🧱 Casing in Oil & Gas Wells: Types, Design, and Installation Explained

Casing Design and Installation - A Complete Engineering Guide with Load Calculations

Casing design is where drilling engineering meets structural engineering. Every casing string you set is a permanent commitment - you cannot revise it after cementing the way you can revise a drilling parameter or mud formulation. A casing string set at the wrong depth, designed with insufficient burst rating, or cemented with inadequate bond creates a well integrity problem that will cost 10-100x more to fix than it would have cost to design correctly. This guide gives you the complete engineering framework: casing string functions, load analysis, grade selection, setting depth criteria, and the failure modes that end careers and wells.

1. Casing String Architecture - The Well Construction Sequence

A conventional well uses 4-6 casing strings, each set progressively deeper and at smaller diameter. Every string has a specific engineering function and is triggered by a specific downhole challenge. Understanding why each string exists prevents the most common design error - setting casing too deep and running out of diameter before reaching the target.

String	Typical OD Range	Primary Function	Setting Depth Trigger
Conductor	20" - 36"	Structural foundation, riser connection, prevent surface washout	30-300 ft - below unconsolidated near-surface sediments
Surface casing	13-3/8" - 20"	Freshwater protection, BOP support, well control anchor	Below deepest freshwater aquifer + 100 ft safety margin
Intermediate casing	9-5/8" - 13-3/8"	Isolate abnormal pressure zones, unstable shales, lost circulation zones	Below problematic zone, above next potential hazard
Production casing	7" - 9-5/8"	Reservoir isolation, production conduit, completion anchor	Through entire productive interval to TD
Liner	5" - 7"	Same as production casing but hung from previous string - cost saving	Overlaps previous casing by 200-500 ft, extends to TD
Tieback	Same as liner OD	Extends liner to surface for pressure isolation or re-entry	Liner top to surface or intermediate casing shoe

2. Casing Load Analysis - The Engineering Core

Every casing string must be checked against three fundamental load cases. Failing any one of them in the worst-case design scenario is unacceptable - even if the other two have generous safety margins.

2.1 Burst Load Analysis

Burst occurs when internal pressure exceeds external pressure plus casing burst strength. The worst-case burst scenario is a gas kick with the annulus empty (lost returns to surface):

Burst pressure at surface = Formation pore pressure - Gas gradient x Depth

Burst pressure at depth D = Pore pressure at D - External mud pressure at D

Design factor for burst: SF_burst = Pipe burst rating / Maximum burst load >= 1.1

Worked example - Production casing burst check:

• Depth = 10,000 ft TVD
• Pore pressure gradient = 0.52 psi/ft (abnormal)
• Pore pressure = 0.52 x 10,000 = 5,200 psia
• Gas gradient = 0.1 psi/ft
• Burst pressure at surface = 5,200 - (0.1 x 10,000) = 4,200 psi
• Required: 7" 29 lb/ft P-110 casing has burst rating = 8,160 psi
• Safety factor = 8,160 / 4,200 = 1.94 - acceptable (>1.1)

2.2 Collapse Load Analysis

Collapse occurs when external pressure exceeds internal pressure plus casing collapse resistance. The worst-case collapse scenario is the casing string emptied of fluid (lost circulation during cementing, or production tubing leak):

Collapse pressure at depth D = External mud pressure at D - Internal pressure at D

Worst case: Internal pressure = 0 (empty casing)
Collapse pressure = 0.052 x mud weight (ppg) x depth (ft)

Design factor for collapse: SF_collapse = Pipe collapse rating / Maximum collapse load >= 1.0

Worked example:

• Depth = 10,000 ft, mud weight = 12 ppg, casing assumed empty
• Collapse load = 0.052 x 12 x 10,000 = 6,240 psi
• 7" 29 lb/ft P-110 collapse rating = 8,530 psi
• Safety factor = 8,530 / 6,240 = 1.37 - acceptable (>1.0)

2.3 Tensile Load Analysis

The casing string hangs in tension from the surface hanger. The maximum tensile load occurs at the top of the string and equals the buoyed weight of the entire casing string:

Tensile load (lbs) = Air weight of casing string x Buoyancy factor

Buoyancy factor = 1 - (mud weight / 65.5)

For stuck pipe contingency, add overpull margin:
Design load = Buoyed weight + Overpull (typically 100,000 - 300,000 lbs)

SF_tension = Pipe body yield / Design tensile load >= 1.6 (API) or 1.8 (operator preference)

Worked example:

• 10,000 ft of 7" 29 lb/ft casing = 290,000 lbs air weight
• 12 ppg mud: BF = 1 - (12/65.5) = 0.817
• Buoyed weight = 290,000 x 0.817 = 237,000 lbs
• Overpull = 150,000 lbs
• Design load = 237,000 + 150,000 = 387,000 lbs
• 7" 29 lb/ft P-110 body yield = 883,000 lbs
• SF = 883,000 / 387,000 = 2.28 - acceptable (>1.6)

3. Casing Grade Selection

3.1 API Grade Designations

Grade	Min Yield (psi)	Min Tensile (psi)	Primary Application	Sour Service
J-55	55,000	75,000	Surface casing, shallow wells	Yes
K-55	55,000	95,000	Surface and intermediate casing	Yes
N-80	80,000	100,000	Intermediate and production casing	Yes (Type 1)
L-80	80,000	95,000	Sour service wells - NACE MR0175	Yes - primary sour grade
C-95	95,000	105,000	Intermediate casing, moderate sour	Yes
P-110	110,000	125,000	Deep production casing - standard workhorse	No - SSC risk
Q-125	125,000	135,000	HPHT sour service wells	Yes (limited)

The sour service constraint: In H2S environments, higher-strength grades (P-110, V-150) are susceptible to Sulfide Stress Cracking (SSC) because their higher hardness makes them brittle in the presence of hydrogen sulfide. NACE MR0175 specifies L-80 as the standard sour service casing grade. When HPHT conditions require higher strength than L-80 provides, use Q-125 or C-90 with specific heat treatment certifications.

