Horizontal oh gp best practices h02233

i

Halliburton Energy Services, Inc.Bibliography No. H02233

Horizontal Gravel PackBest Practices Manual

ii

All information contained in this publication is confidential and proprietary property of Hallibur-ton Energy Services, Inc. Any reproduction or use of these instructions, drawings, or photo-graphs without the express written permission of an officer of Halliburton Energy Services,Inc. is forbidden.

©1999, Halliburton Energy Services, Inc.All Rights Reserved. Printed in the United States of America.

Bibliography No. H02233

Printing History:First Release (July 1999)

July 199

Preface

Preface

’s own nts.

g lving.

as packing

ntal n 3 is a l pack

ailed can be on to the re

ices. In as to ack the

date. gies ntal . This opy of ection

king.

The Horizontal Gravel Pack Best Practices Manual is a collection of information from jobs designed and/or performed by Halliburton, SPE Papers, magazine articles, e-mail, a previous attempt at putting this collection together, as well as information from competitors from a variety of sources. It is not intended to cover every aspect of a horizontal gravel pack in detail. It is intended to give the reader some basic information as a starting point for the readerinvestigation into horizontal gravel packing for his or her specific customers' requireme

The Horizontal Gravel Pack Best Practices information should be considered to be a “livindocument” as the state-of-the art designs for horizontal gravel packs are constantly evoThis is especially true with regard to the drill-in fluids and displacement thereof as wellother aspects of the gravel pack treatment such as the use of the alternate path gravel technology.

Section 1 discusses horizontal completions in general, although this manual is a horizogravel pack best practice manual. Section 2 covers candidate selection criteria. Sectiobrief horizontal gravel pack procedure (water base). Section 4 is a brief horizontal graveprocedure (oil base). Section 4 has not been completed at this time.

There are numerous ways to write a completion procedure. These would include a detprocedure that covers the fine points in a step-by-step fashion. This type of procedure difficult to read unless the reader is very familiar with the general steps in the completidesign. A multilevel numbering system can be used to provide the reader with a clue asmajor steps and successively more detailed steps. In some cases, a summary proceducovering only the main steps is used with the details covered in attachments or appendthis manual, there is a combination of the latter two in an effort to be clear and concisethe successive completion steps required to successfully achieve a horizontal gravel pwhile still supplying as much detail as possible. Sections 5–10 can be considered to beappendices to Section 3 and 4.

Section 11 is a brief summary of the horizontal gravel packs performed by Halliburton toAdditional information is available on HalWorld. Section 12 covers any competitor strateor important information on current competitor practices. Section 13 is a listing of horizopapers that can be used to attain further information concerning horizontal completionsis not intended as a reference list to back up statements in the manual. If you wish a cany of the documents please contact Richard Todd at the Duncan Technology Center. S14 is intended to list the marketing information available covering horizontal gravel pac

9 Preface

Horizontal Gravel Pack Best Practices Manual

Preface

Section 15 is a survey listing various questions and answers concerning horizontal gravel packing designs.

July 1999

Table of Contents

1. Introduction

1.1 Cased Hole versus Open Hole Sand Control Completions 1-1

Screens Only Versus Gravel Packing .................................1-1

1.2 Open Hole Horizontal with Gravel Pack.............................. 1-2

1.3 Cased Hole Horizontal Gravel Packs ..................................1-3

1.4 Perforating for Horizontal Gravel Packs ..............................1-4

1.5 Joint Industry Projects......................................................... 1-4

1.6 Summary .............................................................................1-5

1.7 Reference Papers for this Section ...................................... 1-5

2. Candidate Selection

2.1 SC2OOP .............................................................................2-1

2.1.1 Kv /Kh .......................................................................2-1

2.1.2 Young’s Modulus ......................................................2-1

2.1.3 Formation Layering ...................................................2-1

No layering ................................................................2-1

Multiple Producing Intervals ......................................2-1

Laminated ..................................................................2-2

Long Shale Streaks ...................................................2-2

2.1.4 Rock Properties ........................................................2-2

Unconsolidated Formations .......................................2-2

Friable ........................................................................2-2

Consolidated ..............................................................2-2

Clay and Fines Content .............................................2-2

i


Table of

2.1.5 Formation Damage Extent ............................................................... 2-3

No formation damage ....................................................................... 2-3

Shallow formation damage (2 to 3 inches beyond wellbore and perfs) ........................................ 2-3

Moderately deep damage (4 to 6 inches beyond wellbore and perfs) ........................................ 2-3

Deep formation damage (6 to 12 inches beyond wellbore and perfs) ...................................... 2-3

Excessive formation damage (> 12 inches beyond wellbore and perfs) .......................................... 2-4

2.1.6 Damage Mechanism ........................................................................ 2-4

Liquid Damage ................................................................................. 2-4

Solids Invasion ................................................................................. 2-4

Fines Migration ................................................................................. 2-4

2.1.7 HCl Solubility .................................................................................... 2-4

2.1.8 Faulted Sands (small reservoirs) ..................................................... 2-5

2.1.9 Large Reserves ................................................................................ 2-5

2.1.10 Naturally Fractured Formation ....................................................... 2-5

2.1.11 Need for Accelerated Recovery ..................................................... 2-5

2.1.12 Additional Zones Up Hole .............................................................. 2-5

2.1.13 Near Water/Oil Contact .................................................................. 2-5

2.1.14 Near Gas/Water Contact ................................................................ 2-5

2.1.15 Large Gas Cap with Thin Oil Column ............................................ 2-6

2.2 Cased Hole versus Open Hole ................................................................... 2-6

2.2.1 Cased Hole ...................................................................................... 2-6

2.2.2 Open Hole ........................................................................................ 2-7

3. Horizontal Gravel Pack Procedure—Water Base

3.1 Drill-out Float Shoe .................................................................................... 3-1

3.2 Pre-Displacement Steps ............................................................................ 3-1

3.3 Surface Preparation ................................................................................... 3-1

3.4 Displace Well to Drill-in Fluid ..................................................................... 3-2

3.5 Drilling Operations ...................................................................................... 3-3

3.6 Conditioning the Drill-In Fluids (DIF) .......................................................... 3-3

3.7 Displace OH to Solids Free DIF ................................................................. 3-3

Contents ii July 1999

July 199


3.8 Casing Displacement to Completion Fluid ................................................. 3-4

3.9 Wash-down Assembly with Screen and Gravel-Pack Packer .................... 3-4

3.10 Displace DIF to Completion Brine before Setting Packer ......................... 3-6

3.11 Gravel Pack Packer Setting Procedures .................................................. 3-7

3.12 Pickle Workstring ...................................................................................... 3-8

3.13 Circulation Testing .................................................................................... 3-8

3.14 Pump Horizontal Gravel Pack .................................................................. 3-9

3.15 Reverse Out after GP ............................................................................... 3-9

3.16 Setting Plug, Closing Packer Sleeve, and Pulling out of the Hole .......... 3-10

3.17 Acid Wash Open Hole ............................................................................ 3-10

3.18 Pump Brine Flush ................................................................................... 3-12

4. Horizontal Gravel Pack Procedure—Oil Base

5. Drill-In Fluids

5.1 Available “Drill-In” Fluid Systems ............................................................... 5-1

5.1.1 Sized Salt Systems .......................................................................... 5-1

Pros .................................................................................................. 5-1

Cons ................................................................................................. 5-2

5.1.2 Calcium Carbonate Systems ............................................................ 5-2

Pros .................................................................................................. 5-2

Cons ................................................................................................. 5-2

5.1.3 Oil Based Mud Systems ................................................................... 5-2

Pros .................................................................................................. 5-2

Cons ................................................................................................. 5-2

5.2 Baroid DRIL-N Fluid ................................................................................... 5-4

5.2.1 Baroid’s SOLUDRIL-N™.................................................................. 5-5

Advantages ....................................................................................... 5-5

Density Range .................................................................................. 5-5

Temperature Range .......................................................................... 5-5

5.2.2 Baroid’s BARADRIL-N™ .................................................................. 5-5

Advantages ....................................................................................... 5-5

Density Range .................................................................................. 5-6

Temperature Range .......................................................................... 5-6

9 iii Table of Contents


Table of

5.2.3 Baroid’s BRINEDRIL-N™ ................................................................ 5-6

Advantages ....................................................................................... 5-6

Density Range .................................................................................. 5-6

Temperature Range ......................................................................... 5-6

5.2.4 Baroid’s COREDRIL-N™ ................................................................. 5-6

Advantages ....................................................................................... 5-6

Density Range .................................................................................. 5-7


5.2.5 Baroid’s QUIKDRIL-N™ ................................................................... 5-7

Advantages ....................................................................................... 5-7

Density Range .................................................................................. 5-7


5.2.6 Baroid’s SHEARDRIL-N™ ............................................................... 5-8

Advantages ....................................................................................... 5-8

Density Range .................................................................................. 5-8


5.2.7 Baroid’s MAXDRIL-N™ .................................................................... 5-8

Advantages ....................................................................................... 5-8

Density Range .................................................................................. 5-9


5.3 Drill-In Fluid Recommendations ................................................................. 5-9

5.4 Particulate Sizing ..................................................................................... 5-10

5.5 Estimating / Measuring Pore Throat Size ................................................. 5-10

5.5.1 Kozeny Relationship ...................................................................... 5-10

5.5.2 Blick and Civan Relationship* ........................................................ 5-10

5.6 Lessons Learned ...................................................................................... 5-11

5.7 Competition .............................................................................................. 5-11

5.7.1 MI Drilling ....................................................................................... 5-11

FLO-PRO™ System ....................................................................... 5-11

N/A .................................................................................................. 5-12

FLO-PRO‘ Calcium Carbonate System .......................................... 5-12

5.7.2 Baker Hughes INTEQ .................................................................... 5-12

5.7.3 International Drilling Fluids ............................................................. 5-12

Contents iv July 1999

July 199


5.7.4 TBC Brinadd ................................................................................... 5-12

5.7.5 Scotoil Services .............................................................................. 5-12

5.7.6 TETRA Technologies, Inc. ............................................................. 5-12

5.7.7 Baker’s PERFFLOW ...................................................................... 5-13

6. Surface Equipment Cleanup Prior to Gravel Pack

6.1 Generic Procedure ..................................................................................... 6-1

6.2 Lessons Learned ........................................................................................ 6-2

7. Changing from Mud to DIF Before Drilling the Openhole Section

7.1 Displacement Options for Water Based Muds ........................................... 7-1

7.1.1 Sized Salt Based System Clean Up (Baroid’s SOLUDRIL) .............. 7-1

Displacing Casing from Water Base Mud to SOLUDRIL-N System . 7-1

7.1.2 Sized Carbonate Based System Clean Up—(Baroid’s BARADRIL) 7-2

Displacing Casing From Water Base Fluid To Baradril-N™ System 7-2

7.2 Displacement Options for Oil Based Muds—General Guidelines .............. 7-2

7.2.1 Option 1—Preferred Option .............................................................. 7-2

7.2.2 Option 2—Less Preferred ................................................................. 7-3

8. Displacement of Drill-In Fluid from Openhole and Casing

8.1 Introduction ................................................................................................. 8-1

8.2 Displacement of Cased Hole or OH/Screen Annulus Prior to Gravel Pack ................................................................................... 8-1

8.3 Cased Hole Displacement – General Guidelines ....................................... 8-2

8.4 Open Hole Displacements – General Guidelines ....................................... 8-3

8.5 Displacement Options for Water Based Muds ........................................... 8-3

8.5.1 Sized Salt Based System Clean Up (Baroid’ SOLUDRIL) ............... 8-4

Displacing to SOLUDRIL-N™ Clean Pill at TD ................................. 8-4

Displacing SOLUDRIL-N System from Casing ................................. 8-4

Displacing Clean Pill And Filter Cake Removal ................................ 8-5

8.5.2 Sized Carbonate Based System Clean Up—(Baroid’s BARADRIL) 8-6

Displacing To Baradril-N Clean Pill At Td ......................................... 8-6

Wellbore Spacer Pumping Sequence ............................................... 8-6

Displacing Baradril-N System From Casing ..................................... 8-7

Displacing Clean Pill And Filter Cake Removal ................................ 8-7

9 v Table of Contents


Table of

8.6 Displacement Options for Oil Based Muds—General Guidelines .............. 8-8

8.6.1 Option 1—Preferred ......................................................................... 8-8

8.6.2 Option 2—Less Preferred ................................................................ 8-8

8.6.3 Option 3—Least Preferred ............................................................... 8-8

8.7 Example Calculations ................................................................................. 8-9

8.7.1 Well Data ......................................................................................... 8-9

8.7.2 Annular Volumes .............................................................................. 8-9

8.7.3 Circulation Rates .............................................................................. 8-9

8.7.4 Contact Time/Volume Required ....................................................... 8-9

8.8 General Guidelines .................................................................................. 8-10

8.9 Lessons Learned ...................................................................................... 8-10

9. Gravel Pack Tool Assembly

9.1 Tool Systems and General Guidelines ....................................................... 9-1

9.1.1 General Best Practice Guidelines .................................................... 9-1

9.1.2 Well Control Situations ..................................................................... 9-2

9.2 Typical Sales Equipment ............................................................................ 9-4

9.2.1 VTA Versa-Trieve™ Packer ............................................................. 9-4

9.2.2 Closing Sleeve Assembly ................................................................ 9-4

Specific Sleeve Operation ................................................................ 9-5

9.2.3 Upper Extension .............................................................................. 9-5

9.2.4 Seal Bore ......................................................................................... 9-5

9.2.5 Lower Casing Extension .................................................................. 9-5

No-Flow Extension ........................................................................... 9-5

9.2.6 Mechanical Fluid Loss Device—Ceramic Flapper ........................... 9-6

9.2.7 Make Up Sub ................................................................................... 9-6

9.2.8 Blank Pipe ........................................................................................ 9-6

9.2.9 Production Screen ........................................................................... 9-6

Screens ............................................................................................ 9-6

Sizing the screen openings/Prepack Sand for Horizontal Completions ...................................................... 9-7

9.2.10 Upper Seal Bore Receptacle ......................................................... 9-8

9.2.11 Sacrificial Screen ........................................................................... 9-8

9.2.12 Centralizers .................................................................................... 9-8

Contents vi July 1999

July 199


9.2.13 Lower Seal Bore ............................................................................. 9-9

9.2.14 Washpipe Deployed Plug for Upper Seal Bore .............................. 9-9

9.2.15 Side Port Down Jet Float Shoe ...................................................... 9-9

9.3 Service Tools .............................................................................................. 9-9

9.3.1 MPW Gravel Pack Service Tool with Isolation Sleeve, Tapered Ball Seat, and Proppant Containment System ...... 9-9

9.3.2 C-Ring Isolation Sleeve in MPW Service Tool ............................... 9-10

9.3.3 Tapered Ball Seat .......................................................................... 9-10

9.3.4 Proppant Containment System ...................................................... 9-10

9.3.5 Actuated Ball Check ....................................................................... 9-10

Packer Test and Pressure Maintenance Assembly ........................ 9-11

9.3.6 Weight Down / Wash Down Collet System Option ......................... 9-11

9.3.7 Washpipe ....................................................................................... 9-12

9.4 Post Gravel Pack Wash Assembly ........................................................... 9-12

9.4.1 Wash Cup Assembly ...................................................................... 9-12

9.4.2 Baffle Cups ..................................................................................... 9-12

9.4.3 Isolation Seals and Locator Sub .................................................... 9-13

9.4.4 Rupture Disc (RD) Safety Circulating Valve ................................... 9-13

9.4.5 OMNI Valve .................................................................................... 9-13

9.4.6 RFC-III Valve .................................................................................. 9-13

9.5 Reference 12ZZ-xxxx – Shell Ram-Powell System 7-5/8-in. Casing x 4-1/2-in. Screen ........................................................... 9-14

9.5.1 Assembly Notes ............................................................................. 9-15

9.5.2 Running Notes ............................................................................... 9-16

9.6 Reference 12ZZ1830 – Petrobras Job 9 5/8-in. Casing x 5-1/2-in. PoroPlus Screens ......................................... 9-17

9.6.1 Completion Assembly Notes .......................................................... 9-17

9.6.2 Service Tools Notes ....................................................................... 9-18

Notes .............................................................................................. 9-19

Job Procedure Notes ...................................................................... 9-19

9.7 Amoco Bolivia Job – OBM 7-in., 29 lb Casing x 4-in. Screen ............................................................ 9-19

9.7.1 Service Tools Notes ....................................................................... 9-20

9 vii Table of Contents


Table of

10. Gravel Pack Fluids/Sand

10.1 HzGPSim Horizontal Gravel Pack Design Spreadsheet ........................ 10-1

10.2 Fluid Rates and Pressures ..................................................................... 10-1

10.3 Fluid Design ........................................................................................... 10-2

10.4 Breakers for Drill-in Fluid Filter Cakes ................................................... 10-2

10.4.1 Cleanup of THIXSAL PLUS Drill-in Fluids ................................... 10-2

10.4.2 Cleanup of Calcium Carbonate Drill-in Fluids .............................. 10-2

10.4.3 Cleanup of Oil Based Drill-in Fluids ............................................. 10-3

10.5 BJ’s MudZymes‘ Information .................................................................. 10-3

10.6 Tetra’s ACT Breaker System ................................................................. 10-4

10.7 Pickling Workstring ................................................................................. 10-4

10.8 Gravel ..................................................................................................... 10-4

10.9 Optimum Sand Concentration ................................................................ 10-4

10.10 Equipment ............................................................................................ 10-4

10.11 Acid Washing Equipment ..................................................................... 10-6

10.12 Lessons Learned—Operations ............................................................ 10-6

11. Reporting Results/Case Histories

11.1 Total No. of Jobs ................................................................................... 11-2

11.2 Potential or Planned Jobs in 1999 ......................................................... 11-2

12. Competition Information

12.1 Baker ...................................................................................................... 12-1

12.2 Dowell Schlumberger ............................................................................. 12-1

12.3 Others .................................................................................................... 12-2

13. Reference Papers

14. Marketing Information

14.1 Brochure No. H00180—Horizontal Washdown System ......................... 14-1

14.1.1 One-trip acid cleanup saves rig time, improves production ......... 14-1

14.1.2 One trip acid cleanup without coiled tubing ................................. 14-1

14.1.3 Leading wash technology allows fluid weight changes, minimizing fluid loss ..................................................... 14-1

15. Horizontal Gravel Pack Survey

15.1 Horizontal Gravel Pack Variables and Rules-of-Thumb for Design ....... 15-1

Contents viii July 1999

July 199

Section

11. Introduction

Various methods of completing a horizontal well are available for sand producing formations. These would include various types of screen or slotted liner in open hole, gravel pack in open hole, or gravel pack in perforated casing, etc.

1.1 Cased Hole versus Open Hole Sand Control CompletionsOne of the first decisions that must be made by the operator and/or Halliburton is whether or not the target formation will be completed as a cased and perforated wellbore or an open hole wellbore. This decision depends on a number of factors, but the need for isolating various parts of the reservoir will weigh heavily in the decision making process. The ability to isolate the perforations will enhance any remedial treatments. However, due to the cost and compli-cations with cementing a horizontal well, perforating the casing, and successfully gravel packing perforations, this method of completing horizontal wellbores is not utilized often. The difficulty in placing gravel in the high side perforations cause concern when considering this option. However, there have been a number of successful horizontal gravel packs in cased and perforated wells reported. Placing a screen in a cased and perforated horizontal application without gravel in the annulus is not recommended. The main concern is that the perforations will act to focus the stream of sand laden production fluids against the screen and sand blast a hole in the screen. The fact that the intervals are typically very long in horizontal comple-tions will alleviate some of the potential damage due to reduced flow velocities. However, the risk of cutting the screens is still considered to be high. Even if the sand-laden stream does not cut the screens, the annulus and eventually the perforations will fill with formation sand and thus cause a high pressure drop, especially in the perforations due to the relatively low perme-ability of the formation sand. Most of the horizontal completions in suspected sand producing intervals have been in open hole wellbores.

Screens Only Versus Gravel PackingHorizontal/Open Hole/Screen Completions have been a widely accepted method of sand control. This method involves circulating the annulus free of drilling debris, placing a screen (prepack screen, standard screens or slotted liner) across an open hole interval and setting a packer above the screen. In some cases, the drill-in fluid filter cake is allowed to break up naturally and is then flowed back through the screen. No sand is pumped around the screen. Until recently this was the favored method for horizontal sand control. Due to a number of failures (related to screen plugging and sand production) with this method in certain forma-tions (typically in the smaller grained formations with high concentrations of clays and fines),

9 Page 1-1 Section 1—Introduction


Section 1

ide a lter-n omple- of the

non-

an If the This hori-

6 icient that

wire ent.

ue to ith ravel rying sist the ids nt the

gravel packing horizontal wellbores is becoming more commonplace. The gravel between the open hole and the screen should enhance the ability of the completion to filter out the forma-tion particles and to distribute flow more uniformly, and thus potentially extend the productive life of the well.

The inclination of the hole reduces the effect of skin. The open hole reduces the velocity of the fluid flowing into the screen and thus reduces the drag forces on the sand grains thereby minimizing sand production problems. Packing sand around the screen, in theory, would further reduce the drawdown across the screen completion. However, in most cases the draw-down is insignificant due to the effects of the horizontal well on the skin effect. Any gravel pack sand placed around the screen is beneficial but determining the success or failure of the gravel pack placement is more difficult than in vertical wells. The screens are not usually eroded as in screen-only completions in vertical wells in that there are no perforations to focus the erosion point on the screen, but if the pack does not succeed in shutting off crossflow in the screen-open hole annulus, flow may concentrate at points which are not packed or plugged, and erosion may occur at these “hot spots”.

Depending upon the formation, horizontal screen-only completions may or may not provlong term, productive sand control completion. In general, if the formation consists of anating sand / shale sequences then a gravel pack should be considered. If the formatioconsists of thick homogeneous sands then a screen only-completion or a gravel pack ction may be considered. The choice will depend to a large extent upon the consistencyformation as measured by the Uniformity Coefficient (D40/D90) as defined by Karpoff / Schwartz. Schwartz defined uniform sands as those with a uniformity coefficient <3, anduniform sands are defined to be those with coefficients >5.

Note—Baker utilizes the following rules-of-thumb. If the Uniformity Coefficient is less th2 (well sorted, uniform formation sand) then a screen only completion is recommended.Uniformity Coefficient is greater than 2 then a gravel pack completion is recommended.seems to be a conservative viewpoint and would sway Baker personnel to recommendzontal open hole gravel packs.

Obviously, there are variations in the Uniformity Coefficient cut off point.

King and Tiffin of Amoco states that Pall utilizes a Uniformity Coefficient cut off point of(maximum) for an 80 mesh Stratapac Screen (woven wire mesh) and a Uniformity Coeffcut off point of 8 (maximum) for the 200 mesh Stratapac Screen. They further indicateda Uniformity Coefficient of 5 was to be taken as a warning size that fines could plug themesh screen. The latter value falls in line with Schwartz definition of Uniformity Coeffici

1.2 Open Hole Horizontal with Gravel PackHorizontal gravel packs have become a popular method of completing horizontal wells dthe number of failures of open hole screen-only completions, especially in formations wlarge amounts of fines. Operationally the horizontal gravel packs are similar to vertical gpacks. Horizontal gravel packs can be placed in open or cased hole completions of valengths. The horizontal hole presents sand transport problems since gravity does not aspacking process. For this reason the jobs must be designed with pumping rates and fluwhich are sufficient to provide proppant transport. This is usually done with low proppadensity and brine (or lightly gelled slurries) while fluid loss control is maintained to stop

—Introduction Page 1-2 July 1999

July 199


than water duce

al river l dune tal open moves

thief about

zone. f the n inter-rmal.

vail-ined rts ently

perfora-st be

formation of bridges in the annulus due to fluid losses. Fluid loss control is obtained by drilling the open hole section with a drill-in fluid which will leave a filter cake. Since fluid loss control is required, a means of removing the fluid loss control material after the pack is in place must be included in the completion plan.

The basic theory behind the alpha-beta wave approach to gravel packing horizontal wells can be traced back to the mechanics and practice of slurry transport in pipelines1. The basic method for the horizontal gravel packing process is a two step (two lift) process. The gravel is transported to the toe of the well via a water-sand slurry. As the velocity of the slurry decreases when it enters in the open-hole / screen annulus, the sand will drop out of the slurry thus forming a sand dune on the low side of the hole. The dune will build to a point where the decreased cross sectional flow area causes the velocity to increase. A velocity range of 1-3 ft/s will transport sand across the top of the dune and further down the hole. The process is described in the reference documents2. “The water in the ullage flow space (annulus) appears to stabilize automatically at 1-3 ft/s (30-91 cm/s). If the water velocity is greater1-3 ft/s (30-91 cm/s), the gravel is washed ahead to open a larger ullage flow space. If thevelocity is less than 1-3 ft/s (30-91 cm/s), the gravel deposits more rapidly to fill in and rethe cross section of the ullage flow space.”1 “The actual movement of gravel in the ullage space is not by slurrification. Instead the gravel moves by hopping (saltation) of individugravel grains along the top of the gravel dune, much like the sedimentation process in abed. The net saltation velocity along the base of the ullage flow space on top of the gravesurface is about 1 ft/s (30 cm/s)3." The progressive movement of the gravel dune down theannulus is referred to as the Alpha Wave. This step will fill about 70-90% of the horizonannulus. As the sand reaches the end of the horizontal annulus it begins to back fill thespace above the dunes in a manner which is known as the Beta Wave. The Beta Waveback towards the heel of the well, fully packing the annular space.

A thief zone may cause the Alpha-Beta wave to stall resulting in an early sandout “Forzone loss rates of about 0.30 bbl/min and an inlet pump rate of 1 bbl/min, a return rate of0.40 bbl/min has to be maintained to prevent the alpha wave from stalling prematurely.

High thief zone losses cause the alpha wave dune height to increase opposite the thiefThis interferes with transport over the top of the dune at that location. Also, the effect othief zone losses cause the gravel to dehydrate quickly. The increase in the concentratioferes with transport downstream and tends to make the equilibrium height higher than noThe consequence is a potential alpha wave stall opposite the thief zone.”1

A technology patented by Mobil called “alternate path” or “shunt tubes” that has been aable for many years for transporting gravel past annular gravel bridges has recently gasome interest for use in horizontal gravel pack applications. Dowell-Schlumberger repomore than 300 jobs using this technology in vertical well gravel packs. Halliburton is currinvestigating an alternative method of transporting gravel past annular gravel bridges.

1.3 Cased Hole Horizontal Gravel Packs Cased hole gravel packs must have enough gravel outside the casing to assure that alltions remain filled with un-invaded gravel while the size and number of perforations musufficient to minimize restriction of fluid flow through gravel-filled perforation tunnels.



Section 1

tinual ions in a ards

umber g the hori-ch ori-ori-

een nup on -ple-lls

t oject acks,

Several systems have been proposed for packing the perforation tunnels and subsequently the screen/casing annulus in horizontal wells. These systems range from a water pack using brine and gravel pack sand or a low-density ceramic material to a super-high sand concentration slurry with very little fluid.

A widely accepted fact is that as the angle of deviation increases, the ability to successfully pack the perforation tunnels and the screen/casing annulus decreases.

Studies have shown that, with the alpha beta wave approach, gravel can be placed in the screen/casing annulus using water regardless of the angle of deviation. However, in the field, fluid leakoff to the formation and fluid leakoff to the screen and back into the washpipe will interfere with the transport phenomena noted in laboratory studies. To successfully pack the high side perforations will require that the fluid velocity entering the perforation tunnels exceed the critical transport velocity of the gravel. Lessening the density of the gravel pack sand will lessen the required critical transport velocity. Increasing the viscosity of the carrier fluid will also lessen the required critical transport velocity.

1.4 Perforating for Horizontal Gravel PacksThe perforating pattern for horizontal gravel pack completions plays a part in the success of packing the annular space (including the perforations). Some authors1 believe that the best option is to perforate only the sides of the horizontal well (not the top and not the bottom) while many believe that we should perforate only the lower 180° to 240° of the wellbore. “The successful propagation of the alpha wave towards the toe of the horizontal requires confluid flow over the top of the alpha wave. If however, enough fluid is lost to the perforaton the top of the hole, erosion of the alpha wave ceases. Thus, the alpha wave will attaheight that will bridge across the well and initiate propagation of the beta wave back towthe heel of the horizontal.”2

1.5 Joint Industry ProjectsThe success of sand control completions in a horizontal wellbore depends upon a large nof variables. All of the variables are interrelated and must be considered when designincompletion. A number of industry consortiums have studied the various aspects of the zontal completions. Heriot-Watt University in Edinburgh, Scotland has a separate bran(Horizontal Well Technology Unit) which coordinates industry funded projects studying hzontal completions. Halliburton was involved in the “Evaluation of Screen Options for Hzontal Wells” from 1995 to 1997. The Completions Engineering Association has also binvolved in various studies concerning horizontal completions. CEA-73 “Wellbore Cleain Horizontal Wells”, in which Halliburton was involved, was a fluids screening evaluatiprogram utilizing Westport Technology in Houston to evaluate various drill-in fluids. RFRogaland Research in Norway has various programs underway to study horizontal comtions. StimLab, Inc. is currently performing tests for a Screen Cleanup in Horizontal WeConsortium. The latest addition to this list would be the BP-Amoco led Consortium thaincludes Arco, Elf, Exxon, Petrobras and Chevron. This consortium is a three-phase prthat has been put together to study mathematical simulations of the horizontal gravel pdrill-in fluids (especially OBM) and erosion / removal of the filter cake material. It also addresses the alternate path technology.


