Mehul Report

SUMMER TRAINING REPORT

AT WELL STIMULATION SERVICES (WSS)

Oil and Natural Gas Corporation Limited, Ahmedabad

PROJECT: STIMULATION JOBS FOR

OIL AND INJECTOR WELLS

2015

MEHUL JAIN Summer trainee, ONGC, Ahmedabad asset University College of Engineering, RTU, KOTA [Type the company name]

1/12/2015

ACKNOWLEDGEMENT

The training here at Oil & Natural Gas Corporation (ONGC), WSS, Ahmedabad in Stimulation jobs has been a great experience, both educative and enjoyable at the same time. I would like to thank the entire WSS team for their support and co-operation throughout the training period 15.05.2015 to 15.07.2015.

I wish to express my indebted gratitude and special thanks to Mr. S.P.Nainwal, GGM-Head of Well Stimulation Services (WSS), Oil & Natural Gas Corporation Limited (ONGC) for giving me an opportunity to gain an insight into the working of an industry.

I would specially like to thank Mr.P.Dinesan, Sr. HR Executive for allowing me to do my project here at WSS.

I express my deepest thanks to my guide Mr. K.W.S Rajendra (GM, Location Manager WSS) And Mr. S.K. Singh (DGM, Production) for his vital encouragement and guidance to carry out my industrial training work at WELL STIMULATION SERVICES.

I would like to thank Mr. Suyog Yadav (Asst. Executive Engineer) For his guidance throughout the training period.

Mehul Jain

Student of B.Tech. (Petroleum)

University College of Engineering,

Rajasthan Technical University, Kota

Trainee

Comp: Oil & Natural Gas Corporation Limited

Ahmedabad

Well Stimulation Services

Oil and Natural Gas Corporation Limited

Ahmedabad Asset

Certificate

This is to certify that Mr. Mehul Jain from University College of Engineering,

RTU, Kota has successfully completed his project work on ‘Well Stimulation

Jobs for Oil and Injector Wells’ at the Well Stimulation Services (WSS),

ONGC, Ahmedabad as a part of his Curriculum. The Project was carried out

from 1st June 2015 to 15th July 2015.

The project is a part of the fulfillment of the B.Tech. degree in Petroleum

Engineering from University College of Engineering , RTU, Kota.

Mr. Suyog Yadav Mr. S.K. Singh

(Asst. Executive Engineer) DGM- Production

Project Coordinator Project Guide

INDEX

Sr. No. Contents

1. Overview of Well Stimulation Services in ONGC

2. Introduction to Well Stimulation

3. Hydraulic Fracturing

4. Acidization

5. Coiled tubing Services

6. Nitrogen Services

7. Sand Control Services

8. Hot Oil Services

9. Case Study

OVERVIEW OF WELL STIMULATION

SERVICES ONGC

Well Stimulation Services in ONGC started with the creation of central

stimulation team (CST) in year 1975 to cater the stimulation needs of western

region.

The CST was transformed into Well Stimulation Services (WSS), Ahmedabad in

1982.

ONGC entered into a technical collaboration with NOWSCOW, Canada for

transfer of state of the art equipment and technology that were required for

well stimulation.

After the base at Ahmedabad other Well Stimulation Service bases were

subsequently created to cater the needs of different regions.

The Ahmedabad base was made the mother base and the other bases were

developed under its guidance. ONGC now has bases at:

Ahmedabad(1982,mother base)

Sivsagar(1982)

Rajahmundry(1982)

Karikal(1990)

Gandhar(1995)

Bokaro(2001)

Jorhat(2004)

The services provided by WSS can broadly be categorized under two heads

namely 1) Stimulation Services and 2) Allied Production Services. Hydraulic

fracturing, Acidization and solvent / surfactant treatment falls under

stimulation category, whereas Coiled Tubing Services, Sand Control Services,

Nitrogen Services, Hot Oiler Services, Casing Tubing Cleaning, Microbial EOR

etc falls under allied production services.

At present, ONGC own a fleet of highly sophisticated WSS units of different

make and type which are distributed across all the WSS onshore work centers.

These units are;

o Coil Tubing Unit

o Nitrogen Pumper

o Hot Oiler

o Sand Blender

o Sand Dumper

o Multi Purpose Pumping Unit (MPPU)

o Frac Pumper

o Acid Pumper

o Acid Tanker

WSS AHMEDABAD

WSS Ahmedabad was established in 1982, it has expertise in carrying out

different types of stimulation jobs. The head office of WSS Ahmedabad is

located at Chandkheda, Ahmedabad which houses the offices of Head WSS, IN

charge HR-ER, IN charge TSG, IN charge Material Management, IN charge

finance and IN charge procurement and contracts. It has two bases located at

Saij and Sertha. The Saij base takes care of Hydraulic fracturing, Hot oil

circulation and Acidization jobs. It also houses the Maintenance section and

the Chemistry lab, while Sertha base is involved in carrying out Coiled tubing

applications, Nitrogen jobs and Sand control jobs.

WSS Ahmedabad caters to the needs of both Ahmedabad asset and

Mehsana asset it also provides services to Mumbai offshore as and when

required apart from this it also provide support to other bases for special jobs.

