1 Remedial Efforts for Fracture Treatment in Horizontal Laterals Robert Reyes, Halliburton Introduction As oil and gas well fracture stimulation has progressed, multiple novel technologies have been developed to keep pace. With the onset of horizontal lateral drilling and completion work, this trend has been magnified even more. It has been reported that 500 to 1,000 TCF of recoverable gas reserves have been added by North America Shale plays alone. In 19 geographical basins, an estimated 35,000 horizontal wells have been drilled and completed using multistage fracturing techniques. Proved reserves of U.S. oil and natural gas in 2010 rose by the highest amounts ever recorded since the U.S. Energy Information Administration (EIA) began publishing proved reserves estimates in 1977. An important factor for both oil and gas was the expanding application of horizontal drilling and hydraulic fracturing in resource shales and other "tight" (very low permeability) formations. The same technologies that first spurred substantial gains in natural gas proved reserves have more recently expanded into similar oil producing formations. Helping to drive proved reserves increases in 2010 were also higher prices used to assess economic viability relative to the prices used for the 2009 reporting year, particularly for oil. (EIA U.S. Energy Information Administration, August 2012) Fracture stimulation methods have evolved significantly from the high rate (100 to 180+ bbl/min) true limited entry design that used perforation techniques in an attempt to fracture treat from the heal to toe with a one-time pump-in stage. Many of these applications were where as much as a mile of lateral was treated in one or two hours in a single operation. On most of these jobs, when a postfrac survey was performed, a large percentage of the lateral would show little or no stimulation, with the toe section most often untreated. This led well operators to seek better completion plans, and new completion and stimulation tools designed to implement such changes. The first major change was to subdivide the wellbore and use the same limited entry perforating technique on shorter sections, with the industry designing new staging plug designs that allowed them to be pumped down the lateral to the desired position and wireline set. Soon, this type of plug would also drag down a multi-shot perf gun in the same operation, and by about 2002-03 we had the perf and plug process in use. New completion designs emerged that required lower injection rates, typically 50-90 bbl/min, depending on the number of dividing stages that were selected or the number of perforated intervals per stage. Thus, staged fracturing completions began to be the dominant method as resource shale completions became more common. This perf and plug method reduced horsepower costs while providing each fractured compartment a better chance to be effectively treated. The savings in horsepower was initially a trade off with the amount of increased time spent performing the stage frac
Transcript
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Remedial Efforts for Fracture Treatment in
Horizontal Laterals Robert Reyes, Halliburton
Introduction
As oil and gas well fracture stimulation has progressed, multiple novel technologies have
been developed to keep pace. With the onset of horizontal lateral drilling and completion
work, this trend has been magnified even more. It has been reported that 500 to 1,000
TCF of recoverable gas reserves have been added by North America Shale plays alone. In
19 geographical basins, an estimated 35,000 horizontal wells have been drilled and
completed using multistage fracturing techniques. Proved reserves of U.S. oil and natural
gas in 2010 rose by the highest amounts ever recorded since the U.S. Energy Information
Administration (EIA) began publishing proved reserves estimates in 1977. An important
factor for both oil and gas was the expanding application of horizontal drilling and
hydraulic fracturing in resource shales and other "tight" (very low permeability)
formations. The same technologies that first spurred substantial gains in natural gas
proved reserves have more recently expanded into similar oil producing formations.
Helping to drive proved reserves increases in 2010 were also higher prices used to assess
economic viability relative to the prices used for the 2009 reporting year, particularly for
oil. (EIA U.S. Energy Information Administration, August 2012)
Fracture stimulation methods have evolved significantly from the high rate (100 to 180+
bbl/min) true limited entry design that used perforation techniques in an attempt to
fracture treat from the heal to toe with a one-time pump-in stage. Many of these
applications were where as much as a mile of lateral was treated in one or two hours in a
single operation. On most of these jobs, when a postfrac survey was performed, a large
percentage of the lateral would show little or no stimulation, with the toe section most
often untreated. This led well operators to seek better completion plans, and new
completion and stimulation tools designed to implement such changes.