July 199


and es s icals

pletion ll in the

nes:

nes:

lu-

In addition, a number of SPE Papers and magazine articles have been published by various operators and service companies and combined operator/service company teams concerning the various aspects of the horizontal sand control completion program. Please note that the completion program now encompasses drilling the actual production interval.

1.6 SummaryUnfortunately there are no industry-wide accepted guidelines concerning this type of comple-tion at this point in time. The total program is complicated and spans many of the PSL’scompanies within Halliburton. The list of processes includes: (1) drilling related processsuch as directional drilling, MWD / LWD, (2) drilling fluids, (3) cementing, (4) drill-in fluidand completion brines, (5) displacement chemicals and processes, (6) stimulation chemand processes, (7) sand control chemicals and processes, (8) oilfield screens, (9) compackers and equipment, (10) liner hangers, etc. Successfully designing a horizontal wecompletion program requires involving all of the related personnel as early as possible design process.

1.7 Reference Papers for this Section1. Gravel Packing of Horizontal Wells, SPE 16931

2. Gravel Packing of Horizontal Wells, SPE 16931

3. Gravel Packing of Horizontal Wells, SPE 16931

4. Gravel Placement in Horizontal Wells, SPE 31147

5. Horizontal Gravel Packing Technique for Slim, Cased Holes in Highly Permeable ZoA Single Well Case History, SPE 39469

6. Horizontal Gravel Packing Technique for Slim, Cased Holes in Highly Permeable ZoA Single Well Case History, SPE 39469

Note—A Second Generation Horizontal Drilling System, IADC-SPE 14804” contains vaable information on the A/B wave technique.



Section 1

This page was intentionally left blank.


July 199

Section

22. Candidate Selection

sand

en o will the -

2.1 SC2OOP SC2OOP (Sand Control Completion Optimization Program) is a computer program developed by Halliburton that assists in selecting the optimum type of completion for a formation which has already been determined to require sand control. It currently is limited to recommending frac pack’s, acid prepack/HRWP’s, gravel packs with gelled carrier fluids or horizontal controlled completions. The following information was obtained from the SC2OOP Manual as well as from other sources.

2.1.1 Kv /Kh

The ratio of vertical permeability to horizontal permeability is a very important factor whevaluating a reservoir as a potential horizontal well candidate. Larger values of this ratistrongly favor horizontal wells since vertical permeability is required to effectively drainentire zone. Lower values of KV/KH favor completions that minimize the effects of permeability contrast such as FracPacs or HRWP.

2.1.2 Young’s Modulus

Open hole (OH) horizontal wells are also ranked higher for high Young’s Modulus due to improved wellbore stability.

2.1.3 Formation Layering

No layering

This represents a uniform formation distribution without layers restricting the vertical perme-ability. Horizontal open hole and gravel pack completions, acid prepacks and conventional gravel packs are favored under this condition.

Multiple Producing Intervals

In this case there are vertical barriers separating two or more productive intervals where the productive intervals have relatively good vertical permeability within a particular interval. The model favors conventional gravel packs and acid prepacks under these conditions.

In the case of horizontal wells, more complex drilling procedures would be required to connect the multiple intervals.

9 Page 2-1 Section 2—Candidate Selection


Section 2

Laminated

This refers to thin bed laminated formations that consist of multiple, thin layers of productive and non-productive rock. These formations often have good, but disjointed horizontal perme-ability and virtually no vertical permeability.

In these reservoirs, horizontal wells will not provide good drainage over the entire reservoir height due to the poor vertical permeability. Horizontal wells drilled in these formations would likely require a hydraulic fracturing treatment to improve vertical permeability, and so horizontal wells are generally less desirable in these conditions.

Long Shale Streaks

If the horizontal section will be exposed to long water sensitive shale streaks then consider perforated casing as opposed to an open hole completion.

2.1.4 Rock PropertiesUnconsolidated Formations

Unconsolidated formations (unconfined compressive strength <?2000? psi) are considered to be essentially neutral for most of the completion options, however, it is a strong negative to OH horizontal completions. The primary reason for this is the increased risk of wellbore collapse.

Friable

Friable formations (?2000? psi<unconfined compressive strength <?3000? psi) are suscep-tible to shear failure during drilling and draw down during production.

FracPacs and horizontal wells which are supported by screens or a gravel pack are favored for this condition since they will help to minimize the draw down at a given production rate.

Consolidated

Consolidated rock (compressive strength >?3000? psi) is considered to be rock that would remain competent and stable during drilling and most production operations. These forma-tions can begin to produce sand at high flow rates, high drawdowns or when water break through occurs.

Conventional sand control completions such as gravel packs, HRWP, and acid prepacks are rated low as their benefits would not be realized until late in the life of the well, if at all. Here there is a significant up front expense that will hurt the net present value of the project.

FracPacs (screenless) and OH horizontal wells are favored since they minimize the skin and draw down potential making higher rate production without sand possible. Since these completions do not use screens it will be easier to perform remedial sand control operations late in the life of the well if the economic life can be extended using this approach. The cost of this is deferred until the problem is verified. If this cost can be deferred several years there will be a significant benefit to the net present value of the project.

Clay and Fines Content

Horizontal completions on formations containing large amounts of clays and fines material should be gravel packed as opposed to just running screens (PoroPlus or Prepacked Screen)

—Candidate Selection Page 2-2 July 1999

July 199


that

with

in the open hole. In areas where the formations are well sorted, large grained, high perme-ability with very few movable fines (clays), a screen only in an open hole horizontal well works fine. Examples of this would include the Troll Vest Oil Province in Norway. Halli-burton has installed screens in approximately 30 wells in this area without any reported prob-lems due to erosion of the screen and subsequent sand production. In areas of fine grained formation sands with large amounts of clays and fines some operators have noted a fairly high percentage of failures with a screen only, open hole horizontal well completion. Numerous examples of this have been noted in the Gulf of Mexico. For those wells horizontal open hole gravel packs would be the preferred type of completion.

2.1.5 Formation Damage ExtentNo formation damage:

If there is no formation damage, any stimulation type treatments would only be helpful in low permeability reservoirs. Since the focus is on high permeability reservoirs here, there would be no major advantage in stimulating an horizontal undamaged wellbore. For this reason gravel packing and horizontal well solutions are favored under this condition.

FracPacs and acid prepacks are ranked lower as options since there would be no gains to be made from the stimulation benefits while introducing an additional cost. However, it is a well accepted industry belief that the practice of gravel packing itself introduces appreciable forma-tion damage (some operators use skins of 15-30 as their expectation), and so these stimulation type techniques actually may merely return the well back to the equivalent of an undamaged state. HRWP was ranked neutral since it is often used as a procedure to obtain a good gravel pack.

Shallow formation damage (2 to 3 inches beyond wellbore and perfs)

For shallow damage the HRWP and acid prepacks are strongly favored due to their ability to remove or by-pass shallow formation damage. Horizontal well solutions are also favored, but not as strongly since the damage can be tolerated, but may be hard to remove.

Moderately deep damage (4 to 6 inches beyond wellbore and perfs)

Under these conditions the HRWP and acid prepack completions are most favored as they should still be capable of penetrating or removing damage of this depth.

Gravel packs are ranked low here due to the difficulty in removing damage under these condi-tions and the potential of having a high positive skin. Horizontal wells are also ranked lower due to the potential of a high positive skin completion that is difficult to clean up.

Deep formation damage (6 to 12 inches beyond wellbore and perfs)

Under these conditions the FracPac option was the only favored solution due to its ability to bypass the deep damage. Until this point it had been essentially ranked neutral since there was no perceived advantage if there is no significant damage.

Note—In Angola Halliburton have frac packed wells for Chevron and BP-Amoco in wells have permeabilities in the 2-5 Darcy range. Results thus far are excellent.

All other completions will be negatively affected by the deep damage. The risk associatednot being able to penetrate the damage is high and results in the lower rating.



Section 2

ctly.

solu-e also

it will igh ntal

mize

ple o the The

Excessive formation damage (> 12 inches beyond wellbore and perfs)

In this case the FracPac should be the only option recommended to effectively by-pass the skin and achieve desirable production.

2.1.6 Damage Mechanism

The cause of the damage is just as important as the depth of the damage.

Liquid Damage

Liquid damage resulting from excessive losses of completion fluids to the formation, fluid incompatibilities causing emulsions, or fluid incompatibilities causing clay swelling or fines migration is considered in this case.

Depending upon the depth of the damage, the model will favor acid prepack completions for this condition. All other options are seen as being neutral or slightly negative.

Note—This type of damage can be limited if fluid loss control processes are used corre

Solids Invasion

For solids invasion due to drilling mud or cuttings, the acid prepack is the most favoredtion due to the ability to remove the damaging material. Both the FracPac and HRWP arranked positive for this condition due to their ability to by-pass the damaged region.

Gravel packs and horizontal well options are ranked very low for this condition.

Fines Migration

In a well damaged by fines migration, the FracPac option is the favored solution since reduce draw down and help to minimize the problem. Acid prepacking was also rated hsince additives can be used to obtain deeper penetration and stabilize the fines. Horizowells are also seen as slightly positive due to the long exposed interval helping to minifluid velocity and fines migration.

2.1.7 HCl Solubility

The HCl solubility of the formation is used strictly to evaluate the potential for acid prepacking. All other options are left at neutral for this condition.

For the acid prepack option the following criteria are used.

For HCl solubility > 20% there are differing opinions on acidizing the formation. Many peofeel that when the HCl solubility exceeds 20% the formation strength will be weakened tpoint where severe fines migration may become a problem at higher production rates.

Table 2.1—Acid Prepack Criteria

HCl solubility Rank

<10% Highly favored10 to 20% Favored>20% Favored (with conditions)


July 199


other school of thought is that if screens are being used anyway and sand production is already controlled, the removal of 20% of the rock bulk volume represents a significant increase in porosity and permeability. Under this condition it would be possible to achieve improved production rates at lower drawdowns. The conditions applied when the HCl solubility is greater than 20% HCl should be used instead of sandstone acid and screens or mechanical sand control equipment must be in place.

2.1.8 Faulted Sands (small reservoirs)In small, faulted sand reservoirs the preferred options are HRWP and acid prepacks. In this situation the FracPacs are not favored due to associated cost and the potential difficulty in achieving the desired job in a highly faulted reservoir. The benefits from larger treatments are very limited in small reservoirs.

2.1.9 Large Reserves

In fields with large reserves, the horizontal well options are ranked the highest due to the potential to drain the entire reservoir with fewer wells. FracPacs are also favored, but not as highly as the horizontal well solutions for this case.

2.1.10 Naturally Fractured FormationThere has been some question as to the applicability of natural fractures in high perm sand-stone formations, but in some of the more competent formations in the North Sea, it was seen as a potential. In this condition the use of horizontal wells was ranked very highly since it is possible to intersect that natural fractures and improve the effective permeability to the well-bore.

2.1.11 Need for Accelerated RecoveryIn most cases this will be an economic issue where the reserves must be recovered as quickly as possible to improve the viability of the project. For this case, the horizontal solutions and FracPacs are ranked the highest. Acid prepack is ranked slightly positive.

2.1.12 Additional Zones Up Hole

When additional zones are present higher up in the well, there may be problems associated with the horizontal wells in that the upper zones may be located in the build sections. For this reason horizontal wells are ranked low for this condition. HRWP, FracPacs and acid prepacks are ranked high for this condition.

2.1.13 Near Water/Oil Contact

Horizontal well solutions are ranked the highest with all others being slightly positive as well with the possible exception of FracPacs. Completions should be cased and perforated..

2.1.14 Near Gas/Water Contact

Similar to Near Water/Oil Contact



Section 2

vel

ot the

ria (It ance

2.1.15 Large Gas Cap with Thin Oil Column

Horizontal wells are very strongly favored in this condition with all other options receiving a strong negative ranking due to the increased potential for coning the gas in a vertical wellbore.

2.2 Cased Hole versus Open Hole

2.2.1 Cased Hole

If horizontal is cased, cemented and perforated a horizontal gravel pack may have to be broken up into shorter (e.g., 500 ft) sections, a special perforating pattern (low side or similar) may have to be used, or alternate path technology may be required for packing the longer intervals. Currently a length of 1000 ft is considered to be the maximum even with alternate path tech-nology. If long shale streaks are encountered (especially if they are water sensitive) the oper-ator should consider a cased and perforated completion over an open hole completion.

If the well contains long, water sensitive shale streaks consider using a slurry pack as opposed to a water pack.

There have been a number of cased hole gravel packs reported (Baker has performed some in the Gulf of Mexico but the perforated intervals are relatively short). The concern is, of course, obtaining an adequate perforation pack prior simultaneous with obtaining the annular pack between the screen and casing.

In Norway, Statoil, Dowell and Baker performed an uphill (92° deviation) gravel pack on a live well using snubbing in the early 1990s. Baker supplied the AUGER perforating system, the downhole tools and screens, Dowell supplied the ISOPAC light-weight proppant and the fluid systems. Prior to perforating the well, they established circulation. Circulation was continued as the well was perforated (dynamic underbalance). Circulation/production continued while pulling the guns above the perforations. The well was then shut in and excess perforating debris was circulated out of the hole via the circulating port above the guns. Shunt Screens are run in the hole and Dowell packed the well using ISOPAC (light-weight proppant). No report on the actual perforating pattern (low side only, lower 270°, lower 180°, etc.) was available.

A horizontal cased hole gravel pack was reported in SPE paper 39469 “Horizontal GraPacking Technique for Slim, Cased Holes in Highly Permeable Zones: A Single Case History”. In that paper the authors recommend perforating only the sides of the hole (ntop or bottom).

Halliburton has been involved in at least one cased hole horizontal gravel pack in Nigewas a relatively short interval by horizontal well standards—185 ft). In that particular instFloPac was utilized to pack the horizontal screen/casing annulus.


July 199


this is

2.2.2 Open HoleIf a synthetic DIF fluid is utilized to drill the open hole consider using a screen only completion first. Changing out to a solids free water-based fluid system, which is currently required to prevent plugging of the screens and pack, and gravel packing with the synthetic filter cake in place poses considerable compatibility issues. There are also problems with potential early lift-off of the filter cake during the packer setting process as well as moving the service tools, as OBM and SBM filter cakes lift off more easily than filter cakes deposited by water-based fluids.

Note—Numerous topics can be discussed under this section but due to time constraintsnot possible at this time.



Section 2

This page was intentionally left blank


July 199

Section

33. Horizontal Gravel Pack Procedure—Water Base

N

r

affect

Short

ce

of o

Note—Well has been drilled to top of formation, casing has been run and cemented.

Note—This Displacement/Clean-up procedure for a water based drill-in system is a general-ized recommendation based on Halliburton’s current technology with regards to DRIL-fluids. Before making formal recommendations to potential customers, please confirm with ouDRIL-N fluids technical personnel regarding spacer compatibility and cleanup solution compatibility. Various factors such as temperature and formation sensitivity can and do the type of recommendations made.

3.1 Drill-out Float ShoeDrill out float shoe and 5 ft into formation with drilling mud.

3.2 Pre-Displacement Steps1. RIH to T.D. with bit, casing scrapers, and/or bristle brushes for the casing interval.

trip the bit, casing scrapers, and bristle brushes.

2. Circulate and condition drilling fluid to reduce viscosity and gel structure of fluid inpreparation for displacing to BARADRIL-N or other drill-in fluid system.

3. Offload the mud in the surface drilling system (tanks and lines) to the workboat.

3.3 Surface PreparationAfter loading the mud from the surface drilling fluid system to the workboat, begin surfacleaning by performing the following steps:

1. Wash fluid handling system equipment and adjacent areas utilizing a combinationhigh volume wash to remove most solids followed by high-pressure steam wash tremove caked materials.

9 Page 3-1 Sec. 3—Horizontal GP Proc.—Water Base


Sec. 3—

2. Start at the highest point of the fluid handling system (typically the flowline area) and wash down. This involves starting at the shaker area and ending at the mud pits, including the mud pumps and lines.

3. Ensure that all troughs, flowlines, trip tanks, pits, etc. are opened and thoroughly cleaned.

4. Ensure that all structural steel such as angle irons, ladders, equalization lines, etc. are thoroughly cleaned, paying special attention to areas not readily visible.

5. Also ensure that all walkways and gratings above the pit areas are cleaned of all mud residues.

6. After removing all visible mud solids and residues, open all suction and discharge lines of the circulating and transfer system to ensure that trapped solids are removed.

7. Surface sweep: Fill the slugging pit with fresh water and add 4 ppb Caustic Soda and 4 cans CONDET per 50 bbls of water.

8. Circulate the surface sweep throughout the entire fluid handling system ensuring that all pits, suction lines, transfer lines, equalization lines, mixing pumps, and mud pumps, trip tanks, displacement tanks, and the cement unit are cleaned adequately. Utilize all avail-able pumps and circulate to ensure at least 10 minutes of contact time for the entire system.

9. Individually close each valve in the circulating/mixing/transferring system against centrifugal pump pressure and monitor for leaks. Replace any valves that appear to leak.

10. Drain all tanks and lines and squeegee all residues to dump valves. Use a mop or diaphragm pump to drain all low spots in the pit system. Remove any remaining mois-ture by mopping. Any residual fluids could dilute the drill-in fluid that has been opti-mized for the particular hole conditions.

11. Break all circulating lines and open all valves to ensure that all water is drained from the mixing and transferring system. Blow the system dry with compressed air prior to closing lines and valves.

12. Close all dump valves and seal with silicone caulk. Replace any valves or seat which appear to be cut, damaged, or worn. All dump valves should be locked out to prevent inadvertent opening during the completion/workover process

13. Mud returns should be isolated to flow into the workboat for return credit. A mud sample should be collected for bioassay purposes before dumping any mud.

3.4 Displace Well to Drill-in Fluid1. Calculate the volume of the spacer based on covering 500 ft of largest annulus using the

following formulation.

___ bbls water, 2-3 ppb N-VIS (Viscosity should be greater than that of the drilling fluid). Utilize Barite for density (Density greater than drilling fluid by no more than 0.5 ppg)

2. Determine the formulation of the spacer as follows:

100 bbls water 1 drum BARA-KLEAN FL

Horizontal GP Proc.—Water Base Page 3-2 July 1999

July 199


nulus

ppb N

free of

3. Calculate the volume of the spacer based on covering 500 ft of largest annulus using the following formulation.

___ bbls fresh water, 2-3 ppb N-VIS

4. Pump spacers at rate of 2 to 6 bbl/min keeping spacers in turbulent flow to aid in better casing cleaning results. Follow last spacer with BARADRIL-N system.

3.5 Drilling OperationsOnce the spacers have been pumped, begin drilling.

3.6 Conditioning the Drill-In Fluids (DIF)1. After reaching TD, circulate well clean, working pipe to aid in removal of cuttings bed.

Do not circulate continuously in one spot as hole will wash out. Circulate at least 2 hole volumes or until clean.

2. Make wiper trip to bottom of casing and circulate at maximum rates until bottoms up. Run back to bottom and circulate out and prepare to displace dirty BARADRIL-N system

3.7 Displace OH to Solids Free DIFSpacers and other fluids should be pumped at 2-3 bbl/min.

1. Calculate the volume of the spacer based on covering 500 ft of largest annulus using the following formulation.

___ bbls completion brine (Brine density should equal that of system in well) 2-3 ppb LIQUI-VIS EP (Viscosity should be 2-3 times low shear viscosity of BARADRIL-N system in wellbore or 1.5-2.0 times the yield point of the fluid being displaced.)

2. Calculate the volume of the wellbore spacer (BARADRIL-N Clean Pill) using the following formulation. Clean the Pill to cover the open hole section.

Volume of the system equals open hole volume, plus washout (10% or more) and 200-500 ft of coverage into casing.

Note—Bridging particles in Clean Pill should only comprise BARACARB 5

3. Calculate the volume of the wellbore spacer based on covering 500 ft of largest anas follows:

___ bbls completion brine (Brine density should equal that of system in well) 2-3LIQUI-VIS EP (Viscosity should be 2-3 times low shear viscosity of BARADRIL-system in wellbore or 1.5-2.0 times the yield point of the fluid being displaced).

Spacer number 3 will be followed with a DIF fluid with specially sized particles, a solids drill-in fluid or a clean completion brine, depending upon the situation. For the purposes



Sec. 3—

n

plus

-3 bbl/

and

nulus

ppb N

t

ppb

e

ole.

g and

ble to

this particular procedure we will assume that the open hole will be changed out to a drill-in fluid with specially sized particles for bridging.

Note—Brine should be filtered through Halliburton’s pre-coat filtration unit with 2 microabsolute filter cartridge unit.

4. Drill-in the fluid—BARADRIL-N Clean Pill with BARACARB 5 Bridging Particles.

5. Circulate the new DIF down workstring to displace the former DIF out of open hole 200-500 ft up into casing.

3.8 Casing Displacement to Completion FluidDisplace the casing to completion fluid. Spacers and other fluids should be pumped at 2min.

1. Pull the drill string back into casing near top of BARADRIL-N Clean Pill.

2. Prepare and pump the following spacers to remove the dirty BARADRIL-N systemclean casing.

3. Calculate the volume of the Clean-Up Spacer based on covering 500 ft of largest anusing the following formulation.

___ bbls completion brine (Brine density should equal that of system in well) 2-3LIQUI-VIS EP (Viscosity should be 2-3 times low shear viscosity of BARADRIL-system in casing or 1.5-2.0 times the yield point of the fluid being displaced)

4. Use the following formulation for the Clean-Up Spacer:

Formulation: 100 bbls brine water 1 drum BARA-KLEAN FL

5. Determine the volume of the Clean-Up Spacer based on covering 500 ft of largesannulus using the following formulation.

___ bbls filtered completion brine (Brine density should equal that of system) 2-3LIQUI-VIS EP

6. Pump the above 3 clean-up spacers followed with clean filtered completion brine (filtered to 2 micron) to fill casing section. Continue circulation until completion brinreturns are clean (< 20 NTUs).

7. If necessary, spot a fluid loss control pill to cure losses prior to pulling out of the h

The well is now ready to run gravel pack assembly through the filtered brine in the casininto the clean BARADRIL-N Clean Pill with BARACARB 5 bridging particles.

3.9 Wash-down Assembly with Screen and Gravel-Pack Packer1. Run the wash-down assembly with the screen and gravel-pack packer.

If difficulties are encountered in running gravel pack screens into open hole, it is preferawash the screens down and to not rotate the screens in the open hole section. Additionally,


July 199


bpm.

llow nk

hich the

.

keep gravel pack screen full of filtered brine to prevent intrusion of fluid into screen from annular sections of well.

2. RU screen table, power tongs and crummy

3. Pick up lower BHA to include the following:

•float/washdown shoe,

•lower seal bore (with isolation plug installed),

•sacrificial screen,

•upper seal bore and

•crossover

4. Make up to top drive and establish circulation through assembly at rates of 1 and 2Record pressures at each rate. Verify that no plugging is occurring.

5. Make up bundle carrier and pressure/temperature gauge assembly.

6. Pick up and make up first screen joint.

7. Pick up and make up balance of screen joints.

8. Specify amount of blank to be run for proper space-out. Ensure blank amount will athe packer to be set a maximum of 100 ft from shoe with no more than 30 ft of blaexiting the shoe.

Note—Some of our personnel feel that we should run screen 30-50 ft into the casing wwould allow a competent gravel pack in the open hole and 200-300 ft of blank betweenscreen and the packer.

9. RIH balance of blank and set blank in slips.

10. Install washpipe running table and slip bowl for washpipe.

11. Make up male Ratch Latch to first joint of washpipe.

12. Make up gauge carrier to washpipe with gauge assembly installed.

13. Install crossover to top of gauge carrier.

14. Pick up and make up balance of washpipe.

15. RIH with balance of washpipe, space out for installation of packer.

16. Pick up packer sub assembly and make-up wash pipe to packer.

17. Remove wash pipe table and slip bowl.

18. Disconnect make-up sub and install lower end to top of blank.

19. Lower packer assembly and make-up to make-up sub and blank pipe.

20. Pick up packer, washpipe and screen assembly.

21. Verify packer, washpipe and shoe are clear, break circulation at 1 bpm and 2 bpm

22. Record rate and pressure.



Sec. 3—

23. Lower assembly in hole below BOP’s. Close BOP on workstring, ensure work string is lined up to take returns.

24. Perform reverse pressure test on parked plug by attempting to break circulation in reverse position. Do not exceed 200 psi. If flow up work string is observed, POOH with work string and re-space out wash pipe. Go back in hole and repeat the test.

25. If test successful go in hole one stand and install ___" gauge carrier and gauge.

26. Run in hole at no faster than one 3 joint stand per minute (1 ft/s), filling workstring with fluid every five stands.

27. Prior to exiting the shoe with screen, stop, measure and record 10 minute fluid loss rate.

28. Measure and record pick up and slack off loads.

29. Break circulation at 1 and 2 bpm. Record pump pressure and rate. Verify no plugging is occurring before running in open hole.

30. Stop circulation. Take a 10 minute fluid loss rate. Record in bbl/hour. If fluid loss rate is more than 20 bbl/hour, consult with project engineer and prepare to pump a contingency fluid loss control pill.

31. Slowly exit the shoe with first three joints of screen.

32. Run screen in open hole to depth specified at a rate not to exceed 1 ft/s. Avoid shut downs, fill pipe only between connections, but do not shut down to fill. Monitor and record fluid loss rate while GIH. If a ledge is encountered, circulate through work string to pass. If screen gets stuck while GIH, contact project engineer and prepare to pump stuck pipe acid. Do not rotate.

33. Take a 10 minute fluid loss rate. Record in bbl/hour.

34. Screw top drive into pup joint/pump in sub assembly and break circulation with rig mud pump.

35. Position assembly at near TD but do not tag TD.

36. Pick up 5 ft.

37. Measure 10 minute fluid loss rate.

3.10 Displace DIF to Completion Brine before Setting Packer1. Calculate the volume of the spacer based on covering 500 ft of largest annulus using the

following formulation.

___ bbls completion brine (Brine density should equal that of system in well) 2-3 ppb LIQUI-VIS EP (Viscosity should be 2-3 times low shear viscosity of BARADRIL-N Clean Pill in wellbore or 1.5-2.0 times the yield point of the fluid being displaced)

2. Displace filtered completion fluid down workstring and through GP assembly (out the Float/washdown Shoe) to circulate Solids Free DIF out of hole. Continue circulating for a minimum of 3-5 hole volumes or until the irreducible minimum turbidity is attained (the goal is < 20 NTUs).

3. Stop pumping. Measure and record fluid loss rates.

4. If the fluid loss rates are above 20 barrels per hour spot fluid loss control pill.


July 199


f the are the

essure.

e note

tion.

5. Resume circulation to remove all of pill material is out of open hole prior to setting packer.

3.11 Gravel Pack Packer Setting Procedures1. Prior to setting the packer, rig up GP pump lines, flush and test to 5,000 psi.

2. Confirm packer is on depth.

3. Break circulation to ensure a clear flow path.

4. Drop the correct setting ball. Allow 5 min per 1000 ft of measured depth if section is deviated less than 60°, and 10 min per 1000 ft for deviations of 60-75° for free fall osetting ball. The ball should be pumped down at greater deviations, but extreme cmust be taken when pumping the ball down so that when the ball reaches its seatpump rate is < 0.25 BPM, to prevent prematurely shearing the ball seat.

5. Begin pumping slowly until the ball goes on seat.

6. Apply 500 psi to test work string.

Note—The setting tool isolation sleeve will shear at 600 psi.

7. Pressure up to 1500 psi and hold pressure for 30 seconds.



10. Bleed off pressure.

11. Close annular BOP and pressure up annulus to 1500 psi to test packer. Bleed off pr

12. Apply over-pull of 10,000 lb above pick up weight to ensure the packer has set.

13. Slack off 6000 lb.

14. Pressure up on workstring to 5000 psi to expel ball into seat of the crossover. Makof ball expending (~4200 psi). Bleed off pressure.

15. Rig down pump lines.

16. Apply neutral weight to the packer.

17. Rotate approximately 12 turns at the packer to release running tool string.

18. Pick up approximately 6 ft and slack back down to new weight down circulate posi

Warning—Always move service tools as slowly as is practical (creep rates) to minimizepressure surges that could lift the open hole filter cake from the formation face.

Warning—Do not actuate reverse ball check at this time. Apply weight down as neces-sary to compensate for expected cooling of workstring during circulation. Mark pipe.

19. Open annular. Monitor weight indications and compensate as necessary for tubing move-ment from cooling of the workstring. Close annular. Reverse circulate a minimum of 5



Sec. 3—

rmation

open hole annular volumes down casing annulus at a rate not to exceed 2 bpm. Do not exceed fracture pressure. Be prepared to divert DIF to catch tank. Reverse circulate until brine is reading less than 20 NTUs or until the irreducible minimum turbidity is attained. Stop pumping.

