SPE HC in Horizontal Wells Presentation1 - Virbmedia.virbcdn.com/files/17/04465223afc53504-SPEHorizontal101Sep... · drilled formation allowing uninterrupted operations due to

© 2011 BAKER HUGHES INCORPORATED. ALL RIGHTS RESERVED. TERMS AND CONDITIONS OF USE: BY ACCEPTING THIS DOCUMENT, THE RECIPIENT AGREES THAT THE DOCUMENT TOGETHER WITH ALL INFORMATION INCLUDED THEREIN IS THE CONFIDENTIAL AND PROPRIETARY PROPERTY OF BAKER HUGHES INCORPORATED AND INCLUDES VALUABLE TRADE SECRETS AND/OR PROPRIETARY INFORMATION OF BAKER HUGHES (COLLECTIVELY "INFORMATION"). BAKER HUGHES RETAINS ALL RIGHTS UNDER COPYRIGHT LAWS AND TRADE SECRET LAWS OF THE UNITED STATES OF AMERICA AND OTHER COUNTRIES. THE RECIPIENT FURTHER AGREES THAT THE DOCUMENT MAY NOT BE DISTRIBUTED, TRANSMITTED, COPIED OR REPRODUCED IN WHOLE OR IN PART BY ANY MEANS, ELECTRONIC, MECHANICAL, OR OTHERWISE, WITHOUT THE EXPRESS PRIOR WRITTEN CONSENT OF BAKER HUGHES, AND MAY NOT BE USED DIRECTLY OR INDIRECTLY IN ANY WAY DETRIMENTAL TO BAKER HUGHES’ INTEREST.

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


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


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


Temperature and Pressure Effects on Viscosity


Temperature and Pressure Effects on DensityBase Fluid Pressure / Volume / Temperature Effects on Density



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


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.


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


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)


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


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

Barnett Shale PlayTypical Well Profile


Barnett Shale PlayAdvantage Well Profile


Barnett Shale PlayRPM Effect on Hole Cleaning

rpm = 0 rpm = 70 rpm = 120Wellore

Haynesville Shale PlayPore Pressure / Frac Pressure / Loss Zones


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


Haynesville Shale PlayTypical Well Profile


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


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


Haynesville Shale PlayROP Effect on ECD at Bit


Haynesville Shale PlayROP Effect on ECD at Shoe


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


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


Eagle Ford Shale PlayTypical Well Profile


Eagle Ford Shale PlayAdvantage Hole Cleaning


“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


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)


• 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



• 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


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


Thank You for Attending – Questions? Tough Day on the Water


Documents

SPE HC in Horizontal Wells Presentation1 - Virbmedia.virbcdn.com/files/17/04465223afc53504-SPEHorizontal101Sep... · drilled formation allowing uninterrupted operations due to