Chilingarian G.V. et al. Surface Operations in Petroleum Production, II
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95
Cement Basket
Fig.
3-20.
(a) Placement
of
cementing baskets, stage collars, and centralizers
on
the casing string used for
primary cementing operation where weak or
porous
sands occur in the interval to be cemented.
(b)
Cementing basket. (Courtesy
of
the Halliburton Services.)
96
Fig.
3-21.
Schematic
of
an
external casing packer. (Courtesy
of
Lynes Inc.)
97
rotated
or
reciprocated. Scratchers are specifically designed for either type of action
(see Smith,
1976,
for additional details).
Fig.
3-22a.
For
explanation
see
p.
98.
98
Fig.
3-22.
(continued). Multiple uses
of
a
casing packer. in cementing
and
well completion operations.
ECP
=
external casing packer \(Courtesy
of
Lynes, Inc.)
99
Cement baskets and external casing packers
Cement baskets (Figs. 3-19 and 3-20) and external packers
(Fig.
3-21 and 3-22)
are used in cases where weak (and porous) formations need help to support the
cement column until the occurrence
of
initial set. Baskets are often installed over
casing collars or mounted between limit clamps. External casing packers are placed
where desired in the casing string as the casing
is
lowered into the wellbore. The
packers are expanded before initiation of cementing (Baker Oil Tools, 1974).
ACKNOWLEDGEMENTS
The authors are greatly indebted to Halliburton Services and Dwight
K.
Smith
whose help was invaluable in carrying this work to completion. Dr. Smith is one of
the foremost experts
on
cementing in the World.
REFERENCES
American Petroleum Institute, 1948.
California’s Oil.
API, Dallas, Tex., 12 pp.
American Petroleum Institute, 1959,
Oil- Well Cementing Practices in the United States.
API, Dallas, Tex.,
American Petroleum Institute, 1960a.
API Specifications for Oil- Well Cements and Cement Additives,
API
American Petroleum Institute, 1960b.
API Recommended Practice for Testing Oil- Well Cements and
American Petroleum Institute, 1974.
Specifications for Oil- Well Cements and Cement Additives,
API
Baker Oil Tools Inc., 1974.
Technical Sales Catalog.
Houston, Tex.
Bearden, W.G. and Lane, R.D:, 1961a. You can engineer cementing operations to eliminate wasteful
Bearden, W.G. and Lane, R.D., 1961b. Engineered cementing operations to eliminate wasteful WOC
Blanks, R.F. and Kennedy, H.B., 1955.
The Technology of Cement and Concrete.
Wiley, New York, N.Y.,
Brice Jr., J.W. and Holmes, B.C., 1964. Engineered casing cementing programs using turbulent flow
Byron Jackson Inc., 1979.
Applied Engineering Cementing,
Vol.
I:
2nd printing, 102 pp.
CEMBUREAU, 1967.
Cement Standards of the World- Portland Cement and its Derioatiues.
Pans.
Coffer, H.F., Reynolds, J.J. and Clark Jr., R.C., 1954. A ten-pound cement slurry for oil wells.
Trans.
Craft, B.C., Holden, W.R. and Graves Jr., E.D., 1962.
Well Design: Drilling and Production.
Prentice-Hall,
Dumbauld, G.K., Brooks Jr.,
F.A.,
Morgan, B.E. and Binkley, G.W., 1956.
A
lightweight, low-water-loss,
Fams, R.F., 1946. Method of determining waiting-on-cement time.
Trans. AIME,
165: 175-188.
Gatlin, C., 1960.
Petroleum Engineering: Drilling and Well Completions.
Prentice Hall, Englewood Cliffs,
Gibbs, M.A., 1965.
Prima? and Remedial Cementing in Fractured Formations.
In: Southwestern
297 pp.
STD 10A. API, Dallas, Tex., pp. 4-7.
Cement Additiues,
API RP 10B. API, Dallas, Tex., pp. 2-3.