The services rendered and capabilities of WSS Ahmedabad are as follows:

1. Hydraulic fracturing

Pumping horse power 9000 HP

Pumping pressure 12000 psi

Pumping rate 60 BPM

Design by 3D FracPro simulator

Experience of more than 1700 jobs

First ever FracPack job in India

2. Acidization

Acid storage capacity 50m3

Pumping pressure 10,000psi

Job design using MACIDES


Development of customized acid formulation for sand stone reservoirs

Deep penetrating acid system

Retarded mud acid system

Reduced strength mud acid

Emulsified acid system

Chemical diversion system

Alcoholic mud acid system

Nitrified acid system

3. Coiled tubing applications

Coiled tubing size :1 1/4 ̓ ̓, 1 1/2 ̓ ̓

Depth: 5000 meters

Injector capacity up to 80,000lbs

Online monitoring of tubing fatigue


CTU operations carried out by WSS Ahmedabad

Well Bore Clean Outs

Zone Isolation for Water Control

Well Stimulation

Well Activation

Velocity String Completion

Well Intervention In Horizontal/High Angle/Multilateral Wells

Well Subduing And Fishing

Well Plug And Abandonment

Cement Drilling

Dewaxing

4. Sand control

Job design and execution of different sand control techniques

GP for 5 1/2 ̓ ̓ and 7 ̓ ̓ casing

High rate water pack

Pre pack completion

Fracpack

High density slurry packing


First gravel packing of horizontal well

Longest gravel pack (>200mts)

First ever fracpack

5. Nitrogen services

Liquid nitrogen storage capacity :100 m3

Pumping rate : 8.5-170 m3/min

Pumping pressure : 10,000psi


Nitrogen applications

Well fluid displacement

Nitrification of fluids for acidization

Foam cleanout in sub-hydrostatic wells

Pressure testing/purging of gas plant,pipe lines and equipment

Foam fracturing

6. Hot oil circulation

Ciculation fluid temperature: 90 ͦ c

Pumping rate : 140 lpm

Heat transfer : 7MMBTU/Hr

Experience of more than 4500 HOC jobs

7. Laboratory services

o Equipments

High temperature, high pressure viscometer

Core flow setup

Sieve analyser

Corrosion test apparatus

API crush test machine

o Chemical formulation for specific field requirements

Hydraulic fracturing

Acidiztion

o Development for field application

High temperature frac fluid

Breaker for low temperature reservoir

8. Maintenance services

o Workshop facilities

Preventive maintenance

Breakdown maintenance

Capital overhauling

Under chassis repair

o Expertise in

Transmission system

Engine

Hydraulic systems

Instrumentation

Pump and compressor

Heat exchengers

o Equipment population

60 primemovers cummins/Detroit/caterpillar

60 transmission Allison and fuller

20 reciprocating pump OPI and SPM

35 centrifugal pumps

250 hydraulic pumps and motors

5 cranes

6 heat exchangers

INTRODUCTION TO STIMULATION

History:-

Stimulation can be traced to the 1860s, when liquid (and later, solidified)

nitroglycerin (NG) was used to stimulate shallow, hard rock wells in

Pennsylvania, New York, Kentucky, and West Virginia. Although extremely

hazardous, and often used illegally, NG was spectacularly successful for oil well

“shooting.” The object of shooting a well was to break up, or rubblize, the oil-

bearing formation to increase both initial flow and ultimate recovery of oil.

This same fracturing principle was soon applied with equal effectiveness to

water and gas wells.

In the 1930s, the idea of injecting a nonexplosive fluid (acid) into the ground

stimulate a well began to be tried. The “pressure parting” phenomenon was

recognized in well-acidizing operations as a means of creating a fracture that

would not close completely because of acid etching. This would leave a flow

channel to the well and enhance productivity. The phenomenon was

confirmed in the field, not only with acid treatments, but also during water

injection and squeeze cementing operations. But it was not until Floyd Farris of

Stanolind Oil and Gas Corporation (Amoco) performed an in-depth study to

establish a relationship between observed well performance and treatment

pressures that “formation breakdown” during acidizing, water injection, and

squeeze cementing became better understood. From this work, Farris

conceived the idea of hydraulically fracturing a formation to enhance

production from oil and gas wells.

The first experimental treatment to “Hydrafrac” a well for stimulation was

performed in the Hugoton gas field in Grant County, Kansas, in 1947 by

Stanolind Oil. A total of 1,000 gal of naphthenic-acid and- palm-oil- (napalm-)

thickened gasoline was injected, followed by a gel breaker, to stimulate a gas

producing limestone formation at 2,400 ft. Deliverability of the well did not

change appreciably, but it was a start. In 1948, the Hydrafrac process was

introduced more widely to the industry in a paper written by J.B. Clark of

Stanolind Oil. A patent was issued in 1949, with an exclusive license granted to

the Halliburton Oil Well Cementing Company (Howco) to pump the new

Hydrafrac process.

What is stimulation?

Oil well stimulation is the general term describing a variety of operations

performed on a well to improve its productivity. Stimulation operations can be

focused solely on the wellbore or on the reservoir; it can be conducted on old

wells and new wells alike; and it can be designed for remedial purposes or for

enhanced production. Its main two types of operations are matrix acidization

and hydraulic fracturing. Matrix acidization involves the placement of acid

within the wellbore at rates and pressures designed to attack an impediment

to production without fracturing or damaging the reservoir (typically,

hydrofluoric acid is used for sandstone/silica-based problems, and hydrochloric

acid or acetic acid is used for limestone/carbonate-based problems). Most

matrix stimulation operations target up to a ten foot radius in the reservoir

surrounding the wellbore. Hydraulic fracturing, which includes acid fracturing,

involves the injection of a variety of fluids and other materials into the well at

rates that actually cause the cracking or fracturing of the reservoir formation.

The variety of materials includes, amongst others: water, acid, special polymer

gels, and sand. The fracturing of the reservoir rock and the subsequent filling

of the fractured voids with sand ("proppant") or the creation of acid channels

allows for an enhanced conduit to the wellbore from distances in excess of a

hundred feet.

Why is stimulation required?

Hydraulic fracturing and acid fracturing in practically all types of formations

and oil gravities, when done correctly, have been shown to increase well

productivity above that projected in both new and old wells. From an economic

standpoint, oil produced today is more valuable than oil produced in the future.

Fracturing candidates may not necessarily "need" oil well stimulation, but the

economics may show that such a treatment would payoff.

