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Contrast Between Plug And Perf Method And Ball And Sleeve

Method For Horizontal Well Stimulation

By Prakhar Mathur, Nitesh Kumar

Summary:

In recent years world has witnessed a huge increase in demand of energy. Hence, mankind is now compelled to develop and

use new technology to recover from non-conventional resources. This calls for new technological developments whose

application can cater to the global energy needs. One such development is multi-stage well stimulation in horizontal wells. This

review paper compares the two most common methods of multi-stage horizontal well stimulation i.e., widely used “plug & perf

method” and relatively new “ball & sleeve method”, with their detailed analysis, operating principles and limitations. The paper

closely examines their feasibility of economical as well as time aspects. It deals with confinement of fracturing process, involved

potential risks and differences are showcased including maximising the production by tailoring treatments for unorthodox

problems with a help of short case study.

Introduction

Well Stimulation is a technique to improve the well productivity/ injectivity by applying various reservoir and/or wellbore

treatments. This process aims at minimizing reservoir damage or eliminating production problems. It fulfils the following

basic requirements:

Bypasses near-wellbore damage and return a well to its “natural” productivity / injectivity

Extends a conductive path deep into a formation and thus increase productivity / injectivity beyond the natural

level

Produces hydrocarbon from tight formation

This technique can be achieved by matrix acidization, fracture acidizing and hydraulic fracturing. Among these, hydraulic

fracturing is the most accepted operation of the industry. Hydraulic fracture is a process of creating a fracture in a porous

medium by injecting a fluid under pressure through a well bore in order to overcome native stresses and to cause material

failure of the porous media. Although naturally occurring fractures in the rock such as cracks, fissures, joints, faults, etc. are

caused due to thermal, chemical and other geo-stress imbalances in the past. The artificial fractures are achieved by

pumping of hydraulic power fluids in the wellbore at a pressure exceeding the fracture pressure based on fracture gradient.

The integrity of the produced cracks and fractures is preserved by adding the propping agents to the power fluid at the time

of injection. Hydraulic fracturing is desirable under prevailing conditions:

When the formation is very tight

Having low permeability and poor conductivity

Having relatively high pressure.

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Since the inception of this technology, its scope has increased by many folds. Earlier its applications were limited to

conventional reservoirs with vertical orientation. With latest advancements in technology like horizontal well completion we

got better method for infill drilling and reservoir depletion.

Unconventional reservoirs have been defined as formations that cannot be produced at economic flow rates or that do not

produce economic volumes of oil and gas without stimulation treatments or special recovery processes and technologies.

Unconventional resources like tight-gas reservoirs, shale gas, coal bed methane have come into existence recently.

The problems faced during the exploitation of these unconventional resources using conventional techniques were:

Increase in the effective surface area of the well to maximize reservoir contact. (Figure 1)

Low vertical permeability resulting in less inflow.

Less net pay thickness.

Other short comings were the ability to effectively stimulate or fracture the horizontal wellbore from the toe to the heel,

particularly in reservoirs that were not naturally fractured.

The use of limited entry and bull-heading techniques provided little benefit compared to vertical wells. Post production

analysis on the deliverability of horizontal wells in reservoirs such as matrix, heterogeneous and non-conventional

formations showed a direct correlation to the completion and stimulation methods employed and their shortcomings in

horizontal applications. Thus, the added expense of a horizontal well was not justified by the equal to or slightly better

production results versus vertical wells.

Thus for efficient exploitation of the non-conventional plays and to fulfil the ever increasing global energy demand Multi

Stage Horizontal Well Stimulation was introduced. The goal was of increasing access to the reservoir through the induction

of fractures along the entire length of the horizontal wellbore. Since then extensive research has been done in this field

which provided satisfactory results and remarkable increase in production from horizontal wells.

This system comprise of the traditional methods of fracturing in multiple number of stages. The number of stages vary

according to the extent of the horizontal well in the reservoir (usually 1000’-1500’). This technique called off for introduction

of new improved equipments whose details have been provided further in the paper.

