Transcript

World Oil

®

Originally appeared in

aPRIL 2013 issue, pgs 39-50. Posted with permission.

special Focus: DRILLING TECHNOLOGY

Liner drilling prevents circulation losses
for wells offshore Mexico

A series of wells in complex
lithology, in Carpa field of the
Faja de Oro (Golden Lane)
area, used liner drilling to
isolate the problem intervals
and reach planned setting
depths.

ŝŝRENATO G. RAMOS, F. AGUILERA

NAVEJA, GIOSWALD R. INCIARTE FERMIN,
Pemex Exploration and Production; MARCO
A. DOMINGUEZ, STEVEN M. ROSENBERG,
Weatherford

Massive circulation loss and hole instability problems offshore Mexico were
mitigated in a series of wells that incorporated liner drilling in their basis of design.
Problems on two previous wells in the
field had resulted in 55 days of nonproductive time (NPT) that cost an estimated $5.68 million. The drilling-with-liner
(DWL) solution allowed the operator to
reach the intended liner setting depths,
eliminate contingency liners, and ultimately meet well construction objectives.
Application of the technology over nine
wells also allowed optimization of the
liner drilling process for the specific application, including equipment selection,
operations and results.
The key to success was the ability of
liner drilling technology to isolate the loss
and instability intervals. Lost circulation
and wellbore instability problems, seen in
conventionally drilled wells, were effectively mitigated with liner drilling. In addition,
annular fluid management was enhanced
by the narrow annular geometry created by
liner drilling. Drilling operations were assisted by high torsional capacity and cyclic

fatigue resistance achieved with a hydraulic liner system, as well as the effectiveness
of drillable PDC casing bit technology in
drilling the trouble sections.
EL ABRA CHALLENGE

Pemex’s Carpa field is in the Golden
Lane (Faja de Oro) area of the Gulf of
Mexico offshore of northern Veracruz
state, Fig. 1. The El Abra reservoir rock
is a naturally fractured middle Cretaceous limestone capped by impervious
Miocene shales. It was extensively eroded
prior to Miocene age burial, and, as a result, the structural depth is very difficult
to predict. This difficulty is compounded
by the differential pressure between the
overlying shale and the El Abra, which is
the source of serious downhole problems,
including severe lost circulation, stuck
pipe, cave-ins and poor cement jobs.
Two appraisal wells, the Carpa 101
and Carpa 7, experienced significant
problems while drilling and required sidetracking to reach the El Abra. In the case
of the Carpa 101, 7-in. casing was run and
cemented at 7,865 ft. Drilling continued
World Oil / April 2013 39

DRILLING TECHNOLOGY

Fig. 1. Pemex’s Carpa field is in the Gulf of Mexico offshore of
northern Veracruz state.

San Diego de la Mar-1
Isla de Lobos

Gulf of Mexico

Tiburón
Tintorera-1
Calipso-1
Carpa

Tuxpan
Campos en
El Abra
Campos en
Tamabra

DWL EVALUATION

Esturión-1
Loc. Esturión-101
Marsopa
Bagre-101 Loc. Bagre-501
Campo Bagre
Campo Atún
Atún-101 Loc. Picón-1
Campo Morsa
Campo Escualo
Mejillón-1

Poza Rica
Tecolutla

0

20

40 km

with a 5⅞-in. bit and 8.8-ppg mud. The top of the El Abra was
reached at 7,960 ft, and drilling continued to 8,101 ft. A drillstem test (DST) was conducted, and no flow was observed.
A 5⅞-in. bit run to condition the hole met resistance at
7,875 ft, and the hole was reamed to total depth (TD) while
fighting cave-ins and mud losses. A 3½-in. liner with inflatable packers was then run and set at 8,016 ft. No production
was observed, and a 5⅞-in. sidetrack was initiated from the
7-in. casing at 7,209 ft. The sidetrack was drilled to 8,823 ft,
and the well was successfully placed on production. In total,
NPT drilling the El Abra accounted for 15 days and had an
economic impact of $900,000.
In the Carpa 7 drilling operations, 13⅜-in. casing was run
and cemented at 3,955 ft, and a 12¼-in. hole was drilled at
70° to 8,574 ft, using 10.3-ppg mud. At the top of the El Abra,
total mud loss was experienced, and seawater was pumped to
reestablish circulation. A trip into the hole met resistance, and
several incidents of stuck pipe occurred until 8,085 ft, when
the pipe got stuck again. Mud weight was increased to 10.7
ppg and the drill string was retrieved, but a fish was left in the
hole. When the fish was recovered, a Tricone bit was run. It
found resistance, particularly at the 8,091- to 8,144-ft interval.
After several attempts to go deeper failed, a cement plug was
set and a 12¼-in. sidetrack was drilled.
The sidetrack reached 8,515 ft—about 16 ft above the top of
the El Abra formation. A short trip back to the casing shoe experienced 30,000-lb drag between 8,190 and 8,537 ft. Mud weight
was increased slightly, and the bit was run to bottom. When attempting to pull out of the hole, 25,000-lb drag was experienced
and a pressure build, followed by circulation loss, occurred. The
pipe stuck and was eventually cut, leaving 154 ft of fish in the hole.
A cement plug was set above the fish, and a sidetrack was
drilled. Because of the potential of circulation loss in the top of
the El Abra and marl-related stability issues, the sidetrack was
drilled to about 40 ft above the El Abra, and 9⅝-in. casing was
run and cemented to 8,312 ft. An 8½-in. hole was drilled out of
the 9⅝-in. casing shoe with a 8.7-lb mud to 8,528 ft at an inclination of 72°, where a 7-in. liner was set, and a 5⅞-in. hole was
40 April 2013 / WorldOil.com

