SPE 54285 Single Trip Perforating and Gravel Pack System Reduces Formation Damage.pdf

8/11/2019 SPE 54285 Single Trip Perforating and Gravel Pack System Reduces Formation Damage.pdf

1/15

Copyright 1999, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 1999 SPE Asia Pacific Oil and GasConference and Exhibition held in Jakarta, Indonesia, 2022 April 1999.

This paper was selected for presentation by an SPE Program Committee following review ofinformation contained in an abstract submitted by the author(s). Contents of the paper, as

presented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society ofPetroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paperfor commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractImprovements in the Gulf of Mexico (GOM) sand control

completion methods have been and continue to be an ever-

changing process. However, the goals have remained the same

to complete wells efficiently and generate the greatest

production using the most cost-effective technology.

One of the new techniques that is available to operators to

accomplish these goals is a method that allows perforating and

gravel packing to be accomplished with a single trip into the

well. This technique, the Single Trip Perforate and Pack

(STPP) method, has recently been introduced to the industry.

The purpose of this paper is to provide engineers and

operators with a better understanding of when this technology

should be applied. The method discussed will attempt to

quantify the decision making process.

IntroductionIn the Gulf Coast area, unconsolidated sandstone formations

previously completed with a mechanical form of sand control

were usually perforated with big-hole tubing-conveyedperforating (TCP) guns in an under- balanced condition. After

the perforating process has been performed, the wells are

killed to facilitate removal of the perforating assembly from

the well bore. The killing of the well could damage the

formation, and fluid loss can occur any time between well

perforating and completion.1,2,3,4,5 The subsequent loss of

fluids may also damage the formation. (The degree of damage

and mechanisms of damage have been addressed in previous

papers and will not be reiterated at this time.)

Any formation damage that occurs ultimately effects the

production potential of a well; however, the degree of damage

is not necessarily proportional to the effect on productionThus, since it is important to minimize and control any

damaging phenomena, much effort in the industry has been

devoted to developing methods and techniques to address the

problem.

STPP Back GroundSingle Trip Perforate and Pack systems (STPP) were firs

introduced in the late 1980s. These early STPP systems used

complex mechanical designs, and the treating/isolation packer

was weight set with no provision to limit upward movement

A reliable system for isolation of the gravel pack packer

setting ports was not available. Overall the mechanical design

had several areas that were marginal at best. The early jobswere perforated under-balanced with pressures of 750 to 1200

psi. If the produced sand volume during perforating was

excessive, the perforating guns would often become stuck

The perforating guns available at that time were not of the low

debris design, the added debris produced by these guns

contributed in mechanical problems associated with early

STPP completions.

Wells that were mechanical successes would often be

economic failures because of the resulting high skins

associated with the gravel pack and perforating techniques

available at the time.

Overview of New STPP DesignsThe methods that have been recently developed for the STPP

systems in use today allow wells to be perforated and grave

packed in a single run.6,7

The complex mechanical design of

earlier STPP systems has been replaced with more

reliable/simpler designs that have raised the degree o

reliability to an acceptable level. The reliability of curren

STPP design is equal the reliability of the conventional multi-

trip systems but adds the sought-after enhancements of

minimizing formation damage. Service tools can now

SPE 54285

Single Trip Perforating and Gravel Pack System Reduces Formation Damage inOffshore Gulf of Mexico Wells: Case Histories and Guidelines for Candidate SelectionRalph H. Jones, SPE, Halliburton Energy Services, Inc.


2/15

2 RALPH JONES SPE 54285

accommodate higher frac rates and slurry densities required

for the fracpac stimulation treatments in use today.

Technical Objectives of STPP CompletionsFollowing are the targets at which the STPP systems are

aimed:

1) Perforate and gravel pack wells with a singleintervention into the well bore.

2) Minimize fluid losses to the formation.3) Reduce fluid costs by minimizing fluid losses into the

formation.

