Libya

Ministry of Higher Education

Bright Star University_Brage

Bright Star University_Brage

Faculty Of Technical Engineering

Department Of Petroleum Engineering

Water Shutoff Treatment in Zelten Field (S.O.C)

By Ayoub Faraj Bushala 21142294

Bobkraamd Abdullah Abuhajr 21142391

Gamal Abdel Nasser Bouayad 21142371

Mohamed El - Mabrouk Mohamed 13024

Saleh Ahmed Saleh 21142044

Supervised By

Mansor Bogful

Project Report Submitted as Partial Fulfillment of the Requirements

for the Degree of Bachelor in petroleum Engineering

SPRING 2019

I

Water Shutoff Treatment in Zelten Field (S.O.C)

By

The Student Name SN

Ayoub Faraj Bushala 21142294

Bobkraamd Abdullah Abuhajr 21142391

Gamal Abdel Nasser Bouayad 21142371

Mohamed El - Mabrouk Mohamed 13024

Saleh Ahmed Saleh 21142044

Supervised By

Mansor Bogful

Project Report Submitted as Partial Fulfillment of the Requirements for the

Degree of Bachelor in petroleum Engineering

SPRING 2019

II

ABSTRACT

Water shut-off is defined as any operation that delays water to reach and enter the production

wells. Water production is one of the major technical, environmental, and economic

problems associated with oil and gas production. Water production not only limits the

productive life of the oil and gas wells but also causes several problems including

corrosion of tubular, fines migration, and hydrostatic loading . The conventional water

shutoff method has been applied in Zelten field (S.O.C) for the wellbore isolation by cement

plug in the watered out zone, unfortunately it was not successful.

However, in December 2005, a pancake type water shutoff treatment was proposed and

conducted.

The polymer only sets in the watered out zone and acts as a barrier for a certain

time to prevent the water coning. The water cone eventually circumvents the barrier

created by the polymer and starts affecting the well production. However, during the

time period when the water conning is prevented/minimized, there should be an

increase in the oil production before water coning is back again.

The pancake type treatment involves pumping a polymer (OrganoSeal of Schlumbeger) at

some distance in the shape of a pancake from the wellbore into the watered out zone.

This project presents case histories of treatments that was performed to shut off water

producing in well (C98) in Zelten Field After that comparing C-98 and C-164 with C-

149, while the water production and water-oil ratio were reduced after the water shut

off job, the water shut off jobs were not successful in case of wells C-98 and C-164 as

experienced in C-149.

III

DEDICATION

We Salh, Mohammed, Gamal, Ayoub And Abubaker Confirm that this work

submitted for assessment is my own and is expressed in my own words. Any uses

made within it of the works of other authors in any form (ideas, equations, figures,

text, tables, program) are properly acknowledged at the point of their use. A list of

references employed is included.

Signed ………………………………………….

Date …………………………………………..

Project supervisor signature

IV

ACKNOWLEDGEMENTS

Praise be to Allah, who has done good deeds ... Now after the years and tired of travel

and fatigue study .... Now complete the course of study .. And pledge this work to the

honest actors The source of love and affection and pleasure heart my father and my

mother To those who are pleased my heart my brothers and sisters To those who

share my concerns and joy in the studies of my friends and colleagues To the source

of science and knew this great edifice (Bright Star University) To the professors and

doctors They thank us for their and appreciation.

Thank you to the supervisor of this letter and its success. He has all the thanks

and appreciation of Professor (Mansor Bogful ) . Peace be upon you.

V

APPROVAL

This project report is submitted to the Faculty of Technical Engineering, Bright Star

University – Braga, and has been accepted as partial fulfillment of the requirement for

the degree of bachelor in petroleum Engineering. The members of the Examination

Committee are as follows:

________________________________________

Supervisor

Mansor Bogful

Department of petroleum Engineering

Faculty of Technical Engineering

Bright Star University – Braga

____________________________________________

Examiner 1

…………………………………………………………

Department of petroleum Engineering

Faculty of Technical Engineering

Bright Star University – Braga

____________________________________________

Examiner 2

………………………………………………………..

Department of petroleum Engineering

Faculty of Technical Engineering Bright Star University – Braga

VI

DECLARATION

I hereby declare that the project report is my original work except for quotations and

citations, which have been duly acknowledged. I also declare that it has not been

previously, and is not concurrently, submitted for any other degree at Bright Star

University – Braga or at any other institution.

___________________________________

The student name

SN

Ayoub Faraj Bushala

Bobkraamd Abdullah Abuhajr

Gamal Abdel Nasser Bouayad

Mohamed El - Mabrouk Mohamed

Saleh Ahmed Saleh

Date:

VII

LIST Of CONTENT

Subject Page No

ABSTRACT II

DECLARATION III

ACKNOWLEDGEMENTS IV

APPROVAL V

DECLARATION VI

Table of Content VII

LIST of FIGURE IX

LIST of TABLE X

CHAPTER 1 .INTRODUCTION

1.1 Background 1

1.2 problem statement 1

1.3 Objectives of The Dissertation 2

CHAPTER 2

2.LITERATURE REVIEW

2.1 History of water shut off 3

2.2 Water shut off concept 4

2.3 classifications of water shut off 5

2.3.1 Well configuration and well completions 6

2.3.2 Mechanical method 6

2.3.3 Mechanical and cement treatment 6

2.3.4 Chemical methods 7

2.3.4.1 Nonselective water shut off agent 7

2.3.4.1.1 Weak gel plugging agent 7

2.3.4.1.2 Oily sludge plugging agent 8

2.3.4.1.3 Cement plugging agent 8

2.3.4.1.4 Resin plugging agent 9

2.3.4.2 Selective water shut off agent 9

2.3.4.2.1 Oil-based plugging agent 9

2.3.4.2.2 Water plugging agent 9

2.3.4.2.3 Alcohol-based plugging agent 10

2.4 GEL TREATMENT FOR CONFORMANCE CONTROL 10

2.4.1 WATER PROBLEM 10

2.4.2 WATER CONTROL PROBLEMS 13

2.4.2.1 Near Wellbore Problem 13

2.4.2.1.1 Casing leaks problem 13

VIII

2.4.2.1.2 Flow behind the pipe 14

2.4.2.1.3 Barrier breakdowns 14

2.4.2.1.4 Channels behind the casing 15

2.4.2.1.5 Inappropriate completion 15

2.4.2.1.6 Scale, debris and bacterial deposits 15

2.4.2.2 Reservoir Related Problems 15

2.4.2.2.1 Coning and cresting 15

2.4.2.2.2 Watered-out layer with and without crossflow 16

2.4.2.2.3 Channeling through a high permeability zone 17

2.4.2.2.4 Fingering 17

2.4.2.2.5 Out of zone fractures 17

2.4.2.2.6 Fracture between the injection and producing well 18

2.4.3Excessive Water Production Problems and Treatment Categories: 18

2.4.4 Gel treatment for improved production Well performance 20

2.4.5 GEL CONFORMANCE IMPROVEMENT TREATMENT 22

2.4.6 GEL TYPE 22

2.4.6.1 Polymer Gels 22

2.4.6.2 Silicate Gels 24

2.4.6.3 Relative Permeability Modifiers (RPM) 25

2.4.6.4 Advantages Gel Treatment over Cement Treatment 25

2.4.7 GEL TREATMENT SIZING FOR PRODUCTION WELL 25

2.4.7.1 Gel injection volume based on minimum volume 25

2.4.7.2 Gel injection volume based on distance 26

2.4.7.3 Gel injection volume based on well response 26

2.4.7.4 Gel injection volume based on experience in a given field 26

2.4.8 PLACEMENT TECHNOLOGIES 26

2.4.8.1 Bullhead Placement Technique 27

2.4.8.2 Mechanical Isolation 28

2.4.8.3 Dual Injection 29

2.4.8.4 Isoflow Placement 30

2.4.8.4 Overview of Three Gelant Placement Methods 31

CHAPTER 3

3.METHADOLOGY 3.1 Descriptive Approach To Research 32

CHAPTER 4

4.RESULTS AND DISCUSSION 4.1 Zelten Field: Water Shut off

CHAPTER 5

5.CONCLUSIONS AND RECOMMENDATIONS 5.1 Conclusion 44

5.2 Recommendations 44

Reference 45

IX

LIST OF TABLE

Page No Subject 3 The development of water shut off profile control technology application in

China

91 Conformance problem for excessive water and treatment

categories (Seright, 2001)

