied bit balling risk
• no flexibility to include a performance PDM and a MWD which, combined, will require approximately an additional cumulative 1000 psi pressure drop

The same calculations were performed for a 5 ½” Drill String highlighting the significant pressure loss decrease.

	Required Surface Pressure
Flow Rate	5” DP	5 ½” DP	Gain
2100 lpm	4300 psi	3300 psi	1000 psi
2500 lpm	5500 psi	4200 psi	1300 psi
3000 lpm	7200 psi	5500 psi	1700 psi

Conclusion:

The table and graphs must be considered as only a comparative working base to identify the benefits of one configuration over another. The values are calculated from limited parameters, and are not considered as definitive.

The model used to calculate / simulate seem to be conservative. On well 9806, the same 12 ¼” section was drilled with 5 ½” DP & HWDP, a PDM and the BHA included also a MWD tool. With a mud at 1.64 SG, a flow rate at 3000 lpm, the surface pressure was recorded at 273 bars – 4000 psi. The estimated pressure with a packed hole BHA without MWD and PDM is 5500 psi.

The simulation confirms the fact that the use of 5 ½” DP is necessary for the 12 ¼” section. A significant gain in flexibility, drilling parameters optimization is effective.

One step further could be the use of 5 7/8” DP by Grant Prideco, usually used in extra deep wells or ERD wells. As sensitivity analysis, calculations and a detailed engineering study were done for this configuration (see case 6 later) to evaluate the benefits of such DP compared to the basic 5 ½” ones.

Tool-Joint Determination:

For the further Torque & Drag analysis, the DP connection will be Full Hole type, presenting an Internal and External Upset (IEU). This connection is an API one and this is the only one available in the WellPlan software database for 5 ½” DP – Grade G or Grade S – 21.9 ppf or 24.7 ppf.

The geometric characteristics of the tool-joint are as follow:

	DP Body		Tool Joint
Grade	OD	ID	OD	ID
G	5 ½”	4.778”	7 ¼”	3.5”
S			7 ½”	3”

Hydraulics Comments:

The value shown on the Pressure Loss vs. Pump Rates graph presented above must be used with extreme caution. Indeed, the calculations include the hypothesis of a DP internal pressure loss generated by the tool joints. This type of pressure loss occurs as a result of constrictions inside the DP tool joints as indicated in the geometric characteristics table. Thus, the magnitude of this type of loss is affected primarily by the internal geometry of the tool joint. Pressure losses due to tool joint upset in the annulus are accounted for in the calculations by considering the cross-sectional area change in the annulus. Tool joint pressure losses are sometimes referred to as minor pressure losses.

It seems that the WellPlan software tends to overestimate this tool joint pressure drop. Without this option, the pressure loss drop by about 900 psi at 2100 l/min and up to 1400 psi at 3000 l/min as indicated in the graphs below.

Consequently, the Internal Pressure Loss at the Tool Joints was not included in the analyses.

 

• Case 2: 5 ½” DP – Grade G – 21.9 ppf – FH – No Tortuosity Model – 12 ¼” Rotary BHA

The purpose of this simulation is to evaluate the Grade G Torque & Drag safety margin evolution with the drilling operations duration. All the calculations are made from Class 1 and Class 2 DP to analyse the Torque & Drag safety margin vs. Time and consequently to avoid a drill string failure due to excessive premature wear. Indeed, the drilling conditions could be considered as harsh due to:

• an hostile environment, with large surface temperature range, may generate critical stress & thermal fluctuations
• significant solids contents in mud (due to its weight in 12 ¼” section) associated to significant flow rates, which may lead to premature and excessive erosion of the internal walls
• Low drillability formations: the drilling duration represent a large percentage of the well duration (up to 42% for well 9805 once TD is reached)
• Large drill string vibrations suggested by the incorporation of a the shock absorber in the 12 ¼” BHA for the Phase 2M development program

Graph Analysis

Based on the graphs below, the main following points are raised:

• with no tortuosity model, the torque applied on the bit is equal to the torque provided at surface: no additional torque is generated by the open hole, which exceeds 2600 meters long and despite the presence of 3 full gauge stabilizers in the drill string.
• as anticipated, the mechanical properties of the DP is drastically reduced between Class 1 and Class 2.
• even with a perfect vertical well, the safety margin while tripping in or tripping out is dramatically reduced as soon as the DP is de-rated to Class Premium or Class 2. In case of severe backreaming as usually experienced in this kind of well, the tension margin is nil for Premium but is exceeded by 50 kLbs for Class 2.

Conclusions

Despite the presence of H2S in reduced concentration, the use of Grade S is highly recommended for the following reasons:

• the class G DP showed their limits regarding the tension concerns, even in a perfect vertical well with no tortuosity.
• As the safety margin is low, any well profile change (due to near-surface side-track in 16” hole for example) may lead to unexpected DP failure despite an accurate DP fatigue monitoring and third party inspections performed on regular basis.