To understand why remedial stimulation (matrix acidization) is necessary, one

has to consider the conditions at work, deep down inside the reservoir. Before

the well is ever drilled, the untapped hydrocarbons sit in the uppermost portions

of the reservoir (atop any present water) inside the tiny pore spaces, and in

equilibrium at pressures and temperatures considerably different from surface

conditions. Once penetrated by a well, the original equilibrium condition

(pressure, temperature, and chemistry) is permanently changed with the

introduction of water or oil-based drilling fluids loaded with suspended clays,

and the circulation of cement slurries. The interaction of the introduced fluids

with those originally present within the reservoir, coupled with pressure and

temperature changes can cause a variety of effects which, in turn, can plug the

numerous odd-shaped pores causing formation damage. Some of the types of

damage include: scale formation, clay swelling, fines migration, and organic

deposition.

Petroleum engineers refer to the level of formation damage around the wellbore

as skin effect. A numerical value is used to relate the level of formation damage.

A positive skin factor reflects damage/impedance to normal well productivity,

while a negative value reflects productivity enhancement. Formation damage,

however, is not limited to initial production operations. Remedial operations of

all kinds from well killing to well stimulation itself, can cause formation

damage. Nor is fines and scale generation limited to the reservoir. They can also

develop in the wellbore in casing and tubulars, and be introduced from surface

flowlines and incompatible injection fluids. These fines and precipitates can

plug pores and pipe throughout an entire oil field.In short, any operation

throughout a well's life can cause formation damage and impede productivity.

Hydraulic Fracturing

What is fracturing?

If fluid is pumped into a well faster than the fluid can escape into the formation,

inevitably pressure rises, and at some point something breaks. Because rock is

generally weaker than steel, what breaks is usually the formation, resulting in

the wellbore splitting along its axis as a result of tensile hoop stresses generated

by the internal pressure. the simple idea of the wellbore splitting like a pipe

becomes more complex for cased and/or perforated wells and nonvertical wells.

However, in general, the wellbore breaks—i.e., the rock fractures—owing to the

action of the hydraulic fluid pressure, and a “hydraulic” fracture is created.

Because most wells are vertical and the smallest stress is the minimum

horizontal stress, the initial splitting (or breakdown) results in a vertical, planar

parting in the earth.

The breakdown and early fracture growth expose new formation area to the

injected fluid, and thus the rate of fluid leaking off into the formation starts to

increase. However, if the pumping rate is maintained at a rate higher than the

fluid-loss rate, then the newly created fracture must continue to propagate and

grow.This growth continues to open more formation area. However, although

the hydraulic fracture tremendously increases the formation flow area while

pumping, once pumping stops and the injected fluids leak off, the fracture will

close and the new formation area will not be available for production. To

prevent this, measures must be taken to maintain the conductive channel. This

normally involves adding a propping agent to the hydraulic fluid to be

transported into the fracture. When pumping stops and fluid flows back from

the well, the propping agent remains in place to keep the fracture open and

maintain a conductive flow path for the increased formation flow area during

production.

The propping agent is generally sand or a high strength, granular substitute for

sand. Alternatively, for carbonate rocks, the hydraulic fluid may consist of acid

that dissolves some of the formation, leaving behind acid-etched channels

extending into the reservoir.

Stages in Proppant Fracturing job

Spearhead

Sometimes, the formations can be difficult to breakdown and under such

scenario spearhead is pumped to reduce formation breakdown pressure. In this

stage, typically 5 - 10 bbl of HCl acid is pumped ahead of pad. -half the volume

at matrix acidization rates and the remaining at higher rates.

Pad

Pad stage breaks down the blocked perforations and initiates fracture. Proper

volumes of fluids are required to be pumped since small pads may not develop

sufficient width for placement of proppant thereby potentially causing screen-

outs. Excessive pad may delay closure for a significant period of time, allowing

proppant convection out of zone. The pumping rates must exceed formation

leak-off limits in order to propagate the fracture.

Proppant Stages

The proppant stages immediately follow the pad in which fracturing fluid mixed

with proppant is pumped into the formation to generate length and width of the

fracture.

Initially proppant slurry of low concentration is pumped since perforations and

formation near well bore may not accept higher concentrations of proppant early in

the treatment if the wedge is not large enough. The proppant concentration is

gradually increased in steps of 1 to 2 ppg once the perforations and formation near

well bore are eroded.

Flush

In this stage, clean fluid is pumped to displace the proppant to within a short distance

of the perforation and remove it from the well bore. Often low friction, economical

fluid is used.

Energized Treatments

These specialized treatments make use of N2/CO2 and are used in sub-

hydrostatic formation to aid in load fluid recovery.

Why fracture?

Hydraulic fracture operations may be performed on a well for one (or more) of

three reasons:

• To bypass near-wellbore damage and return a well to its “natural” productivity

• To extend a conductive path deep into a formation and thus increase

productivity beyond the natural level

• To alter fluid flow in the formation.

Fracturing Fluid Systems

The basic function of fracturing fluids is to transmit pressure to the formation and

transport proppant into the fracture. Based on formation types and base lithology,

presence of additional mineral components, formation fluid nature, objective of

fracturing, pumping configuration planned and above all the economics, various

fluids-both Newtonian and Non-Newtonian- are used as fracturing mediums. Some of

them are Water-Based, Hydrocarbon–Based, CO2 assisted Fluids, Emulsion–Based,

N2 Foams, Methanol based etc.

Various type of additives used in fracturing fluids are Gelling agents/ Gellants,

Cross-linkers, breakers, buffers, surfactants, clay stabilizers, friction reducers,

fluid loss controllers etc.

Crosslinkers

Crosslinkers are added to the fluid systems to increase the viscosity of the

fracturing fluid so that it can transport the proppant deep inside the fracture. If

the fluid viscosity is low, the proppant would settle down before reaching the

fracture and it would be detrimental to the treating iron.

