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www.oiijournal.com 

OIL INNOVATORS 

VOLUME 06 | MAR. 2018 INTERNATIONAL JOURNAL 

Overcoming Challenges 

of Increasing 

Recovery Factor 

in Iran 

IOR/EOR of Iranian Oil Fields 

NAED’s EOR Decision Workflow, 

with Focus on Subsurface 

EOR Piloting; Unlocking Reservoir 

Potential and Reducing Uncertainties 

Monitoring of IOR/EOR Projects 

IOR and Its Relation to the Surface Facilities; 

A Step-by-Step Approach

OIL INNOVATORS 

INTERNATIONAL JOURNAL 

Inside this issue 

Owner: 

Hossein Shariatpanahi 

Managing Director: 

Seyed Farzad Shariatpanahi 

Editor-in-chief: 

Hamed Z. Qadim 

Authors: 

Hamed Z. Qadim, 

Sheila Jahanlou, 

Reza Falahat, 

Yaser Mirzaahmadian, 

Mohammad Fouladi, 

Mahdi Abbasi, 

Arman Aryanzadeh, 

Javad Madadi Mogharab 

Graphic & Design: 

Nima Sayar, 

Sara Osati 

Printing: 

Negarestan Co. 

Overcoming Challenges of Increasing 

Oil Production and Recovery in 

Existing ‘‘Brownfields’’ 

Improving / Enhancing Oil Recovery 

of Iranian Oil Fields 

NAED’s EOR Decision Workflow, 

with Focus on Subsurface 

PAGE.4 

PAGE.8 

PAGE.16 

Role of Petrophysical Data 

in Reservoir Monitoring and 

Management 

Characterize Your Reservoirs 

through Application of Chemical 

Tracer Technologies 

Increased Oil Recovery and Its 

Relation to the Surface Facilities; 

A Step-by-Step Approach 

PAGE.48 

PAGE.54 

PAGE.66 

Address: 

No.14, West Sepand St., 

Sepahbod Gharani Ave., 

Tehran, Iran 

Phone: 

+9821 88949312 

Fax: 

+9821 88949311 

Email: 

info@oiijournal.com 

Website: 

www.oiijournal.com 

EOR Piloting; Unlocking Reservoir 

Potential and Reducing 

Uncertainties 

How Can 4D Seismic Assist to 

Monitor the IOR/EOR Projects? 

PAGE.26 

Optimized Solutions thorough 

Integration of Subsurface and 

Surface Engineering 

PAGE.74 

PAGE.42

Overcoming Challenges of Increasing 

Oil Production and Recovery in 

Existing ‘‘Brownfields’’ 

The Importance of Increased Oil 

Recovery in Iran 

Currently, the main challenge of the National 

Iranian Oil Company (NIOC), as the owner of 

the Iranian oil and gas fields, is renewal of oil and 

gas reserves. Increasing oil recovery is essential 

for Iran, as its in-situ oil reserves is about 712B 

barrels with recovery factor of below 25%. 

Hamed Z. Qadim, CEO & Business Developer 

Nargan Amitis Energy Development (NAED) 

Increased oil recovery can be obtained through 

the following methods: 

• Discovery of new reservoirs as a consequence 

of continuous exploration activities. 

• Better understanding of reservoir behavior by 

utilizing adequate reservoir monitoring tools 

which leads into improvements in simulation 

models and better forecast. 

• Application of IOR and EOR methods in oil 

reservoirs with low recovery factor and/ 

or inefficient displacement drives both as 

secondary and tertiary stages of oil production. 

• Demployment and/or development of new 

technologies on the existing fields (such as 

infill drilling, smart completion, fracturing, 

fishbone technology, drilling of horizontal 

wells and sidetracking from existing holes to 

activate less permeable parts of the reservoir, 

multi-lateral wells, well shut-off and etc.). 

• Integrated operations (IO) (i.e. new workframe 

processes and ways of performing oil 

and gas exploration and production), which 

has been facilitated by new information and 

communication technology. One example 

for IO is multi-disciplinary collaboration in 

plant operation. In short, IO is believed to be 

collaboration between surface and subsurface 

disciplines with production in focus. 

With the decline in oil discoveries over the last 

years, it is believed that the other four methods 

will play key roles in maintaining the reserves in the 

country in the years to come. Most of the current 

oil production in Iran is coming from ‘aged-fields’, 

which are in their ‘tail-end production’. Cost of 

producing hydrocarbons from some of the ‘aged 

offshore fields’ can sometimes be higher than 

the revenues (especially when then oil price goes 

below 30 USD), if no improvement is made in the 

processes and none of the technologies above is 

utilized. 

Considering the current state of Iranian 

hydrocarbon fields which have been producing 

under nonsystematic reservoir management, 

it seems that there are lots of rooms for 

improvements and it is expected that by 

implementing the aforementioned techniques, 

a significant improvement in recoverable reserve 

can be obtained. It is worth mentioning that even 

1% increase in oil recovery in Iranian oil fields 

would be a great achievement for the country. 

The first and most important step towards 

increasing oil recovery is to improve subsurface 

understanding, which can be achieved through: 

• Utilizing advanced reservoir monitoring 

techniques 

• High qualified and ‘fit-for-purpose’ laboratory 

experiments 

• Advanced numerical reservoir modeling and 

prediction under uncertainty 

The second step is, of course, to utilize the 

advanced and new technologies made for the 

needs of our fields. There are some analogies 

between Iranian fields and other fields in 

the world for which some technologies have 

already been developed to resolve our common 

issues or needs. For example, well completions 

technologies, advanced fracturing techniques 

and chemicals have been significantly developed 

over last decades (especially in the period when 

oil price was high and due to the sanctions we did 

not have access to the latest technologies), which 

can easily be utilized in our fields. 

Current State of EOR Contribution 

on Total Oil Production 

EOR projects in both onshore and offshore oil 

reservoirs have made a relatively marginal 

contribution in terms of total oil recovered in 

the world. Less than 3% of total worldwide 

production is reported to be due to EOR project 

implementation, among this the share of chemical 

EOR project is as low as 0.5%. Majority of this 

contribution comes from onshore fields. 

IOR projects, however, are implemented widely in 

the world and have turned into a normal practice 

in many of their assets. This could help operators 

to increase their oil recovery quite significantly 

(i.e. recovery factor of above 60% in the assets 

operated by Statoil in the Norwegian Continental 

Shelf, NCS, is targeted). 

In Iran, however, no chemical EOR projects have 

been initiated so far, and only gas injection and 

water flooding are performed in some fields 

mostly to maintain pressure (except in one 

case in which gas injected in miscible mood to 

change the oil properties). Reservoir pressure 

maintenance is categorized in IOR projects. There 

is no official number reported in Iran to exactly 

know how much of total oil is produced from IOR/ 

EOR projects. 

It should also be mentioned that most of the IOR/ 

EOR projects in Iran have been implemented in 

more traditional way without utilizing neither 

advanced modeling techniques nor high quality 

of data/tools. This has led into high level of 

uncertainties associated with the projects. 

4 OIL INNOVATORS International Journal MAR. 2018 5

Challenges of Implementation of 

EOR Projects in Iran 

I 

t is very challenging to establish a competitive 

accomplishment of EOR projects in Iran: 

Incomplete subsurface understanding: Very 

limited efforts have been made so far to map 

the remaining oil in the reservoirs and almost 

no monitoring techniques have been utilized 

to understand the flow in the reservoirs and 

consequently improve the quality of simulation 

models for prediction. 

Not-optimized well locations: Current well 

placements are not necessarily optimized for 

EOR projects. In addition, in offshore fields, 

there is usually a large distance between wells 

(injectors and producers) which make the 

implementation of chemical EOR very difficult. 

High cost of building EOR facilities or 

redevelopment of existing brownfield: The cost 

of EOR implementation projects is very high 

in offshore fields (High CAPEX and operating 

costs). The projects usually are of a large scope 

and involve usage of infrastructure. They 

usually require a big investment upfront (in 

both offshore and onshore) and have relatively 

long payback periods as production response 

does not occur immediately. 

High cost of EOR fluids: (i.e. chemicals and 

miscible gas) 

Concerns over EOR economics: Economy of EOR 

project is very much time dependent; delayed 

implementation, reduced reserve. Time-line 

of an EOR project, which usually consists of 

field/reservoir selection, process selection, 

geological and reservoir studies, design 

parameters, pilot testing and implementation, 

can be up to 10 years before observing field 

response. This requires great efforts, time and 

focus of an organized and integrated team 

(combined surface and subsurface disciplines) 

and usually with huge investment. The break- 

even of EOR projects is ranging from 20 to 25 

USD/bbl 

Technology needs: It is also experienced that 

depending on the selected EOR method and 

field characteristics and production system, 

for each field, a set of specific technology is 

required. Therefore, sometimes a ‘tailor-made’ 

technology is required to be developed. 

Limited technical and managerial experience: 

Since this has never been practiced in the 

country, no or limited in-house technical and 

managerial knowledge is available in the body 

of NIOC. 

Not a clear EOR ambition and strategy: 

Although, Iranian parliament has passed a 

law demanding oil ministry to increase the 

oil and gas recovery rate, this has never been 

turned into a clear ambition and strategy and 

consequently no roadmap is defined towards 

increasing oil recovery by oil ministry as the 

sole owner of hydrocarbon fields in Iran. 

Proposed Strategy for Increasing 

Oil Recovery in Iran 

new look at the field development plans 

A with more focus on increasing oil recovery is 

required, in which the most desirable drainage 

strategy to be chosen. Considering the current 

state of our fields, the following areas are 

suggested to be the ‘focus-areas’ of NIOC: 

• A clear Increase oil recovery ambition to be 

defined by NIOC and consequently a strategy 

how to achieve the ambition 

• Needs and challenges of each individual asset 

to be identified by NIOC and its subsidiaries. 

This could help service companies to define 

their strategies too, for the years to come. 

• Due to high cost of EOR projects, NIOC is 

suggested to put equal or even more efforts on 

‘fast response’ increase oil recovery methods 

consisting, and limited to the followings: 

 

Increase productivity/injectivity in the 

existing wells 

Optimization of artificial lift design and 

injection 

Minor modifications in the surface facilities 

for removing the obstacles 

This will lead into a relatively faster increased 

oil recovery using low CAPEX required. 

• Improved understanding about the flow in 

the reservoirs using the available monitoring 

technologies, more often well tests and fluids 

sampling, more accurate data collection from 

fields and better quality of laboratory works. 

These will lead into improved simulation 

models resulting in better prediction forecast. 

Increased recovery projects (both IOR/EOR) 

are very much dependent on the outcomes 

of simulation models which less attention has 

been paid to it so far. 

• Improved reservoir management system to 

be established as a dynamic process which 

recognizes the uncertainties in reservoir 

performance seeks to mitigate the effects of 

these uncertainties by optimizing reservoir 

performance through a systematic application 

of integrated, and multidisciplinary 

technologies. 

IOR/EOR workgroup of Iran E&P congress, in which 

representatives of main key players in industry are 

participating, is a very good opportunity to address 

these challenges. Participants from petroleum 

ministry and integrated planning department of 

NIOC, as well as production subsidiaries of NIOC 

(NISOC, IOOC, ICOFC, POGC and PEDEC) and local 

E&P companies like Pasargad, Qadir, IOEC, and etc. 

sit together with engineering consultancy service 

companies and discuss over these challenges. 

Nargan is hosting the event during 2018 and we 

are planning to have contribution of international 

consultants in these events. Overcoming these 

challenges require a comprehensive and thorough 

understanding and collaboration of all key players 

and stakeholders. The necessity and need to 

apply IOR/EOR techniques is well understood and 

is known to everyone. It is the time to deploy our 

expertise and technical capacities to have better 

plans and successful implementations. 

Hamed Z. Qadim 

Hamed Z. Qadim, CEO & Business Developer 



Improving / Enhancing 

Oil Recovery of 

Iranian Oil Fields 

- Background 

- Iran Oil Fields 

- Current IOR/EOR Status of Iran 

- Shortages and Challenges of EOR in Iran 

- Conclusion and Suggestions 

Mahdi Abbasi, Reservoir Engineer 


Producing from 358 oil and gas 

formations, Iran contains about 170 

hydrocarbon fields (120 oil fields and 

50 gas fields) which 78 of them are 

under production by the share of 62 

onshore fileds and 16 offshore fields. 

These producing fields are extracting 

oil from 163 developed reservoirs and 

195 reservoirs are remaining for future 

developments. Albeit the universal 

efforts to reach the recovery factors of 

more than 34%, Iranian active fields are 

producing with sharp variations but with 

an average recovery factor of 25%.

Table 1: Iran major oil producing fields and original oil in place [4] 

Original Oil In 

Daily Production 

Oil Field Formation 

Reserve (MMbbl) 

that 68.5% of the fields in Iran are in extreme 

Place (MMbbl) 

(Mbbl/day) 

Background 

need of enhancement of oil recovery (EOR/IOR) 

P 

1 Ahwaz Asmari and Bangestan 65.5 25.5 945 

roducing from 358 oil and gas reservoirs, Iran methods . 

2 Marun Asmari 46.7 21.9 520 

contains about 170 hydrocarbon fields (120 oil 

3 Aghajari Asmari and Bangestan 30.2 17.4 200 

fields and 50 gas fields) from which 78 of them Iran Oil Fields 

are under production by the share of 62 onshore 

4 Gachsaran Asmari and Bangestan 52.9 16.2 560 

O 

fields and 16 offshore fields. These producing wning 157.8 Bbbl of reserve crude of the 

5 Karanj Asmari and Bangestan 11.2 507 200 

fields are extracting oil from 163 developed world by 2015, Iran ranked fourth among 

reservoirs and 195 reservoirs are remaining for giant oil producing countries such as Venezuela, 

future developments. Some of these fields are Saudi Arabia and Canada [1] . 

shared by Iran neighboring countries such as 

Ahwaz oil field, as the biggest Iranian oil field and bring an average of 5 Bbbl of oil potential and a 5% 

Total hydrocarbon in-place of Iran is estimated to 

Iraq, United Arabia, Qatar, Kuwait, Turkmenistan, 

third world’s giant oil field contains 65.5 Bbbl of oil increment in oil recovery is equal to exploration 

be about 126.44 Bbbls of oil and gas condensates 

Bahrain and Saudi Arabia. Iranian producing 

in place which 25.5 Bbbls of them are recoverable. of a new field in scale of Azadegan oil field [7] . 

which 99.54 Bbbl of them are in land and 26.90 

reservoirs are containing about 600 Bbbl of oil 

Gachsaran oil field contains about 52.9 Bbbls and 

Bbbl are located in sea areas. Conducting EOR 

Water and gas injection with the purpose of 

originally in place while about 157 Bbbl of them are 

16.2 Bbbls of respectively originally in place and 

methods, it’s predicted to achieve an extra 

pressure maintenance are categorized as IOR 

producible using current condition and remaining 

recoverable oil is ranked second in Iranian oil 

production of about 27.04 Bbbls of hydrocarbons 

methods and considered as secondary production 

hydrocarbons are left unrecoverable without any 

fields. Iran’s third oil field is Marun oil field with 

and finally 153.48 Bbbls of oil from primary and 

scenarios which are evaluated and selected based 

further actions. Albeit the universal trails to reach 

46.7 Bbbl of oil that is originally located in Asmari, 

secondary production stages. To guarantee 

on reservoir characteristics. Currently 19 fields 

the recovery factors of more than 34%, Iranian 

Bangestan and Khami oil bearing formations. 

the production plateau and being assure of a 

are under injection scenarios from which, 13 fields 

active fields are producing with sharp variations 

Azadegan oil field is the fourth one with 32 oil in 

sustainable development with consideration of 

of NISOC are gas injected and in 6 fields owned 

but with an average recovery factor of 25%.This 

place and is the largest shared field between Iran 

future generation, implementation of IOR/EOR 

by Iranian Offshore Oil Company (IOOC) water is 

gap is an indication of unfavorable condition of 

and Iraq. Aghajari is the next oil field with 30.2 Bbbl 

project to correct oil extraction scenarios is highly 

injected 

Iranian formations. In fact some statistics show 

of OOIP ranking fifth. Ahwaz, Marun, Aghajari and 

. Table 2 shows the amount of water or 

important [2] . 

gas injected to these fields in ten years: 

Gachsaran oil fields are containing the main share 

of daily production of Iran with about 2 mmbbl 

of crude oil production. Azadegan oil field is also 

capable to produce 40 mbbl per day [3] . 

