World Oil
®
Originally appeared in the ShaleTech Supplement of
MARCH 2015 issue, pgs 31-34. Used with permission.
SHALETECH REPORT
How curable resin-coated proppant tail-in
prevents proppant flowback, reduces workover costs
This study examined 46 wells in AWP field
in McMullen County, Texas, over a 10-year
time frame. The authors compared 23 wells
using 100% frac sand, and 23 wells utilizing
a curable resin-coated proppant tail-in. The
study concluded that there is a positive net
present value when using curable resincoated proppant tail-in to control frac sand
flowback.
ŝŝKEITH GREFF, KEITH HUEBINGER and BRUCE GOLDFADEN,
Fairmount Santrol
An in-depth study compares workover equipment and
material cost, workover rig and crew expense, and lost-time
production in the years following hydraulic fracturing stimulations that used 100% frac sand as the proppant vs. a curable
resin-coated proppant tail-in (RCT) for proppant flowback
control. All wells in the study are vertical and are artificially
lifted by rod pumping. The wells are in AWP field, McMullen
County, Texas, in the Olmos formation.
The well data encompass 46 vertical wells during a 10year time frame, from the early 1990s through May 2013. The
For the AWP field study, curable resin-coated proppant tail-in
yielded $114,614 of additional value per well, at a 10% NPV vs. the
100% sand wells. Photo courtesy of Fairmount Santrol.
authors compared workover equipment and material cost,
workover rig and crew expense, and the lost production cost of
23 wells stimulated with 100% frac sand, and 23 wells stimulated with a curable resin-coated tail-in at an average 10.5% of
the total volume. The proppant cost for a curable resin-coated
tail-in well was $20,000 higher, compared to the proppant cost
for a100% frac sand well for these hydraulic fracturing jobs.
The study reveals the long-term economic value of preventing proppant flowback into the wellbore, to reduce workover
cost. By using a curable RCT to prevent proppant flowback,
this study documents how an operator can pay for the proppant through lower workover cost and increased well uptime.
The net present value (NPV) of the difference in the compared groups for the total workover cost equals $2,770,419. This
assumes a 10% discount rate. By subtracting the cost difference of
the two proppant types from the NPV of the total workover cost,
we see the operator experienced a net value gain of $2,310,419.
Looking at the sample size, the 100% frac sand wells experienced lost production of 24,837 hr, equating to lost production of one well for 2.8 years. The RCT wells experienced lost
production of 11,413 hr, equating to lost production of one
well for 1.3 years. The difference between these two groups of
wells equals an increase of 13,424 hr that is equivalent to one
well’s production for 1.5 years, confirming the long-term economic value of proppant flowback control. The research documented workover equipment and material cost, the workover
rig and crew, and lost production from downtime were the
most important factors contributing to the difference.
BACKGROUND
AWP field is in McMullen County, Texas, and produces
from the Olmos formation. A clastic wedge that gradually
thickens southward from Medina and Uvalde counties, the
formation is truncated by post-Olmos erosion to more than
1,000 ft in Webb County.1
The Olmos formation reservoir has a complex oil-gas-water
pattern, rather than the traditional gas-oil-water pattern. Oil can
be found in the upper part of the reservoir and gas in the deeper,
more distal part. The reservoir is normally-to-slightly underpressured, having an average fluid-pressure gradient ranging
from 0.36 psi/ft to 0.43 psi/ft. Regionally, net sandstone thickness is about 60 ft to 150 ft in depositional packages that vary
from 15 mi to 75 mi in length, and 20 mi to 60 mi in width.2, 3
A few horizontal wells have been drilled by various operators in the field, but most of the results have been poor, due
to issues associated with staying in zone or partial depletion by offsetting, earlier wells. In the southern, deeper, gasprone parts of the field, horizontal wells have been more
successful. Because AWP field wells are drilled in a tight,
low-porosity, low-permeability sand of 0.1 mD or less, with
World Oil® / MARCH 2015 S–31
SHALETECH REPORT
Table 1. Documented operational problems caused by proppant
flowback in the Olmos formation.
