Chilingarian G.V. et al. Surface Operations in Petroleum Production, II
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185
TABLE
5-VII
Different acidizing solutions (After Hendrickson, 1972, table
1,
p.
312, in: Chilingar et
al.,
1972; courtesy
of the American Elsevier)
Concentration
(%)
Pounds of Relative reaction
and type
of
acid CaCO, equivalent to time
a
1000
gal
of
acid
7.5 HCl
15 HCl
28 HCl
36 HCI
10
Formic
10 Acetic
15 Acetic
14 HCl
14 Acetic
8
90
1840
3610
4860
910
710
1065
2420
2380
1700
0.7
1.0
6.0
12.0
5.0
12.0
18.0
6.0
12.0
18.0
a
Approximate time for acid reaction to be completed (“spent”) to an equivalent strength of 1.5% HCl
solution. Comparative values will vary depending on reaction conditions.
the required optimum acid volumes. Information obtained from other acid treat-
ments in the nearby areas and in similar formations should also be used. In the case
of
absence of such information and laboratory test results, acid volumes around
100-200
gal/ft of treated interval can be used (rule
of
thumb).
The following formula is recommended by the writers for the determination
of
TABLE
5-VIII
Injection rates and bottomhole differential pressures required
to
produce different depth of penetration
during matrix acidizing (After Hendrickson et al., 1960, p. 17, table
1;
courtesy of the Society of
Petroleum Engineers of AIME)
Desired penetration
{ft) indicated formation permeabilities
Necessary minimum injection rate and pressure differential at
5
md
100
md
0.5
1
5
0.56 bbl/min/ft 0.26 bbl/min/ft
26,800 psi
624 psi
1.7 bbl/min/ft 0.17 bbl/min/ft
117,000 psi
2710 psi
-
14.2 bbl/min/ft
94,000
psi
186
surface area per unit of pore volume,
sp,
of consolidated rocks in cm2/cm3
(Chilingar et al., 1963):
(5-17)
where
F
=
formation resistivity factor,
k
=
permeability in md, and
@
=
fractional
porosity of the rock.
For unconsolidated sands, Langnes et al. (1972, p. 247) proposed the following
formula for determining the surface area per unit of bulk volume,
sb,
in cm2/cm3:
sb
=
5650
(
@3/k)0’5
(5-18)
where
@
=
the fractional porosity and
k
=
permeability in darcys.
FRACTURE
ACIDIZATION-DESIGN
As
pointed out by Williams et al. (1979, p. 53) in their excellent monograph, the
selection of the first candidate well is an important step in designing an acid
fracturing treatment. In a particular reservoir, the first selected well should give the
greatest productivity increase with minimal down-side risk.
A
reservoir study,
including pressure buildup tests, are required, therefore,
so
that a proper acid
fracture treatment can be designed and priority list for stimulation established.
Much of the material on the design of the fracture treatment has been included in
Chapter 4 entitled “Fracturing”. The design of an acid fracture treatment involves
the following steps: (1) selection
of
fracturing fluid to be used as pad, injection rate,
etc., (2) determination of formation rock and fluid properties, (3) prediction
of
the
fracture geometry, (4) prediction
of
distance of acid penetration of the fracturing
fluid and acid,
(5)
prediction of the fracture conductivity, (6) prediction of stimula-
tion ratio, and (7) a thorough economic study (see Williams et al., 1979). If
improvement in the production occurs in a reasonable payout time, job can be
considered successful.
If propping agents are used in fracture acidizing, they limit the injection rates to
some extent, and the distance penetrated by the acid before it is spent is less.
Formation heterogeneity (differences in composition, solubility, and reaction rate)
usually causes irregularities on the face of the acidized fracture. This prevents the
fracture from closing completely (“healing”) when the pressure is released.
As
a
result of fracturing, the surface area into whch the fluids enter the wellbore is
greatly increased.
Widening the preexisting fractures by acidizing results in a decrease in the
surface area (i.e, surface area per unit of grain, bulk, or pore volume).