4) Minimize the use of fluid-loss control treatments(FLCT).

5) Eliminate clean up trips between perforating andgravelpack processes.

6) Reduce completion time.7) Incorporate productivity enhancement stimulation.

Big Bore Sump Packer (BBSP) STPP DesignOf the systems currently in use, the BBSP/STPP system has

been one of the most successful system operationally.

BBSP/STPP completions use a mechanical-set-type packer to

isolate the zone of interest during the perforating sequence

(Fig. 1).

A Big Bore Sump Packer is used to isolate the screen-to-

casing annulus below the bottom perforation. After

perforating, the guns are passed through the BBSP to prepare

for pumping the gravel-pack treatment (Fig. 2).

The STPP design consists of the following equipment in

ascending order:

1. Big Bore Sump Packer (BBSP)2. Tubing Conveyed Perforating (TCP) Gun Assembly3. BBSP Seal Assembly

4. Sand Control Screens5. Blank Pipe6. Packer Assembly7. Perforating/Testing Packer Assembly8. Circulating Valve9. Hydraulic Jars10. Radio Active Marker.

Component Description for BBSP/STPP

Big Bore Sump Packer (BBSP)The BBSP is the pivotal item that allows the STPP process to

maintain the high degree of reliability. The BBSP has a large

inside diameter that allows the perforating guns to be passedthrough the sump packer after perforating (Fig 2). After the

perforating sequence is complete, the BBSP is employed, the

perforating packer is released, and the perforating guns are

passed through the BBSP into the casing below the sump

packer. The BBSP seal assembly is inserted into the BBSP to

achieve a seal between the screen and casing as this will allow

for sand containment in the screen to casing annulus when the

sand control treatment is pumped.

This has proven to be more reliable than earlier designs in

which a mechanical packer performed a dual function of a

perforating packer and a screen to casing isolation packer. The

BBSP is set on electric line, which allows the packer to be

accurately correlated to depth. The TCP guns can be placed on

depth from the BBSP top.

To ensure that the BBSP packer can be successfully run to

depth, a dummy BBSP is run on electric line to a depth below

the packer setting depth. After completion of the BBSP

dummy run, the BBSP packer is run and set with electric line.

New Designs are currently planned to reduce the outside

diameter of big bore sump packers. This will enable wells tha

have casing drifts below API specifications to use BBSP.

Perforating TechniquesMuch research has been conducted on this subject.

1,2,3,4 Gul

Coast unconsolidated sandstone formations perforated in an

under-balanced condition with high-density, bighole charges

are an industry standard. The objective is to obtain debris-free

perforation tunnels and then fill these tunnels with sand during

the sand control process. 1,2,3

The desired results are large cross sectional area high

density perforation tunnels with minimum flow restriction

Under-balanced perforating with (TCP) Tubing Conveyed

Perforating guns has proven to be a very successful method to

obtain clean perforation tunnels.4 Care should be exercised

when calculating the required under-balance for perforation

tunnel cleaning with STPP designs because excessive under

balance could pull formation sand into the well bore that could

sand up the perforating guns.

Low Debris perforating charges are recommended to

minimize the amount of debris left in the wellbore after

perforating. If under-balance perforating is not feasible due to

excessive sand production during perforating, over-balancedperforating should be considered. Over-balance perforating in

conjunction with fracpac stimulations have historically

produced very low skin damage.

The perforating guns are fired using Pressure Operated

Time Delayed Firing heads; redundant firing heads are

employed for reliability.

Gravelpack Packer AssemblyA hydraulic set gravelpack assembly is used for the STPP

process.

During the perforating process, an unrestricted flow path mus

be maintained through the gravelpack assembly (Fig 3).

To establish the proper flow path for pumping the sandcontrol treatment, a dual ball design is used. The lowe

isolation ball is dropped down the workstring and allowed to

gravitate to bottom. This ball will be used to isolate fluid

losses down the wash pipe during the sand control treatment

(Fig 4).