The first major change was to subdivide the wellbore and use the same limited entry
perforating technique on shorter sections, with the industry designing new staging plug
designs that allowed them to be pumped down the lateral to the desired position and
wireline set. Soon, this type of plug would also drag down a multi-shot perf gun in the
same operation, and by about 2002-03 we had the perf and plug process in use. New
completion designs emerged that required lower injection rates, typically 50-90 bbl/min,
depending on the number of dividing stages that were selected or the number of
perforated intervals per stage. Thus, staged fracturing completions began to be the
dominant method as resource shale completions became more common.
This perf and plug method reduced horsepower costs while providing each fractured
compartment a better chance to be effectively treated. The savings in horsepower was
initially a trade off with the amount of increased time spent performing the stage frac
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treatment, but going back to non-staged completions was not considered an economic
option. With decreased total completion time becoming a critical issue for improving
economics further, pumping service companies began to address how the stage fracture
treatment could be as efficient as the compartmental lower rate plug and perf method yet
significantly reduce the stimulation timeframe. The next major solution was sliding
sleeves activated by ball drop mechanics. This approach increased the hardware costs of
completion, but offered economic benefits of reduced stimulation times
By installing the lateral sliding sleeves with a baffle (increasing in opening size as the
position approached the heel) each stage would now end by dropping a specifically sized
ball from the surface to land on the baffle and slide the sleeve into an open position.
Now, instead of shutting down to pump a plug and perforate, the time between stages was
reduced significantly. Operators were again able to fracture an entire wellbore lateral (10
to 20 stages) in a day, possibly even allowing for flowback. However, just as plug and
perf operations often encounter malfunctions that add costs, so might the ball activated
sliding sleeve completion. They may be caused by human error of action or judgment,
mechanical failure, or by unforeseen quirks of nature.
With respect to premature sticking of plugs or failed perf guns, recovering from these
failures is usually possible, with added time and costs for the recovery operations, but
seldom with very much loss of producing zones. However, when a failure occurs with a
ball activated sliding sleeve assembly in place, the degree of problem may be as small as
losing a single pay interval to an issue such as in the case of 10 or more completion
stages with sliding sleeves in the lateral and unable to open any of the sliding sleeve
ports. Such a case could possibly be solved by milling out all the ball seats and then
attempting to revert back to the application of plug and perf technique, requiring possibly
a week or longer to recover the wellbore and to pump a perf and plug stimulation.
This paper discusses a novel technique detailing a west Texas case history where a
service company was asked to recover a well in which all sliding sleeves completion
tools were in failure mode. It was decided to open up all zones and use a new product to
effectively treat all stages in one pumping treatment. This technique is called diversion
frac for proppant distribution.
The method is engineered to improve the efficiency of completion techniques;
consequently, production increases should be observed. The procedure involves
providing all reservoir access points an opportunity to receive fracture stimulation
treatment. The access points are the perforations, completion sliding sleeve tools,
hydraulic sleeves, hydrojetted holes, open hole, etc., which are the fracture initiation
points. By staged dropping of a biodegradable material, which exists in a range of mesh
sizes, a previously treated zone is bridged and diverted, sending the trailing fracture
treatment stage into the next access point, which should be the next untreated zone least
resistant to taking fluid. Time is saved when the drop is made, and the previously treated
zone is diverted, redirecting the treatment fluid that follows to “break down” the next
zone. This process occurs in the same time frame in which crews operating the old plug
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and perforate method would be shutting down to get ready for wireline runs to set a plug
and perforate the next zone, which could take two hours per stage on an average well.
Background: Plug and Perforate Method
The plug and perforate completion technique has been the primary process for stage frac
completions for most of the past decade. The well completion type most commonly
applied has been be a cemented liner or casing, or, less often, an openhole liner using
casing external packers to partition the annulus into zones, and includes pumping down
plugs and perforating guns in horizontal applications. The application consists of gaining
entry to the formation by perforating the farthest interval or the toe section and then
breaking down the formation and pumping the first fracture treatment into this zone.
After a large flush stage to wash residual proppant from the wellbore and then shutting
down, isolation is achieved from the just-treated zone by placing a pump-down
mechanical plug above it. Then, the process repeats as the next zone to be treated is
perforated (typically 2 to 7 perf clusters), the gun is retrieved and then the interval is
broken down and fracture stimulated. This procedure continues until the last planned
zone is treated and flushed.
In North America, the plug and perforate process is being used in about 85% of today’s
horizontal well completions (Halliburton 2012). Efficiencies can be improved by
combining multiple perforating runs (i.e., multiple stages) into one and a significant
amount of time can be saved by using diversion frac for proppant distribution in between
these sub-stages. With an hour or two as a baseline to perform wireline runs, running
three sub-stages in one run saves two to four hours per treatment.