As
a result,
spending time of the acid is increased with consequent increase in the penetration
distance of acid before it is spent.
187
SAMPLE
QUESTIONS
AND
PROBLEMS
'
(1)
List the types of acids used in well stimulation operations. Explain the
(2)
What are the applications of acids in oilfield operations? Discuss in detail.
(3)
List and discuss the main types of acidizing techniques.
(4)
Explain the sources
of
well damage in detail.
(5)
What kind of acid is used most widely in treating carbonate formations?
Explain why. Give typical acid-carbonate reactions.
(6) Explain why hydrochloric acid alune is rarely used in treating sandstones (it is
used only when sandstone has a high calcite content). What type of acid is most
widely used in sandstone acidizing? Give typical reactions.
(7)
Discuss the factors that affect the acid penetration distance in an acid-fractur-
ing treatment.
(8)
What are the steps in designing a successful acid fracturing treatment?
Explain each one in detail.
(9)
What are the purposes of using additives in acidizing operations? Name at
least three additives for each purpose.
(10)
List and discuss the factors that should be considered in economic evalua-
tion of acidizing treatments.
(11)
Calculate the surface area per unit of pore volume of a carbonate rock
having porosity of
15%,
permeability
of
8
md, and cementation factor
(m)
of
2.
Use
different equations and compare the results.
(12)
What effect does enlargement of pores have on acid velocity and on
surface/volume ratio? Are these effects opposite in significance or not? Explain!
(13)
How much deeper would later increments of acid penetrate before being
spent? Why?
(14)
On using stronger acid, does spending time increase or decrease? Why?
(15)
Is
the spending time of the acid lower or higher in the case of lower specific
surface area? Why?
(16)
Is
sludge formation more or less likely with stronger acid? Why? How can it
be prevented?
(17)
How are acid volumes and pumping rates determined for acidizing oper-
ations.
(18)
During matrix acidizing, what promotes formation of small-diameter
wormholes.
(19)
A skin factor of +6 was calculated from a pressure buildup test conducted
in a 6000-ft deep oilwell. The formation is known to be an arkosic sandstone having
25
ft net thickness. Average formation permeability was calculated to be
40
md, and
advantages and disadvantages of each one.
'
The
help extended
by
Mehmet Parlar
in
preparing this section is indeed greatly appreciated
by
the
writers.
188
the formation temperature is known to be 200
OF.
Engineers decided to stimulate
this well by an acid treatment. The following information is also available: (1) Oil
viscosity at reservoir conditions
=
5
cP;
(2)
well drainage area=
20
acres; (3)
fracture gradient at current reservoir pressure is estimated to be
0.7
psi/ft; (4) the
overburden pressure gradient
=
1.0
psi/ft;
(5)
the wellbore radius
=
4.5
in.; and (6)
current reservoir pressure
=
2000
psi. (Consult Craft et al., 1962.)
Determine:
0.57
cP, without fracturing the formation.
pressure gradient of the acid is 0.465 psi/ft? Neglect the frictional losses.
estimated to be
11
in.
(a) The maximum injection rate that can be used
if
the acid viscosity
at
200
O
F
is
(b) The maximum surface injection pressure without fracturing
if
the hydrostatic
(c) Volume (in gallons) of mud acid required
if
the radius of damaged zone is
(d) Volume of acid (15% HC1) required for preflush?
(e) The increase in productivity due to acidizing if the well is tested again after
the stimulation job and the skin factor is calculated to be
-2.
(f)
What would have been the stimulated/natural permeability ratio
if
the acid
has increased the permeability out to a distance of 6.5 in. from the wellbore.
(g)
The maximum depth of permeability increase
if
the total mud acid volume to
be used is economically limited to
5000
gal.
(h) The stimulated/damaged permeability ratio, if the skin factor after acidizing
is
-2
[assume same conditions as in
(g)].
