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SPE 27092

Coiled-Tubing Completion Procedure Reduces Cost and Time forHydraulically Fractured Wells

D.A. Harms, Mobil E&P U.S. Inc.

SPEMember

Copyright 1994, SocMy of Petr oleum Engineer s, Inc .

This peper wee prepsred for presenta tion a t t he Western Regional Meeting bald in Long Seach , CaffiOr nf a, U .S.A. , 22-25 Mar ch 1~.

This paper wee eeleofed for presentat ion by an SPE Program Committee following review of information c or rt it na d I n a n e bs t rs ct submtied by t he aut hor (e ). Cont ente of thepaper .se present ed , heve not been r ev iewed by t he soc ie ty of Petr oleum Engineers and are sub ject to cor rec tion by t he author( a) , The mat erial , se presented, doea not neceaserily ref fect

,.. . e-any pmbori m me WCWIY”1 , e. . - e-. .. -. .=...

.., .’ D ,,A ,,~ Fnoi_rs. its ~ffi=, or ~m~m, papem Wa~nted at SPE ~~nga em s@ecf t o pubf i iat ion review by Edhorial COmmlffWa of the %Oiefy,,,. ._...-m ,,,.. .ti * ~n~, The ~r~ eh~~ oon~in ~nspicuous acknowledgment

o f Petr oleum Engineers . Parmisei in t oCOPYisrest rict ed t oan ah- t o f not mcfe t hm w me. I II IWULU~WB-S-J ... . - .-.

of where and by whom the pew is presented. Wrne Librtisn! SpE, p.o. Sox m, ~mhwd~n, TX 7~1 U. S.A.,Telex 1SS24S SPEUT.

ABSI’RACT

A unique completion procedure has been developed to

reduce the cost and time to hydraulically fracture welis.

In the procedure, coiled tubing is used to replace

conventional tubing in most of the operations. This

procedure is made possible by a wellhead design that

enhances safety and simplifies switching from oneoperation to the next.

Hydrauiic fracturing coats comprise the majority of the

total cost for new diatomite welia. Muitiple stimulations

can be compieted in a single day by using coiled tubing to

cleanout or piace sand plugs which are used to isolate the

perforated interval between hydraulic fracture

stimulations. This allows significant savings to be realized

by fuiiy utii izing the service company’s entire minimum

daiiy charge. The coiled tubing also functions as a dead

string during fracture stimulations which allows real time

monitoring of downhole fracturing pressures.

The new wellhead incorporates two unique ideas: 1) a

hammer union tree cap which replaces the conventional

tlangeii tree *p. ~=~wm! te ~he ~r~ ~p iS a blast joint

that provides protection from sand erosion

when using coiied tubing as the dead string. The wellhead

design enables the tree cap (with attached blast joint) to be

References and illustrations at end of Paper

quickiy and easily exchanged with a fullbore lubricator

2) a full opening gate valve located between the casinghead

and the fracture wellhead. The valve is a safety device

that ailows any part of the wellhead to be removed whil

ensuring a completely controlled condition.

INTRODUCTION

The coiled tubing completion procedure was developed fo

diatomite welia at Mobil’s Lost Hills field. The field

located on the southeast nose of the Lost Hilis Anticiine i

the San Joaquin Basin (Kern County, Caiifomia). Th

reservoir consists of 600 to 800 ft of three m~”o

iithologies: interbedded diatomite, diatomaceous shale an

diatomaceous silt.

These three iithologies have different mechanica

properties that greatly affect their abiiity to fracture

Attempting to fracture stimuiate intervais greater the

200’ has proven ineffective in the past due to the partiavertical coverage of the intervai. Therefore muitipl

fracture stimulations are required to effectively deplete th

reservoir.

Hydrauiic fracture completions comprise approximatel

65% of the total weil cost. A procedure to reduce the co

and make new well economics more attractive w

required to continue the development of the fieid. Th

paper outlines anew procedure that effectively reduces t

cost and time required to complete the weiis.

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Coiled Tubing Completion Procedure Reduces Cost

2 and Time for Hydraulically Fractured Wells SPE 27892

COi+iiTmTIaWL mommwu

To identify major cost drivers for the conventional

completion procedure, 1992 completion charges were

tabulated on a Pareto diagram (see fig. 1). As expected,

the fracture stimulation costs accounted for most of the

total completion cost. The sum of the six fracture service

company expenses comprised 73% of the total completion

cost during 1992.