A second, larger OD ball is dropped and allowed to

gravitate to bottom, acting as the packer setting ball (Fig 5)

After setting, the packer the ball is expended to act as a


3/15

SPE 54285 SINGLE TRIP PERFORATING AND GRAVEL PACK SYSTEM REDUCES FORMATION DAMAGE 3IN OFFSHORE GULF OF MEXICO WELLS: CASE HISTORIES AND GUIDELINES FOR CANDIDATE SELECTION

isolation ball directing fluid to exit through the slurry ports of

the service tool (Fig 6).

The well stimulation/ sand control process can now be

pumped (Figs. 7,8) after completion of this treatment the well

is reversed out through the service tool (Fig. 9). (Note: The

testing packer and circulating valve is not used during the sand

control process.)

Upon completion of the sand control treatment, the

gravelpack service tools and testing equipment are retrieved to

surface (Fig. 10).

BBSP/STPP Installation ProcedureThe typical installation procedure follows:

1. Set BBSP on electric line, depth to be correlated with(CCL/GR).

2. Assemble TCP and Gravelpack equipment assembliesand run into the wellbore (Fig 1).

3. Upon reaching the perforating depth the TCP guns arecorrelated on depth.

4. The perforating / testing packer is then set and tested.

5. To achieve an under balance, if required, thecirculating valve above the packer is opened to obtain

the desired under balance. The circulating valve is

then closed in preparation to firing the perforating

guns.

6. Pressure is applied down the workstring to initiate thePresure Activated Time Delayed Firing Head

(PATDF) which detonates the TCP perforating guns.

A time delay-firing head is required to allow the

PATDF actuation pressure to be bleed off before

firing of the TCP guns.

7. The well can be flow tested at this time.8. After the flow period the circulation valve is opened,

and the well is reversed out.9. The formation is isolated at this time from any fluid

losses (Fig 1).

10. The testing packer can be unseated to facilitate reversecirculation from the bottom of the wash pipe if

desired, (Note: the formation is exposed to fluid loss

at this time.)

11. After reversing out, the perforating packer is released,and the STPP assembly is lowered into the wellbore.

12. The TCP guns are allowed to pass through the BBSP,and the sump seal assembly is inserted into the BBSP

isolating the screen assembly (Fig. 2).

13. The wash pipe isolation ball is then dropped in the

workstring and allowed to gravitate to bottom.14. After sufficient time has lapsed, the packer setting ballis dropped and allowed to gravitate to bottom.

15. Pressure is applied to the work string to open thehydraulic setting port isolation sleeve and allow the

packer to be set.

16. After setting the packer, it is tested.17. Upon completion of the pressure test, the packer

setting ball is expended into the tapered seat to form

the isolation between the slurry port and return

annulus (Fig. 6).

18. The slurry port is placed in the packer sealbore, andthe slurry port isolation ball is tested.

19. The MPT positions are obtained, and the sand controltreatment is pumped (Figs. 7,8).

20. After reversing out the workstring, the lower flapper isclosed, controlling any fluid losses into the formation(Figs. 9,10).

The Alternative Wash Down Method of theBBSP/STPP System

BBSP/STPP Design with Wash Down CapabilityIf the completion design requires that the stimulation pumping

rates or proppant volumes exceed the rates and volumes

available from the packer service tool or completion

equipment, and if the casing configuration is of a slim hole

design, then a STPP wash down system may be required. The

wash down system uses many of the same components as the

BBSP/STPP (Fig 11).

The advantage of the wash down method is that the wel

can be perforated, the guns dropped, and the zone stimulated

on a single intervention into the wellbore (Fig. 12). The

fracpac or high-rate water pack (HRWP) will be designed to

fill the casing inside volume below the treating packer with

sand after placement of the stimulation treatment. The

screen/packer assembly will then be washed into place

(Fig 13).