(i) The skin factor after acidizing,
if
the production rate has been increased by a
factor of
2
as a result of acidizing [assume same conditions as in (g)].
(20)
Matrix acidizing is used in treating a dolomite formation. The following
information is available: (1) formation depth
=
7000
ft,
(2)
net formation thickness
=
25
ft,
(3)
formation permeability
=
20
md, (4) porosity
=
0.13,
(5)
fracture gradi-
ent
=
0.65 psi/ft, (6) the current reservoir pressure
=
2500
psi,
(7)
overburden
pressure gradient
=
1.0
psi/ft,
(8)
well drainage area
=
40 acres, (9) the wellbore
radius
=
3 in., (10) acid viscosity at reservoir temperature
=
0.5
cP, and
(11)
hydro-
static pressure gradient of the acid
=
0.45
psi/ft.
Determine:
(a) The maximum injection rate that can be used without fracturing the forma-
tion.
(b) The maximum surface injection pressure that can be applied without fractur-
ing the formation. Neglect the frictional losses.
(c) The distance of acid penetration until it is spent, assuming an injection of 100
gal of
15%
HC1 per foot of treated interval at an injection rate of 90% of the
maximum. Acid spending time
=
20 sec.
(d) The weight of dolomite treated by the acid.
(e) The acid penetration distance under the conditions of question (c), if the acid
(f)
The hydraulic horsepower required,
if
the frictional pressure loss is-psi/ft.
(21)
A zone is going to be stimulated by matrix acidizing using acid having a
specific gravity of 1.09. Calculate the maximum allowable surface pressure if the
spending time is retarded to 40 sec.
189
frictional pressure drop is 600 psi and the fracture gradient is 1.0 psi/ft. Depth of
the treated zone
=
9000
ft.
(22)
A
50-ft producing section of pure limestone with a porosity of 0.18 has been
acidized to increase the matrix permeability. The well radius is 6 in.
Determine:
(a) How many gallons of 16.5% HCI (spending time
=
15
sec
and sp. gr.
=
1.075)
would dissolve
900
Ib of limestone?
(b) What would be the pumping rate in bbl/min for this acid to penetrate a
radial distance of 1.5 ft before it is spent.
(c)
If
the producing section contains
90
preexisting fractures at the wellbore, the
average width of the fractures is
0.005
in., and the spending time is 50 sec, calculate
the depth of penetration
of
the unspent acid.
(23)
Determine the approximate spending time of an acid given the following:
(a) Fracture width,
w
=
0.005
in.
(b) Channel or openhole diameter,
d=
0.01 in.
(c) Relative spending time of acid,
c,
=
1.0 sec.
(d) Formation temperature,
T
=
150
OF.
REFERENCES
Chapman, M.E., 1933. Some of the theoretical and practical aspects of the acid treatment
of
limestone
Chilingar,
G.V.,
Main, R. and Sinnokrot, A,, 1963. Relationship between porosity, permeability, and
Chilingar,
G.V.,
Mannon, R.W. and Rieke
111,
H.H., 1972.
Oil and Gas Production from Carbonate Rocks.
Craft, B.C., Holden,
W.R.
and Graves Jr., E.D., 1962.
Well Design: Drilling and Production.
Prentice-Hall,
CRC, 1980-1981.
Handbook of Chemistry and Physics.
CRC Press, Inc., Boca Raton, Florida.
Crowe, C.W., 1971.
Evaluation of Oil Soluble Resin Mixtures as Diverting Agents for Matrix Acidizing.
SPE Paper
No.
3505,
presented at the SPE-AIME
46th
Annu. Fall Meet., New Orleans, Oct. 3-6.
Dunlap, P.M., 1966. Acidizing subterranean formations.
U.S.
Patent
No.
3,254,7I8
(June 7).
Foshee, W.C. and Hurst, R.E., 1965. Improvement of well stimulation fluids by including a gas phase.
J.
Frasch, H., 1896. Increasing the flow of oil wells.
US.
Patent
No.
556,669
(Mar. 17).