drilled to 9,020 ft TD.
NPT was also significant for the Carpa 7. The time spent
fighting the El Abra accounted for 39.65 days and a fluid loss
of 2,554 bbl, at a cost of $4.78 million. Experience drilling both
wells made it clear that drilling the El Abra formation required
finding a means of mitigating the circulation losses and instability
that were causing so much NPT.
Alternative solutions were examined with several objectives
in mind. Ultimately, the new approach had to minimize or eliminate NPT. Key goals included ensuring that the liner could be
set as planned into the top of the El Abra, while isolating the
overlying shale in a single hole section. In addition, it was important to achieve a competent cementing job that would eliminate the need for remedial cementing.
Offset well data were reviewed, including drilling, lithology, geological, bit records, and an analysis of NPT. The analysis
found approximately 55 days of NPT were spent in the problem
intervals of the Carpa 101 and Carpa 7 wells. Most of this was due
to circulation losses, and the related hole instability encountered
when attempting to identify the top of the El Abra.
Liner drilling offered several advantages that addressed the
project objectives. The technique is effective in minimizing and
eliminating lost circulation problems due, in part, to the smear effect, in which cuttings crushed in the narrow liner-wellbore annulus form an impermeable cake on the wellbore wall. The narrow
annulus also results in higher fluid velocities that improve hole
cleaning. Surge and swab problems related to pipe tripping are
minimized, because the liner is drilled-in and cemented in a single
trip. Once landed, the liner can be cemented almost immediately,
which reduces or eliminates hole preparation.
To take full advantage of these capabilities, Weatherford’s
DWL methods were incorporated in the well construction basis of design. The plans called for drilling the section into the
top of the El Abra formation in two stages. A conventional directional drilling system, with continuous rotation, would be
used to build a high-angle hole. After reaching a suitable depth
determined by an on-site geologist, DWL would be used to drill
the wellbore to the top of the El Abra, where the liner would be
hung immediately and cemented in place.
EQUIPMENT SELECTION

Choice of equipment was critical to the success of the project, because of the long time that the liner and the liner hanging
equipment would be exposed to the extreme loads and torques
of the proposed DWL operation. Bit experience in the original
wellbores led to the selection of 9⅝ × 12¼-in. and 7 × 8½-in.,
displaceable casing bits for the respective 9⅝-in. and 7-in. DWL
operations. The five-bladed PDC bit designs, with respective 16mm and 13-mm PDC cutters and tungsten carbide gauge protection, provided the appropriate cutting structure with the ability to
perform in formations with unconfined compressive strengths up
to 15,000 psi, Fig. 2. The gauge section design provided a backreaming capability. The drillable bit is converted to a drillable
casing shoe at TD, to enable drill-out with conventional PDC or
roller cone drill bits. Drill-out is eased with drillable copper or
ceramic nozzles that avoid the damage that conventional carbide
nozzles can cause to the drill-out bit.
When TD is reached, a ball is dropped into the liner run-