Rod or
Pump
Tubing Job
change
Fishing
Resin
135291
Sand
483 17131
Differences: Sand minus resin
348
142
30
Percentage improvement
72%
83%
97%
In resin wells
Material/third-party cost
Cost/event $600 $4,500 $3,000
downhole temperatures up to 259°F, oil and gas will not flow
naturally.4 Hydraulic fracturing is required. During the paper's
study time frame, operators had not drilled many horizontal
wells in this field. That has changed with better horizontal
drilling technology.
These tight sands are similar to unconventional shale reservoirs, in that they both have very steep initial production
decline curves. The value of these wells increases because of
refracturing, which can increase production higher than the
initial output, even as long as 15 years later. Most of these
vertical wells are refractured two to three times, because the
stress field changes over time, as the wells are drawn down; refracturing appears to contact a new undrained reservoir. This
field remains vital, because most wells are being refraced.
AWP FIELD FRACTURING HISTORY
Production from the Olmos formation was established in
the 1920s, and some production from AWP field began in
1975; however, it was not until December 1981 that the actual
field discovery well was drilled (Burnett Oil Co.’s Elliot No.
1). Fracture stimulation technology was applied to the tight
Olmos sand formation, making oil and gas production from it
economic. The field produced oil early in its history, and later
produced gas in a step-out to the south.
The Eliott No. 1 was completed with a gelled, water-based
hydraulic fracture fluid, using 70,000 lb of 20/40 Ottawa sand
and 16,600 lb of 20/40 sintered bauxite. The well produced
250 bopd and 150 Mcfd.5
The initial hydraulic fracturing treatments following the Eliott No. 1 well were smaller jobs, with relatively low proppant
concentrations, yielding minimal production. Next, operators
used moderately sized stimulation treatments of 60,000 to
160,000 gal of gelled oil, with 70,000 to 410,000 lb of sand
or high-strength proppant, yielding good initial production.
There was, however, rapid production decline, thereafter.
Operators also tried mini-fracs to calculate the closure stress
of the fractures, based on the fracture fluid efficiencies. This approach indicated that the fracture closure time could be long
enough to allow all of the proppant to settle to the bottom of the
fracture. This understanding led to a high-sand fracture design,
with concentrations of 14+ lb/gal for a large part of the designed
job. This design provided a settled proppant bed across the pay
zone, while compensating for proppant crushing and embedment
problems. Because of cost considerations, operators re-evaluated
and chose water-based fluid systems for these treatments. A typical frac job included 145,000 gal of gelled water with 1,610,000 lb
of sand, which produced results based on calculated expectations.6
By the mid-1980s, with declining oil prices, operators applied less expensive fracture stimulation using gelled waterS–32 MARCH 2015 / ShaleTech Report
based designs with 400,000 to 702,000 lb of proppant. Curable
resin-coated proppant was included in these designs to minimize or eliminate costly proppant flowback problems, and to
maintain better long-term conductivity in the near-wellbore
area. The curable resin-coated proppant also helped to address the frac sand crush and embedment problems. The RCT
wells’ production met or exceeded the larger 100% frac sand
stimulations.7 From 2000 to 2012, two operators performed
more than 150 hydraulic fractures and refractures, using gelled
water and an average 455,800 lb of total proppant per well on
vertical wells. Of these wells, 68% included an RCT, with an
average volume of 58,700 lb.
When the AWP field operator, who supplied the data for
this study, initiated a refracturing program, the service company found frac sand had flowed back into the wellbore, rather
than formation sand as first believed. Because the rod pumps
originally had been set at 1,000 ft above the perforations, to
prevent pump damage from the frac sand flowback, initial
production was not as robust as would have been the case, if
the pumps had been set closer to the perforations at 100 ft
to 200 ft.