20. Take a 10 minute fluid loss rate. Record in bbl./hour. If fluid loss rate is more than 20 bbl./hour, consult with project engineer and prepare to pump a contingency fluid loss control pill.

21. Rig pump back up and test lines to 5000 psi. Set pop-off valve to 4000 psi.

22. Conduct a sand out rehearsal on the rig floor but do not PU to reversing position.

23. Open annular and PU to reversing position. Do not actuate reverse ball check.

3.12 Pickle Workstring1. Pickle work string with the following:

___ gallons Dope Buster ME+

___ gallons 15% FE Acid + __ gal. HAI-85M or other inhibitor as required.

2. Ensure that GP crossover tool is in reversing position

3. Displace the above pickling treatment to the within 2 barrel of the crossover tool with completion fluids at a rate of 2 bpm.

4. Reverse out with rig pumps at a rate of 2 bpm. Catch pickle returns in catch tank. Neutralize and check for sheen. Dispose of pickle returns as necessary.

5. Continue reverse circulating until completion brine is less than 20 NTUs or until the irre-ducible minimum turbidity is attained.

3.13 Circulation Testing1. Slack off cross-over tool to the weight down circulating position. Close annular. Perform

circulation rate test at rates of 0.5, 1, 1.5, 2, 2.5, and 3 bpm. Do not circulate above frac gradient. Record pump rates, return rates, and pressures after stabilization occurs. Be prepared to spot contingency fluid loss control pill if fluid loss rate does not meet expec-tations.

2. Open annular. Pick up cross-over tool to the reversing position. Do not actuate reverse ball check. Close annular. Perform circulation rate test at rates of 0.5, 1, 1.5, 2, 2.5, and 3 bpm. Record pump rates, return rates, and pressures after stabilization occurs.

3. When designing a horizontal gravel pack, the return rate is determined by the desired alpha wave height and sand concentration. The HzGPSim spreadsheet calculates the alpha wave height as a percentage of the openhole height. The user specifies a desired alpha wave height and a sand concentration, the spreadsheet then calculates the return rate needed to place that alpha wave height at the toe. Before pumping the gravel pack, fluid is circulated with the tool in the reverse and circulating positions. The pressure needed to overcome the friction below the packer is also exerted on the filter-cake. This pressure can be calculated for a given rate as follows:

Pressure in Circulate Position – Pressure in Reverse Position = Pressure Exerted on Fo


July 199


3.14 Pump Horizontal Gravel Pack1. Activate Halliburton data acquisition system.

2. Hold rig floor meeting to discuss the remaining steps of these procedures.

3. Conduct a sand-out/reverse out rehearsal on the rig floor including manipulation of all manifold valves before proceeding.

4. Perform circulating test with GP ports above the packer.

5. Move GP ports to weight-down circulate position.

6. Perform circulating test in circulate position.

7. Confirm or re-design the gravel pack.

8. Move GP ports above the packer to allow the spotting of sand in the workstring.

9. Begin metering re-sieved gravel pack sand at design concentration (typically 1 ppg).

10. Spot sand laden slurry to within 15 barrels above crossover tool at a rate of 6 bpm. Stop metering sand into brine 5 barrels before shut down. Shut down the pump.

11. Open annular. Slack off crossover tool to the weight down circulating position. Put 25,000 lb on packer. Close annular.

12. Resume metering sand at a concentration of __ ppg. Begin pumping slurry into open hole at a rate of __ bpm while taking full returns through squeeze manifold.

13. Make note of end of alpha wave/beginning of beta wave.

14. After beta wave has started, a decrease in return rate below minimum acceptable indi-cates the beginning of sand out. When this occurs, immediately go to quick flush and prepare to slow down pump rate.

15. Upon reaching sand out pressure, decrease pump rate while holding steady sand out pres-sure at surface. Maintain injection until pump rate falls below 0.25 bpm. Record time to bleed off to half of sand out pressure.

3.15 Reverse Out after GP1. Pressure up on annulus to 500 psi.

2. Strip through annular to activate reverse ball check and place tool in the reversing posi-tion. Line up to take returns to return tank and sand catch tank. Collect and measure sand volume reversed out. Bleed off work string through choke on squeeze manifold.

Caution—Pressure applied to annulus is being applied to the formation at the toe of theopen hole until the reverse ball check valve is activated, so move to this position quicklyafter pressure is applied.

3. Reverse out a minimum of 1 1/2 workstring volumes or until returns are clean at a rate of __ bpm with rig pump. Divert sand into sand catch tank and record sand volume reversed out.



Sec. 3—

shift

10 ss

-3 s to d be ores of

ove

NoGo’s

oes not

4. Reverse circulate the workstring with filtered gravel pack fluid until no trace of sand returns and NTU readings are less than 20 or until the irreducible minimum turbidity is attained.

3.16 Setting Plug, Closing Packer Sleeve, and Pulling out of the Hole1. Pick up cross over tool ½ stand above gravel pack packer to set isolation plug and

closing sleeve. Avoid swabbing.

2. Take a 10 minute fluid loss rate. Record in bbl./hour. If fluid loss rate is more thanbbl./hour, consult with project engineer and prepare to pump a contingency fluid locontrol pill. A viscous pill may be spotted using completion brine viscosified with 2ppb LIQUID-VIS EP. This viscous pill can be spotted inside of screen. If fluid losseformation are excessive, requiring a pill with bridging particles, the particles shoulsized to bridge on the pores of the screen and/or gravel pack rather than on the pthe formation.

3. Continue POOH. Rinse work string with fresh water after racking in derrick to remresidual sand. Rack wash pipe stands in derrick.

3.17 Acid Wash Open Hole1. Pick up wash cup assembly. Space out wash cup assembly so packer seal locator

on packer and the end of the cup assembly is above permanent plug.

•Bull Plug

•Lug shifter for closing fluid loss flapper(s)

•Cup packer

•Perforated Pup Joint

•Cup Packer

•Crossover

•Gauge Hanger

•Crossover

•Workstring

•Gauge Carrier

•Workstring

•Baffle Cups

•Workstring

•Shifter

•Extension Pump

•Packer Isolation Seals and Locator (Space out isolation seals so wash assembly dtag permanent plug.)


July 199


erify

ssure

rig

ve to

.

tion.

essi-

•Workstring

•OMNI Valve

•Workstring

•RD Valve

•RFC III Landing Nipple with RFC III Valve installed

•Workstring

2. Run assembly in hole until ___ft above packer.

3. Install RFC III injection valve nipple and injection valve to work string.

Note—Initial equipment check should have verified that surface TIW valve had ID largeenough for running slickline tools to retrieve and re-run injection valve.

4. Run RFC III assembly-in-hole one workstring stand. Stop and break circulation to vvalve operation and opening pressure.

5. Stop just before reaching gravel pack packer to conduct circulation test. Record preat rates of 1, 2, and 3 bpm.

6. Record slack off and pick up weights when cups are passing through the blank.

7. Continue in hole until isolation seals sting into packer.

8. Slack off 25000 lb on packer.

9. Rig up Halliburton lines and test to 7000 psi. Test pop-off valve to 6000 psi. Verifymanifold pop-off valve setting.

10. Close annular and use rig pump to pressure up on annulus to cycle the OMNI Valthe circulating position. Bleed off.

11. Circulate 100 bbl. weighted acid solution followed by completion brine to 5 barrelsabove the OMNI Valve at 6 bpm.

12. Rig up pump. Cycle OMNI Valve to the well test position. Bleed off. Open annular

13. Rig down Halliburton lines and rig up to top drive.

14. Raise cup assembly to straddle the two lowermost screen joints to allow fluid circulaDisplace acid to the bottom of the wash assembly at 1+ barrel per minute. Keep pump pressure < 100 psi over workstring friction pressure.

15. Lower the wash assembly to cover the first (toe) screen joint.

16. Inject ___ barrels of acid into the first screen joint.

Volume of spacer approximately 40-70 gal/ft of open hole.

Formulation: 6-15% HCl plus Corrosion inhibitor

As HCl reacts with filter cake and bridging particles, losses to formation may occur nectating higher pumping rates to ensure open hole is contacted by HCl.



Sec. 3—

17. PU wash assembly to 2nd screen joint and inject acid. Repeat for all screen joints except the topmost screen joint as this may disturb the gravel pack at this critical point. An equal amount of acid should be injected through each screen joint.

18. Monitor fluid loss rate while acid washing screen.

19. After washing the second to topmost screen joint, PU until wash assembly is in blank. Monitor fluid loss rate on the annulus. If fluid loss rate on annulus is acceptable, allow acid to soak for a period of 2 - 6 hours. Soak time will be determined by project engineer and is based on wash time.

20. After soak repeat steps 6 through 19 for second acid wash.

3.18 Pump Brine Flush1. Run wash assembly back to bottom.

2. Inject 5 barrels of completion brine into the lowermost screen joint. Do not exceed 3 bpm.

3. PU to the 2nd screen joint and inject 5 barrels of completion brine. Do not exceed 3 bpm.

4. Repeat for all screen joints except the topmost screen joint.

5. Monitor fluid loss rate while brine washing the screen excluding the lowermost joint and the uppermost joints of screen.

6. Pick up until wash cups are in blank pipe above screens to isolate well during soak period.

7. Allow the fluid to soak for six hours.

8. Continue POOH slowly to avoid swabbing in the well. Allow lug shifter to activate the fluid loss control device. Stop when circulating ports of wash assembly are above packer.

9. Circulate the well as necessary to balance and kill the well.

10. PU so wash assembly is one stand above packer. Verify fluid loss control device is acti-vated. Be prepared to spot contingency fluid loss control pill. Notify project engineer if fluid loss rate is unacceptable.

11. POOH

12. RIH with production tubing and production seals with stinger to break fluid loss control device.


August 1

Section

44. Horizontal Gravel Pack Procedure—Oil Base

This section has not been written.

997 Page 4-1 Sec. 4—Horizontal GP Proc.—Oil Base


Sec. 4—


Horizontal GP Proc.—Oil Base Page 4-2 July 1999

July 199

Section

55. Drill-In Fluids

uids n be

hout ate ance

differ-n effi-d long tion

repre-

thetic parated lcium ixture

l brine l brine

as per-

e

5.1 Available “Drill-In” Fluid SystemsThe ability to drill through the producing interval and leave a relatively undamaged but stable open hole is a key element in the open hole completion program. A number of “drill-in” flhave been developed by various service companies for this purpose. A “drill-in” fluid cadefined as a fluid that can be used to effectively drill through the producing interval witdamaging that formation. These systems are designed to provide the lowest filtration rpossible in order to minimize or prevent formation damage. A 150 psi minimum overbalis suggested.

From a drilling standpoint, the mud used to drill a greatly deviated section can make a ence in coming in under budget and safely with the objective reached. From a completiociency standpoint the mud used to drill the lateral section can greatly affect the short anterm productivity of the well. Therefore, when designing a horizontal sand control compleit is important that the local engineer communicate early on in the design process with sentatives from Baroid or other Drill-in fluid companies such as MI Drilling Fluids, TBCBrinadd, Scotoil and Tetra.

Three main systems are utilized as Drill-N fluids; (1) water based systems, (2) oil or synoil based systems and (3) mixed metal hydroxides. The water based systems can be seinto saturated salt solutions with sized salt particulate material and systems utilizing cacarbonate particulate material. Oil based or synthetic oil based systems can contain a mof calcium carbonate and barite, and may or may not be invert emulsions with an internaphase. The density of the oil based systems can be controlled by modifying the internaphase or the type and amount of solids in the mud.

Note—The barite portion of the weighting material is not soluble in acid. Products suchBASOLVENT would dissolve small amounts of this material but would be a very costly oation.

5.1.1 Sized Salt Systems

Pros

• Solubility of the bridging material (NaCl) in less than saturated water to prevent thdissolution of the bridging material (sized NaCl salt)

9 Page 5-1 Section 5—Drill-In Fluids


Section 5

mum

rilling

l will

hase

pres-

han

s

han

g

5.2

Cons

• Minimum density controlled by the need for a saturated salt base solution (the minimay be more than desired)

• Need to maintain saturated solution – some fine particles may be removed by the dsolids control system.

5.1.2 Calcium Carbonate Systems

Pros

• Minimum density is lower than that of a saturated salt solution. The bridging materianot be dissolved by the base fluid.

Cons

• Acid is required to dissolve the calcium carbonate bridging material.

5.1.3 Oil Based Mud SystemsPros

• Density can be tailored to specific well requirements by altering the internal brine por the type and amount of solids in the mud.

• Drilling performance is generally superior to water-based systems, especially in theence of water sensitive shales or in extended reach wells.

• The filter cake from OBM/SMB systems is generally thinner and lifts off more easily tfor water based systems.

Cons

• Hole displacement procedures are complicated due to chemical compatibility issuebetween two phases. May form sludgy emulsion.

• The filter cake from OBM/SMB systems is generally thinner and lifts off more easily tfor water based systems.

• Environmental/logistical problems related to dealing with contaminated brine cominback to surface.

A listing of the common companies and related drill-in fluids is listed in Table 5.1, Tableand Table 5.3.

—Drill-In Fluids Page 5-2 July 1999

July 199


Cy

e

.5

5

.7

.0

B

Tec

aCa nd carrhydprob

Typ

Table 5.1—Drill-In Fluids

ompany Trade Name Type SystemWeighting /

Bridging Material

Particle size

(microns)

DensitRang(ppg)

Baroid

SOLUDRIL-N™Saturated NaCl brine with a crosslinked poly-mer.

Sized Salt 10.4 – 14.5

BARADRIL-N™Sized Calcium Carbon-ate System Calcium Carbonatea 8.4 - 14

BRINEDRIL-N™ 11 – 16.

QUIKDRIL-N™Clay and Solids Free Polymer System

None 8.4 – 12

SHEARDRIL-N™Clay and Solids Free Modified Polymer Sys-tem

None 8.4 – 15

TBC rinadd

Thixsal Ultra™ System

Saturated NaCl brine with Xanthan Polymer and Starch. Stable up to 290°

Sized NaCl, 5-30 >10

Ultra-Carb™ Sys-tem

KCl, NaCl, CaCl2 brine with polymer and starch. Staple up to

Calcium Carbonatea 2-30 8.5-12.0

Ultra-PF™

Biopolymer system which is formulated usng Potassium For-mate Brine. Stable up to 350°F

Calcium Carbonatea 2-30 12.5-17

Hy Dens™Xanthan Polymer. Sta-ble up to 275°F

Calcium Carbonatea

Solids loading of <20 ppb

2-30 12.5-17

MI Flo-Pro™Xanthan Polymer, Starch Calcium Carbonatea

BakerPERFFLOW® Xanthan Polymer,

Starch Calcium Carbonatea <100

AQUA-DRIL®

Tetrahnologies

PAYZONE® Fluids

Breaker catalyst is in the filter cake. Activator for the breaker catalyst is in the gravel pack carrier fluid

8.4-20.5

PayZone DF-CC™ Calcium Carbonatea

PayZone DF-SS™ Sized Salt

lcium Carbonate weighting / bridging materials are normally used in horizontal gravel packs due to the ability of the saier fluid (clear brine) to dissolve the sized salt particles unless the carrier fluid is saturated with salt. The additional rostatic pressure due to the saturated carrier fluid could potentially frac the formation and thus could cause fluid loss lems.

ical solids loading for a water based system is 40 lb/bbl. Typical solids loading for an oil based mud is 180-190 lb/bbl.



Section 5

ns e itions

ns e itions

The websites for the companies in Table 5.1 are below:

• Baroid’s web site can be found at http://www.baroid.com/z_baroid.htm

• TBC-Brinadd’s web site can be found at http://www.tbc-brinadd.com/

• TETRA Technologies web site can be found at http://www.tetratec.com/

• MI Drilling Fluids web site can be found at http://www.midf.com/

5.2 Baroid DRIL-N FluidBaroid’s DRIL-N Family has seven specialized systems to address the unique conditioencountered in a wide range of drilling, completion and workover operations around thworld. Each system is designed to do a specific job of addressing a specific set of condand objectives.

Baroid’s DRIL-N Family has seven specialized systems to address the unique conditioencountered in a wide range of drilling, completion and workover operations around thworld. Each system is designed to do a specific job of addressing a specific set of condand objectives.

Table 5.2—Oil-Based Drill-in Fluids

Company

Trade Name Type SystemWeighting /

Bridging Material

Particle size

(microns)

Density Range (ppg)

Baroid COREDRIL-N™100% Oil/ Synthetic drilling fluids

Calcium CarbonateBarite

7.5 – 12.0

Baroid PETROFREE™MI Versaclean™

Versadril™Baker INTEQ

SYN-TEQ™

Table 5.3—Mixed Metal Hydroxide Fluids

Company Trade Name Type SystemWeighting /

Bridging Material

Particle size

(microns)

Density Range (ppg)

Baroid MAXDRIL-N™ Mixed Metal Silicate Calcium Carbonate 8.8 – 13.0IDF


July 199


-N

agent

istry

Table 5.4 rates DRIL-N fluids as good, better or best under various drilling situations.

5.2.1 Baroid’s SOLUDRIL-N™

SOLUDRIL- N fluids are sized salt systems designed for drilling, completion or workover operations in horizontal and vertical wells. SOLUDRIL-N fluids utilize BARAPLUG (sized salt) and a crosslinked polymer to provide superior rheological and filtration control.

Advantages

• Filter cake is easily removable with unsaturated sodium chloride brine.

• Excellent return permeability has been demonstrated in tests that prove SOLUDRILfluid is far superior to conventional water-based systems.

• Solids and fluids are prevented from entering production zone because the bridginghas correct particle size distribution to assure a thin, low permeability filter cake.

• Improved suspension under downhole conditions because advanced polymer chemprovides low viscosities at high shear.

• Provides thermally stable fluid up to 290° F with use of specialty products that allowcontrol of rheological properties at elevated temperatures.

Density Range

10.4 – 14.5 lb/gal

Temperature Range

Up to 290°F

5.2.2 Baroid’s BARADRIL-N™ The BARADRIL-N system provides acid soluble drilling, completion, and workover fluid compositions. The BARADRIL-N system is designed for non-damaging drilling when fluid loss and formation stability are of primary concern. Return permeabilities are excellent with the BARADRIL-N system and the filtercake is easily removed by treating with hydrochloric acid.

Advantages

• Disperses easily with minimal shear.

Table 5.4—DRIL-N Fluids versus Drilling Situations

SystemsReactive shales

Depleted Zones

Horizontal / High Angle

Drilling

Minimize Formation Damage

Cleanup

BARADRIL-N™ Better Best Better Best BetterCOREDRIL-N™ Best Best Better Best BetterMAXDRIL-N™ — Best Best Good GoodQUIKDRIL-N™ Better — Good Best BestSHEARDRIL-N™ Better — Good Best BestSOLUDRIL-N™ Best Best Better Best BestBRINEDRIL-N™ — — — — —



Section 5

rma-

agent

abili-

se wetta-

• Provides hole stability and effective seepage loss control while drilling permeable fotions.

• Can be weighted-up for pressure control.

• Acid soluble and non-damaging to producing reservoirs

• Solids and fluids are prevented from entering production zone because the bridginghas correct particle size distribution to assure a thin, low permeability filter cake.

Density Range

8.5 – 14.5 lb/gal

Temperature Range

Up to 300°F

5.2.3 Baroid’s BRINEDRIL-N™

A high-density, low-solids, non-damaging drill-in system

Advantages

• Solids-free fluid with bridging agents added as required.

• Easy to mix; weight can be added as sack or brine bulk.

• Additives exhibiting uniquely high low shear rate viscosities and shear thinning capties.

• Formation friendly with superior return permeability results.

Density Range

11.0 – 16.5 lb/gal

Temperature Range

Up to 300°F

5.2.4 Baroid’s COREDRIL-N™COREDRIL-N is an oil-drilling and coring fluid for maximum formation protection without altering native wettability. COREDRIL- N fluids are 100% oil/synthetic drilling fluids (diesel, mineral, ester or crude) that have been developed to control the formation damage that could be caused by conventional drilling operations. The COREDRIL-N system contains an optimum concentration of BARACARB designed to bridge rock pores, thus providing low filtration rates—minimizing fluid invasion into potential pay zones. COREDRIL-N fluids upassive emulsifiers that reduce the risk of creating emulsion blockage and preserve thebility characteristics of the reservoir rocks.

Advantages

• Is non-damaging to pay zones

• Allows for improved formation evaluation by unmasking reservoirs

• Can be formulated with good properties over a wide range of fluid densities


July 199


agent

• Temperature stable and resistant to solids and water contamination

• Can be used with a variety of base oils and synthetics

• Solids and fluids are prevented from entering production zone because the bridginghas correct particle size distribution to assure a thin, low permeability filter cake

• Does not contain strong emulsifiers

• Requires much lower concentrations of emulsifiers than conventional oil muds

• Exhibits excellent return permeabilities

Density Range

7.5 – 12.0 lb/gal

Temperature Range

Up to 300°F

5.2.5 Baroid’s QUIKDRIL-N™

QUIKDRIL-N fluids are designed as water-based, solids-free polymer drilling fluids. QUIKDRIL-N fluids are especially beneficial in slimhole drilling or coiled tubing operations when minimizing circulation pressure is critical.

Advantages

• First system specifically designed for coiled tubing and slimhole drilling

• Provides stable filtration control

• Provides superior return permeability results

• Lower pumping pressures

• Reduces hole washoutsE

• Easy borehole cleanup

• Minimizes circulating pressure losses

• Allows ease of weight up

• Provides ease in mixing

• Increases drilling rates

• Drill solids can be effectively removed if needed

Density Range

8.4 – 12.7 lb/gal

Temperature Range

Up to 300°F



Section 5

agent

ystem

5.2.6 Baroid’s SHEARDRIL-N™

SHEARDRIL-N fluids are designed as a solids-free modified polymer drilling fluid for drilling consolidated horizontal wellbores. SHEARDRIL-N fluids provide maximum penetra-tion rates while minimizing formation damage.

Advantages

• Provides stable filtration control

• Gives superior return permeability results

• Easy to clean up

• Has been used in limestone and tight consolidated sand formations

• Provides excellent hole cleaning and allows settling of solids at surface

• Minimizes circulating pressure losses

• Tolerates calcium or magnesium

• Drill solids can be effectively removed with flocculants if needed

Density Range

8.4 – 15.0 lb/gal

Temperature Range

Up to 300°F

5.2.7 Baroid’s MAXDRIL-N™

The MAXDRIL-N system is a mixed-metal silicate system (MMS) designed for drilling, milling, and completion operations. MAXDRIL-N fluids provide borehole stability and supe-rior hole cleaning for milling casing and drilling highly deviated/horizontal sections. This fluid is especially effective when drilling in unconsolidated, unstable, stressed or faulted formations. MAXDRIL-N fluids form a low permeability filtercake that restricts solids and fluid invasions into the formation, thus reducing damage to the formation.

Advantages

• Provides high yield point with relatively low funnel viscosity

• Has high, low-end rheological properties

• Provides superior shale stability to a mixed-metal hydroxide

• Solids and fluids are prevented from entering production zone because the bridginghas correct particle size distribution to assure a thin, low permeability filter cake

• Optimizes hole-cleaning capabilities

• Maintains filtration control in the presence of contaminants

• Has excellent suspension characteristics

• Requires no special or sophisticated rig equipment for mixing and maintaining the s

• Has few components and is simple to use


July 199


an up

Density Range

8.8 – 13.0 lb/gal

Temperature Range

Up to 300°F

5.3 Drill-In Fluid RecommendationsRecommended mud properties, which will help ensure minimal damage and proper cleof filter cake are listed in Table 5.5.

Table 5.5—Drill-In Fluid Mud Property Recommendation

Preferred Drill-in Fluid Calcium Carbonated Based System / Salt Based System / Oil Based Mud System

Recommended Drill-In Fluid Properties

Methylene Blue Test (MBT1) for Cation Exchange Capacity

<10

Particle Plugging Test (PPT2)<12 using a Particle Plugging Apparatus (PPA)

with grade 2 ceramic disks3 at temperatureParticle Plugging Test (PPT) Cake < 1/32 in.

Insoluble Solids or Drill Solids4—Total Concentration

<20 ppb

35 - 65° - fluid velocity in excess of 3 ft/s, with a YP/PV ratio greater than 1.Above 65° -- turbulent flow and pipe rotation are recommended to keep the hole clean.

OBM Drilling MudPV = 12 to 16 cp

YP = 14 – 18 lb/100 ft2

Water Based Drilling Mud

After Drilling OH section condition mud to PBM – lower YP to around 12 – 15 lb/100 ft2

Pipe Rotation 10 – 20 rpm

Pipe Reciprocation 10-20 ft strokes, with 1 – 2 strokes/min1Methylene Blue Test (MBT) measures the clay content expressed in ppb. Prefer to keep this value to less than 5 ppb.2Particle Plugging Test (PPT) using the PPA (Particle Plugging Apparatus) allows for filtration testing at temperature and high pressures. 3Ceramic Disks—Filtration tests on DRIL-N fluids are conducted using a ceramic disc that simulates as close as possible the pore size of the formation. These tests can be utilized in the field to determine proper application of the DRIL-N fluids system. Use these instead of filter paper for filtration testing. These disks are available in several sizes in order to better test fluids on a three dimensional material that is representative of the formation permeability. This test is usually done at bottom hole temperature and 500 psi for a period of 30 min. Spurt values of 0.5-4 ml and total volume of 8-20 are acceptable numbers. These change dependent on system design, formation permeability, pressure used, etc.The rheology of DRIL-N systems is designed to be low, but sufficient to provide the required hole cleaning.4Insoluble solids are measured using a retort. From here we utilize special testing to determine how much of these solids are bridging particles and how much are formation drilled solids. Prefer to keep the drill solids to less than 4-5%.After drilling open hole section with DRIL-N system change out to clean system with fine bridging particles, clean system with no bridging particles or to brine.



Section 5

the

by 7.32

5.4 Particulate SizingBridging off the production zone is a key to preventing formation damage. Bridging materials that are utilized in DRIL-N fluids include sized calcium carbonate an sized salt. The pore diameter of the formation must be known to effectively bridge. An industry rule of thumb for estimating an unknown pore diameter (microns) is to take the square root of the permeability in millidarcies. To effectively bridge off the production zone, 20-30% by weight of the bridging material should be one-third of the pore size in microns.

Depending upon the formation pore throat diameter and requirements to produce the filter cake particles back through the gravel pack screen, the median particle diameter can be altered by varying the grind size and changing out the shaker screen on the drilling circulation system on the rig.

5.5 Estimating / Measuring Pore Throat SizePore throat diameter can be determined by a number of mechanisms such as:

• mercury injection and capillary pressure relationships

• directly measured by a scanning electron microscope

• estimated via the Kozeny relationship between permeability and pore throat size orBlick and Civan relationship between permeability, porosity and pore throat size

5.5.1 Kozeny Relationship

where:µ = pore throat diameter (microns)k = permeability (millidarcies)

Example:

If the formation has a permeability of 300 md then the pore space can be approximatedtaking the square root of 300 mD (17.32 ) Therefore the pore throat is approximately 1microns.

5.5.2 Blick and Civan Relationship*

where:µ = pore throat diameter (microns)k = permeability millidarcies)φ = porosity (percent)

k=µ

)/32( φµ k•=


July 199


ice in ll be

the

oss

pa-hori-s are ery any -in ause bility e ilored ent. ore ree

intro-e fluid rines

tions. tem coun-

Once the pore throat diameter has been estimated then the median diameter (D50) of the bridging material is normally designed to be 1/3 the pore throat diameter.

*SPE-Reservoir Engineering August 1988, Porous-Media Momentum Equation for Highly Accelerated Flow, E.F. Blick and F. Civan.

5.6 Lessons Learned• Establish beforehand the disposal/environmental concerns associated with your cho

muds. Determine if the rig will be placed in a "Zero Discharge" state or if disposal wiallowed at your well site.

• Utilize a mud testing laboratory on location to give up-to-date mud properties.

• Catch samples of the used drill in fluid for dissolution/regain permeability testing withproposed clean up fluid.

• Change out wellbore fluid to clean drill in mud loaded with a "super fine" sized fluid lmaterial before coming out of the hole to pick up the completion assembly.

5.7 Competition

5.7.1 MI Drilling

FLO-PRO™ System

The MI Flo-Pro System is based on a purified xanthan polymer that is an M-I Drilling Fluids exclusive. This product yields higher low-shear-rate viscosities (LSRV’s) than any comrable product on the market today. This translates into far superior cuttings removal in zontal wells and the prevention of cuttings beds or “slides” in high-angle holes. Drill solidtotally suspended under static conditions. A Brookfield viscometer, with one rotation evthree minutes, is used to measure LSRV’s. M-I Drilling Fluids is currently the only compto use Brookfield viscometers on location to maintain LSRV’s of 60,000 cP + in the drillfluid system. This ensures that hole-cleaning properties are constantly maintained, becpolymer depletion is detected long before it will register on a standard viscometer. Flexiis inherent in the system because it can be run solids-free, or, when bridging agents arrequired, with sized salt particles or calcium carbonate. Flexible Flo-Pro systems are tato be compatible with the formations to be drilled and with every unique drilling environmSpecific lithology, hydrocarbon characteristics, pore pressure, temperatures, and wellbgeometry are all considered when a Flo-Pro recommendation is made. Flo-Pro Solids Fprevents formation damage because high LSRV’s impede flow into the formation while ducing no solids from the base system. Formation overbalance is minimized as the basweights 9.0 lb/gal (1.1 specific gravity), and density is increased by additions of clear bup to 12.5 lb/gal (1.5 specific gravity).