• Case 3: 5 ½” DP – Grade S – 21.9 ppf – FH – Tortuosity Model – 12 ¼” Rotary BHA

Graphical Analysis

• for Class 2 DP, the safety margin (45 Klbs) remains sufficient to withstand heavy backreaming or any other standard operations as trip out of the hole without any circulation or rotation.
• A torque increase is observed from bit to surface due to the implementation of the tortuosity model, which allows a more realistic prediction.
• despite a drastic torque limit reduction from Class 1 to Class 2 (from 53,000 to 31,000 ft.lbs), the safety margin, which exceeds 15,000 ft.lbs, remains adequate.
• 10% torque reduction is observed from Class 1 condition to Class 2 condition for both Rotate on Bottom & Rotate Off Bottom cases. The possible explanation is the reduction of the drill string stiffness.

Conclusions

The 5 ½” DP – Grade S – 21.9 ppf with FH connections meets all the mechanical and hydraulics requirements and are the minimum admissible DP configuration. Any other drill string design might bring some technical improvements, but should be clarified by a cost-benefits analysis.

• Case 4: 6 5/8” DP – Grade S – 25.2 ppf – Tortuosity Model – 12 ¼” Rotary BHA

The purpose of this simulation is to evaluate the 6 5/8” DP benefits brought over the 5 ½” Drill string configuration.

Based on the graphs above, the conclusions will be the same for the 5 ½” DP, case 2. The G grade is not sufficient to support the 12 ¼” drilling sections over all the drilling campaign duration. Once de-rated to Class 2, the tension limit is exceeded by about 30,000 lbs in backreaming mode. The Class S DP grade is highly recommended and all further calculations will be run assuming this configuration.

Graph Analysis

• As expected, all the mechanical properties are largely improved compared to the 5 ½” DP.
• The pressure loss is drastically decreased from case 3.

 

Conclusions

The 6 5/8” DP – Grade S option provides a conservative solution for both mechanical and hydraulics analyses. Indeed, a flowrate of 4000 liters/min is achievable with standard 5000 psi surface equipment including mud pumps and circulating system. The tension and torque limits are far in excess of what the Phase 3 wells campaign will require.

The main disadvantages are:

• Additional handling equipment to handle requiring longest duration for picking-up & making up
• longest connection duration, which is not recommended in case of unstable formation
• sacrifice of the rig floor space, reduced racking and setback capacity
• no possible use for the 8 ½” section due to the 8 ½” OD Tool Joint
• 4500 meters of 6 5/8” DP are required to be laid down prior to running the production casing: the clearance between Tool Joint OD and Production Casing ID is not sufficient enough to enable a full strength overshot running e.g. Bowen Series 150 overshot
• a tapered string is not recommended for the same reason than above
• If harsh hole conditions encountered while running the casing requiring a control trip (as it occurred on one of the previous wells), all the 4500 meters of DP must be picked up and made up again
• 6 5/8” DP daily rental may cost higher than the 5 ½” DP but must be confirmed by tender process
• All the rig equipment must be adapted to these DP as elevator, slips, TDS connection and back-up dies, lifting equipment. This dedicated and upgraded equipment will generate additional costs

For the above reasons, 6 5/8” DP has not been considered further in this study. To complete this technical study by a commercial evaluation and a cost-benefits analysis, 6 5/8” DP technical specifications will be included in the ITT process.

• Case 5: 5 ½” DP – Grade S – 21.9 ppf – Tortuosity Model – 8 ½” Steerable BHA

Graph Analysis

• For the 8 ½” section, the main criteria to be considered is the generated torque, more critical than the tension forces.
• The tension forces are very similar between the 12 ¼” and 8 ½” section despite of a lighter 8 ½” BHA. The additional weight comes from the drill string length.
• Most of the weight and the resulting tension forces come from the DP
• The 9 5/8” casing is affected by a friction factor (0.25) very close to the open hole one (0.30), the drag being very slightly reduced.
• The torque generated by the small deviated section (less than 300 meters long) is significant and exceeds the additional torque generated by the all vertical section (more than 4800 meters long). The ratio generated torque by section length is 17.7 ft.lbs/meters for the build-up section and only 0.74 ft.lbs/meters for the vertical section
• Additional study may be required to evaluate the benefits of a less drastic dogleg severity in the build-up section, which may be possible by a modification of the well profile in order to reduce torque in this section and also in the following reservoir sub-horizontal drain
• Oil Based Mud would be beneficial in reducing this additional torque. This assumption must be confirmed by additional evaluation based on fluids design engineering. In this study, the fluids were basically defined by their rheology model (Bingham Plastic) and their limited properties (PV & YP). To really compare their benefits, we will need to obtain a more detailed rheological specification for both fluids from the Fluids Services Company.

 

Conclusions

The S-graded DP is fit-for-purposes and provide safety margin large enough to get flexibility in the BHA design, drilling parameters and well operations for both 12 ¼’ and 8 ½’ sections as follows.

