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SPE HC in Horizontal Wells
SPE Dallas Section
September 28, 2011
Greg Mullen – Engineering Software Manager
TopicsTopics
• Definition
• Indicators
• Solutions
• Hole Cleaning Model
• Pre-Well planning
• Post Well Analysis
• Pipe Rotation
• Shale play – Eagle Ford
– Haynesville
– Barnett
• Bottoms Up
• Case History
Hole Cleaning: One Definition
• Simply put, hole cleaning is the ability to remove sufficient drilled formation allowing uninterrupted operations due to insufficient cuttings removal.
– This does not mean 100 percent cuttings removal
– The intention is to remove enough cuttings to prevent NPT due to poor hole cleaning
© 2011 Baker Hughes Incorporated. All Rights Reserved. 3
Poor Hole Cleaning Indicators
• Abnormally high down hole pressures while circulating
– Trends from pressure tools
• High torque and drag while drilling / tripping
• Lack of cuttings return over shakers
• Pack off events
• Stuck drill pipe
• Loss circulation
• Required back-reaming**
• Fill on connections / TIH
• Stuck casing**
• Difficult logging
© 2011 Baker Hughes Incorporated. All Rights Reserved. 4
Solutions for Poor Hole Cleaning
• Flow rate, flow rate, flow rate
• Maximum allowable drill string RPM
• Reduce sliding to rotation ratio
• Control ROP
• Utilize Rotary Steerable
• Drill pipe size 5” or 5 ½”?
• Change drilling fluid properties
• Increase circulation time between connections
• Minimal downhole restrictions
© 2011 Baker Hughes Incorporated. All Rights Reserved. 5
Solutions for Poor Hole Cleaning
• Remove cuttings beds
– Sweeps (weighted) with increased drill string rotation
– Pump / rotate until sweep arrives at surface
• Sweeps – use as an indicator of poor hole cleaning
– High density
– Low viscosity / high viscosity
– Fibrous materials
• Short trip
• Backream**
• Casing design
• Wellbore trajectory
© 2011 Baker Hughes Incorporated. All Rights Reserved. 6
Temperature and Pressure Effects on Viscosity
© 2011 Baker Hughes Incorporated. All Rights Reserved. 7
Temperature and Pressure Effects on DensityBase Fluid Pressure / Volume / Temperature Effects on Density
© 2011 Baker Hughes Incorporated. All Rights Reserved. 8
© 2011 Baker Hughes Incorporated. All Rights Reserved. 9
Temperature and Pressure Effects on Density
Reference Mud Weight: 16.47ppg / 150 °F / 15 psi
48% Oil, 8% Brine, 44% Solids
OBM vs. WBM Circulating Temperature Profile (CTP)IntelliBore™ - Wellbore Strengthening
© 2010 Baker Hughes Incorporated. All Rights Reserved. 10
WBM
OBM
Geothermal
Zone of increased formation stresses
Zone of decreased formation stresses
Advantage Hole Cleaning Model
• SPE 28306 - Clark, Bickham, “A mechanistic model for Cuttings Transport”
• The model is based on the balance of the forces acting on a cutting in the annulus.
• Settling - The cuttings moving downwards due to the gravitational force against the buoyancy and the drag force
• Lifting - A cyclic motion of moving the particle in the area of higher fluid velocity due to lift and buoyancy forces, moving the particle suspended in the fluid and continuously settling down again
• Rolling - Particles roll on the low side of the annulus when the Lift and Drag force exceed the gravitational force and the plastic force.
© 2010 Baker Hughes Incorporated. All Rights Reserved. 11
Hole Cleaning Criteria
• Vertical sections to 30°
– Cuttings concentration < 5% vol / vol
– VT = 30 ft/min
• Angle > 30º either 0% cuttings bed or predefined allowable limit (5-10% allowable cuttings bed)
ADVANTAGE Engineering (Process Overview)
Step 2
Hydraulics
Modeling
for
Hole Cleaning
Step 1
Review
initial
data
•Select fluid type.
•Search data base for
properties.
•Run ADVANTAGE
to determine required
gpm’s to clean the
hole.
•Riser Booster
pump?
•ROP & string RPM
Step 3
Hydraulics
Modeling
for
E.C.D.
•Review system
pressure losses.
•Review String
design.
