youngpetro - 4th issue - summer 2012

summer / 2012

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>110,000 employees

>140 nationalities


years of

innovation85

What will you be?

careers.slb.com





>110,000 employees

>140 nationalities


years of

innovation85

What will you be?

careers.slb.com





>110,000 employees

>140 nationalities


years of

innovation85

What will you be?

" What our planet needs right now is a big change in the energy policy, we have to use more gas and save oil for some less trivial purposes than for example transportation.

Th is is the message which Phil Rae – 2011/2012 SPE Distinguished Lecturer is traveling the world with. It is diffi cult to disagree with him, as we need this change. We have been trying to introduce alternative energy sources, bio additives, renewable and atomic energy for a couple of decades. Some of them turned out to be too expensive, others not very effi cient, safe or ethical. Th e problem is that we wanted a revolu-tion, hoping to change our whole energy system in the blink of an eye. But as history teaches us constantly, everything needs time and energy business will need a lot of it to transform. Meanwhile instead of creating a doom scenarios and sitting and waiting for a change to come, we should use our almost infi nite abilities to improve the industry. Fortunately the fi rst decade of XXI century has brought us a simple and rather overlooked solution – natural gas, which proved to be cleaner, cheaper, more effi cient and with constantly developing E&P technologies just easier to extract. For the fi rst time in more than 100 years we are look-ing on a candidate which is to become a new prima-ry energy source. Of course it does not mean that we should completely rule out oil from the equation but with everyday rising energy demands we will simply need more energy than oil can provide us with.

In this issue of YoungPetro students from universities all over the world will try to explain their ideas on how to improve the petroleum industry.

Editor's Letter

[email protected]

5

SUMMER / 2012

Editor-in-ChiefWojtek [email protected]

EditorsJulia BrągielIwona DereńPrzemysław GubałaKamil IrnazarowJakub JagiełłoAlexey KhrulenkoKrzysztof LekkiPatrycja SzczesiulJakub SzelkowskiMichał TurekLiliana TrzepizurBarbara PachJoanna WilaszekJan WypijewskiKacper Ż[email protected]

Art DirectorMarek [email protected]

Social MediaKacper [email protected]

PhotoKSAF AGH www.ksaf.pl

Published by

An O�cial Publication of The Society of Petroleum Engineers Student ChapterP o l a n d • www.spe.net.pl

Anna Ropka - Chairman

6

Necessity of Energy Cooperation In The Frames of Eastern Partnership with Neighbouring EU Countries

Andrew Skriba

Assessment of Satellite Imaging as Monitoring and Verifi cation Technology in the In Salah CO2 Storage Site

Ergene Suzan Muge, Turanli Ayse Merve

Production Optimisation of the Two Phase Flow Reservoir in Secondary Recovery Phase Using

Simultaneous Method and Interior Point OptimiserDariusz Lerch

Research the Processes of Increasing Wells Exploitation Effi ciency

Nazarii Hedzyk

Enhanced Heavy Oil Recovery MethodsIlia Gurbanov

East meets West

Canadian Dream

13

2

3

1

1

7

SUMMER / 2012

Abstract�Crises and difficulties in the economies of

some of Eastern Partnership countries (es-pecially Ukraine and Belarus) has increased the threat to their independence due to the growing energy dependence on Russia. Be-cause of his fact energy co-operation of the Eastern Partnership countries with the par-ticipation of the bordering countries of the European Union is extremely important to-day.

The Eastern Partnership was officially launched in 2009 when the Czech Repub-lic invited the leaders of the six members of the initiative. As it was mentioned before, the main objective of the project is to make the EU position closer to six former Soviet re-publics: Ukraine, Moldova, Armenia, Azerbai-jan, Georgia and Belarus. One of the planned spheres of future cooperation was energy sec-tor.

Meanwhile, Germany attended the summit to signal their alarm to the economic situation in the East. Russia accused the EU of trying to carve out a new sphere of influence, which the EU denied. As it was said, the Eastern part-nership was a response to the demands of the six countries, and the economic reality is that most of their trade is done with the EU. Prob-ably one of the reasons for Russia’s dissatis-

Necessity of Energy Cooperation in the Frames of Eastern Partnership with Neighbouring EU CountriesAndrew Skriba

faction with EU's policy was having Georgia as a member of this group (Russia fought a brief war over the regions with Georgia in August 2008). However, it looks like participation of Belarus and Ukraine (Russia considers their territories as the area of exclusive political in-terests after the collapse of the Soviet Union) caused much more dissatisfaction.

After Ukraine became independent in 1991, its leaders repeatedly spoke of the interest in participating in European integration pro-jects. However, serious internal political and social problems and contradictions, as well as economic instability, did not allow this coun-try to become a full member of the European Union, as it was in case of Lithuania, Latvia and Estonia. As a result, during the first dec-ade of the XXI century Ukraine turned out to be in an uncertain position. On one hand, there are natural obstacles of its desire to co-operate with Europe. On the other hand, the country's leadership refused to participate in Russian integration projects because of the fear of losing national sovereignty. This, in particular, gave rise to numerous energy con-

* Belarusian State Economic University

Þ Belarus

[email protected]

* University Þ Country E-mail

8 Necessity of Energy Cooperation

flicts, which affected not only Ukraine, but also some other European countries.

At first glance, the situation in Belarus looks much more transparent. The leadership of this country often demonstrated greater eco-nomic and political affinity with Russia than with the European Union. However, in reality the situation is much more complicated. The Belarusian leaders experience the same fears as their Ukrainian counterparts. The high lev-el of integration with Russia, in their opinion, would mean a significant limitation of nation-al sovereignty. Belarusian-Russian contradic-tions in 2004-2007 years led to a number of energy conflicts as well. Relationship between the two countries has deteriorated to such a level that in 2008 Belarus refused to recognize the independence of Abkhazia and South Os-setia. Furthermore Belarusian leadership has demonstrated a desire to work more closely with European countries and, moreover, par-ticipated in Eastern Partnership.

Disputes between Russia and Ukraine and Russia and Belarus have exposed some un-desirable consequences of European depend-ence on Russian energy resources.

In the late 2009 - early 2010, when the Bela-rusian-Russian energy contradictions reached their peak, cooperation between Belarus and Ukraine in the energy sector came to a quali-tatively new level. Against the background of intensification of dialogue between the two countries on the topic of energy secu-rity, Belarusian oil contracts with Venezuela and Ukrainian transit infrastructure – Odes-sa-Brody oil pipeline should be taken into ac-count.

A little bit earlier, during 2006-2007 energy conflicts and disputes with Russia, Belarus attempted to enter the oil markets of other countries. In particular, the agreements to allow Belarus to extract oil in Venezuela and Iran were signed at the highest political level. Due to political and economic contradictions between Belarus and Russia, the conditions of oil supplies to Belarusian refineries in 2010 were non-profitable. As a result, in order to provide favorable conditions for oil refining and its transportation to the country, Bela-rusian authorities signed contracts with al-ternative oil exporters. Our main partner in 2010 became Venezuela, where Belarus had already started oil extraction. The 2010 agree-

�Fig. 1 – Current and proposed oil import system

Andrew Skriba 9

summer / 2012

ments provided 4 million tons of oil from Venezuela to Belarusian refineries. In autumn 2010, it was demonstrated that, if necessary Belarus can import up to 10 million tons of oil annually - about 50% of domestic consump-tion and processing.

Therefore, Belarus signed an agreement on oil supplies from Venezuela and studied the lo-gistics of its transit through Lithuania, Esto-nia and Ukraine. However, the price of the im-ported oil was still too high, and Belarus tried to sign a swap-deal with Azerbaijan. After that, Belarus ensured a stable transport of oil, and allowed to start using the Odessa-Brody pipeline. Thus, the Azerbaijani oil was cheaper than Venezuelan and Belarusian oil refining profitability has increased significantly.

As a consequence, the prospects of the Bela-rusian-Ukrainian energy dialogue have in-creased considerably.

Firstly, the Belarusian side used railroad oil deliveries through Ukrainian territory more actively than in other states in 2010. Second-

ly, after processing at Belarusian refineries, the majority of oil products are returned to the Ukrainian market for further sale. Thus, the interest of Ukraine in Belarusian oil from either Venezuela or Azerbaijan would remain even if Belarus replaces it by Russian duty-free oil. Finally, at the end of 2010 Belarus and Ukraine began to discuss joint projects concerning the construction and use of tran-sit pipeline infrastructure for the supply of Venezuelan oil to Belarus (Odessa-Brody oil pipeline, building a new one from the Kre-menchug Oil Refinery (Ukraine) to the Mozyr Oil Refinery (Belarus)).

After the European financial crisis in 2010-2011 the level of European Union initiatives in eastern direction has decreased.

This fact has enabled Russia to strengthen its foreign policy. As a result, Belarus became a member of the Customs Union and Common Economic Space (both are Russian projects). Ukraine, being not able to finalize an agree-ment on free trade zone with the European

�Fig. 2 – Eastern European oil transport routes

10 Necessity of Energy Cooperation

Union, officially stated that it was also consid-ering such a possibility.