Applications of Diversion Frac for Proppant Distribution The service operator’s special biodegradable diverting agents provide temporary temperature- or time-
based fluid-loss control (i.e., temporary perf sealing) in the near-wellbore region (NWB) of the perforations
and the fracture of new zones accepting fluid after the diverter arrives. Diverting agents of this type have
been used to divert in perforation tunnels, near-field fractures, slotted liners, and open hole zones to redirect
the fracturing treatment fluid to non-treated zones (zones that accepted little or no fluid previous to diverter
placement). Treatment fluids used to-date include frac gel, acid, scale treatment, and well-control
treatments. The treatment can either be placed in aqueous fluid between applications or bullheaded before
an application, such as with split casing where one is attempting to divert away from a trouble zone.
Volumes required depend on the geometry of where diversion is desired. Reservoir or treating pressure will
not affect biodegradable diverters. Advantages of the biodegradable diversion material include reducing
treatment time, distributing treatment fluid more efficiently, eliminating the need to drill out plugs,
compatibility with many fracturing fluids, and degradation over time. Proper prejob planning with attention
to equipment preparations and rig up are keys to successful usage of the Diverter Frac (Halliburton 2012)
for proper pumping.
Diverter Delivery and Diversion
Using a method to alter flow distribution is called diversion. Its purpose is to divert the
flow of fluid from one portion of an interval to another. The diversion method best suited
for a particular situation depends on many factors, including but not limited to the type of
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well completion, perforation density, the type of fluid that is produced or injected after
the diversion treatment, casing and cement sheath integrity, bottomhole temperature, and
bottomhole pressure available as flow-back energy (Reyes et al. 2011).
In this paper, particle bridging is achieved with a product that is multi-sized,
biodegradable, and temporary. Two specific size distributions exist.
The action of the smaller particles will “nest” in the pore throats of the coarse-sized
particles and create a seal to fluid flow. A characteristic of particle bridging is that it is
independent of the size or geometry of the perforation or void space. The “variable” mesh
will accumulate and divert fluid flow. At the designed temperature, the material will
soften, helping achieve a seal that is more restrictive to flow, which creates back-
pressure against any fluid that attempts to flow into a diverted channel; this allows higher
pressure in the wellbore that may be needed to initiate flow in a new zone.
Once the material is pumped into the perforation or fracture, it will later degrade based on
temperature and/or time. The “Material A” form of this agent is effective in wells with a
bottomhole static temperature (BHST) of 160 to 320°F. Refer to Fig. 1 for the
degradation of Material A. For wells with lower BHSTs, Material B is effective in as low
as 140 and up to 450° F (see Fig. 2 for details). For cooler wells, because the degradation
takes time to occur, depending on pumping time, it can be acceptable to use diversion
frac for proppant distribution, but laboratory testing must confirm the candidate well.
Case History A was such a well, with BHST of only 127O
F.
Degradation of these materials is based on the dissolution of the materials in water or
other brine solutions. For typical well flowback, 100% dissolution is not required. Field
experience has indicated that as little as 20% degradation would result in non-restrictive
flowback and clean up times would not be impacted.
Case History A
Wellbore
The case history discussed here derives from a horizontal west Texas well in Ward
County. The well is cased with 7-in. 26 ppf casing to 8,610 ft, then a 4.5-in. liner 11.6 ppf
is hung at 7,651 to 12,353 ft. True vertical depth (TVD) is 8,144 ft. Drilled in the
Devonian formation, perforations are at 12,213, 11,900, 11,546, 11,145, 10,703, 10,253,
9,989, 9,633, 9,366, 8,967, 8,655, and 8,344 ft shot with 12 shots per foot. Pore pressure
is 3,092 psi with 127°F BHST. In the original completion sliding sleeves were run as a
part of the liner, and the sleeves would not open, causing a job failure. The ball-seat
baffles had to be drilled out to allow perforating. Using the diversion frac for proppant
distribution material, it was decided to perforate the above depths and have the horizontal
lateral 100% open in all zones planned to frac. The fracture treatment design would
incorporate diversion to place the proppant treatment into all zones in one large pump-in
stage. Tables 1 through 3 present the details for the tubulars, perforations, and lithology
of the Ward County well.