Solution: Plug & Perf Technique

Introduction

Cemented liner,multi-stage fracturing method. This type of completion involves cementing production casing in the

horizontal wellbore and “plug and perf” stimulation (Blanton and Mackenzie, 2006). Mechanical isolation in the liner is

accomplished by setting of bridge plugs using pump down wireline or coiled tubing (CT), followed by perforating and then

fracturing the well to provide access to the reservoir. The cement provides the mechanical diversion in the annulus while

the bridge plug provides the mechanical diversion inside the liner. This process is then repeated for the number of

stimulations desired for the horizontal wellbore. After all the stages have been completed, Coiled Tubing is used to drill

out the composite plugs, thus re-establishing access to the toe of the horizontal wellbore. Although an effective method of

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creating diversion along the horizontal for discrete stage stimulation, the inherent cost of multiple interventions with CT,

perforating guns and deployment of fracturing equipment needed for each stage are extremely high, not to mention, very

inefficient and time consuming (Houston et al., 2010; Samuelson et al., 2008). Production using this method can also be

limiting, as cementing the wellbore closes many of the natural fractures and fissures that would otherwise contribute to

overall production (Themig, 2010).

Working

The technique requires multiple trips in and out of the well to accomplish individual components of an overall fracture

stimulation completion. The first step in the process is to get communication from the tubing to the annulus at the toe of the

well. Perf and plug uses a perforating assembly to initiate a fracture by using shaped explosives (perforating gun) (Figure

2). Once the perforation has been created, the assembly is run out of the hole and the wellhead is rigged up to pump trucks

so that proppant can be injected into the fractured zone. Once completed, the pumping equipment is detached and a new

perforating assembly coupled with a mechanical plug is run into the hole and set to isolate the treated zone from the next

highest zone targeted for stimulation. There the perforation assembly is triggered to initiate the fracture in the new target

zone, which is run back out of the hole to allow for the pumping of proppant into the fracture. This process continues until

all zones within the well have been treated. The description of the fracturing fluid and proppant are as follows:

Fracturing Fluid: The fluid used during hydraulic fracture treatment of reservoir consists primarily of water with some

additives (in required concentrations) depending upon the conditions of the specific well being fractured. It has two

functions. Firstly it opens and extends the fracture and secondly transport the proppant along the fracture length.

Proppant: These are the suspended particles in fracturing fluids that are used to hold fractures open after hydraulic

fracturing treatment, thus producing a conductive pathway that fluids can easily flow along. Naturally occurring sand grains

or artificial ceramic materials are common proppants used.

Advantages

Used to stimulate cased wells.

After the plugs have been milled out, the hydrocarbon get full wellbore radius for production.

It is the simplest system to run in the hole and providing the full availability of wellbore diameter for stimulation

purpose.

Modelling of induced fractures can be done (simulation possible)

Controlled fracturing

Because of the above mentioned advantages it has gained strongest foothold in the market.

Problems faced

The necessity for repeated CT interventions and the repeated rigging up and down of the fracturing or stimulation

equipment.

The situation gets complicated when the wellbore crosses sensitive zones, such as water zones, that need to

be isolated from wellbore treatments

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Depending on the well design and fracture-treatment design requirements, this process could take several

hours per zone and require the frac crew to be idle while the plug and TCP/wireline trips are made to get ready for

another frac.

Problems are often encountered when cementing horizontal liners in place with the added benefit of having a

liner in the horizontal, which is beneficial for CT access and remedial operations later in the life of the well.

Continued innovation such as pump-down plugs etc. have made this process more efficient, but at its best,

operators are still only able to perform two or possibly three frac jobs per day on a single well.

This process works well if over- flushing a previous fracture treatment is not an issue. It is a well-established

process, but not feasible when multiple fractures are desired for a short duration.

Solution to the above mentioned problems – Ball & Sleeve Method

Introduction

In 2000, the development of open hole mechanical diversion was placed at the forefront of research and development. Over

the next two years various product components and systems were tested and deployed in the field. These tests led to what

is now the standard system for open hole completions, with more than 300 successful runs to date.