	Class 1	Class 2
Tension	> 300,000 lbs	> 55,000 lbs
Torque	> 37,000 lbs.ft	> 15,000 lbs.ft

 

• Case 6: 5 ½” DP – 21.9 ppf vs. 5 ½” DP – 24.7 ppf for 8 ½” Section

8 ½” Mechanical Comparison

• the tension forces get additional 40 kLbs from 21.9 ppf to 24.7 ppf
• the tension limit moves from 700 kLbs for 21.9 ppf DP to 800 kLbs for 24.7 ppf
• the overpull margin is larger for the 24.7 ppf DP than for 21.9 ppf by 60 kLbs

Regarding the tension forces, the use of 24.7 ppf DP offers a greater margin than 21.9 ppf DP. The weight on hook is slightly increased caused only by the heavier unit weight. No abnormal extra drag could be noticed.

Hydraulics Comparison for 12 ¼” & 8 ½” Sections

The table below presents the flowrate loss for a pre-determined pressure (the maximum allowable or reached) from 21.9ppf DP design to 24.7ppf DP design. The complete graphs are shown below.

Section	Mud Weight	Max Achievable SPP	Flowrate 21.9ppf DP	Flowrate 24.7ppf DP	Flowrate Loss	Flowrate Loss (%)
12 ¼”	1.60 SG	4500 psi	3240 lpm	3120 lpm	-120 lpm	-3.7%
8 ½”	1.20 SG	3800 psi	2440 lpm	2360 lpm	-80 lpm	-3.3%

For two different mud weights and flowrates combination, the pressure loss in the drill string does not change dramatically. The smaller ID of the 5 ½” DP – 24.7 ppf cannot be considered as an operational issue.

Conclusion

Due to the benefits brought by the extension of the overpull margin not counter-balanced by the potential hydraulics constraints, it is recommended to use the 24.7 ppf DP instead of the 21.9 ppf DP.

12 ¼” Hydraulics Comparison Graphs

 

8 ½” Hydraulics Comparison Graphs

• Case 7: 5 ½” DP – 24.7 ppf vs. 5 7/8” DP – 23.4 ppf

8 ½” Mechanical Comparison

• The calculations are only conducted for Class 1. The Wellplan database is not complete and does not provide characteristics for 5 7/8” DP in Class 2 condition.
• Compared to the 5 ½” DP – 24.7 ppf, the tension safety margin of the 5 7/8” DP is reduced by 40 Klbs. But due to the gain on the weight, the overpull margin remains almost the same, at 410 Klbs for both configurations.
• The same comments are brought for the torque. The torque safety margin remains constant when comparing the 5 ½” DP specification to 5 7/8” DP.

Hydraulics Comparison for 12 ¼” & 8 ½” Sections

The table below presents the increased flowrate capacity for a pre-determined pressure (the maximum allowable or reached) from 5 ½” – 24.7ppf DP design to 5 7/8” – 23.4ppf DP design. The complete graphs are shown below.

Section	Mud Weight	Max Achievable SPP	Flowrate 5 ½” DP	Flowrate 5 7/8” DP	Flowrate Gain	Flowrate Gain (%)
12 ¼”	1.60 SG	4500 psi	3120 lpm	3600 lpm	480 lpm	+15.4%
8 ½”	1.20 SG	3700 psi	2320 lpm	2500 lpm	+180 lpm	+7.8%

The larger ID of the 5 7/8” DP provides benefits for important flow rates, as shown for the 12 ¼” section. Indeed, the pressure loss reduction in the drill string is significant when passing from 5 ½” DP to 5 7/8” DP. For reduced flow rates as expected in the 8 ½” section, the benefit is no more significant.

 

Conclusions

The 5 7/8” DP does not provide any additional mechanical capacity, but provides additional hydraulic capacity in the 12 ¼” hole section. A decision to run this DP size will be based on the cost-benefit analysis of increased ROP in the 12 ¼” hole due to the potential improvement in bit hydraulics. A further sensitivity calculation will demonstrate an additional benefit in the use of the 5 7/8” DP (see to case 11).

12 ¼” Hydraulics Comparison Graphs

8 ½” Hydraulics Comparison Graphs

• Case 8: 3 ½” DP – 13.3 ppf – NC38 x 5 ½” DP – 24.7 ppf – FH for 5 7/8” Section

To drill the 5 7/8” hole section, a tapered 3 ½” x 5 ½” drill string was designed in order to optimize hydraulics and to reduce new DP make-up duration. A 7” 32ppf liner was set at 4435m MDBRT with its shoe at 5140m MDBRT.

3 ½” DP Selection

For S-Grade, 3 ½” DP is available for 2 different weights: 13.3 ppf or 15.5 ppf. For our applications, the primary drill string configuration will include the 13.3 ppf DP. If the mechanical properties of this DP are not adequate, another analysis would be performed using the 15.5 ppf DP.

The WellPlan database includes the following connections:

	NC38	NC40	SLH90
OD	5”	5 3/8”	5”
ID	2 1/8”	2.438”	2 1/8”
Connection Torsional Yield	26,515 ft.lbs	29,930 ft.lbs	28,078 ft.lbs
Make-Up Torque	15,909 ft.lbs	17,958 ft.lbs	16,847 ft.lbs

The NC40 connection was rejected due to its too large OD, which would not permit the running of a full strength overshot in a 5 7/8” open hole in the event of fishing operations.