The perforating assembly is as follows in ascending order:

1. Big Bore Sump Packer (BBSP)2. Tubing Conveyed Perforating (TCP) Gun Assembly3. Perforating/Testing packer Assembly

4. Circulating Valve5. Hydraulic Jars6. Radio Active MarkerThe packer assembly is shown in Fig. 13, and in ascending

order consists of the following components.

1. BBSP Seal Assembly2. Sand Control Screens3. Blank Pipe4. Packer assembly.The STPP/WD system allows the well to be perforated and

stimulated in a single trip into the wellbore. After perforating

the well the perforating guns are dropped off the end of the

tubing. The formation can be protected from the completion

fluid by the use of testing tools which enables the packer toremain set. Reversing out after the perforating sequence and

prior to pumping the stimulation is possible by utilizing a

reversing valve.

STPP Wash Down Installation ProcedureThe STTP Wash-down procedure consists of the following

steps:

1. Set BBSP on electric line, depth to be correlated with(CCL/GR)


4/15


2. Assemble TCP Guns with testing tools as depicted in(Fig 11). Run the assembly into the wellbore.

3. Upon reaching the perforating depth the TCP guns arecorrelated on depth.

4. The perforating / testing packer is then set and tested.5. To achieve the required under balance a circulating

valve above the packer is opened to displace the

tubing contents to achieve the desired under balance.

The circulating valve is then closed in preparation to

firing perforating guns.

6. Pressure is applied down the workstring to initiate theTime Delayed Firing Head (PATDF) which detonates

the TCP perforating guns and initiates the auto release

feature (Fig 12).

7. The released TCP are allow to fall through the BBSPinto the casing.

8. After the flow period the circulation valve is openedand the well reversed out.

9. The formation is isolated at this time from any fluidlosses.

10. The formation stimulation can then be pumped. Sandwill be left above the top perforation. The perforating

assembly will then be pulled from the wellbore.

11. The screen and packer assembly will then be made upand run into the wellbore (Fig 13).

12. After tagging the top of the sand, the screen assemblywill then be washed into place.

13. The BBSP seal assembly is then inserted into theBBSP packer.

14. The wash pipe isolation ball is dropped into theworkstring and allowed to gravitate to bottom.

15. After sufficient time has lapsed, the packer setting ballis dropped and allowed to gravitate to bottom.

16. Pressure is allied to the work string to open thehydraulic-setting-port isolation sleeve and allow the

packer to be set.

17. After setting the packer, the packer is tested.18. The MPT positions are obtained, and the sand-control

annular treatment is pumped.

19. After reversing out the workstring, the lower flapper isclosed, controlling any fluid losses into the formation.

20. The service tool is then removed from the wellbore.

STPP Selection Criteria with BBSPThere are several factors that should be thoroughly considered

when evaluating wells for STPP procedures.

The proposed completion interval requires sufficientdistance below the BBPS to accommodate the TCPperforating guns after perforating the well. If there is not

sufficient distance below the sump packer, the perforated

interval may need to be reduced.

It is recommended that maximum hole angle through thecompletion interval should not exceed 62 degrees. At

higher deviation, perforating debris or formation sand

could prevent the sump packer seal assembly from

entering the BBSP sump packer. If this accumulation is

excessive, formation sand could prevent a successfu

sand-control treatment from being performed.

Casing conditions and design could prevent BBSPinsertion into the casing; i.e., liner tops, deviation

doglegs, squeezed perforations, or casing corrosion

Workover candidates should consider an advance

wellbore cleaning process to ensure the casing is as cleanas possible.

Low debris perforating charges are recommended tominimize the amount of debris left in the wellbore after

perforating.

Fracpac and gravel-pack treatments are applicable to thesingle trip perforate and pack process

Not all wells, however, are candidates for STPP, and

therefore, the planning process must be through and complete

to ensure a successful STPP completion.

