Casing Design

Casing Design Why Run Casing? Types of Casing Strings Classification of Casing Burst, Collapse and Tension Effect of Axial Tension on Collapse Strength These next two lessons will discuss casing. What it is, why we run it, types of strings, how it is classified, and the stresses we design for.

Casing Design What is casing? Casing Cement Why run casing? 1. To prevent the hole from caving in 2. Onshore - to prevent contamination of fresh water sands 3. To prevent water migration to producing formation Casing is steel pipe that is run into the wellbore and usually cemented in place. There are several reason for this and they are listed in this slide and the next one.

Casing Design 4. To confine production to the wellbore 5. To control pressures during drilling 6. To provide an acceptable environment for subsurface equipment in producing wells 7. To enhance the probability of drilling to total depth (TD) e.g., you need 14 ppg mud to control a lower zone, but an upper zone will fracture at 12 lb/gal. What do you do?

Types of Strings of Casing Diameter Example 16”-60” 30” 16”-48” 20” 8 5/8”-20” 13 3/8” 1. Drive pipe or structural pile {Gulf Coast and offshore only} 150’-300’ below mudline. 2. Conductor string. 100’ - 1,600’ 3. Surface pipe. 2,000’ - 4,000’ “Typical” casing size combination and setting depths. Through surface casing for an offshore well. A land well would generally start with the conductor string and not use drive pipe.

Types of Strings of Casing Diameter Example 4. Intermediate String 5. Production String (Csg.) 6. Liner(s) 7. Tubing String(s) 7 5/8”-13 3/8” 9 5/8” 4 1/2”-9 5/8” 7” It may require several strings of casing to get to total depth. The size of the production string is dependent on the size of production tubing, the number of tubing strings, and what other equipment will be installed in the well for production.

Example Hole and String Sizes (in) Hole Size Pipe Size 36” 26” 17 1/2 12 1/4 8 3/4 Structural casing Conductor casing Surface casing Intermediate casing Production Liner 30” 20” 13 3/8 9 5/8 7 Graphical representation of casing combination. You can see from this slide, that every time another casing string is installed, the hold diameter gets smaller. Which means that the larger the production casing required, and the more casing strings needed, the larger the hold size that would be required to begin with.

Classification of CSG. 1. Outside diameter of pipe (e.g. 9 5/8”) 2. Wall thickness (e.g. 1/2”) 3. Grade of material (e.g. N-80) 4. Type to threads and couplings (e.g. API LCSG) 5. Length of each joint (RANGE) (e.g. Range 3) 6. Nominal weight (Avg. wt/ft incl. Wt. Coupling) (e.g. 47 lb/ft) Casing is classified by a number of criteria.

The grade of casing represents the minimum yield strength The grade of casing represents the minimum yield strength. Remember strength and materials class. The plot shows a typical strength test for a material. The red straight line portion shows that the strain and stress are directly proportional. When the stress is released, the length will go back to original. However, at some point the material will undergo permanent deformation then failure. The yield strength is the point in which permanent failure deformation occurs, and the ultimate tensile strength is failure. For safety, we designate the grade of steel by a minimum yield strength, which is lower than the ultimate tensile strength. We do not want permanent deformation to occur. s e

Casing Threads and Couplings API round threads - short { CSG } API round thread - long { LCSG } Buttress { BCSG } Extreme line { XCSG } Other … See Halliburton Book... There are a number of different types of threads cut on casing. Here are common threads with API 8 rd the most common.

Burst, Collapse, and Tension When we design casing, it must be designed to withstand the maximum burst pressure, collapse pressure, and tensile forces that we anticipate that the casing will ever be exposed to. We then increase this by design factors. Casing is way over designed. Why? It will be exposed to hostile treatment from rotation of the drillstring inside it, pressures imposed on it from the inside and outside, and tension forces from changing internal pressures, external pressures, and changing temperatures during treatment and production. It will also be called upon to keep formation fluids in place long after in the well is plugged and abandoned.

API Design Factors (typical) Required 10,000 psi 100,000 lbf Design 11,250 psi 180,000 lbf 11,000 psi Collapse 1.125 Tension 1.8 Burst 1.1 The API recommends using the above design factors. These design factors are safety factors. First we predict the burst, collapse, and tension that we anticipate, and multiply the anticipated numbers by the design factors to determine the stresses we that the casing must be able to withstand.

Abnormal Normally pressured wells do not require the as many strings of casing to reach TD as an abnormally pressured well. Normal Pore Pressure Abnormal Pore Pressure 0.433 - 0.465 psi/ft gp > normal

Casing Design Tension Tension Depth Burst Collapse Collapse STRESS The API recommends that casing be designed to withstand the maximum anticipated formation pressure that the casing string could possibly be exposed to times the design factor from top to bottom, and no backup pressure on the outside. This is represented by the yellow line. The red line represents collapse pressure that may be imposed on the outside of the casing. API recommends that collapse at the bottom of the casing be designed to withstand the maximum mud density that will be in the wellbore when that particular string is run. The HSP imposed by the mud is multiplied by the design factor to determine the pressure requirement to design for. Worst case scenario calls for the collapse pressure applied to the outside of the casing with no pressure on the inside. The blue line represents tension. Once the casing is designed for burst and collapse. The weight of the casing in air is calculated, multiplied by the design factor for tension, and compared to the tension rating of the connection and pipe body at the top of the casing. Burst: Assume full reservoir pressure all along the wellbore. Collapse: Hydrostatic pressure increases with depth Tension: Tensile stress due to weight of string is highest at top Burst

Casing Design Unless otherwise specified in a particular problem, we shall also assume the following: Worst Possible Conditions 1. For Collapse design, assume that the casing is empty on the inside (p = 0 psig) 2. For Burst design, assume no “backup” fluid on the outside of the casing (p = 0 psig) We design for worst possible cases, and they are defined here.

Worst Possible Conditions, cont’d Casing Design Worst Possible Conditions, cont’d 3. For Tension design, assume no buoyancy effect 4. For Collapse design, assume no buoyancy effect The casing string must be designed to stand up to the expected conditions in burst, collapse and tension. Above conditions are quite conservative. They are also simplified for easier understanding of the basic concepts.

Casing Design - Solution Burst Requirements (based on the expected pore pressure) The whole casing string must be capable of withstanding this internal pressure without failing in burst. Depth Pressure

Casing Design - Solution Collapse Requirements For collapse design, we start at the bottom of the string and work our way up.

Tension Check The weight on the top joint of casing would be With a design factor of 1.8 for tension, a pipe strength of

Casing Various Types of Casing Conductor pipe (A): Size 18-5/8” & over. Outer protection of the well to prevent the surface formation from caving into the well Surface casing (B): To avoid contamination to surrounding surface water or to protect from a well collapsing caused by free running water. Intermediate casing (C): Used in the area where abnormally high pressure structure encountered. It is for extra-strengthened protection of a well. Liner casing (E): Same usage as intermediate casing but not run from the surface. It hangs from the preceding with 100-150 meter overlaps. Production casing (D): Placed at the production zone. Since the lower part is exposed to fluid and gas, it may be exposed to corrosion. Proper material selection is needed. This casing is used as a second containment barrier (the first one is the production tubing) hence connection leak tightness is important. Pressure gradients A B Fracturation Gradient C Pore pressure Gradient D E

Example of Typical String Design Conductor 20” Surface casing 13-3/8” Intermediate casing 9-5/8” Packer (Tie Back string) Liner casing 7” Tubing 3-1/2” Production casing 5-1/2” Reservoir zone