Uncemented , open hole, multi-stage (OHMS) fracturing method or in short Ball and Sliding Sleeve System :

Between 2004 and 2006, a new, open hole, multi- stage system (OHMS) completion technology was run in Denton

County, Texas (Lohoefer et al., 2006). OHMS were pioneered in 2001 with the goal of making multi-stage fracturing more

efficient, both in terms of time and cost, as well as repeatable and reliable (Seale et al., 2006; Seale, 2007). OHMS use

hydraulically set mechanical external packers instead of bridge plugs and cement to isolate sections of the wellbore. These

packers typically have elastomer elements that expand to seal against the wellbore and do not need to be removed, or

milled out, to produce the well. Instead of perforating the casing to allow fracturing, these systems have sliding sleeve tools

to create ports in between the packers. These tools can be opened hydraulically (at a specific pressure) or by dropping

size-specific actuation balls into the system to shift the sleeve and expose the port(Figure 3). The balls create internal

isolation from stage to stage, eliminating the need for bridge plugs .OHMS permits that all the fracture treatments can be

performed in a single, continuous pumping operation without the need for a drilling rig. Once stimulation treatment is

complete, the well can be immediately flowed back and production brought on line. By developing a system to set in open

hole, provide mechanical diversion and allow multiple fractures to be performed along the entire horizontal wellbore, all the

problems associated with horizontal completions to date have been addressed. The packer would be required to sustain

differential pressures of 10,000 psi at temperatures up to 425OF and set in holes enlarged up to 50%.

Working

The stimulation sleeves also have the capability to be shifted open by landing a ball on a ball seat. The operator can

use several different sized dropping balls and corresponding ball-landing seats to treat different intervals(Figure 4). It is

important to note that this type of completion must be done from the toe up with the smallest ball and seat working the

bottom/lowest zone. The Ball Activated Sliding Sleeve has a shear-pinned inner sleeve that covers the fracture ports until

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a ball larger than the cast iron baffle in the bottom of the inner sleeve seats on the baffle and a pressure differential

sufficient to shear the pins holding the inner sleeve closed is achieved to expose the fracture ports. When a ball lands on

its specific seat, it isolates any zones treated below it and hydraulic pressure applied above the ball shifts the sleeve

to the open position and aligns the ports to treat the next zone. The opening balls are phenolic and can be either drilled

up or flowed back to surface once all the treatments are completed. The landing seats are made of a drillable material and

can be drilled to give a full wellbore ID. When a ball injector was used, it was not necessary to shut down the pumps

between stages. The shifting-tool profile remains in the inner mandrel so the operator can still engage and close a

selected sleeve once the balls and ball seats are drilled out. Using the stimulation sleeves with ball-activation capability

removes the need for any intervention to stimulate multiple zones in a single wellbore. The description of Stimulation

sleeves, swelling packers and ball seats are as follows:

Stimulation Sleeve: The stimulation sleeve was designed to be run as part of the casing string. It is a tool that has

communication ports between the ID and the OD of casing. The stimulation sleeve was designed to give the operator the

option to selectively open and close any sleeve in the casing string (up to 10,000 psi differentials at 350°F).

Swelling Packer: The swelling packer requires no mechanical movement or manipulation to set. The patented technology

is the rubber compound that swells when it comes into contact with any liquid hydrocarbon. The compound will conform to

the ID that it is swelling in and will continue to swell, up to 115% by volume of its original size.

Ball seats: These are designed to withstand the high erosional effects of fracturing and the corrosive effects of acids.

Advantages

The introduction of the sleeve and swelling packer system (SSPS) technology now gives operators another

completion method of effectively and economically completing new multi-zone wellbores with minimal to no

intervention. Stimulation through the sleeves required less HHP, as a result of lowered treating pressures and

providing the option to close the fracture ports in later date.

A great efficiency is realized by performing multiple fractures or stimulation in a single pumping operation, which

equates to significant savings of time and money, while reducing the health, safety and environment (HSE)

hazards associated with those activities.

Because fractures are able to initiate anywhere within the open-hole section of each isolated stage, the fracture

will take the path of least resistance i.e. where the breakdown pressure is the lowest. This, in turn, reduces the

potential for fracture tortuosity.

The necessity for repeated Coiled Tubing interventions and the repeated rigging up and down of the fracturing or

stimulation equipment is also eliminated with this system.

The erosion resistance technology of the ball seats provides a design that could easily be milled/drilled. This

allows all obstructions in the liner to be removed so full access to the toe of the horizontal wellbore could be

attained.

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Sometimes added backup may be provided in handling the high treating pressures that would be encountered.

This system provides a redundant seal over a specified length, which was determined through modelling would

prevent the stimulation or fracture to propagate past the seal.