Table 2: Volume of Gas and water injected to Iranian fields [8] 

Current IOR/EOR Status of Iran 

Year 

Gas 

Water 

(MMm 3 /Day) (MMbbl/Day) 

Average recovery factor of Iranian producing 

2006 

77.3 

98.9 

reservoirs is about 25%. This number varies a 2007 

73.1 

130.3 

lot from one field to another (e.g. 7% in Soroush 2008 

87.7 

132.9 

oil field and 40% in Ahwaz oil field). Although 2009 

77.7 

420.6 

recovery factor is highly dependent on reservoir 2010 

79 

152.6 

characteristics, the amount in 44 producing 

2011 

88.4 

152.6 

reservoirs under supervision of National Iranian 

2012 

86.9 

403.2 

South Oil fields Company (NISOC) is about 

28% [5] . However, most of producing reservoirs 2013 

77.7 

130.6 

that are under production in offshore Norway 2014 

81.9 

125.9 

have targeted ultimate recovery of above 60% [6] . 2015 

72.17 

295.9 

Regarding the current proved oil in place in Iranian 

reservoirs, each 1% incremental oil recovery will 

2016 

94 

- 


The first secondary production plan in Iran 

commenced in 1977 in Haftkel field with the 

application of gas injection. Then, in 1978 gas 

injection in Gachsaran field with the target of 

pressure maintenance was implemented. Gas 

injection to these fields are still continuing till 

now. Immiscible gas injection to Gachsaran, Bibi 

Hakimeh, Aghajari, Koupal, Marun, Pazanan, 

Karanj, Parsi, Haftkel and Lab Sefid and miscible 

gas injection to Ramshir and Darquein are 

currently being conducted. While there is no 

water injection in any of the onshore fields, IOOC 

conducted several water injection projects on 

offshore fields due to availability of seawater. 

Salman, Siri C, Siri D, Siri E and Balal fields are 

those water injected fields under supervision of 

IOOC. It should be noted that since these water 

injections are done with the main objective of 

pressure maintenance there may have been 

little studies performed to determine possible 

alteration of rock/fluids properties (e.g. water 

salinity and composition have not been optimized 

for wettability alteration). 

Table 3 provides information of water and 

gas volume injected to some of the onshore 

fields in 2014 for IOR/EOR purposes. Offshore 

implementation of EOR/IOR methods is more 

cost consuming and challenging compared to 

the onshore fields. Additionally, long distance 

between injectors and producers in offshore fields 

makes chemical EOR projects to be challenging. 

Due to access of water in offshore fields, waterbased 

EOR seems to be more interesting and 

applicable compared to onshore fields in which 

there is less access to water. 

Due to low injection rate of water and gas in most 

of Iranian fields (due to technical and operational 

issues as well as limited access to gas in onshore 

fields, especially in winter season), cumulative 

injected volume will be far less than required 

amount even in long periods of time. To maintain 

the reservoir pressure, injected volumes of water 

are severely small and usually have no EOR/IOR 

impact. 

Table 3: Volume of Gas and water injected to Iranian fields [8] 

Oil Field 

Haftkel (Gas Inj) 

Rag Sefid (Gas Inj) 

Marun (Gas Inj) 

Gachsaran (Gas Inj) 

Bibi Hakimeh (Gas Inj) 

Koupal (Gas Inj) 

Karanj (Gas Inj) 

Ramshir (Gas Inj) 

Parsi (Gas Inj) 

Pazanan (Gas Inj) 

Nargesi (Gas Inj) 

Darquein (Gas Inj) 

IOOC fields (Water Inj) 

Gas (MMm 3 /Day) 

0.25 

0.02 

15.12 

15.31 

3.78 

2.01 

5.61 

0.13 

2.12 

5.10 

0.11 

6.2 

295.9 

Saudi Arabia has injected more than 2 MMbbl of 

water per day just in Qawar field, since1964 [9] . 

This pressure maintenance activities in addition 

to improving composition of injected water as 

the tertiary recovery method have caused the 

production remaining at 4.5 MMbbl per day and 

the recovery factor of 54% which have been 

achieved. This in comparison with water injection 

of about 259.9 MMbbl per year in all of the fields 

of Iran shows that there is a need to modify the 

injection plans with new mindsets based on more 

detailed studies. 

Although it have been planned to increase the 

recovery factor by an amount of 2.5% by the 

end of fifth development plan, it might not be 

suitable target in comparison with other oil 

producing countries. It should be also considered 

that reduction in average production rate of 

Iranian fields is about 9-11 % per year. With an 

average recovery factor of 25% for Iranian fields 

and this annual decline in production rate, Iranian 

crude producers are only able to produce 134,400 

MMbbl of oil without application of any EOR 

technique. 

To maintain the reservoirs’ pressure, it’s highly 

important to initiate the water/gas injection 

projects in an appropriate time to reach the 

planned production targets and eliminate the 

possibility of irreversible losses of recoverable 

reserve potentials. It is vital to note that secondary 

and tertiary recovery methods are necessary in 

Iranian fields to maintain the optimum sustainable 

production [7] . 

Challenges of Implementing EOR 

Projects in Iran 

Looking into previous experiences of IOR/EOR 

projects in Iran, some challenges for successful 

implementation of projects can be determined: 

1. Selection of the most appropriate EOR 

method requires very good understanding 

about the residual oil and reservoir 

performance, advanced simulations, highqualified 

laboratory work as well as pilot 

application to verify the potential and reduce 

the uncertainties. It seems to be that there 

are limited available data for such studies, 

and thus the decisions have sometimes been 

taken based on unreliable and uncertain 

data. Data gathering for reservoir studies and 

characterization with special focus on EOR/ 

IOR screening is commenced at the beginning 

stages of the field lifecycle. All the activities on 

reservoir have to be designed and conducted 

with focus on EOR methods. Rock and fluid 

samples of the reservoirs need to be obtained 

and high quality laboratorial tests must be 

performed from the beginning of the field 

development. Due to getting used to mindset 

of early production of easy oil in oil and gas 

industry in Iran, there is always several shortages 

in data gathering and construction of valid data 

bases that leads into further issues in future 

plans for EOR studies and implementation. This 

issue is more highlighted in the productionbased 

managerial approaches in which decision 

makers usually do not allocate enough time 

and budgets for data gathering from various 

parts of reservoirs [10] . Data such as amount of 

swept oil, un-swept regions and residual oil 

saturation in water/gas injection processes are 

vital information that are required to be known 

to increase the success of improvement/ 

enhancement oil recovery methods. That is 

why monitoring techniques such as 4D seismic, 

tracer tests and repeated well logging in 

observation wells are highly important in such 

processes and are usually considered as one of 

the main parts of any EOR/IOR studies. 

2. Most of research projects in Iran oil and gas 

industry have been completed with no real 

case application. The results of these works 

are usually stored as leaflets and papers. 

Sometimes even availability of these results 

is problematic and requires a series of timeconsuming 

activities inside the governmental 

organizations. It is strongly required to have 

a systematic plan in designing, budgeting 

and conducting research-based projects in 

Iran oil ministry to have fruit-full and direct 

utility in Iran oil and gas industries. With a 

quick glance on some of the research-based 

projects, it could be concluded that several 

reasons like inappropriate and non-framed 

project description and scope of work, lack of 

required data at time of implementation and 

relying on incorrect assumptions, leads into 

a situation that results are not applicable in 

industry. This fact highlights the importance 

of introducing an effective and efficient 

framework for project scope definition and 


linking researchers with industry with the 

aim of improving the efficiency of industrial 

works with focus on solution –based projects 

resulting from research projects. 

3. There is limited experiences in implementation 

of EOR/IOR projects in Iran and these limited 

works have just been restricted to academic 

research projects. Additionally this situation 

worsened by rushing into execution of such 

methods without comprehensive studies and 

planning. 

4. EOR/IOR projects are containing various 

phases of data gathering, laboratorial 

experiments, simulation of several scenarios, 

pilot application and finally, full field 

implementation. The time required for 

maturation and qualification of an EOR 

technique might be up to ten years. Often 

new technologies are utilized during all of 

the mentioned stages which is one of the 

main concerns in implementation of EOR/IOR 

projects. Acquiring these technologies and 

transferring the technologies to local service 

companies is quite a big issue and thus makes 

these technologies not accessible and easily at 

hand. It also increases the cost of the EOR/IOR 

projects which have negative impact on the 

economic justification of EOR/IOR methods. 

Conclusion and Suggestions 

Comparing the recovery factor in Iranian fields 

(i.e. average of 25 %) with current worldwide 

experiences to achieve a recovery factor of above 

34% and also considering variety of previous 

activities for this targets, it could be concluded 

that there is a high potential for development in 

this area which requires also some infrastructural 

developments including changes in strategies and 

managerial paradigms. Knowing that recovery 

factor targets of more than 60% in some of the 

fields of Statoil in Norwegian Continental Shelf 

(NCS) proves such targets are achievable though 

challenging and requires both technical and 

managerial competencies. 

Generally two different categories of EOR/IOR 

methods with different levels of budget and 

impact on recovery factor can be considered: 

Low risk and low CAPEX methods 

Modification/Improvement of production 

facilities and/or applying new technologies 

for improving the production on well and topside 

facilities such as multilateral wells, infill drilling, 

smart wells, tailored technologies such as water 

shut off technologies, process modifications and 

applying asset integrity tests and equipment 

renewing, increases the production rate. Here the 

focus is more on the production facilities and there 

is no or little focus on reservoir physical properties 

and resultantly there would be no alterations on 

underground production strategies. Therefore it 

will be cheaper and less risky and the production 

increase might be achieved in a shorter time 

duration. 

High risk and high CAPEX methods 

Second approach focuses more on reservoir 

alterations which are more expensive, more 

time consuming and also inherently more risky. 

Such production enhancing methods could be 

categorized as follows: 

1. Empowering current water/gas injection 

projects 

As mentioned before, most of current water/ 

gas injections to Iranian fields are not adequate 

considering low rate and volume of injection. 

Lack of required gas for injection is one of 

the main issues. 72 million m 3 of gas has been 

injected to Iranian fields in 2014 while only in 3 

fields out of 13 fields there has been successful 

gas injection and 10 remaining fields have 

high potential for gas injection. So improving 

current gas/water injection projects to fulfill 

their potentials can be a priority for enhancing 

oil recovery in the fields of Iran. 

2. Conducing new EOR projects with priority 

on giant fields 

There are 120 un-developed and 60 developed 

fields in Iran and also in 60 developed fields 

and only 19 fields have had poorly conducted 

EOR/IOR projects (water/gas injection). Most 

of Iranian fields are under production from 

natural energy of reservoirs and there has been 

no EOR/IOR activities on them. Therefore, 

there are huge potentials in this area which 

need to be explored. 

Continues reservoir monitoring and gathering 

more data from reservoir before and during 

implementation of EOR/IOR methods are 

critical. It is important to note that this 

integrated view, helps us to have an in-depth 

understanding of the field response during 

EOR screening workflow even before piloting 

phases. Resultantly there will be a valid, 

trustable and integrated databank of reservoir 

characteristics and other parameters which 

have been created, modified and matured 

while screening steps to reach to the best 

fitted method to be implemented. 

From technical points of view continues 

monitoring of reservoirs during implementation 

of the EOR projects will result in improving and 

updating knowledge and understanding of the 

reservoir thus assisting the decision makers 

to make more precise and accurate decisions 

improving chance of EOR projects’ success. 

References 

www.commons.wikimedia.org/wiki/ 

File:World_Oil_Reserves_by_Country-pie_ 

chart.svg. 

Scientific Propagative Journal of Oil & Gas 

EXPLORATION & PRODUCTOIN, 2003. p. 3-4. 

www.fa.wikipedia.org. 

The 8th IIES International Conference “Energy 

Security and New Challenges”, h.i.N., IRIB 

Conference Center, Tehran, Iran. 

NIOC Official News Agency , w.s.i.-f.h. 

Tabnak News Agency, h.w.t.c.n.p.i., 2 February 

2010. 

Scientific-Propagative Journal of Oil & Gas 

EXPLORATION & PRODUCTOIN, 2011. 

1390(77): p. 6-11. 



1396(145): p. 28-35. 

www.hydrocarbons-technology.com/projects/ 

ghawar-oil-field 



1391(91): p. 6-9. 

Oil Rig in South Part of Iran 


NAED’s EOR Decision 

Workflow, with Focus 

on Subsurface 

- Background 

- NAED’s EOR Decision Workflow 

Javad Madadi Mogharrab, Reservoir Engineer 


There are high financial and 

technical risks associated with 

EOR projects,which make the 

investment on this type of 

projects challenging in Iran. 

Although,tremendous ‘standalone’ 

experimental studies 

and/or simulations have been 

performed,it is hard to expect 

any positive outcome from these 

studies without a clear roadmap in 

an integrated and timely manner. 

Therefore, it is necessary to 

propose an EOR application road 

map in which the whole processes 

can be addressed (in an integrated 

surface, subsurface engineering 

studies as well as economic 

aspects). 


Background 

Reduced production rate from aged-fields and 

delineated new oil and gas discoveries on 

the one hand and on the other hand increasing 

universal demand for more oil, will turn EOR 

activities to a powerful tool for targeting 

the remaining oil in the depleted reservoirs. 

Therefore, investment tendency has been 

increasing on EOR projects in the last decades. 

Most of Iranian reservoirs are in their late-life 

and ‘tail production’. In order to keep up the 

production rate, more infill wells can potentially 

be drilled as temporary or short-term solution. 

Increased number of producers in the long term, 

however, imposes more pressure drop leading to 

production rate decline and considerable amount 

of oil remained in the reservoir. According to the 

published statistics, Iranian reservoirs average 

recovery factor has been approximated as 25% 

of STOOIP, while the worldwide average recovery 

factor closes to 35%. There are two main reasons 

for Iranian reservoirs low recovery factor; 

reservoir heterogeneity and very limited efforts 

on EOR projects implementation. 

Financing of EOR projects is generally very 

challenging because of several factors like the 

number of uncertainties affecting the economy 

of the project, high early investment (CAPEX) and 

late rate of return. In Iran, however, since there 

is no integrated data bank for Iranian reservoirs 

and sometimes very poor understanding about 

the reservoir performance, the number of 

uncertainties affecting the EOR business case 

is higher which leads into lack of confidence in 

profiles. Despite huge potential for EOR projects 

in Iran and the nature of this type of projects, which 

are risky with high associated uncertainties, no 

effort has been made in the country to define an 

ambitious goal or clear strategy towards increased 

oil recovery. Although, tremendous ‘stand-alone’ 

experimental studies and/or simulations have 

been performed, without a clear roadmap in an 

integrated and timely manner, it is hard to expect 

any positive outcome from these studies to be 

suitable for field application. Therefore, a need for 

an EOR application road map in which the whole 

processes can be addressed (in an integrated 

surface, subsurface engineering studies as well as 

economic aspects) has already been highlighted 

in the country. 

The first EOR decision workflow in four steps was 

proposed by Goodyear et al. (1994) [1] , as illustrated 

in Figure 1. 

Figure 1: Decision and Risk Management Workflow 

(adapted from Goodyear and Gregory, 1994) [1] . 