Russia clearly demonstrates all the advantag-es and disadvantages of participation in these geopolitical projects giving Belarus as an ex-ample. Thus, in early 2012 the price of natural gas for Belarus was 2.5 times lower than for Ukraine. Russia supplies Belarus with duty-free oil, which is much cheaper.

But the issue of energy security of individual countries and the European region itself did not disappear from the agenda. In expert cir-cles of the European Union people continue to talk about the high level of dependence on Russian energy supplies. In this situation, the European Union can work together on ener-gy security with Belarus and Ukraine in the framework of Eastern Partnership.

Therefore, in addition to the existing pipe-lines already in service, several additional projects in Europe could be involved. One of the best options for additional oil transport would be to upgrade the existing oil pipeline which runs from Baku in Azerbaijan to Supsa in Georgia. That line could be extended under the Black Sea or the oil could be loaded onto tankers and shipped to Odessa, Ukraine (as it was shown during Belarus-Ukraine coopera-tion).

The oil could then be pumped through the Odessa-Brody pipeline into Poland. Some, including the Poles, have suggested that the Brody line is to be extended to northern Po-land and possibly into the Baltic states so that it may be used at the Mazeikai refinery in Lithuania.

There are two main directions of our coopera-tion in the energy sector: 1) oil extraction 2) oil refining and petroleum products trade. The idea and necessity of cooperation is based on the fact that Belarus can offer contracts and technologies in oil extraction, as along with the well-developed refineries and technolo-gies of this process, while Poland and Ukraine possess transitional infrastructure and de-mand for alternative (non-Russian) oil prod-ucts at their domestic markets.

The revitalization of Poland, Belarus and Ukraine on the supply of Azeri oil from the Black Sea to the Baltic needs to mobilize polit-ical will of these countries, European invest-ment in the completion of the Odessa-Brody pipeline to Plotsk and Gdansk. Once accom-plished, it could enhance the energy security of all three countries, Central Europe in com-mon and bring the political positions and eco-nomic interests of the leadership of Belarus, Poland and Ukraine together.

Andrew Skriba 11

summer / 2012

For online version of the magazine and news visit us at youngpetro.org

12

Abstract�Environmental concerns of governance and

several private initiatives accelerate actions to find a solution to reduce CO2 emission to the atmosphere globally, since one of the most significant and widespread green-house gas is CO2. For this purpose, CO2 cap-ture and storage technology is emerged as an effective option. In Salah CO2 long-term storage project is the world’s largest on-shore project in Algeria since 2004. Krech-ba Field in central Algeria is an industrial scale monitoring and verification project regarding its role to provide insights to CO2 storage in deep saline formations. A variety of geochemical, geophysical, geomechani-cal and production techniques are used to monitor CO2 movement in this joint indus-try project (JIP). In order to assess the sat-ellite imaging as a monitoring technique, the cost-benefit of each technique is con-sidered by using Boston Square decision chart. According to this chart, this moni-toring technique is regarded as a feasible alternative.

�In this paper, overview of all literature sur-veys related to satellite imaging technique which is applied by using InSAR software in Krechba Field is presented. In the light of those studies, the consistency of the data

obtained from satellite imaging with the other monitoring data is indicated to dis-cuss whether satellite imaging is a new ap-proach for monitoring CO2 movement.

Introduction�The number of governance and private sec-tors that consider the dilemma between ener-gy requirements in any part of life and human based environmental problems is increasing rapidly. The most harmful and widespread en-vironmental issue is greenhouse gas (GHG) emissions. Carbon dioxide emission is one of the common GHG emissions which is tried to be reduced by using several new technologies. As the concern about this issue increases, new approaches and solutions are tried to be found by those institutions. There is no single solution, but the development of carbon cap-ture and sequestration technologies, which has accelerated greatly in the past decade, may play an important role in addressing this

Assessment of Satellite Imaging as Monitoring and Verification Technology in the In Salah CO2 Storage Site: A Literature ReviewErgene Suzan Muge, Turanli Ayse Merve

*Middle East Technical University

Þ Turkey

[email protected]

[email protected]


Ergene Suzan Muge, Turanli Ayse Merve 13

summer / 2012

issue. Carbon capture and storage (CCS) is a plan to mitigate climate change by capturing carbon dioxide (CO2) from large point sources such as power plants and subsequently stor-ing it away safely instead of releasing it into the atmosphere.

CCS process includes several steps such as capture sequestration, transportation, stor-age and monitoring. Th e main focus of this paper is the literature review of monitoring techniques, especially the satellite imaging which uses InSAR technology.

One of the successful and cost-eff ective CO₂ monitoring techniques is satellite imaging, specifi cally interferometric synthetic aper-ture radar (InSAR). Ground movement over a period of time can be detected by remote surveying method. Detection of the subtle ground-deformation changes can be applied by comparing phase differences from suc-cessive satellite passes. Besides, InSAR can be used to monitor natural hazards; our sur-vey will be focused on identifying subsidence and uplifting of structures by applying InSAR technologies [1].

Large scale pilot sites are needed to prove the applicability of CCS on an industrial scale and to verify results with the help of litera-

ture survey. For this purpose, the Norwegian Sleipner off shore CO2 storage project and the world’s largest onshore CO2 storage project the Krechba site within the InSalah gas fi eld development are conducted (Fig 1).

In the world lots of CCS projects are complet-ed with great success while some of them are being conducted even today. One of the hug-est and well known CCS projects is InSalah Gas Project which will be evaluated in detail during this project. Th e In Salah project in Al-geria is an industrial scale CO2 storage project that has been in operation since 2004. Th ere is a limitation for the CO2 content which should be applied by producers. For this pilot site which have a CO2 content of 5-10%, CO2 percentage is targeted to be reduced to spe-cifi cally 0.3% [5].

In Salah CCS Project is one of the internation-al Joint Industry Project (JIP) to enhance the operations in terms of security and economic aspects. In this purpose, US Department of Energy and the EU Directorate of Research collaborate with initiatives from leading tech-nology provider private sector around the world. Th e main objectives of JIP are: to guar-antee long term and secure geological storage of CO2 that can be economically conducted with short term monitoring technologies, to show that geological storage of CO2 is a good alternative for GHG-mitigation to the stake-holders, and to be a pioneer to create new reg-ulations and verifi cation technologies of the geological storage of CO2. In order to provide scientific network by sharing the findings with regulators, policy makers and non-gov-ernmental organizations, JIP is developed to mitigate the eff ects of climate change.

Geology Of In Salah

Stratigraphy

�Th e main units in the region are Carbonif-erous (C10) Tournasian sandstone, which in-

�Fig. 1 – Location map of In Salah fi eld[5]

14 Assessment of Satellite Imaging as Monitoring and Verifi cation Technology

cludes tight sandstone and siltstone (C10.3) and sandstone (C10.2), and lower caprock composed of silty shale with fractures. Ad-ditionally, as it can be seen in the Figure 2 the main reservoir unit is the (C10.2) sand-stone whose thickness is 20-25m and placed in 1880m depth. Th is formation is overlain by tight sandstone and siltstone formation (C10.3) with a thickness of 20m. Carbonifer-ous Visean mudstone interbedded with thin dolomite and siltstone is underlain by this formation. All these formations include C10 formation and lower cap rock C20.1-C20.3 constituteCO2 storage complex at Krechba[2].

Th e injection of CO2 in the Krechba Field is done into a fractured sandstone reservoir whose porosities ranging from 11-20% and average permeability value is around 10md. Th is reservoir is capped by nearly 950m Car-

boniferous mudstones. This mudstone is overlain by 900m sandstone and mudstones which includes the regional potable aquifer. Th e boundary between the Carboniferous and Cretaceous units is Hercynian Unconformity with a thickness of 3m overlain by thin imper-meable anhydrite unit. Th is unit can be con-sidered as a fi nal top seal [6].

Th ere are 3 injection wells (KB-501, KB-502, and KB-503) and5 production wells (KB-11, KB-12, KB13, KB-14, and KB-15). Th eir loca-tions and the Gas Water Contact (GWC) can be seen in (Fig. 3 & Fig. 4).

Structural Geology

Fractures and faults play an important role in understanding the processes with regard

�Fig. 2 – Columnar section of Krechba region[2]


SUMMER / 2012

to CO2 migration within relatively low perme-ability sandstones and shales [4]. Th e thick mudstone caprock sequence provides an ef-fective fl ow and mechanical seal for the stor-age system although fractures at the reser-voir/aquifer level.

Th e Krechba site can be characterized by a low relief anticlinal structure without any signifi -cant fault systems. On the other hand, small fractures and faults were realized after drill-ing stage in 2002. CO2 storage complex in Krechba contains a set of fractures and small faults. Furthermore, in the region as strike-slip stress regime is dominant where the max-imum horizontal stress (NW-SE) is greater than the vertical stress. Th e role of faults and associated fractures is important in control-ling the CO2 plume distribution and the asso-ciated pressure development and multi-phase fl owprocesses [4].

Injection wells (KB-501, KB-502, and KB-503) and gas production wells are drilled across principal open fracture set (maximum hori-zontal stress direction). InSAR technology, which is the main interest of this paper, is

used to measure the surface deformation in In Salah pilot CCS project. For this purpose, after the start of injection uplifted and sub-sided areas are tried to be observed and, as expected,surface uplift was detected around the injection wells, while subsidence was de-tected in the gas production area.