As the 2 remaining connections present similar geometrical characteristics, with minor difference (less than 6%) regarding the torsion yield, the NC38 connection was used in these simulations for standard purposes. The NC38, which is compatible with 3 ½” IF thread, is the most common connection used in 3 ½” DP. The 5” OD in a 5 7/8” open hole offers limited clearance to run a full-strength overshot. The Bowen Series 150 Releasing Overshot, with a 5 ¾” OD, is able to catch fish up to 5 1/8” OD.

Consequently, the associated risks are the overshot may not be:

• run in hole due to the 1/8” clearance between overshot OD and hole diameter
• able to catch the fish at the tool joint in case the tool joint becomes belled out during back-off operations

The option to mitigate the risk to get the 5 ¾” Overshot stuck is to increase the section size from 5 7/8” to 6” to offer more running clearance. The use of a fit-for-purpose Tool Joint as Grant Prideco XT39 Tool Joint will provide more flexibility in the spiral or basket grapples choice for catching fish in case of belled out connection. As the Wellplan database is not up to date, the calculations could not be run with this XT39 Tool Joint.

Comment – “Include Cutting Loading” Option

With the options and parameters chosen to simulate the previous cases, the primary hydraulics calculations issued some spurious results regarding the annulus pressure losses for flowrates ranged between 600 and 900 lpm, which could not be explained by the transition from laminar flow to turbulent flow. Landmark software support personnel were consulted and advised that the “Include Cutting Loading” option must be removed.

Graphical Analysis

• The torque increase resulting from the 5 7/8” open hole tangent section is not so drastic compared to the 8 ½” build-up section due to :
  • Short open hole section length compared to the well depth
  • Slant section without any dogleg: less tortuosity also due to the section inclination. The tortuosity affects more effectively the Torque & Drag outputs in the vertical sections
  • The 5 7/8” Steerable BHA is also more flexible, less stiff than the 8 ½” Steerable BHA. It does not include any DC for WOB purposes. Few Drill collars were incorporated in the drill string to simulate the stiffness of the 4 ¾” LWD tools.
• No excessive tension is expected in this section: the major part of the well is cased and has a lower friction coefficient. The drilling BHA weight is also very light with only 3 ½” HWDP. The maximum tension is recorded at surface, location where the 5 ½” DP is fit-for-purposes.
• The flow path in this section, with a 5 7/8” x 4 ¾” BHA annulus, the pressure loss in front of the drill collars/PDM or LWD tools are significant, leading to an ECD equal to 1.16 SG at 1000 lpm, 6 points above the initial mud weight (additional 430 psi applied onto formation), which does take into account the cuttings loading as explained above. The main risk is to be excessively overbalanced with respect to reservoir pressure leading to losses, formation damage, differential sticking or well bore destabilization.
• The pressure loss does not include the pressure losses generated by the LWD tools because of its absence from the WellPlan database: for this tools size, a max cumulative 300 psi pressure drop can be assumed.
• The turbulent flow would occur in the open hole and 7” liner sections from a flow rate of 900 lpm, the turbulent flow is required in the sub-horizontal drain to sustain the drilled solids and, therefore to improve the hole cleaning.
• The 3 ½” DP – NC38 thread is suitable to the well design and standard drilling parameters. With a turbine or a PDM, the torque applied on bit is limited to 2000 ft.lbs (4 ¾” Sperry-Sun Medium speed PDM – 4:5 lobes – 6.3 stages. As no Insert Bit is anticipated to be run, a Low Speed Motor, whose torque could exceed 3000 ft.lbs was not considered). The torque generated in both open hole and 7” liner would not exceed the 3 ½” DP torque limit while drilling.
• This point must be mitigated in case of BHA stuck above the bit without possible rotation or in case of severe reaming with the obstruction being located on the BHA above the bit. Caution is required while attempting to free the drill string by applying torque at surface

Conclusion

The 3 ½” DP is suitable for the designed application. No operational issue was raised, except in case of severe reaming with an obstruction not located at bit but on the BHA.

• Case 9: 4” DP – 14 ppf – NC40 x 5 ½” DP – 24.7 ppf – FH for 6” Section

4” DP Determination

For S-Grade, the 4” DP are available for 2 different weights: 14.0 ppf or 15.7 ppf. As previous calculations were performed with 13.3 ppf DP showing these DP are suitable, it was decided to use the 14.0 ppf DP.

The WellPlan Database includes the following connections:

	H90	NC40	NC46
OD	5 ½”	5 ½”	6”
ID	2.813”	2”	3”
Connection Torsional Yield	29,535 ft.lbs	36,364 ft.lbs	39,230 ft.lbs
Make-Up Torque	17,720 ft.lbs	21,818 ft.lbs	23,538 ft.lbs

The NC46 connection was rejected due to its too large OD, equal to the open hole.

The NC40 connection was used for the simulations because it represents the best compromise between geometrical characteristics and mechanical properties. As in the simulations, the internal DP pressure loss due to tool-joint is considered as negligible; the smaller ID of this connection would not have any impact in the hydraulics calculations. The benefit of the NC40 connection is the provision of a larger torque limit.