Their workflow starts with a fast screening 

followed by simulations and appraisal before 

field implementation. The weaknesses of this 

workflow are listed as follows: 

1. Fast screening only deals with analogies 

and does not work based on neither simulation 

nor experimental data. 

2. Screening is suggested to be performed 

using the conventional understanding about 

the application of EOR methods, in which the 

new understandings and advanced methods 

(such as Smart-Water) were missing. 

3. Each step is defined as ‘stand-alone’ and 

integration between the different steps is not 

seen. 

This workflow was then modified by Manrique et al. 

in 2009 [2] by considering some laboratory work and 

modeling into the screening step, but integration 

between the phases and need for piloting were 

still missing in the modified workflow. Several 

data banks and success criteria were suggested 

in the literature ranging from the one suggested 

by Taber et al. in 1996 (in which only traditional 

understanding was covered) to Aldasani et al. 

in 2011 who has also included advanced EOR 

methods and new understandings [3-7] . 

Recently, a new step-by-step approach workflow 

is suggested by NAED with more focus on 

the integration of different steps as well as 

surface-subsurface-economy aspects. The main 

advantages of this approach are: 

• Cost efficient: which means operators do not 

need to spend too much money and time on 

the EOR methods, which can easily be rolled 

out from the list (using EOR tool-box). 

• This method is designed to reduce the 

uncertainties and risks associated with 

EOR methods. Risks and uncertainties are 

identified in each step (as well as their impact 

on profile and economy) and then a plan will 

be made to study them in more details in 

the coming phases by either initiating more 

simulation work, lab tests and/or even pilot 

which leads to reduce the most affecting risks 

and uncertainties. 

• This will lead into a very comprehensive pilot 

program with ‘fit-for-purpose’ design and 

correct definition of success criteria. 

• The needs for the new technologies (both 

surface and subsurface) will be identified, 

which help operators to seek and pick the right 

and ‘tailor-made’ technologies. 

• This methodology prevents over-optimization 

of facility design and consequently reduces 

the cost of operation. 

The following section describes the characteristics 

of NAED’s EOR decision workflow and the scope 

of each of its elements. 

NAED’s EOR Decision Workflow 

F 

ulfilling any EOR project requirements, NAED 

brought several categories of software, 

hardware and capable human resources together; 

assisting operators to increase oil recovery. 

Figure 2 shows a schematic view of NAED’s EOR 

decision workflow. NAED’s EOR package provides 

all the essentials and requirements to choose the 

most appreciate EOR method for reservoir given 

field. The workflow consists of six interconnected 

steps, before field implementation, starting from 

a Tool-box (as a property of NAED) and followed by 

preliminary simulation, experimental design and 

assessment, full field reservoir simulation, pilot 

design and ends up to the economic evaluation of 

EOR business case. Economic assessment is also 

suggested to be performed at the end of full field 

“ 

Nargan-Amitis Energy Development (NAED) proposes a 

step-by-step workflow for EOR screening and evaluation 

from laboratory to field. This workflow can be applied to 

any type of oil reservoir, in which EOR screening is planned 

to be executed. 

“ 


simulations to determine the EOR prize of a 

selected technique. From experimental phase 

until a business case, a multidisciplinary team 

(consists of surface and subsurface engineers 

and economists) work closely back and forth 

through the whole process until a common goal 

and understanding is achieved. Steps 2 to 4 are 

repeated until no further mitigation in risk and 

uncertainty is obtainable. If project economy 

(calculated from EOR profiles) is still positive and 

interesting, workflow can now move into the next 

phase, which is pilot design and implementation. 

Results from pilot will then be used to improve 

the quality of simulation model (both static and 

dynamic), which is so called ‘real-case’. Project 

economy will then be revisited using improved 

model to see if risky profiles are still economically 

interesting. If so, field implementation can be 

recommended. 

Technical uncertainties and economic risks during 

the various parts of screening and evaluation 

process, is the main concerns that will be 

addressed in NAED’s EOR decision workflow. It is 

being tried to reduce the technical uncertainties 

and control economic risks when moving from 

one step to another (i.e. moving from ‘best-guess’ 

to more a ‘real-case’). For example, uncertainties 

identified after preliminary simulation will be 

further addressed to narrow down the range of 

them in the next phase of simulation. 

The next sections describe the steps defined in 

NAED’s EOR decision workflow and corresponding 

necessities and intents. 

EOR Tool-box for Fast Screening 

Static and dynamic characterization of the 

reservoir is a basic and fundamental prerequirement 

of any screening procedure. In this 

regard, seismic, petrophysics, well testing, well 

logging, routine and special core analysis as 

well as mineralogy, geology cognition, and fluid 

properties are used to seek for the best match 

or analogy in the tool-box. In addition, material 

balance analysis is necessary to investigate 

reservoir volumetric behavior and define its main 

drive mechanisms. Also, oil recovery factor, water 

cut and GOR, flow rates and pressure decline 

rates are key factors which play very important 

roles in NAED’s primary analysis. This analysis 

is followed by finding the similarity between 

the current reservoir features and previously 

reported successful EOR projects, which is termed 

as ‘analogical screening’. In other words, the 

main objective of this section is to find a rough 

estimation of candidate EOR methods based on 

the previous similar successful projects. NAED’s 

EOR tool-box ranks different EOR methods from 

the most to the least promising techniques. 

It can be said that it is an exemplified model of 

Benchmarking. Figure 3 illustrates a typical result 

obtained from NAED’s EOR tool-box. 

Data collected from laboratory tests, and field 

trials are used as benchmark data, helping us to 

define our “best-guess” input for building a ‘fitfor-purpose’ 

EOR model for a given reservoir 

and selected EOR method. Benchmarking role 

in preventing waste of money and time during 

EOR decisions is undeniable. In addition to the 

conventional EOR methods (like gas injection), 

NAED considers the advanced EOR methods (like 

Low Sal/Smart water injection) which feeds more 

comprehensiveness to its EOR tool-box. 

Preliminary Simulation 

fit-for-purpose dynamic model is built using 

A a range of ‘best-guess’ inputs from the EOR 

tool-box (which is based on available field rock and 

fluid data from our EOR database). This model is 

used to: 

• Understand the reservoir response towards 

the injected EOR fluid(s) in fine grid sector 

model representing the main field 

• Predicting the range of production outcomes 

using simulation full field model 

• Running sensitivity analysis to determine the 

uncertainty parameters affecting the EOR 

profiles 

• Giving input to the next step which is laboratory 

design and assessment 

To determine the biggest EOR prize of a 

given method, the most optimistic case is also 

introduced by defining the input parameters 

to be optimistic. Economic calculation will be 

performed on the outcome of this case and 

project can move to the next phase if and only 

if it meets the financial criteria of the operator. 

This does not allow spending too much time and 

costing on something, which cannot be, by any 

means, economically interesting. 

Figure 2: NAED’s EOR decision workflow 

Figure 3: EOR methods analogy (primary screening) based on 

some parameters. 

It should be noted that building a static or dynamic 

model is not concern of any EOR workflow. It is 


assumed that a history-matched model is ready to 

be used for EOR purposes. It is only required to 

make sure that the dynamic model is capable of 

simulating the selected EOR process. 

Experimental Design 

Experimental investigations are the most 

important part of NAED’s workflow helping us 

to narrow down the range of some uncertainties 

and inputs for simulations. Depending on the 

results of sensitivity analysis performed on the 

‘preliminary simulation’, a test program is defined 

to reduce the risk on the uncertain parameters, 

especially those with high impact on the profiles. 

Experiments can within industrial-standard tests 

or it can be designed for our purpose ranging 

from fluid-fluid/fluid-rock interactions on watersaturated 

cores to flooding experiments in oil 

saturated core plugs. For example, preliminary 

simulation may show that a selected EOR method 

is very much dependent on wettability, which 

is not well understood in the field. Therefore, a 

test program will be designed to look at this in 

more detail to better understand it and reduce 

its range of uncertainty in the model (which can 

also be reflected in the relative permeability and 

capillary pressure). Therefore, this phase is linked 

to the simulation steps helping to reduce the 

uncertainties in the simulation models. 

Full Field Reservoir Simulation 

Simulation and experimental activities 

go shoulder-by-shoulder, meaning that 

uncertainties listed from simulation model are 

always addressed (if possible) in the lab to reduce 

their ranges and consequently their effects on the 

EOR profile. Therefore, results from laboratory 

should be analyzed and then fed into simulation 

to turn the input from ‘best-guess’ obtained from 

EOR tool-box into a ‘real-case’ obtained from real 

samples of the reservoir for a specific technique. 

EOR potential on field scale and its effectiveness 

might still be dependent on some uncertain 

parameters, which cannot be evaluated in the 

laboratory. In this case, larger scale laboratory 

program and/or pilot may be considered, if 

only economic calculation is still interesting. To 

evaluate the field potential, the accumulated 

volumes of oil, gas and water that are produced 

due to injection of EOR fluid is compared with the 

reference case without any EOR fluid injection. 

In addition to the sub-surface simulation, 

surface facilities are designed and simulated (by 

the process team) corresponding to any EOR 

method. They should be matured together with 

interconnected subsurface/surface simulation. 

It is obvious that any EOR method needs its 

own surface facilities (production, transferring, 

separation and refinement). Based on EOR project 

requirements (surface and sub-surface), CAPEX 

and OPEX are determined and fed into economic 

evaluation. This integrated economic evaluation 

is discussed in more details in this paper. 

Pilot Test Design 

Designing an appropriate pilot program is 

one of th e key aspects in EOR decision 

workflow. A successful pilot will provide valuable 

information about reservoir characteristics as 

well as key insights within reservoir behavior 

against EOR methods which are studied through 

laboratorial experiments and full field simulations. 

Piloting plays a critical role on reducing technical 

uncertainties and controlling economic risks which 

leads to more confidence of operators to accept/ 

reject candidate EOR methods. We believe that 

the three key elements to a successful pilot are 

‘Planning’, ‘Monitoring’ and ‘Evaluation’. 

From simulation activities, a list of technical 

questions will be made and addressed through 

pilot implementation to help operators reduce 

their risks associated with the EOR project. These 

questions will lead into a proper pilot planning and 

monitoring program. Questions are as follows: 

• What are the most contributing uncertainty 

parameters that should be addressed in the 

pilot? 

• How pilot can help operator reducing 

uncertainties within a reasonable time through 

a pilot? 

• How remaining uncertainties may affect the 

EOR potential profile? 

• How to make sure that monitoring programs 

addresses the success criteria for the pilot? 

Results from a successful pilot must be evaluated 

to see how uncertainties are narrowed. Then, 

reservoir simulation model should be tuned in a 

way to capture reservoir response over the course 

of pilot. The modified simulation model will then 

be used for determination of EOR potential 

profile. If it is technically and financially viable, the 

EOR scheme could potentially be elaborated to a 

commercial size operation in the field. 

Economic Evaluation of EOR 

Business Case 

EOR economic evaluation starts at the end of 

each step of simulation from which EOR prize 

is determined. There are four types of data which 

are used on economic evaluation; yearly increase 

in production as a result of EOR fluid injection, 

capital expense and operation expenditure as 

well as prediction of oil and gas price over time 

(any type of data can be categorized on two main 

groups as costs and incomes). In order to do 

comprehensive analysis of the costs and incomes 

and investigate the balance between them, cash 

flow chart is used. Cash flow is the money that 

is moving (flowing) in and out of business in a 

specified period. It is obvious that incomes are 

assumed as inflow cash and costs as outflow cash. 

For any EOR project, the inflow is mainly affected 

by increased oil production (daily & cumulative) 

and its price, and also indirect operational costs 

that are refused after implementation of EOR 

techniques. Therefore, it is important to predict 

them accurate enough. The oil price depends on 

various qualitative and quantitative parameters 

which turns its prediction into a challenging issue. 

Oil producing/consumer countries sociopolitical 

situations, economic growth, weather/ 

climate, need to petroleum products, crude 

oil transportation cost and OPEC policies are 

examples of effective factors on oil price. A good 

prediction model should consider mentioned 

factors and give short term, midterm and long 

term expected oil price during EOR project. Since 

there are usually too many technical uncertainties 

and economic risks associated with EOR projects, 

absolute correct estimation of the oil recovery 

and price is not possible and it is recommended 

to perform economic calculation on the possible 

expected rages of increased oil recovery (High, 

Base and Low). In addition to the prediction of oil 

price, the minimum accepted oil price which, is 

calculated based on the projection of cash flows 

and a set of rate of return, is an irrevocable issue. 

The minimum accepted oil price is the threshold 

below which the economic justifications of the 

project are invalid. 

Cash outflow are comprised of the following 

investment and operating costs: field development 

expenditures, equipment expenditures, 

operating and maintenance costs, injection 

material costs and other direct and indirect costs. 

Any type of costs can be categorized on CAPEX 

or OPEX. Capital expenditure or capital expense 

(CAPEX) is the money a company spends before 

the operation stage, to buy or improve its fixed 

assets, such as buildings, vehicles, equipment or 

land. On the other side, operating expense or 

operating expenditure (OPEX) is an ongoing cost 

for running a project, or system. In this regard, 


lower profit per barrel. Also, sensitivity analysis 

is done to determine the dependency of these 

indices to changes on the presumed assumptions 

and estimations. With sensitivity analysis, the risk 

of investment is also determined alongside its 

economic benefits. 

Figure 4 illustrates a typical cash flow for an EOR 

project. The yellow-dashed line (net cash flow) 

shows the payback period at which the total net 

flow moves from negative to positive. The area 

under the yellow-dashed line (cash flow integral 

respect to time) is correspondent to the profit. 

Alternative EOR methods that have proved to be 

technically feasible, are then finally compared in 

terms of their economic indices and sensitivities. 

Economic evaluation based on cash flow converts 

the technical and engineering information to 

the tangible parameters for decision makers 

and facilitate EOR method selection procedure. 

facilities, wells and completions are assumed to 

be CAPEX, while production, maintenance and 

chemical additives costs are considered as OPEX 

for an EOR project. It is necessary to note that, to 

have a profitable EOR project, optimized surface 

facility design should be considered beside the 

sub-surface ones. Therefore, NAED proposes 

an integrated economic analysis based on the 

surface and sub-surface CAPEX and OPEX. 

One of the most important points in economic 

evaluation is to define the best success criteria 

for any EOR project. Having in/out flows, we can 

calculate financial indices such as IRR, ROR, NPV/C, 

Benefit-to-Cost Ratio and etc. This is important to 

have these indices, since higher oil recovery factor 

is not reasonably equivalent to higher revenues in 

production. Since, depending on any EOR method 

costs, its net profit per recovered oil barrel is 

calculated. Therefore, some EOR methods may 

have higher values of recovered oil while show 

Figure 4: Typical cash flow and affecting parameters (Revenue, CAPEX, OPEX) 

In other words, it is considered as pure extract 

of NAED’s EOR decision workflow process. In 

this regard, NAED pays special attention to the 

economic evaluation and categorizes it on three 

main parts as: 

Generating forecasts of key technical 

and economic parameters: 

NAED’s technical and commercial team provide 

the following information to be used as the 

initial step of economic evaluation: 

a. Annual forecast of oil and gas production, 

uncertainty in the geology, and reservoir will 

also be included here. Therefore, it might be 

the case that a range of expected profiles (P10, 

P50, P90) to be given. 

b. Annual forecast of oil and gas prices at which 

the production is expected to be sold. IPA price 

forecasting can potentially be used, if client 

has no preferences. 

c. An annual forecast of the capital expenditures 

that will be required to develop the project. 

d. An annual forecast of the operating 

expenditures that will be required to maintain 

the expected oil and gas production (e.g. cost 

associated with maintenance of the plant, 

chemical to be used, resources etc.). 