Standards
10A.
API, New York, N.Y., 19th ed.
WOC time.
Oil
Gas
J.,
July 3: 104.
time.
Drill. Prod. Pract., API,
p. 17.
pp. 1-64.
techniques.
J.
Pet. Tech.,
16(5): 503-508.
Soc. Pet. Eng. AIME,
201: 146-148.
Englewood Cliffs, N.J., pp. 158-255.
oil-emulsion cement for use
in
oil wells.
J.
Pet. Tech.,
8(5):
99-104.
N.J., pp. 269-329.
Petroleum Short Course, Texas Technical College, Lubbock, Tex., 1965, pp. 22-23.
100
Goins Jr., W.C., 1971. Selected items of interest in drilling technology.
J.
Pet. Tech.,
23(7): 857-862.
Halliburton Oil Well Cementing Company, 1970.
Halliburton Oil Well Cement Manual.
Halliburton,
Halliburton Oil Well Cementing Company, 1974.
Technical Services Catalog
No.
37.
Halliburton,
Halliburton Services, 1979. ShereliteTM low-density cement.
Cem. Tech. Data,
C-1263 (Rev.).
Hansen, W.C., 1963. Crystal growth as a source of expansion in Portland-cement concrete.
Proc. ASTM,
Howard, G.C. and Clark, J.B., 1948. Factors to be considered in obtaining proper cementing
of
casing.
Hower, W.F. and Montgomery, P.C., 1953a. New slurry effective for control
of
unwanted water.
Oil Gas
Hower, W.F. and Montgomery, P.C., 1953b. New squeeze-cementing mixture.
Oil Gas
J.,
52(24): 136.
Klein, A. and Troxell, G.E., 1958. Studies of calcium sulfoaluminate admixtures for expansive cements.
Lafuma, H., 1952. Expansive cements.
Proc. 3rd In?. Symp. Chem. Cement,
London,
p.
581.
Maier, L.F., Carter, M.A., Cunningham, W.C. and Bosky, T.G., 1971. Cementing practices in cold
environments.
J.
Pet. Tech.,
23(10): 1215-1220.
Morgan, B.E. and Dumbauld, G.K., 1954. Bentonite cement proving successful in permanent-type
squeeze operations.
World Oil,
Nov.: 220.
Morris, E.F., 1970.
Evaluation of Cement Systems for Permafrost.
Annu. Fall. Meet., SOC. Pet. Eng.
AIME, Denver, Colo., Feb. 15-19.
Newman, K., 1960. The design of concrete
mixes
with high alumina cement.
The Reinf: Concr. Reu.,
5
(Mar.).
Rieke, H.H. and Chilingar, G.V., 1982. Casing and tubular design concepts. In: L.M. Edwards, G.V.
Chilingar, H.H. Rieke
111 and W.H. Fertl (Editors),
Handbook of Geothermal Energy,
Gulf, Houston,
Tex., pp. 261-309.
Shryock, S.H., 1982. Geothermal cementing. In: L.M. Edwards, G.V. Chilingar,
H.H.
Rieke
111
and W.H.
Fertl (Editors),
Handbook of Geothermal Energy,
Gulf, Houston, Tex., pp. 310-325.
Slagle,
K.A.,
1962. Rheological design of cementing operations.
J.
Pet. Tech.,
3: 323-328.
Smith, D.K., 1956. A new material for deep well cementing.
J.
Pet. Tech.,
8(3): 59-63.
Smith, D.K., 1966.
Well cementing method.
U.S.
Patent No. 3, 227, 213, Jan. 4.
Smith, D.K., 1976.
Cementing
(Henry L. Doherty Series, Monogr., 4) AIME, Dallas, Tex., 184 pp.
Snyder,
RE.
and Suman Jr., G.O., 1979.
High-pressure Well Completions Handbook.
World Oil, Houston,
Suman Jr., G.O. and Ellis,
R.C., 1977.