Flo-Pro Salt System uses sized salt particles as the bridging agent in high porosity formaThe saturated filtrate is highly inhibitive to formations containing reactive clays. This syscan be broken with hypochlorites when formations that react negatively with acid are entered.

Density Range

9.0 – 12.5 lb/gal



Section 5

main-gher

ids e envi-

rticle mer) oss , satu-

e ny but

1.1 – 1.5 Specific Gravity

Temperature Range

N/A

FLO-PRO Calcium Carbonate System

This system uses ground marble to prevent particle degradation during drilling, thereby taining particle size distribution. This system is entirely acid-soluble and can achieve hidensity ranges by weighting up with calcium carbonate.

Density Range

10.26 ppg -

1.23 –

5.7.2 Baker Hughes INTEQ

Baker Hughes INTEQ provides a complete line of drilling fluids technology to optimize drilling performance while minimizing damage to the producing formation. Advanced flusystems include the AQUA-DRILL glycol technology water base system, the SYN-TEQsynthetic base system, and PERFFLOW drill-in fluid. These systems are designed to bronmentally friendly without compromising drilling performance.

5.7.3 International Drilling Fluids

Mixed Metal Hydroxides

5.7.4 TBC BrinaddTBC Brinadd primarily offers a sized salt drill-in fluid and fluid loss system known as Thixsal-Plus which is composed of a saturated brine, a sized salt bridging / fluid loss pa(Brinewate-A) , a xanthan/starch viscosity / fluid loss polymer system (Thixsal-Plus Polyand a modified starch (FL-& Plus) which is used to supplement the rheology and fluid lcharacteristics of Thixsal-Plus Polymer. Thixsal-Plus can be mixed with saturated NaClrated NaBr and a mixture of the two brines.

5.7.5 Scotoil Services

Scotoil is TBC Brinadd’s agent in the North Sea, Middle East and West Africa. They arlocated in Aberdeen, Scotland. They provide sized salt products to any service compawill not supply directly to the Operators.

5.7.6 TETRA Technologies, Inc.

TETRA’s PayZone® Drill-In Fluids contain a patented/proprietary internal catalyst designed to enhance filter cake removal. When coupled with a properly designed PayZone® A.C.T. clean-up treatment, the formation damaging aspects of the filter cake is eliminated without undue risk to well hardware.


July 199


5.7.7 Baker’s PERFFLOWPERFFLOW is a water based calcium carbonate fluid. The fluid contains several proprietary polymers. The carbonate loading is usually 50 lb/bbl. The fluid loss package is formulated differently than other water-based carbonate systems. The vicious package consists of a non-ionic biopolymer which is similar in its rheological properties as xanthan gum, however, it is different in that it is compatible with divalent salts. The calcium carbonate particle size distri-bution for the fluid shows a bi-modal distribution that ranges from 1 to 200 microns. The parti-cles consist of marble as opposed to conventional limestone. The advantage of formulating the PERFFLOW fluid in the manner described above is that it enhances the return permeability. The fluid can bridge on formations that range in permeability from 1 md to over 10 darcies. For this particular fluid thickness of the filter cake is only 1 mm yet the fluid loss for the system is less than 4 cc.

PERFFLOW is available in several formulations. PERFFLOW 100 and PERFFLOW DIF. PERFFLOW 100 is the basic system that is mixed with calcium chloride up to a mud weight of 11.6 lb/gal; however, the pH of the fluid must be maintained below 9.0. The PERFFLOW DIF is typically designed to be used in divalent salt solutions. PERFFLOW can be mixed in several ways. The usual method is to add a single 55 lb bag of the PERFFLOW which contains the fluid loss package and polymers to a barrel of brine of the desired density. Another alter-native is to add the polymer package to a barrel of fluid and then add the fluid loss package to the barrel of viscous fluid.



Section 5



August 1

Section

66. Surface Equipment Cleanup Prior to Gravel Pack

6.1 Generic ProcedureAfter loading the mud from the surface drilling fluid system to the workboat, begin surface cleaning by performing the following steps:

1. Wash fluid handling system equipment and adjacent areas utilizing a combination of high volume wash to remove most solids followed by high-pressure steam wash to remove caked materials.

2. Start at the highest point of the fluid handling system (typically the flowline area) and wash down. This involves starting at the shaker area and ending at the mud pits, including the mud pumps and lines.

3. Ensure that all troughs, flowlines, trip tanks, pits, etc. are opened and thoroughly cleaned.

4. Ensure that all structural steel such as angle irons, ladders, equalization lines, etc. are thoroughly cleaned, paying special attention to areas not readily visible.

5. Also ensure that all walkways and gratings above the pit areas are cleaned of all mud residues.

6. After removing all visible mud solids and residues, open all suction and discharge lines of the circulating and transfer system to ensure that trapped solids are removed.

7. Surface sweep: Fill the slugging pit with fresh water and add 4 ppb Caustic Soda and 4 cans CONDET per 50 bbls of water.

8. Circulate the surface sweep throughout the entire fluid handling system ensuring that all pits, suction lines, transfer lines, equalization lines, mixing pumps, and mud pumps, trip tanks, displacement tanks, and the cement unit are cleaned adequately. Utilize all avail-able pumps and circulate to ensure at least 10 minutes of contact time for the entire system.

9. Individually close each valve in the circulating/mixing/transferring system against centrifugal pump pressure and monitor for leaks. Replace any valves that appear to leak.

997 Page 6-1 Section 6—Surface Equipment Cleanup


Section 6

10. Drain all tanks and lines and squeegee all residues to dump valves. Use a mop or diaphragm pump to drain all low spots in the pit system. Remove any remaining mois-ture by mopping. Any residual fluids could dilute the Drill-in Fluid which has been opti-mized for the particular hole conditions.

11. Break all circulating lines and open all valves to ensure that all water is drained from the mixing and transferring system. Blow the system dry with compressed air prior to closing lines and valves.

12. Close all dump valves and seal with silicone caulk. Replace any valves or seat which appear to be cut, damaged, or worn. All dump valves should be locked out to prevent inadvertent opening during the completion/workover process

13. Mud returns should be isolated to flow into the workboat for return credit. A mud sample should be collected for bioassay purposes before dumping any mud.

6.2 Lessons LearnedAfter cleaning tanks and lines all residual fluids should be removed as much as possible. Any residual fluids could lead to dilution of the drill-in fluid.

—Surface Equipment Cleanup Page 6-2 July 1999

August 1

Section

77. Changing from Mud to DIF before Drilling the Openhole Section

7.1 Displacement Options for Water Based Muds

7.1.1 Sized Salt Based System Clean Up (Baroid’s SOLUDRIL)

Displacing Casing from Water Base Mud to SOLUDRIL-N System

Circulate and condition drilling fluid to reduce viscosity and gel structure of fluid in prepara-tion for displacing to SOLUDRIL-N system. To enhance casing clean-up the running of casing scrapers is recommended to provide mechanical cleaning.

1. Calculate the volume of Spacer No. 1 casing covering 500 ft of the largest annulus using the following formulation:

___ bbls water containing 2-3 ppb N-VIS. (Viscosity should be greater than that of the drilling fluid). Barite can be used for density (Density greater than drilling fluid by no more than 0.5 ppg).

2. Determine the formulation of Spacer No. 2 casing as follows:

Formulation: 100 bbls water 1 drum BARA-KLEAN FL

3. Calculate the volume of Spacer No. 3 casing based on covering 500 ft of largest annulus usng the following formulation:

___ bbls brine saturated with respect to sodium chloride 2-3 ppb N-VIS

4. Pump spacers at rate of 2 to 6 bbl/min keeping spacers in turbulent flow to aid in better casing cleaning results. Follow last spacer with SOLUDRIL-N system. Commence drilling operations.

997 Page 7-1 Section 7—Changing from Mud to DIF


Section 7

7.1.2 Sized Carbonate Based System Clean Up – (Baroid’s BARADRIL)

Displacing Casing From Water Base Fluid To Baradril-N™ System

Circulate and condition drilling fluid to reduce viscosity and gel structure of fluid in prepara-tion for displacing to BARADRIL-N system. To enhance casing clean up, the running of casing scrapers is recommended to provide mechanical cleaning.

1. Calculate the volume of Spacer No. 1 casing based on covering 500 ft of largest annulus using the following formulation:

___ bbls water 2-3 ppb N-VIS (Viscosity should be greater than that of the drilling fluid). Barite can be used for density (Density greater than drilling fluid by no more than 0.5 ppg).

2. Determine the formulation of spacer casing as follows:

100 bbls water 1 drum BARA-KLEAN FL

3. Calculate the volume of spacer casing based on covering 500 ft of largest annulus using the following formulation:

___ bbls fresh water 2-3 ppb N-VIS

4. Pump spacers at rate of 2 to 6 bbl/min keeping spacers in turbulent flow to aid in better casing cleaning results. Follow last spacer with BARADRIL-N system. Commence drilling operations.

7.2 Displacement Options for Oil Based Muds—General Guidelines

7.2.1 Option 1—Preferred Option

1. Set casing before drilling into the horizontal section.

2. Drill out shoe.

3. Displace out OBM and replace with a pristine water-based drill in fluid using CLEAN-BORE process (four fluid stages--weighted spacer fluid w/surfactants, gelled pill, brine pill, and solvent pill) to effectively sweep the oil based mud out of the wellbore and condition the surfaces for the water-based pristine drill in fluid.

4. Drill the open hole section with a water-based drill in fluid with adequate density to control the well and adequate viscosity to support and transport cuttings out of the well-bore. The selected drill in fluid should have excellent regain permeability, a thin filter cake with a low lift off pressure.

—Changing from Mud to DIF Page 7-2 July 1999

July 199


7.2.2 Option 2—Less Preferred

1. Set casing before drilling into the horizontal section.

2. Drill out the shoe.

3. Displace out the OBM and replace with a pristine OBM drill-in fluid by using a gelled diesel pill (My-T-Oil) followed by a solvent pill to effectively sweep the drill cuttings laden oil based mud out of the wellbore and condition the surfaces for the pristine OBM drill in fluid.

4. Drill the horizontal section with the pristine OBM drill in fluid. The drill in fluid should have an adequate density to control the well and adequate viscosity to support and trans-port cuttings out of the wellbore. The OBM drill in fluid should provide a thin filter cake and low lift off pressure.

9 Page 7-3 Section 7—Changing from Mud to DIF


Section 7

This page was intentionally left blank

—Changing from Mud to DIF Page 7-4 July 1999

July 199

Section

88. Displacement of Drill-In Fluid from Openhole and Casing

d and lation d there-ce e

GY,

fluid

n are lable

8.1 IntroductionIt is recommended that the operator change out the openhole fluid, plus 200-500 ft up into the casing, to a clean drill-in fluid (DIF) before coming out of the hole to pick up the completion assembly. The new DIF can be a DIF fluid with specially sized particles, a solids-free DIF or a clean completion brine, depending upon the situation. After the open hole and the lower part of the casing has been displaced to the new DIF it is recommended that the fluids in the casing above that point be changed out to a clear completion fluid. This will allow the screens to be run into a clear completion fluid. The fluid can then equalize across the screen without plug-ging the screen prior to the screen being run into the new drill-in fluid in the open hole. Once the completion assembly is in the hole, the new drill-in fluid will be displaced to a completion fluid.

Note—Baker has proposed that upper wellbore be circulated to a clean completion fluithen displace the open hole to a completion fluid via reverse circulation. Reverse circuin this manner has several advantages. Returns to the surface are in the workstring anfore will have a higher velocity compared to the velocity in the annulus. This will enhansolids removal. Pipe dope contamination from the workstring to the wellbore will also bminimized.

The specific products utilized in the displacement stage will depend upon the companyoffering the services. Typical procedures are available using WELLFLOW TECHNOLOOSCA, TETRA, MI and BAROID products.

8.2 Displacement of Cased Hole or OH/Screen Annulus Prior to Gravel PackThe displacement procedure will change to a certain extent to take into account (1) thebeing displaced, (2) the type and amount of equipment available, etc.

The displacement procedures and design rules for a horizontal hole containing a screemore ambiguous than for non-sand controlled wells due to the multiple flow paths avai

9 Page 8-1 Section 8—Displacement of Drill-In Fluid


Section 8

wise

fluid

weep mud. that

alls of

teral ell-

lotted

to the fluids. The fluid can flow through the (1) open hole ID / screen OD annulus, (2) Screen ID / Washpipe OD annulus, (3) Screen ID / Base Pipe OD annulus, etc.

The displacement design will be effected by the following variables:

• Fluid density differences

• Hole eccentricity

• Annular velocities

• Yield point of the fluids

• Contact time

• Type fluids to be displaced

• Final fluid type

• BHP/Frac Gradient

• Workstring ID (friction pressures)

• Centralizer or no centralizer

8.3 Cased Hole Displacement – General GuidelinesCased hole displacement of drill-in fluid typically follows the guidelines listed below:

• For deviations above 60°, utilize a displacement pill formulated as discussed below.

• Displacement fluid should have the same density as the fluid to be displaced; otherthe displacing fluid will flow over or under the fluid to be displaced.

• The displacement fluid should have a yield point (YP) of 1.5 to 2.0 times that of the to be displaced.

• A casing sweep should be utilized to flush away the mud at high rates. The casing sis typically formulated using breakers or solvents to break down the rheology of the (This is not advisable in an open hole as it will also act to break down the filter cakeis used to contain fluid losses.)

• Casing scrapers or brushes are utilized to mechanically remove the mud from the wthe casing.

• Utilize high fluid rates

•An annular velocity of 130 ft/min is recommended in wells with a deviation less than 60°

•An annular velocity of 300 ft/min is recommended in wells with a deviation greater than 60°

• Design for a contact time of 5 – 10 min.

• Remember that a horizontal well is very seldom drilled at 90 degrees for the entire lalength if at all. Take this into consideration when pumping corrosive fluids into the wbore as any fluid can have the potential of laying in the low spots with the screen or sliner.

—Displacement of Drill-In Fluid Page 8-2 July 1999

July 199


brine loss

n

luid

e less

o be

in

grity.

to

mon

brine

detri-g

fluid.

roid’s

r

affect

• It is recommended that at least three (3) to five (5) open hole volumes of completion be pumped past the screen following the push pill. Returns should be monitored forrate and clean up. Check NTU's periodically.

• Filter completion fluid to 20 NTUs or until the irreducible minimum turbidity has beeattained before utilizing in screen washing.

8.4 Open Hole Displacements – General GuidelinesOpen hole displacement of drilling fluid typically follows the guidelines listed below:

• For deviations above 60°, the displacement fluid should have the same density as the fto be displaced; otherwise the displacing fluid will flow over or under the fluid to be displaced.

• One option is to run 3 stages prior to the completion fluid, one fluid at 1 ppg over thweight of the fluid being displaced, one fluid at neutral weight and one fluid at 1 ppgthan the weigh of the fluid being displaced.

• In the case of OBM, one of the stages would typically contain the base oil.

• The displacement fluid should have a yield point of 1.5 to 2.0 times that of the fluid tdisplaced.

• A progressively thinner fluid “train” or sequence of fluids is sometimes utilized to aiddisplacing the whole mud.

• High fluid displacement rates are helpful but should not compromise filter cake inte

• Stay below 6 ft/sec or 360 ft/min when circulating open hole with brine / sand slurryminimize erosion of the filter cake. (SPE 23733)

• A heel to toe displacement path followed by a toe to heel displacement path is compractice.

• It is typically recommended that at least three (3) open hole volumes of completion be pumped past the screen following the push pill(s).

A concern has been expressed about the potential for the base oil or diesel to effect a mental change in the OBM filter cake such that excessive fluid losses might occur durindisplacement or during the gravel packing operation if diesel were utilized as the carrier

8.5 Displacement Options for Water Based MudsThis Displacement/Clean-up procedure is a generalized recommendation based on Bacurrent technology with regards to DRIL-N™ fluids.

Before making formal recommendations to potential customers, please confirm with ouDRIL-N fluids technical personnel regarding spacer compatibility and cleanup solution compatibility. Various factors such as temperature and formation sensitivity can and do the type of recommendations made.



Section 8

t

equal

pen

ium. o-

ing

8.5.1 Sized Salt Based System Clean Up (Baroid’ SOLUDRIL)

Displacing to SOLUDRIL-N™ Clean Pill at TD

After reaching TD, circulate well clean, working pipe to aid in removal of cuttings bed. Do not circulate continuously in one spot as hole will wash out. Make wiper trip to bottom of casing and then back to bottom and circulate out and prepare to displace dirty SOLUDRIL-N system

Wellbore Spacers

1. Calculate the volume of Wellbore Spacer No. 1 based on covering 500 ft of largest annulus using the following formulation:

___ bbls brine saturated with respect to sodium chloride (Brine density should equal that of system in well) 2-3 ppb LIQUI-VIS EP (Viscosity should be 2-3 times low shear viscosity of SOLUDRIL-N system in wellbore)

2. Determine the volume of Wellbore Spacer No. 2 (SOLUDRIL-N Clean Pill) based on the following formulation:

Volume of system equal to hole volume, plus washout (10%) and 200 ft of coverage into casing

Note—Bridging particles in Clean Pill should only comprise BARAPLUG 20

3. Calculate the volume of Wellbore Spacer No.3 based on covering 500 ft of largesannulus using the following formulation:

___ bbls brine saturated with respect to sodium chloride (Brine densities should that of system in well) 2-3 ppb LIQUI-VIS EP (Viscosity should be 2-3 times lowshear viscosity of SOLUDRIL-N system in wellbore)

Wellbore Spacer Pumping Sequence

Spacers should be pumped at 2-3 bbl/min.

1. Pump Wellbore Spacer No. 1.

2. Pump Wellbore Spacer No. 2. (SOLUDRIL-N Clean Pill) (Clean Pill to cover the ohole section)

3. Pump Wellbore Spacer No. 3 followed by filtered brine saturated with respect to sodBrine should be filtered through Hallilburton/Baroid filtration unit with 2-micron abslute filter cartridges.

Displacing SOLUDRIL-N System from Casing

Pull drill string back into casing near top of SOLUDRIL-N Clean Pill. Prepare the followspacers to remove the dirty SOLUDRIL-N system and clean casing.


July 199


n plug-

rgest

sity 2-3

actor

open

Clean-up Spacers

1. Calculate the volume of Clean-up Spacer No. 1 based on covering 500 ft of largest annulus usng the following formulation:

___ bbls brine saturated with respect to sodium chloride (Brine density should equal that of system in well) 2-3 ppb LIQUI-VIS EP (Viscosity should be 2-3 times low shear viscosity of BARADRIL-N system in casing)

2. Determine the formulation of Clean-up Spacer No. 2 as follows:

100 bbls brine saturated with respect to sodium chloride 1 drum BARA-KLEAN FL

3. Calculate the volume of Clean-up Spacer No. 3 based on covering 500 ft using the following formulation

___ bbls filtered brine saturated with respect to sodium chloride (Brine density should equal that of system) 2-3 ppb LIQUI-VIS EP

4. Pump the above 3 clean-up spacers followed with clean filtered brine, (filtered to 2-microns) saturated with respect to sodium chloride, to fill casing section. Well is now ready to run gravel pack assembly through the filtered brine, saturated with respect to sodium chloride, in the casing and into the clean SOLUDRIL-N Clean Pill with BARA-PLUG bridging particles.

If difficulties are encountered when running the screen bottom hole assembly (BHA) in the openhole, there are three options available. First, attempt to circulate/wash the assembly past the obstruction or to desired well depth. Second, POOH with the assembly and make condi-tioning trip. The third and the last option which is NOT RECOMMENDED is attempt to rotate the BHA to get past the obstruction.

Note—Rotation of the screen BHA may damage the screen and/or result in severe screeging if centralizers are not used

Displacing Clean Pill And Filter Cake Removal

Cake removal spacers

1. Calculate the volume of Cake-Removal Spacer No. 1 based on covering 500 ft of laannulus using the following formulation:

___ bbls completion brine saturated with respect to sodium chloride (Brine denshould equal that of system in well) 2-3 ppb LIQUI-VIS EP (Viscosity should be times low shear viscosity of SOLUDRIL-N Clean Pill in wellbore)

2. Determine the volume of Cake-Removal Spacer No. 2 equal to hole volume plus fof 20% of hole volume using the following formulation:

Completion brine saturated with respect to sodium chloride 10-12 lb/bbl LithiumHypochlorite

3. Calculate the volume of Cake-Removal Spacer No. 3 equal to 4-5 times volume ofhole using the following formulation:

Completion brine, unsaturated with respect to sodium chloride



Section 8

reen.

roid

st

ppb N

en

4. Pump Cake-Removal Spacer No. 1 followed immediately by Cake-Removal Spacer No. 2 at a rate of 2-3 bbl/min. Cake Removal-Spacer No. 2 should be placed in open hole section and allowed to soak filter cake for a minimum period of 4-6 hours in order to oxidize the polymers and starch comprising the filter cake. After soaking, follow with Cake-Removal Spacer No. 3 containing unsaturated brine in order to dissolve salt bridging particle.

5. After circulating Cake-Removal Spacer No. 3, complete gravel packing operations.

Note—If fluid losses to formation are excessive, a Salt Pill may be spotted inside of sc

Brine used in displacement/clean-up process should be filtered through Halliburton/Bafilter unit with 2-micron absolute filter cartridges.

8.5.2 Sized Carbonate Based System Clean Up—(Baroid’s BARADRIL)

Displacing To Baradril-N Clean Pill At Td

After reaching TD, circulate well clean, working pipe to aid in removal of cuttings bed. Do not circulate continuously in one spot as hole will wash out. Make wiper trip to bottom of casing and then back to bottom and circulate out and prepare to displace dirty BARADRIL-N system

Wellbore Spacers

1. Calculate the volume of Wellbore Spacer No. 1 based on covering 500 ft of largest annulus using the following formulation:

___ bbls completion brine (Brine density should equal that of system in well) 2-3 ppb LIQUI-VIS EP (Viscosity should be 2-3 times low shear viscosity of BARADRIL-N system in wellbore)

2. Determine the formulation of Wellbore Spacer No. 2 (BARADRIL-N Clean Pill) as follows:

Volume of system equal hole volume, plus washout (10%) and 200 ft of coverage into casing

Note—Bridging particles in Clean Pill should only comprise BARACARB.

3. Determine the volume of Wellbore Spacer No. 3 based on covering 500 ft of largeannulus using the following formulation:

___ bbls completion brine (Brine density should equal that of system in well) 2-3LIQUI-VIS EP (Viscosity should be 2-3 times low shear viscosity of BARADRIL-system in wellbore)

Wellbore Spacer Pumping Sequence:

Spacers should be pumped at 2-3 bbl/min.

1. Pump Wellbore Spacer No. 1.

2. Pump Wellbore Spacer No. 2 (BARADRIL-N Clean Pill). Clean Pill to cover the ophole section.


July 199


3. Pump Wellbore Spacer No. 3 followed with clean filtered brine. Brine should be filtered through Baroid filter unit with 2 micron absolute filter cartridge.

Displacing Baradril-N System From Casing

Pull drill string back into casing near top of BARADRIL-N Clean Pill. Prepare the following spacers to remove the dirty BARADRIL-N system and clean casing.

Clean-up Spacers

1. Calculate the volume of Clean-up Spacer No. 1 based on covering 500 ft of largest annulus using the following formulation:

___ bbls completion brine (Brine density should equal that of system in well) 2-3 ppb LIQUI-VIS EP (Viscosity should be 2-3 times low shear viscosity of BARADRIL-N system in casing)

2. Determine the formulation of Clean-up Spacer No. 2 as follows:

100 bbls brine water 1 drum BARA-KLEAN FL

3. Calculate the volume of Clean-up Spacer No. 3 based on covering 500 ft using the following formulation:

___ bbls filtered completion brine (Brine density should equal that of system) 2-3 ppb LIQUI-VIS EP

4. Pump the above 3 clean-up spacers followed with clean filtered completion brine (filtered to 2 micron) to fill casing section. Well is now ready to run gravel pack assembly through the filtered brine in the casing and into the clean BARADRIL-N Clean Pill with BARACARB bridging particles.

If difficulties are encountered when running the screen bottom hole assembly (BHA) in the openhole, there are three options available. First, attempt to circulate/wash the assembly past the obstruction or to desired well depth. Second, POOH with the assembly and make condi-tioning trip. The third and the last option which is “NOT RECOMMENDED” is attempt to rotate the BHA to get past the obstruction. (Note: Rotation of the screen BHA may damage the screen and/or result in severe screen plugging if centralizers are not used). Additionally, keep gravel pack screen full of filtered brine to prevent intrusion of fluid into screen from annular sections of well.

Displacing Clean Pill And Filter Cake Removal

Cake Removal Spacers

1. Calculate the volume of Cake-Removal Spacer No. 1 based on covering 500 ft of largest annulus using the following formulation.

___ bbls completion brine (Brine density should equal that of system in well) 2-3 ppb LIQUI-VIS EP (Viscosity should be 2-3 times low shear viscosity of BARADRIL-N Clean Pill in wellbore)

2. Determine the volume of Cake-Removal Spacer No. 2 using the following formulation:

Volume of spacer approximately 40-70 gal/ft of open hole. Formulation: 6-15% HCl Corrosion inhibitor (Furnished by HCl supplier).



Section 8

mple- of

aroid

acer il

cities ized, le

ng

3. Pump Cake Removal Spacer No. 1 followed immediately by Cake Removal Spacer No. 2. Spacers should be pumped at a rate of 2-3 bbls per minute, however, as HCl reacts with filter cake and bridging particles, losses to formation may occur necessitating higher pumping rates to insure complete open hole is contacted by HCl.

4. After pumping HCl, circulate well and complete gravel packing operations.

Note—If fluid losses to formation are excessive, a viscous pill may be spotted using cotion brine viscosified with 2-3 ppb LIQUI-VIS EP. This viscous pill can be spotted insidescreen.

Brine used in displacement/clean-up process should be filtered through Halliburton / Bfilter unit with 2-micron absolute filter cartridges.

8.6 Displacement Options for Oil Based Muds—General Guidelines

8.6.1 Option 1—Preferred

1. Displace out OBM using CLEANBORE™ process (four fluid stages--weighted spfluid w/surfactants, gelled pill, brine pill, and solvent pill) to effectively sweep the obased mud out of the wellbore followed by a clean brine.

2. The drill string diameter should be sufficiently large so that reasonable annular veloin the range of 300 to 400 ft/min can be obtained. The drill string should be centralif possible. Reverse circulation with a mule shoe located at the toe of the open hosection is preferred.

3. Run in the hole with the gravel packing assembly and implement the gravel packiprocedure.

8.6.2 Option 2—Less Preferred

1. Once the open hole horizontal section is drilled, the well bore should be reverse circu-lated clean with a gelled diesel pill, diesel, and a gelled water-based pill with surfactant followed with the clean filtered brine.

2. The drill string should be sufficiently large so that a reasonable annular velocity can be obtained in the range of 300 to 400 ft/min. The drill string should be centralized, if possible. Reverse circulation with a mule shoe located at the toe of the open hole section is preferred.

3. Run in the hole with the gravel packing assembly and implement the gravel packing procedure.

8.6.3 Option 3—Least Preferred

1. Once the open hole horizontal section is drilled, run the gravel packing assembly into the open hole. The OBM is circulated out of the hole with two alternating stages of a high viscosity, gelled diesel pill followed by diesel.

2. Implement the gravel packing procedure using diesel as the carrier for the gravel pack.


July 199


ween

ed by

ar

8.7 Example Calculations

8.7.1 Well Data

Open Hole ID = 8.5 in.

Screen OD = 4.59 in.

Open Hole Length = 200 m

8.7.2 Annular Volumes

(8.52 – 4.592) x π/4 x 1/144 = 0.2792 ft2 or 0.2792 ft3/ft

0.2792 ft3/ft x 7.4805 gal/ft3 = 2.088 gal/ft

200 meters x 3.281 ft/m = 656.2 ft

656.2 ft x 2.088 gal/ft = 1370.14 gallons or 32.62 bbls approximately annular capacity bet200 meters of screen and open hole.

8.7.3 Circulation Rates

Assuming that we will need a minimum rate of 300 ft/min we can calculate the rate needmultiplying the annular area by the velocity:

0.2792 ft2 x 300 ft/min = 83.76 ft3/min

83.76 ft3/min x 7.4805 gal/ft3 = 626.57 gal/min or 14.9 bbls/min.

8.7.4 Contact Time/Volume Required

We can easily design for a contact time of 5 minutes with the relevant Rates and annulcapacity as follows:

Required rate x contact time = minimum required volume

For example:

8.5 inch OH, 4.59 inch OD screen, 300 ft/min required velocity

14.9 bbls/min x 5 minutes = 74.5 bbls

Table 8.1—Annular Volumes (200 meters OH)

Open Hole ID (in.)