42 Conformance problems suitable for polymer gels (PetroWiki, 2013)

42 Conformance problems suitable for polymer gels (PetroWiki, 2013) (cont.)

39 Overview of gelant placement method (Miller & Chan, 1997)

X

LIST OF FIGURE

Subject Page No

Water shut off concept 5

Worldwide water oil ratio distribution 11

Water control method for increasing well productivity (Bailey et

al., Water Control)

12

Good and bad water (Bailey et al., Water Control) 13

Casing leaks (Bailey et al., Water Control) 14

Flow behind the pipe (Bailey et al., Water Control) 14

Water coning in both vertical and horizontal wells (Chaperon,

1986)

16

production well both with and without coning (PetroWiki, 2013) 16

Watered-out layer (A) with and (B) without crossflow (Bailey et

al., Water Control)

17

Fractures or faults from a water layer surrounding a (A) vertical

well or a (B) horizontal well (Bailey et al., Water Control)

18

Fractures or faults between an injector and a producer (Bailey et

al., Water Control)

18

. Bullhead placement technique (Jaripatke & Dalrymple, 2010) 28

Mechanical packer placement technique (Jaripatke & Dalrymple,

2010)

29

Dual-injection placement technique (Jaripatke & Dalrymple,

2010)

30

Isoflow injection placement technique (Jaripatke & Dalrymple,

2010)

30

Coiled Tubing Operations 35

XI

1

CHAPTER 1

1.INTRODUCTION

1.1 Background

Drilling an oil well is a massive project that requires multiple teams of workers and

very deep pockets. But money and manpower aren't enough. Before beginning, there

will be permits and proposals to fill out, serious research to conduct, and some very

specialized equipment to obtain. Only then can a company begin drilling for its own

deposit of "black gold‖. After the well is drilled it have to be completed in order to

start the production. Oil well completion is the process of preparing the well for

production, it includes operations such as lowering a steel casing inside the drilled

hole and cementing the casing to the formation, it also involves lowering a steel tube

smaller in diameter than the casing known as the production tubing which is

connected to the well head on the surface, this project study the process of cement

technology and its benefits to the petroleum production process, [BJH-72]. Cementing

is the process of mixing cement and water and pumping it through steel casing to

bond and support casing and to restrict fluid movement between formations, is used in

the oil-well industry all over the world, [BJH-72]. The zelten field is located in

concession 6 and it was discovered in April 1959 when well C1-6 tested 17,500

STB/D of 37º API gravity oil on a DST, the zelten reservoir is a structural trap that is

comprised of three lobes (North, South ,and South East Nasser). It is bounded by a

major fault on the west and water-oil contact ranging from 5360 ft.ss in the Southeast

to 5340 ft.ss in the South and North. The zelten has been sub-divided into the upper

zelten ,zelten Porosity and Lower zelten zone .the Uppermost zelten zone is generally

of low permeability and may or may not be in communication with the underlying

zelten porosity zone (Layer 4) the lower zelten zone is of good permeability but lower

porosity than the zelten porosity zone. It hosts the water leg of the zelten in north,

South and the South East Nasser Pools, The porous interval is approximately 300 feet

thick and the very crest of the structure is at ± 5000 ft.ss.

1.2 problem statement

a distinction is made in the water encroachment in oil wells in terms of "good water"

and "bad water". The "good water" is the unavoidable bottom water influx which

helps to displace the oil. On the other hand, the "bad water" is possibly avoidable

2

water which is produced by the phenomenon of the water coning or "water fingering"

in the high permeability layer(s). It is the "bad water" caused by the water coning

which is sought after to be shut off or more precisely "delayed". The water coning is

difficult to be permanently avoided but can be delayed. The success of the water

shutoff should be judged by the incremental oil production due to the increase in the

oil production before the water coning again returns.

1.3 Objectives of The Dissertation

The objective of this study is to prevent and reduce the excessive water from entering

in production oil well and to understand a chemical-based water control technique in

oil wells and the methodology for identification and resolving the source of water

production problem.

In this work, a dataset has been generated from Zelten field (S.O.C) in June/87 and

from 12/2005 to current time. This study also seeks, investigation of objectives

following:

1. Increase useful life of oil well.

2. Increase oil recovery factor.

3. Decrease water production.

4. Prevent water from entering oil well.

5. Decrease water problems.

6. Delay water coning from occurrence.

7. Reduce cost of production.

3

CHAPTER 2

2.LITERATURE REVIEW

2.1 History of water shut off

From the drilling of the first oil well in 1860, oil has become one of the most precious

commodities around the world. Since then, oil has been the source of around 50% of

the world’s energy and the oil industry has grown overwhelmingly attractive to many

investors, be it governments or private companies. The final products of oil, from

petroleum to plastics are a product of heavily invested petrochemical industries.

Nowadays, the oil industry is administrating a significant part of the world economy.

Moreover, the interest in securing the oil producing regions triggers political and

social problems around the world. As a result, the terms ―oil‖ and ―black gold‖ are

frequently used interchangeably. The production of oil is a result of a long process

starting with exploration, passing through the drilling of exploration wells, appraisal

wells, and production wells. Due to its origin, oil is usually produced along with water

and gas. Hence, this mixture requires the construction of many surface facilities to

separate, pump/compress, and transport the separated fluids. Moreover, the separated

water should be disposed appropriately so that it does not harm the environment. The

exponential growth of technology has been assisting in the decrease in the unit

production cost of oil. Moreover, technological advancements in the oil industry have

made it possible to produce oil from previously unrecoverable, or uneconomic,

reserves. (Mennella et al., 1999).

Water shutoff profile control technology application research in China generally has

the following four stages of development, as described in table 1.

Table1.The development of water shut off profile control technology application in China

Years Stage of oil field Technical type Plugging agent

_____________________________________________________________________

50s-70s Early stage Mechanical water plugging Cement, resin, heavy oil

Profile control technology calcium chloride, etc.

_____________________________________________________________________

70s-80s Early stage Physical barrier blocking Strong gel plugging agent

based polymer and

crosslinking agent.

_____________________________________________________________________

4

90s High water Polymer water shutoff and Applied in different

cut stage deep water plugging and system of nearly 100

profile control kinds of plugging agent.

_____________________________________________________________________

After 2000 Extra high Deep water shutoff and the Deep water flooding

water stage deep fluid diversion technology supporting

water shutoff agent.

Flooding problems in high water cut period are increasingly complex, so requirement

of water shutoff technology is becoming higher, driven by its rapid development. In

recent years, water shutoff technique and plugging agent research in China has made

many advances in the international leading position, R & D, containing weak gel

dispersion gel, swellable particle profile control technology, the high water cut

oilfield water flooding development effect is improved, and improved the recovery

ratio [2, 3].

2.2 Water shut off concept

Water shut-off is defined as any operation that hinders water to reach and enter the

production wells. Water production is one of the major technical, environmental, and

economical problems associated with oil and gas production. Water production not

only limits the productive life of the oil and gas wells but also causes several

problems including corrosion of tubular, fines migration, and hydrostatic loading.

Produced water represents the largest waste stream associated with oil and gas

production. Moreover, the production of large amount of water results in:

(a) the need for more complex water–oil separation.

(b) rapid corrosion of well equipments.

(c) rapid decline in hydrocarbon recovery and

(d) ultimately, premature abandonment of the well while others use chemical to

manage unwanted water production.

5

Figer 1

In many cases, innovative water-control technology can lead to significant cost

reduction and improved oil production. Water shut-off without seriously damaging

hydrocarbon productive zones by maximizing permeability reduction in water source

pathways, while minimizing permeability reduction in hydrocarbon zones is the target

for oil and gas operators. In mature fields, oil and gas wells suffer from high water

production during hydrocarbon recovery. High water production represents a serious

threat to the quality of the environment due to water disposal, and is a growing

concern in the petroleum industry. Today, a full range of solutions is available for

virtually any type of produced water challenge. A variety of techniques and tools is

available to appropriately analyze well bore and reservoir characteristics. Most

importantly, diagnosing the problem so as to determine which treatment will provide

the best overall technical and economical solution. The current study presents a

chemical-based water control technique in oil and gas wells and the methodology for

identification and resolving the source of water production problem. It also presents

some water control applications in the world and especially in Saudi Arabia and Arab-

gulf area are mentioned to know the type of the problems and their solutions.11, 13,

16.

2.3 classifications of water shut off

Water shut-off is defined as any operation that hinders water to reach and enter

production wells. There exist countless number of techniques such as polymer and

6

polymer/gel injection, different types of gel systems, organic/metallic cross linkers,

and a combined between them, mechanical solution, cement plug solution and other

hundreds of different mechanical and chemical methods for water shut-off.