Cementing Handbook (Including Casing Handling Procedures).
Taylor, F.B., 1941. Acidizing before cementing helps form effective bottom-hole water block.
Oil Weekly,
Taylor, H.F.W. (Editor), 1964.
The Chemistry
of
Cements,
Vol.
I.
Academic Press, London, 460 pp.
Tough, F.B., 1918. Method
of
shutting off water in oil and gas wells.
U.S.
Bur. Mines Bull.,
163 (also
Pet.
Tech.,
46: 122).
White, F.L., 1952. Setting cements in below freezing conditions.
Pet. Eng.,
Part
I
(Aug.): B7; Part
I1
(Sept.): B59.
Wieland, D.R., Calvert, D.G. and Spangle, L.B., 1969.
Design of Special Cement Systems for Areas with
Low
Fracture Gradients.
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Duncan, Okla.
Duncan, Okla.
63: 932-945.
Drill. Prod. Pract., API,
pp. 257-272.
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52(24).
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102: 17.
101
Chapter
4
FRACTURING
JOHN
0.
ROBERTSON Jr., GEORGE
V.
CHILINGARIAN
and SANJAY KUMAR
INTRODUCTION
Hydraulic fracturing has played a major role in increasing the oil and gas
reserves. Veatch (1983a) reported that 35-40% of all currently drilled wells in the
U.S.A. are hydraulically fractured. As a result of fracturing treatments, there has
been
an
increase of economically producible U.S.A. petroleum reserves by 25-35%.
This
constitutes an increase of over 8 billion barrels of oil.
Oil and gas are displaced to the wellbore by several means after the well is
drilled: (1) fluid expansion, (2) natural or artificial fluid displacement, (3) gravity
drainage,
(4)
capillary expulsion, and
(5)
compaction of sediments and rocks. The
various processes may work together or independently to drive the hydrocarbons
into the wellbore through existing flow channels. In many wells, the production
rates may be commercially insufficient either because of wellbore damage during
drilling or very low formation permeabilities, which do not permit the hydrocarbons
to drain into the wellbore at a sufficiently high rate.
In hydraulic fracturing, fluid
is
injected until the fluid pressure overcomes the
stresses inherent in the rock or is greater than the forces holding the rock together.
This
causes the rock to split apart (rupture), forming a fracture. Fracturing fluid
must be pumped into the fracture rapidly enough to hold the fracture open and
allow the propping agent (e.g., sand) carried by the fluid to enter the fracture and
hold it open. In some cases, a propping material is not used. If there
is
no propping
agent present to hold the walls of the fracture apart, however, the fracture walls can
close or “heal”. Fracturing creates new and larger flow channels through the
damaged zones, around the wellbore. Fractures then extend out into the undamaged
portions of the reservoir and may also connect the preexisting natural fractures and
microfractures to the wellbore. In tight reservoirs, fractures create a much larger
drainage surface area.
Early history
Between 1890 and 1950, the oil industry all over the world often used liquid, and
later solidified, nitroglycerin to stimulate petroleum wells by creating fractures in
the wellbore by the use of explosions (Hurst, 1953). Use of explosives was limited by
the extreme hazards associated with handling of the unstable materials (Howard
102
5
p=PRESS.
AT BOTTOM
OF
INJECTION WELL.pS1
Fig.
4-1.
Water injection test, Hole
14;
shot with
17.75
lb
solidified nitroglycerin
loaded
2.96 Ib/ft in
2-1/2 in.
X6
ft
shell. (After Grant et al., 1950; courtesy
of
Drill. and Prod. Pruc.,
API.)
and Fast, 1970). The fracturing of the wellbore as a result
of
the explosions often
resulted in spectacular increases in fluid production. An example of the type of
improvement experienced is shown in Fig. 4-1. Grant et al. (1950) conducted a
series of shallow well tests to study the effect of “well shooting” on the relationship
between water injection rate and injection pressure. Figure 4-1 illustrates the direct
benefits of stimulation as shown by the increased ability of the formation to take
up
more water at a much lower injection pressure.