By setting the pumps at no less than 200 ft above the perforations, in conjunction with using an RCT to prevent frac sand
flowback and damage to production equipment, the operator
was able to increase production more than 70 bopd, in some
wells. In marginal wells, production increased more than 30
bopd. The operator used 400,000 lb of total proppant, with
350,000 lb of frac sand and 50,000 lb of curable RCT for refracturing, resulting in a 7× to 20× production uplift.
Recently, with most of the current activity focused on
the Eagle Ford shale below the Olmos formation’s AWP
field, only 34 wells have been reported to be completed in
this field from January 2013 to February 2014, with 23 being vertical wells and 11 being horizontal.8 As of April 2014,
operators had drilled 8,482 wells in McMullen County from
1,075 producing leases.9
FLOWBACK OPERATIONAL PROBLEMS
During proppant flowback, which can occur throughout a
well’s life cycle, the proppant flows out of the reservoir fractures and back up into the wellbore. If an operator chooses to
pump a job with 100% frac sand, proppant flowback is common, requiring well intervention and causing significant, costly nonproductive time caused primarily by workover material
expense and crew cost. If the propagated fracture is lost in the
near-wellbore area, the reservoir can be damaged irreversibly,
causing a partial or total production loss.
Besides rod pump damage, there is also the possibility of
proppant flowback damaging surface facilities and filling up
the separation equipment. Frac sand can wash out the flowlines and separator dump valves. Facility repairs can require
wells to be shut in, resulting in lost production time that cannot be recaptured. As far as the reservoir, when proppant
flows back into the near-wellbore area, an operator could
lose a portion of the proppant investment. Direct surface facility costs were not included in this study, but they warrant
further investigation.
A worst-case scenario from raw sand flowback is a lost well,
with the associated investment loss of $1.5 million for this
field’s vertical wells. The right RCT, with the correct bond
SHALETECH REPORT
Table 2. Gain in production hours from curable resin-coated proppant.
Average downtime
Year 1
2
3
4
5
6
7
8
9
10
Resin
70496330 1136 53584495
Sand
125 181139107123137 90 101 45 33
Hourly savings per resin well
55
132
87
77
111
101
37
44
1
(62)
Lost production per year [23 sand wells]
1262
3044
2004
1775
2556
2326
852
1005
20
(1,418)
Incremental downtime factor [resin vs. sand]* 0.14
0.35
0.23
0.2
0.29
0.27
0.1
0.111
0
(0.16)
Gain in production hours from resin [single well] Number of sand wells
23Total production hours in a year [365×24]
Lost production years sand
2.8Lost production hours [23 sand wells]
Lost production years resin
1.3Lost production hours [23 resin wells]
Lost production years (sand minus resin)
1.5Gain in production hours from resin [23 sand wells] 584
8,760
24,837
11,413
13,424
*Lost production hours per year [23 sand wells] divided by total production hours per year [365×24]
Table 3. Net present value (NPV) of increased production.
Year 12345678910
Incremental downtime factor 14%
35%
23%
20%
29%
27%
10%
11%
0%
-16%
[IDF] [resin vs sand]
Average single well, boe/year
10,500 7,332 5,807 4,788 4,308 3,389 3,127 3,014 2,902 2,505
IDF×single well, boe/year
1,512 2,548 2,548 970 1,257 900 304 346 7
(406)
Oil 60% @ $80*/bbl
$72,579 $122,314 $122,314 $46,563 $60,332 $43,187 $14,590 $16,592 $324 $(19,468)
Gas 40% @ $3.50*/Mcf
$2,117
$3,567 $3,567 $1,358 $1,760 $1,260 $426 $484 $9 $(568)
Total hydrocarbon cash flow
$3,248
$5,473 $5,473 $2,084 $2,700 $1,932 $653 $742 $15 $(871)
[single well]
Total hydrocarbon cash flow
$74,696 $125,881 $125,881 $47,921 $62,092 $44,446 $15,016 $17,076 $334 $(20,035)
[23 wells]
Discount rate
10%
10-year npv of hydrocarbon cash flow [single stage]
$14,161 10-year npv of hydrocarbon cash flow [23 wells] $325,699 *Estimated net prices to operator
strength or unconfined compressive strength (UCS), will
form a proppant pack that locks the frac sand into the fractures
and prevents the sand from coming back up the wellbore.