2.3.1 Well configuration and well completions

The number of injection and production wells required to produce a field suggests the

approach of selecting the optimum pattern and spacing. Different well pattern models,

including line-drive, five, seven and nine spot, normal or inverted, could be developed

for different well spacing under different well and reservoir conditions.9 Designing

optimal well configuration, completions and replacements using new technologies

starting with drilling techniques until the reservoir simulation, has the capability to

increase oil recovery and reduce water production. The strategies of drilling and

completion options are numerous. Some of the basic concepts are:

(a) Drilling a vertical well with open or cased and perforated completion either

production or injection well.

(b) Drilling a horizontal and/or deviated well, or perhaps multilateral wells.

(c) Extending the use of an old well by re-perforating new productive zones.

2.3.2 Mechanical method

In many near wellbore problems, such as casing leaks, flow behind casing, rising

bottom water and watered out layers without crossflow, and in the case of bottom

water beginning to dominate the fluid production, the perforations are sealed-off with

a cement-squeeze, packer or plug. The well is re-perforated above the sealed zone,

and oil production is resumed. This process is continued untill the entire pay zone has

been watered out. This method is one of the easiest ways to control water coning.4, 9.

2.3.3 Mechanical and cement treatment

Using squeeze cement alone is not sufficient. This is attributed to the fact that the

size of the standard cement particles restricts the penetration of the cement into

channels, fractures and high permeable zones, only about 30% success is reported.

The easiest method to control water coning when bottom water begins to dominate the

fluid production is to seal off the perforations with a cement-squeeze, packer or plug.

The well is then re-perforated above the sealed zone, and oil production is resumed.

This process is continued until the entire pay zone has been watered out. However,

7

these techniques require separated and easily identifiable oil and gas producing zones.

Where possible, mechanical zone isolation by cement squeezes or plugging type gels

can be the easiest way to shut off water coning from watered out layers. Very often

excessive water-cuts can be reduced by re-completing the well or by placing

mechanical devices to isolate the water producing zones. These solutions however,

are expensive and can cause in micro-layered formations, the loss of volumes of

hydrocarbons. 4, 7

2.3.4 Chemical methods

Mechanical packers can provide sealing in the well hard ware and in large near

wellbore openings [6]. However, sealing materials can penetrate into the matrix or

small fissures where the mechanical packers cannot reach to shut off the excess water

in some cases. Therefore, chemical methods are required in many situations. Listed

below are the plugging agents that have been used for water shutoff in horizontal

wells.

Nonselective and selective water shutoff agents are currently two kinds of commonly

used chemical plugging agents:

2.3.4.1 Nonselective water shut off agent

Nonselective water shutoff technology is used to seal single or high aquifer. The

plugging agent has no selectivity to oil and water, so it can be blocked. Before the

profile, make sure the water layer section, plugging agent injection water layer, use

the appropriate method to separate oil and water layer, injected water plugging agent

formation blockage can be achieved. Main plugging agents are cement, calcium

silicate gel, resin, gel, etc [4].

2.3.4.1.1 Weak gel plugging agent

The weak gel is a kind of polymer which is close to the polymer flooding, formed by

adding a small amount of delayed crosslinking agent [5]. Usually use the

concentration of 800 ~ 3000 mg/L of high molecular weight polyacrylamide to

advocate agent for crosslinking. There are many different kinds of crosslinking

agents, like resin, dialdehyde, polyvalent metal ion, etc. Moreover acetic acid

chromium, aluminium citrate and glyoxal are commonly used abroad [6], while

phenolic composite of resin, poly lactic acid, acetic acid, chromium, chromium etc.

are commonly used in Chinese oilfields.

8

2.3.4.1.2 Oily sludge plugging agent

Oily sludge is a kind of industrial waste due to its complex chemical properties. It is

one of the main by-products of crude oil production. The main ingredients are water,

mud, colloid, asphalt, wax etc. In general, the oil sludge is a stable suspension

emulsion, which is formed by the stabilization of the system, but it is difficult to

realize multiphase separation. As a particle plugging agent, it has characteristics of

high yield, high oil, viscosity, fine grain, hard to dehydration, etc. Compared with

other chemical agents, it has better resistance to salt and high temperature and shear

resistance. It has obvious advantages in high dose injection, low cost and good effect.

Furthermore, it can also solve the problem of oily sludge treatment and emission,

reduce the environmental pollution and the oil sludge solidification cost, and deal

with the harmful components in time.

West GuDong in Shengli oilfield in 1992 used the HPAM/chromium acetate system

to test three well group, which was the earliest application of this technology in our

country. A total of 155 thousand cubic meters of profile control agent, the use of 3000

mg/LHPAM and 500 mg/L chromium acetate system, water injection wells after the

injection pressure profile increased by about 3 MPa on average, the cumulative

increase of oil 9800 t [7]. Liaohe Oilfield used weak gel deep profile control and the

effect was the best overall, the temperature is about 55℃, reservoir depth is 1550 ~

1700 m, 2200 mg/L mineralization, average porosity is 20%, the permeability is 1.13

D, which has significantly improved the efficiency of water flooding, valid for 3 years

[8].

2.3.4.1.3 Cement plugging agent

As one of the early use of plugging agents, cement plugging agent is of low prices,

big intensity, easy to adapt to the temperature environment, etc. After the

solidification of cement impervious to the use of this mechanism to plug the hole, for

example, the lower water, channeling water, or squeeze into the water blocking, Due

to the large size of cement particles, it is difficult to enter the middle and low

permeability formation, so the plugging strength and success rate are low and the

validity period is short, so the application scope is limited [9], In recent years,

superfine cement and cement additive agent have been developed successfully and

have broad prospects for cement plugging.

9

2.3.4.1.4 Resin plugging agent

The resin plugging agent is a polymer material produced by condensation of low

molecular substances, with the body structure is difficult to soluble fusion. After

heated by the change of nature, it can be divided into thermosetting resin and

thermoplastic. Thermosetting resins such as phenolic resin, epoxy resin, sugar alcohol

resin and so on are often used as non-selective plugging agents. Phenolic resins are

commonly used in oil fields [10]. Will preshrinking liquid mixed with thermosetting

phenolic resin curing agent into the water, suitable for formation temperature and

curing agent, the crosslinking, within a certain time to form difficult to soluble

phenolic resin melt, can block the formation of the layer. The advantages of Resin

Plugging Agent: high strength, many kinds of pore. The cured resin is neutral, and the

chemical stability is not easy to react with the underground liquid. However, before

the curing of resin is sensitive to pollution, such as water, watch live agent, acid and

alkali, must pay attention to detect horizon and isolation before use.

2.3.4.2 Selective water shut off agent

Selective plugging agent is used to separate water and profile control by using the

difference between oil and water, oil layer and water layer. With the rapid

development, there are many methods of water shut off, such as water shut off agent,

oil based plugging agent and alcohol based plugging agent type of different dispersion

medium, water, oil and alcohol solvent, respectively.

2.3.4.2.1 Oil-based plugging agent

Oil-based plugging agent is mainly composed of thickener BCI, amphoteric polymer,

diesel and other components [11]. High pressure plugging agent is injected into the oil

well stratum, polymer by oil and oil flow channel of high water content and low

degree of crosslinking and hydrolysis characteristics is difficult, and can avoid the

emergence of gel which did not affect the flow of oil, at the same time, it can be

mined with the flow of oil, into the water channel into the stratum.

2.3.4.2.2 Water plugging agent

Water plugging agent due to the variety and the lowest cost is now widely used in

China's oil production. One of the most commonly used water-soluble polymers [12].

Its aqueous solution will be priority into containing high water-bearing formation,

11

through the adsorption effect of hydrogen bonding in water layer at the grass-roots

level surface to make further reserves, based on polypropylene acyl ammonia as the

main raw material of the application principle of plugging agent.

2.3.4.2.3 Alcohol-based plugging agent

Alcohol-based plugging agent with resin dimer, alcohol based compound plugging

agent, etc., not often used in practical production. It is commonly used to explore the

possibility of selective plugging of reservoir water under the conditions of high

temperature. Alcohol-based plugging agent is mainly composed of water-soluble

polymer and sodium silicate aqueous ethanol solution[13].

2.4 GEL TREATMENT FOR CONFORMANCE CONTROL

2.4.1 WATER PROBLEM

An average of 210 million barrels of water accompanies 75 million barrels of oil

produced daily. This ratio is even higher in the US, as shown in Figure 3.1. Water

problem is worse in the North Sea oil field, where 222 million tons of water are

produced with 4 thousand tons of oil. The economic lives of many wells are shortened

because of the excessive production cost associated with water production. These

expenses include lifting, handling, separation, and disposal. The unwanted water uses

up the natural drive and lead to possible abandonment of the production well.