This type of connection will not allow the running of a full strength overshot, the clearance between the 5 ½” tool joint OD and the 6” open hole ID is not large enough to catch drill string on the tool joint body in case of fishing operations. But, since the WellPlan database is not up to date, the calculations were performed with this connection type, and if the selected DP is suitable for the applications, other connection option would be available to solve the fishing geometry issue as the XT39 Tool Joint from Grant Prideco, presented in section 6 – Conclusions (recommendations paragraph).

Graph Analysis

The calculations were not conducted for the Class II. Indeed, the previous analysis done for the 3 ½” DP – Class II indicated that the drilling parameters are still within their working range. The 4” DP is specified with NC40 connections

• To evaluate the benefits of the 4” DP, the hole section has to be enlarged from 5 7/8” to 6” size. The tool joints coupling of the 4” DP is 4 ¾” OD and the clearance in a 5 7/8” hole is not large enough to allow the running of a full strength overshot in case of fishing requirements
• The 4” DP present a larger torque range, making it attractive for the small size section where torque may be a problem
• The pressure loss and the surface pressure requirements decrease significantly compared to the 3 ½” DP: at 600 lpm, the difference is about 200 psi, at 1000 lpm, it is about 700 psi
• As shown on both pressure loss graphs, the annulus pressure losses for both configuration are similar, only 100 psi higher at 1500 l/min for the 4” DP. That results the ECD for the 4” DP x 6” OH configuration is almost the same than for the 3 ½” DP x 5 7/8” OH configuration.

Comparison between 3 ½” and 4” DP

 The main advantages provided by the 4” DP are:

• less pressure drop inside the DP which offer a potential larger flexibility in the hydraulics and ROP improvement by playing on flow rates, power delivered at bit (by TFA set-up, HSI requirements), RPM & torque at bit related to the PDM/turbine/flow rate configuration
• larger torque margin needed only in case of BHA stuck

The main disadvantages are:

• a requirement to drill the reservoir section in 6” size instead of the 5 7/8” size initially planned. However, it is not expected to negatively impact drilling, completion or production operations and may have advantages in FEWD programme
• ordering special drift 7” x 32 ppf liner as standard, which should allow the running of the 6” bit on a steerable PDM/Turbine in case of a directional correction run
• despite a potential flow rate increase, this one would be limited by the PDM/Turbine requirements
• the downhole tools fleet (bit, stabilizers, accelerators, PDM / Turbine, jars, circulating devices, etc…) must be thread-complied to the 4” DP threads requirements (XT39 instead of NC38 commonly used): a large fleet should be anticipated, and also the availability the threads manufacturing licence by one of the Contractors in the field (threads inspections and recuts, provision of crossovers, etc…)

 

Conclusions

Based on the WellPlan simulations, the 3 ½” DP are fit for purposes and do not require any change in the Basis of Design. The benefits brought by the 4” DP are not entirely justified regarding the drilling constraints and parameters.

• Case 10: 4” DP vs. 3 ½” DP for UBD – Casing Injection Purposes

In the event the Object 3 reservoir would be drilled underbalanced, the running of a 7” Scab Slotted Liner including 1 or 2 DDV remains an option for nitrogen injection via the 9 5/8” x 7” annulus. It is important to anticipate this kind of configuration because, the tapered drill string option is no longer applicable, and a complete 3 ½” or 4” DP string must be used. In this case, the 4” DP benefits raised above are strongly reinforced and even, become mandatory.

For 1000 lpm Flowrate	3 ½” x 5 ½” Tapered String	4” x 5 ½” Tapered String	Ratio
Drill String Pressure Loss	1629 psi	961 psi	59%
Smaller size DP & HWDP Pressure Loss	1077	409 psi	38%
Pressure drop Ratio	66.1%	42.5%
Length Ratio	25%	25%

For the 3 ½” x 5” tapered string calculations, the 3 ½” DP and HWDP internal pressure drop can be estimated at about 66% of the complete string internal pressure drop, the 3 ½” DP and HWDP length representing only 25% of the complete string length.

For the 4” x 5 ½” tapered string calculations, the 4” DP and HWDP internal pressure drop can be estimated at about 43% of the complete string internal pressure drop, the 4” DP and HWDP length representing only 25% of the complete string length. The 4” x 5 ½” string complete pressure loss is reduced by about 59% compared to the 3 ½” x 5 ½” configuration.