According to 3D seismic survey, which is con-ducted to understand the gas reservoirs, mi-nor faults are observed in the northern part of Krechba fi eld (Fig. 5). Th is is the signifi cant evidence of formation of lobes around the KB-502 injection well obtained from the InSAR data which will be explained in detail in the next section. Th is fault may help to explain an enhanced pathway of migrating CO2 from the KB-502 injector towards the NW.

CCS Activities In Krechba�Krechba CCS pilot site which is not orient-ed to gain commercial benefi t from the CO2 storage is selected by Carbon Sequestration Leadership Forum (CSLF) as one of the three worldwide industrial scale monitoring and verifi cation site. Th e scheme of Krechba in-

�Fig. 3 – Schematic Representation of Krechba [9]


Monitoring technology

Risk to monitor Action

Wellhead/annulus sampling

Wellbore integrity Plume migration

Twice-montly sampling since 2005

Tracers Plume migration Implemented 2006

Wireline logging/sampling

Subsurface characterizationOverburden samples and logs collected in new development wells

Soil gas/surface flux Surface seepagePreinjection surveys in 2004 Repeat survey in 2009

3D-4D seismic Plume migrationInitial survey in 1997 High-resolution survey acquired in mid-2009 Provides feasibility evaluation for 4D

Deep-observation wells

Plume migration Not planned at present due to cost

Microseismic Cap rock integrity

Test well drilled mid-2009 above KB-502 injector Depth 500m, 1500m above injection zone, 50 geophones array (10 three components) Recording ongoing

Electromagnetic surface and wellbore

Plume migrationNot useful at Krechba due to subsurface architecture and logistics Wells too widely spaced

Gravity Plume migrationModellingsugests surface response negligible May be tested in 2011 Borehole gravity possible if suitable access available

VSPCap rock integrity Plume migration

Fracture evaluation

Modelling results inconclusive Decision pending 3D VSP into microseismic array

Shallow aquifer wells

Contamination of potable aquifer Cap rock breach

Seven shallow aquifer wells drilled Sampling twice per year

Microbiology Surface seepage First samples collected in late 2009

Eddy covariance flux towers and LIDARs

Surface seepageReviewed, but weather conditions and potential equipment theft ruled this out Reviewing potential for deployment in 2011

InSAR monitoringPlume migration Cap rock integrity

Pressure development

Used extensively, contributions and commissioned work from several providers Images captured every 28 days

Tiltmeters/GPSPlume migration Cap rock integrity

Pressure Development

To calibrate InSAR deformations 70 tiltmeters deployed around KB-501 in late 2009

�Table 1 – Monitoring technologies, risks and status in In Salah site [5]


summer / 2012

jection site where CO2 is being injected into the aquifer leg of the gas producing fi eld in central Algeria can be observed in Figure 3. As a greenhouse-gas reduction initiative In Salah gas development project takes part in provid-ing experimental and demonstration aspects of a geological storage in deep saline forma-tions[5].

Since 2004 around one million tones of CO2 per year have been separated from the pro-duced gas and 70% of this is re-injected to the subsurface into the Carboniferous sandstone

reservoir. In addition to Krechba Field, also from Reg and Teguentour fi elds separated CO2 from natural gas is injected into underground at three wells. Since this study fi eld is located in the rocky desert without vegetation, it is suitable for InSAR processing which uses ra-dar signals [8].

CO2 is separated out due to standardized val-ues for purity, condensed to 185 bar pressure, and transported 14 kilometres by pipeline to the injection wells. Because of high pressure conditions, liquefi ed form of CO2 is observed

�Fig. 5 – Krechba Field Well Locations [5]


at the time of injection. This means that there are mainly four steps in the CCS system from capture to injection processes [1].

Monitoring Technologies Used At Some Geological Co2 Storage Sites�Monitoring technologies used at some geo-logical CO2 storage sites were reviewed in the paper of Hannis [3]. In that paper, two pilot-scale and two commercial CO2 storage sites were evaluated in terms of different moni-toring technologies. The pilot-scale sites were Ketzin(Germany) and Nagaoka (Japan) and the commercial sites are the Sleipner (Nor-way) and the In Salah (Algeria) which is the focused site. Electrical resistivity in Ketzin site, wireline logging including resistivity, neutron and sonic in Nagaoka site, satellite based monitoring in In Salah site and 4D seis-mic surveys in Sleipner were reviewed in the paper called “Monitoring technologies used at some geological CO2 storage sites”.

The purpose of the author while selecting those specific sites is the range of storage sce-narios and the successful results of these spe-cific techniques at those sites. In the light of these results, it can be concluded that useful monitoring techniques are mostly “site specif-ic”. While choosing monitoring techniques, a number of parameters, such as the location of a site and type of a geological storage site, must be considered. For instance, although 4D seismic monitoring technique is appropri-ate for Sleipner site where CO2 is injected into a saline aquifer, it will be useless for the sites where CO2 is injected into a depleted gas field, because of its difficulty in distinguishing be-tween CO2 and residual hydrocarbons. Like-wise, the satellite imaging technology which uses InSAR to detect surface deformation will not be suitable for off-shore geological stor-age sites, such as Sleipner. Detection of ef-fective and right monitoring techniques will

enhance public confidence. Furthermore, se-lection of right technique will save the stake-holders from redundant investment [3].

In order to select the best monitoring tech-nique in In Salah site, Boston Square Method is used as a decision making tool. Key risks associated with the In Salah storage site is de-fined as well bore integrity and direction of CO2 migration to select best monitoring tech-nique. Additionally, not only the key risks but also the site characteristics play a major role while determining the best monitoring technique. All techniques included in Boston Square Chart are standard oil and gas field ex-ploration and development technologies. For instance, for the level of water table, which is around 105-110 m below the surface, surface based monitoring techniques were not appro-priate to use. Moreover, at first glance, the electromagnetic monitoring, which was eval-uated as an appropriate technique, could not be applied in this site due to difficult logis-tics and subsurface architecture at Krechba. When key risks and monitoring technologies were considered together, the table shown be-low was developed (Table 1).

For this purpose, each monitoring technology was placed on a Boston Square Chart which shows the relationship between benefit vs. cost to the JIP. Boston Square Chart covers both the cost of the technology to the JIP and the benefits to overall JIP objectives in Krech-ba field. This chart is divided into four quad-rants named as “consider, just do it, park and focused application”. After pre-assessment of it, final version of Boston Square Chart is ob-tained by eliminating the technologies which drop high cost and low benefit quadrant which is called as “park”(Fig. 7).

Then, after elimination, current monitoring programme is gathered. Although initial as-sessment is over, there are still several moni-toring techniques, such as microseismic, tilt-meters and vadose zone wells, that need to be tested. Even In Salah project was emerged as a non-commercial CO2 storage project, by


summer / 2012

amendment of regulations regarding CO2 storage, the most feasible monitoring tech-nique will be employed. Th e red dotted line of the Boston Square Chart (Fig. 8) shows the position where consensus could be obtained between a developer and a regulator. Th e area under the red dotted line will be cost-eff ective and site-specifi c monitoring program [6].

Satellite Monitoring Technique

�Satellite imaging technique is based on emitting a pulse of electromagnetic radiation. By considering the strength and delay of re-corded signals, ground images can be created. Since this technique provides the repeated data of the same location even two millime-tres change can be detected. Also, satellite imaging is suitable for all weather conditions whether it is day or night due to nature of ra-dio wave and spaceborne SAR systems [1].

Satellite imagery of surface deformations which provide continuous, real-time imag-ing of CO2 migration through the water leg of the Krechba Carboniferous Sandstone gas producing reservoir can be considered as the main part of the monitoring program. Inter-ferometric synthetic aperture radar (InSAR) is a successful and cost-eff ective monitoring technique at In Salah (Fig. 8).

Since this pilot site is currently a gas produc-tion fi eld, monitoring activities were carrying on before CO2 injection to the reservoir. After the start of CO2 injection, as expected, surface uplift was detected by using InSAR technol-ogy at Krechba. Over a period of more than 4 years after the injection, surface uplift was observed up to 2cm. Since the region includes lots of minor faults and fracture systems, mi-gration pathways and surface uplift patterns are formed by the eff ect of those structural features.

CO2 injection and gas production result in ex-pansion or compaction of the reservoir for-mation whose eff ect can be seen as an uplift or subsidence at the surface. Th e injection wells that cause expansion are KB-501, KB-502 and KB-503. As can be seen in Fig. 9, sur-face uplift around KB-502 injection well, ori-entation of 2 distinctive lobes is parallel to the direction of maximum principal stress in the region.