Breakers

Relatively high viscosity fluids are used to transport proppant into the fracture.

Leaving a high-viscosity fluid in the fracture would reduce the permeability of

the proppant pack to oil and gas, limiting the effectiveness of the fracturing

treatment. Gel breakers are used to reduce the viscosity of the fluid intermingled

with the proppant.Breakers reduce viscosity by cleaving the polymer into small-

molecular-weight fragments.

Fluid Loss Additives

The loss of fluid from the fracturing fluid, may result in formation of filter cake

over the perforations. Hence, fluid loss additives are added to the gel.

Bactericides

Bactericides are added to polymer-containing aqueous fracturing fluids to

prevent viscosity loss caused by bacterial degradation of the polymer.

Stabilizers

Stabilizers are used to prevent degradation of polysaccharide gels at

temperatures above 200°F.

Surfactant

A surface-active agent, or surfactant, is a material that at low concentration

adsorbs at the interface between two immiscible substances. The immiscible

substances may be two liquids, such as oil and water, a liquid and a gas, or a

liquid and a solid.

Clay Stabilizers

Clay Stabilizers are used to prevent the swelling of clays encountered while

fracturing the formation.

Proppant

Proppants are used to hold the walls of the fracture apart to create a conductive

path to the wellbore after pumping has stopped and the fracturing fluid has

leaked off. Placing the appropriate concentration and type of proppant in the

fracture is critical to the success of a hydraulic fracturing treatment. Factors

affecting the fracture conductivity (a measurement of how a propped fracture is

able to convey the produced fluids over the producing life of the well) are

proppant composition

physical properties of the proppant

proppant-pack permeability

effects of postclosure polymer concentration in the fracture

movement of formation fines in the fracture

long-term degradation of the proppant.

ACIDIZATION

Acid may be used to reduce specific types of damage near the wellbore in all

types of formations. Inorganic, organic, and combinations of these acids, along

with surfactants, are used in a variety of well stimulation treatments. In

carbonate formations, acid may be used to create linear flow systems by etching

hydraulically created fractures. Acid fracturing is not applicable to sandstone

formations.

The two basic types of acidizing are characterized through injection rates and

pressure. Injection rates below fracture pressure are termed matrix acidizing,

while those above fracture pressure are termed as fracture acidizing.

MATRIX ACIDIZATION :-

Matrix stimulation is a technique that has been used extensively since the 1930s

to improve production from oil and gas wells and to improve injection into

injection wells. Matrix stimulation is accomplished by injecting a fluid (e.g.,

acid or solvent) to dissolve and/or disperse materials that impair well production

in sandstones or to create new, unimpaired flow channels between the wellbore

and a carbonate formation. In matrix stimulation, fluids are injected below the

fracturing pressure of the formation (McLeod, 1984). It is estimated that matrix

treatments constitute 75% to 80% of all stimulation treatments (matrix and

fracturing) worldwide, but the total expenditure for matrix treatments is only

20% to 25% of the total for all stimulation treatments. However, because the

payout time for matrix treatments is normally days rather than months as it is

for conventional fracturing treatments. Many operators around the world have

indicated that an average of 40% to 50% of their wells have significant damage,

but routinely only 1% to 2% of their wells are treated every year. Substantial

production improvements can be achieved with matrix stimulation if treatments

are engineered properly. A success rate greater than 90% is reasonable.

Acidization is a technique of injecting acid and chemicals in the reservoir to reduce

damage near the well bore for improving well productivity/ injectivity. Inorganic,

organic and combination of these acids along with surfactants are used in variety of

well stimulation treatments. The two basic types of acidizing are characterized

through injection rate and pressures. Injection rates below fracture pressure are termed

matrix acidizing while those above fracture pressure are termed as fracture acidizing.

Matrix acidizing is primarily applied to remove near well bore damage caused

by drilling/ completion/ workover fluids. or injection fluids and by precipitation

of scale deposits from produced or injected water. The goal of matrix acidizing

is to achieve radial acid penetration in to the formation for removal of effects of

permeability reduction near well bore. The objective of an acid treatment is to

react with the formation rock and / or pore plugging materials to form suitable

salts that can be produced to the surface, or displaced into the pore system some

distance away from the well bore - thus providing enlarged or more open flow

channels.

Basic acids used in various combinations are Hydrochloric Acid, Hydrochloric

+ Hydrofluoric Acid, Formic Acid and to lesser extent Fluoboric Acid and

Sulfamic Acid. Typically, 15 % HCl acid for carbonate reservoirs and 12 %

HCl & 3 % HF acid for sandstone reservoirs is used in wells.

Acid Additives :-

Acidizing can be the cause of a number of well problems. Acid may release

fines, create precipitants, form emulsions, create sludge and corrode steel.

Additives are available to correct these and number of other problems. Each

acid additive used serves a specific purpose. However, where several additives

are used they must be carefully checked under simulated treatment conditions to

ensure that one additive does not react with another. Some of the commonly

used additives are.

Corrosion Inhibitor

Corrosion inhibitors are used to prevent metallic corrosion from occurring and

work through creation of a protective layer on the metallic surface. Factors that

govern acid attack on steel are; steel type and hardness, temperature, acid type,

acid concentration and acid contact time.

Surfactant

Surfactants are used to change surface and interfacial tensions, prevent emulsions,and

water-wet rockand fines near the well bore. The use of surfactants in acid assists in

faster flow back of spent acid after acid treatment thereby improving the chances of

early well activation.

Non-Emulsifier

The non-emulsifier contains water-soluble polymer that is temperature sensitive

that helps to lower surface tension and prevent damage.

Anti Sludge Agent

“Sludge” is a precipitate resulting from reaction of high strength acid with

crude. The sludge formation can hamper cleaning of the well and flow

performance

Iron Controller

In order to prevent precipitation of iron, iron controllers are used in the acid that

control iron precipitation either through chelating (iron chemically bound) or

sequestering (iron held in solution).