The packer optimizes the mechanical diversion within the designed section length in the open hole horizontal

wellbore and yet, flexible enough to navigate higher dog legs encountered in some drilling environments.

With full access through the liner, standard operations associated with CT, logging, flow testing, etc. can be

performed.

It is common to have issues with noise and the surface owners while completing these wells, so the less time

a stimulation crew can spend on locations, the better it will be for community relations. Removing the

explosives from locations also removes one of the safety hazards.

That issue is the ability to re-fracture the well without having to utilize a work string or a rig. With the Re-

Closable FracPort design, all stages can be closed, leaving only the last one open and the well can be re-

fractured just as it was initially, by dropping balls and pumping specifically designed fracturing treatments for

each specific section of the horizontal well.

Problems faced

The limiting factor in the number of ball-drop activated tools run in a single wellbore is the undesired low

fracture flow rates due the reducing size of available balls and ball seats.

The larger balls would flow back to surface, but the smaller ones could not.

Another issue inherent in the OHMS system is the presence of the “hoop stress” around the wellbore and the

fact that there is no medium in place to combat longitudinal growth along the wellbore (Barree et al, 2009)

Contrasting features between Plug & Perf Method and Ball & sleeve method:

1. Cost Analysis

The most significant cost savings use of OHMS come from the saved time on location and horsepower

requirements associated with the fracture treatment. Tubing Conveyed perforating, Wireline perforating and

plugs are just a few of the added costs needed to perform the plug and perf procedure that are not necessary in

the OHMS system. The OHMS completion method eliminated approximately two weeks of completion operations

at a cost savings of $300,000 to $400,000 per well at 2005 pricing.

Additional costs for plug-and-perf operations include renting and running a tieback string to provide a mono-bore

for plug and gun deployment, wireline charges, and additional pumping charges.

The cumulative effect of this delay over the course of a sustained drilling program can have a significant impact

on the net present value (NPV) of the project.

For example, in the Bakken Shale an extra 200 bbl is used per stage to pump down plugs. For a 14-stage

completion, the average cost for water using OHMS is US$40,000 saving 15% or $6,000 per job (Zander et al.,

2010). The cumulative effect of these savings taken over the course of a sustained drilling program can have a

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significant impact on the net present value of the project.

2. Time Aspects

With no logistical issues or mechanical failures, the fracture treatment of a 20-stage OHMS (the technical limit at

the time of the study) could be pumped in a single, 24-hour period. A comparable plug and perf completion can

take up to five days.

An additional benefit is to greatly increase the availability and flexibility of the service company’s hydraulic

fracturing treatment equipment schedule.

The shorter stimulation treatment time of OHMS completions allows for less stand-by time of frac and wireline

services and also allows the well to be put on production faster than a cemented liner, plug and perf well,

which maximizes usage of increasingly limited frac crews (Edwards et al., 2010; Loehoefer et al., 2010).This

disparity is strictly due to the time required to pump each stage for the plug and perf method.

The plug and perf method require bridge plugs to be pumped down the tubing, which requires the wellbore to be

flushed clean of all proppant to avoid getting the plug stuck before it reaches the desired setting depth which is a

time consuming process.

3. Production Performance

The study was undertaken to compare cemented verses uncemented multi-stage fractured wells in the Barnett

shale. This study analyzed the data of the two types in the same time period and the long-term production

recoveries .

Previous studies in the Barnett Shale have indicated that uncemented wells perform better than cemented

wells (Fisher et al., 2004). However, despite having opened other unconventional plays, the perception

persists that open hole completions do not work within certain areas where cemented casing dominates (Britt

and Smith, 2009).

Example: Once the well list was narrowed down to the Central study area, each well was categorized as OHMS or perf

and plug. Cumulative production was used to evaluate the production performance of wells in each category. A chart

containing the average 6 month and 12 month cumulative production is found below. Results are in MMCFE using a 6:1

bbl:MCF ratio.

6 months 12 months

OHMS 300 478

Plug and Perf 224 358

The OHMS completion method outperformed the plug and perf method by 33% through 12 months of production. Not as

many wells have enough production to extend the comparison beyond 12 months, but most wells appear to be

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staying on trend.