Th is technology gives an opportunity to de-fi ne subsurface CO2 fl ow behaviour. Further-more, the assessment of reservoir conditions (confined or unconfined to target storage complex) can be possible by the utilization of this program. In the light of paper covering fl uid fl ow and geomechanical modelling study of CO2 injection, it can be inferred that reser-voir layer (C10.2) is not able to generate such

�Fig. 5 – a) Updated fault interpretation from new 3D seismic survey, shown on coherency attribute map of Top C10.2 reservoir, and b) updated 2010 fault model for corresponding area (oblique view from south) [10]


�Fig. 6 – Potential Monitoring Actions for the Krechba site [6]

�Fig. 7 – Current Monitoring Programme – Krechba [6]


SUMMER / 2012

an uplift nearly 2cm over KB-501. Th e reason of this unexpected uplift generation can be explained by pressure propagation into the other layers (C10.3 and C20.1). Th e transmit-ted pressure to overlying units of reservoir cause additional surface uplift with increas-ing pressure up to 50m above the top of res-ervoir unit [11].

In the paper it is argued that the surface uplift would be increased (from ~1.2cm to ~2 cm) by allowing upwards pressure propagation into the overlying tight sandstone layer (C10.3) and the lower caprock (C20.1), with increased pressure up to 50m above the top of C10.2 [2].

Uplift is caused primarily due to expansion of the reservoir formation caused by the in-jection, while subsidence is due to compac-tion of the reservoir formation caused by pro-duction. Surface deformation measurements provide useful information on the subsurface CO2 fl ow behaviour and can be used to assess whether the induced volume changes are con-fi ned to the target storage complex or not.

History matching and findings of inverse modelling are used to construct reservoir model. In inverse modelling, simplifi ed res-ervoir properties such as homogeneous res-ervoir and formation without topography at injection levels are used and continuous pres-sure distribution is obtained. Furthermore, by using both fi eld observations and pressure distribution data, permeability values can be normalized. History matching is based on, fi rstly, the assumption of initial reservoir pa-rameters, and running the model with these parameters. After obtaining the base model with default parameters, the model is tried to be converged to real model by considering the fi eld data. History matching is applied for fi eld injection pressure and CO2 breakthrough in the paper of Durucanet. al.[2]. To get bot-tom hole pressure (BHP), estimated data is added to well head pressure (WHP). Although, as default parameter matrix permeability is suffi cient to run the model, the results indi-cate that a dual permeability model including fracture permeability is needed to reach the real model. Th en, the high permeability corri-

�Fig. 8 – Surface deformation detected over the CO2 injection and production wells at Krechba using PSInSARtechnique [2]


dor that connects KB-502 and KB-5 is clarified by using the history matching of CO2 break-through.

Discussion And Conclusion�In order to discuss whether InSAR is a use-ful monitoring technique or not, the princi-ples of this technique should be analysed in detail. InSAR is used to detect and monitor subtle surface deformations by the advance of Digital Elevation Model (DEM). This appli-cation requires DEM of static topography in high resolution to observe actual differences of region before and after the deformation. This difference is achieved by subtracting de-formed interferogram from initial static in-terferogram (by subtracting one phase image from another, yielding a map of interferomet-ric phase called an interferogram). The pre-cision of InSAR is in millimetre-scale for the measurements of displacement but meter scale for elevation [12]. In this case, main con-cern is to detect and monitor the deformation due to CO2 injection. In the light of literature survey during the preparation of this paper, it can be concluded that monitoring techniques cannot be classified as the best and unique for all storage sites. Rather than considering one of the monitoring techniques as the best, in selection the cost effective, site specific and performance based techniques should be con-sidered. When InSAR is compared to other technologies in terms of aspects above, it can be a good alternative technique to understand CO2 breakthrough in In Salah. Additionally, this technique needs a multi-disciplinary ap-proach such as geochemistry, geophysics, re-mote sensing, and geomechanics to monitor CO2 movement effectively.

When the results of InSAR are discussed in In Salah site specifically, the detection of uplift and subsidence in injection and production regions respectively, recognition of fault and high permeability zone is possible.

It can be concluded that In Salah CCS project which is considered as pilot site for using sat-ellite imaging technique provides valuable outputs to enhance future monitoring tech-niques, especially related with remote sens-ing. This technique enables the detection of some heterogeneities resulted from the CO2 plume migration and can handle this incon-sistency by modelling and characterization of the reservoir in high resolution. Subtle mil-limetre scale surface deformation caused by injection and production which are the main reasons of subsurface pressure changes can be detected by InSAR.

Moreover, this technique makes possible in-terpretation of structural features such as faults and fractures by assessing high permea-bility zones and trend of migration pathways. Lastly, satellite imaging method, InSAR, is a good alternative for the sites having similar site characteristics such as lacking of vegeta-tion (to make observation possible by remote sensing), and availability of data obtained from other monitoring techniques (to check the accuracy of InSAR). This comprehensive technique program provides cost efficient and long term monitoring.

Acknowledgement�We wish to thank to Prof.Dr.NilgunGulec,Dr.CagilKolat, Prof.Dr.MahmutParlaktuna,and Assoc. Prof.CaglarSinayucfor their guidance, support and contributions.


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References1. CCS Project. (2010). Retrieved from http://www.insalahco2.com

2. Durucan S., Shi J., Sinayuc C., KorreA., 2011.In Salah CO2 storage JIP: Carbon dioxide plume ex-tension around KB-502well - New insights into reservoir behaviour at the In Salah storage site, Energy Procedia 4 3379–3385

3. Hannis S., 2010.Monitoring Technologies Used at SomeGeological Co2 Storage Sites, Innova-tion for Sustainable Production (i-SUP) conference proceedings.

4. Iding, M., Ringrose, P., 2009. Evaluating the impact of fractures on the long-term performance of the In Salah CO2 storage site. EnergyProcedia. 1(1), 2021-2028. Proc. GHGT-9, 16–20 Novem-ber 2008, Washington DC, USA.

5. Mathieson, A., Midgley, J., Dodds, K., Wright, I., Ringrose, P., Saoula, N., 2010. CO2 sequestra-tion monitoring and verificationtechnologies applied at Krechba, Algeria. The Leading Edge, 29(2), 216-222.

6. Mathieson, A., Wright I., Roberts D., Ringrose P., 2008. Satellite Imaging to Monitor CO2 Move-ment at Krechba, Algeria, Energy Procedia.

7. Onuma T. and Ohkawa S., 2008.Detection of surface deformation related with CO2 injection by-DInSAR at In Salah, Algeria, EnergyProcedia.

8. Onuma T., OkadaaK. and Otsubo A., 2011.Time Series Analysis of Surface Deformation related with CO2Injection by Satellite-borne SAR Interferometry at In Salah, Algeria, EnergyProcedia 4, 3428–3434.

9. Ringrose P., Atbi M.,Mason D., Espinassous M., Myhrer Ø, Iding M., Mathieson A., Wright I., 2009.Plume development around well KB-502 atthe In Salah CO2 storage site, First Break 27, 85-89.

10. Ringrose P., Roberts D., Gibson-Poole C., Bond C., Wightman R., Taylor M., Raikes S., Iding M., Østmo S., 2011.Characterisation of the Krechba CO2 storage site: critical elementscontrolling injection performance,Energy Procedia 4 4672–4679.

11. Rutqvist, J., Vasco, D.W., Myer, L., 2009. Coupled reservoir-geomechanical analysis of CO2 in-jection at In Salah, Algeria. Energy Procedia, 1(1), 1847-1854. Proc. GHGT-9, 16–20 November 2008, Washington DC, USA.

12. Smith L., 2002. Emerging Applications of InterInterferometric Synthetic Aperture Radar (In-SAR) in Geomorphology and Hydrology, Annals of the Association of American Geographers, 92:3, 385-398

13. Vasco D., Ferretti A., NovaliF., 2008. Reservoir monitoring and characterization using satellite geodetic data: Interferometric Synthetic Aperture Radar observations from the Krechba field, Algeria, Lawrence Berkeley National Laboratory.

14. Wright I., BP, 2007.The In Salah Gas CO2 Storage Project, International Petroleum Technology Conference.

24 Assessment of Satellite Imaging as Monitoring and Verification Technology

Abstract�In the world of increasing demand for ener-

gy and simultaneously decreasing number of newly found oil fields one can witness the interest for the simulation studies com-bined with optimisation methods in order to improve secondary recovery phase under water flooding techniques. Since the opti-misation on the realistic reservoirs can be prohibitive when it comes to size and com-putation time a lot of attention was given to single-shooting methods combined with the use of adjoints for gradient computa-tion which reduces the size of the problem. However, there are, other approaches to optimisation of oil reservoirsas multiple-shooting or simultaneous method which have not been investigated that much by the industrial and academic communities mainly because they do not eliminate states from the optimisation algorithm resulting in a problem of up to millions of optimisa-tion variables.

�In this paper we investigate the simulta-neous approach on direct transcription for optimising oil production in the second-ary recovery phase under water flooding. Results are encouraging and suggesting a merit potential of this approach for further investigation.

�In the first section we explain the idea of smart well technology in the two phase flow reservoir. Then we introduce the pro-cess of reservoir management and picture the location of optimisation algorithms in it.Section III describes the two time-scales involved in oil production and result-ing challenges. Section IV points out the features of different optimisation meth-ods, which have the potential for solving oil problem. In section V we present the mathematical formulation of the reservoir model and then we discretise and use it to formulate the optimal control problem in section VI. Section VII presents the par-ticular instance of a production scenario with the corresponding results. Finally, the conclusions and suggestions for the future work are made in the last section.