Graphical Analysis

• As expected, the pressure drop into the 3 ½” DP string exceeds by 60% (1000 lpm – 2800 psi vs. 4500 psi) the one resulting from the 4” DP configuration.
• The 3 ½” DP do not offer any flexibility: a configuration (BHA elements, HSI, etc...) has to be defined prior to drilling and could not be changed or modified following the well requirements.
• The inflexion observed in the annulus pressure drop for both configurations at 900 lpm indicates the switch from the laminar flow to the turbulent flow
• Before this inflexion point, the annulus pressure drops are similar for both configuration
• After this inflexion point, the slopes are different indicating that the fluid velocity is higher in the 6” x 4” annulus than in the 5 7/8” x 3 ½” annulus. The turbulent flow is more effective and the hole cleaning improved. This hole cleaning in sub-horizontal drain is one of the most important concern. The cuttings settling on the low side generates a solids bed, which once settled is difficult to remobilize and could lead to hole pack-off and BHA stuck.
• The Torque & Drag calculations were done for both Class 1 and Class 2. As the Class 2 represents the worst case scenario, only their results are shown above
• The tension safety margin is roughly the same for the 4” DP string and for the 3 ½” DP.
• The 4” DP tool joint provides higher torque limit. Despite the increase of the torque at surface compared to the 3 ½” DP configuration, the torque safety limit is higher for the 4” DP

Conclusion

If UBD using the casing injection is confirmed, the 4” DP string is mandatory. Grant Prideco provide the XT39 connection, offering

• two different Tool Joint OD – 4 7/8” and 5” - both smaller than the 5 ½” OD of the H90 or NC40 Tool Joints.
• enhanced mechanical characteristics compared to the H90 and NC40 connections characteristics.
• best compromise in term of geometry / mechanics properties.

 

• Case 11: Fatigue Calculations in case of shallow side-track

To analyse the drill string mechanical behaviour, the well profile was slightly modified to simulate a side-track in the 16” section in case of Triassic shale instability. The well path is designed at follow: the kick-off point is set up at 150m MDBRT to reach 8° Inclination at 200m MDBRT to be at 17 meters away from the “fish” or from the original 16” vertical section. The inclination is then lowered back to 0°, the verticality being maintained down to the next kick-off point at 4830m MDBRT as per original well path.

MD (m BRT)	Inclination (°)	Azimuth (°)	TVD (m BRT)	DLS (°/30m)
0	0	0	0	0
150	150	0	0	Kick-Off Point #1
200	8	350	200	4.8
400	0	0	399	0
4830	0	0	4830	Kick-Off Point #2
5140	79	350	5050	7.65
5740	79	350	5146	0

The Torque & Drag module includes fatigue analysis because it is a primary cause of drilling tubulars failure. A fatigue failure is caused by cyclic bending stresses when the pipe is run in holes with dogleg. The source of fatigue failure is micro fractures between the crystal structures of the material caused in the construction of the material. These cracks are widened by successive stress reversals (tensile/compressive) in the body of the cylinder.

Fatigue ratio is the combined bending and buckling stress divided by the fatigue endurance limit. The Fatigue Endurance Limit is not a constant value that is related to the yield strength of the pipe. Bending stress concentrations are also in the tubular due to the design of tool-joints and the shape of the upset in the body pipe apart from those considered in the bending stress magnification factor.

Some judgment is required in using the fatigue endurance limit (FEL), because the limit is normally determined for a number of cycles of pipe rotation. The number of cycles for the fatigue endurance limits is approximately taken at 10⁷ rotations, this is the level of cyclic stress beyond which the material is immune to fatigue failure. This is normally equivalent to the pipe drilling for 30,000 meters at 18m/hr at 100 RPM.

Graphical Analysis

The fatigue calculation results show that:

• In any section which present some dogleg, the fatigue ratio is higher than in the vertical or slant section
• The near-surface side-track leads to massive fatigue for all the DP configurations and for all sections size: extra special care would be brought to the DP conditions to prevent any unpredictable DP failure
• The difference is not significant between 5 ½” and 5 7/8” DP for the 12 ¼” section and between 3 ½” DP and 4” for the slant section
• The difference is substantial for the 8 ½” section: the near-surface fatigue ratio is almost reduced by 2 from 8 for the 5 ½” DP configuration to 4 for the 5 7/8” DP one

6.       Conclusions

According to the results and all the concerns raised in this study, the technical conclusions are the following:

• With 5000 psi surface equipment, the minimum requirement is the use of 5 ½” DP to reduce internal pressure loss and gain flexibility in the hydraulics for 12 ¼” and 8 ½” sections
• Due to the fatigue caused by both harsh drilling conditions and dramatic temperature variation, a S-Grade DP will propose more safety margin and should help to prevent any unpredictable failure in case of premature wear
• No special recommendation regarding the Tool Joint and Connection for the 5 ½” DP. The FH connection is suitable
• Due to all the concerns raised concerning the 6 5/8” DP utilisation (rig equipment to be modified, long duration to handle them, to lay them down at the end of the 12 ¼” hole section et al), this option is not fit-for-purpose.
• The 5 7/8” DP – Grade S bring some potential improvement only for the hydraulics aspects of the 12 ¼” section. Their mechanical operating properties remain similar to the 5 ½” DP.
• A near-surface side-track generates drastic fatigue on the DP at the KOP. The fatigue ratio is increased from 0 to 8 for 5 ½” DP and from 0 to 4 for 5 7/8” DP (the 0 value is due to a vertical section without any tortuosity as designed). The 5 7/8” DP is less sensitive to this fatigue than the 5 ½” DP
• 5 7/8” DP should be provided by Grant-Prideco with their XT57 Connection, which is over-rated for our applications but the larger ID will slightly reduce pressure drop, surface pressure requirements, and offer hydraulics flexibility without needing to upgrade the mud pumps and rig surface equipment requirements to a 7500 psi system
• The 3 ½” DP are able to support the Object 3 reservoir drilling. The clearance in a 5 7/8” hole is not sufficient enough to run a full strength overshot.
• As the 5 7/8” DP for the upper section, the main benefits of the 4” DP is the pressure loss reduction offering larger hydraulics working range
• The 4” DP become mandatory in case of drilling with underbalanced conditions created by N2 injection thru 7” tie-back casing or even thru DP (higher velocity at surface due to the gas volume)