Modeling of the Fiscal System: 

The contract term that governs the methods 

by which client must pay a portion of their 

revenue to the government will be gathered and 

imputed into the fiscal model of the project. This 

model is constructed and will ultimately calculate 

the annual after-tax cash flow that client will 

receive over the period of the EOR project. 

Calculation of Economic Indicators: 

This is the final step in NAED’s economic 

evaluation process which summarizes the 

future cash flow projections from step 2 into 

various economic indices and ratios that will allow 

client to make a decision in whether to proceed 

with the project (or any particular part of the big 

project such as any of the EOR methods). 

References 

Goodyear, S. and A. Gregory. Risk assessment 

and management in IOR projects. in European 

Petroleum Conference. 1994. Society of 

Petroleum Engineers. 

Manrique, E. J., Izadi, M., Kitchen, C. D., & 

Alvarado, V. (2009). Effective EOR decision 

strategies with limited data: Field cases 

demonstration. SPE Reservoir Evaluation & 

Engineering, 12(04), 551-561. 

Taber, J.J., F.D. Martin, and R. Seright. EOR 

screening criteria revisited. in Symposium on 

improved oil recovery. 1996. 

Henson, R., A. Todd, and P. Corbett. Geologically 

based screening criteria for improved oil 

recovery projects. in SPE/DOE Improved 

Oil Recovery Symposium. 2002. Society of 


Al-Bahar, M. A., Merrill, R., Peake, W., Jumaa, 

M., & Oskui, R. (2004, January). Evaluation 

of IOR potential within Kuwait. In Abu Dhabi 

International Conference and Exhibition. 

Society of Petroleum Engineers. 

Al Adasani, A. and B. Bai, Analysis of EOR 

projects and updated screening criteria. 

Journal of Petroleum Science and Engineering, 

2011. 79(1-2): p. 10-24. 

Taber, J.J., F. Martin, and R. Seright, EOR 

screening criteria revisited-Part 1: Introduction 

to screening criteria and enhanced recovery 

field projects. SPE Reservoir Engineering, 1997. 

12(03): p. 189-198. 


EOR Piloting; Unlocking 

Reservoir Potential 

and Reducing Uncertainties 

- Background 

- Practical Aspects of EOR Pilot Projects 

- Challenges of Piloting 

- Summaries and Remarks 

Arman Aryanzadeh, Petroluem Engineer 


Implementation of EOR/IOR projects is 

associated with too many uncertainties 

which involve significant financial risks. 

To reduce the risks, ‘Piloting’ of the 

selected EOR technique in a small and 

representative portion of the reservoir 

is planned as a very important step in 

any EOR screening processes. Besides 

reducing uncertainties, pilots provide an 

opportunity to resolve many potential 

issues and to qualify technologies 

developed to resolve the issues 

associated with EOR projects. 

This article reviews the practical aspects 

of EOR pilots. Challenges of piloting as 

well as the value of increased confidence 

on EOR potentials by reducing 

uncertainties will also be discussed. 


Background 

Once a business case for an EOR method 

is recommended through an extensive 

simulation studies supported by lab data, and 

the contribution of uncertainty parameters on 

its economy is determined, a pilot project can 

be initiated to reduce the uncertainties and 

consequently increase the confidence on the 

recommended business case. Uncertainties 

which are involved in different stages of an EOR 

study (due to lack of reliable data, poor reservoir 

characterization/understanding, complex nature 

of reservoirs and unreliable simulation models) 

leads into fascinating challenges for engineers 

on how to predict reservoir behavior and 

consequently dilemma for financers and decision 

makers on whether or not spend money on a 

challenging and risky project. 

Additional lab tests, reservoir characterization, 

and simulation studies are usually required to be 

performed after pilot to resolve uncertainties 

UNCERTAINTIES AND RISKS 

Develop Idea 

Screen EOR 

methods 

Test in 

laboratory 

Model field 

and process 

Feedback lops to improve design 

can be implemented rapidly 

Design field test 

Perform Pilot: 

monitor and analyze 

Effort and investment 

further, as indicated by the feedback loop in Figure 

1. This is how all steps in an EOR decision workflow 

are strongly linked together and steps need to be 

followed one-by-one. Therefore, piloting is a very 

essential chain in EOR screening process, before 

the EOR technique is being implemented in full 

field scale. 

Planning, monitoring, analysis and evaluation are 

building blocks of a sophisticated pilot. This will 

allow to narrow technical uncertainties as well 

as economical risks to an adequate measure. 

Prospectively Pilot studies have uniqueness in 

their details. Encountering with practical aspects 

of Pilot projects, this article will exchange worldlyaccepted 

views on them. 

Practical Aspects of EOR Pilot 

Projects 

Prospective EOR projects are preceded by a 

pilot test to reduce risk of commercial failure 

and consequent investment loss [2] . This is not, 

Design field 

implementation 

Optimizing the EOR project 

continues throughout its life 

Implement 

in field 

Figure 1: EOR road map and Pilot testing position [1] 

Fine-tune field 

development plan 

Monitor and 

control project 

Expand field 

development 

of course, the only reason for conducting pilot 

tests. Results from pilot are also necessary to 

provide information for design of the commercial 

operations [2] . Therefore, pilot tests will assess 

uncertainties and risks and also verify studies 

performed as part of EOR screening. That is how 

more technical and economical confidence on an 

EOR technique might be achieved. 

It’s an inevitable fact that complete elimination of 

uncertainties from EOR decision workflow is not 

factual. There are several sources of uncertainties 

in various stages of EOR workflow (ranging from 

laboratory data, subsurface understanding and 

modeling capabilities) which can be reduced to 

some extent through a successful pilot project, 

which is designed for our purpose. 

Before conducting an EOR pilot, usually the 

following technical and non-technical questions 

will be raised to be discussed and agreed within a 

multidisciplinary piloting team: 

• How uncertainties are identified and how to 

quantify/qualify them? 

• How to address uncertainties and whether 

they are irreducible? 

• Can uncertainties be reduced significantly 

within a reasonable time and cost through a 

pilot? 

• How remaining uncertainties may affect the 

project? 

• How to define collection of monitoring 

programs to be able to address the success 

criteria for the pilot. 

• Are there any alternative or parallel activities 

to the pilot to take to reduce uncertainties? 

These questions lead into a better definition of 

success criteria for pilot, pilot design and any 

other complementary programs to undertake 

in parallel to pilot. It should also be noted that 

the three key elements to a successful pilot are 


Pilot Plan; Objectives and Success 

Criteria 

Pilot objectives are required to be clearly defined 

in order to be able to address the key technical 

and business uncertainties and risks, leading 

into defining success criteria for pilot. Pilot is 

planned in a way to meet the success criteria in 

order to verify the business case of the project. 

For example, in a case where EOR potential 

or business case is strongly dependent on 

injectivity of EOR fluid, determining injectivity 

can be an objective and if we already know that 

below a certain injection rate, EOR project is not 

economically viable, a minimum injectivity or a 

range of acceptance can also be considered as a 

success criterion to evaluate whether the pilot 

can achieve the minimum rate. The objectives of 

a pilot testing may vary a lot from one project to 

another, but it can generally be categorized in the 

following areas: 

• Evaluation of recovery efficiency 

• Assessment of the effects of reservoir geology 

on EOR fluid flow 

• Reducing technical uncertainties in various 

disciplines 

• Acquiring data to calibrate reservoir-simulation 

models 

• Identifying operational issues and concerns 

• Assessment of the effect of development 

options on recovery 

• Assessment of environmental impact 

• Evaluation of operating strategy to improve 

economics and recovery 

• Qualification of a certain technology developed 

for the purpose of the project 

Defining success criteria is significantly linked 

to the EOR method selected and uncertainties 

associated with the selected method. Acceptance 

ranges for success criteria is normally determined 

through sensitivity analysis using the simulation 

models and/or understanding from reservoir 


characteristics and flow. 

Pilot Design 

Like the initial phase of pilot, when designing a 

pilot, it is very important to always think: 

• What are you trying to do? 

• What is expected to achieve? 

• What is the definition of success? 

• How are you going to get there? 

• Who is impacted? 

• Whom do you need help from? 

To increase the chance of success of pilot, it is 

suggested to use prioritize matrix to rationally 

narrow down the focus of the pilot before 

detailed implementation planning. To ensure that 

the pilot is as realistic as possible, a representative 

portion of the reservoir with a reasonable size and 

boundaries need to be selected. It is necessary 

to select the best possible time for the pilot 

execution, which varied from one EOR method 

to another. For example, if a drop in water cut in 

a producer (as a result of EOR fluid injection) is 

the objective of a pilot, it is beneficial to plan the 

pilot to be executed when water cut is stable in 

the pilot producer. 

The cost of pilot is debated in the literature, but 

it is generally believed that pilot should never be 

planned in a way to save money. However, pilot 

is suggested to be executed in a way to collect as 

possible data as needed with all necessary means. 

I) Pilot area selection 

To understand the reservoir characteristics it is 

quite crucial when selecting an area for pilot. A 

pilot area must be a good representative of the 

reservoir. Since the presence of faults and/or thief 

zones may cause diversion of the injected fluid 

(not necessarily flowing through the reservoir oil 

bearing formation), it is recommended to select 

pilot area to be in an area with no thief zones. 

The same principal applies to the barriers as they 

make restriction for the flow of injected fluid. 

Selection of well and/or well pairs is another 

important factor when selecting the area for pilot. 

Pilot is normally executed in an area with minimum 

effect on daily operation and production. This is 

just to ensure a safe situation in case of any failure 

in the pilot project which may have negative 

impact on the entire field production. 

II) Type of pilot 

The complexity of reservoir heterogeneity 

and multiphase fluid behavior are such that 

optimal design of an EOR project requires in 

situ measurements in the reservoir. Depending 

on the size and depth of measurement as well 

as the criteria defined for pilot, size and scope 

of pilot is determined ranging from short and 

single wellbore test to multiple wellbores. Most 

of piloted EOR projects have used combination of 

different scales to obtain the required confidence 

in a step-by-step approach and also not to invest 

a lot early without being certain whether or not 

they can address the criteria defined. 

For example, to determine injectivity and/or rock 

mechanical parameters, a single well pilot would 

be a practical pilot project, in which Residual Oil 

Saturation (ROS) can also be determined in the 

area around the wellbore (i.e. up to a few meter 

around wellbore) using Single Well Tracer Test 

(SWCTT). This can still be considered as relatively a 

quick and inexpensive intermediate step between 

laboratory measurement in small core plugs and a 

multi-well pilot. It has recently been tried to limit 

the depth of measurements to a few centimeter 

of very small portion of a well by utilizing advanced 

tools (i.e. EOR Micro Pilot Using MDT Tester 

developed by Schlumberger). However, it is not 

always preferred and recommended. In single 

well pilot, relatively limited volume of injected 

EOR fluid (which normally requires no surface 

facilities for mixing or processing) is injected over 

a short period of time. As it is obvious, in multi 

well pilot, larger volume needs to be injected 

with preferentially available surface facilities for 

mixing and/or injection to target larger area in the 

reservoir for longer period of time. Wider scope 

with more complicated criteria can be sought in 

multi-well pilots (Figure 2). 

A detailed pilot simulation study and analysis 

needs to be performed before piloting using fine 

and coarse grid models to predict the possible 

outcomes of pilot and to understand the flow 

of injected fluid in the reservoir. Improved 

understanding about the pilot area can then help 

to better design the monitoring and evaluation 

phases. 

It should be noted that EOR piloting is very 

much case dependent and requires a ‘tailoredmade’ 

design and approach for any given case. 

Following table summarizes the advantages and 

Table 1: Advantages and disadvantages of Pilot types 

disadvantages of single well versus multiple pilot 

testing: 

Figure 2: Type of Pilot tests 

Single Well Pilot 

Advantages 

Disadvantages 

Allows to investigate more than one formation Will not reduce uncertainty as much as a 

successful multiwell pilot 

Lower uncertainty in measurement 

Implies decision on full field implementation at 

higher risk 

Relativily low investment level 

Reduced production during testing 

Earlier field implementation 

Requires well intervention 

Multiwell Pilot 

Advantages 

Disadvantages 

Large effect on reservoir uncertainty if successful Large investment upfront 

(can prove both mobilisation and production) 

A successful pilot covers investment (partly at Can cause delayed field implementation 

least) 

Gives operational experience 

Challenging to find good test area 

Facility solution may have possible post-uses Probably can only be tested in one formation 

even if project is stopped 


III) Pilot Timing 

An EOR project is one of the most risky and 

expensive projects over the production life of 

a field with long time-line before production 

response is occurred (i.e. can be up to 10 years). 

Despite the tremendous prize for a successful 

EOR project, risks of budgeting and financing 

for long time and reluctances and hesitations on 

defining an exact return rate for defined time 

durations are challenging. 

From recovery points of view, it is believed that the 

best time for EOR is from day one and/or as early 

as possible, which is not always possible, especially 

for those techniques which have to be qualified 

in a field through extensive piloting before the 

first use. Pilot planning, monitoring, evaluation 

and making decision takes time of up to 10 years 

before an EOR project is being implemented in a 

field. To increase the chance of success in any pilot 

project, good understanding about the reservoir 

is essential which is obtained over time during 

the period of production. Therefore, it can be 

concluded for non-qualified technologies, brown 

fields are better candidate than green-fields, as we 

have usually better understanding about the flow 

which can be led into a better design of a pilot, 

area selection and improved monitoring program 

and evaluation. How to perform pilots and length 

of time for piloting are the things which are 

determined through reservoir simulation study 

prior and during pilot test. 

Operators take different strategies to save 

time and implement the EOR projects as early 

“ 

as possible in their assets. They have defined 

a process called ‘Technology Readiness’, in 

which they mature their understanding about 

the effectiveness and readiness of different 

technologies (which are not even limited to EOR 

methods) through a close collaboration between 

research centers, assets and even decision 

makers. To mature a technology, one important 

step is piloting in a field. Once the effectiveness 

of a technology is proved, then that specific 

technology is so called ‘ready’ to be used in a field 

scale. This means that pilot can be planned and 

executed in one field and EOR in full field level 

gets implemented in another field(s). This is the 

only way to execute EOR project early in a field 

(i.e. Low-salinity waterflooding in the Clair Ridge 

field in UK and MEOR in the Norne field in Norway 

which started from day one of field development). 

IV) Testing and monitoring 

It is crucial to employ suitable methods and 

techniques to monitor the flow of injected fluid 

through porous media and gather reliable data 

during the course of piloting. Piloting is a kind 

of special experiments which are done in an 

area of the field, so several tests under various 

conditions would be performed, depending 

on the objective and success criteria defined 

for pilot. Any uncertain data from EOR effects, 

reservoir characteristics, reservoir production 

strategy, surface facility designs/modifications 

and other detailed questions for any EOR projects 

need special types of approaches for monitoring. 

Parameters such as rock’s fracture pressure 

and possible injection rates and pumping unit 

Pilot tests will assess uncertainties and risks and also verify studies 

performed as part of EOR screening. 

“ 

designs, connectivity of wells and flow conduits 

in reservoirs, behaviors and stability of injecting 

fluids in reservoir conditions could be some 

examples. There are several tools, well tests and 

techniques (including, not limited to, numerical 

methods) to be used during piloting. 

The new advances in technologies and 

methodologies will increase the reliability of data 

and confidence on the data gathered during pilot. 

It is worth mentioning that sometimes piloting 

may occur in a mini scale to test some specific 

parameters as mentioned in the previous section. 

Testing approaches as well as necessities for 

improvement in monitoring and testing could be 

addressed for further piloting trials. In addition, 

monitoring and testing techniques in pilot 

projects could be a valid roadmap to full field 

implementation. 