I i ’m rt h.r rcw im.y ~D&@ed that of the six fracture service“, ..-. .- ..-,

company categories, hydraulic fracture pump charges

were the most significant. These charges accounted for

30$10of the total. The cost of the saiid mid the frac gel.

were ZiSO i%CO@W&Xi having a rn.~”or effect on

completion costs resulting in 18%and 17%of the expenses

respectively.

Increasing or decreasing the cost of the other company

services (workover rig, perforating etc.) has little effect on

the overall completion cost. The Pareto diagram

corroborates this by showing that none of the non-fracture

services or equipment account for more than 10% of the

overaii cost.

In addition to having high stimulation costs, considerable

time was required to complete the well using the

conventional procedure. Time intensive operations

included: running in and out of the hole with the tubing,moving and pressure testing the bridge plug, and switching

the wellhead cotilguration in preparation for fracturing.

An overview of the conventional procedure is outlined in

table 1.

Using this procedure, only one perforated interval could be

fmctured per day. Typical Mobil Lost Hills fmcture

stimulations require pump times between 1 hour and 1.5

hours per perforated intervaL However, since the service

company charges a four hour minimum for their pumping

equipment, by performing otdy one fmcture stimulation

per day, 65% to 75% of the pump expenses incurred were

not used.

Additionally, a snubbing assist unit was required to work

on these wells since they would flow after being fmcture

stimulated. An average of 2 days was required when using

the snubbing assist unit to remove the bridge plug and run

a production string. W]th the conventional completion, a

well with 5 perfomted intervals requires 8 days of

opemtions prior to placing the well on production.

COILED TUBING PROCEDURE

The conventional completion procedure was altered in

three main areas during the 1993 progmm: 1) coiledtubing replaced the conventional tubing for most of the

opemtions. The coiled tubing could be run in and out of

the wellbore more quickly than conventional tubing and

did not require a snubbing assist unit if pressure was

encountered. The coiled tubing was used as the dead

string when fracture stimulating, and was used in cleaning

out or placing sand plugs between perfomted intervals. 2)

a unique wellhead was deveioped to faetii’mte s-witckdng

from one opemtion to the next and to accommodate a

hlass joht to protect the coiled tubing from erosion. 3)

use of sand plugs instead of a retrievable bridge plugs to

isolate intervals between fracture stimulations. A

summary of the coiled tubing procedure is outlined inA&seuaule ~.

The new procedure enhances safety by eliminating the

requirement for a snubbing assist unit. The crossover

depth from snubbing to “stripping” (depth where the

weight of the tubing is greater then the upward force due

to pressure) is less than the depth of the sand plug.

Therefore, the tubing can be run in the hole without weiipressure to the crossover depth. Next, the tubing can be

stripped in the hole while circulating sand out of the

wellbore.

The tubing used to circulate out sand becomes the

production string. Once the sand is circulated out, the

tubing is landed, and the producing tree installed. The

one way circulating valve installed in the tubing is then

sheared out and the well turned over to production.

A second Pareto diagram (see fig. 2) was created to

identify the coat drivers when the coiled tubing completion

procedure is used. Again, the fmcture service company

accounts for the mqjority of the charges. However, with

the new procedure, only 20% of the total completion cost

was due to the hydrati:c fmcture pump charges, which

results in a 33% reductjon (compared to 30% with theconventional procedure). The sand expense, however, is

the most significant cost of the coiled tubing completion

procedure. (Sand is 28% of the total@ compared to 18%

using the coiiveiitkmd procetkre.)

Again, as with the conventional procedure, increasing or

decreasing the cost of the non-fmcture company services

and equipment does not have a noticeable effect on the

ovemll completion costs. Therefore, the cost of a coiled

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SPE 27892 D. A. fiIlllS 3

overall completion costs. Therefore, the cost of a coiled

tubing unit over a conventional w-orimvei fig dk! not add

an appreciable amount to the total cost.

COILED TUBING

Ftw Sandcleammt

After fracture stimulating, the 1.5” coiled tubing unit is

used primarily to clean out sand.. . ..# +haThe ~it i~fi w c =

sand plugs is critical since sufllcient sand is required to

ko!a& the pressure resii!ting from previously stimulated

intervals. However, the sand can not cover the next

interval to be perforated. The coiled tubing provides a

method for cleaning out the sand to the desired depth1 -c h .vo hem e~c Qunt eA in liftingaccuratdy, No prcb.a... . .--------

the frac sand using the 1.5” coiled tubing in 7“ casing.Gelled KC] water (Marsh Funnel Vkcosity of 35 to 40 sec.)

is used as the circulating fluid. A circuiting pump wfiii

shale shaker is employed to retain as much of the gelled

water for m-use as possible. The time to circulate the

sand out of the well and pull the coiled tubing averages

two hours.