Screen OD (in.)Annular Volume

Factor (ft3/ft)Volume

(gal/bbls)

8.5 4.59 0.2792 1370 / 32.67 4.59 0.1523 748 / 17.86 4.59 0.0814 400 / 9.5



Section 8

er of

8.8 General Guidelines

8.9 Lessons Learned• Perform laboratory experiments to select the proper clean up fluids. Optimum numb

soaks and soak times should be determined through laboratory experimentation.

Table 8.2—Displacement Rates for Annulus

Open Hole ID (in.)

Screen OD (in.)

Annular Area (ft2)

Velocity(ft/min)

Rate(bbls/min)

Min. Req. Vol.

(bbls)

8.5 4.59 0.2792 300 14.9 74.54.59 0.2792 130 6.5 32.5

7 4.59 0.1523 300 8.1 40.54.59 0.1523 130 3.5 17.5

6 4.59 0.0814 300 4.3 21.54.59 0.0814 130 1.9 9.5

Table 8.3—Volume of Each Stage*

Open Hole ID(in.)

Annular Volume(bbls)

Minimum Required Volume

(bbls)

Ratio of MinimumVolume per Stage vs.

Annular Volume

8.56 32.6 74.5 2.37 17.8 40.5 2.36 9.5 21.5 2.3

*>60° Deviation, 200 m OH, 4.59-in. OD Screen

Table 8.4—General Guidelines

Minimum required velocity to clean OH in horizontal section (ft/sec)? 250

Displacement stages to cover at least xx (ft) 300

Number of OH Volumes for Displacement? 3

Preferred Cleanup fluid for Calcium Carbonate Based System xx% HCl, Sulphamic Acid, etc.

Preferred Cleanup fluid for Salt Based System (depends on temperature)

xx% HCl, MSA Acid, < Saturated Brine, Enzymes, Oxidizers, Hypochlorites, Sodium Perborate, etc.

Preferred Cleanup fluid for OBM Base Oil + Surfactant Sweep + Mutual Sol-vents?, CLEANBORE, etc.


July 199


drill

sses. ment

ion in a h pill

open

is s

• Double check the laboratory experiments on actual drill in fluid from the well. This isimportant because the drilling of the lateral section has introduced drill solids into thein fluid that can greatly affect the outcome of the repeated testing.

• Monitor pump in rates and return rates carefully while spotting soaks and note any loThis aids in determination of acid placement over the interval and could modify treatdesign and future placement techniques.

• Utilize a density neutral push pill for displacement of drill in fluids from the lateral sectand the annulus. If you really want to get creative, use 3 different density push pillstrain: one at 1 ppg light; one density neutral and one at 1 ppg heavy. Follow the puswith completion brine mixed at density consistent with well control criteria.

• Use the Halliburton’s FORCE4 spreadsheet to calculate minimum velocity to clean hole horizontal section.

• Preferred method of clean up for BARADRIL-N system (calcium carbonate system)with the use of acid. Typically HCl at various concentrations, however, formic acid ibeing used as well as other chemicals and even simply by producing back the well.

• For SBM or OBM clean up this is mostly accomplished through flow back.

• Velocity to clean open hole is based on wellbore configuration and calculated usingBaroid programs. This varies dependent on well geometry and fluid being used.



Section 8



July 199

Section

99. Gravel Pack Tool Assembly

n the

tting grav-

tant

used.

rvice all is

oice -

9.1 Tool Systems and General GuidelinesThe horizontal gravel pack assembly is in many ways similar to a standard Halliburton gravel pack assembly. The following drawings are currently available for reference. Additional drawings may become available so check the ZZ Drawing listing on HALWorld.

• 9 5/8 x 5.00 in. (8.5 in. open hole) – 12ZZ1830

• Color Laminated Multi-view drawing CNO3891

9.1.1 General Best Practice Guidelines

1. Inspect, measure OD & ID, verify all equipment including rental pipe and handlingequipment are correct and on-hand prior to running.

2. Verify ID/OD relationship with casing ID and openhole ID to ensure compatibility.Check service tools and washpipe connections to be sure they are all smaller thasmallest restrictions.

3. Lightly dope only the connection pin ends with a 2-inch paint brush when runningcompletion assembly, workstring, and production tubing.

4. Washpipe OD to screen ID should equal a 0.8 ratio.

5. Ensure all workstring crossovers have proper bevels that will allow the packer seball to pass through without hanging-up. Allow ball 5 minutes per thousand feet to itate to the ball seat for a brass or steel ball

6. Use a double valve side port down jet shoe that is manufactured out of acid resismaterial.

7. Drift all screen and blank. Verify screen gauge with feeler gauge if PLP or ELP is

8. Use swab prevention crippled ball check or activated ball check on gravel pack setool to prevent formation swabbing during tool movement. Check to be sure the bin the tool.

9. Do not rotate while placing the gravel pack assembly on depth except as a last cheffort to get past a “tight spot”. Rotate very slowly while pushing or pulling simultaneously.

9 Page 9-1 Section 9—Gravel Pack Tool Assembly


Section 9

he . .

plug

mp

ula-

upon

the aking ing or

bly.

this

rface

10. Run production seals across flow sub and/or closing sleeve to ensure isolation.

11. Space out workstring to provide for tubing movements during clean up phase.

12. When picking up screen and blank assembly have kill-sub available for make-up in the event the well “kicks.”

13. While running wash pipe into the screen, have three-way crossover available. In tevent the well “kicks,” make-up crossover and run assembly into hole on drill pipeUnder extreme conditions washpipe should be allowed to drop inside of assembly

14. Ensure proper space-out of concentric string between packer and lower washpipeassembly. DO NOT ACTIVATE WASHPIPE PLUG!

15. With packer assembly made-up, run in hole on one workstring stand and verify puthrough capability.

16. Apply light coat of spray on grease to make up sub to reduce galling possibility.

17. Run assembly at 1 1/2 min per 3 joint stand including make-up time.

18. Pick up off slips and set slips smoothly.

19. Prior to entering open hole obtain the following: pickup and slack off weights, cirction pressure and torque.

20. Extreme caution and attention should be placed upon viewing the weight indicatorentering the open hole section.

21. In the event the assembly sits down in the openhole, the first option is to pick up assembly and re-attempt downward movement. Second option would include brecirculation while attempting downward movement. Third option would include addtorque to the above options. Forth option is to either pull assembly out of the holeleave in place.

22. If the assembly becomes stuck and the decision is to pull, work pipe-using option 2 and 3 noted in step 21 while not exceeding 80% of weakest point in bottom hole assem

23. Tag bottom. Pick up and verify bottom.

24. After tagging bottom, raise assembly to pick-up weight. Space out workstring frompoint.

25. Space out with full joint across BOP stack. Allow adequate spacing for ease of surig-up and workstring movement to accommodate tool positions.

Warning—If screen run has to be aborted, DO NOT RACK BACK SCREEN JOINTS IN DERRICK. LAY ALL SCREEN JOINTS DOWN. Racked screen is dangerous and may break due to the additional weight of the prepack material and wellbore fluid.

9.1.2 Well Control Situations

1. Should well "kick" while picking up screen and float assembly, install kill sub and attempt to control well.

—Gravel Pack Tool Assembly Page 9-2 July 1999

July 199


2. Should well "kick" while running wash pipe into the screen, attempt to connect three-way crossover and run assembly into hole with drill pipe. Under extreme condi-tions washpipe should be allowed to drop inside of assembly.

3. Attach kill sub to where applicable and attempt to control well.

Packer Ass’y

Flush Joint Wash Pipe

Pre-packed Screen Joint

TattleTale Screen BHA

Packer Csg Ext Csg ExtClosingSleeve

Make-upSub

Centralizer

FemaleRatch-Latchabove PlugRunning Tool Upper

SealBore

Centralizer CoarsePre-packedScreen

LowerSealBorew/ ParkedPlug

DoubleValveWashShoe

ServiceTool w/Pkr SettingTool

Wash Cup Ass’y

Opposed Swab Cups

X-O



Section 9

9.2 Typical Sales Equipment

9.2.1 VTA Versa-Trieve™ PackerThe VTA AGP and VBA packers are recommended for horizontal completions (1) The packers have the acme top sub which allows the hang load to be transmitted directly from the acme head to the service tool locator. When the load is not excessive the packer can be run on the lugs of the service tool, which transfers load to the scoop and guide of the packer. (2) The packers are retrieved with a VRA retrieving tool, this assembly has a high tensile rating. The packer designs with a clutched top sub, provides the ability to transmit high torque loads through the packer.

9.2.2 Closing Sleeve Assembly

The MCS closing sleeve is composed of a ported housing with fluted guide and internal sleeve for gravel pack port isolation. The standard assemblies also include a seal bore that is attached below the ported housing and a lower connector that has a casing thread box looking down. The upper casing extension and lower casing extensions are not included due to the variation in these components from job to job.

During the process of running the completion, circulation can be achieved by pumping completion fluid through various paths in the MPT service seal unit, down the washpipe, out the float shoe, and around the packer and up the tubing-casing annulus. After the packer is set, the open closing sleeve is the point where circulating flow exits the workstring (forward circu-lating) or returns are taken (reverse circulating) from the screen-open hole annulus. The process of dropping the setting ball and the packer setting sequence changes the flow path in the MPT from a washdown tool to the normal gravel pack flow paths. After the gravel pack

Wash Down Position

New Weight Down Circulating Position

Reverse Position

Plug Parked Position

Packer Ass’y Pre-packed Screen JointTattleTale Screen BHA w/

Parked Plug

UpperSealBore

LowerSealBore

Plugpermanentlyset in upperseal bore


July 199


rts) of to the hole ain-pace, sing

leeve se d

er also dvert-

d until ulder inner

tool to ow nsion

y

sover nd out

range ceed

. The fluid

es a pper

has been completed, upward movement of the closing sleeve shifting tool will close the MCS Closing Sleeve.

During the gravel packing operations, the lower seals of the MPT service seal unit are inside the lower honed seal bore. The sand slurry exits the lower side ports (the “crossover” pothe MPT Service Seal Unit and flows out through the ports in the MCS Closing Sleeve inscreen/casing annulus below the packer, which leads to and becomes the screen-openannulus. As the MPT is moved to the lower and upper circulating positions, seals are mtained in the lower honed seal bore. Slurry is still allowed to travel through the annular screated between the OD of the MPT and the ID of the upper extension of the MCS CloSleeve Assembly.

Specific Sleeve Operation

The shifting tool installed in the washpipe, below the service seal unit, locates the inner sof the closing sleeve and pulls it up as the service seal unit is withdrawn. A fluted releashoulder in the top of the closing sleeve housing forces the positioning tool to retract anrelease from the inner sleeve when it’s in the closed position. The fluted release shouldprovides an important tool deflector to prevent the closing sleeve from being opened inaently by seals and wireline tools passing through the ID of the tool.

If it becomes necessary to reopen the closing sleeve, the positioning tool can be lowereit locates the inner sleeve and moves it down to the open position. A lower release shoin the housing forces the fingers or keys of the positioning tool to retract and release thesleeve.

9.2.3 Upper Extension

The upper casing extension which is designed to be long enough to allow the crossoverbe moved from the “squeeze” position to the “circulating” position while maintaining a flpath from the crossover port on the service tool to the closing sleeve port. The Upper Exteis typically 6 ft long. Other lengths may be required for closely spaced zones or in highlcompetitive bid situations.

9.2.4 Seal Bore

The seal bore below the closing sleeve and the seals on the service tool below the crosport are used to direct the fluids exiting the crossover port through the closing sleeve ainto the screen-open hole annulus.

9.2.5 Lower Casing ExtensionThe lower casing extension is utilized to house the service seal assembly throughout itsof motion. Typical length is 20 ft. The Collapse pressure rating of this component must exthe pump pressure that may exist as a result of a rapid screenout.

No-Flow Extension

An extension of the same size as the blank pipe may be run above the Flapper housingpipe ID provides a sealing surface for the wash cup packers thereby isolating downwardmovement during flapper closure. Isolating hydrostatic pressure above the cups providstatic fluid environment for flapper closure. The longer extension aids in protecting the fla



Section 9

and preventing premature fracturing of the flapper by the water hammer effect induced by slam closure.

9.2.6 Mechanical Fluid Loss Device—Ceramic Flapper

A fluid loss device is utilized to prevent fluid loss after filter cake clean-up. Both single and redundant ceramic flappers have successfully been utilized. Each ceramic flapper is held in the open position by an internal sleeve. The sleeve is shifted upward by a shifting tool that is run below the lower cup packer on the cup wash assembly. Once shifted, the flapper closes, isolating the hydrostatic pressure above by stopping fluid loss to the formation. The ceramic flappers may be opened by breaking the flapper with a special wireline blind box and jars, an explosive charge deployed on wireline or tubing, an elongated production tube or the flapper can be left in place and be allowed to flow into the open position.

Sometimes a flapper valve cannot be run because the ID of the flapper assembly is smaller than the screen base pipe. If the flapper restricts the ID, the washing cups used to do a contin-gency wash treatment of the filter cake will be too large to pass through the flapper or too small to seal on the ID of the screen base pipe.

9.2.7 Make Up Sub

A makeup sub speeds makeup of the packer assembly to the blank pipe and internal washpipe. When a Make-Up Sub is used, the packer assembly does not have to be rotated in the derrick to connect the blank pipe to the packer assembly. The makeup sub has connecting ends that are clutched so torque capability is maintained.

9.2.8 Blank Pipe

The length of blank pipe required for a horizontal well is not as long as the length in an equiv-alent vertical well. This is due to the fact that the blank pipe length in a horizontal well is not designed for gravity settling. Settling that does occur will be to the low side of the hole, as opposed to the vertical well requirement of providing a sand reservoir above the screen at the end of the gravel pack treatment.

The amount of blank pipe for a horizontal is determined by (1) the desired hole angle to set the gravel pack packer at (2) the distance between baffle cups run on the washpipe. Note: Keeping a baffle cup inside the blank pipe during washing will aid in preventing fluid loss.

A minimum of 30 ft of Blank Pipe or whatever it takes to contain the entire wash-cup assembly if it is planned to perform a post gravel pack wash, should be used.

9.2.9 Production Screen

Screens

This section has not been completed. Additional information that needs to be in this section is as follows:

• Brief synopsis on screen testing can be found in SPE 50146.

• Screen Erosion testing

• Screen Plugging


July 199


nagers

ire ution in ened sflow

epack s of ation only

uter wraps. ter uter

fiber iber out

for the esin-

it at a deep-

there ed. lly en for with

• What type of screens have been used where? (North Sea, Gulf Coast, Technical maand the FBM’s to collect the data.)

• Acidizing and Screens

• Competitor Screens

The production screen in a horizontal gravel pack is typically a prepacked screen or a wmesh (PoroPlusTM) screen to provide an additional filtration mechanism for the formationsand in the event that we do not obtain a 100% annular pack. This is a necessary precahorizontal wells because there is a significant risk that at least some portion of the screinterval will be entirely packed, and even if areas are initially packed, settling and/or croscould sufficiently displace the pack to expose bare screen

Note—PoroPlus™ is a trademark of Mark IV Industries, Inc.

In most cases, Enhanced Low Profile Prepack (ELP) Screen or Premium Low Profile Prscreen is the “base case” choice for horizontal wells. The main concerns for these typescreen are that the wire wrap is not sufficiently damage tolerant, and that the depth filtrmedia enclosed in the screen is more subject to plugging than screen types which use surface filtration.

ELP has a 0.052” inner wire wrap with 0.062” round ribs with a standard 0.090” x 0.090” owire wrap. It has a 1/8” thickness of resin-coated sand between the inner and outer wire PLP has a 0.090” inner wire wrap with 0.125” ribs with the standard 0.090” x 0.090” ouwire wrap. PLP has a 3/8” – ½” thickness of resin-coated sand between the inner and owire wraps. The PLP can be tested for concentricity and for full pack tightness (with theoptic device) while the ELP can only be tested for pack integrity using a light test. The foptic device checks for light against a black background. The ELP pack does not blocksufficient light whereas the PLP with the thicker pack does thus allowing the ELP to bechecked using the fiber optic device.

Note—The largest grain size used in the ELP is 16/30, due to the small space available sand and the requirement for minimum layers of sand. PLP can be packed with 12/20 rcoated sand.

In conditions where a premium screen is required due to the excessive cost of replacinglater date a PLP screen is recommended. This would include horizontal applications andwater applications.

Current recommendations for Open Hole Non-GP completions are to use Enhanced orPremium Low Profile Prepack Screen when the well is limited to medium radius, where are no compaction and collapse concerns, and where plugging from fines is not expectOtherwise the recommendation is to use PoroPlus screens. An ELP or a PLP is normarecommended for horizontal gravel pack completions, but PoroPlus is often selected evgravel packed wells because of its higher flow capacity and damage tolerance, coupledits modest additional cost over PLP.

Sizing the screen openings/Prepack Sand for Horizontal Completions

This will be covered in other documents on screen design and selection.



Section 9

ouge

re

ming

over d to

t 713-

9.2.10 Upper Seal Bore Receptacle

An upper seal bore receptacle is made-up above the sacrificial screen. The seal bore receptacle provides a profile for latching the washpipe isolation plug after gravel packing. With the washpipe deployed plug installed, both the sacrificial screen and shoe are isolated.

9.2.11 Sacrificial Screen

The sacrificial screen is used to protect the main production screen from the erosive effects of high and sustained circulation combined with any fines that might be picked up in the flow stream during circulation before gravel packing or circulation during the alpha wave. The sacrificial screen is typically a full joint of screen and is recommended to be more coarse (larger openings or larger gravel or proppant) than the main screen.

The circulation path is down the annulus, through the gravel pack service tool annular by-pass, down the washpipe, through the sacrificial screen, up the screen/openhole annulus, through the gravel pack ports, up the gravel pack service tool, and through the drill pipe to the surface.

9.2.12 CentralizersSeveral types of centralizers are available. Centralizers for vertical or moderately deviated cased hole gravel packs are usually half moon metal plates or metal blades welded to the base pipe and sized for the casing ID. Slip on and bow spring centralizers are also available. Bow spring centralizers have been used in vertical openhole gravel packs and through tubing gravel pack applications. Bow spring centralizers are not recommended for horizontal openhole applications due to the weight of the screen assembly causing the low side bows to collapse.

A solid spiral design centralizer is recommended for openhole screens. Normally two are run per screen joint. The centralizers are slid over the base pipe and are free to rotate. They are held in place by stop rings attached on either side. The spiral design offers several benefits over other designs:

• Centralizer rotation capability aids in dissipating torque build up during running.

• The spiral design provides increased surface contact with the formation and will not gthe formation like a bladed design.

• The spiral design aids in creating turbulent flow that aids in the removable of wellbodebris during cleanup operations.

• The width of the spiral blades reduces the flow area thus increasing fluid velocity.

• During screen running, the centralizers prevent the low side of the screen from becoimpregnated with low side cuttings.

• Centralization aids in 360-degree pack placement.

• Centralizers may be manufactured out of zinc that should provide cathodic protectionthe life of the well. Note: When performing an openhole gravel pack and HCI is usedissolve the filter cake after gravel packing, steel centralizers are recommended.

Several suppliers for these centralizers would include Turbeco Inc. in Houston, Texas a466-0072 (Spir-O-Lizer™) and Ray Oil Tools.


July 199


Circulation rates must be much higher to obtain a clean hole when centralizers are not used. Increasing the pump rate to maximize hole-cleaning efficiency will raise the bottom hole treating pressure closing the spread between the bottom hole treating pressure and Frac pres-sure.

Halliburton recommends that screens in openhole sand control completions are centralized. The centralizer improves the wellbore clean up by taking the screen up off the bottom and allowing a better path for fluid flow/debris removal during clean up operations. Several types of centralizers are available.

9.2.13 Lower Seal BoreThe lower seal bore is utilized to direct flow out through the wash shoe while running in the hole. The fluid flow path when running in the hole is down through the workstring/service tool/washpipe and out the shoe.

9.2.14 Washpipe Deployed Plug for Upper Seal Bore

The washpipe-deployed plug will be used to permanently isolate the sacrificial screen and shoe after the gravel pack. When the gravel pack is complete it is set in the upper seal bore (above the Sacrificial Screen) by a straight pull. It is locked in place by internal slips. The running tool is released by tension. During initial screen running operations, the plug is placed into a lower sub assembly with a latch looking upward. Once the screen is in the well, the washpipe is run with a mating ratch-latch on bottom and is stabbed and latched into the plug assembly.

9.2.15 Side Port Down Jet Float Shoe

The Side Port Down Jet Shoe is a double poppet type. The shoe, attached to the very end of the screen assembly, will allow circulation down the washpipe and out the shoe when running in the hole. Once on bottom, it will allow circulating and conditioning of the screen-open hole annulus. After packer setting the shoe will continue to provide a circulation path. The fluid pumped through the wash shoe will return up the screen / open hole annulus and through the closing sleeve. The Side Port Down Jet Shoe should be constructed of acid compatible mate-rial.

9.3 Service Tools

9.3.1 MPW Gravel Pack Service Tool with Isolation Sleeve, Tapered Ball Seat, and Proppant Containment System

The Weight Down / Wash Down MPW service tool is the base service tool for the horizontal gravel pack tool assembly. This tool is capable of providing a weight down circulating position during gravel packing and washing capabilities through the shoe when running in the well. The tool consists of a hydraulic packer setting portion on top with a C-ring Isolation Sleeve. The basic service tool has a threaded locator for heavy hang loads associated with long screen sections. Upper and lower seal units are provided to seal in the packer bore with the crossover ports between the two sets of seals. A tapered seat in the crossover captures the setting ball and provides a means to re-direct flow for gravel packing operations. An optional yet recom-mended packer test / pressure maintenance assembly can be run to maintain pressure on the



Section 9

lost dled in bly that

l seat

ow the g stuck packer

holds sion f shear

wellbore during packer setting operations. This assembly incorporates the actuated reverse ball seat that is also a required feature of the assembly.

9.3.2 C-Ring Isolation Sleeve in MPW Service Tool

The MPW service tool contains a setting port isolation sleeve with an expendable C-ring seat in the upper end of the tool. This isolation sleeve prevents any pressure and solids from entering the hydraulic setting ports when circulating fluids down the workstring. Once the BHA is on bottom, a ball is dropped and allowed to migrate down to the isolation sleeve and seat on the rubber coated ends of the C-ring isolation seat. Pressure will move the sleeve down, opening ports to allow pressure to the setting piston. A second shear will allow the C-ring ball seat to move out into a recess allowing the setting ball to pass through the C-ring seat.

The ball will then drop through the sleeve and onto the Tapered Ball Seat. The Tapered Ball Seat has a shallow angled taper that will trap the setting ball. Pressure on the workstring will set the packer, release the running lugs of the service tool from the packer and shift the ball seat below the crossover ports (if the tool has the packer setting-circulating assembly).

The proppant containment system can be added to the MPW crossover to will prevent any proppant from getting above the crossover tool. The proppant containment system guards against the tool getting stuck if the production screen cuts out during the gravel pack treat-ment. The screen placed in the lower end of the service tool stops Sand or proppant that is flowing up the washpipe. A precautionary note is that the washpipe and fluids being circulated need to be clean to use the proppant containment system. Dirty fluids will plug the screen and prevent circulation.

Note—Once the ball goes on seat, the formation hydrostatic pressure is isolated. Fluidmust be manageable before dropping the ball. Packer setting and testing should be hanan expedient manner to minimize time. Isolation of the fluid hydrostatic pressure on theformation can lead to hole collapse! There is a packer test/ pressure maintenance assemcan be used to minimize this problem.

9.3.3 Tapered Ball SeatThe Tapered Ball Seat will trap the setting ball. The ball will also act as a plug for gravepacking. In the event the C-Ring sleeves expend early, the ball will seat on the taperedand pressure can be reapplied to finish packer setting.

9.3.4 Proppant Containment System

The proppant containment system is housed inside the gravel pack service tool just belgravel pack crossover. The proppant containment system guards against the tool gettinby preventing sand in the event the screen is damaged or cut out from getting above theon the annulus side during the gravel placement.

9.3.5 Actuated Ball Check The actuated ball check assembly is run on the bottom of the gravel pack service tool. Itthe reverse ball off seat until it is mechanically activated by upward tension. Upward tenapplied against an outer ring when engaging the lower packer seal bore will shear a set o


July 199


le llow pse. dro-rovides tion.

pack wn pen rior to

un on e float

d above eeve is hout leased string nt to ied to vel erable will

pins. This will allow the inner mandrel to travel downward with the ball. The ball will then go on seat. On seat the ball will leak at a predetermined rate.

The actuated Ball Check allows for two flow paths. First during running, the flow path is down the workstring, through the crossover tool, down the washpipe, through and out the shoe, and up the openhole screen annulus. The second flow path is during gravel packing and is:

• down the workstring,

• through the gravel pack service tool,

• out the closing sleeve,

• down the openhole screen annulus,

• through the tell-tale screen,

• back up the washpipe,

• through the actuated ball seat,

• through the crossover tool and

• into casing annulus above the packer.

Packer Test and Pressure Maintenance Assembly

Maintaining a fluid hydrostatic overbalance on the formation is critical to maintaining hostability and successful gravel packing. Removing the fluid hydrostatic overbalance will athe filter cake to lift off creating additional fluid loss and /or allowing the openhole to collaIn order to achieve the objective of packing the horizontal section and maintaining a hystatic overbalance on the formation a packer test assembly can be run. This assembly padditional flow control to allow pressure to be maintained during all phases of the compleThe assembly requires additional components to be added or designed into the gravel service tool. These additional components provide flow paths that control the weight dowashdown circulation, provide for a packer testing position with fluid circulation into the ohole, shut off circulation through the actuated reverse ball seat and re-open that path pfinal reverse circulation and actuation.

9.3.6 Weight Down / Wash Down Collet System OptionThe weight down / wash down option is a system whereby the screen plugging device rthe end of the washpipe is stung into a seal bore below the tell-tale screen and above thshoe when running in the hole. The crossover port is spaced out so that seals are locateand below the crossover ports in the seal bore below the closing sleeve. The closing slrun in the open position. This ensures that any fluid pumped down the workstring whenrunning in the hole will travel through the BHA and up the open hole/screen annulus witre-entering the BHA. Once the BHA is in place, the packer is set and the service tool is refrom the packer, the service tool string is picked up and set back down. The service toolwill bottom out on a weight down collet such that the end of the washpipe will be adjacethe tell-tale screen rather than in the lower seal bore, and sufficient weight down is applthe service tool string to prevent movement during pumping. The BHA is now in the grapack mode. This assembly is suggested for the long horizontal gravel packs as a considamount of fluid will be pumped down the workstring and therefore cooling and shrinkage



Section 9

result; pumping pressures will also cause the workstring to contract. This assembly will mini-mize tool movement during the treatment.

9.3.7 Washpipe

Gravel packing efficiency will improve by decreasing the cross sectional area of the screen/washpipe annulus, thus forcing the gravel flow path alone the casing/screen annulus. A screen/washpipe ratio of 0.8 is recommended. Flush joint connections such as Hydril 511/521 are typically utilized. Note: Due to the long intervals, the small annular clearance between the OD of the washpipe and the ID of the screen will have a significant effect on friction pressures during the job.

9.4 Post Gravel Pack Wash AssemblyAn assembly consisting of the equipment noted below is utilized to isolate and wash/soak the filter cake (through the production screen) in short sections after the gravel pack has been completed. This assembly must be able to pass through the ID of the fluid loss flapper valve and is an important part of the completion design from the beginning. The flapper can be acti-vated, once the washing procedure has been completed, to control fluid losses.

9.4.1 Wash Cup AssemblyThe Wash-Cup Assembly consists of opposing wash cups on either side of a perforated pipe. The function of the wash assembly changes in an openhole horizontal gravel pack. The injec-tion of acid will be directed by cup placement and diffused through an entire joint of screen while the pipe remains stationary. Acid will be slowly injected and allowed to soak each screen section. The wash cup spacing is based on screen joint length. In addition to diffusing the acid through each joint, the wash assembly provides the capability to inject excess acid left in the drill pipe at the end of the wash and soak cycle into the formation through the second and third screen joints.

Caution—Do not pump through the upper most screen joint. The gravel pack density is expected to be the lowest at the top. Pumping through the gravel pack in the upper screen could further loosen the pack and eventually result in a sand control failure.

9.4.2 Baffle Cups

Baffle cups are attached to and spaced out on the washpipe above the lower cup washing assembly. The baffles are designed to prevent fluid flow in the washpipe / screen and blank annulus and isolate the fluid hydrostatic. The lower wash assembly spacing is based on screen length. To provide redundancy for the two top downward facing cups of the wash assembly, downward facing cups are spaced for the next two-uphole joints. The next two joints have upward facing sets of cups to control fluid loss to the formation when lubricating any excess acid in the top second and third screen joints. Additional baffles are spaced to maintain one baffle in the blank section at all times.