METHODS AND RESULTS
The authors began this comprehensive study by identifying wells with sufficient documentation for a 10-year examination, comparing workover costs in wells that were completed
using two separate hydraulic fracturing approaches: 23 wells
were hydraulically fractured with 100% frac sand, and 23 wells
were fractured with curable RCT.
The 100% frac sand wells averaged 428,000 lb, and ranged
from 250,040 lb to 600,080 lb pumped. The RCT wells averaged a total of 435,000 lb, and ranged from 150,120 lb to
575,120 lb. The percent tail-in used of the total volume
pumped averaged 10.5%. Next, the authors scanned 6,999
pages of well files, including the workover-related expenses by
invoice, for all 46 wells. They manually entered all of the data
into an analysis system. The authors determined the difference between the workover costs for the 100% frac sand wells
and the RCT wells during the 10-year time frame.
Table 1 describes three operational problems caused by
frac sand flowback—rod and tubing failures, pump changes,
and fishing.
Rod and tubing failures. Traditionally, rod and tubing
failures fall into two categories: corrosion or rod-and-tubing
wear. This study reveals that the RCT wells reduced this failure rate by 72%, leading to lower workover costs and less production downtime.
Pump changes. Whether the 46 wells in this study were
completed with 100% frac sand or RCT, all wells were lifted,
using a similar sucker rod pumping design. There were 83%
fewer pump failures in the RCT wells.
Fishing. In the 100% frac sand wells, fishing was required
to retrieve broken rods, in addition to other workover tools
and equipment that became stuck during swabbing and
workover. The need for fishing was essentially eliminated in
the RCT wells, because of a general reduction in workover
events and rod failures. During this study’s 10-year history,
there was only one fishing job in the RCT wells, compared
with 31 fishing events in the 100% frac sand wells. Besides
these three workover events listed above—rod and tubing
failures, pump changes, and fishing—all of the workover categories and their related costs for maintaining the wells were
captured in this study.
Gain in production hours. One of the major challenges
for a producing field is to keep production flowing and minimize downtime. Looking at the RCT wells, there were added
production days compared with the 100% frac sand wells.
Each RCT well had an average 584 additional production days
or, for all 23 resin wells, a total of 13,424 additional production hours, Table 2.
Value of increased production. The average single-well
boe/year is the annual average production for all wells in the
study. The authors multiplied the incremental downtime factor (Table 2) by the single well boe/year to determine the
production loss percentage from all of the sand wells. The authors applied a dollar figure by adjusting the boe for the average production stream of $80 for liquids (60%) and $3.50 for
natural gas (40%).
The authors could not determine the amount of NGLs,
but they believe that if the NGLs were included, the NPV
World Oil® / MARCH 2015 S–33
SHALETECH REPORT
Table 4. Economic value of curable resin-coated proppant tail-in.
10% NPV Total Workover Costs
10% NPV Incremental production
Incremental Cost of Resin
Economic Value of Curable Resin
23 Wells
2,770,419 325,699 460,000 $2,636,119 Single stage
120,453
14,161
20,000
$114,614
Fig. 1. Annual cost-saving per well with RCT well.
50,000
Equipment and material
cost saving
Workover rig and workover rig crew cost saving
Total hydrocarbon cash
flow, single well
Total cost saving per well,
per year
40,000
Dollars
30,000
20,000
10,000
0
-10,000
-20,000
1
2
3
4
5
Years
6
7
8
9
10
would increase significantly. The 10-year, 10% NPV for the
difference in lost production for all 100% frac sand wells is
$325,699 or $14,161 per sand well, Table 3.
Total workover cost includes the workover equipment and
material cost, in addition to the workover rig and workover rig
crew cost. The RCT wells had lower workover costs during
eight of the 10 years studied. Each RCT well achieved an average saving of $178,431 (gross) vs. the 100% frac sand wells.
