COMPLETION/STIMULATION
Rewriting the Rules for High-Permeability Stimulation
Stimulation of high-permeability formations has long been the domain of matrix treatments.
Now, short, wide fractures are being created to
Joseph Ayoub
New Orleans, Louisiana, USA
Bob Cooper
Houston, Texas, USA
For help in preparation of this article, thanks to Paul
Martins, BP Exploration (Alaska) Inc., Anchorage,
Alaska, USA; and Jack Elbel and Richard Marcinew,
Dowell Schlumberger, Tulsa, Oklahoma, USA.
18
A classic fracture stimulation creates narrow conduits that reach deep into a formation—typically, about 1/10 in. [2.5 millimeters] wide and up to 1000 ft [300 m] long.
Since the 1940s, relatively low-permeability formations—less than 20 millidarcies
(md)—have been successfully fractured to
give worthwhile increases in productivity.
However, as formation permeability
increases, creating and propagating fractures become more difficult and economically less necessary. In high-permeability
reservoirs, formation damage is usually
diagnosed as the major restraint on productivity and matrix acidization treatments are
prescribed as the solution (see “Trends in
Matrix Acidizing,” page 24).
But matrix acidization cannot solve every
problem. The volume of damaged rock
sometimes requires uneconomically large
quantities of acid. The damage may be
beyond the reach of the matrix treatment.
Diverting acid into the right parts of the formation may also be difficult. Additionally,
the aqueous treatment fluid or the acid
itself may threaten the integrity of the wellbore by dissolving cementing material that
holds particles of rock together.
An alternative strategy for stimulating
high-permeability wells has therefore
emerged: the creation of fractures that are
typically less than 100 ft [30 m] long and
Undamaged reservoir
Damage
Bob Hanna
BP Exploration Inc.
Houston, Texas, USA
Short, wide fracture
nShort, wide fractures bypass widespread
formation damage and link undamaged
rock with the wellbore.
up to 1 in. [2.5 centimeters] wide after closure (above ). To appreciate how short, wide
fractures stimulate high-permeability formations, one must examine the factors governing postfracture productivity.
The permeability contrast between the
formation and the propped fracture is a key
determinant of the optimum fracture length.
In low-permeability formations there is a
large contrast—and therefore a high relative
conductivity—and increased fracture length
can yield improved productivity (next page ).
In high-permeability formations, relative
conductivity is about two orders of magnitude smaller. Increasing the length of conventional fractures offers only minimal
improvement in productivity and cannot be
justified economically. However, the productive performance of the fracture is determined by the dimensionless fracture conductivity which is directly proportional to
the fracture width.1 Conductivity can be
raised by increasing fracture width; in highpermeability formations, this offers significant potential improvements in productivity.
Oilfield Review
October 1992
High-permeability
formations
1.0
0.9
0.8
0.7
Low-permeability
formations
0.6
Increasing productivity
Pinpointing the birthplace of high-permeability fracturing is difficult, but it is clear
that work carried out by Sohio Petroleum
Co. (now BP Exploration Inc.) inspired
much of today’s thinking. In 1984, in Prudhoe Bay, Alaska, USA, Sohio fractured a
well with a permeability of about 60 md.
The overriding aim of the exercise was to
stimulate the well while avoiding fracturing
into the oil/water contact (OWC) about 115
ft [35 m] below the lowermost perforation.2
In a relatively small fracturing treatment,
some 15,000 gal [57 m3] of gelled fluid
were pumped at 45 bbl/min, placing 12,000
lb [5440 kg] of proppant in the fracture.
This treatment was calculated to be sufficient to create a fracture with a propped
length of 43 ft [13 m], which, based on the
assumption that one foot of lateral extension would result in one foot of downward
fracture migration, left the fracture easily
short of the OWC. The treatment was a
mechanical success and production
increased by 133%—versus a theoretical
maximum of 160%.
