Page 248 - Petroleum Production Engineering, A Computer-Assisted Approach

Guo, Boyun / Computer Assited Petroleum Production Engg 0750682701_chap16 Final Proof page 246 21.12.2006 2:30pm

16/246 PRODUCTION ENHANCEMENT
Solution lution and reaction product precipitation. Fortunately,
research results have shown that acidizing efficiency is
Volume of CaCO 3 to be removed:
relatively insensitive to acid injection rate and that the
2
2
V m ¼ p r r ð 1 fÞC m highest rate possible yields the best results. McLeod
a
w
(1984) recommends relatively low injection rates based
2
2
¼ p 1:328 0:328 ð 1 0:2Þ(0:1)
on the observation that acid contact time with the forma-
3
¼ 0:42 ft CaCO 3 =ft pay zone tion of 2–4 hours appears to give good results. da Motta
(1993) shows that with shallow damage, acid injection rate
Initial pore volume:
has little effect on the residual skin after 100 gal/ft of
2
2
V P ¼ p r r f injection rate; and with deeper damage, the higher the
a w injection rate, the lower the residual skin. Paccaloni et al.
2
2
3
¼ p 1:328 0:328 (0:2) ¼ 1:05 ft =ft pay zone
(1988) and Paccaloni and Tambini (1990) also report high
Gravimetric dissolving power of the 15 wt% HCl solution: success rates in numerous field treatments using the high-
est injection rates possible.
y m MW m
b ¼ C a There is always an upper limit on the acid injection rate
y a MW a that is imposed by formation breakdown (fracture) pres-
(1)(100:1) sure p bd . Assuming pseudo–steady-state flow, the max-
¼ (0:15)
(2)(36:5) imum injection rate limited by the breakdown pressure is
¼ 0:21 lb m CaCO 3 =lb m 15 wt% HCl solution expressed as
6
Volumetric dissolving power of the 15 wt% HCl solution: q i, max ¼ 4:917 10 kh p bd p Dp sf , (16:6)

r a m a ln 0:472r e þ S
X ¼ b r w
r m
where
(1:07)(62:4)
¼ (0:21)
(169) q i ¼ maximum injection rate, bbl/min
3
3
¼ 0:082 ft CaCO 3 =ft 15 wt% HCl solution k ¼ permeability of undamaged formation, md
h ¼ thickness of pay zone to be treated, ft
The required minimum HCl volume p bd ¼ formation breakdown pressure, psia
p ¼ reservoir pressure, psia
V m
V a ¼ þ V P þ V m Dp sf ¼ safety margin, 200 to 500 psi
X m a ¼ viscosity of acid solution, cp
0:42
¼ þ 1:05 þ 0:42 r e ¼ drainage radius, ft
0:082 r w ¼ wellbore radius, ft
3
¼ 6:48 ft 15 wt% HCl solution=ft pay zone S ¼ skin factor, ft.
¼ (6:48)(7:48) The acid injection rate can also be limited by surface
¼ 48 gal 15 wt% HCl solution=ft pay zone injection pressure at the pump available to the treatment.
This effect is described in the next section.
The acid volume requirement for the main stage in a mud
acid treatment depends on mineralogy and acid type and
strength. Economides and Nolte (2000) provide a listing of 16.3.4 Acid Injection Pressure
typical stage sequences and volumes for sandstone acidizing In most acid treatment operations, only the surface tubing
treatments. For HCl acid, the volume requirement increases pressure is monitored. It is necessary to predict the surface
from 50 to 200 gal/ft pay zone with HCl solubility of HF injection pressure at the design stage for pump selection.
changing from less than 5% to 20%. For HF acid, the volume The surface tubing pressure is related to the bottom-hole
requirement is in the range of 75–100 gal/ft pay zone with flowing pressure by
3.0–13.5% HCl and 0.5–3.0% HF depending on mineralogy. p si ¼ p wf Dp h þ Dp f , (16:7)
Numerous efforts have been made to develop a rigorous
method for calculating the minimum required acid volume where
in the past 2 decades. The most commonly used method is p si ¼ surface injection pressure, psia
the two-mineral model (Hekim et al., 1982; Hill et al., 1981; p wf ¼ flowing bottom-hole pressure, psia
Taha et al., 1989). This model requires a numerical tech- Dp h ¼ hydrostatic pressure drop, psia
nique to obtain a general solution. Schechter (1992) pre- Dp f ¼ frictional pressure drop, psia.
sented an approximate solution that is valid for Damkohler
number being greater than 10. This solution approximates The second and the third term in the right-hand side of
the HF fast-reacting mineral front as a sharp front. Readers Eq. (16.7) can be calculated using Eq. (11.93). However, to
are referred to Schechter (1992) for more information. avert the procedure of friction factor determination,
Because mud acid treatments do not dissolve much of the the following approximation may be used for the frictional
formation minerals but dissolve the materials clogging the pressure drop calculation (Economides and Nolte, 2000):
pore throats, Economides and Nolte (2000) suggest taking 0:79 1:79 0:207
the initial pour volume (Eq. [16.5]) within the radius of treat- Dp f ¼ 518r q m L, (16:8)
mentastheminimumrequiredacidvolumeforthemainstage 1,000D 4:79
of acidizing treatment. Additional acid volume should be where
considered for the losses in the injection tubing string. r ¼ density of fluid, g=cm 3
q ¼ injection rate, bbl/min
m ¼ fluid viscosity, cp
16.3.3 Acid Injection Rate D ¼ tubing diameter, in.
Acid injection rate should be selected on the basis of L ¼ tubing length, ft.
mineral dissolution and removal and depth of damaged
zone. Selecting an optimum injection rate is a difficult Equation (16.8) is relatively accurate for estimating fric-
process because the damaged zone is seldom known with tional pressures for newtonian fluids at flow rates less than
any accuracy and the competing effects of mineral disso- 9 bbl/min.