4. Optimisation Scope

In terms of optimizing production of multi-stage stimulated wells, recent modelling simulations of depletion profiles

from 6-stage open hole and cemented liner multi-stage completions have shown that open hole completions result

in better drainage of the lateral (Themig, 2010). However, most models are unable to simulate the varying stresses

in a horizontal wellbore the actual growth path and therefore size of the fracture cannot be determined. This

creates a problem when attempting to optimize the fracture growth to allow for the most contact with the

formation.

While the plug and perf method does seem to combat the majority of the concerns above including isolation with

cement, perforations that extend into the formation to combat the hoop stress (Britt et al, 2009).But

cementing off the lateral prevents the contribution of production from natural fractures and fissures often present in

unconventional reservoirs that an open hole lateral would benefit from.

5. Operational Characteristics

The major operational advantage of OHMS completions is that they can be performed in a single, continuous

pumping operation without the need for a drilling rig or wireline/CT services. This single feature provided the

primary source of time and cost savings.(Edwards et al., 2010; Houston et al., 2010; Lohoefer et al., 2010;

Samuelson et al., 2008).

However the plug and perf technology required following tasks, all down hole work after the drilling rig had

reached total depth (TD): cementing of the lateral casing, coiled tubing or tubing conveyed toe stage perforating,

the setting of 5 or 6 bridge plugs, and perforating runs for a 6 or 7 stage hydraulic fracture treatment design. Then,

after fracturing treatment, the long drill out process of bridge plugs set between stages.

6. Stimulation dynamics

There are differing opinions on how fractures initiate in the two systems:

The OHMS system allows for the fracture treatment to seek out the area of least principal stress along the

wellbore and propagate one or multiple fractures. This method seems like a natural fit in a hard rock low perm

environment, however it can lead to some problems when attempting to model the fractures.

However in Plug and Perf method concrete entry points into the formation to allow for easier fracture initiation

(Britt et al, 2009) and then propagation throughout the reservoir.

7. Well Downtime

Discounting fracture treatment scheduling concerns often encountered, a well completed using OHMS can be put

on production within two days of rig release.

The plug and perf system can add an additional 4 days to the fracture treatment and introduce several logistical

“headaches” including trucking and timing issues.

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8. HSE factors (Health, Safety and Environment)

OHMS completions are safer due to the reduced number of trips in and out of well, reduced time on site, as

well as no requirement for perforating explosives.

9. Best fracturing practices

Development of best fracturing practices over the last few decades would include: not overdisplacing proppant, ensuring

near-wellbore conductivity, promoting immediate flowback, optimizing load recovery, keeping breakdown pressures low,

minimizing fracture tortuosity and minimizing fluid loading (Themig, 2010)

Immediate flowback.

The importance of managing the flowback period of a well is another parameter that has been recognized

as an important factor for optimum well production performance (Crafton and Gunderson, 2007). OHMS

completed wells can be immediately flowed back and put on production after stimulation as opposed to

requiring time-consuming drill out of bridge plugs and potential shut-in periods which can exacerbate

formation damage and cause irreparable reductions to the flow rate and regained permeability.

Overdisplacement

In plug and perf ,to ensure that bridge plugs do not get stuck in the well due to the presence of proppant in the

wellbore from the previous stage, an entire wellbore worth of fluid is displaced before a bridge plug is pumped

down which although removes the extra proppant but also pushes that proppant out into the fracture away from

the wellbore. On the other hand, by taking into account the type of system being run, the depths, lateral lengths

and fluids being displaced, OHMS completions can more accurately place a ball on seat to isolate the previous

stage’s fracture treatment resulting in the more ideal situation – proppant placed right at the wellbore reducing

overdisplacement of the fracture treatment.

Case Study

(FracPoint System Increased Production in Bakken Formations)

A well drilled in the Bakken shales in North Dakota was fractured with multistage fracture treatments have shown an

increased production rate. An operator wanted to increase the number of stages in a packer and sleeve well and asked

Baker Hughes to design a system that would combine the cost-effectiveness of a packer and sleeve system with the

increased number of initiation points of a plug and perf system.

Through extensive research into ball materials and redesigning the ball seats, the Baker Hughes team designed and

developed a 24-stage packer and sleeve system that would combine the benefits of both isolation methods and meet the

operator’s needs. The system underwent a thorough testing program that validated its performance. The patented, new ball

seats allowed ratings of 8,000 psi (551 bar), 1/8-in. incremental ball sizes and increased flow rates for the smaller sizes.