Excessive water increases the risk of formation damage, produces a higher corrosion

rate, and increases emulsion tendencies. It may also form a hydrate because the water

and gas are not produced in a proper ratio. The excessive water produced in water

drive production wells is typically a result of a coning zone within the rock or from

vertical fractures which extend into bottom water drive.

11

Worldwide water oil ratio distribution

One barrel of water has the same production cost as one barrel of oil. The annual cost

required to dispose of the excess water is estimated to be 40 billion dollars worldwide;

it is between 5 and 10 billion dollars in the US (Bailey, 2000). Reducing the amount

of water produced would help in decreasing not only the chemical treatments but also

the separation cost associated with the production process. It would also decrease the

costs of artificial lift requirements. Water shut-off treatments can be applied to both

carbonate and sandstone formations as well as fractured and matrix permeability

reservoirs .

Well productivity and potential reserves have been increased by the water control

method. the water oil ratio increases as the production increases within a mature oil

well. The water control method needs to be applied when the water-to-oil ratio

reaches an economical limit with high excessive water handling costs. The WOR will

drop below the economic limit and continue producing oil after the production rate is

reduced. Thus, the water control method extends an oil well’s life.

12

Water control method for increasing well productivity (Bailey et al., Water Control)

Sweep water is good water produced by either injection wells or active aquifers that

sweep the oil from the reservoir. Effective water pushes oil through the formation and

toward the wellbore. It cannot be shut-off without shutting off the oil. Bad water

produces an insufficient amount of oil, increasing the WOR until it is over the

acceptable limit.

13

Good and bad water (Bailey et al., Water Control)

2.4.2 WATER CONTROL PROBLEMS

Water control problems can be classified into one of two major categories: near well

bore problems and reservoir related problems .

2.4.2.1 Near Wellbore Problem

Six near well bore problems have been listed below :

2.4.2.1.1 Casing leaks problem

The water that flows to the wellbore through the casing fissure arrives from either

above or below the production zone. Casing leaking create an unexpected increase in

the water producing rate. These leaks can be classified into one of two types: casing

leaks with flow restrictions and casing leaks without flow restrictions. Gel treatments

offer an effective solution to casing leaks with flow restrictions. The leaks examined

in this study moved through a

small aperture breach. The pipe fissure was less than approximately 1/8-inch; the flow

conduit was less than approximately 1/16-inch. In contrast, Portland cement is a better

treating method for casing leaks without flow restrictions. These leaks are created by

a large aperture breach in the pipe and a large flow conduit.

14

Casing leaks (Bailey et al., Water Control)

2.4.2.1.2 Flow behind the pipe

Two situations contribute to flow behind the pipe:

flow behind the pipe without flow restrictions and flow behind the pipe with flow

restrictions. Cement is an effective method for flow behind the pipe without flow

restrictions. A lack of primary cement behind a casing creates a large aperture,

thereby producing a large flow channel. The flow conduit is approximately greater

than 1/16 inch. Flow behind the pipe with flow restrictions is caused by cement

shrinkage during the well’s completion. A flow conduit less than 1/16-inch is formed

along with small apertures.

Flow behind the pipe (Bailey et al., Water Control)

2.4.2.1.3 Barrier breakdowns

A new fracture can be formed near the wellbore by either fracture breaking through

the impermeable layer or utilizing acids to dissolve the channels. The pressure

difference across the impermeable layer will drive the fluid migration throughout the

wellbore. This type of conformance problem can be related to the stimulation process

sometimes.

15

2.4.2.1.4 Channels behind the casing

Bad connections between not only the formation and the cement but also the cement

and the casing can create water channels behind the casing. A bad cement job, cyclic

stresses, and post-stimulation treatments contribute to these issues. Another cause of

this issue is the space behind the casing created by the sand production. Either a high

strength squeeze cement in the annulus or a lower strength gel-based fluid placed in

the formation can be used to stop the water channel.

2.4.2.1.5 Inappropriate completion

Inappropriate completion can immediately create unwanted water production. This

issue can also cause both coning and cresting near the wellbore. A sufficient

geological survey is quite important before the completion of the project.

2.4.2.1.6 Scale, debris and bacterial deposits

Scale, debris, and bacterial deposits can obstruct and alter the non-hydrocarbon flow

to undesired zone.

2.4.2.2 Reservoir Related Problems

Six reservoir related problems have been listed below :

2.4.2.2.1 Coning and cresting

Coning is a production problem that occurs either when bottom water or a gas cap gas

infiltrate the perforation zone near a wellbore. This behavior reduces oil production.

The interface shape for coning is different between a vertical well and a horizontal

well.

The coning interface shape in a horizontal well is similar to a crest. The horizontal

well will produce a smaller amount of undesired secondary fluids under comparable

coning conditions. The hydrocarbon flow rate will greatly decrease after the cone

breaks into the producing interval, which will also lead to a dramatic increase of water

and gas rate, the reservoir pressure will be depleted shortly after the gas cone breaks

through. This depletion may cause oil well shut-in.

16

Water coning in both vertical and horizontal wells (Chaperon, 1986)

production well both with and without coning (PetroWiki, 2013)

2.4.2.2.2 Watered-out layer with and without crossflow

Both the water crossflow and the pressure communication in a watered-out layer with

crossflow occur between high permeability layers without impermeable barrier

isolation .

Either an injection well or an active bottom water can serve as the water source. A gel

treatment should not be considered when radial crossflow occurs between adjacent

water and hydrocarbon strata. A gelant will crossflow into oil production zones, away

from the wellbore. Thus they do not effectively improve the conformance problem. A

conformance improvement technology (e.g. polymer flooding) should be used to

improve oil viscosity.

Watered-out layer without crossflow is a common problem. It is usually associated

with multilayer production in a high-permeability zone with impermeable barriers

isolation. This problem is easy to treat; either a rigid, shut-off fluid or a mechanical

17

method can be applied in either injection wells or producing well. Coiled tubing is

recommended as a placing method.

Watered-out layer (A) with and (B) without crossflow (Bailey et al., Water Control)

2.4.2.2.3 Channeling through a high permeability zone

A high permeability zone will lead to early breakthrough. The displacing fluid will

bypass lower permeability zones and flow through high permeability zones. This

phenomenon leads to low sweep efficiency and a high WOR. It is most common in

reservoirs with either an active water drive or a water-flooding-treated reservoir .

2.4.2.2.4 Fingering

Viscous fingering can cause poor sweep efficiency during the oil recovery flooding

process. Viscosity will form when the oil has a higher viscosity than the displacing

fluid has.

2.4.2.2.5 Out of zone fractures

Fracturing is one of the main causes for reservoir heterogeneity. Both hydraulic

fractures and natural fractures can cause water production problems. These problems

can be treated by gel placement. The following three challenges, however, must be

addressed:

The gel injection volume is difficult to determine .

Treatment may shut-off the oil producing zone. Thus, a post-flush treatment

needs to be applied to maintain productivity near the wellbore .

The flowing gel must be tolerated to resist flow-back after gel placement.

18

Fractures or faults from a water layer surrounding a (A) vertical well or a (B) horizontal

well (Bailey et al., Water Control)

2.4.2.2.6 Fracture between the injection and producing well

Injection water is easy to breakthrough. It can cause excessive water problem in

production wells with naturally fractured formation between injection wells and

producing wells, Gel treatments offer the best solution because they have limited

penetration to matrix rock. Bullhead injection through injection well can be applied

with the gel treatment.

Fractures or faults between an injector and a producer (Bailey et al., Water Control)

2.4.3Excessive Water Production Problems and Treatment

Categories:

Table 3.2 shows the screening criteria for conformance problem for excess water, the

table was listed in increasing order of treatment difficulty. Seright, Sydansk and Lane

proposed a forthright solution for each catalog. Conformance problem need to be

clearly identified before effective treatment selection. Conformance problems listed in

19

Category A are the easiest problem to solve, conventional techniques such as cement,

bridge plugs and mechanical tubing patches are effective choices. Gel treatments are

the most effective method for conformance problems in category B, Preformed gel are

the best choice for category C. For complex conformance problem in category D,

successful rate for gel treatment application is extremely low.