4. Setting Depth Criteria - The Pore Pressure / Fracture Gradient Analysis

Setting depths are determined by the pore pressure and fracture gradient profiles with depth. The fundamental constraint is that at any depth, the mud weight needed to control the pore pressure must not exceed the fracture gradient of the exposed open hole. When this window narrows to zero, casing must be set.

Casing must be set when:
Pore pressure gradient of next section > Fracture gradient of current open hole

Kick tolerance at any depth =
(Fracture gradient - Current mud weight) x Casing shoe TVD / 0.052

Worked setting depth example:

Depth (ft)	Pore Pressure (ppg)	Fracture Gradient (ppg)	Window (ppg)	Action
3,000	9.0	14.5	5.5	Continue drilling
6,000	10.5	14.2	3.7	Monitor - window narrowing
8,500	13.8	14.5	0.7	Set intermediate casing here
10,000	14.8	15.8	1.0	Drill with 14.8 ppg mud after casing at 8,500

At 8,500 ft the window is only 0.7 ppg - this means the mud weight needed to control pore pressure (13.8 ppg) is only 0.7 ppg below the fracture gradient. A 10-barrel kick influx would raise ECD above the fracture gradient at the shoe, causing lost circulation. Casing must be set at or before 8,500 ft.

5. The Cementing-Casing Interface - Why Cement Failures Happen

A casing string with perfect mechanical design fails its primary purpose - zonal isolation - if the cement job is poor. The three most common cement failure modes after casing installation:

5.1 Micro-annulus

A hairline gap between the cement and casing OD that allows gas migration. Caused by pressure reduction in the casing after cementing - the casing contracts slightly as pressure drops from circulation to static. Prevention: maintain positive pressure on the casing for 8-12 hours after cementing until cement reaches compressive strength of at least 500 psi.

5.2 Mud Channels

Drilling mud left in the annulus due to poor displacement. Cement flows preferentially through the wide side of an eccentric annulus, leaving mud on the narrow side. Prevention: use centralizers to achieve 67%+ standoff, pump at turbulent flow regime (Reynolds number > 2,100 in the annulus), use spacers and chemical washes ahead of cement.

5.3 Gas Migration

Gas from a permeable formation migrates into the cement before it sets (while cement is still in the gel state). Creates channels that persist after cement hardens. Prevention: use compressive strength development additives, reduce fluid loss to <50 cc/30min for HPHT sections, design slurry density to overbalance formation gas pressure throughout the hydration period.

6. Casing Failure Modes - Causes and Prevention

Failure Mode	Root Cause	Detection Method	Prevention
Burst	Gas kick with inadequate BHP, tubing leak pressurizing annulus	Annulus pressure increase, LOT failure	Design SF >1.1, correct grade for worst-case kick scenario
Collapse	Evacuated casing during lost circulation, saltwater flow on outside	Reduced ID on caliper log, stuck pig	Design SF >1.0, never evacuate casing rapidly in high external pressure zones
SSC (sour)	High-strength grade in H2S environment	Sudden tensile failure, casing parting	Use L-80 or C-90 per NACE MR0175 when H2S partial pressure >0.05 psia
CO2 corrosion	Carbonic acid attack from dissolved CO2 in produced water	Pitting on inner wall, wall thickness loss	13Cr or 22Cr duplex stainless for high CO2 partial pressure (>30 psi)
Shear	Salt creep, tectonic movement, compaction	Stuck packer, abnormal completion loading	Increase wall thickness in mobile salt sections, use premium connections
Connection leak	Improper make-up torque, damaged threads, incompatible compound	Pressure test failure, annulus gas buildup	Certified thread inspection, calibrated power tong, premium metal-to-metal seal for critical strings

7. Offshore vs Onshore Casing Design - Key Differences

Design Element	Onshore	Offshore / Deepwater
Conductor setting	Driven or cemented to 30-100 ft	Jetted or drilled to 300-500 ft below mudline
Surface casing	Regulatory depth - below freshwater	Must handle riser loads and BOP weight - structural design critical
Wellhead	Surface wellhead - accessible	Mudline wellhead (deepwater) - ROV operated
Thermal effects	Minor - steady geothermal gradient	Significant - cold seawater at mudline creates large thermal gradient, casing must be designed for thermal expansion/contraction
Connection type	API buttress or LTC acceptable for most strings	Premium metal-to-metal seal connections required for production casing and liners
Running equipment	Standard casing elevators and slips	Casing running tools, torque turn monitoring, rotational running capability for centralization

Conclusion

Casing design is a cascade of decisions where each string constrains the options available for the next. The engineer who sets the surface casing too shallow forces a compromise on the intermediate casing setting depth. The engineer who selects P-110 for a mildly sour well creates an SSC risk that may not manifest for years. The engineer who accepts a poor cement job on the production casing creates an integrity problem that neither remediation nor regulatory compliance can fully resolve.

Get the pore pressure and fracture gradient right. Design each string for burst, collapse, and tension with appropriate safety factors. Select the grade that matches the chemical environment, not just the mechanical loads. And treat the cement job with the same rigor as the casing design - because a perfectly designed casing string with a poor cement job has failed before production ever starts.

Want to access our casing design calculation spreadsheet covering all three load cases with automated grade selection, or discuss a specific casing design challenge? Join our Telegram group for well construction discussions, or visit our YouTube channel for step-by-step casing design tutorials.