Evaluation of Pilot Results 

After initiating a pilot and collecting results and 

data, it is time to analyze the data to identify 

the gaps between the predicted performances 

(achieved using simulation models) and the 

actual ones. Finding out the root causes for the 

gaps is also very important which can lead into 

possible solution changes. To do so, results of 

pilot is necessary to be communicated within a 

multidisciplinary team. 

Plan of pilot has to be revisited to evaluate what 

worked and what didn’t, what had to be added or 

changed. 

In short, results of pilot should be utilized in a way 

to improve the quality of the simulation models 

resulting in a better understanding about the 

reservoir response towards the injected EOR 

technique. Once the reservoir simulation model is 

updated, business case of the EOR project in full 

field has to be revisited. 

Challenges of piloting 

Challenges and issues an EOR project may 

face could be categorized in technical and 

managerial aspects and business risks. Technical 

challenges are coming from uncertainties and 

ambiguities of the data, models and simulations 

(as results of unrealistic laboratorial experiments, 

unappreciated modeling techniques and 

lack of confidences in understanding of EOR 

mechanisms and reservoir response towards 

the given EOR method). Technical challenges of 

pilot projects in onshore and offshore fields have 

several important indications. Onshore fields are 

usually facing with problems such as application 

of old and commingled wells and poor reservoir 

understanding. Offshore trials are always more 

difficult than onshore fields. Offshore field are 

also facing with large well spacing and logistics 

problems in addition to those problems of 

onshore. These issues sometimes combined 

with economical aspects of the projects such 

as justifications for new well constructions. 

Additionally each special type of EOR method 

has some inherent risks such as its negative 

influences on field production (i.e. high water 

production when field produces at plateau). 

Problems like greenhouse gas emission and 

potential of combustion and explosion in thermal 

methods, unavailability of miscible gas injection 

or immiscibility of injected gas or presence of 

non-detected thief zones, faults, and barriers are 

good examples of issues in a pilot project. 

Most of technical issues are valid to be discussed 

in connection with economical analysis which can 

jeopardize the confidence of pilot budgeting. 

Additionally long lasting pilot projects with no 

return value is one of the financial challenges. 

Investors prefer to spend money on projects with 

less CAPEX, high NPV and low breakeven, with 

of course a clear budgeting map. However, pilot 

projects is performed to reduce risk and help 


Integrated Solutions from Pore to Process 

engineers to increase the level of confidence on 

the profiles and in some cases one cannot even 

expect to take any benefits from pilot, it is more 

the value of information captured from pilot. 

Managerial issues are a combination of policies, 

financing, lack of valid business models between 

operators and clients, oil cost fluctuations, 

uniqueness of these projects in each case and lack 

of experiences in this area. 

Summary and Remarks: 

EOR project implementation is a major 

investment in the life of an oil field which is 

associated with too many uncertainties. To reduce 

the uncertainties and/or improve the confidence 

on cost and benefit of an EOR project, pilot in a 

small portion of a reservoir can be planned. If the 

pilot is successful and results of pilot verify that the 

EOR project can still be interesting economically, 

it can be upscaled to a field-scale development. A 

pilot is successful if: 

• Identified risks are lowered and uncertainty 

ranges are narrowed. 

• Pilot results confirm and disprove expected 

results 

• Pilot could validate the measurement system 

utilized 

recommendations from pilot mislead decision 

makers. 

References 

www.slb.com/resources/publications/ 

industry_articles/oilfield_review/2010/ 

or2010win02_eor.aspx. 

Anderson, M., Application of risk analysis to 

enhanced recovery pilot testing decisions. 

Journal of Petroleum Technology, 1979. 

31(12): p. 1,525-1,530. 

Nazir, A., et al., Injection-above-parting-pressure 

waterflood pilot, Valhall field, Norway. SPE 

Reservoir Engineering, 1994. 9(01): p. 22-28. 

The three key elements to a successful pilot are 


To plan a pilot, a list of uncertainties need to be 

generated from our understanding about the 

reservoir behavior. The pilot is then designed with 

an appreciated monitoring program to reduce 

the identified uncertainties. Results from pilot 

are then evaluated to help operator to improve 

the quality of their models. 

It should also bear in mind that a bad pilot can 

lock reservoir potential and sometimes make the 

production from a field less economical, if wrong 

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34 OIL INNOVATORS International Journal MAR. 2018 35 

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Energy Development 

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Monitoring of 

IOR/EOR Projects 

Monitoring of reservoir production and injection has been recently considered as 

one of the main legs of IOR/EOR programs. This is being included as the vital step to 

increase the chance of success. It is normally accepted that the reservoir recovery 

factor decreases by increasing the reservoir complexity. However, by utilising 

comprehensive monitoring programs, reservoir complexity will be understood in 

detail that would result on keeping the recovery factor on the complex reservoirs 

as high as simple reservoirs. Without monitoring program, the fate of injected 

material is unknown and there is a risk of injected material (e.g., CO 2 

, Methane, 

Polymer, Modified water) to be migrated to another layer that would be ended 

up with no or minor impact on production. Another major risk of injection is early 

breakthrough of gas or water. To prevent this, variety of monitoring programs 

have been employed by international oil and gas companies such as 4D seismic, 

repeated production and petrophysical logs, chemical tracers, and etc. The main 

objective of these methods are to detect the saturation and pressure fronts, 

connectivity between reservoir geobodies and fault blocks, producing intervals 

and finally fluid flow and communication between different wells. Repeated logs 

would provide high resolution information about production intervals inside the 

Wells, especially for mature fields which present several challenges related to 

the changes in fluids saturation, connectivity of reservoir layers and fluid contact 

movement. Tracer technology has increasingly been used as one of the effective 

tools in the reservoir monitoring and surveillance. This technique is known as one 

of the enabling technologies that can be deployed to investigate reservoir flow 

performance, reservoir connectivity, residual oil saturation and reservoir properties 

that control displacement processes, particularly in IOR/EOR operations. Time- 

Lapse seismic or four Dimensional seismic (4D) affords the saturation and pressure 

front between the wells, in another word, this technique provide the subsurface 

image in 3 dimensional and through the time. By identifying the fluid flow and 

communication between different wells and different segments of a particular 

reservoir, 4D seismic would assist the reservoir management team to optimise their 

IOR/EOR projects. All of mentioned monitoring techniques offer some solutions 

from different point of view, thus, the major oil and gas companies are typically 

design a monitoring program that includes variety of monitoring techniques. 

Due to the fact that the cost and application of these techniques are different 

in different reservoirs, there is a need to design the most effective monitoring 

program to answer to the challenges of a particular field, and at the same time 

to be cost effective. In this chapter, a brief introduction supported by some case 

studies are being individually discussed for different monitoring programs. 

How Can 4D Seismic Assist 

to Monitor the IOR/EOR 

Projects? 



Management 


through Application of 

Chemical Tracer Technologies

How Can 4D Seismic Assist to 

Monitor the IOR/EOR Projects? 

- Background 

- What Does Seismic Data Offer to Us? 

- The Selected Case Studies 

- The Key Challanges 

Reza Falahat,Director of Subsurface Engineering SBU 


Monitoring of IOR/EOR projects 

is being considered necessary to 

guide and guarantee the success 

of these projects. In lack of a 

proper monitoring program, the 

fate of injected material would 

be unknown. There have recently 

been introduced variety of 

monitoring programs, however, 

4D seismic, due to its full and 

3 dimensional coverage of 

reservoir, is being considered as 

the main monitoring program. 


Background 

As it was introduced on opening part of this 

section, monitoring of IOR/EOR projects 

is being considered necessary to guide and 

guarantee the success of these projects. In lack of 

a proper monitoring program, the fate of injected 

material would be unknown with high risk of 

injected material (e.g., CO 2 

, Methane, Polymer, 

Modified water) to be migrated to another layer. 

There have recently been introduced variety of 

monitoring programs, however, 4D seismic, due 

to its full and 3 dimensional coverage of reservoir, 

is being considered as the main monitoring 

program. Utilising 3D and 4D seismic data, 

international oil and gas companies have improved 

the reservoir recovery factor in North Sea above 

30% and reaching at around 60% [1] . By measuring 

the water and gas fronts and pressure variation 

in the reservoir as well as by identifying bypassed 

oil and gas, it has been successfully used on most 

of IOR/EOR projects on the North Sea reservoirs 

to optimise IOR/EOR projects, well placement 

and production/injection plans. On the other 

hand, most of failed injection projects have been 

typically suffering from lack of comprehensive 

monitoring programs. 

What Does Seismic Data Offer to 

Us? 

Seismic data contains quantitative and valuable 

information that has widely been used 

during reservoir exploration, development, 

production and monitoring steps. Quantitative 

seismic interpretation such as rock physics, 

AVO modelling, inversion and geomechanics is 

normally ended up with extracting reservoir static 

parameters such as porosity, shale content and 

oil and gas saturation from the seismic data. 4D 

seismic, which is a series of repeated 3D seismic 

surveys over time, has been extensively used 

by oil and gas companies to monitor reservoir 

production and injection in time and space. The 

elastic and acoustic parameters of fluid and rock 

changes by production activities, and this affects 

the reflection coefficients at the top as well as at 

the base of reservoir. These changes are detected 

by amplitude changes in different angles, 

timeshift or even frequency-derived attributes 

(Figure 1). 4D seismic has the potential to provide 

information regarding fluid movements, pressure 

changes, reservoir compaction, barriers and 

compartments, fault transmissibility and general 

connectivity. 

These information assist to optimise IOR/ 

EOR projects in the filed scale, improve well 

performance and possibly increase a field’s 

economic life. Time lapse seismic applicability has 

been proven for monitoring of gas injection for the 

storage purposes, water injection and managing 

the gas coming out of solution. It has also been 

used in monitoring of heavy oil reservoirs, gas 

injection and gas reservoir production [3] . Figure 

1 shows repeated saturation logs on 1989, 1992, 

1993, 1994, 1995 and 1997 on Gullfaks field 

(North Sea). It also shows seismic data on 1985 

(before production) and 1999 after production 

and injection. Utilising Rock Physics analysis, top 

of oil bearing sandstone is represented by yellow 

colour on the seismic sections. As it can be seen 

from Figure 1, yellow colour signal disappears 

once it reaches at oil-water contact. OWC 

movement can be observed on both well logs 

and seismic data that matches with the animated 

figures on the right hand side. 

The Selected Case Studies 

In this brief article, there are presented a few 

successful examples from the literature. The 

first example (Figure 2) is from North Sea. Halfdan 

reservoir is a Carbonate (Chalk) oil reservoir that is 

under FAST (Fracture Aligned Sweep Technology) 

production method [1] . Horizontal wells produces 

for 6 months until it is converted to the water 

injection well. Water front is monitored by 4D 

seismic data. Water replaced by oil presents 

hardening signal (increase in acoustic impedance) 

on the 4D seismic maps that is shown by blue 

colour on Figure 2-a and b. A highlighted area 

is shown on d and e for better visualisations. As 

an example, the water front around the injector 

well (dashed blue line) is presented on 2005-1992 

maps (a and d). Water front movement towards 

production wells (green lines) can be detected on 

2012 on b and e maps. White colour represents unswept 

oil in these figures. Figure 2-c and f shows 

2012-2005 to understand the water movement 

over time in one map. Red colour signals on these 

maps represent the softening signal (decrease in 

Figure 1: Repeated saturation logs on 1989, 1992, 1993, 1994, 1995 and 1997 with seismic data before production 

(1985) and after production and injection (1999). Oil-Water contact movement can be observed by comparing 

two seismic sections that matches with the saturation logs over the time [2] . 

Figure 2: 4D seismic maps on 2005-1992, 2012-1992 and 2012-2005 on Halfdan oil field. The bottom figure shows 

the selected area in detail. Blue colour represents the hardening 4D seismic signal that is due to oil replacing by 

water. On the other hand, red colour signal represents the oil replacing by gas due to gas coming out of solution 

mainly on the northern parts in which pressure goes below bubble point pressure. Production and injection wells 

re shown by green and dashed blue lines [1] . 


acoustic impedance) due to gas. Pressure drops 

below bubble point pressure mainly on northern 

parts of reservoir and gas comes out of solution 

that can be clearly detected by red colour signals 

on these maps. 

The second example is from a North Sea turbidity 

reservoir that is going under gas (Methane) 

injection [4] . A channel on Figure 3 is selected for 

the gas injection. Injected gas volume is shown 

over time on figure 3-b, c and d on 1999, 2000 and 

2002 after 1, 2 and 4 years of methane injection 

into reservoir. As it can be seen on Figure 3-d, 

gas movement is controlled by channel boundary 

from the east and west, and by a fault from the 

north side of injected well. The southern faults 

are open, but suffering from low transmissibility 

that has made some delays on gas migration. 

Figure 3: a. Channel boundary mapped from 3D seismic. b, c and 

d. shows 4D seismic maps after 1, 2 and 4 years of gas injection, 

respectively. Gas migration path can be easily detected on these 

map [4] . 

The last example is from Canadian Carbonate Oil 

reservoir that is going under CO 2 

injection (after 

initial water injection program). As Figure 4 shows, 

CO 2 

signal around injected wells are detected by 

4D seismic map. Most of time-lapse anomalies are 

parallel to the orientation of horizontal and vertical 

injectors (NESW), which is the dominant fracture 

orientation. Seismic anomalies reveal that the CO 2 

has moved into both zones. In addition, Figure 4 

compares the 4D anomaly map with production 

engineering data: cumulative injection volume, 

hydrocarbon pore volume and CO 2 

recycle ratio. 

Higher injection volumes correspond impressively 

to strong 4D anomalies. 

The Key Challenges 

Although, international oil and gas companies 

has achieved successful results, majority 

of these projects have been focused on the 

clastic sandstone reservoirs, with few fractured 

carbonate (mainly Chalk) field trials in Norwegian 

Continental Shelf (i.e. Ekofisk and Valhall fields). 

Carbonate reservoirs and in particular, Iranian 

Carbonate reservoirs suffers from variety of 

complexities including high matrix velocity 

and density, different porosity types and etc. 

that prevents direct application of the current 

rock physics and reservoir geophysics and 

geomechanics models. These models have been 

shown deviation from the laboratory and well log 

based observations on the Carbonate reservoirs. 

However, the real examples around the world 

shows successful application of 4D seismic on 

the carbonate reservoirs, thus the necessity of 

a comprehensive and practical study is required 

to develop realistic rock physics models that can 

explain these real successful cases. 

Figure 4: 4D seismic monitoring of CO 2 

flood in a thin fractured 

carbonate reservoir, Weyburn, Canada [5] . The size and strength 

of 4D signal is proportional to the volume of injected gas using 

horizontal wells. 

References 

Calvert M. A., Hoover A. R., Vagg L. D., Ooi K. 

C. and Hirsch K. K., 2016, Halfdan 4D workflow 

and results leading to increased recovery, The 

Leading Edge. 

Amirov K.M., Tusupbekova E.K., Portnov V.S., 

Tursunbayeva A.K., Maussymbayeva A.D, 2012, 

4D SEISMIC, European Journal of Natural 

History 

Falahat R., Shams A. and MacBeth C., 2012. 

Adaptive scaling for an enhanced dynamic 

interpretation of 4D seismic data. Geophysical 

Prospecting 

Falahat R., Shams A. and MacBeth C., 2011, 

Towards quantitative evaluation of gas injection 

using time-lapse seismic data, Geophysical 

Prospecting 

Guoping Li, 2003, Time-Lapse (4D) Seismic 

Monitoring of Massive CO2 Flood at Weyburn 

Field, S. E. Saskatchewan, EnCana Corporation. 




Management 

- Background 

- Pulsed Neutron Logging (PNL) 

- Cased-hole Formation Resistivity (CHFR) 

Yaser Mirzaahmadian, Head of Geoscience Department 


Petrophysics plays a crucial role in reservoir 

monitoring and management. This is 

especially true for mature fields which 

present several challenges related to the 

changes in fluids saturation, connectivity of 

reservoir layers, fluid contact movement, and 

well productivity. A clear understanding of 

modeling purposes (i.e. methods to be used 

and uncertainties across all of the subsurface 

disciplines) is vital to ensure that reservoir 

properties are represented efficiently. 