Introduction�Natural petroleum reservoirs are character-ised by 2-phase flow of oil and water in the po-rous media (e.g. rocks). Conventional meth-

Production Optimisation of the Two Phase Flow Reservoir in Secondary Recovery Phase Using Simultaneous Method and Interior Point OptimiserDariusz Lerch, Andrea Copolei, Carsten Völcker, Erling H. Stenby, John B. Jørgensen

* Technical University of Denmark

Þ Denmark

[email protected]


Dariusz Lerch, Andrea Copolei, Carsten Völcker, Erling H. Stenby, John B. Jørgensen 25

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ods of extracting oil from those fields, which utilise high initial pressure obtained from natural drive, leave more than 70 % of oil in the reservoir. A promising decrease of these remaining resources can be provided by smart wells applying water injections to sustain satisfactory pressure level in the reservoir throughout the whole process of oil produc-tion. Basically, to enhance secondary recov-ery of the remaining oil after drilling, water is injected at the injection wells of the down-hole pipes (figure 1.). This sustains the pres-sure in the reservoir and drives oil towards production wells. There are however, many factors contributing to the poor conventional secondary recovery methods e.g. strong sur-face tension, heterogeneity of the porous rock structure leading to change of permeability with position in the reservoir, or high oil vis-cosity. Therefore it is desired to take into ac-count all these phenomena by implementing a realistic simulator of the 2-phase flow res-ervoir, which imposes the set of constraints on the state variables of optimisation prob-lem. Then, thanks to the optimal control, it is possible to effectively adjust injection rates, bottom whole pressures or other parameters to control the flow in every grid block of the reservoir and effectively navigate oil to the production wells so it does not remain in the porous media. The use of such a smart tech-nology known also as smart fields, or closed loop optimisation, can be used for optimis-ing the reservoir performance in terms of net

present value of oil recovery or another eco-nomic objective.

Reservoir Engineering�In order to maximise reservoir perfor-mance in terms of oil recovery or another economic objective, reservoir management process is carried out throughout the life cy-cle of the reservoir, which can be in order of years to decades. Reservoir management was initially elaborated by Jansen et al. [7] and its scheme is presented in the figure 2. In some other works this scheme might be present-ed in a slightly different way as the reser-voir management can be enriched or missing some elements depending on the manage-ment strategy e.g. in case of an open loop res-ervoir management system models are not updated with data from the sensors through data assimilation algorithms and whole opti-mization is performed offline. Furthermore, some strategies distinguish between low and high order system models, which are respon-sible for uncertainty quantification. The top element in the fig. 2 represents the physical system constituting reservoir and well fa-cilities. The central element refers to system models which consist of static (geological), dynamic(reservoir flow) and well bore flow models. The reason for using multiple mod-els lies in the fact that each of them has some uncertain parameters which allow to deter-mine uncertainty about the subsurface. The updated models through data assimilation and history matching technique with an un-certainty description give the support to the optimizer. On the right side of the figure, we have sensors, which are responsible for keep-ing the track of the processes that occur in the system.Sensors can be interpreted as physical devices taking measurements of the reservoir parameters, such as water or oil saturations and pressures but they can also be considered in more abstract manner as sources of infor-mation about the system variables e.g. inter-preted well tests, time lap-seismics. On the left-hand side of the figure, one can find op-

�Fig. 1 – Schematic view of horizontal smart wells [8]

26 Production Optimisation of the Two Phase Flow Reservoir in Secondary Recovery Phase

timisation algorithms, which try to maximize the performance of the reservoir in terms of the given objective (e.g. net present value) based on the set of the constraints obtained from reservoir models. Since it is almost im-possible to capture all important issues in the mathematical formulation, the optimizer and estimator elements will always include some human judgment. Very important element of the closed-loop reservoir management pro-cess are data assimilation algorithms (bottom of the figure), which obtain the data about the real world from the sensors and then update less realistic models with the more accurate information. Data assimilation and model up-date is performed more frequently than off-line reservoir optimisation as models can eas-ily get off the right track during simulation. As a result, most of reservoir management processes are understood as closed loop ones and their crucial elements are model based optimisation, decision making and model up-dating through the data assimilation tech-niques. One can realise that model based op-

timisation which is the main area of focus in this work, is an extremely important element of the whole reservoir management process.

Multi-scale (Upstream and Downstream) Optimisation�From the physical point of view processes involved in oil production can be classified into upstream and downstream ones. Down-stream processes refer to e.g. pipelines and ex-port facilities whereas upstream processes are the ones happening in the reservoir e.g. sub-surface flows. Those two types of processes differ from each other very distinctively when it comes to their timescales. In the upstream processes the velocity of the fluid can be very slow mainly due to some physical properties of the reservoir such as low permeability val-ue or its size which can be up to two tens of kilometres. Hence it can take up to decades to navigate oil by injecting water towards pro-duction wells. In case of downstream parts

�Fig. 2 – Reservoir Management Process [7]

Dariusz Lerch, Andrea Copolei, Carsten Völcker,Erling H. Stenby, John B. Jørgensen 27

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of production timescales are much lower and can be in order of minutes or even seconds. In this work we focus on optimisation of up-stream production where we model the two phase flow and run so called reservoir simula-tion. The simulation is based on mathemati-cal models governed by partial differential equations (PDEs, governing equations) and is performed for a long time horizon, even up to decades of years. Consequently the optimisa-tion of upstream part of oil production is run off-line whereas downstream part is mostly performed on-line. One of the most challeng-ing aspects in closed loop reservoir engineer-ing involves the combination of short-term production optimisation and long-term reser-voir management. An open question is: what is the best way of implementing the found, optimal trajectory that was computed off-line into the daily performance of an oil field? Technically, daily valve setting are selected so that they result in instantaneous maximisa-tion of oil production limited by constraints on the processing capacities of gas and water co-produced with the oil. Such settings are mostly determined with heuristics operating protocols, sometimes supported with off-line model based optimisation using sequential or quadratic programming to maximise in-stantaneous reservoir performance. What is more, a simple, frequent online feedback con-trol is used for stabilising the flow rates and pressures in the processing facilities to sepa-rate oil, water and gas streams from the wells. It can be seen that there are a few control and optimisation processes going in parallel at different time scales. This kind of strategy in-volves a layer control structure where longer-term optimisation results provide set points and constraints for the instantaneous, short term optimisation, which then navigates and provides set points for field controllers. This modular approach, also known as multi-scale optimisation, has been widely used in the pro-cess industry and was proposed for reservoir management in Jansen et al. [7] and has also been elaborated in Saputelli [11].

Optimisation Methods�Optimisation of oil production is stated as an optimal control problem constrained by the 2 phase flow model and boundaries on state and control variables. The model is non-linear and governed by partial differen-tial equations (PDEs) for an each phase. The optimisation is performed in the nonlinear model predictive control framework where constrained dynamic optimisation problem is re-solved and re-implemented on regular sampling intervals; see Biegler et al. [3]. This supports the advantages coming from the combination of the numerical optimal con-trol solution with the feedback of the updated model through data assimilation techniques. There are three main methods (single-shoot-ing, multiple-shooting and simultaneous method) for solving NMPC dynamic optimi-sation problem and can be categorised based on how they discretise the continuous opti-misation problem; see Ringset [10]. So far, the most of attention from academic and in-dustrial oil communities was given to single-shooting method which has been tried out in many works e.g.in Völcker et al.[15], Capolei et al. [5] or Suwartadi [13] for optimization of oil reservoirs. The main reason for using the single-shooting method (or sequential as op-timisation is executed sequentially to numer-ical simulation for gradient computation) is because after reformulation it uses only ma-nipulated variables (controls) as optimisa-tion variables which reduces the optimisation space in the algorithm. Size reduction is a very attractive feature especially for oil problems since they have the tendency to be very big in the first place (up to millions of variables) so it is very convenient to eliminate the states from the optimisation algorithm and solve the smaller reformulation sequentially(SQP); see Li [9] and Di Oiliveira [6]. What is more, single-shooting is used with high order ES-DRIK methods equipped with the error esti-mator which results not only in lower number of discretisation points but also ensures that the model equations are integrated properly.


Contrary to single-shooting approach, the si-multaneous method, which implementation for optimization of oil reservoirs is the main interest in this work, uses also a discretisa-tion of the future process model variables as optimization variables. Thanks to that, the method offers the full advantage of an open structure after reformulation such as direct access to first and second order derivatives, many degrees of freedomand periodic bound-ary conditions. The transcribed nonlinear program by this method is however, much larger than by single-shooting. Neverthe-less, it is very often the case that after direct transcription the problem is very sparse and structured so it is possible to define the spar-sity pattern in an algorithmic way. Of course implementation of the sparsity pattern can be sometimes very timeconsuming but it offers a great trade-off when it comes to reduction of the problem size and other computational aspects. In simultaneous method the model is not solved at each iteration but a simul-taneous search for both model solution and optimal point is carried out. In case of single shooting the model is solved (with an initial value solver) sequentially with reduced size optimisation problem. Consequently single shooting may be costly if evaluation of the problem functions is costly e.g. if implicit dis-cretisation scheme must be applied, which is the case in optimisation of oil production.