July 199


ition . The cu-

t of a

soak ed e ge out

ipe or

9.4.3 Isolation Seals and Locator SubThe isolation seal assembly and locator sub is used for stinging into the gravel pack packer and isolating the casing annulus from the formation and workstring. Annulus isolation allows pres-sure to be applied for operation on the OMNI valve. Varying the pressure allows the Omni valve to cycle and thereby change positions.

9.4.4 Rupture Disc (RD) Safety Circulating Valve

The rupture disk (RD) safety circulating valve functions as both a safety valve and circulating valve. When the annulus pressure reaches a predetermined value, the valve isolates the work-string below the tool and establishes communication between the annulus and the workstring above the tool.

9.4.5 OMNI Valve

The OMNI valve is an annulus pressure operated valve that has three positions: blank, well test, and circulate. Applying and releasing a predetermined annulus pressure cause the valve to cycle. At a predetermined number of cycles the valve changes position. The OMNI circu-lating valve is run above the wash assembly on the work string and in the “circulate” posprovides the capability to isolate the formation while spotting acid down the workstring.Cycling to the well test position allows spotting the acid soak through the wash assemblycomplete capabilities of the OMNI Valve are many, and are outside the scope of this doment.

9.4.6 RFC-III Valve

The RFC valve controls the amount of fluid pumped into a formation, allowing treatmena completed well without pulling tubing. The valve is preset to hydraulically operate at aspecific pressure and allows precise amounts of fluid to be pumped through tubing intoformation. Opening and closing pressures are adjustable from 1,000 psi to 7,200 psi

The RFC valve allowed the metering of acid to each screen joint during the acid wash/treatment. Presetting the valve for the desired hydrostatic pressure prevents uncontrollrelease of acid to one screen section. The RFC valve is normally run as close to the surfacas possible to provide for quick change out in the event the valve become plugged. Chanby slickline or by pulling the workstring are recovery options.

Note—If the workstring method is used, the cups should not be pulled out of the blank puncontrolled fluid loss may result.



Section 9

9.5 Reference 12ZZ-xxxx – Shell Ram-Powell System 7-5/8-in. Casing x 4- 1/2-in. Screen

Table 9.1—Shell Ram-Powell System

Part Number DescriptionID

(in.)OD(in.)

Length(ft)

Halliburton "VTA" Gravel Pack Packer Assembly

12VTA17-Z Versa-Trieve Packer—7 5/8-in., 39-lb, 13CR Flow Wetted Aflas Elements

3.880 6.44 6.00

12P75237 Bottom Sub—5 1/2-in. 10 UNS Pin x 5 1/2-in. LTC Box 13Cr

3.880 5.880 0.47

92PPC55022 Upper Casing Extension—5 1/2-in., 17-lb, 13Cr 80My LTC (P x P)

4.892 5.50 3.00

12MCS38805-F Closing Sleeve—5 1/2-in. LTC Box x 4 7/16-in. UN 3.890 5.82 1.50

12P71766 Honed Tube—4 7/16-in., 10 UNS x 5-in. LTC Pin x Pin

3.880 5.02 2.00

92BBC55011 Coupling—5-in. 13Cr 105 My LTC Box x Box 4.620 5.28 0.60

92PPC55023Lower Casing Extension—5 in., 18 lb, 80My 13Cr LTC (P x P)

4.276 5.00 24.00

Combo Coupling—5 in., 18 lb, 80My 13Cr LTC x 4 in., 11 lb NU (B x B)

3.476 5.28 0.50

Pup Joint—4 in., 11 lb 13cr 80My NU (P x P) 3.476 4.00 6.00Adapter—4 in., 11 lb, NU 80my 13cr x 5 in., 18 lb, LTC (B x P)

3.476 5.03 0.75

Ref: 12EGF7501

Mechanical Fluid Loss Device—Ceramic Flapper 13Cr 85My 5 in., 18 lb LTC (B x P)

3.460 5.93 3.00

Ref: 12EGF7501

Mechanical Fluid Loss Device—Ceramic Flapper 13Cr 85My 5 in., 18 lb LTC (B x P)

3.460 5.93 3.00

12oo1833Make Up Sub—5 in., 18 lb, 13cr LTC x 4 in., 11 lb Varst-1(B x P)

3.476 5.28 2.00

Pup Joint with Coupling—4 in., 11 lb Varst-1 13Cr 80My (B x P)

3.476 4.00 2.00

Halliburton Blank And Screen Assembly

Blank—4 in., 11 lb, 13cr 80my Varst-1 for 7 5/8-in., 39 lb Casing centralized with Spir-O-Lizer central-izers

3.476 4.00 300.00

Screen—Enhanced Low Profile Prepack 40/60 Sand Resin Coated on 4-in., 11 lb, 13cr 80my

Varst-1 base pipe Spir-O-Lizers for 7 5/8-in., 39 lb Casing Incoloy 825 wire wrap

3.476 5.552500.0

0

Halliburton Horizontal BHA Tattle Tale Screen and Float Shoe Details

92BPC______Adapter—4 in., 11 lb Varst-1 x 4 in. NU 13cr (B x P)

3.476 4.55 1.00

Coupling—4 in., NU, 11 lb 13 cr 80 my 13cr (B x B) 4.000 4.75 0.4012o8848 Upper Sealbore with profile—4 in. NU 13cr (P x P) 3.000 4.25 1.00


July 199


eve.

9.5.1 Assembly Notes

• Space out service tool with weldment packed off across seal bore below closing sle

• A seal must be in packer bottom sub.

Tattletale Screen—4 in., 11 lb, NU (B x P) Incoloy 825 wire 6 GA. With 12/20 pre-prepack resin coated. L-80 base pipe

3.476 4.98 40.00

92C331 Coupling—4 in., NU, 11 lb L- 80 4.000 4.75 0.40

Ref:12o8849Lower Sealbore—4 in., 11 lb, NU (P x P) L-80 with Spir-O-Lizer centralizer attached

3.000 4.00 1.50

Adapter—4 in., 11 lb, NU x 3 1/2-in., 9.2 lb NU L-80 (B x P)

2.99 4.77 0.50

Ref:12oo1679 Double Valve Floatshoe—3 1/2-in. L-80 NU Box N/A 4.25 2.00

Inner String12oo1826 Plug Assembly N/A 3.25 4.5

Horizontal “VTA” Packer Service Tool Assembly

12 MPW 8 VTA Weight-down/Wash-down Service Tool 5.69 2.86 2712oo1823 Reverse indicator/activated ball check 3.86 1.70

12oo1836 Swivel 2 3/8-in. CS (B x P) 1.94 3.86 1.60

12MCP8 Closing Sleeve Shifter – Bow type 2 3/8-in. CS (B x P)

1.93 4.20 3.12

Adapter—2 3/8-in. CS Box x 2 3/8-in. 511 Wedge Pin

1.93 3.02 0.80

Packer Pup Joint—2 3/8-in., 6.4 lb, N80 511 Wedge (B x P) 2- 10 ft and 1- 4 ft

2.38 2.88 10

Primary—Ratch Latch Assembly

Adapter—2 7/8-in. 511 Box x 2 3/8-in. CS Hydril Pin 1.92 2.88 1.13

Ref. 12oo1636 Ratch-Latch 2 3/8-in. OECO A Box x M/S 1.91 2.95 1.63

Primary-Parked Ratch Latch Receptacle & Screen Plug AssemblyRatch Latch Receptacle with 2.55-in. seal bore I.D.

Top: 2.500-6 Ratch Latch RH Bot.: 2 3/8-in. OECO A Pin

1.91 2.95 1.60

Adapter—2 3/8-in. CS Box x 2 3/8-in. 511 Pin 1.96 2.70 0.80

Washpipe Pup 2 3/8-in., 4.6 lb N80 511 Wedge (B x P)

2.40 2.88 24.0

12oo1826 Screen Isolation Plug 23/8-in. 511 Box N/A 3.23 4.75

Wash Cup Assembly

Pup Joint- 2 7/8-in. 511 Wedge Box x Pin 2.40 2.88 6.0

12oo1834 Baffle Cup Assembly

12oo1820 “VHR” Pulling Tool 2 7/8-in. EUE Box 1.72 5.75 2.5

Table 9.1—Shell Ram-Powell System



Section 9

wash-pper

trips.

on ash

own screen

ore

on.

es.

llow The

age

• Closing sleeve will be run in the open position.

• After service tool has been stabbed, test service tool in packer to 500 psi.

• Test gravel pack service tool from bottom by applying 500-psi pressure through the pipe connections. Test verifies crossover port seals, internal washpipe seals and ucirculating port seals.

9.5.2 Running Notes

1. Hole preparation is important to the success of the job, make adequate clean out

2. Space out screen plug after latch-up no more than 1.75 ft off bottom to keep seal screen plug in lower seal bore, there is only a 2 ft window for space out allowing for wdown through float shoe.

3. The last 30 ft before plug latch up, install pup joints starting with longest and work dto smallest in order to use the least amount of pups, and not pick up +- 20 ft and set plug.

4. Break circulation after making up packer, to ensure pathways are open.

5. After getting packer to bottom, displace solids free mud with completion brine befsetting packer.

6. Pick up 4.5 ft then slack-off, this will locate service tool in new weight down positiOnce this done, you are unable to go back to lower wash down position.

Note—Move service tools only at a “creeping” speed to avoid downhole pressure surg

7. If ball seat shears early, the ball will fall in a wedge seat below crossover and it will afor final packer setting if needed. A secondary ball is not needed with this system.ball acts as a fluid diverter, which forces the fluids out of the crossover.

8. Packer setting pressure is 3350 psi.

9. Pick up 10 ft from running position or 7.20 ft from new weight down position to engreverse indicator and shear to create solid ball seat.

Caution—Don’t shear reverse indicator until appropriate time in procedure, needed flow paths are blocked after shearing the indicator.

10. Pick up at 20 ft from new weight down position to locate and set screen isolation plug in upper seal bore profile, thus closing bypass on plug. Straight pull will shear running tool off of plug.

Caution—Don’t set screen isolation plug until appropriate time in procedure, different flow paths are allowed before setting plug.


July 199


bove ning

to

st be

e

9.6 Reference 12ZZ1830 – Petrobras Job9 5/8-in. Casing x 5- 1/2-in. PoroPlus Screens

9.6.1 Completion Assembly Notes

• Length of the 6 5/8-in. pup below packer must be 60 inches so that the molded seal aand below the x-over weldment will be inside the closing sleeve polished bore in runin position.

• Length of the polished bore below the closing sleeve must be 3 ft minimum in orderhouse two seal units inside when in the circulation position.

• If centralizers will be utilized the length of the screens blank pipe above pin end mu2 ft to accommodate the Spir-O-Lizer centralizer and allow room for pipe wrench.

• Couplings on the screens must be delivered torqued according to thread specs.

• A tattle tale with the same length of the production screen will facilitate the wash pipspace out.

Table 9.2—Petrobras Job

Part Number

DescriptionID

(in.)OD(in.)

Length(ft)

12VTA 35-Z 9 5/8-in., 47-53.5 lb VTA Packer 5.00 8.30 73.60

6 5/8-in. SCT Pup Joint

12MCS5000 Closing Sleeve 6 5/8-in. LCT-Assembly 5.00 7.28 58.49

Seal Bore ExtensionCombination Coupling

6 5/8-in. SCT Pup Joint

12EGF9026 Ceramic Flapper—6 5/8 in. LCT 5.00 8.14 37.80

Adapter—6 5/8 in. LTC x 5 1/2 in. LCT

12oo1988 Make-Up Sub—5 1/2 in. LTC 3.68 7.12 318.2

Adapter—5 1/2 in. LCT x 5 1/2 in. BTS 5.50

Blank Pipe—5 1/2 in., 17 lb BTS 5.50

Adapter—5 1/2 in. BTS x 5 1/2 in. LCT 5.50

PoroPlus Screens—5 1/2 in. LCT with Centralizers 6.08

Combination Coupling—5 1/2 in. LCT x 4 in. NU 5.50

12O9225 Upper Seal Bore—4 in. NU P x P 3.00 4.51 19.17Sacrificial Screen—4 in. NU N-80 3.548 4.49Coupling—4 in. NULower Seal Bore—4 in. NU P x P with Centralizer

Adapter—4-in. NU x 3 1/2 in. NU

12oo1939 Float Shoe—3 1/2 in. NU 4.25 26.80



Section 9

sile Z

• The VTA packer’s guide and set sleeve must be made out of P-110 to increase tenrating to provide maximum over pull if the assembly becomes stuck. The 12VTA35maximum hang weight through guide is only 56,799 lb.

9.6.2 Service Tools NotesTable 9.3—Service Tools Notes for Petrobras Job

Part Number

DescriptionID

(in.)OD(in.)

Length(ft)

12MPW20 MPW Tool—5 in. Bore Weight Down MPT 1.64 8.02 408.03Locator02 Molded Seals UnitWeight Down Mandrel(Weight Down Collet - 0.47 m)Circulating Seal Unit1 ft Seal UnitsExtensionX-Over WeldmentShort Seal Unit1 ft Seal UnitsExtensionReverse Ball MechanismSwivel

Adapter—3 1/2-in. CS x 4 in. Hydril 511

Pup Joint—4 in. Hydril 511Wash Pipe—4 in. Hydril 511Pup Joint 4" Hydril 511 ( space out )

Adapter—4 in. Hydril 511 x 2 3/8-in. Hydril 511

Adapter—2 3/8-in. CS Box x 2 7/8-in. Hydril 511 Pin

Adapter—2 7/8-in. Hydril 511 Box x 2 3/8-in. CS Box

Ratch Latch Tool—2 3/8-in. Hydril 511

Screen Plug AssemblySeal Bore Ratch Latch

Pup Joint—2 3/8-in. Hydril 511




Running ToolBull Plug


July 199


sile

verse erse

frac- wash-led in e

id uired : A in-

ni-

you

Notes

• Run short seal units, 6 in. long, below weldment.

• The VTA packer’s guide and set sleeve must be made out of P-110 to increase tenrating to provide maximum over pull if the assembly becomes stuck. The 12VTA35Zmaximum hang weight through guide is only 56,799 lb.

• If working out of a semi-submersible, add an extension to the seal units above the reball mechanism in order to avoid to actuate the reverse ball when the tool is the revposition.

Job Procedure Notes

• Before attempting to test the packer on the annulus, know the formation injection andture pressures. If the packer leaks, pressure is applied directly to the formation. Thedown system isolated the drill pipe fluid return path by having the crossover port seathe lower seal bore, by having the lower end of the washpipe sealed by the washpipdeployed plug and the shoe.

• When the packer setting ball goes on seat, the formation hydrostatic is isolated. Flulosses to the formation must be manageable prior to dropping the ball. Speed is reqin packer setting and testing. Taking to long could result in formation collapse! Notenew tool is currently underdevelopment that will allow hydrostatic pressure to be matained on the formation at all times.

• It is important to test the packer's back side if the pressure required to cycle the Omvalve, usually 2000 psi, is higher than the formation's fracture pressure.

• Rig up a bypass line for the return line so it will not be necessary to stop pumping ifneed to replace a flow-meter, densometer or if the line is plugged during the job.

9.7 Amoco Bolivia Job – OBM7-in., 29 lb Casing x 4-in. ScreenJob was not performed in the field.

Table 9.4—Amoco Bolivia Job

Part Number

DescriptionID

(in.)OD(in.)

Length(ft)

12VTA4-Z 7-in., 29 lb x 3.88-in. VTA Packer 3.880 6.00 1.78012P71042 Guide12P71659 Set Sleeve1P70086 Bottom Sub—5 in. LTC 3.880 5.873 0.140

92C4862Upper Extension—need 3 ft

5 1/2-in., 17-lb, K-55 Pup Joint LTC (P x P)4.892 5.550 0.914

12MCS3880

Closing Sleeve Assembly 3.880 5.820 0.476

12o9225Seal Bore Extension—4 in., 9.5 lb API NU (P x P)

3.880 5.200 0.487

Combination Coupling—5 in. LTC 5.290 0.200Lower Extension—5 in., 18 lb N-80- LTC (P x P) 4.408 5.100 7.320



Section 9

9.7.1 Service Tools Notes

Adapter—5 in., 18 lb LTC x 4 in., 9.5 lb NU ( B x B)

3.548 5.280 0.200

Blank Pipe—4 in., 9.5 lb NU (P x P) 3.548 4.000 1.830Adapter—4 in., 9.5 lb NU x 5 in., 18 lb LTC (B x P)

3.548 5.280 0.200

12P7023 Ceramic Flapper 3.010 0.600Make-Up Sub (B x P) 3.548 5.000 0.750Pup Joint with Coupling—4 in., 9.5 lb NU (P x P) 3.548 4.000 0.610Blank Pipe 4 in., 9.5 lb NU—20-ft joints 3.548 4.000PoroPlus Screens—4 in., 9.5 lb with Centraliz-ers—20 ft joints

3.548 4.590

Combination Coupling—4 in., 9.5 lb NU 3.670 4.790 0.150Upper Seal Bore—4-in., 9.5 lb NU (P x P) 3.000 4.510 0.490Sacrificial Screen—4 in., 9.5 lb NU N-80 3.548 4.590 9.140Coupling—4 in., 9.5 lb NU 3.670 4.790 0.150

12O8849Lower Seal Bore—4 in., 9.5 lb NU P x P with Centralizer

3.000 4.510 1.074

Adapter—4 in., 9.5 lb NU x 4 1/2-in. Buttress (B x P)

3.500 4.750 0.200

12oo1939 Double Valve Float Shoe—4 1/2-in. Buttress --- 4.250 0.681

12oo1942 Isolation Plug Assembly 3.230 1.510

Table 9.5—Service Tools Notes for Amoco Bolivia Job

Part Number

DescriptionID

(in.)OD(in.)

Length(ft)

MPW Tool—3.88 in. Bore Weight Down MPTLocatorMolded Seals UnitWeight Down Mandrel(Weight Down Collet—0.47 m)Circulating Seal Unit1-ft Seal UnitsExtensionX-Over WeldmentShort Seal Unit1-ft Seal UnitsExtensionReverse Ball Mechanism—Actuated

12P71359 Top Baffle Plate12P71358 Bottom Baffle Plate12P71360 Isolation Sleeve12P71362 Ball Seat12P71361 Piston Mandrel12FLD Tapered Seat

Table 9.4—Amoco Bolivia Job


July 199


12P71072 Expendable SeatSwivel

Adapter—3 1/2 in. CS x 4 in. Hydril 511

Pup Joint—4 in. Hydril 511

Wash Pipe—2 7/8 in. Hydril 511

Pup Joint—4 in. Hydril 511 (space out)

Adapter—4 in. Hydril 511 x 2 3/8 in. Hydril 511

Adapter—2 3/8 in. CS Box x 2 7/8 in. Hydril 511 Pin

Adapter—2 3/8 in. Hydril 511 Box x 2 7/8 in. CS Box

Ratch Latch Tool—2 3/8 in. Hydril 511

Screen Plug AssemblySeal Bore Ratch Latch

Pup Joint—2 3/8 in. Hydril 511

Running ToolBull Plug

Table 9.5—Service Tools Notes for Amoco Bolivia Job



Section 9



July 199

Section

1010. Gravel Pack Fluids/Sand

me ove the e, due

ping e other

– 251-

alpha wave e height lace that

d also

ation

Note—Please see Section 14 for further information on design rules-of-thumb.

The Alpha wave is designed so that it covers the top of the screen in the open hole. Sodesign the alpha wave so that it goes halfway up the screen. Others to 5 sand grains abtop of the screen. The screen will be covered to different heights at the heel and the toto the fluid loss along the length of the screen.

10.1 HzGPSim Horizontal Gravel Pack Design SpreadsheetThe HzGPSim spreadsheet is the tool currently used by Halliburton to design the pumprocedure for horizontal gravel packs. This spreadsheet is not to be distributed to anyonthan Halliburton personnel.

To obtain a copy of the HzGPSim spreadsheet, contact: Mike Sanders at Telephone 5803916 or E-mail [email protected].

10.2 Fluid Rates and PressuresWhen designing a horizontal gravel pack, the return rate is determined by the desired wave height and sand concentration. The HzGPSim spreadsheet calculates the alpha height as a percentage of the openhole height. The user specifies a desired alpha wavand a sand concentration, the spreadsheet then calculates the return rate needed to palpha wave height at the toe.

Before pumping the gravel pack, fluid must be circulated with the tool in the reverse ancirculating positions. The pressure needed to overcome the friction below the packer isexerted on the filtercake. This pressure can be calculated for a given rate as follows:

Pressure in Circulate Position – Pressure in Reverse Position = Pressure Exerted on Form

When running the screens into the openhole, the filtercake can be disturbed causing fluid to leakoff into the formation. If solids free drill-in fluid is left in the openhole when running screens, the filtercake may or may not be able to heal from damage as the screen is going into the openhole. Sometimes the solids free drill-in fluid is not enough to prevent fluid loss prob-lems before pumping the gravel pack, and some solids-containing fluid loss control material (a “pill”) may have to be pumped to enable gravel packing.

9 Page 10-1 Section 10—Gravel Pack Fluids/Sand


Section 1

mini-

but a and ping

wash

cker

i-

ower nterval

While pumping in the circulate position, the return rate should be at least 75% of the pump rate. If the return rate is below 75% of the pump rate, spotting a fluid loss pill should be consid-ered. Some horizontal gravel packs have been pumped with only a 75% return rate initially, but during the placement of the alpha wave, the return rate rose to equal the pump rate. Once the alpha wave reached the area where the filtercake was damaged, the sand packed around the area and the fluid was then diverted to the sacrificial screen.

10.3 Fluid DesignThe carrier fluid weight should be high enough to maintain hole stability. If a lighter fluid is selected then the hole could collapse during pumping operations.

Once the gravel pack is complete, the screens may have to be acid washed to remove the filter-cake material depending on the drill-in fluid used to drill the horizontal section. If an acid wash is necessary, the completion fluid in the well may be circulated out with a lighter completion fluid to give the well a 50 – 100 psi overbalance. The lighter completion fluid is used to mize fluid loss once the screens are acid washed.

10.4 Breakers for Drill-in Fluid Filter Cakes

10.4.1 Cleanup of THIXSAL PLUS Drill-in Fluids

Typical clean up solutions would include:

• 10% HCl with Saturated Brine

1. Spot the first wash fluid to the packer. This wash fluid can contain acid or breakershould be under-saturated. Pull the wash cup mechanism into the lower blank aretest for pressure differential. Pull the wash cups across the screen interval while pumthrough the screen with the first wash fluid. Upon reaching the upper blank, test thecups for pressure differential.

2. If the first wash fluid is also a soak fluid, lower the wash cups, sting back into the paseal area and allow to soak while reverse circulating the washed fluids.

3. If the first wash fluid is not a soak fluid, continue pulling out of the hole while montoring loss rate. Engage fluid loss device and continue out of the hole.

4. Spot the second wash fluid to the packer, pull the wash cup mechanism into the lblank area and test for pressure differential. Pull the wash cups across the screen iwhile pumping through the screen. Pull out of the hole while monitoring loss rate. Engage the fluid loss device and continue out of the hole.

10.4.2 Cleanup of Calcium Carbonate Drill-in FluidsTypical clean up solutions would include:

• 10% HCl

• Sulphamic Acid + Claysafe 5

• MSA Acid

• Enzymes

0—Gravel Pack Fluids/Sand Page 10-2 July 1999

July 199


lank l while , test

acker ith

ing

echa-cross

ash is ll out

ut of

ells

mer

• Oxidizers

• Hypochlorites

• Sodium Perborate

1. Spot the first wash fluid to the packer, pull the wash cup mechanism into the lower barea and test for pressure differential. Pull the wash cups across the screen intervapumping through the screen with the first wash fluid. Upon reaching the upper blankthe wash cups for pressure differential.

2. If the first wash fluid is also a soak acid, lower the wash cups, sting back into the pseal area and allow to soak while reverse circulating the washed fluids. Continue wstep 7.

3. If the first wash fluid is not a soak fluid, continue pulling out of the hole while monitorloss rate. Engage fluid loss device and continue out of the hole.

4. Spot the second wash fluid (overflush/dilution) to the packer, pull the wash cup mnism into the lower blank area and test for pressure differential. Pull the wash cups athe screen interval while pumping through the screen. The object of the second wto lower the concentration of any residual acid, thereby reducing corrosion rates. Puof the hole while monitoring loss rate. Engage the fluid loss device and continue othe hole.

10.4.3 Cleanup of Oil Based Drill-in FluidsTypical clean up solutions would include:

• Base oil + Surfactant Sweep + Mutual Solvents

• CLEANBORE

• OSA + Mutual Solvent + Hyflo IV

• Alternating surfactant system followed by 5% HCl

10.5 BJ’s MudZymes InformationBJ Mudzymes is claimed to be a polymer specific enzyme breaker designed to cause a filter cake made up of cellulose, xanthan and starch based fluids to break up, and thus remove drilling damage. According to the BJ literature (brochure and SPE papers) the enzymes are designed to work on specific polymer cleavage sites to remove the polymer residue. They claim that bleach (sodium hypochlorite), lithium hypochlorite, persulfates and acids will react with polymers without regard to cleavage sites and thus are not as efficient as the BJ product. BJ ferments and isolates bacteria to produce particular enzymes which perform for specific downhole conditions. These following SPE papers contain information about BJ Mudzymes:

• SPE 39380 “New Treatment for Removal of Mud Polymer Damage in Multi-Lateral WDrilled Using Starch Based Fluids”

• SPE 35594, “Utilization of Polymer Linkage Specific Enzymes to Degrade HEC Polyin Water Based Drilling and Gravel Packing Fluids”.



Section 1

__ acker

acks, same benefit

ze is d in size. plex

In previous testing performed by Clay Cole in the mid-to-late 1980’s, indications were that Xanthan was not effected very much by enzymes. HCl would degrade it but up to about 150F it was pretty slow.

Kelco (the company which produces the Xanthans) has said that it is possible to produce a specific bacteria (enzyme) to break down a Xanthan polymer. However, the cost per chemical would be upwards of $100,000. To compound the problem Kelco stated that the organisms that make up Xanthan mutate. Therefore, the enzyme that may have been engineered to work with a specific batch of Xanthan won’t have the same effect on a second batch of Xanthan. This implies that the greater the time since the introduction of a new enzyme, the less efficient that the enzyme might be on the next batch of Xanthan.

10.6 Tetra’s ACT Breaker SystemNo information currently available.

10.7 Pickling WorkstringThe workstring is typically pickled with a combination of __ gallons of Baroid’s _______or Production Enhancement’s DopeBuster ME+ and __ gallons of 15% HCl once the phas been set and tested.

10.8 GravelAPI specification gravel pack sand has been most commonly used for horizontal gravel pbut Carbolite is often preferred technically over sand due to higher permeability for the size gravel compared to sand. Its additional cost must be weighed against the expectedfrom the added permeability.

Proppant size is determined by the size of the formation sand. Once formation grain sidetermined, Saucier’s method is usually used to select proppant size. Saucier’s methosuggests using a proppant size that is 5 to 6 times larger than the average formation graHowever, some formations may allow larger sizes; a completion discussion of this comissue is outside the scope of this document.

10.9 Optimum Sand Concentration0.5 – 2 ppg

10.10 EquipmentThe following is a typical equipment list used for horizontal gravel packs in the Gulf of Mexico. Of course, pumping equipment will vary with each job and location.

• two HT-400 (V-8 or larger) Pump Skids

• one 6 X 5 Centrifugal Pump

• one Sand Tank (Large enough to hold job volume)

• one Portable Clam and Gate

• one 100-bbl Open Top Tank


July 199


• one 2-in. Iron Package

• one 2-in. High Pressure Manifold

• one 4-in. Clam Hose Basket

• 25 3-in. CAMLOCK Hoses

• one COMPUPAC Data Acquisition System

• one Connection Basket

• two Sand Return Tanks

• two Air Diaphragm Pumps

• one Pump-In Sub

• one Tool Box

• two 2-in. Densiometers

• four 2-in. Turbine Flowmeters

• two 2-in. Pressure Transducers

Sand Tank

Clam

CompletionFluidTank

HT-400 HT-400

DAS

Cen

trif

ugal

To Rig Floor

Recirc Line



Section 1

sand sand

andle

mp. ump pant

and is e tank conse-

ucers s test

one

sed, e.

ution.

10.11 Acid Washing EquipmentIf filtercake removal requires an acid wash, the following equipment is usually brought to location:

• one 30 bbl Sand Control Blender

• two 100 bbl Bulk Storage Tanks (or necessary storage volume needed for acid)

• one Low Pressure Filter Unit

10.12 Lessons Learned—Operations• The gate used to control the sand rate may have to be re-calibrated due to the low

rates needed for horizontal gravel packs. If the gate cannot maintain control over lowrates, a new gate may have to be manufactured and calibrated.

• When reversing slurry out of the workstring, two sand return tanks were needed to hthe flow rate. One sand return tank was not large enough.

• When rigging up the portable clam, the carrier fluid is not boosted by a centrifugal puThis is to allow better control over the fluid level in the clam tub because of the low prates. This is important because if the fluid level in the tub is not maintained, the propconcentration will fluctuate.

• The sand should not be cut into the sand tank until a few hours before pumping. If splaced into the tank 24 hours before pumping, humidity in the air can condense in thovernight. This causes the sand to become wet; which will affect the sand rate and quently proppant concentration.