•Rheology of the
fluid.
•ROP & string RPM.
•Determine
temperatures profile
with Presmod.
•Run ADVANTAGE
to minimize ECD.
•Run ADVANTAGE
for Swab & Surge.
•HTHP model for
Synthetic.
•Hole Cleaning for
WBM.
Step 4
Hydraulics
Modeling
for
Optimization
•Review system
pressure losses.
•H.S.I.
•Motor / MWD.
•Fluid Bypass subs.
•Run ADVANTAGE :
optimize hydraulics.
•Water depth.
•Water temperature
gradients.
•Casing design.
•Fracture gradients.
•Drill string design.
•Fluid density
requirements.
•Geothermal
gradient.
•Directional profile.
Decision 2
Can the hole
be cleaned?
Decision 3
Is the ECD
acceptable?
Decision 4
Is the well
optimized?
Decision 1
Can we drill
this well?
Step 5
Review
•Initial data.
•Hole cleaning.
•ECD.
•Optimization.
•Apples to Apples.
•Review of results as
a package.
•Risk analysis.
•Contingency plan.
Decision 5
Is this the best
we can do?
1 2 3 54
After Action Review
• Usually when operations do not go well
• Tool for “best practices” on wellsite execution
• Learning process, not a finger pointing exercise
– The goal is to IMPROVE not blame
© 2010 Baker Hughes Incorporated. All Rights Reserved. 14
AAR Questions to Address
What did we
plan to do?
How can we
sustain what
we did right? Why did the
differences
occur?
What were
the differences?
What did we
actually do?
How can we
improve?
Drill String Rotation
• Drill string rotation is essential to remove cuttings from high angle wellbores
• Rotation move cuttings from low side (low AV) to high side (higher AV / mass flow rate)
© 2011 Baker Hughes Incorporated. All Rights Reserved. 16
Viscous coupling between pipe and fluid required to move cuttings into high AV zone of annulus.
• 12 ¼” > 120 rpm
• 9 7/8” > 120 rpm
• 8 ½” > 80-90 rpm
• 6 ½” > 60-80 rpm
Drill String Rotation Recommendations
© 2011 Baker Hughes Incorporated. All Rights Reserved. 17
Barnett Shale PlayBarnett Well
• Casing: 9 5/8” X 5 ½”
• TVD ~ 7400’ – 9000’
• MD ~ 10,000’ – 13,000’
• Perforate / fracture 5 ½” lateral production zones
• Upper hole drill with water w /HC sweeps composed of gel and PHPA
• Mud up 4000’ – 5000’ w / gel, PAC and Ligco, biopolymer to TD
• MW 8.4 – 10.5ppg – low density w/o sufficient flow rate = HC issues
• No ECD limits on flow rate
• Sweeps: hi vis as needed for HC and or low vis for turbulent flow in lateral for HC
• Torque reducer: chemical / inert beads / nut shell / graphite
• LCM: calcium carbonate, mica, cellulosic material
• Minimal use of OBM - mainly for long laterals / torque
Haynesville Shale PlayPore Pressure / Frac Pressure / Loss Zones
© 2010 Baker Hughes Incorporated. All Rights Reserved. 22
Haynesville Shale PlayHaynesville Well
• Hole cleaning problems are minimal
• Lateral – 9k – 12k’ TVD
• MW ~ 16.5 - 17.5ppg
• Lateral hole diameter 6.5 - 8.5”
• Mud 6 rpm reading ~ 1.25 - 1.5 hole diameter
• Yield point ~ 15 – 25 lbf / 100 ft2
• BHST ~ 250°F – 350°F
• Primary drilling fluid is OBM
• WBM usage is minimal w / exception of massive loses
• Tortuosity and poor hole cleaning can cause casing sticking off bottom
© 2011 Baker Hughes Incorporated. All Rights Reserved. 23
Haynesville Shale PlayTypical Well Profile
© 2011 Baker Hughes Incorporated. All Rights Reserved. 24
DESOTO PARISH SOLIDS MUD
DEPTH LOUISIANA CONTROL SYSTEM MW (PPG)
TVD 8.8 12.0 16.4
Spud with 20 - 25 ppb MIL-GEL slurry to prevent wasing conductor shoe.
Fill the mud pits with drill water , 0.5 ppb MD, and 0.15 ppb SAPP.