Mutual Solvent

The mutual solvent is used to reduce water saturation near the well bore, maintain a

water wet formation, water wet insoluble formation fines and help reduce the

absorption of surfactants and inhibitors on the formation

Diverting Agent

The diverting agent plays a major role in selective acidization of a particular

layer. The diverting agent blocks the permeable layer and allows the acid to

enter the intended zone and get stimulated.

Clay Stabilizer

Certain clay compounds can be treated with acid but result in undesirable

reactions during acidization like swelling and creation of water blocks that

hamper the stimulation job efficiency. Clay stabilizers are used to keep the clays

and fines in suspension.

Fluid Loss Control Agents

Helps in extending fractures in fracture acidizing by reducing acid leak off into

the formation.

STEPS INVOLVED IN ACIDIZATION

The primarily acidization treatment involves following three stages:

• Pre-flush Stage

In this stage, 5 to 10 % HCl acid is pumped in to formation to remove the

carbonates and also to push NaCl and KCl away from the well bore. The volume

of pre-flush pumped depends on thickness of the layer to be treated but in general

50 to 100 gal/ft of the formation is the norm.

• Acid Stage

This forms the main stage in the acidization. Requisite volume of HCl acid

is pumped into the formation to dissolve the carbonates and create paths /

vugs to connect reservoir with well bore. HF acid is used in the case of

sandstone reservoirs to dissolve clay and sand.

• After-flush stage (10% EGMBE)

Subsequent to acid stage, 10 % EGMBE is pumped as after flush to make

the formation water wet and to displace acid away from the well bore.

Pump entire treatment at low rate, 0.25 to 0.5 bbl/min below frac pressure.

As HCL and HF spend very rapidly, start removing the spent acid from

around the wellbore within about one hour after treatment is completed. In

flowing wells, initially flow back should be at low rate and gradually

increasing over a reasonable time. In non flowing wells some means of

initiating flow, i.e. swabbing or gas lifting will be required. It is not always

necessary to swab water and gas injection wells following an acid job.

Within one hour after treatment, regular injection in water or gas injection

wells may be resumed.

SET UP FOR ACIDIZATION JOB :-

The acidization set-up typically consists of :

a) Acid tanker of 12m3 volume for transportation of 30 % HCl acid from

WSS base to well site.

b) Acid Pumping Unit (APU) equipped with acid mixing tank to prepare

acid of requisite composition and concentration, pumping system

complete with metering and controls.

c) Syphon assembly to safely transfer acid from acid tanker to acid mixing

tank.

d) Flexible steel pipe / coflex hose to carry acid from pumping unit in to the

well.

COILED TUBING SERVICES

Coiled Tubing :-

In the oil and gas industries, coiled tubing refers to metal piping, normally 1" to

3.25" in diameter, used for interventions in oil and gas wells and sometimes as

production tubing in depleted gas wells, which comes spooled on a large reel.

Coiled tubing is often used to carry out operations similar to wirelining. The

main benefits over wireline are the ability to pump chemicals through the coil

and the ability to push it into the hole rather than relying on gravity. However,

for offshore operations, the 'footprint' for a coiled tubing operation is generally

larger than a wireline spread, which can limit the number of installations

where coiled tubing can be performed and make the operation more costly.

coiled tubing units are second generation of workover rig with hydraulic

system for well servicing under pressure. The Coiled Tubing Unit (CTU) has

endless tubing stored on a reel and run into hole (RIH) or pulled out of hole

(POOH) by means of continuous motion friction device (Injector assembly).

Well servicing using coiled tubing has grown significantly with the

development of tooling and tubing technology. The size of tubing available

vary from 1 inch through 4 ½” inch (in ONGC, 1 ¼” and 1 ½” size is normally

used). The material of tubing has improved tremendously to give higher

performance. Much of the recent increase in capability is due to the increased

performance of downhole motors, which provided the ability to rotate,

enabling drilling and milling operations etc.

CT APPLICATIONS :-

The Coiled Tubing Unit (CTU) is used for various well servicing jobs. Some of the

applications are as listed here under:

CONVENTIONAL CT APPLICATIONS

Jetting for bottom/ screen clean out.

Activation for production

Paraffin removal

Stimulation

Tubing clean out

Emergency well control

ADVANCED CT APPLICATIONS

Through-tubing operations like fishing, packer setting, zone isolation etc.

Cementation and water shut off

Running, setting, pulling wireline pressure operated type tools.

Selective zonal acidizing

SPECIALIZED CT APPLICATIONS

Logging and perforations

Cleaning of flow lines

Servicing of horizontal wells

STIMULATION JOBS THROUGH CT

1. The stimulation jobs, mainly acid applications and nitrogen placement,

are carried out through CT especially when annulus is packed off. Stimulation

jobs through CT not only save the time but provide efficient and accurate

placement of acid, easier & faster removal of spent acid and provides

continuous well control. However, acid job through CT has working pressure

limitation and affect the CT life considerably.

2. The use of CT in high-pressure wells requires additional considerations

with regard to pressure control equipment, burst & collapse rating of the CT,

capability of injector head to push the CT against high wellhead pressures and

possibility of CT buckling. During CT operation in high-pressure wells, the

collapse of CT can be avoided by using smaller diameter, heavy walled CT and

maintaining pressure inside CT. In addition, the CT is run without check valves

to prevent emptying of the string.

DESCRIPTION OF COIL TUBING SYSTEM

The CT system comprises of following equipment;

A. Operator’s Control Cabin

B. Tubing reel

C. Injector head

D. Pressure Control Equipment

E. Power pack

F. Goose neck

G. Stripper

H. BOP system

A. Operator’s Control Cabin

The control cabin houses all the controls for the reel, the injector head, and

also all electronic logging systems and instrumentation. It is placed directly

behind the reel to provide the operator with a full view of all activities

especially the spooling of the tubing off and on the reel, the well head &

injector.

