WELL COMPLETION, WELL INTERVENTION/ STIMULATION, AND WORKOVER

1. WELL COMPLETION, WELL INTERVENTION/ STIMULATION, AND WORKOVER
Well completion means to prepare the well for production by installing the necessary
equipment’s into the well in order to allow the safe and controlled flow of HCS at the surface.
The high time of the well when engineer and personnel comes to decide whether to install the
Production casing in order to initiate the production at the surface or it should be abandoned.
Open Hole Well Completion
In an open hole well completion the production casing is just set above the pay zone, while the
entire deepen bottom of pay zone is left uncased.
Advantages
 Maximum exposure of pay zone
 Less pressure drawdown during flow
 No formation damage occurs due to cementing and perforation.
 Less formation damage
Disadvantages
Inability to plug off water or gas zones
 Inability to stimulate the separate zones within the productive zones
Cased Hole Completion
For the most common type of well completion today involves the cased hole completion, in
which the production casing and liner are cemented and perforated subsequently
 Select the sections of the pay zone we wish to produce
 Stimulate the separate pay zone from the well
 Multiple completion zones
After the well has been drilled it has to be completed and prepared for production
o A lot of equipment is installed in the well e.g.
 Production tubing
 Production packer (fixes the production tubing inside last set casing)
 Downhole safety valve (SCSSV)
 Etc.
o The reservoir has to be prepared for production
 Different solutions exists

2. Types Of Completion

3. Intelligent well completions
1. In these wells one can install valves and control lines which can control the production from
different zones in one well.
2. Need less wells
3. Control water production
–Water production is unwanted.
4. Using an intelligent well completion we can control the water production for instance by
closing zones or by reducing water injection in zones where there is large water cut.

4. WELL INTERVENTION
o During the production phase there can be several reasons for performing a live well
intervention operation:
⁻ Scale removal (salts forming in the well)
⁻ Azid stimulation (carbonates)
⁻ Removing sand/cleaning sand screens
⁻ Perform production logging to detect water producing formations that should be sealed
⁻ etc.
o Most common methods (wireline or coiled tubing)
FORMATION DAMAGE
Contact with a foreign fluid is the basic cause of Formation Damage. This foreign fluid may be a
drilling mud, a clean completion or workover fluid, a stimulation or well treating fluid, or even
the reservoir fluid itself if the original characteristics are altered.
Most oilfield fluids consist of two phases – liquid and solids. Either can cause significant
formation damage through one of several possible mechanisms.
Plugging Associated with Solids
Occurs on the formation face, in the perforation, or in the formation :

5. Weighting materials, clays, viscosity builder, fluid loss control material, lost circulation
materials, drilled solid, cement particles, perforating charge debris, rust and mill scale, pipe
dope, precipitated scale, etc.
• Large Solids (perforating tunnel, face of an open hole zone, face of natural or
created fracture or in fracture channel)
• Small Solids (may be carried for some distance into the pores)
• Solids Precipitated (scale or asphaltene/paraffin)
Plugging Associated with Fluid Filtrate
The liquid filtrate may be water containing varying types and concentrations of positive and
negative ions and surfactants. It may be a hydrocarbon carrying various surfactants.
The liquid is forced into porous zones by differential pressure, displacing or commingling with a
portion of the virgin reservoir fluids. This may create blockage due to one or more of several
mechanism that may reduce the absolute permeability of the pore, or restrict flow due to
relative permeability or viscosity effects.
Classification Of Damage
The numerous mechanisms that result in formation damage may be generally classified as to
the manner by which they decrease production :
• Reduced absolute permeability of formation – results fromplugging of pore channels
by induced or inherent particles.
• Reduced relative permeability to oil – resultss froman increase in water saturation or
oil-wetting of the rock.
• Increase viscosity of reservoir fluid – results from emulsions or high-viscosity treating
fluids.
Relates productivity loss to degree and depth of damage. The important point is that with radial
flow, the critical area is the first few feet away from the well bore

6. PERFORATING
OPTIMIZING FLUID FLOW
Factors that influence fluid flow through the perforations :
- Perforating Geometry
- Damaged zones around the wellbore
- Crushed zones around the perforation
- Differential pressure that exist when perforating
0.01
0.1
1
10
100
0 5 10 15 20 25
Radius of damaged zone beyond well bore, ft
ProductionRatebbl/day
Permeability of undamaged reservoir = 100 md
Formastion thickness 10 ft
Well bore radius 0.25 ft
Drainage Radius 500 ft
Oil Visosity 0.5 cp
Drawdown 53.6 psi
kd = 1 md
kd = 10 md
kd = 50 md