Reservoir Model�The model for two-phase, completely im-miscible flow comprises partial differential equations representing the mass conserva-tion for water and oil phase of the following form:

∂∂=−∂∂+

Ct

Nx

Qw ww

∂∂=−∂∂+

Ct

Nx

Q0 00 1[ ]

which state that the rate of change of water/oil concentration( / ) with respect to time is

equal to negative rate of change of flux( / ) of each phase with respect to distance, enriched by the fee injection and production terms( / ). The concentration of each phase is expressed as product of its density, saturation and po-rosity of the reservoir.

C P Sw w w w=φρ ( )

C P So o o o=φρ ( ) [ ]2

The porosity is the fraction of the void space that can be occupied by the fluid and is as-sumed to be constant with respect to position in the reservoir. Saturations , are defined as the fraction of a volume filled by that phase. Since it is assumed that the petroleum reser-voir contains only oil and water and two phas-es fill the available volume, saturations satisfy the following equation:

S Sw o+ =1 3[ ]

Densities of each phase are pressure depend-ent and are represented by the following equations of state:

r rw wc P Pe w w w= −

00( )

r ro oc P Pe o o o= −

00 4( ) [ ]

cw, co – are compressibilities of each flu-id assumed to be constant in the given range of interest

rw0=rw(Pw0 ), – are the densities at the referencero0=ro(Po0 ) pressures rw0 and ro0

Mass is transported by convection and its ve-locity is obtained from Darcy’s law that for-mulates the velocity through porous medium. This allows to express the fluxes as:

N P u P Sw w w w w w= r ( ) ( , )

N P u P So o o o o o= r ( ) ( , ) [ ]5

uw, uo – are linear velocities and are de-fined as the velocities that a con-servative tracer would experi-ence if taken by the fluid of the given phase through the porous formation


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The reason why we use linear velocities and do not account for the fact that the medium is porous is because in our model we do not have any phenomenon influenced by the porosity such as formation damage or fines migration. This approach has been undertaken in many reservoir simulation works e.g. Völcker et al. [16] or Aziz [1] and yields:

u kk S P

xwrw w

w

w=−∂∂

( )µ

Where k=k(x) denotes the absolute permeabil-ity of the porous medium, which is dependent only on the spatial position in the reservoir. krw=krw(Sw) and kro=kro(So) are relative perme-abilities of each phase and are modelled by the Corey relations; see Völcker et al. [16]. We also use residual oil saturation Sor and connate water saturation Swc to impose the following boundaries on the saturation of each phase.

S S Sor o wc≤ ≤ −1

S S Swc w or≤ ≤ −1 7[ ]

Then the reduced saturations can be modelled as:

sS S

S Sww wc

wc or

=−

− −1

sS S

S Soo or

wc or

=−

− −18[ ]

Due to the surface tension and curvature in the interface between two phases the oil pres-sure tends to be higher than the water. The pressure difference between 2 phases is called the capillary pressure. This effect however, is very low in the highly permeable and porous media and is neglected in this model; see Ber-enblyum [2]. The model is discretised in space by using finite volume method (FVM ) and Gauss’ divergence theorem; see Völcker et al. [14], which enables to consider the reservoir as a grid formed by blocks with constant di-mensions. Each grid block is given an index i which indentifies its position in the reser-

u kk S P

xoro o

o

o=−∂∂

( )[ ]

µ6

voir.The absolute permeabilities ki are as-sumed to be isotropic and constant within the grid block. The geological permeabilities at the interfaces between neighbouring grid blocks i and j are calculated as harmonic av-erage of the absolute permeabilities of those blocks. What is more, the relative permeabili-ties krw,ij , kro,ij , at the interfaces between neigh-bouring grid blocks i and j are calculated using upstream weightingwhich requires the use of integer variables and results in solving mixed integer nonlinear program (MINMLP) hav-ing a highly combinatorial character which is more complex than a regular NLP.

General Formulation and Time Discretisation�In optimisation problems involving pro-cess simulations, reformulating the problem and discretising it in time or space is always a challenge since a new discrete model should preserve such properties as e.g. conservation of mass, energy, or momentum. This is due to the fact that these properties are the initial outlet for the constraints definitions. As pro-posed by Völcker et al. [14] mass preserving, spatially discretised reservoir model has the following form:

ddt

g x t f t x t x t x( ( )) ( , ( )) ( ) [ ]= =0 0 9

In which x t m( )Î represents the states (pres-sures and water saturations),g x t m( ( ))Î are the properties conserved, whereas the right hand side function f t x t m( , ( ))Î has the usu-al interpretation. Then with the use of eq. 9 we can formulate the water flooding problem as a continuous Bolza problem

[ ( ), ( )]min ( , ( ), ( ))x t u t to

tf

J t x t u t dtò

s tddt

g x t f t x t x t x. ( ( )) ( , ( )) ( )= =0 0

u u t umin max( )£ £

uddt

u t umin max( ) [ ] £ £ 10


The constraints uddt

u t umin max( ) £ £ should be understood as movement ones and model the physical limitations on the controls (wa-ter injection rates and bottom whole pres-sures). In order to transcribe the infinite di-mensional problem into numerically traceable one we use direct collocation method and ful-ly discretise the optimal control problem by approximating the controls and states as piecewise polynomial functions on finite ele-ments by applying implicit first order Runge-Kutta method (Implicit Euler). This enables to represent to optimal control problem as a nonlinear program (NLP).

Production Scenario�The numerical experiment of optimising production in oil reservoir was performed under following scenario: Simulation is run in the reservoir discretised into15 x 15 grid blocks. Each of the grid blocks is 25 meters wide, 25 meters long and 15 meters high, the rock porosity is 0.2 and constant within the reservoir which gives the total porous volume equal to 562500 cubic meters. The time hori-zon of 1500 days was divided into 50 equal time steps of 30 days each. The injection well is located at the left hand side of the reservoir and is divided into 15 segments equipped in one injector each. The production well is lo-cated on the right hand side of the reservoir and is divided into 15 segments, where each of the segments contains one producer. In the production simulation water is injected by 15 injectors in order to displace the oil towards the producers sucking the mixture of oil and water. Delivering oil towards production wells is considered as final stage of the upstream production and further processes are not an-alysed in the 2-phase displacement simulator.The discount rate factor related to NPV is set to zero since in many works it has been shown that the optimal injection rates are very sen-sitive to this parameter, e.g. Capolei [5]. The physical model data, as well as fluid proper-ties and economic data that we used for this

experiment can be found in Völcker [14]. The water injection rates are constrained in such a way that no more than 2 porous volumes are injected throughout the total production time which gives minimum and maximum injection rates of single producer Qwmin and Qwmax equal to 0 and 50 cubic meters per day respectively. The lower and upper bounds on production well control parameters ( bottom whole pressures) are set to 150 and 200 bars respectively. Such values are commonly used in this kind of simulations by the industrial community. The decreasing oil saturations within the reservoir at different stages of oil production are shown in the figures 3-7:

The evolution of the net present value(NPV) and the injected porous volumes (PVs) are presented in the figures 8 and 9 respectively:

Figures 10 and 11 present the values of the manipulated controls (bottom whole pres-sures and water injection rates).

Figures 3-7 clearly show how oil is swept out from the reservoir by the injected water throughout the production. Fig. 8 – and 9 dis-tinctly demonstrate that the maximum npv (46 million dollars) was reached after inject-ing 1.08 pvat on the 1000th day of the produc-tion, which means that the value of oil pro-duced after this time did not compensate for the prices of water injection and water separa-tion that also contribute to the economic po-tential of the reservoir. Consequently, accord-ing to the optimizer the wells should be shut down at 1000th day. This kind of simulation studies help in answering the open question when to stop the production and how much profit is to be expected from the reservoir.

Conclusions and Future Work�We have implemented the mathemati-cal model of the two phase flow reservoir with the use of two point flux approxima-tion (TPFA) and the single point upstream


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�Fig. 3 – Oil Saturations after 100 Days

�Fig. 4 – Oil Saturations after 300 days





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(SPU) scheme for computing the fluxes. The partial differential equations were derived by using the property of mass conservation and solved by discretising them in space and time by using finite volume method (FVM) and first order implicit Euler method respec-tively. The developed black oil simulator was applied in the nonlinear model predictive control (NMPC) framework combined with the simultaneous method for optimising the oil production in terms of the net present value (NPV) as the objective cost. As an op-timisation algorithm, interior point method in the line search framework;see Wächter et al.[18] and Schenk [12], was chosen by using large scale optimisation package Ipopt; see Wächter et al. [17]. The package distribution was plugged in as dynamic link library (DLL)to implementation of the reservoir model. The simulator and routines for representing fully discrete nlp were written in C++ object oriented language (OOL) in Microsoft Visual

Studio Integrated Development Environment (MSVS IDE).