Table 3.1. Conformance problem for excessive water and treatment categories

(Seright, 2001)

Category A: ―Conventional treatment‖ effective case

1. Casing leaks without flow restrictions

2. Flow behind pipe without flow restrictions

3. Unfractured wells with effective barriers to crossflow

Table 3.1. Conformance problem for excessive water and treatment categories (Seright, 2001)

Category B: Gelants treatment effective case

4. Casing leak with flow restrictions

5. Flow behind pipe with flow restrictions

6. Two dimensional coning through a hydraulic fracture from an aquifer

7. Natural fracture system leading to an aquifer

Category C: Preformed gels effective case

8. Faults or fractures crossing a deviated or horizontal well

9. Single fracture causing channeling between wells

10. Natural fracture system allowing channeling between wells

Category D: Difficult problem where gel treatment should not use

11. Three dimensional coning

12. Cusping

13. Channeling through strata with crossflow without fractures

21

2.4.4 Gel treatment for improved production Well performance

Typically, gel treatments are one of the most aggressive types of conformance control

or profile modification. Gel technology is more aggressive since it can totally block

certain porous features associated with the porous media and thus, in a very drastic

manner, divert fluid flow from areas of low drag to areas of much greater drag (high

permeability to lower permeability). There are many examples of where this can

occur and how this is achieved. Some of the situations where this occurs will next be

discussed. Following this discussion, some of the parameters which should be

considered in gel treatment applications for production well performance are

Fracturs

Fractured reservoirs can exhibit high productivity coupled with serious technica1

challenges. The major challenge is due to the fact that the permeability through the

fractures is orders of magnitude larger than the permeability through the matrix. Once

the hydrocarbons have been recovered from the fracture then the remaining target for

recovery is in the tighter matrix. Preferentially, this is not where the injection fluids

want to flow and therefore some means of modifying their natural proclivity to flow

through the fractures must be implemented. If successful. the overall recovery can be

significantly higher than that expected from a fractured reservoir.

High Permeability Streaks

In contrast to fractures which may have very localized separation of the porous

media. high permeability streaks are better represented by a natural flow unit or layer

which has a much lower resistance to fluid flow than oilier layers. Examples abound

in the literature where this bas occurred. The Pembina reservoir in Alberta. Canada is

a prime example where the upper layer permeability is in the range of 200 md and

contains approximately 10% of the total oil in place. The lower flow unit, although

having permeability approximately 10 to 50 times lower than the upper flow unit,

contained the bulk of the oil. In such a case, fluid flowed preferentially through the

upper zone and very little of it was diverted into the lower zone. With properly

designed gel strategies, the target from a reservoir such as this is much greater than

21

Bottom Water and Coning

A Common problem for both gas and oil reservoirs is coning. In one example recently

addressed by the authors, a prolific gas well, having potential to produce 100 BSCF

was shut in after only hours of production due to bottom water coning. The rate was

subsequently reduced to a level which mitigated the coning problem but which

reduced revenues by 60%. In such a case, if the bottom water could be controlled, the

Worm Holes

In heavier oil reservoirs with unconsolidated porous media, any pressure surge from

the injector can result in a parting of the formal). In such cases, there are literally

holes which develop in the rock through which fluid flow is very easy. Unless these

holes are blocked and flow is diverted away from these holes, conformance can be

very A number of examples exist in the literature where this has occurred but one of

the most obvious was proven on the basis of a dye &acer test performed on a heavy

oil reservoir in Elk Point, Alberta. In this case, a dye was injected into the injector and

within 30 minutes the tracer was being observed in the offset producers. Based on the

volume of dye injected and the time and distance traveled, the path of least resistance

present in this reservoir was adequately described as a large pipe connecting the

injector to the producer. Unless controlled, this problem can result in abandonment of

RPM

The absence of profile modification, water injected into the reservoir will go into the

high-permeability zones and will bypass the oil-saturated, low-permeability zones.

reservoir simulation of a relative permeability modifier (RPM) used for profile

modification improvement in injection wells. By injecting the RPM within the high

permeability zones, subsequent injected water will be diverted into low-permeability

zones to improve the sweep efficiency of the waterflooding project .

RPM is a water-soluble relative permeability modifier initially developed for water

control in production wells. The polymer functions by adsorption onto rock surfaces

and effectively reduces water flow with little or no damage to hydrocarbon flow.

These treatments are extremely easy to mix and pump, and require no post-job shut-in

time. RPM was evaluated in 5- and 10-ft sand packs to investigate parameters, such as

22

depth of penetration, diversion properties, treatment injection rate, and polymer

concentration. Laboratory results indicate RPM can effectively penetrate through a

10ft sand pack, providing permeability reduction to water throughout the length of the

porous media. In addition, excellent diverting properties were observed while

bulkheading the treatment in sand packs in parallel with significant permeability

contrast .In addition, a 3-D numerical simulator was used to evaluate the performance

of the RPM system under different scenarios and varying parameters, such as (1 )

permeability contrast between injection zones, (2) presence/absence of shale barriers

between injection zones, and (3) treatment volumes, among others.

2.4.5 GEL CONFORMANCE IMPROVEMENT TREATMENT

Gel treatment, acting as a plugging agent for near wellbore treatment, success rate to

water shut off is around 75% (Portwood, 1999). When gel treatment has been injected

into formation, it can divert fluid flow from water channels to formation matrix. Fluid

prefer to flow from high permeability and low oil saturation zone, it will normally

bypass low permeability zones with high oil saturation. Gel treatment can change this

behavior, and to enhance oil production and improve flood sweep efficiency. Gel

treatment can reduce production operation cost by lower water production rate. In the

oil field, gel treatment can be applied to conformance related problems such as water

or gas shutoff treatment, sweep improvement treatment, squeeze and recompletion

treatments or aged wells abandonment treatment.

2.4.6 GEL TYPE

An appropriate gel selection is important to water shutoff treatment; it will affect

treatment result directly. Gel with greater strengths can be applied in reservoir with

large fractures, weaker gel will be used in reservoir with less extensively fracture or

matrix with lower productivity.

2.4.6.1 Polymer Gels

Polymer gel treatment is the most common and effective gel treatment application in

reservoir. Polymer gel can flow through fractures and also strong enough to withstand

high pressure difference near wellbore. It can be placed in high permeable with high

water saturation, to reduce water permeability and block the water channels.

Crosslinked polymer gel can be applied to production wells with excessive water or

gas flow; it can also apply to injection wells with poor injection profiles (Miller.J.M

23

& Chan.K.S 1997). Polymer goes through crosslinking fist and then forms a solid gel

with time and temperature. There have two type of crosslinker to polymer: organic

crosslinker and metal ions crosslinker, the most common use for metal ions

crosslinker is chrome-based crosslinker.

Metal ions crosslinkers are contain Al3+, Cr3+ and Cr6+. Crosslinker with Al3+ is

hard to control or delay the crosslinking time. Chromium (III)-

Carboxylate/Acrylamide- Polymer Gels is also known as CC/AP gels. CC/AP gel can

be both used as water shutoff treatment and sweep improvement treatment. CC/AP is

acrylamide-polymer crosslinked with chromium (III) carboxylate complex. CC/AP

gel can be applied in a broad pH range, and also has a wide range of gel strengths.

CC/AP gel has wide range of controllable gelation-onset delay time, but sensitive to

high temperature reservoir (Sydansk.R.D,Reservoir Conformance Improvement). The

upper limit for CC/AP gel is around 300 oF (Sydansk &Southwell 2000).

The disadvantage for chrome-based crosslinkers are less remaining time during

injection and sometimes tend to set up earlier than desired, particularly at

temperatures above 175 oF ( Uddin.S & Dolan.D.J 2003). For high reservoir

temperature or oxidative degradation, Metal ions crosslinked polymers are less likely

to use (Burns et al. 2008).

Organic crosslinker polymer is an environmental friendly system. It took less job to

mix and pump to the field. Organic crosslinker system reacts more predictable to

change of reservoir temperature, component concentration, brine type, salinity and pH

values. Those characters make organic crosslinking polymer gel easier to control and

to understand during the treating process (Uddin.S & Dolan.D.J 2003). Compare to

chrome based polymer gel, organic crosslinkers lasts longer time than tradition

polymer gel with it deep sealing properties. From the laboratory test data result,

organic crosslinker can penetrate into the formation eight times as far as traditional

chrome-based polymer; it can completely seal off the formation (Uddin.S &

Dolan.D.J 2003).

A list of conformance problems has been tabulated, and the ones which can be solved

by the polymer gel method are indicated in Table 3.2.

24

Table 3.2. Conformance problems suitable for polymer gels (PetroWiki, 2013)

Matrix conformance problems

Without crossflow Yes

With crossflow Challenging—must place very deeply

Table 3.2. Conformance problems suitable for polymer gels (PetroWiki, 2013) (cont.)