This paper gives an overview of the role of 

petrophysics and the well logging tools in the 

long-term monitoring of reservoirs. 


Background 

Reservoir monitoring provides an understanding 

of well and reservoir performance to enable 

efficient management of production. Experts in 

oil companies use different methods and tools 

to gather the required data before and during 

the EOR/IOR projects to build and improve the 

production plan. Based on the objectives of 

reservoir monitoring plans, a combination of 

two or more methods and technologies may be 

employed to help maximizing production rate 

and boosting recovery. Each method has its 

advantages and disadvantages. Selecting the 

most appropriate reservoir monitoring method 

depends on various factors, such as consistency, 

cost, accuracy and installation procedures. Some 

methods are designed for specific applications, 

whereas others can be used for general monitoring 

purposes [1&2] . 

Among these means, Petrophysics plays a crucial 

role in reservoir monitoring and management. This 

is especially true for mature fields which present 

several challenges related to the changes in 

fluids saturation, connectivity of reservoir layers, 

fluid contact movement, and well productivity. 

A clear understanding of modeling purposes 

(i.e. methods to be used and uncertainties 

across all of the subsurface disciplines) is vital to 

ensure that reservoir properties are represented 

efficiently (i.e. relative permeability and capillary 

pressure). This paper gives an overview of the role 

of petrophysics and the well logging tools on the 

long-term monitoring of reservoirs. 

The acquisition of the petrophysical data are 

necessary for evaluating the reservoir rock 

properties (such as density, porosity, mineral 

identification and fluids saturation) and 

calculating the input parameters for building the 

static and dynamic model of the reservoir during 

the life cycle of a field. 

During the life of EOR/IOR projects, there are 

likely to be opportunities to collect additional 

data away from the injection and production 

wellbores. Running the well logging tools over a 

period of times in an injection and producing wells 

gives a series of valuable data about the reservoir 

properties (like the distribution of fluid 

saturations) which allows the monitoring and 

management team of EOR projects to optimize 

the production plan. Each logging tool has its own 

specification like depth of investigation (DOI), 

vertical resolution, well environmental 

requirements and adaptability of reservoir 

geological conditions. The pulsed neutron logging 

series (PNL), case-hole formation resistivity 

(CHFR), RMT Reservoir Monitor Tool, RST- 

Reservoir Saturation Tool are often used to 

predict the residual oil saturation. 

Figure 1: Different data see different scales 

Following gives a summary description of some 

logging tools which can be employed as a method 

to estimate the fluid distribution with respect to 

the displacing flood front location in the reservoir 

monitoring and related case studies. 

Pulsed Neutron Logging (PNL) 

PNL is used to identify the presence of 

hydrocarbons in cased holes and detect water 

saturation changes during production. PNL has 

two data acquisition types: 1) Neutron Capture 

Mode where the water salinity is known. 2) 

Inelastic mode (Carbon/Oxygen), where water 

salinity is unknown, or very low. 

Case study; Kinder Morgan EOR Project: 

The SACROC field is a mature Permian-age 

carbonate reservoir in West Texas with a complex 

fracture network of limestone and dolomite 

vugs. It was under waterflooding for many years 

before being switched to CO 2 

-type enhanced 

oil recovery project. Kinder Morgan needed to 

maximize recovery on a miscible CO 2 

EOR project. 

The Reservoir Monitor Tool 3-Detector (RMT- 

3D) pulsed-neutron tool was used for both new 

and existing wells to solve for porosity, water, oil, 

and CO 2 

saturations in the reservoir using three 

independent measurements (sigma, carbonoxygen, 

and SATG). The whole project including 

its logging program provided the necessary 

insight about what was occuring downhole to 

make decisions for the project moving forward. 

Kinder Morgan reduced cost and risk while also 

improving production and recovery by switching 

to the cased-hole RMT-3D pulsed-neutron logs 

for both new and exisitng wells in some areas. 

Compared to traditional openhole wireline logs, 

this tool can be deployed after the casing has 

been set and the rig moved off location,thus 

saving drilling-rig time and costs. Monitoring 

injection wells, dedicated monitor wells, and 

production wells over time have enabled Kinder 

Morgan to maximize the sweep efficiency of the 

CO 2 

EOR project by increaseing oil production and 

recovery [3] . 

The RMT-3D pulsed-neutron service combines 

SATG gas saturation with carbon-oxygen oil 

saturation to accurately measure 3-phase water, 

oil, and super-critical CO 2 

volumes. 

Cased-hole Formation Resistivity 

(CHFR) 

The CHFR tools are components of Analysis 

Behind Casing (ABC analysis), which provides a 

dataset of the minimum information required for 

basic formation evaluation behind casing, such 

as porosity and saturation. It gives deep-reading 

resistivity measurements behind conductive and 

non-conductive casings and the opportunity to 

compare changes of Rt from the original open 

hole (OH). Some of the important applications of 

this tool are: 

• Location of bypassed hydrocarbons 

• Monitoring of reservoir saturation 

• Monitoring of fluid contacts (GOC, OWC) 

Figure 2: Kinder Morgan EOR Project, 

pulsed-neutro tool. Track 1 – Lithology: 

Limestone, dolomite, clay, and porosity. 

Track 2 – Gas Saturation: Super-critical CO2 

saturation calculated using SATG from 

the RMT-3D tool. Track 3 – Oil Saturation: 

Oil saturation calculated using carbonoxygen 

from the RMT-3D tool. Track 4 – 

TripleSat Saturations: Combined CO2 and 

oil saturation. Track 5 – TripleSat Volumes: 

Combined CO2 and oil volumes [3] . 


These lead to improve production and increase 

reserves. The depth of investigation of the 

resistivity measurement is between 7 and 32 

ft (2 and 10 m), which is more than an order 

magnitude deeper than that of pulsed-neutron 

saturation measurements. The dynamic range 

of measurements also allows evaluations in 

reservoirs with low porosity and formation salinity 

[4] 

. 

Figure 4: The results of the CHFR log in the Bakers field. 

This log is from a well in a water-injection project demonstrating 

the value of CHRF technology in identifying bypassed 

oil. Abandonment earlier, the well produced 300 

BOPD after it was logged and perforated again [4] . 

Figure 5: The CHFR log shows an unlikely case in which 

the oil/water contact had moved down 12 ft. In most 

wells the water level moves up as the oil is produced. In 

this well, the waterflood swept oil to the well, indicating 

that the amount of oil was increasing. When the zone 

with swept oil was perforated, it produced 2.05 BOPD 

with no water [4] . 

Case Study; Bakers field 

The CHFR tool provides an excellent means of 

identifying bypassed hydrocarbon before the 

decision is made to abandon a well or field and 

had a significant impact on field economics. 

In Bakersfield, California, a well in a field with a 

water-injection program was abondoned when 

the water rate reached uneconomic levels at 

1600 B/D. Years later the well was reevaluated 

using the CHFR tool. As shown in Figure 3, the 

logs confirmed that the interval below X720 ft 

had water out and can see hydrocarbons in the 

depth interval between X680 and X700ft. 

After set a plug at X710ft, the perforation job 

was done in the interval between X680 and X697 

ft. Following the workover procedure, the well 

produced oil at 300B/D. Similar logs with the 

CHFR tool were run in the two other wells in this 

field. The result of this logging program proved 

very profitable for the operator because of the 

commercially significant volume of oil produced 

[4] 

. 

References 

Morris, C.W., Morris, F., Quinlan, T.M., Aswad, 

T.A., 2005. Reservoir monitoring with pulsed 

neutron capture logs. Paper presented at the 

SPE Europec/EAGE Annual Conference. 

Ulugbek Djuraeva, Shiferaw Regassa Jufara, 

Pandian Vasantb , A review on conceptual 

and practical oil and gas reservoir monitoring 

Methods, Journal of Petroleum Science and 

Engineering, Volume 152, April 2017,Pages 

586-601. 

www.halliburton.com, Halliburton Helps 

Increase Oil Production for Kinder Morgan EOR 

Project 

www.slb.com, CHFR-Slim 



through Application of Chemical 

Tracer Technologies 

- Background 

- Cost Savings by Applying 

Tracer Technology 

- Application of Tracer Test 

in Oil Reservoirs 

- Conclusion 

Tracer technology has 

increasingly been used in oil 

reservoirs over the last decades 

and has become one of the 

effective tools in the reservoir 

monitoring and surveillance 

toolbox. Tracer technology is 

now an important and costeffective 

tool that has high 

contribution to our better 

understanding of the reservoirs. 

Mahdi Abbasi, Reservoir Engineer 


Tracer is injected into an oil 

reservoir, in which the oil is 

present in layers of porous 

sandstone or limestone. 


Background 

Tracer technology has increasingly been used 

in oil reservoirs over the last decades and 

has become one of the effective tools in the 

reservoir monitoring and surveillance toolbox. 

Tracer technology is now an important and costeffective 

tool that has high contribution to our 

better understanding of the reservoirs. 

Tracer is injected into an oil reservoir, in which 

the oil is present in layers of porous sandstone 

or limestone. The tracers flow together with the 

water or the gas that is being injected in order 

to push out oil from the reservoir layers. Water 

samples are then taken from producer(s) to be 

analyzed for the amount of tracers present in the 

samples. From this, valuable information about 

the reservoir and particularly where oil is trapped 

in the reservoir can be obtained. Such information 

makes it easier to optimize the drainage strategy 

of the reservoirs and to maximize production. 

This technique is known as one of the enabling 

technologies that can be deployed to investigate 

reservoir flow performance, reservoir connectivity, 

residual oil saturation and reservoir properties 

that control displacement processes, particularly 

in improved oil recovery (IOR) and enhanced oil 

recovery (EOR) operations. 

Tracer is conducted either as inter-well tests (in 

which tracer is injected in one or more injectors and 

produced from one or more producers) or singlewell 

tests (i.e. tracer is injected in a well and backproduced 

from the same well). Tracer can also 

be used as part of well completion compartment 

during flooding and/or natural depletion process 

to identify zonal inflow contribution and detect 

the location of water breakthrough. 

Cost Savings by Applying Tracer 

Technology 

Although it is difficult to perform accurate 

cost/benefit analyses for tracer technology, 

there is one specific example of an oil company 

being able to document a saving of more than 

15 million dollars by preventing the drilling 

of unproductive wells. At an oil reservoir in 

Columbia, BP used tracers to identify the location 

of infill wells. Without the information obtained 

about blockages in the reservoir, the company 

would have drilled two useless wells in order to 

produce oil. Two wells would have represented 

a cost of 10-15 million dollars whereas the tracer 

operation cost amounted to 150 thousand 

dollars, or about one percent of the cost of two 

wells. It is even more costly to drill wells offshore, 

so the potential savings there are even greater. 

A typical cost estimate for a single offshore well 

is about 25 million dollars. Tracers are currently 

used in most fields on the Norwegian continental 

shelf, and they have had important contributions 

to optimized production. This is for sure one of 

the very important steps oil companies have 

been taking offshore and onshore to better 

characterize their field and eventually improve oil 

recovery by taking optimum drainage strategies. 

The topics which are selected for a closer 

description in this article are as follow: 

• Tracers in reservoir evaluation (well-to-well 

flow studies for water and gas flooding) 

• Tracers for the determination of residual oil 

saturation (partitioning tracers in single well 

or in well-to-well experiments) 

• Tracers during drilling and completion of a well 

(determination of the most water and gas 

producing zones or segments) 

Application of Tracer Test in Oil 

Reservoirs 

Tracers in reservoir evaluation 

(well-to-well flow studies for water and 

gas flooding) 

The basic concept of Inter-Well Tracer Test 

(IWTT) is to inject a unique and stable chemical 

tracer that does not interact with the reservoir 

rock or oil into an injection well and monitor 

produced water from surrounding production 

wells [1] . A tracer should impart properties that 

are distinguishable from the transporting fluid, 

such as increased electrical conductivity [2] , above 

background radioactive emission [2] , characteristic 

magnetic response [3] , among others. However, 

tracers, by definition, should not disturb the 

hydrodynamics and simultaneously follow the 

flow path without delay. Tracer tests are used 

for water and oil reservoirs to determine inter 

well reservoir characteristics, such as inter-well 

connectivity, layer structure and channeling, 

permeability heterogeneities, barrier to flow, 

rate of movement of injected fluid, and sweep 

efficiency [4-6] . When a small volume of tracer 

fluid (e.g. an easily detectable chemical at known 

concentration) is injected and moves towards 

the producing well, it experiences different 

characteristics of the reservoir and therefore, the 

tracer response at the production well will reflect 

these characteristics. 

Inter-well Tracer Test (IWTT) can give information 

about: 

• Reservoir barriers for flow. These barriers are 

identified by loss of tracer recovery or even a 

change in the time of tracer recovery. 

• Identify limited gas saturated intervals that 

allow preferential water movement. 

• Finding out the contribution of injected water 

in total water production from producers. 

• Estimate the reservoir volume or sweep that 

will result from EOR. 

• Observe time for breakthrough to evaluate 

simulation models 

• Document communication between injector 

wells that may result in sweep loss. 

• Learn the residence time of the different water 

flow paths. 

• Document the tracer recovery that indicates 

injected fluid distribution. 

• Receive information about fingering between 

injector and producer from early tracer arrival. 

Figure 1: Connectivity from tracer test 

A tracer elution curve can be used to evaluate the 

heterogeneity of a formation. The bell-shaped 

elution curve is an indication of a perfectly 

homogeneous formation. On the other hand, 

if tracer concentration in the collected water 

samples approaches a maximum value and 

decreases to zero over a short period of time after 

the injection day, it indicates the existence of a 

high permeability channel between the injection 

and the production well [7] : 

• Heterogeneous flow yields curve far from 

diagonal 

• Homogeneous flow yields close to diagonal 

curve 

• Area between diagonal and curve gives 

Lorentz coefficient 

Enhanced oil recovery (EOR) is being used more 

and more as the need for making the best use 

of existing resources is recognized. Whenever 


eservoir engineers consider an EOR project, 

questions are raised concerning the detailed 

knowledge of the reservoir in which EOR is being 

considered. Such questions are often asked (and 

partially answered) when water flooding has 

occurred, but the far greater cost of any EOR 

process compared with water flooding puts a 

greater emphasis on the need for a detailed 

description of the reservoir to be exploited [8] . 

Figure 2: Characterize the heterogeneity 

Tracers for the determination of 

residual oil saturation (partitioning 

tracers in single well or in well-to-well 

experiments) 

Measurement of remaining oil saturation 

in a near well region, using a single-well 

chemical tracer test (SWCTT) is commonly used 

in the oil industry. This method exploits the time 

lag of back-produced ester vs. hydrolyzed alcohol. 

Partitioning inter-well tracer tests (PITTs), which 

can be used to assess inter-well oil saturation, 

are frequently used to investigate the presence 

and remediation of non-aqueous phase liquids 

(NAPLs) in aquifers. However PITTs are rare in the 

oil industry, with a few notable exceptions dating 

back to the 1990’s [9]. 

Single-well chemical tracer (SWCTT) 

The single-well chemical tracer (SWCTT) test is an 

in-situ method for measuring fluid saturations in 

reservoirs. The most common use is the assessment 

of residual oil saturation (Sor) after water flood 

operation. When monitoring displacement of oil 

from a reservoir, it is important to benchmark 

the amount that remains following secondary 

recovery. SWCTT are non-destructive and can be 

run in either sandstone or carbonate reservoirs 

over widely varying formation characteristics. The 

test is based on injection of a partitioning tracer 

(i.e. an ester) into the reservoir, where part of it 

partitions in the remaining oil phase and the other 

part undergoes a hydrolysis reaction to produce 

a non partitioning tracer. This hydrolysis process 

takes place over a period of few days while the 

well is shut-in. 