 

Comment: Grade S DP in Sour Gas environment

Fatigue cracks are a common occurrence when drilling in a corrosive environment. Most of these failures result from stress corrosion cracking when drilling stresses are excessive and corrosion is not controlled adequately. The corrosion is caused by the acid generated by the sour gas dissolved in the water phase of the mud system. This effect is more drastic for the Grade S DP than the Grade G DP due to the material properties. Because H2S is not miscible with an oil based mud and as the water phase concentration is low (20-40%) and non-continuous, OBM provides a simple mitigation to this corrosion problem. Steel will not corrode when the metal is oil-wet.

In the case of WBM systems, drilling procedures must be implemented to reduce the potential for fatigue cracking to occur. A tapered BHA design should be used with a tapered transition section. A WBM treated to maintain its pH above 10.5 will help reduce stress corrosion fatigue cracking. Adherence to good, established drilling practices also helps minimize the problem. Besides treating the drilling fluid, all possible steps should be taken to keep oxygen out of the drilling fluid system.

The upper hole sections DP (5”, 5 ½”, 5 7/8” or 6 5/8”), as the 3 ½’ or 4” section DP, will be also affected by this corrosion effect due to the tapered string configuration while drilling the H2S/CO2 bearing formations. Prior to implementing these recommendations regarding the mud system (LTOBM or pH-controlled WBM), consult with Town concerning potential for DP corrosion and results of corrosion monitoring for DP currently in use.

Recommendations

Technically and based on operating range and well architecture and design panels, the following DP specification is recommended.

5 7/8” DP – Grade S – 23.40 ppf – XT57 Tool Joint

XT57 Tool Joint Description

Connection	OD	ID	Torsional Yield	Make-Up Torque	Tensile Yield
Streamline Double shoulder	7”	4 ½”	94,300 ft.lbs	56,600 ft.lbs	1,208,700 ft.lbs

Tool Joint Advantages

• Streamline Configuration: 5 7/8" DP utilizes a 7” OD XT Tool joint allowing it to be used to drill inside 9 5/8” casing and 8 ½” open-hole sections.
• Overshot fishing capability in an 8 ½” hole is maintained.

Tool Joint Disadvantages

• See appendix for list of Handling Equipment Changes required to run 5 7/8” DP  
• Most of downhole tools & equipment must be special threaded (Jars, Circulating sub, Dart Subs, etc…)
• large fleet of XO and TDS saver subs
• a threading licence must be available to permit field repairs

5 7/8” DP Advantages

• Prevent accumulation of fatigue, especially in case of near-surface side-track
• Enhanced Hydraulic Performance leading to
  • Surface pressure reduction, and then, the rig specification of 7500 psi pressure rating surface equipment is not necessary
  • Flexibility in the hydraulics parameters: ability to reduce bit TFA to optimize power at bit, PDM configuration and size, and therefore ROP

4” DP – Grade S – 14 ppf – XT39 Tool Joint

XT39 Tool Joint Description

Connection	OD	ID	Torsional Yield	Make-Up Torque	Tensile Yield
Streamline Double shoulder	4 7/8”	2 9/16”	37,000 ft.lbs	22,200 ft.lbs	729,700 lbs
	5”	2 9/16”	40,800 ft.lbs	24,500 ft.lbs	729,700 lbs

For our applications, the 4 7/8” OD Tool Joint is the preferred option offering a larger range of fishing overshot grapple.

Tool Joint Advantages:

• Capability to be fished with full strength overshot
• More available torque in case of BHA stuck above the bit

Tool Joint Disadvantages:

• special 7” Liner drift
• drilling in 6” instead of the 5 7/8” currently used in Phase 2M
• non standard equipment which requires anticipation and pro-active preparation
• all downhole tools & equipment must be special threaded (PDM, LWD, DC, Jars, Circulating sub, etc…)
• large fleet of XO and TDS saver subs
• a threading licence must be available on field

4” DP Advantages:

• Prevent accumulation of fatigue
• Turbulence flow more effective once rate above 900 lpm
• Hole cleaning improvement
• Significant reduction of the pressure loss, that supposes less surface pressure: a MUST for the reservoir UB drilling with a 4” string up to surface
• Flexibility in the hydraulics parameters: ability to reduce bit TFA to optimize power at bit, Turbine or PDM configuration,
• Improvement of ROP

The 5 7/8” DP – XT57 Connection and 4”DP – XT39 are both manufactured by Grant Prideco. In the event that the Drilling Contractor will not be required to provide drill strings as part of its scope under the heavy rigs ITT, it would be advantageous to award a rental drill string contract to one provider:

• avoid interfaces with 2 different contractors
• remove liability concern in case of tapered string failure
• increased opportunity for discounted rates based on this high rental revenue.

