water shutoff treatment in zelten field (s.o.c) shutoff treatment in zelten field (s.o.… · gamal...
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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
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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.
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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:
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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.
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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.
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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
.
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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.