The control console continuously monitors the operational parameters of

various components of the CT system. It houses the controls relevant to the

operation including the main hydraulic control panel (to control the

injector, reel and spooler system), well control package (stuffing box,

emergency BOP functions), main recording instrumentation and depth

correlation.

B. Tubing Reel

Tubing reel stores the tubing which is coiled around the core of the reel.

Ideally the core should be as large a diameter as possible to prevent severe

bending of the tubing but must be of a manageable size for transporting to

and from well sites.

The major components of CT reel include reel drum, reel drive system, level

wind assembly, reel swivel and manifold as shown in figure 2.1. The reel is

driven by chain from a hydraulic motor and is controlled from the control

cabin. The tubing is pulled off the reel up over the gooseneck by the

injector.

C. Injector Head

The injector allows the CT to run in or out of the well. Major injector-head

components include hydraulic motors, drive chains, chain tensioners,

gooseneck or guide-arch and weight indicator.

The injector is the motive device, which imparts upward or downward

movement to the tubing and is mounted above the BOPs on the wellhead.

It must be supported, as the connection to the BOPs is not designed to

absorb the weight and lateral forces caused by the tension in the tubing

from the reel.

Movement is imparted to the tubing by sets of travelling chains equipped

with gripper blocks, which are hydraulically driven.

The gripper blocks grip by friction which is adjustable through a hydraulic

piston applying pressure across the chains. This pressure must be

sufficiently high enough to grip the tubing eliminating slippage but not

excessively high enough to crimp the tubing.

D. Pressure Control Equipment

The pressure control equipment consists of stuffing box, stripper elements

and BOP of various designs depending on a particular application.

The stripper is designed to provide a pressure-tight seal or pack-off around

the coil tubing as it is being run in or pulled out of a well under pressure

conditions.

This seal is achieved by energizing the stripper packer that forces the inserts

to seal against the tubing.

The BOP consists of blind rams, shear rams, slip rams, pipe rams, equalizing

valves, top and bottom connections etc. The BOP rams are hydraulically

operated from the control cabin using the BOP hydraulic circuit and

accumulator. The accumulator provides a reserve of hydraulic energy to

enable the BOP to be operated following an engine shutdown or circuit

failure.

E. Power pack

The power pack provides the hydraulic energy to operate the CTU functions

and controls. Generally, it consists of a diesel engine driving an array of

hydraulic pumps supplying each system or circuit with the required

pressure and flow rate. The major components of power pack include

engine, pumps, pressure control valves, hydraulic reservoir, filters &

strainers, heat exchanger and hydraulic fluid.

F. Goose Neck

The gooseneck is simply a guide who accepts the tubing coming from the

reel and leads it into the injector chains in the vertical plane. The goose

neck guides the pipe using sets of rollers in a frame spaced on the

recommended radius for the tubing being run.

G. Downhole tools

Downhole tools can be categorized in to:

Primary tools such as CT connectors and check valves that are essential

for any CT operation and are hence invariably used

Support tools such as release joint and jar to enhance or support the

basic tool string functions or provide a contingency release function.

Functional tools are some special tools that are selected to perform a

particular operation such as wash over tools, jetting tools etc.

CTU rigged up on a well

NITROGEN SERVICES

Nitrogen constitutes 75% of air by weight or 79% by volume. Almost all the rest

is oxygen. Liquid nitrogen and nitrogen in gaseous form is extensively used in

the oil industry. Use of N2 in stimulation jobs is typically done for faster

activation of sub-hydrostatic formations. It is also used in conjunction with acid

or any other treating fluid in order to provide a source of energy for faster flow

back of spent acid/ recovery of treating fluid, improved penetration, better

clean-up and reduced fluid loss. Other uses of nitrogen in field are for purging

and pressure testing gas plant cleaning out wells.

Nitrogen Properties

Liquid nitrogen is lighter than water. One liter of water weighs 1.0 kilogram

whereas one liter of liquid nitrogen weighs only 0.809 kilogram. Gaseous

nitrogen is lighter than air. At 200 C, 1 M3 of air weighs 1.205 kg whereas 1.0 M3

of N2 weighs 1.165 kg.

Some of the properties of nitrogen are :-

- Colorless, odorless, tasteless, non-corrosive and non-toxic inert gas

- Neither supports combustion, nor respiration.

- Molecular weight : 28.0134

- It is slightly soluble in most of the liquids

- Sp. Gravity of N2 gas (compared to air): 0.967

- Boiling Point: (-) 195.8 °C

- Melting point (-) 2100C

- 1 M3 of liquid nitrogen: 694.43 M3 of gaseous nitrogen (at 150C and 1 atm)

Description of Nitrogen Unit :-

An oil field unit may be mounted on either a trailer or on a single chassis truck

or on the skid. It comprises of three basic components:-

1. Vacuum insulated vessel to store liquid nitrogen

Liquid nitrogen is stored in special pressure vessel at - 1950 C (-3200 F). The

vacuum insulated vessel is of double walled construction. The inner tank is a

stainless steel pressure vessel which holds the liquid nitrogen and the outer

mild steel. The annular space between two tanks contains insulating materials

under a vacuum to reduce heat transfer.

2. Cryogenic pumping system

Liquid nitrogen from the tank flows to a "boost pump" through stainless steel

pipes. This boost pump is a hydraulic centrifugal pump with cryogenic liquid

handling capabilities. The boost pump raises the pressure of the liquid up to

120 psi. The nitrogen at 120 psi is then fed to a high pressure cryogenic pump.

These high pressure liquid nitrogen pumps are positive displacement type

usually in a triplex configuration. The PD pumps raise LN2 pressure to that

required to carryout the particular job undertaken.

