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Expandable
Casing Reduces Drilling Costs
In developing a deep Lower Bossier play in
East Texas, Burlington Resources (Burlington) faced several
constraints in their well plans, including:
- The intermediate open-hole section above
the Travis Peak had to be isolated prior to entering the
geo-pressured Upper Bossier section.
- The 12 ¼-in. hole originally planned
through the Travis Peak/Cotton Valley had to be reduced in
size to improve drilling performance.
- The Upper Bossier interval required
isolation with a liner since the sands have a low fracture
pressure and are in close proximity to the highly pressured
Lower Bossier section.
- 4 ½-in. production casing at TD was the
minimum acceptable size.
Burlington chose to employ solid
expandable tubulars, realizing the following benefits:
- A 7 5/8-in. intermediate casing is
typically set at the intermediate pipe point as opposed to
9 5/8-in. casing.
- The smaller casing thus allows a 9
7/8-in. hole to be drilled through the Travis Peak instead
of the 12 ¼-in. hole required for the 9 5/8-in. design.
- The Upper Bossier is isolated with
solid expandable tubulars, allowing a 6-in. hole to be
drilled to TD.
- 4 ½-in. x 5-in. production casing
is run and cemented at TD.
After drilling seven slimhole wells,
Burlington has found the following:
- The slimhole design (9 7/8-in.)
improves ROP to the intermediate casing point by 37%
(3.1 days per 1000 ft compared with 4.9 days per 1000 ft
with larger casing).
- Average time to TD is reduced 21%,
from 94 days to 74 days. This translates into savings of
about $1 million per well.
Excerpted from "Operators Address
Deep Gas Drilling Challenges," Drilling Contractor,
July/August 2005, p. 28. |
Some New Coiled
Tubing Capabilities
Of several technologies discussed in this
article about coiled tubing advances, the following concepts
appeared most applicable to situations that would be
encountered by independents.
Halliburton's DeepReach string uses coiled tubing sections in
a single string with larger OD sections near the top and
smaller OD sections near the bottom of the string. This
reduces tension along the string length while sufficient flow
capacity is retained. With this configuration operators can
realize up to a 30% increase in depth capability compared to a
conventional coiled tubing string. Specially engineered and
manufactured transition joints are one key to the system. Size
transition occurs in the middle of this joint. Shape and
length of transition joints vary for different tubing sizes.
Several field trials have been conducted, more are planned and
commercialization is anticipated by year-end. The system was
developed as a joint project between BP and Halliburton.
Quality Tubing, Texas Oil Tools and CTES were also involved.
BJ Services' Duralink coiled tubing connector eliminates butt
welds and makes connecting coiled tubing strings easier and
more reliable. Connections can be installed and monitored by
coiled tubing crews. To make the connection, the two ends of
the coiled tubing strings are drawn into a jig, they are slid
into each end of the connector and the connector is crimped to
the coiled tubing. Initial effort focused on a 2 7/8-in
connector, which has been successfully used in 10 jobs (as of
article date). Development is ongoing for additional sizes.
Ensign Resource Service Group's coil over table design coupled
with the company's Automated Drilling Rig technology. The rig
design can drill with larger 3 ½-in coiled tubing as well as
with conventional jointed drill pipe. With the coil over table
design, tubing is bent only twice per cycle compared to six
times per cycle in conventional coiled tubing operations. The
capability for larger diameter tubing allows Ensign to place
more drill collars on bottom, which results in straighter
holes. Ensign notes that cost savings occur from: (1) using a
single rig vs. two in the conventional approach (drill the
hole with one rig, set casing, then move in the CT rig), (2)
safe operations with a fully automated operation, (3) quick
move-on, move-off with completely wheel-mounted units with
dedicated tractor units and (4) time is saved with the unit's
self leveling capability.
Excerpted from "Coiled Tubing Technical Advances Cut
Operational Costs Sharply," Drilling Contractor, July/August
2005, pp. 36-41 available online at
www.iadc.org/dcpi/dc-julaug05/July05-coiled.pdf |
2005
Gulf of Mexico Studies from IHS Energy, PetroSolutions
Updating their two-year old study, IHS Energy
and PetroSolutions noted new trends in deepwater Gulf of
Mexico development. One key observation is the increased
emphasis on channel gas reservoirs when production performance
measures clearly point to sheet sands as the target of choice.
Tom Harris of PetroSolutions offers these explanations: " . .
. may be a function of seismic visibility, along with robust
gas prices and technological advances in the areas of
completions and flow assurance." In the study all 72 deepwater
fields (water depth greater than 1,000 ft, reservoirs made up
of deepwater facies) were analyzed. This involved analyzing
550 completions in 467 wells.
Deepwater oil reservoirs are initially undersaturated. Three
primary drive mechanisms are recognized—fluid expansion,
aquifer influx and formation compressibility. On an average
production per completion basis, there are differences by
reservoir type.
- Sheet sands average 11,000 b/d per
completion
- Channel sands average 6000 b/d per
completion
- Channel levee sands average 4,000 b/d per
completion
Using a variety of techniques, the team
determined original hydrocarbons in place, expected ultimate
recoverable volumes, drive mechanisms, decline rates, plateau
periods, time to water breakthrough, etc. IHS believes
providing this common benchmarking data allows operators to
better focus efforts on specific prospects.
IHS also recently updated their study of Deep GOM reservoirs
in less than 1,000 feet water depth. This study looked at more
than 120 fields, discovering that the newest Deep GOM fields
are outperforming their older peers. Facies were correlated
with production behavior across 29 new fields. This led to
discovering that certain combinations of depositional setting
and facies posted higher performance by an order of magnitude.
Excerpted from "Channel Sands Shift US Gulf E&P Focus,"
Offshore Engineer, June 2005, p. 69 available online at
www.oilonline.com/news/
features/oe/20050610.Channel_.
18255.asp and from study information available
on IHS Energy's website (www.ihsenergy.
com/solutions/production/index.
jsp, products and
services by category). |
Tech
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