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Design
It was decided to pump a guar-based crosslinked fluid ( prepared from 15 cp base gel)
carrying 1, 2, 3, and 4 lbm/gal brown 20/40-mesh sand in five separate stages. After each
flush, the plan was to drop 240 lbm of 100-mesh sand with 240 lbm of the diversion frac
for proppant distribution material such that it equates to 2 lbm/gal concentration for the
diverter combinations based on the volume in which they were mixed. As there were five
proppant frac stages planned, diversion material was dropped after Stages 1 through 4.
After Stage 5, only a flush was to be used.
Actual
The fracture treatment used the following volumes: 74,848 gal of linear 15cp fluid used
for flushes and to place diverting material downhole; 75,663 gal of crosslinked gel used
in pad stages and 209,464 gal of crosslinked gel used to carry 319,848 lbm of 20/40-mesh
brown sand at 1, 2, 3, and 4 lbm/gal concentrations; and 5,964 gal of crosslinked gel to
carry the diverters at a 2 lbm/gal concentration.
Note: All crosslinked gel was prepared using the 15 cp linear gel.
Figs. 3 through 6 illustrate diversion effects. Stage 1 (not shown) pumped 47,833 lbm of
proppant, and Stage 2 was commenced (Fig. 3). Stage 2 first dropped diverter at 11:23
min on the surface and then arrived at the calculated bottom interval at 11:43 min, which
corresponds to a 200-psi increase in pressure in between these two times as diverter
approaches an uphole open perforation; operations proceeded to frac, as designed. A total
of 123,203 lbm of proppant was pumped in Stage 2.
In front of Stage 3 was the second diverter drop (Fig. 4). Diverter was dropped at 13:46
on the surface and at 14:11 on the calculated bottom interval, with a 400-psi increase in
pressure at 13:56. Operations proceeded to frac Stage 3. Sand-laden fluid was pumped
(not as designed, due to high pressures) at 0.5 and 1 lbm/gal. A total of 32,891 lbm of
proppant was pumped.
Prior to Stage 4 was the third diverter drop (Fig. 5). Diverter was dropped at 15:54 on the
surface and at 16:18 on the calculated bottom interval, with a 300-psi increase in pressure
at 16:16; operations proceeded to frac Stage 4. Sand-laden fluid was pumped (not as
designed due to pressure rise) from 0.5, 1, 2, and 3 lbm/gal. The operator did not attempt
to pump the 4 lbm/gal concentration. A total of 115,921 lbm of proppant was pumped in
Stage 4.
Preceding Stage 5 was the fourth diverter drop (Fig. 6). Diverter was dropped at 17:45 on
the surface and at 18:17 on the calculated bottom interval, with elevated pressures.
Pumping sand-laden fluid was not attempted because of maximum pressure, and the job
proceeded to the flush stage.
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Conclusions for Case History A
This work discusses a case history from a horizontal west Texas well in Ward County
involving diversion frac for proppant distribution. The project was initiated with a
troubled horizontal wellbore with an economic burden. Having not been stimulated, any
treatment seemed costly, as completion tools that had previously failed had to be altered
before the operator believed a fracture treatment could be attempted. A pumping service
company engineered a remedial design stimulation program involving pre-perforating of
12 zones and using a diversion frac for proppant distribution, which was pumped with
excellent results. Both the service company and the operator were satisfied with the
results, but production numbers have not yet been released at the request of the well
operator. The 4,000-ft lateral and 144 perforations encompassing many stages of shale
pay were effectively stage fracture treated in approximately 10 hours. This pump-in
included 319,848 lbm of 20/40-mesh brown proppant and 365,939 gal of fracturing fluid
with additives and breakers set to create a significant stimulated reservoir volume (SRV),
providing the well a very good chance for economic production.