Single Trip Perforate and Pack utilizing a MechanicalIsolation PackerThe early STPP designs employed mechanical set packers

positioned between the screens and the perforating assembly

Several operational problems arose with designs of the time.

1. Some of mechanical packers did not employ a hold downmechanism. Weight would have to be maintained or the

packer would unset.

2. A reliable slurry port isolation system was not available.Complex systems were tried with varying degrees of

success.

3. Positive Isolation of the packer setting ports was noavailable.

4. Weigh applied to the mechanical treating packer coulddamage the sand screens during perforating.

5. Mechanical firing heads for the perforating guns we used

Requiring a drop bar to pass through the packer assemblyto detonate the perforating guns.

New innovations to STPP utilizing a MechanicalIsolation PackerSTPP systems utilizing a big bore sump packer have achieved

a high degree of reliability.

The BBSP should be considered as the primary design for

STPP, but if for operational or economic reason the BBSP

system cannot be employed then a STPP system utilizing a

mechanical packer could be considered.

The developments of new technologies for STPP with a

BBSP have adapted very well to STPP with mechanical

packers. These developments are as follows:1. Pressure Activated Time Delayed Pressure Firing Head

(PATDF) has eliminated the mechanical drop bar firing

heads.

2. Improved Hydraulic Isolation Port systems.3. Bi-directional Mechanical Packer for positive engagemen

of the isolation packer to the casing.

4. Service Tool Dual ball isolation system allow for positiveisolation between the slurry ports and the annulus return

ports.


5/15


5. The increased flow area of the dual ball isolation systemenables Fracpacs to be used.

The mechanical packer STPP design consists of the

following equipment in ascending order. (Fig 14):

1. Tubing Conveyed Perforating (TCP) Gun Assembly2. BI Directional Mechanical Packer3. Sand Control Screens4. Blank Pipe5. Packer Assembly6. Radio Active Marker.

Mechanical Packer STPP Installation Procedure1. Assemble TCP and Gravelpack equipment and run into the

wellbore (Fig 14).

2. Upon reaching the perforating depth the TCP guns are

correlated on depth.

3. The Bi-directional Mechanical packer is then set and tested.

Weigh does not have to be left on the packer, the screens

can be left in tension or neutral position.

4. To achieve a under balance if required, The by pass of the

packer is opened to achieve a underbalance the packer by passis then locked closed in preparation to firing perforating guns.

5. Pressure is applied down the workstring to initiate the Time

Delayed Firing Head (PATDF) which detonates the TCP

perforating guns. Upon firing of the guns the automatic drop

off sub release the guns allowing them to drop into the casing

(Fig 15,16).

6. After the flow period, the by pass is opened, and the well

reversed out. The formation is not isolated from fluid losses at

this time.

7. After reversing out, the mechanical packer is released and

the STPP assembly lowered into the well bore. The screens

are placed across the perforated interval and the mechanical

packer set and tested from below (Fig. 16).8. The wash pipe isolation ball is then dropped in the

workstring and allowed to gravitate to bottom.

9. After sufficient time has elapsed, the packer setting ball is

dropped and allowed to gravitate to bottom. Pressure is allied

to the work string to open the hydraulic setting port isolation

sleeve and allow the packer to be set.

10. After setting the gravel pack packer the packer is tested.

11. Upon completion of the pressure test the packer setting

ball is expended into the tapered seat to form the isolation

between the slurry port and return annulus.

12. The slurry port is placed in the packer sealbore and the

slurry port isolation ball is tested.

13. The MPT positions are obtained and the sand controltreatment is pumped.

14. After reversing out the workstring the lower flapper is

closed controlling any fluid losses into the formation (Fig 18).

