2. Objective:
To provide consistent, high quality
supervision, in a more effective, efficient
and safer manner than the conventional
approach
EnCana Corporation
3. Remote Geosteering - WHY
- Safety
- Costs
- Data Flow
- Communication
- Real Time Decision Making
- 24/7 Supervision
4. Remote Geosteering - Where
• Horizontal wells with no need for real-time sample
description. (Steering based on LWD/MWD data and drilling
parameters)
• Drilling close to the roof of the reservoir
• Night supervision for one man Hz jobs
• Follow optimum reservoir zones
• Drilling a set distance above the water contact
• Avoid unproductive zones in the reservoir
• Optimal wellpath placement
• Combining two or several of these objectives in one well
EnCana Corporation
5. Remote Geosteering - How
Continuous supervision
Real time assessment of stratigraphic location
Relation to markers
Position within porosity windows
Critical evaluation of wellpath shape
Optimal landing using TVD logs
Timeline estimates
Critical Formation tops
Casing points
Entering reservoir
Reaching TD
Exhaustive daily and final reports
Wireline Logging Supervision
11. Monitor current rig operations, paying particular
attention to nature of bottom hole assembly in the
hole (slick, stiff, pendulum, directional, etc.).
Although this is a drilling matter, the remote
geologist must understand all operations, and
recognize any deviations from the drilling program.
If any deviations are observed, Client’s personnel
are notified as per protocol.
13. Directional Drilling Supervision
Synergetic communication
Collision Avoidance
Plot wellpath into Petrel, and proactively evaluate
wellpath position in relation to existing and planned
wellbores (provides an additional line of defense in
the avoidance wellbore collisions)
EnCana Corporation
14. Additional Benefits
Knowledge and resources shared in all compartments.
Standardized internal and government reporting.
Detailed daily reports, to be distributed within the company and to
partners as needed. Everything stored on client’s dedicated data base,
using consistent file naming protocol.
Further reduction in cost is realized by reducing the required number
of accommodations, Pason terminals and trailer transportation costs
on the lease.
EnCana Corporation
This plot shows the correlation of the volume of fluid pumped versus the average 30 day max month rate following completion. This relationship of more stages frac’d and larger fluid volumes shows that well performance can be increased by optimizing completions. The 2009 budget was based on 8 stages per well, however with the results of the b-C76-K well this fall, the plan has shifted to 10 stages per well and we are working on the justification to realize up to 14 stages per well. As part of their Q3 results, EOG released information that 3 wells in their Horn River program had IPs of 6 to 19 MMcf/d. One well has been identified to have 14 stages frac’d resulting in a 30 day IP of 10.8 MMcf/d. Relating frac stages to spacing, a 10 stage per well program would equate to 12 acres per interval while a 14 stage per well program would equate to 8 acres. As a comparison, the Barnett in the Fort Worth Basin is being spaced typically to 6 acres with downspacing pilots testing 3 acres.