The established solution to the test problem clearly shows that the simultaneous method by direct collocation has a clear and merit po-tential for solving real case problem as the results obtained in this work make physical sense. This is very important as in this ap-proach model is not solved in a convention-al way, sequentially at each iteration but a simultaneous search for points satisfying model equations is done by the algorithm. Consequently, it could be the case that the model constraints are not satisfied if the al-gorithm terminates before converging. The relatively steep transition in the saturations between the neighbouring grid blocks is a suggestion for incorporating the mathemati-cal term representing sweep efficiency in the objective cost function or reducing the size of the grid blocks. In the future work, real life



�Fig. 8 – Evolution of Net Present Value throughout the production time

�Fig. 9 – Evolution of injected porous volumes throughout the production


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�Fig. 10 – Bottom whole pressures in bars at the 15 producers throughout the production time

scenarios of productions for satisfyingly small time steps will be solved. This can be accom-plished by deriving and implementing analyt-ical expressions for second order derivatives constructing the Hessian of the Lagrangian matrix. At the current stage, this matrix is ap-proximated by BFGS method which does not enable to represent it in a sparse way which meansconsidering only non-zero elements and reducing the problem size.

Acknowledgements�Very grateful acknowledgements for con-tributing to this work are given to Associate Professors at Centre For Energy Resources Engineering (CERE): Wei Yan, Alexander Sha-piro, as well as PhD students: BjørnMaribo – Mogensen andHao Yuan.


�Fig. 11 – Water injection rates incubic meters at the 15 injectors throughout the production time

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7. Jansen, D. R. and Brouwer, J.D. "Dynamic optimization of water flooding with smart wells using optimal control theory." SPE Journal, 9(4), 2004: 391–402.

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14. Völcker, C. Production optimisation of oil reservoirs. Kongens Lyngby, Denmark: Departmen for Informatics and Mathematical Modelling (IMM), Centre for Energy Resources Engineering (CERE), Technical University of Denmark (DTU), 2012.

15. Völcker, C., Jørgensen, J.B. and Stenby, E.H. Oil reservoir production optimisation using optimal control. Kongens Lyngby, Denmark: Department of Infomatics and Mathematical Modelling(IMM), Centre for Energy Resources Engineering (CERE), Technical University of Denmark (DTU), 2010.

16. Völcker, C., Jørgensen, J.B., Thomsen, P.G. and Stenby, E.H. "Simuation of the subsurface two-phase flow in an oil reservoir." Proceedings of the European Control Conference. Budapest, Hungary, August 23-26, 2009. 1221-1226.

17. Wächter, A. "A tutorial for downloading, installing, and using Ipopt." 2011.

18. Wächter, A. and Biegler, L.T. "On the implementation of an interior point-point filter line-search algorithm for large scale nonlinear programing." Springer-Verlag. 2006.


Abstract�One of the most common sources of fuel is

natural gas. This project offers some ways of increasing gas production that are based on the example of the gas fields in western Ukraine.

�The aim of this research is to find ways to stabilize well operation by relaying on the example of Luybeshivske gas field.

�The results of the research show that the total gas rate of the deposithas has in-creased significantly in comparison to the previous gas production.

Introduction�A lot of natural gas deposits associated with the water system and developed on wa-ter drive mode condition.

As a result there are many complications dur-ing their operation:

ÈWater coning

ÈGas pinching

ÈLiquid loading

ÈHydrates formation

All these complications are very dangerous. They lead to a decrease in wells production and disturb the stability of their work up to a complete stop of natural flowing. Providing accident-free work of the wells and gas col-

Research the processes of increasing wells exploitation efficiencyNazarii Hedzyk

lection system plays an important role at this stage of many gas fields development.

To overcome complications during well ex-ploitation comprehensive approach was con-sidered.

Problem solvingModel of a gas field was built in Schlumberg-er program PipeSim. It includes gas collection system and wells construction.

Field parameters È initial reservoir pressure 7.23 MPa

È reservoir temperature of about 300 K

Èdepth of the formation ranges from 300 to 850m

È initial gas reserves 1.742 bln m3

Èdaily output of the deposit is 215103 m3/d

Èpressure at the entrance of gas condition-ing system equals 0.56 on the low pressure comb and 1.5MPa on the high pressure cumb

È current gas extraction ratio is 50%

È at this stage of development it has 12 wells

* Ivano-Frankivsk National Technical University of Oil and Gas

Þ Ukraine

[email protected]


Nazarii Hedzyk 39

summer / 2012

�Fig. 1 – General view of the model

�Fig. 2 – Geological section of the Luybeshivske gas fi eld

40 Research the processes of increasing wells exploitation effi ciency

�Fig. 3.1 – Graph of the dependence of liquid loading velocity ratio on the distance to other wells

�Fig. 3.2 – Graph of the dependence of liquid loading velocity ratio on the distance to other wells

Nazarii Hedzyk 41

SUMMER / 2012

After running calculations we got the basic performance of wells, which is the same as the actual, after model fi tting.

Pressure, MPaGas rate, msm3/d

Low pressure comb 0,56 45,76

High pressure comb 1,5 169,58

Well 1 0,98 8,52

Well 11 2,71 53,48

Well 12 2,7 19,12

Well 13 2,67 48,73

Well 14 2,65 19,03

Well 15 1,05 19,48

Well 16 1,07 16,24

Well 17 1,25 1,53

Well 1Sh.Lb 4,53 2,72

Well 25 4,9 23,15

Well 26 4,9 2,91

Well 5 3,52 0,44

Total gas rate 215,34

�Table 1 – Results of calculation

Th e main complication during the operation of wells is adgewater admission. Th erefore, one of the factors to pay attention to is lift-ing water from the bottomhole to the surface.

Control of fl uid accumulation in bottomhole includes Liquid Loading Velocity ratio – the

ratio of the speed required for removal of wa-ter to the actual gas speed. If this parameter is less than 1 it means that the liquid is lifted to the surface.

Figure 3 shows the results for the initial mod-el liquid loading velocity ratio value.

As fi gure 3 shows, most wells have problems with fl uid removal.

First of all let’s have a look at the processes which take place in the well. To confi rm the critical gas velocity required for removal of liquid droplets to the surface was considered to study the forces acting on a drop of fl uid in the gas fl ow in the hole.

A drop will be in equilibrium if the forces are equal to each other.

F FDrag Gravity= [ ]1

gd

A Vl g g c( ) [ ]ρ ρπ

ρ ϕ− = ⋅ ⋅ ⋅3

2

612

2

rl , rg – density of liquid and gas, kg/m3;g=9,81 – gravity, m/s2;j – aerodynamic coeffi cient for drop

of water j = 0,44;A=pd2/4 – drop area, m2;Vc – critical gas velocity, m/s.

Vg d

cl g

g

2 4

33=

−

⋅

( )[ ]

ρ ρ

ϕ ρ

Weber number (We) is a criterion of similar-ity in hydrodynamics, which determines the ratio of inertia to the fl uid surface tension. It can be defi ned as:

WeV dc g=⋅ ⋅

=2

30 4ρ

σ[ ]

dVc g

=⋅

30 52

σρ

[ ]

Vg

Vcl g

g c g

22

4

330 6=

−

⋅ ⋅

( )[ ]

ρ ρ

ϕ ρσρ

Vg

cl g

g

=−

⋅

40724

σ ρ ρ

ϕ ρ

( )[ ]

�Fig. 4 – Scheme of forces acting on a drop of liquid in the gas fl ow in the borehole


Vcl g

g

=−

2 7046 824, [ ]r r

r

Gas density in bottomhole conditions can be calculated as:

r rgwf st

wf at wf

P T

z P T=

⋅

⋅ ⋅0 9[ ]

Substituting the values of atmospheric pres-sure, standard density and temperature we obtain:

rgwf

wf

wf

wf

P

z

P

z=

⋅

⋅ ⋅=0 72279

293

0 1013 3006 968 10,

,, [ ]

V

Pz

Pz

c

lwf

wf

wf

wf

=−

2 7046

6 968

6 96811

24,

,

( , )[ ]

r

As we know the density of fluid equal 1100 kg/m3 obtains an equation for the criti-cal velocity:

V

Pz

Pz

msc

wf

wf

wf

wf

=−

4 3942

157 864

6 96812

24,

,

, ( ), [ ]

Similar to the dependence 12 is Turner (13) and Coleman (14) equation:

VP

Pft sc water, ,

( , )

( , ), / [ ]=

−5 321

67 0 0031

0 003113

14

12

VP

Pft sc water, ,

( , )

( , ), / [ ]=

−4 434

67 0 0031

0 003114

14

12

To check the obtained formula let’s make the calculation of the critical velocity using 12 equation and in the software environment PipeSim and compare values.

Well #Critical velocity

using equation, m/sCritical velocity

using PipeSim, m/s

1 11,504 9,0

5 6,134 5,49

11 6,36 5,3

12 6,757 5,23

13 6,931 5,6

14 6,664 5,3

15 9,946 7,6

16 11,27 8,3

17 10,101 9,0

1-Sh.Lb. 6,254 5,75

25 3,955 3,54

26 3,56 3,2

�Table 2 – Results of the critical velocity calculation

To improve liquid droplets removal we need to increase the speed of the rising gas flow, which can be achieved by changing tubes by smaller diameter tubing. For example, with the value of critical velocity we can find the diameter of pipes required for the removal of liquid at the current production rate. If we know the well construction we can calculate minimum required gas rate for well deliquifi-cation.