In addition, several improvements were made in the 1993

project to help the frac sand settle faster in the wellbore:

1) the crosslinking agent was cut out of the gelled fluid

during the last two minutes of the fracture stimulation.

(The sand laden gelled fluid was pumped into the wellbore

and the near wellbore area as a linear fluid.) 2) KCIwater was pumped as a flush instead of gelled fluid. The

difference in sand settling is significant. For example, on

the wells pumped with all crosslinked gelled fluid and

flushed with gelled fluid, over 3 hours is required for the

sand to settle. Tailing in with a linear gelled fluid and a

KC1water flush allows the sand to settle in 30 minutes.

On occasion, the sand plug ieft in the weiiimre after

completing a fracture stimulation was not of suftlcient~e~g~~ tO pFOVMe pressure integrity. In these cases sand

can be pumped dQwnthe coiled tubing to provide a larger

sand plug. The sand is pumped at low concentrations (1

to 2 lb./gaL) using KCI water. No bridghg of sand in the.coiied tubing has ‘*ii experwimi.

As ADead Strhqg

The coiled tubing is also employed as a “dead string” when

fracture stimulating. The coiled tubing, run in the hole

just above the perforated interval, is used to monitor

bottom hole pressure during the stimulation. To prevent

excess sand from falling around the coiled tubing after

fracturing, the tubing is pulled slowly up the hole at theend of the jQb.

A blast joint is used as a sleeve in the wellhead to prevent

sand from eroding the coiled tubing. The thickness of the

coiled tubing is monitored before and after fracturing. No

incremental metal loss has been detected on the coiled

tubing when it was used as the dead string. However, the

blast joint has shown noticeable wear at the point of sand

entry into the wellhead. Without the blast joint such~ro~ion ~ouid have possibly parted the coiled tubing.

A unique wellhead was designed to improve the eftlciency

of the coiled tubing completion procedure (see fig. 3).

Two features have been combinwi to ensure the eom@etimiwellhead is secure and accessible. A tree cap was devised

ti,tii an =ttt&d sieve t Q protect the coiled tubing from

sand and a full opening master valve has been employed

to enhance safety. With a total height of 5.5’ the

wellhead allows service company personnel to switch the

tree cap with a lubricator while standing at ground level.

The most diathwtive part of the completion wellhead is the

hammer union tree cap (see fig. 4). It has been designed

to allow connection of the coiled tubing blow out

prevention equipment (BOPE) to the top of the cap. A

blast joint can then be threaded into the bottom. Since

the blast joint has to be removed prior to conductingintermediate operations (logging, perforating etc.),

attaching the tree cap to the coiled tubing BOPE, allows

both to be treated as an integral unit. This enables the

tree cap and blast joint to be quickly removed when

placing a lubricator on the completion wellhead.

A hammer union connection was designed to attach the

tree cap go~iiew~ilii=d, The tree cap connection matched

the perforating company’s lubricator connection. With

this design, the tree cap/ coiled tubing BOPE equipment

and a lubricator can be exchanged hi apprdmatciy 15

minutes.

In order to remove the tree cap and lubricator under

controlled conditions, the well pressure has to be isciated.

A master valve has been incorporated between the casing

head and the fracture stimulation wellhead for this

purpose. The valve is a full opening gate valve with the

internal diameter sized to match the internal dhuneter of

the production casing. This ensures that there are no

restrictions for equipment entering the well.

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Coiled Tubing Completion Procedure Reduces Cost

4 and Time for Hydraulically Fractured Wells SPE 27892

During the 1993 completion project, we discovered that the

master valve seats require reconditioning after 5 to 6

million pounds of sand (typically 3 to 4 wells) have been

pumped through it. In the latter stages of the project, two

completion wellheads (master valve and frac valve) are

employed. The inactive completion wellhead can be

reconditioned and installed on the next well to be

Cmnp:eted.

REsuL’rs

The coiled tubing has worked well in circulating sand out

of the wellbore. The time required to circulate and pull

out of the hole with the coiled tubing averages two hours.This allows a fracture stimulation treatment to be

performed every three hours. Additionally, sand plugs

can be safely placed through coiled tubing using KCI water

and low sand concentrations (1 lb./gal. to 2 lb./gaL). No

sand bridging has been observed in the coiled tubing.