Fracture conformance problems

Simple Depends—case-by-case basis

Network—intermediate intensity and

directional trends

Yes

Network—highly intense Often not

Hydraulic Yes

Coning

Water and gas via fractures Yes

Water and gas via matrix reservoir rock No

Behind pipe channeling Yes, for microflow channels

Casing leaks Yes, for microflow channels

2.4.6.2 Silicate Gels

Silicate gel used to be the most wildly applied inorganic conformance improvement

technique years ago. But because of the low injectivity in reservoir matrix rock and

reduced gel strength with increased gelation onset time, silicate gel is not been widely

applied recently (Sydank.R.D, Reservoir Conformance Control).

25

2.4.6.3 Relative Permeability Modifiers (RPM)

The purpose of RPM is to reduce water flow permeability while don’t have

meaningful changes to hydrocarbon flow. Unswept and low water saturation fracture

zone are the most favorable condition for RPM application. And also RPM can be

used to use to wells with water drive problem, low mobility ratio problem or layered

reservoir with distinct vertical permeability barriers (Jaripatke & Dalrymple, 2010).

2.4.6.4 Advantages Gel Treatment over Cement Treatment

Gelents can penetrate into porous rock while cement can only seal rock surface.

Cement can only seal near wellbore channels or plug normal permeability rock,

sufficient injection pressure is required for significant distance by fracturing or

parting the rock or sand. Cement may not sufficiently seal the channel if cement does

not adhere strong enough to the rock. And also, cement cannot penetrate into narrow

channels (Seright.R.S 2001). There have three advantage gels over cement listed

below; two of them are summarized by Seright.R.S:

1-Gel can formed an impermeable and deeper barrier inside porous media

2- Gel can flow into narrow channels behind pipe.

3- Gel can form a non-permanent plug and can be remove easily.

4- Gel treatment is cheaper than cement because of reduced crew and rig time.

2.4.7 GEL TREATMENT SIZING FOR PRODUCTION WELL

Gel treatment sizing design is an unsolved problem in oil and gas industry so far. A

lot of failure field cases demonstrated facts that wrong gel treatment sizing estimate is

one of the main failure water shut off treatment reason. Several strategies as follows

have been used to gel treatment sizing design in oil field, they are summarized from

300 producing well water shut off treatment. But comparing and considering all the

methods to make final decision is always better than just relying on a single method

(Potwood 1999):

2.4.7.1 Gel injection volume based on minimum volume

The effective way to estimate the capacity of the well is let the fluid producing for

more than 24 hours in a pumped off condition, the total volume for gel treatment is

the maximum daily rate. The maximum daily rate is also refers as minimum volume.

26

This strategy will be based on individual field, well specifics and the history data and

experience. This method gel better result in natural fractured reservoir. Normally no

less than minimum volume needs to be pumped, but for fractured well, 2 or 3 times

the minimum gel treatment volumes need to be pumped to fill more fractures near

wellbore.

2.4.7.2 Gel injection volume based on distance

It’s difficult to predict gel treatment’s penetration. One of the numerical methods of

sizing a gel treatment is used radial flow calculation. According to the experience, 50

to 60 food radius of rock originating from the wellbore will be used for calculation.

Another numerical method is using a minimum of 50 and up to maximum of 200

barrels of gel per perforated food. This method is productivity related, if the well has

high productivity, a factor close to 200 barrels of gel per perforated food will be used;

if the well has low productivity than close to 50 barrels of gel per perforated food will

be applied.

2.4.7.3 Gel injection volume based on well response

Treating pressure is a good indicator in injection process. During the injection

process, if the treating pressure starts low and increase gradually at the beginning, but

then increase rapidly after barrels of gel has been pumped. That shows gel already

plugged high permeability water producing zone and no more gel is required. but if no

rapidly increase for treating pressure during the injection process, injection volume

don’t need to readjusted and keep the injection pressure below previous established

maximum pressure.

2.4.7.4 Gel injection volume based on experience in a given field

Previous treatment field data is the most reliable source compare to methods above.

Operators need to keep on tracking of gas, oil, water fluid level after gel treatment. A

good before and after treatment formation profile records are good reference to

evaluate treatment success, help the interpretation of result. Future treatment

modification and improvement will relay on those experience (Portwood 1999).

2.4.8 PLACEMENT TECHNOLOGIES

Proper placement technique is one of the major determination to treatment

successfully control unwanted water. A proper placement technique will plug the

27

excessive water or gas zone with minimum invasion of gel into oil producing

intervals. The selection of placement technique is based on reservoir properties and

previous field experience. Weather fluid flow around the wellbore is radial or linear is

a critical consideration for gel placement technique. Linear flow normally occurs in

flowing situation: flow behind pipe, fractures and fracture-like features. Radial flow

occurs in matrix reservoir rock without fracture. In radial flow condition, oil

producing zone need to be protected during gel injection, mechanical packer need to

be considered (Seright.R.S 2001). But for linear flow, it’s easier to achieve with

simple placement method such as bullhead injection. Four main types of placement

methods are listed as below: bullhead method, mechanical packer placement method,

dual injection method, isoflow placement method.

2.4.8.1 Bullhead Placement Technique

Bullhead placement is the simplest and most economical method compare to other

three placement method. If operations need to be processed during day hours,

bullhead placement takes shorter time than other methods. Treatment has been

injected through casing without isolating the targeted zone. During the placement

process, injection profiles need to be analyzed, multi rate analyses need to be

performed to determine the entry zone which associated with different injection

pressure/rate. There have three main reservoir situations are favorable for bullhead

placement. First, it can be applied for wells with high permeability and saturation

contrasts. Second, it can also apply to reservoir with a large pressure drop to

breakdown gel damage in oil zones. Third, it could be used when wells will apply

reperforating to oil zone after gel treatment (Miller.J.M & Chan.K.S 1997). The

disadvantage for bullhead placement is treatment fluid may dilute in large size of

casings, and also wellbore fluid can be polluted at the interface (Uddin.S & Dolan.J

2003). Compare to bullhead placement, coiled tubing can place the treatment to

desired area accurately, less pollution and easier to control the process, but it takes

longer time and is more expensive (Uddin et al., 2003). For channel flow behind

casing, coiled tubing is an efficient placement method.

28

Figure 3.11. Bullhead placement technique (Jaripatke & Dalrymple, 2010)

2.4.8.2 Mechanical Isolation

Mechanical isolation is placement technique by using mechanical packers, selective

zone packers or bridge plugs to isolate perforations or open hole area to prevent

treatment fluid from sealing adjacent oil layers. Depending on the circumstances, the

tool could be used as a control for injection or production when left it in the well.

During the placement process, infectivity and communication aspects have to been

fully tested before the determination of the packer’s degree of placement control on

the zone. When treating a vertical conformance problem of a radial flow well,

mechanical isolation need to be used to assure that the gelant is injected exactly into

the high permeability zone or low oil saturation area for near well bore gel treatment

process (Seright, R.S., 2001). Mechanical isolation is an effective placement method

for non- communicating layers when high permeability zone is isolated and low

permeability zone is protected (Miller.J.M & Chan.K.S 1997).Compare to bullhead

placement, mechanical isolation have higher successful rate. According to annual

report from Alaska Prudhoe Bay, 60% success at shutting off excessive gas well by

using mechanical isolation to place gelants into formation (Sanders,G.S, 1994). Other

than that, 84% of the successful treatment at modifying injection profiles with

mechanical isolation was applied (Roberson, J.O., 1967). Mechanical isolation

method will lead to a good placement result when oil well has a good casing and

cement; and don’t have near wellbore fissures problem; also one or two excessive

29

water or gas production zone have been identified. But when oil wells have channels

behind pipe, this method is not always effective (Miller & Chan, 1997).

Figure 3.12. Mechanical packer placement technique (Jaripatke & Dalrymple, 2010)

2.4.8.3 Dual Injection

Dual injection is a placement method when gel treatment has been placed through

tubing while protection fluid has been injected through the annulus into the protected

oil zone. Before dual injection placement, injection profile and multirate analyses

need to be completed (Jaripatke & Dalrymple 2010). During the dual injection

process, packers, bridge plugs, sand plugs, chemical plugs, chemical packers, and

other mechanical tools are normally used. Fluid to oil zone needs to be compatible

with formation. Dual injection method can be applied to any of the flowing

conditions: (Miller.J.M & Chan.K.S 1997)

a)-Oil well without horizontal barriers with high vertically permeability or nearby oil

zones are thin.

b)-Open hole or gravel pack.

c)-Communication behind the pipe.

Dual injection method is not a common placement method compare to bullhead

method and mechanical isolation. The success rate for this method is relatively low

31

because of improperly sized treatment or inappropriate injection method (Miller &

Chan, 1997).

