Drilling with casing cuts top-hole time, sets length record

Originally appeared in World Oil ®
CASING teChNoloGy
Drilling with casing cuts top-hole time,
sets length record
Drilling with casing in Australia’s Carnarvon
basin saved 24 hours of rig time by drilling,
casing and cementing the top-hole section
to total depth in a single trip.
ŝŝBUDI UTAMA, Weatherford; and RICHARD READING, Apache
Energy Ltd. Australia
In western Australia’s Carnarvon basin, drilling the 16-in.
hole section and running 13⅜-in. casing was a long process.
Fluid losses—sometimes total—required use of seawater to
drill, and tight hole conditions resulted in back reaming, wiper
trips and spotting pills. To reduce time spent fighting these
problems and ensure the 13⅜-in. casing reached TD, a casing
drill bit was employed to ream the casing to bottom while improving
drill-out time. The operations were carried out using
a top drive casing running system already installed on the rig.
The drilling-with-casing (DwC) operations effectively mitigated
hole problems, yielded a safer and more cost-effective
surface hole, and significantly reduced non-productive time
(NPT). In reaching a total depth of 3,296 ft, the application also
set a global service company and operator record for the longest
section drilled with 13⅜-in. casing.
CASING BIT SELECTION
The Barberry-1 exploratory well is in the TL/2 permit area,
southwest of Barrow Island off the northwest coast of Australia.
One of the first tasks in preparing to drill with casing was a
january 2012 issue, pgs 57-64. Posted with permission.
drillability analysis using data from two offset wells, Chervil-1
and Basil-1 ll. The analysis ensured that unique design limitations
of casing drilling bits were considered when comparing
performance to conventional drill bits. Based on regional experience,
offset findings and previous product performance, a
premium 13⅜ x 17½-in. DPC519 Defyer casing drilling bit was
selected to ensure TD would be achieved at high ROP, Fig. 1.
The bit is designed for drilling in medium-to-medium-hard formations
with unconfined compressive strengths up to 15,000
psi. It features five displaceable steel blades with 19-mm PDC
cutters. The blades are coated with a layer of tungsten carbide
to provide resistance to erosion and abrasion during drilling. A
pressure-cycled, PDC-drillable piston displaces the PDC-laden
blades into the annulus after reaching TD.
Drillable nozzles with ceramic bore liners were fitted on the
bit to resist fluid erosion at expected high flow rates. The 10 14/32in.
nozzles were matched to desired flow rate. Total flow area and
hydraulic horsepower at the bit were calculated using proprietary
hydraulic analysis software to enhance penetration rate.
DRILLING EQUIPMENT
A specialized top drive unit provided rotational force for turning
the casing string. The Weatherford OverDrive top drive casing
running and drilling system was already aboard the jackup
drilling rig, Ocean Shield, where it had been used over the previous
18 months to rotate drill pipe. In prior work, the versatile
drive was employed to drill-in 18⅝-in and 13⅜-in. casing strings.
The top drive, fitted with a 13⅜-in. internal clamping tool
(ICT), extension bails, and single-joint elevators, was the primary
means for making up and drilling with the casing string. It
has a maximum rotary speed of 100 rpm and maximum pump
pressure capacity of 3,750 psi. Flush mounted slips and hand
slips were used to suspend and retain the casing in the rotary
table as connections were being made up. Hand slips were employed
to minimize damage to the flush mounted slips due to
increased vibration experienced at greater hole depth, Fig. 2.
A 13⅜-in. modified drilling-with-casing spear was prepared
as a back up in the unlikely event of a top drive failure. Commonly
used to drill-in casing strings, this simple tool has the
capacity to drill the 13⅜-in. string to 1,000 m. The spear is connected
to the top drive with a drill pipe pup joint and crossover
sub. It incorporates a pack-off seal to retain pressure, gripping
members, and a stop ring. The spear is inserted into the casing
from the top. When the stop ring contacts the top of the connection
or casing collar, slips are precisely positioned on the casing
joint. A quarter turn to the right engages the grapple slips. As
the top drive is elevated, the slips fully engage the inside casing
diameter to hold the string and enable torque transmission. Removing
tensile force from the spear and rotating a quarter-turn
to the left releases the tool.
World Oil / january 2012 57

CASING teChNoloGy
The float valve was modified for the application. A conventional
poppet-type float valve cannot be used with the casingdrilling
bit, because a ball (2.75 to 3-in. phenolic or aluminum)
is required to cycle the tool and displace the cutting structure.
Instead, the system uses a converted auto-fill float collar rated
at 30 bbl/min for 24 hours using 12 to 12.5-ppg mud with 2 to
4% sand content. The auto-fill feature is not required for the
DwC application, so its ball and tube assembly is removed in
the workshop prior to make-up.