Gallus, J.P. and Pye, D.S., 1969. Deformable diverting agent for improved well stimulation.
J.
Pet.
Technol.,
21(4): 497-504 (also in
Trans. AZME,
246: 497-504).
Hall, B.E., 1975. The effect of mutual solvents on adsorption in sandstone acidizing.
J.
Pet. Technol.,
27(12): 1439-1442.
Harp,
L.J.
and Dobbs, J.B., 1967.
The Family
of
Acids Used in Reservoir Stimulation,
The Western
Company,
Fort
Worth, Tex., 16 pp.
Hendrickson, A.R., 1972. Stimulation
of
carbonate reservoirs. In:
G.V.
Chilingar, R.W. Mannon and
H.H.
Rieke
111
(Editors),
Oil and Gas Production from Carbonate Rocks.
American Elsevier, New
York, N.Y., pp. 309-339.
Hendrickson, A.R., Hurst, R.E. and Wieland, D.R., 1960. Engineered guide for planning acidizing
treatments based on specific reservoir characteristics.
Trans. AZME,
219: 16-23.
Hendrickson, A.R., Rosene, R.B. and Wieland, D.R., 1960.
Acid Reaction Parameters and Reservoir
Characteristics Used in the Design of Acid Treatments. ACS paper,
presented at the ACS
137th
Natl.
Meet., Cleveland, Ohio, Apr. 5-14.
wells.
Oil Gas
J.,
Oct. 12: 10.
surface areas
of
sediments.
J.
Sediment. Petrol.,
33(3): 759-765.
American Elsevier, New York, N.Y.,
408
pp.
Englewood Cliffs, N.J.,
pp.
536-546.
Pet. Tech.,
17
(7):
768-772.
190
Hidy, R.W. and Hidy, M.E., 1955.
Pioneering in Big Business
-
History
of
Standard Oil Company
(New
Howard, G.C. and Fast, C.R., 1970.
Hydraulic Fracturing.
Monograph Series. (Henry L. Doherty Ser.,
Labrid, J.C., 1975. Thermodynamics and kinetics aspects of argillaceous sandstone acidizing.
Soc. Pet.
Langnes, G.L., Robertson Jr., J.O. and Chilingar, G.V., 1972.
Secondary Recovery and Carbonate
McDougall, L.A., 1969. Corrosion inhibitors
for
high temperature acid applications.
Muter. Prot.,
8(8):
McLeod, H.O. and Coulter, A.W., 1966.
The Use
of
Alcohol in Gas Well Stimulation. SPEpaper
No.
1663,
McLeod, H.O., McGinty, J.E. and Smith, C.F., 1966. Alcoholic acid speeds clean-up in sandstones.
Pet.
Muskat, M., 1946.
The Flow
of
Homogeneous Fluids through Porous Media.
McGraw-Hill, Ann Arbor,
Newcombe, R.B., 1933. Acid treatment for increasing oil production.
Oil
Weekly,
May 29: 19.
Putman,
S.W.,
1933. Development of acid treatment
of
oil wells involves careful study
of
problems of
each.
Oil
Gas
J.,
Feb. 23:
8.
Smith, C.T., Crowe, C.W. and Nolan
111,
T.J., 1968.
Secondary Deposition
of
Iron Compounds Following
Acidizing Treatments. SPE Paper
No.
2358,
presented at the SPE-AIME East. Reg. Meet., Charleston,
W.Va., Nov. 7-8.
Sutton, G.D. and Lasater, R.M., 1912.
Aspects
of
Acid Additive Selection in Sandstone Acidizing. SPE
Paper
No.
4114,
presented at SPE-AIME 47th Annu. Fall Meet.,
San
Antonio,
Tex.,
Oct 8-11.
Williams, B.B., Gidley, J.L. and Schechter, R.S., 1979.
Acidizing Fundamentals.
(Henry L. Doherty Ser.,
Monogr. 6). S.P.E. of A.I.M.E., Dallas, Tex., 124 pp.