Even considering the additional $20,000 resin proppant cost
per well, and using a 10% NPV, the saving for an RCT well
was $100,453. Collectively, all 23 RCT wells saved the operator $4,103,924 (gross) or $2,310,419 with a 10% NPV, minus
RCT. Figure 1 details the annual well cost saving.
TOTAL ECONOMIC VALUE
For the AWP field study, the RCT wells yielded $114,614
additional value per well at a 10% NPV, when considering the
workover expenses and the lost production because of down-
time vs. the 100% sand wells. The additional value for all 23 tailin wells at this NPV calculation was $2,636,119, Table 4.
ACKNOWLEDGMENT
This article is adapted from URTeC paper 1922860, presented at the Unconventional
Resources Technology Conference, Denver, Colo., Aug. 25-27, 2014.
REFERENCES
1.Tyler N., “Depositional setting and production characteristics of low-permeability
sandstones, Upper Cretaceous Olmos formation, South Texas,” SPE/DOE paper
16424, presented at SPE/DOE Low Permeability Reservoirs Symposium, Denver,
Colo., May 18-19, 1987.
2.Condon, S.M. and T. S. Dyman, “Geologic assessment of undiscovered conventional oil and gas resources in the upper Cretaceous Navarro and Taylor groups,
Western Gulf Province, Texas,” U.S. Geological Survey Digital Data Series DDS69-H, 2003.
3.Kosters, E.C., D. G. Bebout, S. J. Seni, C. M. Garrett, Jr., L. F. Brown, Jr., H.
S.Hamlin, S. P. Dutton, S. C. Ruppel, R. J. Finley and N. Tyler, Noel, Atlas of Major
Texas Gas Reservoirs, University of Texas, Bureau of Economic Geology, Austin,
Tex., 1989, p. 161.
4.Barrett, K., L. Fogarty, L. Simoneaux, Project Literature Review, Nov. 5, 2009.
5.Pauls, R. W., J. Venditto, P. Chisholm, M. Holtmyer and W. Gregorcyk, “Successful stimulation of the Olmos formation using oil-base fluids and high-proppant
concentrations,” SPE paper 13817, presented at the SPE Production Operations
Symposium in Oklahoma City, Okla., March 10-12, 1985.
6.Conway, M.W., D.E. McMechan, J.M. McGowen, D. Brown, P.T. Chisholm and J.J.
Venditto, “Expanding recoverable reserves through refracturing,” SPE paper 14376,
presented at the SPE ATCE, Las Vegas, Nev., Sept. 22-26, 1985.
7.N.S. Peard, M.L. Macaluso, M.C. Griffin, R. Andress, M.J. Callanan, “Improved
fracturing techniques increase productivity in the AWP (Olmos) field, paper SPE
21646 presented at the SPE Production Operations Symposium in Oklahoma City,
Okla., Apr. 7-9, 1991.
8.DrillingInfo, info.drillinginfo.com.
9.Texas-drilling.com/mcmullen county
KEITH GREFF, JR, is senior analyst, marketing, for
Fairmount Santrol. He contributes to the demand
planning for well-placed and right-sized mines,
terminals, processing facilities, and the management
of the company’s private railcar fleet. Mr. Greff has a
BS degree in economics from the University of
Louisville.
KEITH HUEBINGER is Southern Basins sales director
for Fairmount Santrol. He is responsible for frac sand
and resin-coated sand sales in the southern U.S. Mr.
Huebinger has 33 years of oilfield experience, with
30 years in pressure pumping services. He has a BS
degree from Texas A&M University.
BRUCE GOLDFADEN is technical communications
manager for Fairmount Santrol. Mr. Goldfaden has
been working in upstream oilfield marketing
communications since 1997. He has an MA degree in
journalism from Ohio State University and a BS
degree in journalism from The University of Texas.
Article copyright © 2015 by Gulf Publishing Company. All rights reserved.
Printed in U.S.A.
S–34 MARCH 2015 / ShaleTech
Report
Not to be distributed
in electronic or printed form, or posted on a website, without express written permission of copyright holder.