Primary Cementing

Primary Cementing

Sealing the Annular space between Casing and the wellbore:

to isolate and contain productive, problematic or weak intervals

to support & protect Casing Strings

to insulate Geothermal & Thermal wells

Core Process used throughout the world

Primary Cementing Evaluation

Primary Cementing - Casing

Conductor

Surface

Intermediate

Production

Liners

Tie-back

Conductor Casing

Purpose:

Confines circulating fluids

Prevents washing out under rig

Provides elevation for flow nipple and bell nipple

BOP are usually not attached to conductor casings.

Conductor Casing

Characteristics:

Set from 40 to 1500 feet

Casing is large; 16-in to 36-in diameter

Hole may be eroded severely

Casing can be pumped out easily and must be tied down

Conductor Casing

100 to 200% excess cement is common

Low mud density

May require a low density cement

Cool temperatures

Centralization?

Conductor Casing

Surface Casing

Fresh Water Sand

Surface Casing

Purpose:

Protect water sands Case unconsolidated formations Provides primary pressure

control (BOP usually nippled up on surface casing)

Supports subsequent casings Case off loss circulation zones

Characteristics: Set from 40 to 4500 feet

Casing may stick easily in unconsolidated formations

Loss of circulation may be a problem

Most areas require that cement be circulated

Guide shoe, or float shoe, and float collar commonly used

Surface Casing

Common sizes: 20-in to 8 5/8-in 100 to 150% excess cement

Usually a lightweight filler cement followed by a tail cement (20% of

casing length or 300 ft minimum)

WOC time, cement performance and centralization requirements

are regulated in many areas

Surface Casing

Remarks:

Often cemented through drill pipe with sealing sleeve (stab-in)

Top and Bottom plugs should be used because of high mud

viscosities

Bottom joints should be centralized and thread locked to

prevent loss down hole

Surface Casing

Stage Cementing

Stage Tool

Fresh Water Sand

Multiple Stage

Cementing Tool

(DV)

Why?

Potential casing collapse due to hydrostatic pressure of a full column of cement

Cover weak zones on first stage to insure cement returns to surface

Large volumes of cement

Deep holes that require cement to surface

Stage Cementing

Intermediate Casing

Intermediate Casing

Purpose:

Cases off loss circulation zones, water flows, etc.

Isolates salt sections

Protects open hole from increase in mud weight

Prevents flow from high-pressure zones if mud weight must be reduced

Basic pressure control casing BOP always installed

Supports subsequent casings

Common sizes: 16-in to 7-in

25 to 100% excess cement

Cement coverage is generally back to surface

Usually a lead and tail cement

Cement density depends on frac pressure limitations

WOC time, cement performance and centralization requirements are

regulated in many areas

Intermediate Casing

Production Casing

Productive

Interval

Purpose:

Conduit for Completion String

Provides pressure control

Cover worn or damaged intermediate casing

Production Casing

Liners - Cementing Methods

Single stage:

Circulate cement to top of liner - reverse

excess

Single stage:

Circulate excess cement 10-12 joints above

liner- drilled cement after setting

Planned squeeze (Tack and Squeeze):

Lower part cemented - Top part squeezed later

Drilling Liner

Liner Overlap

Weak Zone

Production Liner

Production

Interval

Production

Interval

Tie-Back Casing

Production

Tie-Back

Production

Interval

Production

Liner

Tie Back Casing

Purpose:

To extend Production casing to surface for maximum pressure control

Serves as production casing

Covers worn or damaged intermediate casing

Permits testing well before installing final casing

Cases off exposed liner tops

Horizontal Wellbore

Productive Interval

Well Types

Oil & Gas Producers

Injection Wells

Gas Storage Wells

Salt Water Disposal Wells

Hazardous Waste Disposal Wells

Fresh Water Wells

Geothermal Wells

Mine Shafts

GAS Migration

Prevention of Annular Gas Migration

Types of Gas Migration

Under-balanced annular fluids: Influx not controlled prior to or during cementing

Influx is generally right away

Cement volume shrinkage during initial setting phase:

Influx is generally seen in four (4) to twelve (12) hours after

cementing

Problem may be solved if the casing annulus is shut-in, pressure is applied to the annulus, or other techniques are applied

Types of Gas Migration (cont.)

Micro-Annulus: Pressure is normally seen 12-36 hours after cementing

High Permeability Cement: Pressure is usually seen in a few days to weeks

It may take a long time for gas to reach the surface

Stress cracking of the cement sheath: Pressure may occur over a long time period (months - years)

Considerable testing is ongoing

Test Procedures

Regular Fluid Loss Cell

Modified Fluid Loss Cell

Transition Time

Gel Strength Development

0 gel strength

Transition Time (100 to 500 lbs. Per 100 sq. ft.)

Test Procedures (cont.)

Various Gas Flow Models:

BJs Gas Flow

Dowells Gas Flow

Halliburtons Gas Flow

Elfs Gas Flow

Shells Gas Flow