Rather than quantify fracture width, conventional terminology uses proppant concentration—most commonly stated as
pounds of proppant per square foot of fracture [lbm/ft2 ]—which is directly proportional
to the width. A conventional, long and narrow fracture may contain 0.5 lbm/ft 2 of
proppant. The Sohio job was designed to
place 1 lbm/ft2—modest by today’s standards, which aspire to place 4 lbm/ft2 or more.
After this job, attention shifted to the
North Sea. The Valhal field, offshore Norway, has a soft chalk reservoir. Amoco Production Co. found that, although the formation was not highly permeable (about 2 md)
0.5
0.4
0.3
0.2
0.1
10 2
10 3
10 4
10 5
Length of fracture,
fracture length/drainage radius (x f /re)
reach beyond wellbore damage and provide a conduit to undamaged reservoir rock.
10 6
Relative conductivity
nIncrease in posttreatment productivity versus relative fracture
conductivity—proportional to the permeability contrast between
the formation and propped fracture—for a variety of fracture
lengths (shown as fracture length/drainage radius). In these curves
for steady-state production, a normal, low-permeability fracture
treatment has a relative conductivity on the order of 10 5. Consequently, there is scope to increase productivity by increasing
fracture length.
But for high-permeability formations, relative conductivity is
about 10 3, and an increase in fracture length makes virtually no
difference. However, if a wider fracture can be created, fracture
conductivity is increased, yielding a higher relative conductivity. This increases productivity for a given fracture length and
offers the chance of raising productivity by increasing the fracture length.
Adapted from McGuire WJ and Sikora VJ: “The Effect of Vertical
Fractures on Well Productivity,” Transactions of the AIME 219 (1960):
401-403.
1. C = Kf W
fd
KX f
where: Cfd is the dimensionless fracture conductivity,
K f is the permeability of the proppant pack, W is the
width of the fracture, K is the permeability of the formation and X f is the length of the fracture.
2. Hannah RR and Walker EJ: “Fracturing a High-Permeability Oil Well at Prudhoe Bay, Alaska,” paper SPE
14372, presented at the 60th SPE Annual Technical
Conference and Exhibition, Las Vegas, Nevada, USA,
September 22-25, 1985.
19
A
Proppant
bridges
at tip
B
Proppant
Fluid
leakoff
C
Proppant
fills
fracture
nTip-screenout treatments place a high
proppant concentration and create fractures that are usually less than 100 ft long
and up to 1 in. wide.
A) The fracture is propagated to its
desired length just as the proppant in
the slurry begins to bridge off near the
tip of the fracture, preventing further
propagation.
B) Additional slurry is pumped into the
fracture increasing the net pressure
inside the fracture, causing it to widen.
C) Further dehydration of the slurry creates a pack of proppant that gradually
evolves from the tip toward the wellbore.
20
it was very unstable and conventional stimulation was difficult. After acid fracturing,
the acid-etched channels quickly collapsed
as pore pressure was reduced. And after a
conventional propped fracture, the proppant
became embedded in the soft rock, destroying fracture conductivity.
In 1986, Amoco opted to place a high
concentration of proppant in a wide fracture
using a technique it called “tip screenout.”
In normal fracturing, the tip should be the
final part of the fracture to be packed with
proppant. But in tip screenout, the proppant
forms a pack near the end of the fracture
early in the treatment. When additional
proppant-bearing slurry is pumped into the
fracture, its length cannot grow, so the width
increases (left ).3
At about the same time, in the UK sector
of the North Sea, BP Petroleum Development Ltd. was applying tip screenout techniques to stimulate gas wells in the Ravenspurn South field. Permeability was 2 md
higher than gas wells that are normally fractured, but BP found that conductivity of
long, conventional fractures limited the
reservoir’s high rate of production, giving
only a threefold increase in production.
Laboratory tests showed that up to 0.5
lbm/ft2 of proppant in the fracture can be
“lost” largely through embedment. To combat this loss in conductivity, stimulation programs were designed to create wide fractures, typically placing 3 to 4 lbm/ft 2 of
proppant. This “excess” of proppant
ensured that enough remained in the fracture after embedment to deliver the
designed conductivity. Subsequent treatments in Ravenspurn South, using high
proppant concentrations, posted increases
in production of up to sevenfold.4
Tip screenout also returned to Prudhoe
Bay. Since 1989, BP and ARCO Alaska Inc.
have employed tip-screenout treatments and
report considerable success.5
However, following some tip-screenout
treatments, proppant flowed out of the
fracture during posttreatment production.