7. PERFORATING GEOMETRY
PLANNING AN EFFECTIVE PERFORATING JOB
To plan an effective perforating job, one must consider :
• Characteristic of the formation
• Completion type
• Well condition (type, size, condition of wellbore tubular goods)
• Wellbore hardware
• Wellbore fluids
• Depth Control
• Characteristic of the formation
Formation characteristic to be considered include : Depth, Lithology (sand, lime, dolomite),
pore fluid (gas, oil, water), fractured, and pressure.
Completion type
Three completion type will be considered :
1. Natural Completions
No stimulation or sand control
The Order of importance of the perforating geometrical factor is :
1. Shot Density
2. Penetration Depth
3. Gun Phasing
4. Perforation Diameter
2. Sand Control
In unconsolidated formations, sanding can occur if there is an appreciable pressure drop
between the formation and wellbore. Since this pressure drop is inversely proportional to the

8. perforating cross section, the probability of sanding can be minimized by maximizing the total
perforated area. This is controlled primarily by shot density and perforation diameter.
The Order of importance of the perforating geometrical factor is :
1. Perforation Diameter
2. Shot Density
3. Gun Phasing
4. Penetration Depth
3. Stimulation
Stimulation operations involve acidizing and hydraulic fracturing. The object is to increase the
size and number of path by which fluid can flow from the formation to the wellbore. Both
operation – acidizing and fracturing – require that large amount of fluid be pumped under high
pressure into formation.
The Order of importance of the perforating geometrical factor is :
1. Perforation Diameter
2. Shot Density
3. Gun Phasing
4. Penetration Depth
STIMULATION
- Acidizing
- Fracturing
ACIDIZING TECHNIQUES
Three Fundamental techniques used in acidizing treatment :
1. Wellbore Cleanup
This entails fill-up and soak of acid in the wellbore. Fluid movement is at minimum unless
some mechanical means of agitation is used.

9. 2. Matrix Aciding
This is done by injecting acid into the matrix pore structure of the formation, below the
fracturing pressure. Flow pattern is essentially through the natural permeability structure.
3. Acid Fracturing
This is injection into formation above fracturing pressure. Flow pattern is essentially
through hydraulic fracture; however, much of the fluid does leak off into matrix along the
fracture face.
FORMATION FRACTURING
The objective of hydraulic fracturing for well stimulation is to increase well productivity by
creating a highly conductive path (compare to reservoir permeability) some distance away
from wellbore into the formation.
Fracture Initiation
A hydraulic fracture treatment is accomplished by pumping a suitable fluid into the
formation at a rate faster than the fluid can leak off into the rock. Fluid pressure is built up
sufficient to overcome the earth compressive stress holding the rock material together. The
rock then parts or fractures along a plane perpendicular to the minimum compressive stress
in the formation matrix.
Fracture Extension
As injection of frac fluid continues, the fracture tends to grow in width as fluid pressure in
the fracture, exerted on the fracture face, works against the elasticity of the rock material.
After sufficient frac fluid ‘pad’ has been injected to open the fracture wide enough to accept
proppant, sand is added to the frac fluid and is carried into the fracture to hold it open after
the job.
The growth upward or downward may be stopped by a barrier formation; downward
growth may also be stopped by fallout of sand to the bottom of the fracture. The growth
outward away from the wellbore will be stopped when the rate of frac fluid leakoff through
the face of the fracture into the formation equals the rate of fluid injection into the fracture
at the wellbore.

10. Horizontal Fracture
Assuming vertical components of force are exerted against the formation, the condition
necessary for horizontal fracture initiation is that the wellbore pressure must exceed the
vertical stress plus vertical tensile strength of the rock plus pore pressure.
Vertical Fracture
Condition for vertical fracture initiation depend on the relative strength of the two principal
horizontal compressive stresses.
Fracture Propagation
Fracture Orientation
The fracture will propagate in a plane perpendicular to the minimum effective matrix stress.
Usually the minimum stress is horizontal, and a vertical fracture results.
Where horizontal matrix stress are unequal, there will be a preferred direction for the vertical
fracture.
Fracture Closure Pressure
To hold the fracture open after initiation (or to just keep it from closing), the pressure in the
fracture must exceed the pressure by an amount equal to the minimum effective rock matrix
stress. This pressure is usually called the fracture closure pressure. The fracture gradient is the
fracture closure pressure divided by depth.