Coiled tubing has been used successfully as a “dead string”

to monitor the bottom hole pressure during fracture

stimulations. No incremental metal loss has been detected

on the coiled tubing. However, the sleeve around the

coiled tubing has exhibited noticeable wear at the point of“--J ..-4-. :..4...qL. ...mIIL. .Sauu C1lL1 y l l l LU UK w cul l -u .

w k . .“—..AIAI. .1-.,. h ..s l lC cApUluuusG v--r G u

worked well to prevent the coiled tubing from erosion and

possible parting.

The new wellhead has reduced the time required for

switching from one operation to the next. An average of

15 minutes were required to switch out the coiled tubing

BOPE to a lubricator and vice versa. The seats in the

master valve have required redressing after completing

three to four wells. Similar results have been observedw it h t hm v ml vx in fhm nnder l fmdmw h-d. I t ~St~g~~f~~~. . . . . . . . . . . . - . . . . .. . . . ..& J.—------- - -—-.

recommended that on large projects, two wellheads be

used alternately. One wellhead could be redressed while

the other is being used.

With the coiled tubing procedure, a well with 5 fracture

stimulated intervals can be placed on production in 4 days.

This has resulted in a 50% reduction in completion time

when compared to conventional methods. During 1993 an

average of 3 intervals were fracture stimulated per day.

Although it was necessary to increase the hours worked

per day from 10 to 12, use of the 4 hour minimum service

company pump charge was maximized.

conventional and the 1993 coiled tubing completion

procedures. Both in the conventional procedure and the

coiled tubing procedure, fracture service company charges

account for the majority of the costs. However, the coiled

tubing procedure reduces the completion costs by an

average of $60M. Fully using the 4 hour minimum

charged for the hydraulic pumps accounts for $35M (orEOOZ.\f + k . WARM c d rdmdinn.J 7 W J u. .“ . v “ ” ... w “ . . .“ ” -..” .. .

Additional savings were realized by reducing the rental

time, not using bridge plugs, and eliminating the snubbing

assist unit.

When compared to the average completion costs for Lost

Hills wells in the past five years (see fig. 5), the new

completion procedure lowers costs by 21%.

ACKNOWLEDGEMENTS

The author would like to acknowledge the technical-- ..,.

assistance of J. Ryan, Halliburton Energy Services and i?.

Litzel, Dowell Schhnnberger, and the significant

contribution of W. Johnson, Mobil Exploration and

Producing U.S. Inc. in implementing the procedure. The

author also wishes to thank Mobil Exploration &

Producing U.S. Inc. for granting permisdon to publishth:. ---bm pp. .

REFERENCES

1. Coats, E. A., and Johnson, K. J.: “Realed-Tubing

Technology Accelerates Coalbed Methane

Production in the Black Warnor Basin” paperSPE 23697, nresented at the Production–_––-–--—

Operations Symposium of the Society of

Petroleum Engineem, Oklahoma City, Oklahoma,

April 7-10, 1991.

2. Fast, R. E., Murer, A. S., and Timmer, R. S.:

“Description and Analysis of Cored Hydratilc

Fractures, Lost Hills Field, Kern County

California” paper SPE 24853, presented at the

67th Annual Technical Conference and Exhibition

of the Society of Petroleum Engineers,

Washington , D.C., October 4-7, 1992.

Table 3 compares the average costs for both the 1992

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Figure 1. Pareto chart identifying conventional completion cost drivers.

40 -“-... .-

Frac Company Charges

Non-Frac Company Charges

1 100

Step 1.Step 2.

Step 3.Step 4.Step 5.

Step 6.~~q 7

Step 8.

Step 9.

Repeat

seep 10,

Step 11.

Move in production rig, install necessary equipment.Set retrievable bridge plug (RBP) below bottom stage (withtubing) .Perforate interval to be fracture stimulated.Run tubing in hole.Fracture stimulate down tubing/casing annulus (with tubing used

to monitor bottom hole pressure) .

Force ciose fracture with limited floiiback.cleanQut sand with tubing.

Retrieve, reset RBP above perforated interval and pressure test.Pull out of hole with tubing.

steps 3 through 9 for each interval to be stimulated.

Move in snubbing assist unit, install necessary equipment.

Snub RBP out of hole and snub/strip in production string

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.

Table 2. Coiled tubing completion procedure outline.