DRILLING TECHNOLOGY

DRILLING OPERATIONS

Nine wells were drilled in the Faja de Oro area using DWL
technology—five in Carpa field and four in Bagre field, Fig.3.
Standard drilling procedures were applied on each well to
reach the geologist-selected point above the El Abra. At this
point, the drillstring was pulled out of the hole (POOH), and
drilling continued using DWL methods.
The first well, Carpa 3, was drilled with the objective of
eliminating a contingency liner above the El Abra formation.
A 12¼-in. vertical hole was drilled conventionally to 7,808 ft.
The hole was conditioned, and the drill string was POOH.
A 4,252-ft length of 9⅝-in., 53.5 lb/ft liner, equipped with a
12¼-in. casing bit, cementing float collar, and the 9⅝ × 13⅜in. hydraulic liner hanger and compression-set packer, was
run-in on drill pipe.
An additional 52 ft of 12¼-in. hole were drilled with the
42 April 2013 / WorldOil.com

Fig. 3. Ft/hr performance of the DWL wells.

600
DwL length drilled, ft
DwL time, hr
DwL ROP, ft/hr

Units (ft, hr, ft/hr)

500

N°
1
2
3
4
5
6
7

400
300

DwL wells
Carpa-55
Bagre-110
Bagre-130
Bagre-510
Bagre-210
Carpa-21
Carpa-13

200
100
0

1

0

2

3

4
DwL wells

5

6

7

8

Fig. 4. DWL achieved a drastic reduction in NPT and mud losses,
and the elimination of contingency liners resulted in great
improvements in drilling time.

0
200

Carpa-101
Carpa-7
Carpa-3 DwL 1 ero.
Carpa-55 DwL 2do.
Carpa-55 2 do brazo
Carpa-101 side track
Carpa-7 side track 1
Carpa-7 side track 2

400
600
800
1,200
1,200
1,400
Depth, m

ning string to block fluid
flow through the drilling nozzles. The resulting hydraulic pressure
shears pins and forces an
inner piston downward.
The piston displaces
the bit’s steel blades and
PDC cutting structure
into the annulus, and
exposes cementing-circulation ports. Once cementing is complete, the
inner piston is drilled
out, and the next hole
section is drilled with
the drill-out bit, without milling or additional
trips.
A heavy-duty liner
hanger system included
a liner-top packer and
tieback completion polished bore receptacle
(PBR). These components were designed to suspend the liner load and seal the annulus after cementing operations, as well as to transmit the required torque and dynamic forces needed to drill the openhole
section. A premium, hydraulic-set rotating liner hanger and top
packer system, designed for deep, high-angle applications, were
selected. The package provided the ability to support extended
rotation periods and enable maximum workability during deployment.
Cementing equipment included a double-flapper float collar. It was strategically positioned in the shoe track to allow the
passage of the 1¾-in. ball, dropped to activate the drill shoe displacement, and the 2⅛-in. OD ball to release the liner-setting
tool. The float collar served two purposes: it acted as a mechanical well control barrier, similar to a drill pipe float valve in standard drilling operations; and it provided a one-way check valve
system to retain the cement after placement. A landing collar
located one joint above the float collar received the liner wiper
plug at the end of the liner cement job.
Fig. 2. Five-bladed PDC bits with
16-mm and 13-mm PDC cutters and
tungsten carbide gauge protection
helped achieve high-performance
drilling with liner.

1,600
1,800
2,000
2,200

101

41
56

2,400

65

2,600

85

2,800

151

3,000
3,200
0

10

20

30 40 50 60 70 80 90 100 110 120 130 140 150 160
Time, days

9⅝-in. liner, cementing equipment was rigged up, and an activating ball was dropped and pumped to convert the casing bit
and activate the liner hanger. The efforts failed, and eventually the bottomhole assembly (BHA) was POOH, and a full
string of 9⅝-in. casing was run and cemented on bottom prior
to drilling the El Abra.
In examining the liner drilling BHA, it was discovered that
the flapper in the float collar had sheared off, and the activation ball was jammed, preventing the pressure build-up needed to convert the casing bit. While the issue was problematic,
it was noteworthy that the DWL section was drilled without
a problem.
With some modifications to procedures and equipment,
a second well, Carpa 55, was drilled. The 12¼-in. hole was