Wilson, J.R., 1935. Well treatment.
U.S.
Patent
No.
1,990,969
(Feb. 12).
Jersey)
1882-1911.
Harper, New York, N.Y., 156 pp.
Monogr. 2). SOC. Pet. Eng. of AIME, Dallas, Tex., 203 pp.
Eng.
J.,
15(2): 117-128.
Reseruoirs.
American Elsevier, New York, N.Y., 304 pp..
31-32.
presented at the SPE-AIME Eastern Reg. Meet., Columbus, Ohio, Nov. 11-12.
Eng.,
38(2): 66-70.
Mich., 763 pp.
191
Chapter
6
GRAVEL PACKING
W.B. HATCHER, GEORGE V. CHILINGARIAN and JAMES R.
SOLUM
IN T
R
0
DUCT
I0
N
Sand production is an operational problem that occurs in many wells that are
producing from unconsolidated formations. If left unchecked, this problem can
result in high operating expenses and may even require the abandonment of a
producing well. If a well is a frequent sander, then many hours of hoist time are
required in order to bail the sand from the well. Additional costs are incurred due to
lost production during downtime and erosion that occurs as a result of sand
production. In addition, with large amounts of sand production the liner or casing
may collapse.
Gravel packing is a mechanical means of controlling sand production. If properly
designed and applied, this completion technique can provide adequate sand control
throughout the life of a well. In order to obtain an effective gravel-packed comple-
tion, it is essential that the pack be properly designed using the proper gravel,
screen, carrier fluid, and placement technique.
SAND PRODUCTION
As pointed out by Allen and Roberts
(1982,
p.
39,
sand production is usually
associated with shallow formations of Tertiary age. It is important to note, however,
that the problem can be encountered at almost any depth. The production of sand is
related to formation strength, flow stability, viscous drag forces, and pressure drop
into the wellbore.
Formation strength is dependent upon the degree to which cementation has
occurred during diagenesis. Both water and steam have the capability of dissolving
cementing material. If a steamflood or waterflood is to be initiated in a consolidated
sandstone reservoir, therefore, it is advisable to plan ahead and consider completing
producing wells with provisions for sand control. It is also possible for cementation
to break down as a result of compaction due to fluid depletion (decrease in pore
pressure).
Viscous drag forces are related to flowrate and viscosity.
192
GRAVEL
SELECTION
Choosing the proper gravel is of utmost importance in obtaining an effective
gravel pack. Both gravel size and quality should be considered in designing a gravel
pack.
Gravel
sizing
In order
to
determine the optimum gravel size, it is essential to conduct sand
sieve analysis on representative formation samples. Sieve analysis from conventional
cores is preferable; however, sidewall core samples can also be used. If no cores are
available, then sand samples from perforation washing, bailing, or produced sands
can be used.
Early work in sand control relied upon sand bridging to occur in order
for
sand
to be excluded. Coberly (1937) concluded that “spherical grains form stable bridges
on openings larger than the diameter
of
the grain, the ratio being two for rectangu-
lar openings and three for circular openings.” Coberly also concluded that in sands
of varying grain size, the larger sand grains have the greatest influence on sand
bridging and should, therefore, be used for sizing determinations. Although Coberly’s
work applied specifically to sizing screens for sand control, the concept
of
sand
bridging has also been used in determining the size of gravel.
Under conditions that typically exist downhole, it is very unlikely for stable sand
bridges to form. Two-phase flow, varying production rates, pressure washing, cyclic
steam stimulation, gas expansion, and pressure transients induced by artificial lift
systems can all prevent stable sand bridges from forming. Currently, the most
common gravel-pack design criteria is based upon absolute stoppage of sand at the
sand-gravel interface. According to Saucier (1974, p. 211), sizing a gravel based
upon absolute stoppage, with a gravel/sand size ratio of between 5 and
6,
will
provide the greatest sand control without a reduction in gravel-pack permeability
(see Fig.