CASING AND CONNECTIONS
Casing drilling operations subject the casing string to many
stresses, including cyclic fatigue, torsion cycles, and compression
loads. The potential for this moderate wear must be con-
Fig. 1. The 13⅜-in. x 17½-in. OD casing bit used offshore australia
is designed for unconfined compressive strengths up to 15,000
psi (1,034 bar). The bit’s five steel blades, fitted with 19-mm PDC
cutters, are displaced at TD prior to cementing.
sidered in the casing design phase. Casing design must also factor
in burst and collapse loads as well as sealing requirements
after being subjected to these drilling stresses.
Casing and connection specifications for Barberry-1 called
for 13⅜-in., 68 lb/ft, L-80 pipe with API buttress connections.
This common casing connection does not have a torque shoulder
inside the connector ("J" area), which results in low-torque
transmission capacity. To provide additional torque resistance,
dedicated torque rings were installed in each connection, Fig.
3. The torque ring is a pressure-actuated, metal-to-metal sealing
system. When made up, initial contact force is established
between the pin end and the fulcrum center torque ring. Additional
internal pressure increases sealing contact force beyond
axial loads and pressure of accepted string design limits.
To make up the casing, a special insertion tool was used to
install and seat the ring in the "J" area prior to coupling. Makeup
at 5 to 14 rpm requires close attention to torque. When
torque begins to rise quickly, the pin nose has shouldered up
to the rings.
DRILLING OPERATIONS
The 20-in. shoe was drilled out with a re-run 17½-in.
roller cone bit, which then drilled on to a depth of 685.73 ft
measured depth from the rotary table (MDRT) or 367.47 ft
drilled. Two of the 36-in. hole opener cones were lost in the
previous hole section; one was retrieved but the second cone
remained in the hole. It was not encountered while drilling the
17½-in. hole to 685.73 ft MDRT.
Total losses were encountered while drilling the section,
which is common for the area. At that point, the 17½-in. bot-
58 january 2012 / WorldOil.com
tom-hole assembly (BHA) was pulled out of hole and the top
drive system was rigged up to drill-in with 13⅜-in. casing. A job
safety analysis was conducted to communicate the DwC running
procedure and all associated potential hazards.
The pre-assembled shoe joint and casing-drilling bit was
picked up and visually inspected to ensure all PDC cutters and
blades were undamaged. The assembly was then run through
the rotary table and flow tested to confirm that all nozzles were
free of debris. The flush mounted slips were installed. The float
collar joint was made up on the shoe joint and the connection
was thread-locked. Torque rings were installed on the subsequent
casing joints, which were made up to 25,000 ft-lb.
The string was washed down to TD at 250 gpm until bottom
was tagged. Casing drilling operations began at 685.73 ft within
recommended parameters of 60 to 100 rpm, 1,200 to 1,400
gpm and 1,000 to 25,000 lb WOB. High-viscosity sweeps were
pumped every joint to deliver effective hole cleaning.
Some drilling-induced vibration was noted at surface. To
avoid damage to the flush-mounted slips, they were replaced with
conventional casing hand slips. Drilling continued to the section
TD. Maximum drilling parameters were 80 to 100 rpm, 1,400
gpm at 1,350 psi standpipe pressure (SPP), 15,000 to 28,000 lb
WOB and 15,000 to 22,000 ft-lb drilling torque.
Some minor problems were encountered drilling the section.
The casing string stalled at 1,426 ft and a 25-bbl high viscosity
sweep was pumped to resume the drilling process. When ROP
dropped to around 98.43 to 164.05 ft/hr and SPP increased to
1,800 psi at 2,562 ft, the casing string was raised off bottom and
partially hydrolyzed polyacrylamide (PHPA) mud was circulated
around the bit to clear what appeared to be sticky claystone.
Drilling resumed with the torque limit increased to 16,000
ft-lb. High-viscosity, 25-to-30-bbl sweeps were pumped at every
joint, with mud returns to surface observed during the entire casing
drilling process. This is not typically observed when conventionally
drilling this interval. Standpipe pressure dropped 250 psi
from 1,350 to 1,100 psi at 3,215 ft. Reverse hydraulic calculations
suggested that one or more nozzles might have lost their ceramic
liners, thus slightly enlarging total flow area. However, the section
was drilled without effect to TD at 3,296.09 ft MDRT.