Selection Guide MatrixAs can be noted from the above section describing the

completion scenarios involved in the STTP processes, not

every completion requiring sand or fluid-loss control is a

candidate for this type of completion. To help in determining

the appropriate conditions for its application, a selection guide

matrix has been developed based upon knowledge acquired

while designing and implementing STPP jobs over the past

few years. This Matrix is not intended to be a definitive source

for determining if a well is a good candidate for Single Trip

Perf Pack but should be considered as a tool to assist in the

preliminary decision making processes.

Seven areas have been identified as critical to review in the

decision process for appropriate condidates.

1. Formation Sensitivity2. Completion Fluid Type3. Completion Fluid Loss Risk4. Well Deviation5. Casing Configuration6. Sufficient Distance Below the BBSP setting depth.7. Rig CostsEach area is weighted equally, but any single area could

carry a higher value depending upon the evaluation scenario

Each selection criterion is weighed with a value 1 to 4 with the

exception of two the distance below the sump packer and

the well deviation.The distance below the sump packer carries a zero or one

value. If there is not sufficient distance below the BBSP, then

a flag will appear, indicating that STPP is not possible with

the present conditions. Well deviation will be evaluated with

a zero or four values.

Formation SensitivityFormation sensitivity to completion fluid is very critical in the

decision process. If the formation is very sensitive, this in

itself could be an overriding issue.

1. = No Fluid Sensitivity

2. = Slight Fluid Sensitivity

3. = Fluid Sensitive4. = High Sensitivity

From xray defraction, the formation will be determined if

it is sensitive; a completion fluid compatibility test should also

be performed.

Completion FluidThe completion fluid type is weighed to determine fluid costs

incurred while completing a well.

1. = Nacl, KCL, Sea Water

2. = Cacl2

3. = Cabr2/Znbr2

4. = Znbr2

Completion Fluid Loss RiskThe completion fluid loss risk is the anticipated fluid losses

that could be experienced after perforating the well.

1. = Low Fluid Losses 0 to 15 barrel per hour

2. = Medium Fluid Losses 15 to 30 barrel per hour

3. = High Fluid Losses 30 to 45 barrel per hour

4. = Excessive Fluid Losses Above 45 barrel per hour


6/15


Well DeviationWell deviation may increase the problems incurred in

mechanical operation of down hole equipment.

The highest deviation that has employed STPP has been 62

degrees. If the deviation is higher than this, there could be

problems passing the perforating guns through the BBSP. The

length of perforation and the tendency of formation sand to be

pulled into the casing will need to be considered Over-

balanced perforating and low-side perforating could aid in the

preventing of excessive formation sand being pulled into the

formation. The effect of over-balanced perforating or low-

side perforating should be considered in the completion and

stimulation design. A value of 1 to 3 could be used in certain

applications.

0. = Deviation greater than 62 Degrees

4. = Deviation less than 62 Degrees

Casing ConfigurationCasing conditions and design could prevent the BBSP from

being set on depth. These could relate to liner tops, deviation,

doglegs, squeezed perforations, or casing corrosion.Any casing condition could prevent the BBSP packer from

being able to be set on depth. Workover candidates should

consider advance wellbore cleaning process to ensure the

casing is as clean as possible.

1. = Long String with Liner with Deviation greater than 60

Degrees

2. = Long String with Liner 5 or smaller with Deviation

less than 45 Degrees

3. = Long String with Liner larger than 5 and Deviation

less than 45 Degrees

4. = Long String with Deviation less than 60 Degrees

Sufficient Distance Below the BBSPIf the distance below the BBSP is not sufficient to accept the

perforating gun assembly then the perforated interval or the

plug back depth will need to be adjusted. This is the only

evaluation criteria that will display a not possible notice. A

value of 0 and 1 has been assigned.0. = Insufficient Distance to accept perforating guns.

1. = Sufficient Distance to accept perforating guns.

Rig CostsSTPP can substantially reduce the completion time required.

The time between completing wells and putting the wells on

production can be reduced by several days, increasing the net

present value of the well (NPV). It is common knowledge thatdaily costs can have a dramatic effect on total completion

costs, and the value of early production is reflected here. This

is a very subjective consideration.

