An IffTech
An IffTech
An IffTech
Abstract
The oil and gas industry continuously strives to develop tools
and techniques to meet and exceed operational objectives with
less cost. These efforts have brought about advancements in
downhole tools that enhanced slickline technology, making it
a more versatile means of providing accurate depth
measurement so that more complicated services can be
performed1. Likewise, development of slickline deployed
inflatable packers also exemplifies the on-going industry
endeavors to conform to a business model that simplifies
costs, operations, and logistics2.
This case study involves work done on the Rang Dong
Oilfield located 160 kilometers offshore S.R. Vietnam. In
operation since 1998, this field has produced oil and gas from
sandstone and granite basement reservoirs since 1998. In all
four existing wells in this field that were studied, a workover
campaign was performed to install gas lift valves because of
declining reservoir pressure. To prevent formation damage
while pulling the existing completions and running the new
completions, with gas lift mandrels, isolation plugs were
chosen to isolate the producing intervals. This technique was
used because of its ability to minimize rig time by working
offline and because the plugs could pass through a small
restriction and set in the tubing joint of the tail pipe without
requiring a landing nipple profile.
The innovative techniques for well workovers used in this
project utilized slickline deployed inflatable technology to
provide economic alternatives traditionally reserved for more
costly options. Borrowing from computer age terminology,
this approach is know as the offline approach which
conveys the meaning that well preparation work takes place
before the rig is placed on location. As implemented, the plug
isolated the formation from kill weight fluid before the rig was
needed so that production tubing could be removed and
reinstalled with gas lift mandrels. The use of this method
reduced rig cost by an average of eighty-four hours per well
SPE 100744
Project Planning
Figure 2 shows that the typical completion technique used in
the four 1998 1999 wells consisted of production tubing
with a seal assembly landed into a permanent packer with a
sealbore extension. These four wells ranged in deviation from
40 to 69 degrees. Three of the four wells did not have a
landing seal nipple in the tail pipe that would have facilitated
setting a plug and isolating the reservoir below. Isolating the
reservoir below by setting the plug in the tail pipe of the
completion string was deemed important in order to avoid
both a post-workover acid job to restore the original
permeability and to keep from damaging the reservoir during
the workover. An added benefit of the plug was that it
functioned as a physical barrier between the reservoir and the
surface while nippling down the production tree and nippling
up the drilling blow-out preventors (BOPs). Removing a
completion without the aid of a physical barrier can pose an
unacceptable risk because kill fluid can be depleted and the
well can revert to an underbalanced condition with no means
to control it. Still another advantage of the plug was that it
allowed the new completion to be pressure tested once it was
landed and spaced out in the sealbore extension. Because of an
uphole restriction in the production tubing with a 2.635-in. ID
XN landing nipple, an inflatable packer was chosen for its
ability to be set in the tail pipe, to isolate the completed
reservoir below.
SPE 100744
X Landing nipple
XN Landing nipple
9 5/8 Packer
Offline Sequence
A. Run in the hole with a through tubing bridge plug
and set it in the sealbore extension below the packer,
then pressure test the bridge plug to its working
pressure.
B. Perforate the tubing with slickline above the packer
and circulate to kill the well.
C. Remove the production tree.
2. Online Sequence
A. Move rig onto well location and install BOPs.
B. Unsting the seal assembly from the sealbore
extension of the production packer and remove the
tubing string.
C. Install the new completion consisting of a sealbore
extension, gas lift mandrels and tubing into the well,
and sting into the permanent packer.
D. Pressure test the tubing.
E. Remove the BOPs, and remove the rig from the
well.
3. Offline Sequence
A. Install the production tree.
B. Retrieve the inflatable thru-tubing bridge plug, and
kick off the well utilizing the platform gas lift
system.
This project called for preparing the first well by setting an
inflatable bridge plug in the sealbore extension and killing the
well before the rig was moved on location. During the rig
operations on the first well, slickline was to be utilized to set
an inflatable bridge plug in the sealbore extension of the
second well. After this, the rig was to be moved to the second
well to repeat the same work as on the first well. Meanwhile,
slickline would return to the first well and remove the bridge
plug. Slickline then was to proceed to the third well,
following the established procedures. As a contingency, coil
tubing was to be deployed for utilization if slickline had
difficulties setting and/or retrieving a bridge plug. Table 1
displays a time verses operational matrix on each of the wells
in this project.
SPE 100744
Table 1
Time vs. Operational Matrix per Well
Day
-2
-1
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
Well RD-1
Offline
Offline
Rig move
Rig move
Rig move
Rig
Rig
Rig
Rig
Offline
Offline
Well RD-2
Offline
Offline
Offline
Offline
Rig
Rig
Rig
Rig
Offline
Offline
Rig
Rig
Well RD-3
Offline
Offline
Offline
Rig
Rig
Rig
Offline
Well RD-4
Offline
Offline
Rig
Rig
Rig
Offline
SPE 100744
2.
3.
Well No. 4, RD-4
On May 8, 2004, work began similarly on the RD-4. The
packer was run to a setting depth of 6,847 ft MD or 6,294 ft
TVD. After 2 motionless hours at the appropriate depth, the
slickline was slacked off and the weight dropped, indicating
the bridge plug was set. Next, the inflatable packer setting
tools were removed from the well. Three days later after the
rig installed new tubing with gas lift mandrels, a 2 -in. JDC
pulling tool was utilized to recover the inflatable bridge plug.
Once the tool was located and latched, the jarring down
motion of the JDC tool and the expulsion of the equalizing
plug by the equalizing prong balanced the well from below to
above the bridge plug. Gas was subsequently injected into the
annulus to help lift the fluid in the tubing, thus, further
equalizing the well from below to above the bridge plug
before the bridge plug was removed.
Picture 1 illustrates the simultaneous operations work
performed during this project from the platform view. This
visual shows the offline work being done, the retrieval of
the plug from the RD-1, and the simultaneous setting of the
plug in the RD-3 with the removal of the tubing from the RD2.
Picture 1: View of multi-offline work on platform beneath rig floor
RD-2, Online
RD-1, Offline
Plug Retrieval
4.
RD-1
Offline
Well Prep*
RD-2
Online
24.5
Offline
RD-3
Online
97
Offline
RD-4
Online
Offline
60
Online
28
Rig Move**
54
0.5
Simultaneous
Operations***
20.5
N/D Xmas
Tree
4.5
5.5
16
5.5
7.5
POOH
Completion
28
29.5
15
13
RIH
Completion
40
30
30
48
N/D BOP
2.5
2.5
3.5
5.5
3.5
34
54
19
Retrieve Plug
40.5
16
Unload Well
N/A
N/A
N/A
N/A
N/A
N/A
N/A
Totals
69
171
131
139.5
90
55.5
44
84
Total Offline
334 Hrs
14 days
43%
Total Online
450 Hrs
19 days
57%
Total Time
784 Hrs
33 days
100%
Observations
Examination of the data and procedures reveals the following
impressions concerning the work done on the wells in this
study:
1.
Conclusions
Presently, because of the availability of innovative tools that
can provide more accurate depth measurements, perforating,
and real time log presentations, the industry can avail itself of
modern technology to increase profits. Two such tools that
have proved their worth in many applications around the
world are slickline and the slickline deployed and battery
operated inflatable packer systems.
Slickline has the
capability of delivering services equal to that of real time
electric line at a fraction of the cost and with high reliability.
SPE 100744
2.