At TD, a 150-bbl high-viscosity sweep was pumped to clean
the hole prior to running the wellhead assembly. The wellhead
assembly was made up and run in hole on a landing string using
the top drive. A 3-in. phenolic ball was dropped and circulated
downhole to displace the bit blades. The ball was chased at 400
gpm. An excellent indication of displacement was presented
when the ball landed and the SPP built up to 1,600 psi before
dropping to about 90 to 100 psi at 100 gpm. Cementing commenced
once it was confirmed that the bit was fully displaced.
The top drive system was retracted, the cement head rigged up,
and cement was pumped according to plan.
SUCCESSFUL RESULTS
The 13⅜-in. DwC operation on the Barberry-1 well was
successful by many measures. The planned depth of 3,296.09
ft MDRT was reached at a high ROP, which saved approximately
24 hours of rig operating time compared with offset wells
drilled conventionally to a similar depth. Additional non-productive
time was avoided by the onshore make-up of the 13⅜in.
casing-drilling bit to the float collar and casing.
Rigging up the top drive running and drilling system was ac-

CASING teChNoloGy
Fig. 3. Torque rings were used to increase torque transmission
capacity of the standard casing during drilling operations.
Pipe
Coupling
FCR ring
complished without delay and according to plan. The system
proved to be well-suited to drilling with the 13⅜-in. casing
string. The torque rings installed in the “J” area of the coupling
to provide extra torque resistance sustained the expected medium-
to-medium-high drilling torque.
The 13⅜-in. x 17½-in. premium casing bit drilled from
685.73 ft to 3,296 ft for 2,610.36 ft of drilled depth. The average
on-bottom ROP was 285.12 ft/hr. As a result, the section was
drilled to TD in 16.27 hr, including connection time. Drilling
the 3,296-ft section set a world record length for drilling with
13⅜-in. casing for both Apache and Weatherford.
The high-viscosity sweeps pumped with every joint ensured
sufficient hole cleaning with the high ROP and increased cuttings
volume. Circulation losses were mitigated by the “smear
effect” mechanism produced by casing drilling, and mud returns
were observed over the entire interval.
LESSONS LEARNED
Surveys taken afterward when tripping into hole with a 12¼in.
rotary steerable assembly recorded inclinations in the 13⅜in.
casing, growing from 1° at 685.73 ft to 3° at 1,640.5 ft and to
9.15° inclination at 3,185.85 ft. This equates to an average build
rate of about 0.32° per 98.43 ft (30 m). Three main factors have
contributed to building angle on Barberry-1. First is the high
flow rate and potential for some formation intervals to wash
out. While the critical annular velocity was 221 ft/min at 1,400
gpm, annular velocity between the casing and a gauge borehole
(17½-in.) was 269 ft/min.
High WOB could have effectively tilted the bit to deflect
the wellbore from vertical. This effect is multiplied where
borehole wall erosion is present. Building angle could also be
due to the relationship of the outer diameter of the casing bit
to outer diameter of the casing, combined with high flow rate
and bit weight.
Changes in the relationship between casing bit and casing
OD were not achievable on the Barberry-1, because internal
and external dimensional limitations of the 13⅜-in. casing bit
prevent a design with a final borehole diameter any smaller
than 17½ in. Advances in casing bit technology now allow a
smaller final outer diameter of 16 in. Along with decreased
flow rates and WOB, the new design should reduce the build
tendency.
Pipe
Torqued up connection when
run in well in vertical position
Fig. 2. The Weatherford top drive casing running and drilling
system was already on the rig for standard drilling operations
when the decision was made to implement DwC operations.
CASING DRILLING SOLUTION
Success in drilling the troublesome top-hole section of the
Barberry-1 demonstrated the effectiveness of casing drilling
methods relative to conventional drill pipe operations. The capabilities
of casing drilling enabled by a unique top drive running
and drilling system resulted in a significant reduction in rig
time due to problem mitigation and operational efficiency.
BUDI UTAMA graduated with a BS in Petroleum
Engineering from universitas Pembangunan nasional in
Indonesia. He joined Weatherford Indonesia in 2006 as a
managed pressure field engineer. He transferred to the
Drilling with Casing department as an applications
engineer and presently works in onshore planning and
assists in drilling with casing field applications.
RICHARD READING began working in the oilfield in 1992
with ODE on Barrow Island for two years, for WaPET in
Western australia. In 2007, he went to work for apache
Energy as a drilling supervisor on the Van Gogh project.
after several months in this position, he moved to the
Perth office as a workover coordinator while pursung a
degree from the university of Western australia in oil
and gas engineering. upon completing his degree, he accepted his
present position as a drilling engineer with apache in the Perth office.
Article copyright © 2012 by Gulf Publishing Company. All rights reserved. Printed in U.S.A.
60 january 2012 / WorldOil.com
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