1. = Low Rig Cost2. = Medium Rig Cost3. = High Rig Cost4. = Deep WaterA matrix showing the above considerations has been

developed in Table 1.

Matrix ConclusionBased on the available case histories, the evaluation average is

3.28 with the highest evaluation 3.67 and the lowest 2.67. As

for determining a minimum evaluation grade this will be very

subjective. Each candidate will need to be thoroughly

evaluated before a decision can be assessed. Candidates above

2.5 will be the appropriate candidate for STPP completions.

Conclusions The STPP system can reduce completion time by

combining the perforating and gravel packing operations

into a single trip

The reliability of current STPP technology equals

conventional multi trip completion systems.

Completion fluid losses can be minimized with the STPP

system.

Casing configuration could determine if a STPP

completion is feasable.

Under balance Perforating pressure may need to be

reduced to prevent sand up of the perforating guns.

Fracpac stimulations in conjunction with STPP haveyielded very low formation damage.

The STPP system is capable of being washed into place if

formation or gravel pack sand is present in the wellbore.

AcknowledgmentsThe authors express their sincere appreciation to the

management of Halliburton Energy Services, Inc. A specia

thanks to all parties that worked together to successfully

complete this project. Also, a special thanks to Nancy Woods

Lori McEwen, and Dean Oneal.

References

1. Bruise E. H. Better Performance of Gulf Coast Wells SPE 4777presented at the SPE Symposium on Formation DamageControl, New Orleans, LA, 7-8 February 1974.

2. Penberthy W.L. Jr. and Cope, B.J.: Design and Productivity ofGravel Packed Completions, JPT(Oct, 1980).

3. Penberthy W.L. Jr.: Gravel Placement Through Perforations andPerforation Cleaning for Gravelpacking, SPE paper No. 14161presented at the SPE 60th Annual Technical Conference, 22-25Sept. 1985, Las Vegas, NV.

4. Bonomo J.M. and Young W. S.: Analysis and Evaluation ofPerforation and Perforation Cleanup methods, JPT (March1985).

5. Himes, R.E., Dahl, J.A., and Foley, K.A.:Low-Damage Fluid-Loss Control for Well Completions paper SPE 22355presented at the SPE International Meeting on Petroleum

Engineering held in Beijing, China, 24-27 March 1992.6. Marple, B., Griffith, F., Oneal, D,: Successful Completion

Using the Single Trip Perf and Pack7. Jones R.H. and Bolin T.D. New Single Trip Perforating and

Gravelpack Proceedure with Advanced Stimulation Techniques

SPE 393348. Marple B. , Griffin F. Oneal D. Successful Completions in the

Gulf of Mexico Using Sing Trip Perforating and PackingSystems.


7/15


Table 1Single Trip Perf Pack Selection Matrix

Well A Well B Well C Well D Well E Well FFormation fluid sensitive 3 4 4 4 4 21= No Fluid Sensitivity2= Slight Fluid Sensitivity3= Fluid Sensitivity4= High Fluid SensitivityCompletion Fluid 3 4 4 4 4 21= NaCl, KCl, seawater2= Cacl2

3= Ca Br2/ZN Br24= ZN Br2Completion Fluid Loss Risk 2 3 3 3 3 31= Low Fluid Losses2= Medium Fluid Losses3= High Fluid Losses4= Excessive Fluid LossesWell Deviation0= Deviation>62 Deg. 4 4 4 4 4 44= Deviation60 Deg. 3 4 2 4 4 42= Liner < 5.5 and Deviation< 45 Deg.