6-1).
In order to properly size a gravel pack with absolute stoppage of sand, it is
important to distinguish between formation sand or matrix and fines that flow with
the formation fluid. Fines should not be prevented from migrating into the wellbore.
Otherwise the fines would continually plug the formation near the wellbore as the
fluid flows into the well.
A
reduction in permeability near the wellbore (skin
damage) would then occur and the well’s productivity would be greatly reduced.
Common practice is to design a gravel pack such that
90%
by weight
of
all solids
will be retained at the sand-gravel interface. To design a gravel pack based upon
this criterion, it is necessary that the pore throats within the gravel pack be smaller
than the 90-percentile sand-grain size.
The median pore throat size
of
a gravel pack is dependent not only upon the
gravel size, but alsO upon the paclung arrangement and the grain shape.
This
concept is illustrated in Figs.
6-2
through Fig.
6-4,
which show that packs consisting
of uniform spherical grains have more consistent pore throat sizes than do packs
of
1
.o
0
0.8-
n
.-
-
._
m
P)
:
a
Y
2
0.6-
!%
E
.c
0.4-
a
-
m
m
-
.- .-
c
0
(u
>
0
c
.-
+-
:
'i5
0.2-
a"
.-
0
c
0
3
m
I
I
I
I
/H---'
I
I
I
/'
I
/
/'
I
I/
than required
to
within gravel pack,
I/
I/
I/
1
/I
/I
/I
'I
Gravel smaller Sand bridges
1
/
Unrestricted
retain formation
sand, less than
maximum
productivity
realized
sand movement
through gravel
pack
reducing productivity
---/
I
I
I
I
I
II
II
II
I
;I
:I
I I
I
I
I
I
I
I
I
I I
I
I
I
I
1
I
I
0
2
4
6
8
10
12
14
16
18
Fig. 6-1. Effect of the ratio
of
median gravel size
to
the median sand size on gravel-pack permeability. (After Graham et al., 1959, and Saucier, 1974,
modified by Patton and Abbot, 1982, p. 87, and Allen and Roberts, 1982,
p.
39.)
194
CUBIC PACKING ORTHORHOMEIC
PACK IN G
TETRAGONAL PACKING RHOMOEOHEDRAL
PACK
I
NG
Fig.
6-2.
The four close packings of equal prolate spheroids when the major axes lie in the planes
of
the
layers. (After Allen, 1969, as illustrated in Chilingarian and
Wolf,
1976,
p.
149; courtesy of
Geological
Magazine.)
non-spherical grains. In a pack of uniform spherical grains, the pore throat size
varies inversely with the degree of compaction.
A
cubic packing is the loosest
packing arrangement
of
uniform spheres with a porosity
of
approximately 48% and
a
pore throat diameter of 0.4142 times the gravel-grain diameter. In comparison, a
rhombohedral pack (hexagonal) has a porosity of 26% and a pore throat size of
0.1547 times the gravel-grain diameter (Coberly, 1937). The pore size, therefore, is
reduced 2.68 times by aclueving rhombohedral packing.
In actual borehole conditions, the packing arrangement is a random combination
of numerous packing geometries. According to Allen
(in:
Chilingarian and Wolf,
1976,
p. 149), a haphazard packing
of
uniform spheres has a concentration
of
grains,
C
[C
is defined as (space occupied by solids)/(total space)], ranging from 0.60 to
0.64. This corresponds to a porosity range between 36 and
40%.
Obtaining a tight gravel pack (i.e., low-porosity) is desirable. Such packs are less
likely to have large void spaces and are not as prone to compact after the well is put
on production. Should compaction occur after placement, then a void would be
@@B@
PLAN
ELEVATION PLAN
ELEVATION PLAN
ELEVATION PLAN
Fig.
6-3.
The five open packings of equal prolate spheroids. (After Allen, 1969, as illustrated in
Chilingarian and Wolf, 1976,
p.
150;
courtesy
of
Geological Magazine.)