Step 1.Step 2.Step 3.Step 4.

Step 5.

Step 6.

Step 7.

Repeat

Step 8.Step 9.

Step 10.

Step 11.

Move in coiled tubing unit, install necessary equipment.Perforate interval to be fracture stimulated.

Run coiled tubing in hole.Fracture stimulate down tubing/casing annulus (with coiled

tubing used to monitor bottom hole pressure) .

Force close fracture with limited flowback and allow timefor sand to settle.Clean out sand to bottom of next perforated interval, or

place sand through coiled tubing if necessary.Pull coiled tubing out of hole.

steps 2 through 7 for each stage.

Rig down coiied tubing unit and equipment.Move in production rig, install necessary equipment.

Run conventional tubing in hole, circulate out sand to totaldepth.

Land production string.

Figure 2. Pareto chart identifying coiled tubing completion cost drivers.452

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Figure 3. Wellhead developed for coiled tubing completion procedure.

Hammer union treecap

10” threaded to API 7“ flanged crossover

API 7“ by API 1 Iii flanged fracture

head with 3“ API flanged gate valves

Apl 1 1“ to API 7“ flanged adapter

API 7“ flanged gate valve

Internal diameter 6.75”

API 7“ flanged tubinghead

Surface casing

7“ production casing

3.5” 8 Round internal upset threads

(to connect to Coiled tubing BOPE)

10” Hammer WIiOn

(same threads as lubricator)

10” threaded to API 7“ flanged crossover

2.375” internal upset threads

u ~ 2/375” blast joint

Figure 4. Hammer Union Treecap with attatched blast joint.

453

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.

Co n v e n t i o n a 1 Cc mp l e t i o n ~ Co i l e d T b g Co mp l e t i o n

( 1 9 9 2 Av e r a g e ) I ( 1 9 9 3 Av e r a g e )tt

c o s t I Coat

(M$) P er c e n t I ( MS) Pe r c e n t. - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

D, —1 OI a d. . I Iru , ~,o . c ,luc ,

?f.~ 70 0G.. . 1~~.~ ~Q.~

S a n d I 4 3 . 6 1 8 . 2 I

I I

4 9 . 1 2 7 . 5

F r a c F l u i d t 4 0 . 1 1 6 . 8 iI 2 5 . 9 1 4 . 5

Mi l a g e / Oe l i v e r y , 8 . 7 3 . 6 6 . 5 3 . 6

F r a c Va n I 5 . 3 2 . 2 5 . 2 2 . 9

Ot h e r 1 5 . 1 2 . 1 5 . 2 2 . 9- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

F r a c Su bt o t a l I 1 7 4. 3 7 2 . 8 4 t 1 2 8. 1 7 1 . 7 6

Ri g 1 1 . 5 4 . 8 2 . 8 1 . 6

~ Qi ! e d T@ o 0 , 0 7 . 8 4 . 4

Eq u i p me n t Re n t a l s ~ 9 . 5 4.0 I 3.6 2.0P e r f o r a t e I 9 . 2 3 . 8 I 8 . 7 4 . 9

Ui r e l i n e I 7 . 4 3 . 1 II 7 . 5 4 . 2

T u bi n g f 6 . 3 2 . 6 tI 6 . 5 3 . 6

P u n p 3 . 5 1 . 5 I 2 . 6 1 . 5

Su pe r v i s i o n 4 1 . 7 ; 2 1 . 1

Ue l l h e a d 3 . 8 1 . 6 I 3 . 8 2 . 1

Sn u b bi n g Un i tII 3 . 2 1 . 3 I 0 . 0

Co mp l e t i o n F l u i d I 3 . 5 1 . 5 1I I 1 . 8 1.0

T r a n s po r t a t i o n 1 . 3 0.5 1 1 . 1 0 . 6

Ua s t e Di s p o s a l I 1 . 1 0.5 II 1.3 0.7

L oc a t i o n I 0 . 7 0 . 3 I 0 . 9 0 . 5- - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - - -

T ot a l 2 3 9 1 0 0 ~ 1 7 9 1 0 0

Table 3. Mobil’s Lost Hills Diatomite Completion Costs for 1992 and 1993

2 1$%Reduction7

I&3 H 1989 through 1992 cost average/’

“f

. . . . . .. . .. . . . . . .. .

~ ~ ~ ~

1 B

1988 1989 1990 1991 1992 1993

Figure 5. Average Lost Hills completion costs for last 6 years

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