The 24-stage FracPoint™ multistage fracturing system was deployed in a horizontal well where it performed flawlessly. The

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FracSur EX technology increased the initiation points along the wellbore as well as increasing initial production rates.

Because of this success, the operator continues to use the FracPoint multistage fracturing system with new Baker Hughes

technologies to enhance well completions.

Conclusion

Although contrasted above it can be concluded that the advent of these stimulation techniques has led to the tremendous

growth in the unconventional reservoir. Plug & Perf and Ball & Sleeve method have risen up as the most common

completion methodologies for tight reservoirs. The OHMS completion strategy accomplished all initial efficiency objectives

with the added benefits of improved high density completion (more stages in the same lateral length),. In addition to better

long-term recoveries, OHMS completions intrinsically use better fracturing practices, as well as being a safer and more

efficient use of resources. On the other hand, plug and perf method has also proved its reliability. For example it is

historically opted method of completing Granite Wash wells till today.The fracture direction can be better controlled using

this method since the flow path to the reservoir is manually generated. In the presence of high stress rock, plug and perf

should be the preferred method. The technique being most utilized, efficiently initiates fractures with lower treating

pressures. However Ball & Sleeve Technique has been running worldwide in a variety of formations, both on and offshore

proving it to be more versatile.

System Cost Analysis

Time Aspects

Production Performance

Optimisation Scope

Operational Characteristics

Stimulation Dynamics

Well Downtime

HSE

Best fracturing practices

Plug and perf system

- - - + - + - - -

Ball activated sliding sleeve

system

+ + + - + + + + +

+ Advantage, - Disadvantage , ** Comparisons done above are relative to one another.

References

ONGC Production Operations Manual

SPE 104557; Multistage Fracturing System: Improving Operational Efficiency and Production R. Seale, SPE, Packers Plus Energy Services; J. Donaldson, SPE, D&J Oil Co.; and J. Athans, SPE, Packers Plus Energy Services

SPE 142729;Optimisation of Completions in Unconventional Reservoirs for Higher Ultimate Recovery Daniel J. Snyder, SPE and Rocky Seale, SPE, Packers Plus Energy Services

SPE 138445;Tight Gas Multi-stage Horizontal Completion Technology in the Granite Wash W. M. Jason Edwards P.E., SPE, Daniel K. Braxton, SPE, Vince Smith, Jones Energy, SPE

SPE 135386;Comparative Study of Cemented Versus Uncemented Multi-Stage Fractured Wells in the Barnett Shale Darrell Lohoefer, SPE, Eagle Oil & Gas, and Daniel J. Snyder, SPE, Rocky Seale, SPE, and Daniel Themig, SPE, Packers Plus Energy Services

SPE 124120;Cemented, Ball-Activated Sliding Sleeves Improve Well Economics and Efficiency Timothy Bozeman, SPE, Halliburton, and Dennis Degner, SPE, Encana

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SPE 106705;Multizone Completion With Accurately Placed Stimulation Through Casing Wall Ron Hinkie and Matt Howell, Halliburton

SPE 147546; Benefits And application of a surface controlled sliding sleeve for fracturing operation Joel Shaw, Halliburton

www.bakerhughes.com

SPE JPT Online Magazine

www.packersplus.com

www.halliburton.com

www.glossary.oilfield.slb.com

Figures

Figure 1: Illustration of increased reservoir contact in horizontal well as compared to vertical wells.

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Figure 2: Schematic of plug and perf method in horizontal well.

Figure 3: The 4 phases involved in the process of sleeve activation: sleeve closed before landing, ball landing,

sleeve shifting open and the sleeve reaching the end of travel.

Figure 4: Schematic of ball activated sliding sleeve technique in horizontal well.

About the authors :

Prakhar Mathur, student 3rd year, Pandit Deendayal Petroleum University.

e-mail: prakhar.mbtech09@spt.pdpu.ac.in, ph.no. : +91 9723493492

Nitesh Kumar, student 3rd year, Pandit Deendayal Petroleum University.

e-mail: nitesh.kumarbtech09@spt.pdpu.ac.in, ph.no. : +91 9408334433