Case History: Well B
The second case history is in Ward County, TX where the customer had experienced a
troublesome drilling experience and resulted in over-budget costs to drill and breach in
liners of two wells. Breach in liners was due to dogleg severity at magnitudes of 18% at
multiple points after drilling had gone 90 Degrees. Questionable liner threads had
apparently failed as liner was lowered into wellbore and a breach occurred. With
expensive remediable work foreseeable, the option presented itself to cut losses and move
off wells and plug or abandon lateral and move for uphole production. The well operator
sought for a new solution. Diversion Frac for Proppant Distribution PD was the well
operator’s chosen option, designed to first seal the beach, then to stage fracture the
horizontal below the damaged liner. This would accomplish a few things. First, this
breach repair was relatively inexpensive, unlike scab liners or alternative repairs. Second,
it would allow the operator to stimulate and produce from a well that ran overbudget and
was possibly going to be a total loss otherwise. The third value point was the internal
diameter would be undisturbed, whereas costly patches could limit internal diameter
making perforation runs more complex. The fourth advantage is the Proppant
Distribution PD stimulation would offer the operator some potential to pay expenses of
the costly aborted drilling program.
The breach was sealed by pumping Diversion Frac for Proppant Distribution PD to
prepare the wellbore for a fracture stimulation. The design was to pump three stages with
a diversion material and evaluate using surface pressure after each drop of diverter to
determine if the next diverter drop was necessary. First drop was 500 lbm of
BioDegradable Diverter at 0.5 lbm/gal in xanthan gel. Note pump schedule in Table 4:
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A second more aggressive diverter schedule was pumped next (Table 5):
After the first diverter hit, surface pressure showed 5600 psi to 6300 psi increase was
observed. After the second diverter stage hit, surface pressure showed 5950 psi to 6300
psi was observed. This was good news and it was decided that Diversion Frac for
Proppant Distribution PD had achieved objectives and it was decided to schedule and rig
up fracture crew and move forward with stimulation. Diversion Chart is below, see
Figure 7.
The fracturing equipment was rigged up and the compartment stages below the sealed
breach were fracture stimulated. To reduce exposing the perforation and plug runs
through the breeched region of wellbore, it was decided to redesign the fracture design
from one stage at a time and combine three stages into one pump-in operation.
Combining fracture stages into one pumping operation is achieved by using Distribution
Frac for Proppant Distribution PD. This allows the operation to eliminate top plugs that
would normally isolate the previously fracture stage. Bio Degradable material, (Material
B) is used to screenout and seal the previously pumped fractured area allowing operations
to then proceed to next fracture treatment into subsequent zone. The material will degrade
with time after the fracture stimulation is complete. On this particular well three stages
were pumped with two Proppant Distribution PD drops made.
Conclusion: The liner breech was sealed with the biodegradable material and fracture
treatment was resumed using a one pump in operation from below the repair to the toe.
This combined three stage in one and used this same biodegradable material as a bridge
to isolate the previously fracture stimulated zone. This allowed a troubled well to produce
without the expense of a costly well bore remedial repair.
Case History C
The third well was again in Ward County, TX . It was a Devonian Formation horizontal
well completion. A production liner was set at 7564 ft and ran to depth of 15110 ft. A
tieback liner was run to surface. Both liners were 4.5 inch, 11.6 lb/ft, P-110 grade.
Intervals were as such, see Table 6 below. The stage completion tools had failed and
opening the sleeves was not an option. It was decided to drill out the baffles so it would
be possible to perforate for all zones below the Woodford, from toe section to the heal
portions of the lateral and use Diversion Frac for Proppant Distribution PD to divert
between stages, fracturing all zones in one pumping operation. The Woodford zone near
the heel was not perforated and would not be treated until later. For this operation, the
material would divert the zone that accepted the previous treatment stage and open up the
next least-resistive zone to break it down. The next treatment stage would go into this
newly broken down zone. This process would be repeated up to 11 times until all zones
were treated. Table 7 shows a treatment schedule for one zone. Pumping treatment stages
1 – 14 (skipping 2 stages in between). Drop 1000lbs of Material B in 1000 gallons.
Repeat after 11 stages, then shut down and prepare well for wireline. Do not drop
Material B on 12th
or last pump in.
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Conclusion for Well C
Inheriting the wellbore with 100% completion tool failure and a complex and expensive
plan to overcome the situation, remedial efforts went with the biodegradable diverter
which allowed the service company to stimulate all stages without costing the well
operator the expense of reverting back to plug and perforating methodology. It was
observed that all zones were believed to be treated and all 12 stages were completed in
one day. This saved days in completion time and allowed operator to flowback well days
ahead of schedule. Treatment Charts are below with proppant mass pumped. See
following charts which all indicate diversion.
References EIA U.S. Energy Information Administration, August 2012.