11. Fracture Propagation Pressure
As the fracture is extended, the pressure in the fracture at the wellbore (fracture propagation
pressure) increases as a result of fluid friction required to push the frac fluid through an
increasing distance toward the tip of the fracture.
Other factor that can increase fracture propagation pressure is the increasing of pore pressure
in the rock near the fracture due to fluid leakoff (also increased closure pressure).
Net Fracture Pressure
Pressure in the fracture in excess of the fracture closure pressure is the net fracture pressure.
Net fracture pressure acts against the elasticity, or Young’s modulus, of the rock to open the
fracture wider.
During the fracture job, the net fracture pressure (Nolte Plot) can be used as an indicator of
fracture extension
Fracture Propagation Pressure
As the fracture is extended, the pressure in the fracture at the wellbore (fracture propagation
pressure) increases as a result of fluid friction required to push the frac fluid through an
increasing distance toward the tip of the fracture.
Other factor that can increase fracture propagation pressure is the increasing of pore pressure
in the rock near the fracture due to fluid leakoff (also increased closure pressure).
Net Fracture Pressure
Pressure in the fracture in excess of the fracture closure pressure is the net fracture pressure.
Net fracture pressure acts against the elasticity, or Young’s modulus, of the rock to open the
fracture wider.
During the fracture job, the net fracture pressure (Nolte Plot) can be used as an indicator of
fracture extension
Propping the Fracture
The objective of propping is to maintain desired fracture conductivity economically.
Fracture conductivity depends upon a number of interrelated factors :
• Type, size, and uniformity of the proppant
• Degree of embedment, crushing, and or deformation of proppant
• Amount of proppant
• Manner of placement
Desirable Properties For Propping Agents
• Size and Uniformity
• Strength
• Physical Properties (Acid solubility, roundness, and density)
• Cost

12. Frac Fluids
Basically oil or water fluids are used to create, extend, and place proppant in the fracture.
Fluid Properties and Modification
Frac fluid consideration :
• Fluid viscosity
• Fluid loss
• Friction loss (down the pipe)
• Proppant carrying ability
• High temperature stability
• Formation damage
• Fracture clean up
• Mixing and storage problems
• Cost
Frac Job Design
1. Select the right well
Consider the risks involved – condition that increase risks are :
• Less than 15-20 ft of shale between the frac interval and gas or water sand.
• Others things being equal fractures tends to move upward due to sand fallout to
the bottom of the fracture – sometimes this effect can be maximized.
• Water or gas contact nearby and located in a direction so that fracture would go
toward it.
• Well producing high GOR or WOR are poor candidates for fracturing unless it is
free gas or water from a zone which can be shut off.
2. Design for the specific well
Design parameter to be considered are :
• Lithology and mineralogy of the formation
• Fracture geometry parameters (Young’ modulus, Poisson’s ratio, formation
boundary horizontal matrix stress)
• Reservoir fluids and reservoir pressure/energy
• Physical well configuration
3. Optimize design over several jobs
Usually the experience gained in several carefully designed and evaluated jobs is necessary to
achieve optimum design.
4. Utilize calculation procedures as a guide
Treatment design must specify the following parameters :
⁻ Frac fluid type
⁻ Fluid volume
⁻ Fluid viscosity and fluid loss schedule
⁻ Proppant size and type

13. ⁻ Proppant schedule
⁻ Injection rate schedule
Basic design procedures :
⁻ Determine required fracture length and conductivity
⁻ Determine frac fluid characteristic and injection rates
⁻ Determine a treatment pumping and proppant injection schedule
⁻ Computerization speeds calculation procedures
Hydraulic Fracturing Equipment
• Fluid storage
• Proppant storage
• Blender
• Primary high pressure pumps
• The Operational control centre
Frac Job Evaluation
To evaluate the success of a frac treatment and help design succeeding treatments, it is
necessary to know :
• What sustained production increase was obtained
• What zone or zones were actually stimulated.
• For vertical fractures, what was the fracture height and azimuth.
• What was the fracture length
• What was the fracture conductivity
WORKOVER
Different / moving test zone
ZONE ISOLATION
SQUEEZE CEMENTING
PACKERS

14. Squeeze Cementing - Definition
Injection of Cement Slurry
into the voids behind the
casing
Dehydration of cement
requires: fluid fluid-loss, porous
(permeable) matrix,
differential pressure, time.
Injection below or above
fracture pressure
Squeeze Cementing - Job Cycle
Design
• Well conditions
• Slurry properties
Execution
• Slurry placement
• Surface pressures
• Equipment
Evaluation
• Final squeeze pressure
• Pressure test
• Inflow test
• Logs
PACKERS
Objectives
All packers will attain one or more of the following objectives when they are functioning
properly :
1. Isolate well fluids and pressure.
2. Keep gas mixed with liquids, by using gas energy for natural flow.
3. Separate producing zones, preventing fluid and pressure contamination.
4. Aid in forming the annular volume (casing/tubing/packer) required for gas lift or
subsurface hydraulic pumping systems.
5. Limit well control to the tubing at the surface, for safety purposes.
6. Hold well servicing fluids (kill fluids, packer fluids) in casing annulus.
Tubing-To-Packer Connections
There are three methods of connecting a packer and a tubing strings, and the tubing can be set
in :
1. Tension
2. Compression
3. Left in natural (no load on the packer, tension nor compression)

15. Packers Classification
1. Retrievable
2. Permanent or semi permanent
Consideration for Packer Selection
1. Surface/Downhole Equipment Coordination
2. Packer Mechanics
3. Corrosive Well Fluids
4. Sealing Element
5. Retrievability
6. Fishing Characteristic
7. Through Tubing Operation
8. Purchase Price
References
From many sources (Dari berbagai Sumber)