This is caused by factors such as low effective stress in the proppant pack or drag
forces due to high-velocity flow in the conductive pack. Proppant flowback leads to
reduced fracture conductivity or blockages
at the fracture-wellbore interface. If the
proppant is flowed to surface, damaging
erosion of the production equipment can
also occur.
Sand-control techniques have been
employed after fracturing to prevent proppant flowback. The two main techniques
use resin-coated proppant or gravel packing. Proppant coated with a curable resin
consolidates once the proppant has been
placed in the fracture and resists drag during
production. Alternatively, the fracture treatment can be followed by a gravel pack
using a conventional screen to retain the
proppant within the fracture (see “Sand
Control: Why and How?” page 41).
In Indonesia, more than 30 treatments
have been carried out that combine tipscreenout fracturing with either resin consolidation or a gravel pack. These wells had
high skin factors but undamaged permeabilities in excess of 100 md. Following treatment, many now produce with low skin factors while adjacent conventionallycompleted wells have skins of 20 to 40 (see
”Average Data From Three Types of Treatment,” next page, below left ).6
Tip-screenout fracturing and gravel packing treatments are also being used in combination in the Gulf of Mexico, USA. Over the
past 12 months, more than a dozen combined treatments in formations with permeabilities as high as 1 darcy have realized
two- to threefold improvements in production (next page, below right).
Experience around the world has enabled
development of a methodology for selecting
3. Smith MB, Miller WK and Haga J: “Tip Screenout
Fracturing: A Technique for Soft, Unstable Formations,”
SPE Production Engineering 2 (May 1987): 95-103.
4. Martins JP, Leung KH, Jackson MR Stewart, DR and
Carr AH: “Tip Screen-Out Fracturing Applied to the
Ravenspurn South Gas Field Development,” paper
SPE 19766, presented at the 64th SPE Annual Technical Conference and Exhibition, San Antonio, Texas,
USA, October 8-11, 1989.
5. Reimers DR and Clausen RA: “High-Permeability
Fracturing at Prudhoe Bay, Alaska,” paper SPE 22835,
presented at the 66th SPE Annual Technical Conference
and Exhibition, Dallas, Texas, USA, October 6-9, 1991.
Martins JP, Bartel PA, Kelly RT, Ibe OE and Collins PJ:
“Small Highly Conductive Hydraulic Fractures Near
Reservoir Fluid Contacts: Applications to Prudhoe
Bay,” paper SPE 24856, presented at the 67th Annual
SPE Technical Conference and Exhibition, Washington
DC, USA, October 4-7, 1992.
6. Peters FW, Cooper RE and Lee B: “Pressure-Pack
Stimulation Restores Damaged Wells’ Productivity,”
paper IPA 88064, Proceedings Indonesian Petroleum
Association 17th Annual Convention, Jakarta, Indonesia, October 1988.
Peters FW and Cooper RE: “A New Stimulation Technique for Acid-Sensitive Formations,” paper SPE
19490, presented at the SPE Asia-Pacific Conference,
Sydney, Australia, September 13-15, 1989.
7. Ayoub JA, Kirksey JM, Malone BP and Norman WD:
“Hydraulic Fracturing of Soft Formations in the Gulf
Coast,” paper SPE 23805, presented at the SPE Formation Damage Symposium, Lafayette, Louisiana, USA,
February 26-27, 1992.
Oilfield Review
wells for tip-screenout treatments. 7 There
are three classes of candidate:
•Reservoirs with significant wellbore damage, perhaps caused by formation collapse as the pore pressure reduces during
depletion. Past matrix treatments have
failed, and short, wide fractures are
designed to bypass the damage and connect the undamaged part of the reservoir
with the wellbore.
•Reservoirs with fines migration. A short,
wide fracture can alleviate this by reducing pressure losses and velocities in the
reservoir sand near the wellbore.