1,000' 13 1/2" Pump 1.0 ppb NEW-DRILL / 25 ppb MIL-GEL sweeps every stand to aid in hole
cleaning. Drop 1 Soap and 1 SAPP stick every connection to combat
gumbo. Add SAPP and MD as needed to control gumbo.
Pump MIL-PLUG sweeps to prevent balling and scour the bit.
2,000'Fill the active pits with water and 12 ppb MIL-GEL for viscosity.
TUSCALOOSA Pre-treat with .25 ppb Bicarbonate of Soda for cement contamination.
Drill out with a 9.2 ppg MW. Add SAPP and MD as needed for any
gumbo encountered. Drop 1 SAPP STICK and 1 SOAP STICK every
3,000' connection while drilling gumbo.
Salt water injection wells are located in Desoto Parish and primarily
in the Tuscaloosa formation. Injection well locations should be
identified in mud program through SONRIS prior to spud.
4,000'
MASSIVE ANHYDRITE The Massive Anhydrite comes in around ~ 4,500' - 5,000'. While
B/ MASSIVE ANHYDRITE drilling the Massive Anhydrite add SODA ASH, & water as needed
to maintain desired rheological properties. Once at the base of
the Massive treat calcium levels down to <150 mg/l with SODA ASH
5,000' and SODIUM BICARBONATE.
JAMES LM Add MIL-PAC and NEW-TROL additions to maintain
fluid loss in specified ranges.
Keep pH at between 8.5 - 9.0 a with Caustic Soda
9 7/8" PETTET and maintain until casing point, maintain scheduled viscosity
6,000' with BENEX, MIL-GEL, and DESCO.
BEGIN 2°/100' DROPHOSSTON Pump 35 bbl sweeps every 500' of new hole to aid in hole
cleaning consisting of 25 ppb MIL-GEL and 1.0 ppb NEW-DRILL.
Possible loss circulation while drilling the "CV" with 10.8# - 11.0# MW. LCM
pills consisting of 10 ppb MIL-CARB, 5 ppb MIL-PLUG, 5 ppb
7,000' CHEK-LOSS and 10 ppb MIL-MICA have proven to be effective in
the area. In the event of continued loss circulation it is recommended to
reduce shaker screen mesh size to API 100's (137µm - 165 µm) to
maintain a broader PSD. Wells drilled in close proximity to the Red
River are more prone to losses due to "CV" production.
8,000' Maintain small additions of MIL-LIME in the active system to
combat any CO² encountered.
Maximum anticipated mud weight at TD for the intermediate
interval is 10.8 - 11.0 ppg.
COTTON VALLEY "B" LIME Pump a 35 bbl High Density MIL-GEL / NEW-DRILL sweep before pulling out
9,000' of the hole to run intermediate string to ensure hole is clean.
Spot a 30 bbl HPHT pill on bottom before running pipe consisting of
active mud and 6 ppb SULFATROL.
BOSSIER LATERAL SECTION
10,000' The lateral section will be drilled with 15.8 - 16.4 ppg
CARBO-DRILL®.
IF additional lubricity is needed to communicate weight to the
bit in the lateral pump 8 - 12 ppb LC-GLIDE / LC SHIELD sweeps
while sliding. Results of sweep effectiveness should be noted on reports.
Maintain ES above 600V with additions of CARBO-TEC and
11,000' 6 3/4" CARBO-MUL HT.
HAYNESVILLE Maintain Excess lime concentration at 4 - 5 ppb with MIL-LIME.
HAYNESVILLE SHALE 11,829'
Some wells experienced higher than normal MW in Desoto Parish due to
12,000' hydraulic fracturing and pressured sands in the Bossier.
Control rheologies with additions of OMNI-COTE, SURF-COTE, and
CARBO-GEL.
Maintain O:W ration 80:20 to 85:15 with additions of diesel and
water.
Control WPS at 240K to 260K with additions of CaCl².
COMMENTSGEOLOGICAL (TVD)HOLE SIZE CASING (MD)
SP
UD
MU
D
16" @ (65.0#)
AP
I 1
40
/ D
es
an
de
r /
De
sil
ter
NO
N-D
ISP
ER
SE
DC
AR
BO
-DR
ILL
S
ha
le S
ha
ke
rs-
AP
I 1
20
- 1
40
me
sh
*
Ce
ntr
ifu
ge
s C
on
tro
l L
GS
< 6
%
* H
igh
Sp
ee
d O
pti
on
al
Fo
r M
W >
10
.0 p
pg
Ce
ntr
if.