Well stimulation with a high explosive charge became less popular after 1950
when the oil industry found that commercial fracturing treatments could accomplish
the same results without the problems of
(1)
major postshooting wellbore cleanup
operations,
(2)
damage to the casing, and
(3)
exposing personnel to the dangers
of
severe injury while handling dangerous explosives. Stanolind Oil and Gas Company
(later Pan American Petroleum Corporation and then AMOCO) announced its
hydraulic fracturing process in 1948. Farris (1946; in: Howard and Fast, 1970)
studied the relationship between observed well performance and treating pressures.
In review of
115
cement squeeze jobs in the Louisiana-Texas Gulf Coast area,
U.S.A., Farris prepared a graph (Fig.
4-2)
showing that the “breakdown” pressure is
equal to the fracturing pressure (i.e., the pressure necessary to overcome the tensile
or compressive strength) plus the effective overburden pressure. A similar study in
the Oklahoma, North Texas, and New Mexico areas is shown in Fig. 4-3. Howard
and Fast (1970) constructed Fig. 4-4 using data published by Grebe (1943), Dickey
and Andersen (1945), and Yuster and Calhoun (1945). Howard and Fast (1970)
103
16,000
I
I
,I
MAXIMUMI
14,000
t
12,000
w
Y
lO.000
Y
5
8,000
0
Y
6,000
0
2
4,000
8
IL
2.000
0
OEPTH
-THOUSbNDS
OF
FEET
Fig. 4-2. Formation breakdown pressures. (After R.F. Farris, 1946, in:
6; courtesy of the Society of Petroleum Engineers.)
Howard and Fast, 1970,
fig.
1.6, p.
noted that the values fell within the extrapolated portion of the curves based upon
formation breakdown field data.
A
hydraulic fracture treatment for the Klepper
No.
1
gas well, Hugoton gas field,
Grant County, western Kansas,
U.S.A.,
in 1947 is one of the earliest descriptions
of
the first attempts to hydraulically fracture wells. This well was completed and
produced gas from four limestone horizons between 2340 and 2580 ft. Howard and
Fast (1970) described the following treatment for this well:
Fig. 4-3. Comparison
of
various estimates of overburden pressures. (After Farris,
Fast, 1970, fig.
1.10,
p. 7; courtesy
of
the Society
of
Petroleum Engineers.)
1946, in: Howard and
104
Fig.
4-4.
Comparison of various estimates of effective overburden pressure gradients. (After Howard and
Fast,
1970,
fig.
1.17,
p.
8;
courtesy
of
the Society of Petroleum Engineers.)
A
centrifugal pump was used for
mixing
the gasoline-base napalm gel fracturing
fluid. Fluid was injected with a positive-displacement high-pressure pump into the
wellbore.
All
equipment was kept away
(150
ft apart) from the well and mixing area
due to high fire hazards.
The treatment consisted
of
four separated treatments-one on each gas-produc-
ing horizon. Each horizon was treated with 1000 gal of napalm-thickened gasoline
followed by 2000 gal of gasoline containing
1%
of
an amine gel breaker.
Tests indicated that the treatment did alter the relative producing characteristics
of the four gas-producing zones. Inasmuch as the deliverability of gas from these
zones did not significantly improve, the attempt to stimulate the well was consid-
ered unsuccessful.
The technology associated with fracturing has improved with time. The first
treatments consisted
of
injecting small volumes of fluid (200-400 gal) mixed with
sand (1/2 lb/gal), injected at rates
of
2-4 bbl/min (Halliburton, 1976).
As
40
32
24
16
B
1950
1958
1966
1974
Fig.
4-5.
Trend of average fracture treatments in the United States. (Courtesy of the Halliburton
Co.,
1976, fig.
2.1,
p.
5.)