DRILLING TECHNOLOGY

Table 1. Forecast assumptions for liquids production in three key basins

Liner
Well
Inc., deg
Depth in/depth out, ft
OD, in.
Carpa–3
0.48
7,808 7,860 9–5/8
Carpa–55
75.9
9,451 9,717 9–5/8
Bagre–110
65.09
8,776 9,219
7
Bagre–130
70.38
8,808 9,130
7
Bagre–510
70.28
12,319 12,729
7
Bagre–210
73.29
12,949 13,525
7
Carpa–21H
74.75
8,477 8,562
7
Carpa–13H
73.14
8,743 8,877
7

drilled conventionally to 9,452 ft at 75°. The drilling BHA
was POOH, and 4,964 ft of 9⅝-in., 53.5-lb/ft liner were run
in the well. As in the previous well, the assembly included a
Defyer DPC casing bit, and hydraulic liner hanger system. A
9⅝ ×11⅞-in. centralizer was positioned 26 ft above the casing
bit and, to help maintain hole angle, a 9⅝ × 12⅛-in centralizer
was placed 22 ft higher in the hole.
An additional 266 ft of hole were drilled to 9,718 ft. The casing bit was successfully converted, and the liner hanger was set
and the running tool released. The liner was then cemented in
place, the packer set, excess cement above the packer was circulated out, and the drillstring was POOH. The DWL operations
successfully stopped loss circulation problems.
The Bagre 110 was drilled, and 9⅝-in., 53.5-lb/ft casing was
cemented at 4,265 ft. An 8½-in. hole was drilled conventionally
to 8,776 ft. The well was reamed and conditioned, and 4,967
ft of 7-in., 29-lb/ft casing were run in the well. The string was
equipped with a 7 × 8½-in. casing bit, and 7 × 9⅝-in. hydraulic
liner system and compression set packer.
The liner was run in on drill pipe and reamed to bottom, and
an additional 443 ft of 64–67°, 8½-in. hole were drilled with
the 7-in. liner to a total depth of 9,219 ft. The setting ball was
dropped to convert the bit and set the liner hanger, and the liner
was cemented in place without incident. No instances of lost
circulation were experienced.
Three additional Bagre wells (130, 510 and 210) were
drilled in a similar manner to Bagre 110. A 7-in. liner was used
to drill 322 to 577 ft of hole at angles from 72–75°. Setting
depths ranged between 9,130 ft and 13,527 ft. The liners on
each well were successfully set and cemented in place with
negligible mud losses.
Significantly, Bagre 210 and 510 had extended-reach depths
of 13,527 ft and 12,730 ft with a 75° angle, where the liner was
landed. Mechanical friction-reducing tools were strategically
positioned on the landing string, across the build section of the
well. While torque was generally a little higher, no pack-offs or
stall-outs were encountered.

Liner drilled

distance, ft
Time, hr
ROP, ft/hr
52
16
3.3
265
35
7.5
442
25
17.5
321
36
8.7
410
28
14.6
576
46
12.4
85
16
5.3
134
10
13.4

For the next two wells, Carpa 13-H and 21-H, a 7-in. liner
was drilled in, successfully hung off and cemented, and the liner
packer was set. The hole angles were 73° and 75°. Both wells
were drilled with little or no lost circulation.
On the Carpa 15-H, the 8½-in. hole was conventionally
drilled to 8,854 ft. While running in hole with the 7-in. × 8½in. DWL assembly, conditions required washing and reaming
the liner in the existing 8½-in. hole. At 8,867 ft, MD, reaming
parameters (flow, rotation and torque) were increased in an effort to ream the remaining open hole. An attempt to pick up the
string only moved it 10 ft, presumably due to a tight hole, poor
cleaning or hole collapse. Surface pressure was increased to
1,800 psi, which was higher than the liner hanger shear pin setting. It was determined that the hanger was activated, preventing weight from reaching the casing bit. Ultimately, the DWL
string had to be pulled out of the well.
LINER DRILLING SOLUTIONS

The principle of DWL technology worked very well in this
difficult drilling environment. Apart from mechanical problems
experienced on Carpa 3 and 15, the technology solved the problem of massive circulation and mud losses. It is noteworthy that
the first well was drilled very conservatively with only 52 ft of new
hole. As the operator became more comfortable with DWL, the
lengths drilled increased to a maximum of 576 ft, Table 1. The
use of DWL has resulted in a drastic reduction in NPT (Fig. 4)
and mud losses in these wells, and the elimination of contingency
liners resulted in great improvements in the economics of drilling
and completing wells in the Faja de Oro’s El Abra formation. 
STEVE ROSENBERG is the global drilling reliability
manager at Weatherford. Mr. Rosenberg has 25 years of
experience in the oil and gas industry, previously holding
drilling and production engineering positions with
Diamond Offshore Team Solutions and Conoco. He holds
BS degrees in petroleum engineering, from Mississippi
State University, and biology, from St. Lawrence
University in Canton, New York.

Article copyright © 2013 by Gulf Publishing Company. All rights reserved.

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44 April 2013 / WorldOil.com
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