LG
S <
6%
S
ha
ke
rs A
PI
14
0-1
70
10 3/4" (45.5#)
K.O.P. @ 11,716' BUR 10°/100'
BEGIN VERTICAL HOLD
7 5/8" (29.7# P-110)
Monitor f ilter cake quality, cuttings structure, torque, and drag closely. Adjust API water loss as per down hole conditions.
Possible Loss
Circulation
Zone
Haynesville Shale PlayDrilling Fluid Properties
© 2010 Baker Hughes Incorporated. All Rights Reserved. 25
INTERVAL
(MD)MUD WEIGHT
FUNNEL
VISCOSITY
API
FILTRATE
PLASTIC
VISCOSITY
YIELD
POINT
80’ - 1,900’ 8.8 - 9.0 32 - 42 NC - 20 4 - 8 8 - 15
INTERVAL
(MD)
MUD
WEIGHT
FUNNEL
VISCOSITY
API
FILTRATE
PLASTIC
VISCOSITY
YIELD
POINT
1,900’ - 5,000 9.0 - 9.5 32 - 38 20 - 15 4 - 10 8 - 15
5,000’ - 8,500’ 9.5 - 10.2 38 - 44 15 - 10 8 - 14 10 - 15
8,500’ - 10,500’ 10.2 - 10.8 40 - 45 10 or less 14 - 25 10 - 15
INTERVAL
(MD)
WEIGHT
ppg6 RPM
PV
@120º
YP
@120º
WPS PPM
ES
VOLTS
HPHT
@300º
10,500’ - 16,500’ 15.8 - 16.4 6 - 8 42 - 47 10 - 12 240K - 260K ≈600 15 cc’s
Haynesville Shale PlayROP Effect on Hole Cleaning
© 2010 Baker Hughes Incorporated. All Rights Reserved. 26
Haynesville Shale PlayROP Effect on ECD at Bit
© 2010 Baker Hughes Incorporated. All Rights Reserved. 27
Haynesville Shale PlayROP Effect on ECD at Shoe
© 2010 Baker Hughes Incorporated. All Rights Reserved. 28
Eagle Ford Shale PlayEagle Ford Well
• Hole cleaning problems are minimal
• Lateral – 10,000 – 13,000’ TVD
• MW ~ 10.0-15.5ppg
• Hole size 6.25 - 8.5”
• Reach 5500 – 8500’
• Mud 6 rpm reading ~ 1.25 - 1.5 hole diameter
• Yield point ~ 10 – 14 lbf / 100 ft2
• BHST up to ~ 325°F
• Primary drilling fluid is OBM
• WBM usage is minimal w / exception of massive loses
– Fractured chalk above Eagle Ford
– Fibrous high fluid loss squeeze material
© 2011 Baker Hughes Incorporated. All Rights Reserved. 29
Eagle Ford Shale PlayEagle Ford Well
• Required sweeps in lateral – triggered by high torque
• Weight to bit an issue
– Torque / drag reducers
• Plastic clay – volcanic ash
– Stuck pipe
– Increase MW to mitigate sticking
© 2011 Baker Hughes Incorporated. All Rights Reserved. 30
Eagle Ford Shale PlayAdvantage Hole Cleaning
© 2010 Baker Hughes Incorporated. All Rights Reserved. 32
“Lag Time - vs - Hole Angle” BP Model
Inclination
of well
(Degrees)
Section Length Factor
17.1/2” 12.1/4” 8.1/2” 6”
0 - 10 1.5 1.3 1.3 1.3
10 - 30 1.7 1.4 1.4 1.4
30 - 60 2.5 1.8 1.6 1.5
60 - 90 3.0 2.0 1.7 1.6
1. Divide the well into sections according to inclination in the diagram.
2. Multiply each section by the correct section length factor from the table (Note: the
same factors are used for inside the previous casing string). Add all the effective
lengths together to give the Total Effective Length.
