American Oil and Gas Reporter - January 2019 - 97

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Tech Trends
Cost savings while using the wellbore
shield system for this operator included
the cost to run the liner as well as the subsequent cement job. In addition, time in
coordinating that work was saved as well
as NPT directly related to wellbore instability issues such as stuck pipe and lost
circulation to the depleted formations.
Merge Case Study
An operator drilling in the Merge play
in southern Canadian and northern Grady
counties consistently was encountering
severe lost circulation (more than 3,000
barrels per well) while drilling the Tonkawa,
Hogshooter and Checkerboard formations
in the intermediate interval, as well drilling
through the Red Fork sands and other depleted formations before setting casing in
the Inola formation. Table 2 shows the
lithology for a Merge well.
The "before" wellbore diagram at the
left in Figure 2 shows the operator's well
plan prior to adopting the wellbore shield
additive. The program included a 7.0inch casing string to cover mechanically
weak formations. When previously encountering severe lost circulation, a contingency plan was in place which included
running a 7.0-inch liner to cover these
formations and resume drilling the lateral
section with a 61⁄8-inch bit.
After incorporating the wellbore shield
technology, the operator reported zero
mud losses, and was able to eliminate the
intermediate casing string and liner planned
as a contingency in case of a total lost
circulation event. This allowed the company
to complete wells using a monobore design
without incurring any instability issues
("after" diagram in Figure 2).
The preferred drilling fluid system for
both operators was an oil-based mud that
displaced water-based mud from 1,500
feet to total depth. The operator in the
Blaine County STACK play drilled with
mud weights ranging from 13.5 to 15.2
pounds/gallon. Other properties of the
OBM included plastic viscosities of 1830 centipoise, yield points of 10-18
pounds/100 square feet, and high-temperature/high-pressure fluid losses of twosix milliliters/30 minutes. The wellbore
shielding additive treatment level was
three-six pounds/barrel of drilling fluid.
The operator in the Merge well referenced in Table 2 drilled with 9.0-9.2
pounds/gallon mud weights. With the
lower mud weight, the required concen-

TABLE 2
Merge Well Lithology

Formation

TVD RK8

Heenner Shale
Douglas
Tonkawa
Cottage Grove
Hogshooter
Checkerboard
Cleveland
Oswego
Verdigris
Skinner
Redfork
Inola
Atoka
Meramec
MRMC E
MRMC D
MRMC B
MRMC B10
MRMC A
WDFD
WDFD OHERT Base
Target
WDFD Mid
HNTN

5,287
5,437
6,145
6,955
7,169
7,285
7,462
7,952
8,131
8,213
8,291
8,354
8,402
8,444
8,468
8,503
8,519
8,551
8,573
8,641
8,680
8,700
8,723
8,758

Hazards

Shale
Washouts
Sandy Shale-Gas-Loss Zone
Sandy Shale
Sandy Shale-Gas Show
Sandy Lime-Possible Loss
Sandy-Possible Loss
Lime
Lime w/Sand-Sh Intervals
Sand/Shale-Washouts
Sand/Shale-Washouts
Lime-Washouts
Shaly Lime
Shaly Lime
Shaly Lime
Shaly Lime
Shaly Lime
Shaly Lime
Lime
Shaly Ohert
Shale
Shale
Shale
Lime

FIGURE 2
Merge Wellbore Diagrams Before and After
Adopting Drilling Fluid Shield Technology

9.625 inches

7 inches

KOP: 8,141 feet
EOC: 9,041 feet

1,500 feet

9.625 inches

1,500 feet

8,354 feet

TMD: 16,323 feet
TVD: 8,700 feet
LL: 7,282 feet

Before

5.5 inches

TMD: 16,323 feet
TVD: 8,700 feet
LL: 7,282 feet

KOP: 8,141 feet
EOC: 9,041 feet

After

5.5 inches

JANUARY 2019 97
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