3. Vaporizer unit.

The liquid nitrogen is vapourised to gas by the addition of heat either by a

direct fired or a flameless vaporizer. On the type of vaporizer system criteria,

nitrogen units are categorized as

- Diesel fired nitrogen pumping unit

- Non-fired nitrogen pumping unit.

In the former type of unit, liquid nitrogen from high pressure pump is forced

through a series of stainless steel coiled tubes which are heated by hot air from

diesel burner. The liquid nitrogen in these coils absorbs heat & is gasified.

The non-fired nitrogen pumping unit works on waste heat recovery principal.

This vaporizer system uses the engine coolant (glycol / water) to recover heat

from the engine, transmission, exhaust and hydraulic system. The engine

coolant temperature is about 760 C to 820 C (1700 F to 1800 F) as it leaves the

engine system. Heat exchange between this coolant and liquid nitrogen from

high pressure triplex pump takes place in a helical coiled tube heat exchanger.

Low temperature coolant is then circulated through a transmission oil to

coolant heat exchanger and exhaust gases to coolant heat exchanger to reach

about 600 C (1600 F ) before it re-enters the diesel engine. Temperature of the

gasified nitrogen through nitrogen to coolant heat exchanger may further be

enhanced, as it passes through stainless steel coiled tubes, by diverting

exhaust gases from the engine over these tubes if required, by means of a

diverter valve. This gaseous nitrogen from 100 C to 650 C (500 F to 1300 F) is the

final product which flows down the line for its various applications.

SAND CONTROL SERVICES

Marine deposited sands, most oil and gas reservoir sands, are often cemented

with calcareous or siliceous minerals and may be strongly consolidated. In

contrast, Miocene or younger sands are often unconsolidated or only partially

consolidated with soft clay or silt and are structurally weak.

These weak formations may not restrain grain movement, and produce sand

along with the fluids especially at high rates.

Fluid movement causes stresses on the sand grains because of the fluid pressure

differences, fluid friction and overburden pressures. If these stresses exceed the

formation-restraining forces, then the sand will move and be produced. Rapid

changes in flow rates and fluid properties cause unstable conditions which can

result in increased sand production.

It has been shown that particle movement occurs in multiphase flow when the

wetting fluid starts to move.

Consequences of Sand Production

Production interruptions can be caused by sand plugging the casing,

tubing, flow lines and separators.

Casing collapse can be caused by changes in overburden pressures and

stresses in the formation.

Downhole and surface equipment can be destroyed, downtime and

replacement costs, spills and in extreme cases a blowout.

Disposal of produced sands is costly.

Methods of Sand Control

Restricting the production rate of the well. This reduces the drag forces on the

sand grains. This is often an uneconomical solution. Increasing the number and

diameter of the perforations also reduces the flow velocity and drawdown

pressures.

Gravel packing is the oldest and simplest method of sand control. Works in both

on and off shore wells.Sand consolidation; resins are injected into the formation

binding the grains of sand while leaving pore spaces open.Resin coated gravel

packs; gravel coated with resin is placed in the casing and perforations. The

resin binds the grains together which results in a strong but permeable filter.

The excess is drilled out of the casing so the well is produced with a full

opening wellbore. This can be used with or without a screen, can be placed

using coiled tubing.

The method of sand control will depend on such parameters as grain-size

distribution, clay content, interval length, well deviation, flow rate and of course

costs. Various methods of sand control in use are:

Restrictive production rate.

Mechanical methods using Slotted liner, Wire-wrapped screen, Pre-packed screen,

Frac pack, Gravel pack, High rate water pack.

Chemical methods.

Combination methods.

Gravel Pack

Gravel pack consists of sized particles placed in the annular space between an

unconsolidated formation and a centralized screen. The GP job can be carried

out in open or cased hole.

The several advantages of GP are:

Suitable for long intervals

No chemical reaction is involved.

Suitable for old wells too that have already produced sand.

Cheaper than chemical treatment techniques for sand control.

Does not affect permeability.

Equipment for Gravel Pack

The GP equipment can be categorized into:

Surface equipments

Tanks

Filtering units

Pumping/Blending units

Down hole equipments

Bull plug / Shoe

Screen

Blank pipes (60’ to 300’)

Tell tale screen

Centralizers

Packer

Over the top system

Cross over

Sequence of Operations:

The sequence of operations in a typical cased hole GP job hole are as follows:

1. The hole is cleared up to bottom.

2. The prospective/producing layer is perforate/ re-perforated.

3. The casing is scraped.

4. Bridge plug is set below the perforations with appropriate sump.

5. The mud is then circulated & conditioned.

6. The GP assembly is then run up to the required depth.

7. The GP packer is set.

8. The circulating / Squeeze / Reverse position modes are marked.

9. The layer is acidized in squeeze mode

10. The gravel slurry is pumped till screen out/pack off.

11. The excess gravel is reversed out.

12. The seal assembly is then stabbed out and GP assembly is pulled out of hole.

13. Well is then completed for production.

HOT OIL SERVICES

A problem that has plagued producers since the discovery of the first oil well is

that of paraffin deposition in well tubular. This is especially true for oils with a

high asphaltine base.

The low ends of oil may build up on the tubular to the extent of completely

shutting off production. Usually production gets chocked with solid paraffin

deposition in upper portion.

An effective method of removing paraffin build-up is to melt the paraffin with

hot oil/hot water/chemicals circulation. Specially designed Hot Oil Units are

used to heat the oil/water to a temperature of 2000 to 5000 F and either

bullhead it into the well or circulate it through a work string.

If the paraffin depositing is solid it will often have to be “washed” out with a

work string.

Common Procedure for Paraffin Removal from the Well Tubing

using CTU :-

Common procedure to remove paraffin from the tubing involves rigging up of

CTU in standard manner and circulating hot oil using hot oil unit. A high

temperature pack-off rubber should be used in the pack-off. Procedure in brief

is as described below.