• Before beginning any pumping operation, all flow-meters, densiometers, and transdshould be tested with a small circulating test through all equipment and meters. Thihas saved hours of potential downtime on location.

• A backup should be in line for each meter, transducer, and the densiometer.

• If an acid wash is needed after the gravel pack, the inhibitor should be mixed withinhour or two of pumping. Normally, a large amount of inhibitor is needed to provide protection for long contact time on the screens. Depending on the type of inhibitor uthe inhibitor will separate from the acid if it is allowed to settle for a long period of timAlso, a special inhibitor may be required when used with acid in a salt-saturated sol


July 199

Section

1111. Reporting Results/Case Histories

ri-

ls

C

Bla

Gas-

Ste

EveLim

Mik

Pauit v-

PetNicAla

.

t-

Dar

Please refer to the following URL address for the latest information on Halliburton’s Hozontal Gravel Pack Case Histories:

http://halworld.halnet.com/hes/hesps/hespscp/hespscp_content/sandcontrol/990415.x

Date of Update: 21 January 1999

Table 11.1—Reported Results and Case Histories

ontact: Customer LocationNo. of Jobs

Comments

ine Spies Mobil Gulf of Mexico 1Shunt Screen utilized - Johnson Screens?Open Hole GP

ry Cormier Caltex Duri, Indonesia 2First job failed. Rates stipulated by cutomer too low. Open Hole GP.

ve Smith Chevron Gulf of Mexico 1 Slurry Pack—inside casing

raldo a

Petrobras South America 1Nick Gardiner was involved in sales effort.Open Hole GP

e Perry Mobil Nigeria 1 FloPac utilized—cased hole

l McGinn Chevron Aberdeen, UK 1

Performed pumping services under Baker contract. Halliburton cement unon location. SPE Paper written by Cheron, Baker and DS—cased hole

e Duhonk Gardinern Holley

Shell Deepwater

Gulf of Mexico 5

Ram Powell. 7 5/8-in. csg. 6 1/2-in. OHBrine based CaCO3 drill in fluid. One

4 1/2-in. and four 4-in. PLP screens. Tatletale BHA with isolation plug. Acid

clean up squeeze on 2nd trip. All jobs pumped and produced successfully. SPE paper 50146. Open Hole GP

ryl CarrollShell Brunei

Brunei Open Hole GP

9 Page 11-1 Section 11—Reporting Results/Case Histories


Section 1

11.1 Total No. of Jobs =

11.2 Potential or Planned Jobs in 1999BP—Troika

BP—Amberjack

Exxon—Diana/Hoover—4-6 wells

Shell—Auger—1 well

1—Reporting Results/Case Histories Page 11-2 July 1999

July 199

Section

1212. Competition Information

ple-ning

ion. e used

p the

gher reens,

frac-t tubes, t with tion of

d mers. o uses

12.1 BakerBaker is the one competitor that performs horizontal gravel packs in the Gulf of Mexico on a regular basis. The following list of design parameters was comprised from information given to us from customers who have used Baker to perform openhole horizontal gravel packs before Halliburton.

• Baker often uses a drill-in fluid (PERFFLOW™) that they claim does not require an acid wash after the gravel pack. They claim that the filtercake material will flow back through the gravel pack and screen.

• Once they have drilled the horizontal section, they displace the entire well with comtion fluid. They do not leave a solids-free pill across the openhole section while runin the screens.

• They don’t recommend using any centralizers on the screens in the openhole sectThey claim that the screens cannot be run in the openhole section if centralizers arbecause they “hang up”.

• They do not use a sacrificial screen at the end of the bottomhole assembly to pumgravel pack. They only run production screen.

We understand that Baker’s open hole horizontal gravel packs are pumped at much hirates than Halliburton. This may be due to the fact that Baker does not centralize their scwhich requires a lower alpha wave height.

12.2 Dowell SchlumbergerMobil has granted an exclusive license to the shunt tube technology (ALLPACK and ALLFRAC) to Dowell Schlumberger (DS). They have licensed both gravel packing and turing to DS. Although DS does not itself manufacture screens and the associated shunit controls the manufacture of these types of screens; DS currently has an arrangemenJohnson Screens (a division of U.S. Filter Company) whereby Johnson does the fabricascreens with shunt tubes.

DS, by virtue of its exclusive license, has the right, but not the obligation, to permit thirparties (such as Halliburton) to perform pumping services under their license for custoDS is using this as a competitive advantage when selling horizontal gravel packs. DS als

9 Page 12-1 Section 12—Competition Information


Section 1

00 –

hori-e fluid rrently o cure

an l open PAC uato-

the ech-

this as a competitive advantage when selling FracPacs on multiple zone wells with variable permeability. DS claims to have performed 320 jobs as of 23 September 1998 on conventional gravel pack completions; most of these completions were for Mobil operated wells or wells on which Mobil had great influence as to the design. However, several operators other than Mobil are considering use of the shunts for packing long intervals with varying permeabilities or intervals for which there is a high risk of failure of the filter cake during packing. They also claim to have performed 8 jobs on long interval, horizontal wellbores with lengths of 1,62,600 ft.

Baker, Halliburton and Dowell all utilize the Alpha-Beta wave technique to gravel pack zontal wells. However, Dowell markets the Shunt system as a fail-safe alternative in casloss becomes a problem (causing the Alpha-Beta wave to stop). Halliburton does not cuhave a similar system. Halliburton and Baker currently use graded calcium carbonate tthe fluid loss as it becomes a problem.

Dowell tries to combine their ISOPAC lightweight ceramic proppant, PERMPAC carrierfluid, and the Mobil Shunt Screens (sold by either DS or directly by Johnson screens inagreement with Dowell Schlumberger) as a system that enables them to pack horizontahole completions regardless of the fluid loss conditions. They are currently selling ISOgravel at $10 per pound. It is reported that the long interval gravel packs for Mobil in Eqrial Guinea are running at $1 – 1.5MM per well.

12.3 OthersBJ, OSCA, and other competitors are not currently believed to significantly compete inhorizontal gravel pack market, although this could change as horizontal gravel packingbecomes more common in offshore completions (as we believe will happen), and the tnology becomes more widely known.

2—Competition Information Page 12-2 July 1999

July 199

Section

1313. Reference Papers

SPE No./ Location of Paper Paper, Author, etc.

SPE 53926

“The Evolution of Horizontal Completion Techniques for the Gulf of Mexico. Where Have We Been and Where Are We Going! “ Jeff Foster, Tommy Grigsby and Jackie LaFontaine—Halliburton Energy Services

World Oil (Nov.1988)"Controlling Sand in a Horizontal Completion”, Sparlin, D.D. and Hagen, R.W. Jr.

Journal of Petroleum Technology (Nov.1983) Pages 2079-2086

"Experience in Gravel Packing Long, Perforated Intervals in Deviated Holes”, Van Ballegooyen, J., Giap, T.K., and Seng, T.K.

Journal of Petroleum Technology (Jan. 1984)

"High-Angle Gravel-Pack Completion Studies," 69-78. Elson, T.D., Darlington, R.H., and Mantooth, M.A.

Journal of Petroleum Technology, March 1980

“A Method of Analyzing Performance of Gravel-Pack Completions in Seria Field, Brunei”,

Proceedings 1996 (6 Pages)

“Acid Stimulation Of Openhole Horizontal Section Behind Prepack Screen Using Coiled Tubing And New Isolation Method”, Koshak, W E; Attah, M 1st SPE/International Coiled Tubing Assembly North American Coiled Tubing Roundtable (Montgomery, Texas, 96.02.25-28)

36583-P “An Expandable-Slotted-Tubing, Fiber-Cement Wellbore-Lining System”, Stewart, R.B. ,Gill, D.S. ,Lohbeck, W.C.M., Baaijens, M.N.

Offshore Incorporating Oilman (International Edition) V 52, No 4, Pages 42,44,47, April 1992 (2 References)

“Array Of Completion Tools, Methods For Horizontal Well Sections”, Bila, V.J.,

Journal of Petroleum Technology, January 1983

“Case History of Yakin Field: Its Development and Sand Control”,

Harts Petroleum Engineer Inter-national, November 1996. Pages 31 – 35.

“Casing/Liner/Screen Installation in Extended Reach Wells.”

9 Page 13-1 Section 13—Reference Papers


Section 1

Proceedings V 1, Pages V51-V55, 1991 (ISBN 0-646-07408-3; 7 References)

“Cementing Liners In Horizontal Wells”, Vinson, E; Shry-rock, S; Womacks, D1st Victorian Department Manufacturing Industry Develop Et Al Offshore Australia Conference (Melbourne, Australia, 91.11.25-27)

Proceedings 1996 (Icota-96004; 16 Pages; 7 References)

“Coiled Tubing Workover Saves Horizontal Well In Lake Maracaibo”, Lizak, K; Patterson, J; Suarez, D; Salas, J 1st SPE/International Coiled Tubing Assembly North American Coiled Tubing Roundtable (Montgomery, Texas, 96.02.25-28)

Proceedings Pages 9-30, 1995 (8 References)

“Completion Options For Management Of Sand Production In Horizontal Wellbores”, Restarick, H Soc Indonesian Petroleum Engineering Production Optimization Interna-tional Symposium (Bandung, Indonesia, 95.07.24-26)

World Oil, November 1988 “Controlling sand in a horizontal completion”,

Petroleum Engineering Interna-tional V 63, No 11, Pages 54,56,58, Nov 1991(9 References)

“Current Stimulation Technology Used In Horizontal Wells”, Rose, B

Paper No, 95-407, April 1995“Damage Removal Techniques Prove Successful in Hori-zontal Completions”, CADE/CAODC Spring Drilling Conference,

Offshore Oilman, February 1983“Drainage Tool Finding Uses for Many Reservoir Conditions”,

Petroleum Engineer International August 1995

“Estimate Formation Damage Effects on Horizontal Wells”, , Bob Burton

SPE Drilling and Completion, September 1997

“Evaluation and Selection of Drill-in-Fluid Candidates to Minimize Formation Damage”,

Proceedings V 1, Pages 1141-1144

“Expanded Stimulation Capabilities In Horizontal Liners”, Burns, T1st Victorian Dep. Manufacturing Industry Develop Et Al Offshore Australia Conference (Melbourne, Australia, 91.11.25-27), 1991 (ISBN 0-646-07408-3; 7 References)

American Oil Gas Reporter V 39, No 8, Pages 58-61, Aug 1996

“Factors Driving Completion Advances”, Gardiner, N.H.,

27341-P “Field and Laboratory Verifications of Sand Production Pre-diction Models”, Morita, Nobuo

World Oil, March 1992 “Gravel Packing Horizontal and High Angle Wells”

Oil & Gas Journal, September 1, 1997

“Gravel Packing Prevents Productivity Decline”

“Highly Deviated And Horizontal Well Cementing: (Mud) Displacement Mechanics And Cement Slurry Design”, Hashimoto, H., Japan Assembly Petroleum Technology V 59, No 5, Pages 374-381, Sept 1994 (1 Ref; In Japa-nese)Japan Ass Petroleum Technology Spring Meeting (Nagaoka, Japan, 94.06.09-10) Paper; J


3—Reference Papers Page 13-2 July 1999

July 199


Proceedings Paper No 15, 1994 (24 Pages; 8 References)

“Horizontal Well Completion Options In Reservoirs With Sand Problems”, Restarick, H; Oncale, R6th Annual Petro-leum Network Education Conference (PNEC) Horizontal Well & Emerging Technology International Conference (Houston, 94.10.24-26)

“Horizontal Well Mud Clean out and Filtercake Removal” Internal Paper by Ron Dusterhoft

Proceedings Paper No. 21, 1993 (8 Pages; 4 Reference)

“Horizontal Well Servicing By Coiled Tubing Enhanced For High Angle/Horizontal Wells” Fowler, H., 5th World Oil Et Al Horizontal Well Technology International Conference (Amsterdam, Netherlands, 93.07.14-16)

American Oil Gas Reporter V 31, No 12, Pages 30-32, Dec 1988

“Horizontal Well Technology : Cement Sheath Vital In Hori-zontal Well”, George, C.,

Ocean Industry Volume 26, No 2, Pages 20-25,28, March 1991 (21 References)

“How Industry Completes Wells In Offshore Environments : Pt.1 : Horizontal/Extended-Reach Wells Offer Valuable Advantages In Many Worldwide Areas”, Thomas, B D; Yuan, W P

Petroleum Engineering Interna-tional V 70, No 11, Pages 63-64,65,67-70, Nov 1997 (2 References)

“How To Complete A Horizontal Well In The Gulf Of Mexico: Operators Share Experiences”, McLarty, J.,

World Oil V 214, No 10, Pages 69,71,73-75,79, Oct 1993 (3 Reference)

“Hydraulic Jet Technology : Versatile, Cost Effective”Bila, V.J.,

“ICCI Sand Control”, Pages I-17 – I-22

Proceedings Paper No. 29, 1994 (17 Pages; 8 References)

“New Completion Procedures Using Screens In Horizontal Openhole Completions In The North Sea”, Restarick, H;

Sanders, M., 2nd Annual Petroleum Network Education Conference (PNEC) Emerging Technology International Conference (Aberdeen, Scot, 94.06.01-03)

Proceedings Sect No 19, 1993 (19 Pages; 5 References)

“New Horizontal Completion Designs Facilitate Develop-ment And Increase Production Capabilities In Sandstone Reservoirs”, Whiteley, T G; Harrison, D5th World Oil Et Al Horizontal Well Technology International Conference (Hous-ton, 93.11.09-11)

Paper No. HWC 94-59, 1994 (11 Pages; 6 References)

“New Horizontal Openhole Completion Designs For Reser-voirs With Sand Producing Problems”, Restarick, H Can SPE/CIM/CANMET, Recent Advances In Horizontal Well Appl International Conference (Calgary, Can, 94.03.20-23) Preprints

Proceedings V 1, Pages 179-192, 1993 (8 References)

“New Horizontal Openhole Completion Designs For Reser-voirs With Sand Producing Problems”, Restarick, H 7th EAPG Improving Oil Recovery Europe Symposium (Moscow, Russia, 93.10.27-29)




Section 1

Proceedings Paper No. 22, 1993 (18 Pages; 8 References) SRLA# 566,852

“New Horizontal Openhole Completion Designs For Uncon-solidated Sands Enhance Production Potential”, Restarick, H5th World Oil Et Al Horizontal Well Technology Interna-tional Conference (Amsterdam, Netherlands, 93.07.14-16)

SPE Production Engineering, May 1987

“Overview of Gravel-Packed Completions”

Petroleum Technology V 42, No. 4, Pages 398-400, April 1990 (SPE-20005; 10 References)

“Problems In Cementing Horizontal Wells”, Sabins, F.

“Recommended Practice for Formation Damage Testing”,

Offshore July 1997 “Sand Control Complexity Grows with Water Depth”,

Petroleum Engineer International, July 1996

“Sand Control Screen Exhibit Degrees of Plugging”,

EP 92-1150”, Pages 116 – 122 “Shell Sand Control Manual,

American Oil Gas Reporter V 36, No 12, Pages 44-65, Dec 1993 (16 Pages)

“Stimulation & Completion”, Sackeyfio, A; Restarick, H; Thompson, J; Church, D; Callaway, C; Norton,

AIChE Journal (Vol. 26, No.4) July 1980

“The Critical Velocity in Pipeline Flow of Slurries”

Petroleum International V 56, No 5, Pages 50,52, July-Aug 1997 (In Spanish)

“The Use Of Slotted Liners” (Usan Forros Ranurados) Balli-nas, J Halliburton Mexico

“Unique Breaker System Treatment for Open Hole Horizon-

tal Completions”, 7th International Conference on Horizontal Well and Emerging Technologies, November 1995

American Oil Gas Reporter V 34, No 8, Pages 37-38,40-42, Aug 1991

“Variety Of Factors Affect Completions”, Bila, V J

Offshore Magazine, May 1996“Workover of a Failed Prepacked Screen in a Horizontal Well”,

Halliburton Internal Laboratory Report on Formation Sand Intermixing.

Halliburton Internal Research Laboratory Reports.

Tech Data Sheet SC-6063.

Spe/Iadc-21970, Proceeding Pages 619-631, 1991 (; 37 Refer-ences)

“Keys To A Successful Cement Job For A Horizontal Liner On Statfjord A Platform, Well A-37a : A Case History”, Tors-voll, A; Olaussen, S R; Almond, S W SPE/IADC Drilling Conference (Amsterdam, The Netherlands, 91.03.11-14)

Otc-8586, Proceeding V4, Pages 125-135, 1998 (; 4 References)

“New Completion Techniques Applied To A Deepwater Gulf Of Mexico TLP (Tension Leg Platform) Completion Suc-cessfully Gravel Pack An Openhole Horizontal Interval Of 2400 Feet”, Duhon, P; Holley, A; Gardiner, N; Grisby, T., 30th Annual SPE Et Al Offshore Technology Conference (Houston, 98.05.04-07)



July 199


Otc-8224, Proceeding V 4, Pages 665-672, 1996 (; 7 References)

“Coiled Tubing Workover Saves Horizontal Well In Lake Maracaibo”, Lizak, K; Patterson, J; Suarez, D; Salas, J 28th Annual SPE Et Al Offshore Technology Conference (Hous-ton, 96.05.06-09)

95-407

“Damage Removal Techniques Prove Successful In Hori-zontal Completions”, Callahan, T; Cheng, A; Hartford, C; Nowek, S; Archibald, K CADE/CAODC Spring Drilling Con-ference (Calgary, Can, 95.04.19-21) 1995 (10 Pages)

Hwc94-57

“A Method For Completing Horizontal Wells”, Surjaatmadja, J B Can SPE/Cim/Canmet Recent Advances In Horizontal Well Appl International Conference (Calgary, Can, 94.03.20-23) Preprints 1994 (7 Pages; 4 References)

EUR 39

"Full Scale Gravel Packing Model Studies," paper presented at the 1978 SPE European Offshore Petroleum Conference and Exhibition, London, Oct. 24-27. Rensvold, R.F. and Decker, L.

91-16

“Expanded Stimulation Capabilities In Horizontal Liners” Burns, T Sr., Cim Petroleum Society & Aostra Technology Conference (Banff, Can, 91.04.21-24) Preprints V 1, , 1991 (4 Pages; 7 References)

4031"Sand Particle Transport in Perforated Casing," presented at the 47th Annual Fall Meeting, San Antonio, TX, Oct. 8-11, 1972 . Haynes, C.D., and Gray, K.E.

6805

"Design of Gravel Pack in Deviated Wells," paper presented at the 1978 Annual Technical Conference and Exhibition, Denver. Oct. 9-12. Gruesbeck, C., Salathiel, W.M. and Echols, E.E.

6806 “A Method of Analyzing Performance of Gravel-Pack Com-pletions in Seria Field, Brunei”, Jones, R.W. ,Thorp, G.

7001“Visual Model Study Shows When and When Not to Pres-sure Wash Open Hole Gravel Packs”

7006"Particle Transport Through Perforations," paper presented at the 1978 SPE Symposium on Formation Damage Con-trol, Lafayette, Feb.15-16. Gruesbeck, C. and Collins, R.E.

7123

"Preliminary Results from Full-Scale Gravel Packing Stud-ies," paper presented at the 1978 SPE California Regional Meeting, San Francisco, April 1214. Shyrock, S.G., Dunlap, R.G., and Milhone, R.S.

7755 “Gravel Packing High-Volume Water Supply Wells”, Monroe, S.A. ,Penberthy Jr., W.L.

8428 “Design and Productivity of Gravel-Packed Completions”, Penberthy Jr., W.L. ,Cope, B.J.

9421

"Gravel Packing Studies in a Full-Scale, Deviated Model Wellbore," paper presented at the 1980 Annual Technical Conference and Exhibition, Dallas, Sept. 21-24. Shyrock, S.G.

10173 “Long Interval Open-Hole Gravel Packs”




Section 1

10173 “Long-Interval, Open-Hole Gravel Packs”, Gottschling, John C. ,Legan, Thomas L.

10654"Gravel Transport in Deviated Wellbores," paper presented at the 1982 SPE Symposium on Formation Damage, Lafay-ette, March 24-25, Hodge, R.M.

11008

"Gravel Packing for High Rate Completions,", presented at the 1982 Annual Technical Conference and Exhibition, New Orleans, LA, Sept. 26-29,16 Pages. McLeod, H.O. and Crawford, H.R.

11011

"The Influence of Placement Conditions on the Response of Gravel Packs to Production," paper presented at the 1982 SPE Annual Technical Conference and Exhibition, New Orleans, Sept. 26-29. Torrest, R.S.

12481

"Gravel Packing Highly Deviated Wells with Crosslinked Polymer System,", presented at the 1984 Formation Dam-age Control Symposium, Bakersfield, CA Feb 13-14 Under-down, D.R., Das, K., Nguyen, H.

12997

“The Design and Optimization of Gravel Packing Opera-tions in Deviated Wells," paper presented at the 1584 Euro-pean Petroleum Conference, London, England, Oct. 25-28. Peden, J.M., Russel, J., and Oyeneyin, M.B.

14162

"Recent Design, Placement, and Evaluation Techniques Lead to Improved Gravel Pack Performance,", presented at the 1985 Annual Technical Conference and Exhibition, Las Vegas, Nevada, Sept. 22-25. Ledlow, L.B., Sauer, C.W., and Till, M.V.

15057 “New Sand-Control Filter for Thermal Recovery Wells”, Toma, Peter ,Livesey, Declan ,Heldrick, Theodore

16980

"Gravel Pack Studies in a Full-Scale, High-Pressure Well-bore," paper presented at the 1987 SPE Annual Technical Conference and Exhibition, Dallas, Sept. 27-30. Schroeder, D.E. Jr.

17480"Monitoring HEC Gel Shearing to Optimize Improvements," presented at the 1988 SPE Regional Meeting, Long Beach, March. Cole, C., Shah, S., and Bellenger, B.

17664 “Gravel Packing for the Duri Steamflood”, Shryock, Stephen G. ,Ahmad, Syafriwal ,Meloy, James M. ,Kent, John W.

17925

“A Laboratory Investigation Of Cementing Horizontal Wells”, Wilson, M A; Sabins, F L6th Spe Middle East Oil Show (Manama, Bahrain, 89.03.11-14) Proceedings Pages23-33, 1989 (11 References)

18994 “Hydraulic Fracturing Slurry Transport in Horizontal Pipes”,

19476 “The Cardinal Rules of Gravel Packing To Avoid Formation Damage”, Winchester, P.H.



July 199


21385

“Use Of Oil-Base Gel System For Multiple Proppant Fractur-ing Of Horizontal Wells” McCabe, M A; Champetier, J L; Edwards, M G R7th SPE Middle East Oil Show Conference (Manama, Bahrain, 91.11.16-19) Proceedings Pages413-419, 1991 (; 14 References)

21836

“Logging And Perforating Of Horizontal Wells : An Innova-tive Approach”, Hall, D J; Walker, J L; Schmelzl, E G; Haene, T B SPE Rocky Mountain Region / Low Permeability Reservoirs Symposium (Denver, 91.04.15-17) Proceedings Pages 307-316, 1991 (; 7 References)

23450

“Expanded Stimulation Capabilities In Horizontal Liners” Burns, T SPE Permian Basin Oil & Gas Recovery Confer-ence (Midland, Texas, 92.03.18-20) Proceedings Pages 149-154, 1992 (7 References)

23770“Design and Application of Sintered Porous Stainless Steel Well Screens in Sand Control Completions”

23773“The Effects of Erosion Velocity on Filter Cake Stability Dur-ing Gravel Placement of Openhole Horizontal Gravel-Pack-ing Completions”

23773“The Effects of Erosion Velocity on Filter-Cake Stability Dur-ing Gravel Placement of Openhole Horizontal Gravel-Pack Completions”

23804“Formation Damage Control During Underreaming and Gravel Packing in an Over-pressured Reservoir”

23869 “BJ-Center Bit Performance Reduces Drilling Cost in Cali-fornia”, Quintana, J.L.

23909 “Innovative Steerable Underreaming BHA Design Over-come BOP Restrictions”, Raitt, Ferrier W.S. ,Boyle, John

23948

“Completion Of The KCC (Keystone Cattle Co.) 378-H : A Case History” Pritchett, J L Jr; Waak, K A; Chambers, R W; Conner, J L SPE Permian Basin Oil & Gas Recovery Con-ference (Midland, Texas, 92.03.18-20) Proceedings Pages 189-202, 1992 (; 9 References)

24606 “Dome PDC Technology Enhances Slim-Hole Drilling and Underreaming in the Permian Basin”, Carter, J.A., Akins, M.E.

24762“New and Simple Completion Methods for Horizontal Wells Improve the Production Performance in High-Permeability, Thin Oil Zones”

24993“An Effective Matrix Stimulation Technique for Horizontal Wells”

25431 “Technique Improves Openhole Gravel Pack”, Wilton, B.S. ,Swain, R.S. ,Tuttle, J.D. ,Harkey, Dee

25546

“Practical Horizontal Cementing Today”, Kettl, F C; Edwards, M G; Covington, R L., 8th Spe Middle East Oil Show Conference (Manama, Bahrain, 93.04.03-06) Pro-ceedings V 1, Pages 307-314, 1993 (23 References)




Section 1

26030 “Waste Minimizing Processing Technique for Solids Laden Biopolymer Gels”, Haagenson, R.V. ,Blount, C.G.

26086 “Emerging Coiled-Tubing Applications at Prudhoe Bay, Alaska”, Blount, C.G. ,Ward, S.L. ,Hightower, C.M. ,Walker, E.J.

27344“Dual Openhole Gravel Pack in Shaley Fine Sands” in SPE Drilling and Completions, December 1995

27344 “Dual Openhole Gravel Pack in Shaly Fine Sands”, Moricca, Giuseppe ,Ripa, Giuseppe ,Rucci, Domenico ,Pitoni, Enzo

27890

“Case Histories: New Horizontal Completion Designs Facili-tate Development And Increase Production Capabilities In Sandstone Reservoirs”, Harrison, R D Jr; Restarick, H; Grigsby, T F64th Annual SPE Western Region Meeting (Long Beach, Ca, 94.03.23-25) Proceedings Pages 431-445, 1994 (7 References)

29396 “New Bi-Center Technology Proves Effective in Slim Hole Horizontal Well”, Sketchler, B.C. ,Fielder, C.M. ,Lee, B.E.

29831

“Horizontal Completion Options In Reservoirs With Sand Problems”, Restarick, H Horizontal Wells (SPE Reprint Series No. 47) Pages 45-60, 1998 (ISBN 1-55563-076-6;; 7 References) SRLA# 598,634

29831

“Horizontal Completion Options In Reservoirs With Sand Problems”, Restarick, H, 9th Spe Middle East Oil Show Conference (Manama, Bahrain, 95.03.11-14) Proceedings V1, Pages 545-560, 1995 (7 References)

30116“Simple Approach to the Cleanup of Horizontal Wells With Prepacked Screen Completions”

30466 “New Concepts Lower Deep Water Drilling Costs”, Jenkins P.E., Roger W.

30474 “Simultaneous Drilling and Reaming with Fixed Blade Reamers”, Warren, T. M. ,Sinor, L. A. ,Dykstra, M. W.

31092“Long-Zone Squeeze Gravel Packs in Geopressured Reser-voirs in the Gulf of Mexico”

31147 “Gravel Placement in Horizontal Wells”

35081

“Drill-Cutting Removal In A Horizontal Wellbore For Cementing” Ravi, K; Weber, L Iadc/Spe Drilling Conference (New Orleans, 96.03.12-15) Proceedings Pages 347-355, 1996

35332 “Design and Application of Brine-Based Drilling Fluids”, Swartwout, R. ,Pearcy, R.

36403 “A Review of HPHT Drilling Campaign, 1991-1995”, Will-iams, M.J. ,Dumont, P.

36429“Evaluation of a New Technique for Removing Horizontal Wellbore Damage Attributable to Drill-in Filter Cake”

36454“Use of Longitudinally Fractured Horizontal Wells in a Multi-Zone Sandstone Formation”



July 199


36462 “Drilling and Underreaming Simultaneously: A Cost-Effec-tive Option”, Dewey, Charles H. ,Miller, Gregory C.

36678

“Comparison Of Perforating And Notching A Horizontal Wellbore For Hydraulic Fracturing”, Underwood, P J Annual SPE Technology Conference (Denver, 96.10.06-09) Pro-ceedings (Drilling And Completion) Pages 943-944, 1996 (Poster Session)

36867

“Finite Element Analysis Shows Screenout Development And Cement Bond Destruction In Horizontal Wells”, Surjaat-madja, J B 2nd SPE Horizontal Well Technology Interna-tional Conference (Calgary, Can, 96.11.18-20) Proceedings Pages 65-72, 1996 (8 References) Srla# 641,573

37110

“Slotted-Liner Completions Used In The First Horizontal Wells In Mexico”, Navarro, J B2nd Spe Horizontal Well Technology International Conference (Calgary, Can, 96.11.18-20) Proceeding Pages 613-618, 1996 (4 Refer-ences)

38157 “High Productivity Open Hole Gravel Packs in Depleted Per-meable Sands”, Pitoni, E. ,Ripa, G. ,Lorefice, R. ,Formisani, D.