•Multiple pay zones in laminated sandshale sequences. The thin sand laminae
may not communicate efficiently with the
wellbore until a fracture provides a continuous connection to the perforations
(above, right ).
Candidate selection is a multidisciplinary
task. Basic openhole logs detect sands and
their bounding shales, and indicate their relative permeability and degree of invasion—gaining an insight into the formation’s
natural permeability before damage, the
depth of invasion, the presence of zones
Proppant
nLaminated pay zone with sand-shale sequences. The sand laminae may be connected to the wellbore by short, wide fractures.
thinner than 5 ft (1.5 m) and the formation
strength. Specialized techniques like
microresistivity logging may then be used to
detect thinner layers of interbedded sandshale laminae. Logs also detect water-bearing zones which must be considered during
the design. Pressure transient analysis is
used to identify wellbore damage and quantify the production potential of the well.
After a candidate well has been identified,
the next stage is to design the treatment, a
process that relies on knowledge of the
rock’s mechanical properties and an estimate of the stresses in the reservoir and
adjacent rock (see “Cracking Rock: Progress
in Fracture Treatment Design,” page 4 ).
Simulation
Data
10 3
Average Data From Three Types of Treatment
Average data
Type A
Type B
Type C
7240
3560
4400
Zone thickness, ft
68
32
48
Zone permeability, md
72
53
60
Pad volume, gal
1600
5100
3500
Slurry volume, gal
685
2000
1740
3.8
2.1
1.2
Total vertical depth, ft
In-situ proppant concentration,
lbm/ft2
Propped fracture length, ft
28
Propped fracture conductivity, md-ft
5670
Pretreatment oil production, BPD
1040
Posttreatment oil production, BPD
2140
Pretreatment skin
October 1992
156
1313
Fractured
Nonfractured
10 2
0
30
60
90
Production time, days
nPredicted and real productivity increase in a Gulf of Mexico, USA, well stimulated in early 1992 using tip-screenout
fracturing.
18
Posttreatment skin
Treatment Type A
A series of six Indonesian
wells fractured using the
tip-screenout technique.
Although all the wells were
potential sand producers no
special sand-control
techniques were employed.
115
Production rate, B/D
Treatment Type
2.3
Treatment Type B
Two Indonesian wells
fractured with tip-screenout
treatments performed
through gravel-pack tools
and screens to place a
small, highly conductive
fracture and a gravel pack
in a single step.
Treatment Type C
Series of treatments
performed on two offshore
exploration wells to create
vertical communication
between several thin, highpermeability zones that
were believed to be waterand acid-sensitive.
21
Mechanical properties can be derived
using cores, logs and direct in-situ measurements. In many cases, however, retrieving
good cores and then accurately testing them
in the laboratory are difficult. Log-derived
mechanical properties rely on density and
sonic measurements. Both compressional
and shear sonic measurements work well in
consolidated, fast formations. But in soft,
slow formations, conventional sonic tools
cannot measure shear wave velocity. However, a recently introduced dipole sonic tool
can now make these shear wave velocity
measurements in any formation.8
In practice, there is rarely a comprehensive collection of core and log data with
which to build a model predicting fracture
shape, used for treatment design. To plug
this knowledge gap, data are collected using
stress tests.
Stress tests consist of pumping a relatively
small volume of ungelled fluid without
22
nFracturing high-permeability formations
in Indonesia. A specially modified twin
50-bbl mixer is capable of mixing and
pumping 18 lbm/gal slurries at more than
20 bbl/min. A centralized control station
allows one operator to control and monitor
the complete treatment—essential as pumping times can be as short as 2 minutes.
proppant into the formation at sufficient
pressure to fracture the well. In normal,
low-permeability stress tests pumping is
then stopped and the pressure can be monitored during flowback. However, in highpermeability formations, the fluid normally
leaks off into the formation rather than flowing back. Stress test are repeated several
times and the resulting pressure measure-
ments are used to determine the minimum
in-situ stress, which equals the closure pressure of the fracture.