Figure 3.13. Dual-injection placement technique (Jaripatke & Dalrymple, 2010)

2.4.8.4 Isoflow Placement

Isoflow placement is an effective technique for crossflow wells. During the isoflow

placement, the treatment has been injected into the desire zone while non-sealing fluid

has been injected to protect oil zone. Non-sealing fluid contains a radioactive tracer in

the annulus; a detection tool is set in tubing to help to control the annulus pump rates

(Jaripatke & Dalrymple 2010). The detected tool can help to locate the interface

between the annulus fluid and the sealant which is being pupped down the tubing, and

the interface can be adjusted by changing the two fluid’s pumping rates. Isoflow

placement can get better treating result in open-hole completion when it’s hard to

achieve reliable zone separation (Cole & Mody, 1981)

Figure 3.14. Isoflow injection placement technique (Jaripatke & Dalrymple, 2010)

31

2.4.8.4 Overview of Three Gelant Placement Methods

Table 3.3 (by Miller and Chan, 1997) lists the advantages and disadvantages among

bullhead placement, mechanical isolation placement and dual-injection placement.

Table 3.3. Overview of gelant placement method (Miller & Chan, 1997)

Placement

Technique

Advantage Disadvantages

Bullhead Most economical method

Operational simple

Better result in Fractured

formations

Damage low pressure, low

permeability zones

Hard control over fluid

placement

Mechanical Isolation Can be used for low KH/KL when

FK is less than 0.01

Can applied when KH/KL is larger

than 100 for any FK

Effective for non-communicating

layers

Easy to control wellbore fluid

Good casing and cement are

in demand

Hard to apply in open holes

More completed workover

procedure

Dual- injection Effective for open hole

Provide wellbore control of fluids

for poor wellbore mechanical

integrity or complex completions

Hard to control treatment

flow in deep formation zone

and or fractures.

Difficult to operate

Only one HPZ at a time

32

CHAPTER 3

3.METHADOLOGY

The water coning is difficult to be permanently avoided but can be delayed. The

success of the water shutoff should be judged by the incremental oil production due to

the increase in the oil production before the water coning again returns. Water shut-

off is defined as any operation that delays water to reach and enter the production

wells. Water production is one of the major technical, environmental, and economic

problems associated with oil and gas production. Water production not only limits the

productive life of the oil and gas wells but also causes several problems including

corrosion of tubular, fines migration, and hydrostatic loading. The current project

presents a chemical-based water control technique in oil wells and the methodology

for identification and resolving the source of water production problem.

3.1 Descriptive Approach To Research

Water shut-off is defined as any operation that hinders water to reach and enter

production wells. There exist countless number of techniques such as polymer and

polymer/gel injection, different types of gel systems, organic/metallic cross linkers,

and a combined between them, mechanical solution, cement plug solution and other

hundreds of different mechanical and chemical methods for water shut-off.

Well configuration and well completions The strategies of drilling and completion

options are numerous. Some of the basic concepts are: (a) Drilling a vertical well with

open or cased and perforated completion either production or injection well. (b)

Drilling a horizontal and/or deviated well, or perhaps multilateral wells. (c) Extending

the use of an old well by re-perforating new productive zones.

Mechanical method In many near wellbore problems, such as casing leaks, flow

behind casing, rising bottom water and watered out layers without crossflow, and in

the case of bottom water beginning to dominate the fluid production, the perforations

are sealed-off with a cement-squeeze, packer or plug. The well is re-perforated above

the sealed zone, and oil production is resumed. This process is continued untill the

33

entire pay zone has been watered out. This method is one of the easiest ways to

control water coning.4, 9.

Mechanical and cement treatment Using squeeze cement alone is not sufficient. This

is attributed to the fact that the size of the standard cement particles restricts the

penetration of the cement into channels, fractures and high permeable zones, only

about 30% success is reported. The easiest method to control water coning when

bottom water begins to dominate the fluid production is to seal off the perforations

with a cement-squeeze, packer or plug. The well is then re-perforated above the

sealed zone, and oil production is resumed. This process is continued until the entire

pay zone has been watered out. However, these techniques require separated and

easily identifiable oil and gas producing zones. Where possible, mechanical zone

isolation by cement squeezes or plugging type gels can be the easiest way to shut off

water coning from watered out layers. Very often excessive water-cuts can be reduced

by re-completing the well or by placing mechanical devices to isolate the water

producing zones. These solutions however, are expensive and can cause in micro-

layered formations, the loss of volumes of hydrocarbons. 4, 7

Chemical methods Mechanical packers can provide sealing in the well hard ware and

in large near wellbore openings [6]. However, sealing materials can penetrate into the

matrix or small fissures where the mechanical packers cannot reach to shut off the

excess water in some cases. Therefore, chemical methods are required in many

situations. Listed below are the plugging agents that have been used for water shutoff

in horizontal wells. Nonselective and selective water shutoff agents are currently two

kinds of commonly used chemical plugging agents:

Nonselective water shut off agent Nonselective water shutoff technology is used to

seal single or high aquifer. The plugging agent has no selectivity to oil and water, so it

can be blocked. Before the profile, make sure the water layer section, plugging agent

injection water layer, use the appropriate method to separate oil and water layer,

injected water plugging agent formation blockage can be achieved. Main plugging

agents are cement, calcium silicate gel, resin, gel, etc [4].

Selective water shut off agent Selective plugging agent is used to separate water and

profile control by using the difference between oil and water, oil layer and water

layer. With the rapid development, there are many methods of water shut off, such as

34

water shut off agent, oil based plugging agent and alcohol based plugging agent type

of different dispersion medium, water, oil and alcohol solvent, respectively.

RST log

The reservoir saturation tool combines the logging capabilities of traditional methods

for evaluating saturation in tool slim enough to pass through tubing. Now saturation

measurements can be made without killing the well to pull tubing and regardless of

the wells salinity.

• Monitor water saturation through tubing

• Locate by-passed oil

• Detect water flood fronts

• Fine-tune formation evaluation through casing

• Evaluate wells lacking open hole logs

• Monitor production profiles

• Monitor water saturation

Production in old wells is affected by natural depletion and, when reservoirs are under

waterflooding, by the progression of the front of injected water.

A major concerning these wells is the increased water cut that may quickly become

uncontrollable.

Reservoir evaluation and saturation monitoring through casing are generally

performed in two ways. One measures the decay of thermal neutron populations (TDT

Thermal Decay Time principle), and the other determines the relative amounts of

35

carbon and oxygen in the formation by inelastic gamma ray spectrometry, as used in

the GST Induced Gamma Ray Spectrometry Tool. Because chlorine has a large

neutron capture cross section, the TDT technique provides good results in areas with

highly saline formation waters. When the formation water is not sufficiently saline or

when its salinity is unknown, the carbon-oxygen method usually provides a more

reliable answer, and the TDT data may not be interpretable. A combination of the two

methods may sometimes provide the best results and yield additional information

Coiled Tubing (CTU)

A cost- and time-effective solution for well intervention operations employs coiled

tubing. Instead of removing the tubing from the well, which is how workover rigs fix

the problem, coiled tubing is inserted into the tubing against the pressure of the well

and during production.

The coiled tubing is a continuous length of steel or composite tubing that is flexible

enough to be wound on a large reel for transportation. The coiled tubing unit is

composed of a reel with the coiled tubing, an injector, control console, power supply

and well-control stack. The coiled tubing is injected into the existing production

string, unwound from the reel and inserted into the well.

Coiled tubing is chosen over conventional straight tubing because conventional tubing

has to be screwed together. Additionally, coiled tubing does not require a workover

rig. Because coiled tubing is inserted into the well while production is ongoing, it is

also a cost-effective choice and can be used on high-pressure wells.

Coiled Tubing Operations

36

All performed on a live well, there are a number of well intervention operations that

can be achieved via coiled tubing. These include cleanout and perforating the

wellbore, as well as retrieving and replacing damaged equipment.

Additionally, some advances in coiled tubing allow for real-time downhole

measurements that can be used in logging operations and wellbore treatments.

Enhanced Oil Recovery (EOR) processes, such as hydraulic and acid fracturing, can

also be performed using coiled tubing. Furthermore, sand control and cementing

operations can be performed via coiled tubing.

Perforation

perforation in the context of oil well refers to a hole punched in the casing or liner of

an oil well to connect it to the reservoir.

The objective of perforating a well is to provide effective flow communication

between well bore and reservoir. Perforating involves shooting a hole through casing

and cement and providing a perforation into the formation.