Cost – Benefit Analysis

As this study has recommended that a separate cost-benefit analysis be undertaken to compare several drill strings, the drill string ITT should include the following DP specifications. A separate cost-benefits analysis will be performed for each DP against expected ROP, risks analysis:

Size	Grade	Weight	Thread	Class
3 ½”	S	13.3	NC38	1
4”		14.0	XT39
5”		19.5	NC50
5 ½”		24.7	FH
5 7/8”		23.4	XT57
6 5/8”		25.2	FH

7.       Mud Pumps System and DP specification Discussion – Recommendations

Discussion

Based on the results of the analyses, it appears that the drilling hydraulics output parameters are within 5000 psi working pressure range for mud pumps and stand pipe manifold. There is no need to upgrade it to the 7500 psi (Stand pipe Manifold, HP flow lines), where the additional operating costs may not be offset by the drilling operations time saving. Larger 14-P-220 Triplex pumps advocated by Phase 2M, but a cost-benefit analysis has not been provided to support this.

The only section, in which these high-performance mud pumps characteristics could be applied is the drilling of the 12 ¼” phase. But, according to the Phase 2M data, its drilling could be performed with a 3000 lpm flow rate with a PDM, and an associated surface pressure of 4000 psi at section TD.

This surface pressure may be lowered by the use of the Low Toxic OBM, which present lower friction and an enlargement of the DP, using the 5 7/8” from Grant-Prideco.

We need to better understand the case for a 7500 psi circulating system by further investigation with Phase 2M.

Recommendations

If the decision is made to upgrade the rig with 7500 psi surface equipment, there is no need to optimize drill strings configurations. Standard equipment as 3 ½” & 5” DP – Grade S are efficient enough to achieve the well objectives. The inherent risk is a premature wear of the DP (erosion due to solids content and high fluid velocity, fatigue due to internal working pressure associated with mechanical stresses generated by the well profile, which are drastically increased for tortuous wells or near-surface side-track), which may lead to an unpredicted DP failure.

The use of such pumps will also eliminate all the problems related to the threads connections and downhole tools special manufacturing.

8.       Appendix: Handling Equipment Changes required to run 5 7/8” DP

The list below and provided by Grant Prideco details what changes will be required to run 5-7/8” DP with XT57 connections.

Item	Change Description
Slips:	5 ½” slip bodies can be used. Thinner dies will be required on the slips to accommodate the 5-7/8″ DP. A 7” slip body dressed with inserts to grip the 5-7/8” pipe body can also be used. The 7″ slip body will allow the use of thicker dies
Elevators:	New elevators with a bore of 6 1/8″ should be used
Top Drive Saver Sub:	The top drive saver sub should be crossed over to Grant Prideco’s XT57 connection. All Varco top drive saver subs should be 5 ½” from shoulder to shoulder. This ensures the top drive pipe handler torque wrench grips the box at least 2″ from the box shoulder face, eliminating opportunities for squeezing the box in the counterbore region. As such, for other top drive brands, the top drive saver sub should also be a length that provides torque wrenching at the same 2″ length minimum from the box shoulder face
Pipe Wiper:	No modifications are required.
B.O.P. Pipe Rams:	If variable size rams are being utilized, no modifications are required. Otherwise, the B.O.P. pipe rams will have to be ordered for the 5-7/8” DP. Note: If it becomes necessary to hang off and shear the pipe with the rams, a fixed ram for 5-7/8” may be required. Check with the B.O.P. manufacturer.
DP Safety Valve:	The safety valve should be ordered with the XT57 connection and a 4 ¼” ID
Finger Board:	No modifications are required.
Automatic Pipe Handling Equipment:
Iron Roughneck Spinner:
Pick-up Line:
Lift Nipples:
Mud Bucket:	The mud bucket will need to be bored out so that it will seal around the pipe body
Crossover Subs:	Crossover subs need to be ordered with the XT57 tool joint
Heavy Weight DP:	5-7/8” HWDP can be ordered from Grant Prideco with the XT57 tool joint
Top Drive Bell Stabbing Guide:	The top drive bell stabbing guide should be checked to ensure a tight clearance between the stabbing guide and the box connection. Adjust the effective bore in the top drive bell stabbing guide to ensure there is no more than ½” clearance (on the diameter) between it and the XT57 box tool joint OD. With a 7.000” O.D. tool joint, the standard 5” top drive bell stabbing guide will usually work good. (Varco flipper part number is 99304)
Rig Floor Stabbing Guide:	A stabbing guide should be used on the rig floor any time a pin is stabbed into the box. For the XT connection, this will ensure proper alignment when stabbing and reduce stabbing damage