Analysis of data from stress tests and
larger-volume calibration tests—which fracture the formation usually using gelled fluid
without proppant—enables choice of the
most suitable fracture geometry model and
confirmation of the fluid leakoff coefficient.
Fracture geometry models of varying sophistication are available. All of them use the
basic processes that occur during fracturing—fluid flow in the fracture and leakoff,
proppant transportation and settling, and
rock response—to describe the relationship
Oilfield Review
October 1992
the proppant size, the greater the fracture
permeability. In gravel packs, the sand must
have intergranular spaces small enough to
keep formation sand at bay.
To date, most wells have been treated
using the same size proppant for the fracture
and the gravel pack. This simplifies procedures but in most cases, proppant size tends
to be smaller—and therefore of lower conductivity—than would ideally have been
employed if fracturing had been carried out
alone. ARCO has been performing treatments with larger than normal sand sizes.9
After the job is completed, the first performance yardstick is its mechanical success—“Has everything gone according to
plan?” The effectiveness of the treatment
may then be assessed by comparing theoretical net pressures (fracture propagation pressure minus closure pressure) with pressures
measured during the treatment by down-
hole memory gauges (below ). Other placement evaluation techniques include use of
multiple-isotope tracers in the sand and
temperature logs to estimate the fracture
height and assess the fracture’s communication with the perforated interval along the
wellbore by tracing cooling anomalies
where the fluid has entered the formation.
However, the most important indicators of
success are the well’s production responses
both immediately after treatment and during
the rest of its productive life. To date, these
indicate that the traditional guidelines ruling
out fracturing for high-permeability formations have been successfully rewritten.—CF
8. “Taking Advantage of Shear Waves,” Oilfield Review
4, no. 3 (July 1992): 52-54.
9. Hainey BW and Troncoso JC: “Frac-Pack: An Innovative Stimulation and Sand Control Technique,” paper
SPE 23777, presented at the SPE International Symposium on Formation Damage Control, Lafayette,
Louisiana, USA, February 26-27, 1992.
Simulation
Data
1000
500
Net pressure, psi
between pressure and fracture shape and
produce criteria for fracture propagation.
The models assume that rock is an elastic
material, meaning that its deformation is
reversible. Dowell Schlumberger is currently examining whether this assumption
holds for soft formations, as it is an important factor when looking at the fracture closure and the stress it exerts on the proppant
pack. If closure stress is less than anticipated, the proppant pack could become
unstable during production—unless the
treatment has included a gravel pack.
Calibration tests also provide a more
accurate way of measuring fluid-loss characteristics of the fracturing fluid than can be
devised in a laboratory. Fluid loss depends
on the viscosity and wall-building capability
of the fracturing fluid, the viscosity and
compressibility of the reservoir fluid, and
the permeability and porosity of the formation. In a formation with high porosity and
permeability, fluid loss can be controlled by
increasing the viscosity of the fracturing
fluid or enhancing the fluid’s wall-building
capability on the fracture face by the addition of polymers and properly sized fluidloss control agents.
Once the choice of fracturing fluid is confirmed, the next step is to design a pumping
schedule capable of delivering the necessary high proppant concentrations. The data
generated by stress and calibration tests are
fed into the chosen fracture geometry
model, which calculates the volume
required to initially propagate the fracture to
a predetermined length. To ensure tip
screenout, proppant concentration in the
fracture fluid is gradually increased during
the treatment from zero at the start, to more
than 16 lbm/gal at the end.
Continuous mix and batch mix treatments
using high concentrations of proppant have
been executed fairly smoothly. In the larger
continuous mix jobs maintaining high concentrations of sand may require specialized
blending equipment (previous page).
Choice of proppant size depends on the
ultimate fracture conductivity needed and
whether the treatment is being carried out in
conjunction with a gravel pack. The larger
100
2
5
10
20
50
100
Production time, days
nComparing simulated pressures with the real thing. The
effectiveness of a treatment can be judged by comparing
theoretical net pressures with pressures measured during
the job using downhole gauges. This plot of a tip-screenout fracturing job shows excellent agreement between
the simulated and actual pressures.
23