1. The hot oil unit discharge line is connected to the rotating hub of the CTU

reel. Hot oil/hot water/chemicals should be circulated through the CT until

the CT is hot prior to going in the hole.

2. Circulation of the hot fluid should be maintained from surface to

approximately 500 feet below the fresh water zones. Circulation should be

maintained for at least two hours after reaching the desired depth. This will

ensure melting away all the paraffin rather than simply washing a hole

through it.

3. Returns should be monitored to be sure the oil is hot enough to melt the

paraffin before circulation is stopped.

4. Extreme caution should be used when working around hot oil. If the hot

come in contact with someone, then creates severe burn.

5. Hot water and chemicals can also be used for paraffin removal depending

upon the situation.

CASE STUDY

CASE STUDY

As a part of my On Training Program, I have been a part of few stimualation

jobs that have been carried out. Few of the case studies have been mentioned.

ACTIVATION JOB (CTU with NITROGEN):

Well no. – NKD#194

Well type – Oil Well

Tubing Size – 2 7/8”

Casing Size – 5 1/2”

Perforation Interval – 1026-1028 m

Objective of Job – Well Activation

Lowered Depth – 900 m

Circulating Medium – Nitrogen

Units used for Job: Coil Tubing Unit and Nitrogen Pumper.

Job Details – RIH 11/4” CT lowered with wire of Nitrogen @ 2000 psi upto

900 m, obstruction did not felt upto lowered depth. Return observed

little amount of oil, N2, brine. CT P/O upto the surface.

ACID JOB :

Well no. – SK#135

Well type – Injector-Effluent


Tubing Shoe Depth – 1870 m


Perforation Interval – 1875-1883 m

Objective of Job – Acidization

Units used for Job: Acid Pumper

Job Objective – Bottom Hole Cleaning To Improve t Injectivity of

the well

Job Details –

Chemical Used by (%): HCl – 10%, ACI – 1% , Acetic Acid – 2%,

Surfactant – 5%, Citric Acid – 2% Amonium Bifluoride, EDTA.

Noted injectivity following solutions were squeezed in the formation.

3 m3 – 7.5% HCL+Additives, 3 m3- 7.5% HCL+1% HF+ Additives

Injectivity before job – 150LPM @2400 psi.

Injectivity after job – 4000 LPM @2200 psi.

FOAM JOB (CTU with FOAM):

Well no. – NGM#252




Perforation Interval –1719-1727 , 1736-1739 m

Objective of Job – Well Activation


Circulating Medium – Nitrogen,Water,Gel.

Units used for Job: Coil Tubing Unit and Nitrogen Pumper.

Job Details –

RIH 11/4” CT lowered with wire of Nitrogen @ 3200 psi upto

1754 m, obstruction did not felt upto lowered depth.

A lot of sand and N2 were observed in return. P/O CT upto 1600m. N2

Cut and knockout tubing volume from 1600m foam&N2 observed in

return, then CT P/O upto the surface.

BOTTOM HOLE CLEANING (CTU with ACID):

Well no. – BECH#171

Well type – Effluent Disposal Well



Perforation Interval – 1002-1006,1007-1009.5,1010-1014,1017-1019,

1021-1025,1026-1028,1031-1035,1038-1043,1047-1050m.


Circulating Medium – Water, gel then acid.

Units used for Job: Coil Tubing Unit and Acid Pumper.

Job Details – RIH 11/4” CT with circulation of water @3000 psi upto 900m

then RI with gelled water @4000 psi CT lowered upto 1067m with

Reciprocating pump. Obstruction felt at 1045&1047m. Return flow

observed Blackish dirty water, fine sand, clean water then 2m3 pre flush,

7.5% HCL + Additives, 4m3 mud acid, 7.5% HCL+1%HF+Additives.

Injectivity Before Acid – 150 LPM@4000psi.

Injectivity After Acid – 200 LPM@3600psi.

HOC JOB:

Well no. – KL#431


Problem in the Well – Wax Deposition



Packer – SRP

Objective of Job – Hot oil circulation

Circulating Medium – Hot Oil

Units used for Job: Oil tanker and hot oil Pumper.

Job Details –

Oil was transferred from oil tanker to the hoc unit where it was heated

at 850 C and then pumped into the well in the annulus. Circulated oil and

produced oil was observed in return.

HYDRO FRACTURING JOB :

Well no. – GM#152

Well type – Oil


Tubing Shoe Depth – 1000.36 m


Perforation Interval – 1012-1017m

Objective of Job – To increase the permeability

Units used for Job: Acid Pumper

Job Objective – Productivity improvement

Frac Fluid – X- linked Guar Gel

Job Details –

Chemical Used:-

Proppant- 37 mt, KCL- 3 mt

G.A(Grade II),.-1000 kg, Borax- 50kg, Soda ash- 150kg, Surfactant- 720kg,

Acetic acid- 30kg, APS- 70kg,TEA- 50kg, Biocide- 60 lt.

The units that were employed for the hydrofracturing job are:

Frac Pumpers - 3

Blender - 1

Sand Dumpers - 2

Fracvan - 1

Acid pumper - 1

Lorry Loader - 1

Frac Tanks - 3

Job detail - The total frac fluid was 37 MT which was placed in the well at

an avg. 2471 psi. the injectivity was 13 bpm and the breakdown pressure was

1571 psi.

Gravel Pack Job:

Well no. – SNL#261


Well Depth- 1174m

Screen length- 9.28m

Problem in the Well – Sand Production


Casing Size – 7

Objective of Job – To minimize the sand production

Rig - John- 5

Job Details –

Firstly screen was placed at the perforation interval.5 MT Gel was prepared

first, was a mixture of HSC(Hydroxy Ethyl Cellulose) plus brine (1.2 S.g) plus ISP

(Proppant). Then gel was placed in the well at 2000 psi. in return broken gel

was observed.

Documents

Mehul Report