Total Effective length =
(2500 x 1.5) + (1000 x 1.7) + (1200 x 2.5) + (2800 x 3.0) = 16850ft.3. Number of circulations = 16850 / 7500 = 2.2 circulations4. Circulation Required = 2.2 times Bottoms-Up Volume.
“Lag Time vs Hole Angle” Example
Haynesville Shale PlayCase History: Stuck Casing
© 2011 Baker Hughes Incorporated. All Rights Reserved. 35
17 1/2" Spud with MILGEL/NEW-DRILL slurry. Pump MILGEL / NEW-DRILL
sweeps as needed for hole cleaning. Add SAPP for any gumbo
encountered. Run all solids control equipment for minimal mud
1,000' weight.
If balling is suspected add 3-5 sacks of MIL-PLUG to scour bit and
help maximize ROP while drilling soft upper hole formations.
MD may also be used to prevent shale balling tendencies.
2,000' B / WILCOX 2,025' Pump high vis sweep before POOH to run casing.
13 3/8" @ 2,125'
Drill out with 2-3 sacks of SAPP. Continue with SAPP additions
12 1/4" to keep all remaining gumbo dispersed and to prevent attacks.
3,000'
AUSTIN 3,858'
4,000'
Due to shallow pressures allow mud weight to measure 10.2 -10.5 ppg
by 4,200'.
Watch for lost circulation between 4,000' - 6,500'.
GLEN ROSE 4,958' Pump a high viscosity sweep before POOH to run casing
5,000' 9 5/8" @ 5,050'
Treat cement contamination with SODIUM BICARBONATE.
8 3/4" While drilling the Massive Anhydrite maintain desired rheological
properties with SODA ASH, LIGCO, and UNICAL. At the base of
6,000' the Massive eliminate remaining calcium with SODA ASH.
Proceed to drop fluid loss to 10-8 cc's with LIGCO and MIL-
RODESSA 6,570' PAC additions. Maintain a ±9.5 pH with CAUSTIC SODA, and
scheduled viscosity with MILGEL.
Begin tourly treatments of MIL-MICA and MIL-CARB in order to
7,000' seal porosity and help prevent differential sticking. Increase
JAMES 7,109' additions as needed for torque, drag.
PETTET 7,418' Watch for heaving shale, and consider adding 2-4% diesel.
Pump 30 ppb LCM pills if needed to combat losses
8,000' TRAVIS PEAK 8,076'
9,000'
Avoid swab and surge pressures when tripping.
10,000'
Keep pipe moving at all times.
11,000'
B / KNOWLES 11,221'
Maximum anticipated mud weight at TD is 11.1 ppg. Keep wt as low
as hole will allow.
12,000' Pump a high viscosity sweep before POOH to run 7" liner.
7" @ 12,200' BOSSIER 12,347'
HAYNESVILLE 12,737' The lateral will be drilled with 15.5-16.3 ppg WBM.
6"
17,511 MD
COMMENTSGEOLOGICAL (TVD)DEPTH HOLE SIZE CASING (MD)
Haynesville Shale PlayCase History: Stuck Casing
• Drill 17.5” set 13 3/8” casing @ ~ 2100’
– WBM, 8.9ppg
• Drill 12.25” set 9 7/8” at ~5000’
– WBM, 10.9ppg
– Losses, tight hole
• Drill 8.75” set 7” casing @ ~ 12200’
– WBM, 11.8ppg
– FIT=12.5ppg,
– Tight spots
– Losses
© 2011 Baker Hughes Incorporated. All Rights Reserved. 36
Haynesville Shale PlayCase History: Stuck Casing
• Drill 6” to TD lateral ~ 17,700’
– HPWBM, MW=16.3ppg
• Running 4 ½” production liner
– Stuck liner ~ 14,000’
– Cut liner & began fish ops
• Retrieved fish / pick up BHA, w/r to TD
– Low Vis / Hi Vis sweeps produced “3 in. deep coffee ground cuttings”.
• Washed 4 ½” liner to TD
• Successfully cemented
© 2011 Baker Hughes Incorporated. All Rights Reserved. 37
Case History: Open Hole Exposure to HPWBM
Days to14,000’ 18
Days to drill 6” lateral 23
Days fishing and getting liner to bottom / cmt. 19
Total days open hole exposed to HPWBM 42
© 2011 Baker Hughes Incorporated. All Rights Reserved. 38