Reaction for ethyl acetate is: 

CH 3 

COOCH 2 

CH 3 

+ H 2 

O CH 3 

CH 2 

OH + CH 3 

COOH 

i.e. 

Ester + Water Alcohol + Acid 

The well is then back-produced and wellbore 

samples are analyzed for tracer returns. The 

analysis of the flowed-back samples are plotted 

as in Figure 3, where concentration vs. produced 

volume is generated. 

Figure 3: Typical tracer production curves used for interpretation 

from a SWCTT 

From the differences in arrival times (maximum 

of the peaks) and the partitioning coefficient 

value, one can obtain the remaining or residual 

oil saturation (ROS or Sor). The partitioning 

coefficient is a physical property that relates 

tracer concentration in oil and water phases at 

equilibrium as shown below: 

K d 

=C o 

/C w 

Where, C o 

and C w 

are tracer concentrations in oil 

and water phase respectively. 

From chromatographic theory, the retardation 

factor (1+ β) which is equivalent to the peaks ratio 

Q a 

/Q b 

(Figure 3) as defined as follow: 

Q 

Q 

kS 

= (1 + β ) = 

(1 − S ) 

a d or 

Rearranging this formula gives: 

b 

Commonly utilized esters in SWCTTs are propyl 

format and ethyl acetate. 

β 

Sor 

= 

β + k 

The SWCTT can also be used to evaluate the 

effectiveness of EOR processes to mobilize 

residual oil (S or 

) or “trapped oil”. First, SWCTT 

is used to determine Sor to water flood. Then 

the EOR fluid is injected for a certain volume 

followed by water in the test well/interval. Lastly, 

the SWCTT is carried out again for the second 

time to determine Sor to the EOR process. The 

results of the test will give direct indications of 

the effectiveness of the EOR process to mobilize 

residual oil [10] . 

d 

or 

Figure 4: The partitioning inter-well tracer test (PITT) 

The important features of SWCTT are summarized 

below [11] : 

• The Sor measurement is made in situ in the 

water flooded layers of the target formation. 

The tracers can go only where the injected 

water goes. 

• Compared to coring or logging method results, 

the S or 

results are from a relatively large 

reservoir volume. 

• The S or 

measurement is carried out on an 

existing well and usually in an existing 

completion, which can be perforated or open 

hole. 

• Because the Sor measured actually is the 

volume fraction of oil in the pore space, the 

measurement is independent of porosity. 

Partitioning inter-well tracer test (PITT) 

The partitioning inter-well tracer test (PITT) is 

a non-intrusive low-cost test that can provide 

measurement of oil saturation in the region 

between injectors and producers in an oilfield. 

The test is run during normal operation of both 

injector and producer and thus neither cause loss 

of production nor halt of injection. 

Although the comparison with a SWCTT or 

saturation obtained from core floods are indeed 

useful and required as an independent verification 

of the PITT methodology, it should be noted that 


the PITT is an inter-well test. PITTs are capable of 

assessing oil saturation in the inter-well region, 

whereas both core samples and the single well 

tracer test estimate saturation in the near-well 

region, as illustrated in Figure. 5. The PITT can 

thus be expected to be a better representation 

of oil saturations on a field-wide scale. It is 

important to highlight that a PITT represents the 

average saturation in an inter-well region and may 

therefore be different from spot measurements 

obtained through sponge cores and SWCTTs. 

Figure 5: Comparison of single-well chemical and partitioning 

inter-well 

Tracers during drilling, completion and 

treatment of a well 

Tracers’ advantages are not only limited for 

reservoir characterization application, but 

also valid for further usages to improve the 

operations for drilling and well construction. 

Tracers technologies improve efficiencies of 

these operations in reducing losses and damages 

specially those damages are mostly occurring of 

drilling fluid losses. Additionally with application 

on controlling cementation, this technology is a 

potential assistant for improving well integrity. 

Tracer technology has recently been developed 

to be utilized in completion compartment to help 

operators identifying the most producing water 

zones. In brief, tracer is widely used in drilling and 

completion to: 

• To measure drilling fluid invasion in wells [12] 

• To identify the location of cementing level 

behind casing [2] 

• To find out the location of casing leaks and 

channels behind casing [12] 

• Stimulation and control treatment [13] 

• Treatment of fractures [12] 

Case Study I: 

SWCTT for verifying the effect of low 

salinity water flooding in Snorre Field in 

Norwegian Continental Shelf 

The Snorre is a sandstone field located in the 

Norwegian Continental Shelf. Snorre is a system 

of rotated fault blocks with beds dipping 4-10° 

towards North-West (Figure 6). The reservoir 

sections consist of fluvial deposits and reservoir 

units contain thin sand layers with alternating 

shale in a complex fault pattern. The average 

reservoir pressure in the central fault block 

(CFB) is 300 bar and the reservoir temperature is 

900°C [14] . 

Low-salinity (lowsal) water flooding has been 

evaluated at the Snorre field. Core flooding 

experiments and a single-well chemical tracertest 

(SWCTT) field pilot have been performed to 

measure the remaining oil saturation after sea 

water flooding and after lowsal flooding to verify 

the effectiveness of low-salinity water. 

An SWCTT is carried out as a push-andpull 

operation in a producer. It is based on 

chromatographic principles in terms of which a 

reactive partitioning tracer [ethyl acetate (EtAc)] 

is injected into the formation. Parts of the injected 

partitioning tracer dissolve in the remaining oil, 

and parts dissolve in water. Local equilibrium 

is established rapidly and continuously as the 

partitioning tracer flows through the formation. 

When the tracer is displaced to a target depth 

from the wellbore, the well is shut in. A fraction 

of the reactive partitioning tracer present in 

the water phase hydrolyzes and generates a 

product tracer [ethanol (EtOH)], which is water 

soluble only. Upon startup of back production, 

the product tracer follows the water passively, 

whereas the remaining unreacted partitioning 

tracer is delayed. The delay of the partitioning 

tracer depends on the oil saturation in place. 

The SWCTT field pilot was carried out in the Upper 

Statfjord formation. The average oil saturations 

after seawater injection, after low-salinity 

seawater injection, and after a new seawater 

injection were determined; no significant change 

Figure 6: Location of Snorre field in the North Sea [15] 

in the remaining oil saturation was observed 

after flooding low-salinity water, which was in a 

good agreement with SCAL measurements in the 

laboratory. 

Case Study II: 

Partitioning inter-well tracer test 

(PITT)- Lagrave field [9] 

The tracers were tested in a field pilot in the Totaloperated 

Lagrave field located in the South-West 

of France in 2011 to determine oil saturation 

through PITTs from the difference in retention 

times for the partitioning and water tracers, in 

addition to the oil/water partition coefficient. 

Lagrave is a relatively small carbonate field with 

fast injector-producer communications, which 

allows relatively low cost field qualification of 

partitioning tracers. Six partitioning tracers were 

injected in February 2011, together with a wellknown 

non-partitioning tracer (2-FBA), Figure 7. 

The pilot area encloses one injector and three 

producers. Frequent sampling (2-3 times per 

week) yielded concise tracer response curves 

for estimation of remaining oil saturation. The 

response curves from the partitioning tracers 

were compared to the non-partitioning tracer 

to estimate saturations. The results are also 

compared with other reservoir data. 

Lagrave is an onshore field located in the South- 

West of France at approximately 25 km northeast 

from Pau. The Lagrave field was discovered 

by Total in 1983 and put on stream in November 

1984. The field is composed of a limestone 

reservoir (Upper Cretaceous) corresponding 

to a carbonate environment. The reservoir is 

divided into four zones based on geology and 

petrophysical properties. The producers LAV-1 

and LAV-2 are both completed in zones A, A/B and 

B, whereas the producer LAV-6 and the injector 

LAV-7 are both completed in zones A, A/B, B and 


C. More information about the reservoir is as 

follow: 

• Carbonate field with large water production 

~95% watercut 

• Short well distances 

• Water cycled 

• Residual saturation also known from cores to 

be about 25% 

In the Lagrave case the six new tracers yielded 

a saturation of 24 +/- 1 %, based on retention 

times, which corresponds very well to saturation 

measurements on core samples. 

Figure 7: The pilot area in the Lagrave field 

Figure 8: Research status prior to the Lagrave pilot: 6 

Partitioning tracers qualified and ready for pilot field 

experiments 

Conclusion from Lagrave pilot: 

• Six tracers have been qualified in laboratory 

and field test. 

• Field pilot confirms the applicability of the 

tracers 

• Partitioning tracers can be used to estimate oil 

saturation in the inter well region 

Figure 9: Saturation from PITT in Lagrave 

Conclusion 

Taking advantages of tracer technology, it could 

be categorized in three sub division: tracer 

applications in well construction, piloting and full 

field monitoring of EOR projects. Tracer is one 

of the most cost-saving and effective techniques 

enabling to increase confidence on operations 

which are under performing. Generally speaking, 

tracers are usable in monitoring most fluid 

conduits which are necessary to be controlled. 

Tracers are designed to be used during the entire 

life cycle of a reservoir from natural depletion 

to IOR and EOR where tracers can be added into 

injected fluids. Piloting any types of EOR methods, 

tracers are providing valuable information on 

well connectivity and describing the dynamics of 

complex formations, including fractures, faults 

and channels, which can be resulted in a better 

or optimized drainage strategy from a reservoir 

leading to better sweep efficiency. 

Tracer has also been widely used by several 

operators to measure residual oil saturation in 

secondary production (i.e. water flooding) as 

well as tertiary production (i.e. low salinity water 

flooding and surfactant), and results have helped 

companies to make a better decision for the 

future of the EOR projects. 

References 

www.chemicalfloodingtechnologies.com/ 

products-services/inter-well-tracer-test. 

Zemel, B., Tracers in the oil field. Vol. 43. 1995: 

Elsevier. 

Kutsovsky, Y., et al., Dispersion of paramagnetic 

tracers in bead packs by T1 mapping: 

experiments and simulations. Magnetic 

resonance imaging, 1996. 14(7-8): p. 833-839. 

Al-Dolaimi, A., et al. Evaluating Tracer Response 

of Waterflood Five-Spot Pilot: Dukhan Field, 

Qatar. in Middle East Oil Show. 1989. Society of 


Rogde, S. Interpretation of Radioactive 

tracer observations in the Gullfaks field. in 

International Energy Agency Symposium on 

Reservoir Engineering, Paris, France. 1990. 

Skilbrei, O., L. Hallenbeck, and J. Sylte. 

Comparison and analysis of radioactive tracer 

injection response with chemical water analysis 

into the Ekofisk formation pilot waterflood. 

in SPE Annual Technical Conference and 

Exhibition. 1990. Society of Petroleum 

Engineers. 

Asadi, M. and G.M. Shook. Application of 

chemical tracers in IOR: a case history. in North 

Africa Technical Conference and Exhibition. 

2010. Society of Petroleum Engineers. 

Brigham, W.E. and M. Abbaszadeh-Dehghani, 

Tracer testing for reservoir description. Journal 

of petroleum technology, 1987. 39(05): p. 519- 

527. 

Viig, S.O., et al. Application of a new class of 

chemical tracers to measure oil saturation 

in partitioning interwell tracer tests. in SPE 

International Symposium on Oilfield Chemistry. 

2013. Society of Petroleum Engineers. 

www.chemicalfloodingtechnologies.com/ 

products-services/single-well-tracer-test. 

Tomich, J. F., Dalton Jr, R. L., Deans, H. A., & 

Shallenberger, L. K. (1973). Single-well tracer 

method to measure residual oil saturation. 

Journal of Petroleum Technology, 25(02), 211- 

218. 

Cooke Jr, C. E. (1971). Method of determining 

residual oil saturation in reservoirs. us Patent, 

3. 

Goswick, R.A. and J.L. LaRue. Utilizing oil 

soluble tracers to understand stimulation 

efficiency along the lateral. in SPE Annual 

Technical Conference and Exhibition. 2014. 

Society of Petroleum Engineers. 

Huseby, O.K., et al., Improved understanding 

of reservoir fluid dynamics in the North Sea 

Snorre field by combining tracers, 4D seismic, 

and production data. SPE Reservoir Evaluation 

& Engineering, 2008. 11(04): p. 768-777. 

Chatzichristos, C., et al. Application of 

partitioning tracers for remaining oil saturation 

estimation: an experimental and numerical 

study. in SPE/DOE Improved Oil Recovery 

Symposium. 2000. Society of Petroleum 

Engineers. 


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Increased Oil Recovery 

and Its Relation to the 

Surface Facilities; 

A Step-by-Step Approach 

- Background 

- Required Data Gathering 

- Screening Potential / Possible Modifications 

- Evaluation and Decision Making 

Mohammad Fouladi, Surface Upstream Director 


The issue of increasing 

production of oil from 

the producing fields has 

recently become a very 

attractive topic in Iran. This 

can be achieved through the 

available technologies both 

without changing drainage 

strategy of the reservoir and 

by changing the drainage 

strategy in the field (by 

employing new wells or new 

fluids to be injected into 

the reservoirs as an EOR 

fluid). The generic term of 

Enhanced/Increased Oil 

Recovery in the context of 

this document addresses any 

technologies through which 

increased oil recovery can be 

extracted from the fields. 


Background 

The issue of increasing production of oil from 

the producing fields has recently become a 

very attractive topic in Iran. This can be achieved 

through the available technologies both without 

changing drainage strategy of the reservoir (i.e. 

through minor modifications in the well and/or 

facilities) and by changing the drainage strategy 

in the field (by employing new wells or new 

fluids to be injected into the reservoirs as an EOR 

fluid). The generic term of Enhanced/Increased 

Oil Recovery in the context of this document 

addresses any technologies through which 

increased oil recovery can be extracted from the 

fields. 

Time-line of an EOR project (in which drainage 

strategy of reservoir is changed), which usually 

consists of field/reservoir selection, process 

selection, geological studies, design parameters, 

pilot testing and field implementation, can be 

up to 10 years before we observe field response. 

This requires great effort, time and focus of 

an organized and integrated team (combined 

surface and subsurface disciplines) and usually 

with huge investment. The following are major 

characteristics of EOR applications: 

• The projects usually are of a large scope and 

involve usage of infrastructure. They require 

a big investment upfront and have relatively 

long payback periods. 

• It takes a while to implement them. 

• For each of the fields – a specific technology is 

used 

• The average cost is 20-25 $/Bbl 

• After implementation production response 

does not occur immediately 

In order to be able to increase oil recovery within 

a relatively shorter period of time, it is believe 

that it is always worth looking into advanced 

technologies and best practices from which more 

oil can be extracted within much shorter time 

and by less operational investment and at no/ 

negligible CAPEX (and of course without changing 

the drainage strategy of the reservoir). There 

are some ways to increase oil recovery before 

deploying EOR. 

• Well integrity improvement (such as water, and 

shut off) 

• Organic and in-organic scale removal by 

injecting solvent 

• Acid clean up and potentially fracturing 

• Optimization of artificial lift design and 

injection 

• Minor modifications in the surface facilities 

Thus, increased oil recovery methods can be 

categorized in two groups; 

Fast response increased oil recovery 

Improvement plan for modifications in the 

existing well and facilities (i.e. almost with no 

or negligible CAPEX). A very fast response on oil 

recovery is expected through this plan. 

Revisit of field development plan 

Through screening EOR techniques and/or 

optimizing the ongoing plan. Infill drilling can 

be discussed in the first group, if its potential is 

not linked to any additional energy to be given to 

the reservoir, otherwise it should be discussed in 

this category. 

This article focuses on the fast response increased 

oil recovery step by step approach which can be 

employed in any assets. 

