8. Production Considerations.

1. Is the well's production decline curve typical for the field.

2. What is the current gas/oil ratio (GOR). Has this changed with time.

3. What is the current water/oil ratio . Has this changed with time.

4. Has the water/oil ratio changed with total produced fluid remaining the
same.

5. Has the API gravity of the crude oil changed.

6. What is the current asphaltene content of the crude oil. Has this
changed with time.

7. What is the current paraffin content of the crude oil. Has this changed
with time.

8. Have paraffins or asphaltenes been known to accumulate at any time
in the flow lines, surface equipment, production string, or perforations.

9. Have scale deposits been found. If so, where and what type.

10. Has formation sand been produced.

8.1 Production Curves.

As water increases:

• · Formation fines plugging occurs.
• · Chloride content increases, resulting in the nucleation and deposition of acid-insoluble organic deposits.
• · Maltenes are stripped due to their lower melting point than that of the host asphaltene molecule, resulting in asphaltene deposition.
• · Higher probability of the formation of mineral salts.

Sudden Decline:

• · Mechanical Failure.
• · Fines Migration

Water increases, oil decreases, but total fluids remain the same:

• · Chemically altered wettability1.
• · Acid insoluble organic deposition1.
• · Depletion.

Increasing GOR with associated drop in API Gravity:

• · Acid insoluble organic deposition.

8.2 Bottom Hole Temperature Design Factors.

1. Select acid strength according to Maximum Strength recommended
(see Table , page 21).

2. Acid reaction rate is exponential with temperature therefore, there is a
very high potential for acid attack of tubulars.

3. High temperature acidizing can result in wettability damage from
corrosion inhibitors and surfactants. Use mutual solvents in the
preflush. (EGMBE, INFLO-40).

4. Live acid penetration is reduced in high temperature wells due to
increased acid reaction rates. This can create problems of reduced
near wellbore permeability as a result of compressive strength
reduction. This is caused by the total removal of the matrix binder in
the formation ( for example; carbonates, silicates, clays etc.).

5. Damage from reaction precipitates is more likely in high temperature
wells.

6. Chlorination of mutual solvents can occur at bottom hole temperatures
above 200° F (93° C). Reduced acid strengths at these conditions will
minimise this potential.

7. Corrosion inhibitor concentrations are critical at higher temperatures.
Reduce the contact time and cool down the well whenever possible.

8. Acid contact times in the near wellbore area should be no more than
four hours at low temperatures (less than 180° F (82° C)). At higher
temperatures, contact times should be limited to the time required to
prepare the well for flow back