Casing Gun:

The perforations are made after drilling, casing and cementing of the pay zone with

the drilling rig on location. Pressure overbalance is maintained in the wellbore so the

well will not flow immediately after perforating. Usually a large gun is run on an

electrical cable. In order to perform the perforation technique successfully, the well

must be kept under the control of the completion fluids during the perforation and

tubing installation

37

HCL acid

Stimulation is performed on a well to increase or restore production. Sometimes, a

well initially exhibits low permeability, and stimulation is employed to commence

production from the reservoir. Other times, stimulation is used to further encourage

permeability and flow from an already existing well that has become under-

productive.

A type of stimulation treatment, acidizing is performed below the reservoir fracture

pressure in an effort to restore the natural permeability of the reservoir rock. Well

acidizing is achieved by pumping acid into the well to dissolve limestone, dolomite

and calcite cement between the sediment grains of the reservoir rocks. There are two

types of acid treatment: matrix acidizing and fracture acidizing.

There are different acids used to perform an acid job on wells. A common type of acid

employed on wells to stimulate production is hydrochloric acids (HCI), which are

useful in removing carbonate reservoirs, or limestones and dolomites, from the rock.

Also, HCI can be combined with a mud acid, or hydrofluoric acid (HF), and used to

dissolve quartz, sand and clay from the reservoir rocks.

In order to protect the integrity of the already completed well, inhibitor additives are

introduced to the well to prohibit the acid from breaking down the steel casing in the

well. Also, a sequestering agent can be added to block the formation of gels or

precipitate of iron, which can clog the reservoir pores during an acid job.

After an acid job is performed, the used acid and sediments removed from the

reservoir are washed out of the well in a process called backflush.

38

CHAPTER 4

4.RESULTS AND DISCUSSION

4.1 Zelten Field: Water Shut off

خريطة

In water shutoff technology, a distinction is made in the water encroachment in oil

wells in terms of "good water" and "bad water". The "good water" is the unavoidable

bottom water influx which helps to displace the oil. On the other hand, the "bad

water" is possibly avoidable water which is produced by the phenomenon of the water

coning or "water fingering" in the high permeability layer(s). It is the "bad water"

caused by the water coning which is sought after to be shut off or more precisely

"delayed".

39

The water coning is difficult to be permanently avoided but can be delayed. The

success of the water shutoff should be judged by the incremental oil production due to

the increase in the oil production before the water coning again returns.

The conventional water shutoff method applied in Zelten field has been the wellbore

isolation by cement plug in the watered out zone(s). However, in December 2005, a

pancake type water shutoff treatment was proposed and conducted by the team leader

of this report. The pancake type treatment involves pumping a polymer (OrganoSeal

of Schlumbeger) at some distance in the shape of a pancake from the wellbore into the

watered out zone. The polymer only sets in the watered out zone and acts as a barrier

for a certain time to prevent the water coning. The water cone eventually circumvents

the barrier created by the polymer and starts affecting the well production. However,

during the time period when the water conning is prevented/minimized, there should

be an increase in the oil production before water coning is back again.

The first water shut off performed using OrgaoSeal was in well C-149. An RST

log was run prior to the water shut off which showed 20' of oil zone and 23' of the

watered out zone below. During the workover in 12/2005, a 5-1/2" liner was

cemented across the open hole. A 10' interval was perforated in the top watered out

zone and 110 bbls of OrganoSeal was pumped at 2 bpm with 5 bbls cement slurry

pumped at the tail end. Subsequently, an 18' interval was perforated in the oil zone.

An acid job was performed using CTU and 1,200 gallons of 15% HCL acid. The well

performance in the last 10 years after the job is shown graphically below. The

following is a summary:

The polymer treatment was useful for at least 4 years in increasing the oil

production and reducing the water cut. As a result, about 449,000 STB of the

incremental oil has been produced from C-149 after the polymer water shut off

treatment. Therefore, the water shut off job was a big success.

Two more water shut off jobs were performed in wells C-98, & C-164. The details of

the jobs are summarized below:

41

Well # RST Log Run before Water shut

off Job

Workover Date

Job Details Acid Stimulation

Performed after Workover

C-98 Yes 5/2010 5-1/2" liner cemented. Pumped 110 bbls of OrganoSeal

No

C-164 Yes 2/2010 5-1/2" liner cemented. Pumped 110 bbls of OrganoSeal

No

The well production performance plots after the treatment are shown below:

41

Comparing C-98 and C-164, while the water production and water-oil ratio were

reduced after the water shut off job, the water shut off jobs were not successful in case

of well C-164 as experienced in C-98. The water production and WOR is expected to

be reduced by shutting off the watered out zones only by the liner but the OrganoSeal

barrier is expected to increase the oil production by keeping the water shut off for a

longer period as it did for 2.5 years in C-98.

It appears that the acid stimulation after the water shut off workovers is a

mandatory requirement to increase the oil production and to increase the "useful" life

of the water shut of treatment. The acid stimulation was performed in the case of C-

149 to remove the formation damage likely caused during the workover but it was not

done in case of C-98 and C-164.

Well # Well Performance before Water

Shut off

Initial Well Performance after Water

Shut off

Acid Stimulation Performed after Water Shut off

Workover

Remarks

C-98 Oil: 95 bopd Water: 2,276 bwpd

WOR: 24.0

Oil: 235 bopd Water: 26 bwpd

WOR: 0.10

No

Water shut off good for 2.5 years. Incremental oil produced after water shut off: 169,000 STB

C-164 Oil: 76 bopd Water: 2,460 bwpd

WOR: 32.3

Oil: 144 bopd Water: 757 bwpd

WOR: 5.2

No

Water production and WOR reduced but no increase in oil

production. Only good for only 4 months.

42

Pump 90 bbls of Oregano Seal-R at 2 bpm in the perforated interval. Pump 5 bbls

cement slurry to displace Oregano Seal-R. Displace the cement slurry and Oregano

Seal-R with water at 4 bpm. Squeeze the cement to shut off the perforated interval and

have a cement plug in the wellbore. DO NOT SQUEEZE THE DISPLACEMENT

WATER IN THE PERFORATED INETRVAL. POOH w/packer WOC.

The first water shut off performed using Oregano Seal was in well C-149. An

RST log was run prior to the water shut off which showed 20' of oil zone and 23' of

the watered out zone below. During the workover in 12/2005, a 5-1/2" liner was

cemented across the open hole. A 10' interval was perforated in the top watered out

zone and 110 bbls of Oregano Seal was pumped at 2 bpm with 5 bbls cement slurry

pumped at the tail end. Subsequently, an 18' interval was perforated in the oil zone.

An acid job was performed using CTU and 1,200 gallons of 15% HCL acid. The well

performance in the last 10 years after the job is shown graphically below.

The following is a summary

water cut % Remarks water rate bwpd oil rate bopd Date

96

Well remaind shut in

until Fed 2006

2459 102 June87

37

Water shut off

performed in 12/2005

316 539 March 2006

82

Treatment hseful life 4

year

953 209 Jnly 2010

93

Well returned back to

pre-job oil rate/wc

1378 104 current

The polymer treatment was useful for at least 4 years in increasing the oil production

and reducing the water cut. As a result, about 449,000 STB of the incremental oil has

been produced from C-149 after the polymer water shut off treatment. Therefore, the

water shut off job was a big success.

43

In order to compare the performance of the wells after the water shut off

treatments, the following data is tabulated.(table ..)

Well # Well Performance before Water Shut off Initial Well Performance after Water

Shut off Acid Stimulation Performed after Water Shut off Workover Remarks.

Compare

After WSO

Before WSO

Well #

bopd 539 :

Oil production :

102 bopd

C-199

bwpd 316 : Water production : 2460

bwpd

0.6 : WoR : 24. 0

Yes Successful water shut off job. Water shut off good for 4 years. Incremental oil

produced after water shut off: 449,200 STB

.

44

CHAPTER 5

5.CONCLUSIONS AND RECOMMENDATIONS

5.1 Conclusion

It appears that the acid stimulation after the water shut off workovers is a mandatory

requirement to increase the oil production and to increase the "useful" life of the water

shut of treatment. The acid stimulation was performed in the case of C-149 to remove

the formation damage likely caused during the workover .

5.2 Recommendations

If more water shut off jobs are to be performed in the future, the following steps must

be undertaken to improve the chances of success :

1-Before the water shut off workover, run RST log to determine the OWC

2-During the workover, run a liner and cement. Perforate an interval in the watered

out zone and pump 110 bbls of OrganoSeal followed by 5 bbls of cement. Perforate in

the oil zone.

3-After rig release, acidize the perforated oil zone by using 1,500 gallons of 15%

HCL with the same additives used in case of C-149 in three up/down CT passes.