38403

“Advances In Sliding Sleeve Technology And Coiled Tubing Performance Enhance Multizone Completion Of Abnormally Pressured Gulf Of Mexico Horizontal Well”, Plauche, R; Koshak, W E 2nd SPE International Coiled Tubing Assem-bly North American Coiled Tubing Roundtable(Montgomery, Texas, 97.04.01-03) Proceeding 1997 (13 Pages; 4 Refer-ences)

38613 “Development and Case Histories of an MWD Directional Drilling Package for 2-3/4" Openhole”, Blount, C.G. ,Mooney, M.B. ,Smith, B.E. ,Quinn, D. ,Larson, E.B.

38759

“Drilling And Completing Multilateral Horizontal Wells In The Middle East”, Taylor, R W; Russell, R Annual SPE Technol-ogy Conference (San Antonio, 97.10.05-08) Proceeding (Production Operations and Engineering/General) Pages 115-127, 1997 (7 References)

50146

“New Completion Techniques Applied to a Deepwater Gulf of Mexico TLP Completion Successfully Gravel Pack an Openhole Horizontal Interval of 2400 Feet”, Duhon, Pete, Holley, Alan ,Gardiner, Nick ,Grigsby, Tommy

50146

“New Completion Techniques Applied To A Deepwater Gulf Of Mexico TLP (Tension Leg Platform) Completion Suc-cessfully Gravel Pack On Openhole Horizontal Interval Of 2400 Feet”, Duhon, P; Holley, A; Gardiner, N; Grigsby, T., SPE Asia Pacific Oil & Gas Conference (Perth, Western Australia, 98.10.12-14) Proceeding Pages 477-487, 1998 (; 5 References)




Section 1

ICOTA 96005“Acid Stimulation of Openhole Horizontal Section Behind Prepack Screen Using Coiled Tubing and New Isolation Method”

39469

16931 “Gravel Packing of Horizontal Wells”

48976“Advancing Horizontal Well Sand Control Technology; An OHGP using Synthetic OBM”, BP



July 199

Section

1414. Marketing Information

nd

s from

ction.

packer

ool

or toe-

h

leted

es,

en

14.1 Brochure No. H00180—Horizontal Washdown System

14.1.1 One-trip acid cleanup saves rig time, improves production Halliburton’s Horizontal Washdown System delivers acid soaks to remove filter cake aenhance production.

Developed for openhole, horizontal completions, the system is available for screen size2 7/8 to 5 1/2 in.

14.1.2 One trip acid cleanup without coiled tubing• Enhance production—Remove filter cake from screens and clean the openhole se

• Save rig time, cut equipment costs—In a single run, the system sets the screen andthen performs openhole and screen cleanup. No coiled tubing is required.

• Avoid premature setting of the packer—An anti-preset mechanism on the running tprevents presetting of the horizontal packer at pumping pressures up to 5000 lb.

• Select the optimal treatment—Design the system to spot fluids or soak heel-to-toe to-heel.

14.1.3 Leading wash technology allows fluid weight changes, minimizing fluid loss

• Washcup assembly fits screens as small as 2 7/8 in. Proven in extensive testing, the wascups have unmatched acid resistance and can inflate openhole packers.

• Closing sleeve creates a path for the circulating fluids so the cleanup can be compwithout losing LCM or other fluids behind the screen.

• OMNI™ Valve minimizes fluid loss by allowing acid spotting and fluid weight changreducing formation exposure to acid.

• Acid service float shoe provides a path to circulate acid around the end of the screduring cleanup of screen assembly.

9 Page 14-1 Section 14—Marketing Information


Section 1
4—Marketing Information Page 14-2 July 1999

July 199

Section

1515. Horizontal Gravel Pack Survey

d

rly

id as shifts signif-either rob-

ud

Mud

Horizontal Gravel Pack Variables and Rules-of-Thumb for DesignA group of technical advisors and solutions team members were asked to fill in a survey on horizontal gravel pack best practice rules-of-thumb for design purposes. This survey was undertaken to get an idea of how much variance there was between the various personnel and locations prior to finalizing the Halliburton Horizontal Gravel Pack Best Practice Manual. Mike Sanders’ answers were provided as a starting point.

1. What is the preferred Drill-in fluid for a horizontal gravel pack?

Mike Sanders: Calcium Carbonate Based System / Salt Based System / Oil Based MuSystem?

Travis Hailey: Calcium Carbonate Based System. Can be weighted as appropriate, faieasily removed.

Colby Ross: No comment.

Ron Dusterhoft: Calcium Carbonate is definitely the preferred system if we can use aca fluid to treat the filter-cake after the gravel pack. If we can not use acid, my preferenceto the sized salt systems. In retrospect, however, I feel that in the future there will be a icant push on using the synthetic mud systems and we will have to address this issue chemically or mechanically or both. If we move in this direction, mechanical diversion, pably better than CAPS will be required.

Harvey Fitzpatrick: Calcium Carbonate Water Based System or CaCO3 – Synthetic BM

Jackie LaFontaine: No comment.

Ian Mickelburgh: Calcium Carbonate Based System / Salt Based System / Oil Based MSystem

Nicholas Gardiner: Calcium Carbonate Based System

Ron Van Petegem: Calcium Carbonate Based System / Salt Based System / Oil BasedSystem

9 Page 15-1 Section 15—Horizontal Gravel Pack Survey


Section 1

Ashley Donaldson: No comment.

2. Typical Methylene Blue Test (MBT) Values for Cation Exchange Capacity?

Mike Sanders: <100, < 30 preferred

Travis Hailey: No comment.


Ron Dusterhoft: No comment.

Harvey Fitzpatrick: <100 , < 30 preferred


Ian Mickelburgh: <10

Nicholas Gardiner: No comment.

Ron Van Petegem: <10

Ashley Donaldson: Measures the clay content expressed in ppb. Prefer to keep this content < 5 ppb.

3. Typical Particle Plugging Test (PPT) Values?

Mike Sanders: <12 using a PPA with grade 2 disks at temperature




Harvey Fitzpatrick: <12 using a PPA with grade 2 disks at temperature


Ian Mickelburgh: <12 using a PPA with grade 2 disks at temperature


Ron Van Petegem: <12 using a PPA with grade 2 disks at temperature

Ashley Donaldson: <12 using a Particle Plugging Apparatus (PPA) with grade 2 ceramic disks at temperature. Spurt values of 0.5-4 mls and total volume of 8-20 are acceptable numbers

4. Typical Particle Plugging Test (PPT) Cake Values?

Mike Sanders: < 1/32 in.

5—Horizontal Gravel Pack Survey Page 15-2 July 1999

July 199


for ns.

nd




Harvey Fitzpatrick: < 1/32 in.


Ian Mickelburgh: < 1/32 in.


Ron Van Petegem: < 1/32 in.

Ashley Donaldson: < 1/32 in.

5. Drill-in Fluid Insoluble Solids—Total Concentration?

Mike Sanders: <20 ppb

Travis Hailey: Maximum particle size should be < ½ screen gauge size (or micron ratingmesh filters) for screen-only completions, < 1/7 prepack sand size for prepacked scree



Harvey Fitzpatrick: <20 ppb

Jackie LaFontaine: No Comment

Ian Mickelburgh:<20 ppb

Nicholas Gardiner: <20 ppb

Ron Van Petegem: <20 ppb

Ashley Donaldson: <20 ppb, Like to keep the drill solids to less than 4-5%.

6. Condition drill-in fluid to what after drilling OH section?

Mike Sanders: No comment.



Ron Dusterhoft: After drilling OH section the hole should be cleaned and conditioned athen displaced over to a solids free drill in fluid

Harvey Fitzpatrick: > 90 % circulatable hole volume




Section 1

c.

at

Ian Mickelburgh: No comment.


Ron Van Petegem: This can be a big time saver, if we can avoid mud conditioning all together (i.e.: to condition mud to 270 mesh, this sometimes take 40-60 hours), just plan to replace mud to new mix when screens on bottom.


7. Minimum required velocity to clean OH in horizontal section (ft/sec)?

Mike Sanders: 250

Travis Hailey: Should change somewhat with different drill-in fluids—with calcium carbonate based system of average weight (8.5-10.0 lbm/gal), should be 300 ft/min.


Ron Dusterhoft: 250

Harvey Fitzpatrick: 250 ft/min minimum or recommended - 500 ft/min, if ECD below fra


Ian Mickelburgh: 250

Nicholas Gardiner: Should be calculated using Force4 spreadsheet.

Ron Van Petegem: 250


8. Displacement stages to cover at least xx (ft)

Mike Sanders: 300

Travis Hailey: Depends on solids loading, tubulars, etc.


Ron Dusterhoft: I prefer contact or exposure time to length of spacer. I would shoot forleast 1 minute contact time and would suggest 2 stages in the clean up.

Harvey Fitzpatrick: 300 (This is apparently highly dependent on system)


Ian Mickelburgh: 300


Ron Van Petegem: 300



July 199


be

s,

9. Number of OH volumes for displacement?

Mike Sanders: 3

Travis Hailey: Varies—2 minimum.


Ron Dusterhoft: 3

Harvey Fitzpatrick: 3 or until data giving indication of “clean hole”


Ian Mickelburgh: 3

Nicholas Gardiner: 5 annular volumes

Ron Van Petegem: 3


10. Preferred cleanup fluid for calcium carbonate based system?

Mike Sanders: xx% HCl, Sulphamic Acid, etc.

Travis Hailey:5-15% HCl, (readily available, known characteristics)


Ron Dusterhoft: 5% HCl would be my preferred choice although some evaluation shoulddone to ensure that the formation is compatible with HCl.

Harvey Fitzpatrick: xx% HCl, Sulphamic Acid, what about Sulphamic Acid + Claysafe 5


Ian Mickelburgh: xx% HCl, Sulphamic Acid, etc.

Nicholas Gardiner: 10% HCl

Ron Van Petegem: xx% HCl, Sulphamic Acid, etc.


11. Preferred cleanup fluid for salt based system (depends on tempera-ture)?

Mike Sanders: xx% HCl, MSA Acid, < Saturated Brine, Enzymes, Oxidizers, HypochloriteSodium Perborate, etc.





Section 1

Ron Dusterhoft: Depending upon temperature, in low temp applications the use of enzyme breakers would be preferred. At higher temperatures I would prefer to develop ViCon with activators to break the filtercake. We must be careful in running an oxidizing agent in any acid as we can not control corrosion. Therefore I would tend to avoid the acid in nearly all applications here unless the acid was used exclusively as the breaker itself.

Harvey Fitzpatrick: Yes and salt saturated HCl too. xx% HCl, MSA Acid, < Saturated Brine, Enzymes, Oxidizers, Hypochlorites, Sodium Perborate, etc.


Ian Mickelburgh: xx% HCl, MSA Acid, < Saturated Brine, Enzymes, Oxidizers, Hypochlo-rites, Sodium Perborate, etc.

Nicholas Gardiner: 10% HCl w/Saturated Brine.

Ron Van Petegem: xx% HCl, MSA Acid, < Saturated Brine, Enzymes, Oxidizers, Hypochlo-rites, Sodium Perborate, etc.


12. Preferred cleanup fluid for OBM?

Mike Sanders: Base Oil + Surfactant Sweep + Mutual Solvents?, CLEANBORE, etc.

Travis Hailey: If filter cake not needed during gravel pack>>Base Oil + Surfactant Sweep + Mutual Solvents, If filter cake left in place for gravel pack>> N-ver-Sperse A or O, plus fluid to remove filter cake solids, e.g. 5-15% HCl


Ron Dusterhoft: After the gravel pack has been completed, my preference to clean up OBM would be a fluid with a very high loading of mutual solvent. If there is carbonate used to build the filtercake, then I would prefer to use a water based system with mutual solvent to attach the emulsion in the filtercake followed by an acid to attack the carbonate.

Harvey Fitzpatrick: Base Oil + Surfactant Sweep + Mutual Solvents?, CLEANBORE, etc. OSA +mutual solvent + Hyflo


Ian Mickelburgh: Base Oil + Surfactant Sweep + Mutual Solvents?, CLEANBORE, etc.

Nicholas Gardiner: Alternating Surfactant system followed by 5% HCl

Ron Van Petegem: Base Oil + Surfactant Sweep + Mutual Solvents, CLEANBORE, etc.


13. Gravel Pack Carrier Fluid of choice for a Horizontal Gravel Pack?

Mike Sanders: Brine / Lightly gelled brine / Carrier fluid using viscosity to carry sand into place (HEC, Xanthan, FloPac).


July 199


Travis Hailey: Brine


Ron Dusterhoft: With the Alpha/Beta approach I would prefer ungelled brine to place the gravel. In a squeeze type treatment we really have no mechanical solution for this application. FloPac would probably be my preferred choice if we had a better shunt or diversion system.

Harvey Fitzpatrick: Brine or oil. Brine / Lightly gelled brine / Carrier fluid using viscosity to carry sand into place (HEC, Xanthan, FloPac).


Ian Mickelburgh: Brine / Lightly gelled brine / Carrier fluid using viscosity to carry sand into place (HEC, Xanthan, FloPac).

Nicholas Gardiner: Brine

Ron Van Petegem: Brine / Lightly gelled brine / Carrier fluid using viscosity to carry sand into place (HEC, Xanthan, FloPac).


14. Optimum Sand Concentration Range (lb/gal) for a horizontal gravel pack?

Mike Sanders: 0.5 – 2 ppg

Travis Hailey: 0 – 2 ppg


Ron Dusterhoft: 0.5 – 2 ppg

Harvey Fitzpatrick: 0.5 – 2 ppg


Ian Mickelburgh: 0.5 – 2 ppg

Nicholas Gardiner: 0.5 – 2 ppg

Ron Van Petegem: 0.5 – 2 ppg


15. Preferred / typical gravel used for a horizontal gravel pack?

Mike Sanders: Sand / Carbolite / ISOPAC-LitePak?

Travis Hailey: Sand




Section 1

pm BHP

1- .

tool d loss

to

Ron Dusterhoft: Carbolite or sand

Harvey Fitzpatrick: Carbolite


Ian Mickelburgh: Carbolite

Nicholas Gardiner: Carbolite/Sand

Ron Van Petegem: Sand / Carbolite / ISOPAC-LitePak


16. Typical pump rates required? Spotting sand to tool (bpm), Circulating sand into annulus (bpm)

Mike Sanders: 6-8 bpm for spotting sand to tool and 1-3 bpm for circulating sand into annulus depending upon BHP and other variables.

Travis Hailey: 6-8 bpm for spotting sand to tool and 1-3 bpm for circulating sand into annulus depending upon BHP, hole & screen size, and other variables.


Ron Dusterhoft: 6-8 bpm for spotting sand to tool and 1-3 bpm for circulating sand into annulus depending upon BHP and other variables.

Harvey Fitzpatrick: Typical Spotting Rate as per HzGPSim design – 1 to 5 BPM. 6-8 bfor spotting sand to tool and 1-3 bpm for circulating sand into annulus depending uponand other variables


Ian Mickelburgh: Typical spotting rates are 6-8 bpm depending upon workstring ID and3 bpm (depending upon BHP and other variables) for circulating sand into the annulus

Nicholas Gardiner: Typical pumping rates are 1.5 – 6 bpm. 6-8 bpm for spotting sand to and 1.5 – 6 bpm for circulating sand into annulus depending upon frac gradient and flui

Ron Van Petegem: 6-8 bpm for spotting sand to tool and 1-3 bpm for circulating sand inannulus depending upon BHP and other variables.


17. Preferred workstring OD for a horizontal gravel pack?

Mike Sanders: 4 ft

Travis Hailey: 4 ft DP although several others are acceptable.


Ron Dusterhoft: 3.5 – 4 ft


July 199


Harvey Fitzpatrick: 4 ft Size to give 8 to 30 ft/sec bulk velocity



Nicholas Gardiner: Depends on BHA, but larger is better for cleanup

Ron Van Petegem: 4 ft


18. Tool configuration required for a horizontal gravel pack?

Mike Sanders: Circulate through sacrificial screen and then circulated through main produc-tion screen until sandout.

Travis Hailey: Circulate predominantly through sacrificial screen during Alpha wave and then circulate through main production screen during Beta wave until sandout


Ron Dusterhoft: Circulate through sacrificial screen and then circulated through main production screen until sandout. I like this approach.

Harvey Fitzpatrick: Circulate through sacrificial screen and then circulated through main production screen until sandout.


Ian Mickelburgh: Circulate through sacrificial screen and then circulated through main production screen until sandout.

Nicholas Gardiner: Circulate through sacrificial screen and then circulate through main production screen until sandout.

Ron Van Petegem: Circulate through sacrificial screen and then circulated through main production screen until sandout.


19. Recommended length of sacrificial (tattle-tale) screen (ft) for a hori-zontal gravel pack?


Travis Hailey: 10-20 ft (not critical)

Colby Ross: 20 ft

Ron Dusterhoft: 10 to 30 ft depending upon the volume of fluid to be circulated

Harvey Fitzpatrick: Just enough…. Velocity through gap less than 1 ft/sec



Section 1

er

ing

rnate re lost

S



Nicholas Gardiner: I understand that 30 ft would be easier to space-out

Ron Van Petegem: I’m not absolutely sure, but as I remember, a good number is 10 ft p2000 bbl at 5 bpm


20. Placement procedure for a horizontal gravel pack?

Mike Sanders: Alpha-Beta Wave / Alternate Path if available

Travis Hailey: Alpha-Beta Wave preferred / Alternate Path only if necessary due to varypermeability in producing interval


Ron Dusterhoft: Alpha beta wave is the preferred approach to get a complete pack. Altepath is interesting when there is a risk of exceeding the fracture gradient or if returns aduring the treatment

Harvey Fitzpatrick: Alpha-Beta Wave / Alternate Path if available. Alpha beta plus CAPrecommended best practice. Or CAPS H FracPac


Ian Mickelburgh: Alternate Path if available

Nicholas Gardiner: Alpha-Beta Wave / Alternate Path if available

Ron Van Petegem: Alpha-Beta Wave / Alternate Path if available


21. Prepad for vertical section of workstring prior to a horizontal gravel pack?


Travis Hailey: Yes (but do need to ensure wellbore & tubulars are clean)



Harvey Fitzpatrick: No, use pipe velocity to reduce gravel string out


Ian Mickelburgh: Yes


July 199


om 4

Nicholas Gardiner: No

Ron Van Petegem: Depends upon base fluid density


22. Prepad to even out permeability variations prior to a horizontal gravel pack?


Travis Hailey: No (not normally, but may be advisable or even necessary if there is a large permeability variation which also requires use of AP equipment



Harvey Fitzpatrick: No, use intact wall-cake primary. Reverse out and use FL pill to regain returns if necessary


Ian Mickelburgh: Possibly

Nicholas Gardiner: No

Ron Van Petegem: Not if there are no initial losses. Without losses the pre-pad will not get at the correct place anyway


23. Washpipe OD/Screen ID Ratio for a horizontal gravel pack?

Mike Sanders: > 0.75

Travis Hailey: > 0.75 also Screen OD/Open or Cased Hole ID Ratio of <0.75


Ron Dusterhoft: > 0.75

Harvey Fitzpatrick: > 0.75


Ian Mickelburgh: > 0.75

Nicholas Gardiner: > 0.75

Ron Van Petegem: > 0.75 - This need to be reworded to focus on washpipe/screen ID versus Screen OD/Hole ID ratio. I noticed that on long GP’s, by stepping down the wash pipe frto 3.5 in. a frac on the beta wave can be avoided



Section 1

r

al

r


24. Preferred annular clearance between screen OD and open hole (inches) for a horizontal openhole gravel pack?


Travis Hailey: 1 ¼ to 2 in. radially (2 ½ to 4” on diameter)



Harvey Fitzpatrick: Max available and not have liner friction limiting to production flow oenough to prevent leakoff too high as a minimum.



Nicholas Gardiner: <0.75

Ron Van Petegem: See above, Minimum clearance .4” radial with centralizers, .25” radiwithout centralizers, This is due to screen being off center


25. Preferred annular clearance between screen OD and casing ID (inches) for a cased hole horizontal gravel pack?


Travis Hailey: ¾ to 1 ½ in. radially (1 ½ to 3 in. on diameter)



Harvey Fitzpatrick: Max available and not have liner friction limiting to production flow oenough to prevent leakoff too high as a minimum.



Nicholas Gardiner: <0.75

Ron Van Petegem: 120° / 180° / Only perforate the sides / 360°I like to add that this is also depending if we run centralizers or not


26. Preferred perforation phasing for cased hole horizontal gravel packs?


July 199


Mike Sanders: 120° / 180° / Only perforate the sides / 360°

Travis Hailey: 180° low side


Ron Dusterhoft: Prefer open hole only for horizontal gravel pack procedures. If the well is cased, I would recommend an alternate path approach and exceed the fracture gradient in a squeeze pack approach. I would prefer to be fully phased and pack every perforation that I can.

Harvey Fitzpatrick: Plus or minus 45 degrees from the 90 and 270 (horizontal ) phasing.


Ian Mickelburgh: 120° / 180°

Nicholas Gardiner: Regular low side perforating (shots at 120 and 240?)

Ron Van Petegem: 120° / 180° / Only perforate the sides / 360°I like to add that this is also depending if we run centralizers or not


27. Preferred SPF for cased hole horizontal gravel packs?

Mike Sanders: 8/12/etc?

Travis Hailey: maximum practical within 180° low side


Ron Dusterhoft: 8

Harvey Fitzpatrick: As many effective spf as needed to not limit flow.


Ian Mickelburgh: 8/12/etc.

Nicholas Gardiner: Only need 6-8

Ron Van Petegem: 8/12/etc.


28. Preferred perforating gun for cased hole horizontal gravel packs?

Mike Sanders: KISS, Big Hole, etc.

Travis Hailey: Big Hole


Ron Dusterhoft: KISS or big hole



Section 1

Harvey Fitzpatrick: Clean Hole size rules.


Ian Mickelburgh: KISS

Nicholas Gardiner: KISS

Ron Van Petegem: KISS, Big Hole, etc.


29. Required % of returns to keep Alpha/Beta wave going in a horizontal gravel pack?


Travis Hailey: The rate rather than the % returns. Varies with carrier fluid and proppant (consult HzGPSim), but should create 200-250 ft/min velocity of slurry over top of dune filling +-60% of height of wellbore (roughly equals velocity of 100 ft/min with entire wellbore open, before dune forms)


Ron Dusterhoft: Without a CAPS screen, 100%. With a CAPS screen, 75% or better.

Harvey Fitzpatrick: Velocity needed, not % or rate.



Nicholas Gardiner: Preferred 60% - Absolute minimum 40%

Ron Van Petegem: This is depending on so many factors, that we should recommend HzGPSim model


30. Required annular velocity between screen and OH / casing to place sand properly in a horizontal open hole gravel pack?

Mike Sanders: Minimum 1 ft/sec

Travis Hailey: Varies with carrier fluid and proppant (consult HzGPSim), but should create 200-250 ft/min velocity of slurry over top of dune filling +-60% of height of wellbore (roughly equals velocity of 100 ft/min with entire wellbore open, before dune forms)


Ron Dusterhoft: Minimum 1 ft/sec

Harvey Fitzpatrick: Minimum 3 ft/sec


July 199


to

ith at

C /

etc.


Ian Mickelburgh: Minimum 1 ft/sec

Nicholas Gardiner: Minimum 1 ft/sec during alpha wave

Ron Van Petegem: Minimum 1 ft/sec


31. If fluid loss pills are required to minimize fluid loss during the pack what type do you recommend?

Mike Sanders: Calcium Carbonate Based System / Salt Based System / K-MAX / HEC / etc.

Travis Hailey: Same material as the original filter cake from the drill-in fluid—may havebe modified to avoid significant movement of the Alpha wave by viscous fluid


Ron Dusterhoft: My preference would be a polymer or starch which could be pumped wan accompanying breaker. I would try to pump a pill and if extreme losses persist, lookadding a carbonate.

Harvey Fitzpatrick: Preferred – whatever make us the most money. Minimum – K MAX


Ian Mickelburgh: Calcium Carbonate Based System / Salt Based System / K-MAX / HEetc.

Nicholas Gardiner: Viscosified fluid compatible with original DIF. Usually solids free version of DIF

Ron Van Petegem: Calcium Carbonate Based System/Salt Based System/K-MAX/HEC/A particulate pill as this creates hole stability by forming/repairing the mud cake


32. Type packer recommended for horizontal gravel packs?

Mike Sanders: VTA, VTL

Travis Hailey: MGP or VTA, prefer bore larger than screen ID

Colby Ross: VTA, VBA, AGP


Harvey Fitzpatrick: Halliburton


Ian Mickelburgh: VTA, VTL



Section 1

Nicholas Gardiner: VTA, VTL

Ron Van Petegem: VTA / VBA/ AGP. Take out VTL, this packer is being obsoleted


33. Length of upper extension recommended for horizontal gravel packs?

Mike Sanders: 3 ft

Travis Hailey: 3 ft (or more, depending on need for & difficulty of locating position without weight down—affected by depth, deviation, wellbore tortuosity, workstring type)

Colby Ross: 6 ft


Harvey Fitzpatrick: No comment.


Ian Mickelburgh: 3 ft


Ron Van Petegem: 3 ft


LENGTH OF LOWER EXTENSION RECOMMENDED FOR HORIZONTAL GRAVEL PACKS?


Travis Hailey: As necessary to house service tool

Colby Ross: 20 ft


Harvey Fitzpatrick: No comment.




Ron Van Petegem: Minimum required length to do the job


34. Amount of blank pipe recommended for horizontal gravel packs? (ft)



July 199


ove

p

op

ases

l-

Travis Hailey: Enough so annular volume around Blank equals workstring volume if possible—otherwise not critical, minimum 30 ft. (Screen must extend minimum 30 ft ab[toward heel] producing interval.)



Harvey Fitzpatrick: MD to give ~ 30 ft. TVD length



Nicholas Gardiner: Minimum of 30ft would rather have enough to hold all of the washcuassembly if will do workstring conveyed washing.

Ron Van Petegem: We should try to recommend to have top of screen 10 ft above the tperforation in cased hole or top above 65° to avoid production through uncovered


35. Centralizers recommended for horizontal gravel packs?

Mike Sanders: Yes

Travis Hailey: Yes


Ron Dusterhoft: Yes

Harvey Fitzpatrick: Yes


Ian Mickelburgh: Yes

Nicholas Gardiner: Yes

Ron Van Petegem: Depending on length of hole and screen size versus hole ID, in most cYES


36. If Centralizers are recommended for horizontal gravel packs, what type?

Mike Sanders: Spir-O-Lizer, Ray Oil Tool, Bow Spring, Typical Half Moon Metal Centraizers, Slip on Centralizers, Halliburton Centraflow?

Travis Hailey: Spir-O-Lizer, Ray Oil Tool




Section 1

Ron Dusterhoft: Spir-O-Lizer

Harvey Fitzpatrick: Rib type with thick (wide) ribs.


Ian Mickelburgh: Spir-O-Lizer, Ray Oil Tool (OH), Halliburton Centraflow ( ICGP)

Nicholas Gardiner: Solid, angled vane, non fixed

Ron Van Petegem: I do not believe that Spir-O-Lizers add any value on a Alpha/Beta wave pack. So in cased hole I would recommend the blade type, and in open hole I would recom-mend the wide fluted type.


37. How far up into the OH or casing do you recommend running the production screen for horizontal gravel packs?


Travis Hailey: 30 ft



Harvey Fitzpatrick: OH – almost to top of pay sand. Casing – not



Nicholas Gardiner: 1 joint

Ron Van Petegem: 10 ft above top perforation and preferably above 65° for open hole

Ashley Donaldson: No comment.0

38. Maximum Deviation to set packer for horizontal gravel packs?


Travis Hailey: No restriction.



Harvey Fitzpatrick: None


Ian Mickelburgh: 65°


July 199


Nicholas Gardiner: 90

Ron Van Petegem: 65°


39. Type screen recommended for oh horizontal gravel packs?

Mike Sanders: ELP unless fines are a big problem then PoroPlus

Travis Hailey: PLP unless fines, high flux, or mechanical damage risk (rough window, reser-voir compaction) are a big problem then PoroPlus


Ron Dusterhoft: ELP unless fines are a big problem then PoroPlus

Harvey Fitzpatrick: ELP or PoroPlus or All Welded


Ian Mickelburgh: PLP

Nicholas Gardiner: PLP, but WW is suitable

Ron Van Petegem: ELP unless fines are a big problem then PoroPlus add PLP


40. Type screen recommended for cased hole horizontal gravel packs?


Travis Hailey: PLP unless fines, high flux, or mechanical damage risk (rough window, reser-voir compaction) are a big problem then PoroPlus


Ron Dusterhoft: PoroPlus due to protective shroud which may minimize erosion if perfora-tions are left open.

Harvey Fitzpatrick: ELP or PoroPlus or All Welded


Ian Mickelburgh: PLP

Nicholas Gardiner: PLP, but WW is suitable provided no perforating burrs

Ron Van Petegem: ELP/PLP All welded




Section 1



Horizontal oh gp best practices h02233

Engineering

Transcript of Horizontal oh gp best practices h02233