Required Data Gathering 

To propose a solution for a producing field, 

first of all, the current situation of the field, 

processing plant and exiting bottlenecks and 

boundaries have to be identified. Data expected 

to be gathered during this phase include, but not 

limited to: 

• Production history from wells 

• Identifications of any well integrity issues (i.e. 

high water-cut, high gas-cut) 

• Design basis for the surface facilities, pipelines 

and production wells 

• Identification of the elements critical to 

facilities and well design 

• Identification of any further (lab) tests required 

to assure performance of processing facilities 

• Mean failure of the processing facilities 

throughout the life time of its production 

• Variation in emulsion tendency 

• Propensity for foaming 

• Sand production 

• Salt / corrosion issues 

• Identification of the currently installed chemical 

treatment plans (wax, scale, hydrogen 

sulphide, hydrates, asphaltenes, corrosion) 

• PVT Data 

• Fluid characterization data (crude assay) 

• Compatibility tests 

• Performed well testing results 

• Performed artificial lift optimization studies 

• History of any kind of solid precipitation and 

blockages throughout the production life time 

(i.e. organic and in organic precipitations) 

• History of any unplanned shutdowns and 

causes (both in well and field level) 

• Logistic data (means of produced oil and gas 

transport) 

• Environmental data 

• Emission requirements/philosophy based on 

minimum emission policy or No flaring / no 

venting policy 

The data must be evaluated within a 

multidisciplinary team with an integrated 

approach where there is an understanding and 

appreciation of the potential issues associated 

with aspects such as flowing wellhead pressure 

on productivity, gathering network pressure 

drop, artificial lift methods, water injection and 

gas injection for reservoir pressure maintenance 

and plateau production periods. 

The information gathered and analyzed during 

this phase is essential for the next phases and 

should be treated as the basis and back bone of 

the project. 

Main objectives of this phase are (but not limited 

to) the following; 

• Develop early common understanding of 

available data and information 

• Map potential problems and bottlenecks from 

reservoir to the production (including well 

issues) 

• Ensure that project objectives are fully 

understood within team members 

• Describe and establish the relevancy of the 

gathered information and challenge the 

uncertainties of the gathered data 

• Highlight any missing information 

Screening Potential / Possible 

Modifications 

In this phase, based on the data gathered, short 

term and low CAPEX solutions can be proposed 

to enhance the production and possibly reduce 

OPEX. The modifications can be split in two 

categories. The activities associated with each 

category include, but not limited to; 

I. Category A 

Surface modifications that are independent of 

the subsurface studies, such as; 

• Acid/chemicals injection to remove the solid 

depositions in processing facilities 

• Investigating the possibility of employing 

fracturing operation to improve well 

productivity 

• Produced water recycle to first stage 

separator to reduce the Asphaltene and 

emulsion issues 

• Chemical injection to enhance water in oil 


and oil in water separation in the processing 

facilities (e.g. Demulsifier for oil treatment 

trains and Reverse Demulsifier for the 

water treatment trains). 

• Flow assurance study of the transfer 

pipelines to obtain operating envelope of 

the pipelines 

• Flow improver injection into the transfer 

pipelines 

• Installing new internals in the oil separator 

trains to increase the nominal capacity of 

the separation train (e.g. Calming baffle to 

create a laminar flow in the separators, VIEC 

to be able to coalesce more water droplets 

before entering the desalting unit). 

• Installing new devices upstream the 

produced water treatment train to enhance 

oil in water separation (e.g. Mare’s tail). 

• Heat integration possibilities within the 

processing facilities 

II. Category B 

Surface modifications that are linked to 

subsurface studies 

• Chemicals injection to remove the solid 

depositions in the wellbore (e.g. scale, 

Asphaltene inhibitor in the wellbore) 

• Usage of newly developed chemicals to 

selectively plug the formations from which 

only water and/or gas is produced 

• Injection of chemicals/gel to resolve well 

integrity issues (i.e. casing leakage) 

• Possibility to reduce the associated gas 

compression and production separator 

pressure to decrease the back pressure on 

the wells 

• Possibility of changing the artificial lift 

method from gas lift to Electric Submersible 

Pump (ESP) 

• Adequacy of power generation and 

possibility of installing VSD’s, if ESP is 

proven to be a proper artificial lift method 

Artificial lift optimization 

At the end of this phase all the technically viable 

scenarios will be identified. The identified 

scenarios’ will pass to the next step where they 

will be compared in terms of economic aspects. 

Evaluation and Decision Making 

In this phase, all the possible identified 

modifications must be studied thoroughly. The 

approach for the identified set of modifications in 

category A and B will of course be different. 

I. Category A 

The modifications will be studied with a focus 

on reducing downtime and OPEX, increasing 

throughput and thereby increasing revenues. 

II. Category B 

The modifications in this category are more 

cost intensive as they are coupled with 

improvements in the production wells. 

Workflow for this category of changes 

are somewhat different than category A. 

It is important that the sub-surface team 

understands where breakpoints are for the 

surface facilities. For example where a small 

decrease in throughput will need significant 

investing by adding a new separation or 

compression train. Furthermore, the artificial 

lift optimization should be developed in a close 

collaboration with surface team, as the overall 

costs of various strategies need to be offset 

against the recovery achieved. 

The techno-economical aspects of the studied 

alternatives must then be discussed and the 

economic gains as a result of the modifications 

are suggested to be evaluated by comparing 

the CAPEX and added revenues with the help 

of an agreed economic model. The acceptable 

economic criteria (e.g. discount rate, IRR and 

NPV) can vary from one company to another, 

which needs to be known beforehand. As a result 

of the assessments performed, the modifications 

should be ranked. Then based on the ranking 

and operator priorities, the most feasible and 

cost effective solution can be chosen for further 

studies in basic and detail engineering phases. 

The flowchart overleaf describes the step-by-step 

approach. 


SOUTH PARS GAS FIELD DEVELOPMENT 

(ON-SHORE GAS PROCESSING FACILITIES) 

NARGAN 

211, TALEGHANI AVENUE, TEHRAN 15989 17431, IRAN 

Tel: (+9821) 8891 4926-30 Fax: (+9821) 8880 9839 

info@nargan.com 



Optimized Solutions 

thorough Integration 

of Subsurface and 

Surface Engineering 

A Case Study of Nasr Platform 

Iranian Offshore Oil Company (IOOC) 

- Background 

- Conceptual Study Framework 

- Base Case Results 

- Remedy Solutions 

- Conclusion and Suggestions 

Sheila Jahanlou, Principal Process Engineer 

Nargan Co. 

Improving the production 

capacity in the upstream sector 

can be achieved by focusing on 

removing production obstacles 

from the reservoir to the well 

and up to topside facilities to 

the production units. While 

EOR techniques applied on the 

sub-surface are long term with 

higher impacts, also well therapy 

and surface modifications 

may have considerable results 

with lower costs. In Nargan, 

our philosophy is to look into 

production optimization in an 

integrated view. 


Background 

Improving the production capacity in the upstream 

sector can be achieved by focusing on removing 

production obstacles from the reservoir to the 

well and up to topside facilities to the production 

units. While EOR techniques applied on the subsurface 

are long term with higher impacts, also 

well therapy and surface modifications may have 

considerable results with lower costs. 

In Nargan, our philosophy is to look into production 

optimization in an integrated view. Focusing on 

one aspect and missing the other aspects leads 

into sub-optimum solutions while integration 

leads into lowered costs and higher results. Also in 

some cases at which, applying reservoir therapies 

are restricted due to financial limitations or 

technical reasons, still the production can be 

improved by looking into production obstacles on 

the transfer pipelines and surface facilities. 

In this case, a conceptual study delivered by 

Nargan which has led into developing a practical 

solution to remove the production obstacle in one 

of the offshore fields of Iran is presented. To do 

the study, we used integrated subsea and surface 

dynamic modeling and applied engineering 

solutions to see the results and find the optimum 

solution. The project has been done with intense 

allocation of resources in two months with 1700 

engineering man-hours. The maximum estimated 

cost of implementing the solution including 

engineering, procurement and construction is 5 

MUSD while it adds up to 15 MMSCFD of sweet 

gas to the production of the platform. 

Sirri island located about 72 km Iranian coastal 

line to the south of Bander-Lengeh, i.e. 40 km to 

the west of Abu-Musa island, is one of the main 

production locations in Iran. The five oil fields of 

Civand, Dena, Alvand, Esfand and Ilam are located 

25 to 33 km of Sirri island south of Iran. The oil 

and gas recovered from the fields are transferred 

to Nasr and Ilam platforms for processing to feed 

two petroleum separation plants in Sirri island. All 

the seven pipelines from the satellite platforms 

are gathered in Nasr platform on which Iranian 

Offshore Oil Company (IOOC) is intending to install 

a compressor which has already been engineered 

and purchased. Observation from the flow proves 

that the associated gas is separated from the oil 

and slug flow is formed in the pipelines leading to 

high fluctuation of gas on the platform in the range 

of 5 MMCFD to 20 MMSCFD. The associated gas is 

a sweet gas of high quality which is now burned 

and IOOC is intending to install a compressor on 

the platform to deliver the gas to NGL unit in Sirri 

island. This shall increase the production while 

it also leads into elimination of the flare on the 

platform. It was the mission of Nargan to help 

the client understand if the current available 

compressor can operate under this situation and 

if not, what remedy solutions and modifications 

can be applied to make it possible to deliver the 

gas to the NGL unit. 

Conceptual Study Framework 

As the pressure has been dropped in the 

reservoir, now the production is delivered 

using ESP pumps. Furthermore, due to low 

production flow rate the current pipelines are 

now oversized with respect to current flow. This 

leads into separation of associated gas in the riser 

pipelines and formation of gas pockets. Thus the 

uniform one phase transforms into two phase 

flow which is sluggish. Other factors that might 

be added to this main cause are low flow gas 

(liquid to gas ratio is high) and flow regime profile 

which finally leads into slug formation. 

The sluggish flow of the 7 pipelines from satellite 

platforms then gather in one manifold on the 

Nasr platform and transfers into separators. The 

inlet separator has been transformed from three 

Figure 1: Slug Formation 

phase to two phase (by removing the baffle plate) 

in order to handle the liquid flow fluctuation and 

high peaks of liquid flow rate . Due to liquid flow 

fluctuations, the gas flow fluctuates accordingly. 

Currently the gas is totally flared. Another 

concern is about suitability of compressor design 

with current situation. Specially the total flow of 

the gas which seems to be much lower or much 

higher than the flow amount interval for which 

the compressor is designed and fabricated. The 

conceptual study is done through reviewing the 

base case conditions to assure that he compressor 

cannot function under these fluctuations and 

if dysfunction of compressor is proved then the 

remedy solutions should be developed. 

In Nargan, our philosophy is to look into production 

optimization in an integrated view. Focusing on one aspect and 

missing the other aspects leads into sub-optimum solutions 

while integration leads into lowered costs and higher results. 

76 OIL INNOVATORS International Journal MAR. 2018 77 

“ 

“

Base Case Results 

To calculate the gas flow fluctuations, all the 

pipelines from the satellites to Nasr platform 

were modelled in OLGA, using available data. 

Next figure shows a snapshot of the constructed 

model. The next figure shows the oil and gas flow 

fluctuations based on the production figures as 

given. 

To see the behaviour of the compressor, the 

topside facilities were modelled using HYSYS 

Figure 3: Olga Model of Fluctuations 

Figure 2: Problem Identification 

Dynamic which was integrated into Olga model 

to input the fluctuation predicated in the subsea 

model to the surface model. The following shows 

the behaviour of the system in the first 6 minutes 

after start-up. 

As it is seen, the compressor functions with low 

alterations using its anti-surge while at the first 

high alteration, the pressure goes beyond the 

limit and system shall shut-down within 6 minutes 

of operation. It should be noted that still very 

high peaks have not entered the surface and 

Figure 4: Stage 2 Discharge Condition at First High Alteration 

compressor will definitely shutdown on very 

high alterations. Therefore we need to develop 

solutions for resolving the issue. 

Remedy Solutions 

To resolve the issue the very first option is 

to eliminate the fluctuation which means 

either to eliminate it in Subsea or on Surface. If 

elimination is not working then, as it is tested in 

the base case model, the low altitude fluctuations 

are not troublesome and can be easily managed. 

Thus, in case elimination is not possible, the main 

issue will be resolving the sudden high alterations 

(gas flows peaks). 

Based on the calculations, to store the feed gas 

in the surface to buffer the fluctuations (extra 

gas) the required vessel needs to have 8m the 

internal Diameter, Tangent to Tangent (TT) of 

24m and Volume of 1000 m 3 . It is obvious that we 

do not have such volume inventory on the surface 

of the platform and the current available space 

does not allow us to create such inventory either. 

Thus elimination on the sub-sea pipelines was 

considered. Generally, there are 3 main methods 

to eliminate the fluctuation on the: 

SS1: Topside Choking of the pipeline 

SS2: Riser base gas lifting(reinjection of the gas 

into the riser base) 

SS3: Combination of the two above mentioned 

Scenarios. 

Based on received information (which requires 

formal confirmation by the production 

management) the pumps can be modified to 

tolerate up to 27 barg wellhead pressure. Thus 

for our review, we had two main criteria for 

acceptance: 

Elimination of the fluctuations and FWHP 

below 10 barg (green rows) 

Elimination of the fluctuations and FWHP 

between 10 barg and 27 barg which requires 

slight modification on ESP pumps which has 

already been orally confirmed to be applicable 

(yellow rows) 

Note: Riser base gas lifting was excluded 

based on client suggestion due to its costs and 

difficulties of implementation though results 

are provided below to have a comparison of 

the cases. 

As it is seen in figure 6, topside choking of around 

50 mm on the five sluggish pipelines will eliminate 

the fluctuation while in Dena 3 and DPD, the FWHP 

is below the current allowed range and in Nosrat, 

Civand and Alvand, it requires slight modification 

on ESP pumps to increase the allowable range to 

16 barg. Figure 5 shows the compassion of the 

base case on the combined flow in the manifold 

without choking (red curve) and with choking 

(black curve). As it is seen no wellhead pressure 

impact on two lines and moderate wellhead 

pressure which can be resolved by increasing 

ESP pumps up head pressure. It shall require high 

integrity valves to do the choking and it has the 

value of being variable in cases of variations in 

flow rate to maintain stable the flow throughout 

the time. 

Figure 5: Stage 1 Discharge Condition at First High Alteration 


Conclusion and Suggestions 

As it is illustrated in this case study, remedy 

solutions developed under integrated view 

are very much cost efficient in comparison to 

alternative solutions developed under single 

aspect of subsurface or surface. During this 

conceptual study, we had a systematic analysis 

of the problem to determine the root cause 

and develop conceptual solutions for resolving 

the issue. The results showed that elimination 

on the subsea by topside choking is technically 

feasible with slight modifications on some of 

the ESP pumps. This solution is not expensive in 

comparison to stable flow conditions that could 

endure for 10 years of operation. 

NARGAN-AMITIS 

Energy Development 

NAED 

INTEGRATED 

SOLUTIONS 

INTEGRATED RESERVOIR STUDIES 

SOLUTION BASED SERVICES 

EXPLORATION 

PRODUCTION 

ECONOMIC STUDIES & RISK EVALUATION 

DRILLING & WELL 

EOR / IOR 

LABORATORY DESIGN 

FIELD DEVELOPMENT STUDY 




Tel: +98-2188949312 

Fax: +98-2188949311 




NARGAN 

South Pars Gas Field | Phase 12 


NARGAN-AMITIS 

ENERGY DEVELOPMENT 

WE HAVE THE SOLUTION 


No.14, West Sepand Street.,Sepahbod Gharani Avenue.,Tehran, 1598995311, Iran 

84 OIL INNOVATORS Nargan International Amitis Energy Journal Development MAR. 2018 | info@naed.nargan.com | +98 21 889 49 312

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