3= Liner >7" Deviation< 45 Deg.4= Long String Deviation< 60 Deg.Sufficient Distance Below BBSP0= Insufficient Distance to accept Guns. 1 1 1 1 1 11= Adequate Distance to accept Guns.Rig Costs & Completion Time 3 3 1 3 3 11= Low2= Medium3= High4= Deep Water

3.00 3.67 3.00 3.67 3.67 2.67

Evaluation Average 3.28


8/15


Circulating Valve

Testing Packer(Set Position)

Gravel Pack Packer(Run-In Position)

Fluid Flapper

Blank Liner

Gravel Pack Screen

Pressure OperatedFiring Head

TCP Perforating Guns

BBSP Big BoreSump Packer

Perforating

Fluid Loss Flapper


Sump Packer Seals

Testing Packer(Released)

Gravel Pack Packer(Run-In Position)

TCP Guns Fired

BBSP Big BoreSump Packer

Packer Setting Position

Sump Packer Seals

Fig. 1 The Single Trip Perf andPack System Configuration

Fig. 2 The Single Trip Perf andPack System Configuration


9/15


Lower Isolation Ball

Fig. 4

Full Open Perforating Position

Fig. 3

Setting Packer

Fig. 5

Ball Blown To Lower Seat

Fig. 6


10/15


Squeeze

Seals In Seal Bore(Ports Closed)

Circulating

Gravel Pack Packer(Set Position)

Perforations

BBSP Big Bore SumpPacker With Seals Installed

Testing Packer(Released)

TCP Guns Fired

Seals Out Of Seal

Bore (Ports Open)

Fig. 7 Fig. 8


11/15


Reverse

Lower Seals Out OfSeal Bore(Crossover Open)

Lower Seals inSeal Bore(Crossover Open)

Formation Isolated

Upper Fluid LossFlapper (Closed)

Fig. 9 Fig. 10


12/15



Big Bore Sump Packer


Service Tool Packer (Set)

Tubing

Circulating Valve

Pressure Operated Vent

Mechanical Auto Release

Big Bore Sump Packer

Service Tool Packer (Set)

Tubing

Circulating Valve

Pressure Operated Vent

Mechanical Auto Release



Fig. 11 STPP Wash Down Perforating Fig. 12 STPP Wash Down Stimulating


13/15


Fig. 13 STPP Wash Down Completion Fig. 14 STPP/Mechanical Packer Run In

WashdownService Tool

Fluid Loss Flapper

Gravel PackPacker

Setting Ball Opens Isolationand Forms X-over

Washpipe

Blank Liner

Screen

Float Shoe

Perforations

BBS Big Bore SumpPacker for Locating Bottom

ONE JOINT OF TUBING

MULTI-POSITION TOOL

GRAVEL PACK PACKER

CLOSING SLEEVE

FLAPPER VALVE( Open )

PRODUCTION SCREEN

BI DIRECTIONAL MECHANICAL PACKER

PUP JOINT

GUN RELEASE SUB

PORTED SUB WITH GLASS DISC

PERFORATING GUNS

ROTATING SCREEN CENTRALIZER


14/15


TUBING

RADIOACTIVE MARKER

ONE JOINT OF TUBING

MULTI-POSITION TOOL

GRAVEL PACK PACKER (SET)

CLOSING SLEEVE

FLAPPER VALVE ( Open )

PRODUCTION SCREEN

BI DIRECTIONALMECHANICAL PACKER (SET)

PUP JOINT

GUN RELEASE SUB

Fig. 16 STPP/ Mechanical Circulating

TUBING

RADIOACTIVE MARKER

ONE JOINT OF TUBING

MULTI-POSITION TOOL

GRAVEL PACK PACKER (UNSET)

CLOSING SLEEVE

FLAPPER VALVE ( Open )

PRODUCTION SCREEN

BI DIRECTIONAL PACKER (SET)

PUP JOINT

GUN RELEASE SUB

PORTED SUB WITH GLASS DISC

PERFORATING GUNS

Fig. 15 STPP/ Mechanical Packer Run In


15/15

Documents

SPE 54285 Single Trip Perforating and Gravel Pack System Reduces Formation Damage.pdf