VQF

z P T

P TQd

z P T

P Tcat wf

wf st ID

at wf

wf st

= ⋅⋅ ⋅

⋅=⋅⋅⋅

⋅ ⋅

⋅ ⋅4

864002p

VQ

d

z P T

P TcID

at wf

wf st

= ⋅ ⋅⋅ ⋅

⋅−14 74 10 156

2, [ ]

dQV

z P T

P TIDc

at wf

wf st

= ⋅ ⋅⋅ ⋅

⋅−3 5 10 163, [ ]

Qd V P T

z P TID c wf st

at wf

=⋅ ⋅ ⋅

⋅ ⋅ ⋅ ⋅−

2

314 74 1017

,[ ]

To calculate those parameters we used Adam-ov’s equation and minimum required gas rate.

Nazarii Hedzyk 43

summer / 2012

ID, sm

Well # Using eq. 12 Adamov’s eq. PivKavNDIgas eq. VNDIgas eq. IFTUOG eq.

1 3,571 3,153 3,715 4,56 5,756

1-Sh.Lb. 1,505 1,58 1,549 2,28 1,838

5 0,585 0,74 0,602 1,1 0,784

11 6,825 6,224 7 7,6 9,9

12 4,443 4,369 4,586 5,4 5,468

13 6,901 6,989 7,126 7,71 9,995

14 4,307 4,198 4,44 5,29 6,969

15 5,239 4,016 5,451 6,2 8,559

16 5,228 4,187 5,433 6,18 8,52

17 1,058 1,14 1,09 1,72 1,642

25 3,548 3,154 3,593 4,52 5,689

26 4,351 3,503 4,519 5,33 7,309

�Table 3 – Results of calculating the internal diameter tubing for wells

Minimum required flow rate, msm3/d

Well # Using eq.PivKavNDIgas

eq.VNDIgas eq. IFTUOG eq.

Req. flow rate eq. 1

Req. flow rate eq. 2

1 20,044 22,287 17,279 9,049 19,607 27,576

5 37,383 42,455 32,341 17,011 36,923 51,938

11 36,073 40,921 31,221 21,311 37,801 48,599

12 33,984 38,377 29,353 27,185 38,062 45,904

13 33,141 37,39 28,626 19,559 34,63 44,275

14 34,449 38,917 29,75 16,112 34,154 46,601

15 23,166 25,873 20,007 10,523 22,741 32,047

16 20,457 22,839 17,7 9,31 20,106 28,508

17 22,812 25,47 19,701 10,362 22,391 31,369

1-Sh. 36,677 41,642 31,748 27,713 40,658 50,561

25 57,352 67,225 49,879 22,427 55,489 76,726

26 21,94 24,475 18,946 9,965 21,528 30,636

�Table 4 – Results of calculating the minimum required flow rate

The results obtained by different depend-encies are in the same range. Tables 4 and 5 show the results necessary for the wells sta-bilization and improve the fluid removal – we need to change the tubing.

Another way to increase gas rate and to in-crease the speed of movement necessary for removal of fluid is to reduce pressure on the wellhead.

44 Research the processes of increasing wells exploitation efficiency

At this time the pressure on high pressure combs is about 1.5MPa, and on the low pres-sure combs – 0.56MPa. Let’s consider the ef-fect of reducing these pressures at wells and gas collection system work.

Pressure, MPa Gas rate, msm3/d

0,56 45,76

0,46 55,04

0,36 61,8

0,26 66,3

0,16 69,18

0,06 71,11

0 71,78

�Table 5 – Dependence of the well production of pressure on low pressure comb

Pressure, MPa Gas rate, msm3/d

1,5 169,58

1,4 179,73

1,3 190,02

1,2 200,17

1,1 210,29

1 220,22

0,9 230,51

0,8 239,78

0,7 247,02

0,6 254,64

0,5 262,51

0,4 269,79

0,3 275,75

0,2 279,73

0,1 282,79

0 284,27

�Table 6 – Dependence of the well production of pressure on high pressure comb

�Fig. 5 – Graphical dependence of fl ow rate for pressure on low pressure comb

Nazarii Hedzyk 45

SUMMER / 2012

�Fig. 6 – Graphical dependence of fl ow rate for pressure on high pressure comb

�Fig. 7 – Graphical dependence of absolute rate increased low pressure comb from the pressure of this combs


To determine the optimum value of pressure drop at comb graphs of the absolute rate in-creased on combs for pressure were built.

After solving equation systems:

y x

y x

y x

y x

= += −

= += +

12 16 0 407

23 9 2 952

9 060 1 937

3 004 6

, ,

, ,

, ,

, ,,[ ]

37418

For low pressure comb optimum value of pressure, it should be reduced it is 0.286MPa. Production rate will increase by 21.24 msm3/d compared with the current value. For high pressure comb optimum value of pressure, it should be reduce equals 0.7326MPa. Produc-tion rate will increase by 73.42 msm3/d com-pared with the current value.

Well #Initial gas

rate, msm3/d

Gas rate after pressure

reduction, msm3/d

1 8,52 12,04

11 53,48 77,47

12 19,12 29,93

13 48,73 71,46

14 19,03 34,22

15 19,48 28,33

16 16,24 23,06

17 1,53 1,88

1-Sh.Lb. 2,72 3,1

25 23,15 24,51

26 2,91 14,91

5 0,44 0,63



TOTAL 215,34 321,55

�Table 9 – Results of the rate increased after pressure reduction

�Fig. 8 – Graphical dependence of absolute rate increased high pressure comb from the pressure of this combs

Nazarii Hedzyk 47

SUMMER / 2012

To sum up, it should be said that the pressure drop at combs increases the production rate of 106.21msm3/d in comparison to the current value. Reduced pressure at this stage of devel-opment is justifi ed due to gas compression installation operation which entered in 2011.

Reduced pressure at the entrance to gas con-ditioning system allows us also to improve the removal of fl uid from the bottom to the surface.

Figure 9 shows that in wells 5, 25, 26, 17 and 1-Sh.Lb. fl uid has still been accumulating at the bottom. Th erefore, it is proposed to re-place tubing on pipes with smaller diameters in these wells, the value of which is given above, or to consider the possibility of two-stage column in these wells.

Well # L1,m L2,m d1,m d2,m

1-Sh.Lb. 51,692 188,308 0,062 0,0503

25 289,445 280,505 0,0403 0,0352

26 86,842 178,508 0,0352 0,0264

�Table 11 – Results of the two-stage tubing column cal-culation

�Fig. 9 – Graphical dependence of the liquid loading velocity ratio

�Fig. 10 – Scheme design of two-stage tubing column


�Fig. 11 – The value of erosional velocity ration for the wells

Nazarii Hedzyk 49

SUMMER / 2012

As a result of pressure reducing on the heads of wells and the installation of two-stage tub-ing column on individual wells we received a significant increase in the production rate and a stabilization of the work of wells, as Table 12 shows. The effective diameter for wells 17 and 5 is too small to calculate two-stage tubing column. Therefore it is better use surfactants in these wells.

Well #Initial gas

rate, msm3/d

Gas rate after changes, msm3/d

1 8,52 11,77

11 53,48 77,59

12 19,12 29,87

13 48,73 71,47

14 19,03 34,15

15 19,48 28,34

16 16,24 23,06

17 1,53 1,88

1-Sh.Lb. 2,72 3,1

25 23,15 20,26

26 2,91 15,28

5 0,44 0,63



TOTAL 215,34 317,41

�Table 12 – Calculation results

As it is known, the increase of gas speed leads also to the increase of the erosion processes on the downhole and surface equipment. That can cause accidents. Erosional velocity ration allows us to control these processes.

As for gas collection system, the possibility of hydrates formation and fluid accumulation have been considered in previous sections.

As a result, a deeper analysis was proposed to separate pipelines from 12 and 14 wells, and wells 5 and 1-Sh.Lb.

According to the results of calculation of the total gas flow rate separate pipelines from 12 and 14 allows us to increase gas

rate for 4msm3/d.

Conclusions for wells operation improvement on the Lyubeshivsky gas fieldNowadays, the problem of ensuring the stable operation of wells and gas collection system is very important.

As a result of the research an equatation for determining the critical gas velocity was ob-tained. Also, there was found an algorithm of the minimum required gas flow and an inter-nal tubing diameter.

Calculation results were confirmed by mode-ling in Schlumberger program PipeSim. Us-ing this software optimum pressure in combs was defined, which allows us to increased pro-duction rate and improve the process of fluid removal.

In those wells where the above actions failed to produce the desired effect, the establish-ment of two-step tubing column was pro-posed.

Only using a comprehensive approach to overcome liquid accumulation gives the best results. For example, after introducing all the above measures gas rate has increased from 215.34msm3/d to 317.41msm3/d. It allows also the stabilization of the operation of a well.

50 Research the processes of increasing wells exploitation efficiency

Abstract�Heavy oil is generally defined as uncon-

ventional oil resources that have high vis-cosity (higher than 10 CP) and API gravity less than 20°, and it is also associated with bitumen in oil sands. Heavy oil has a high content of asphaltenes, heavy metal, sul-phur and nitrogen, thus it requires special refining process as well as special recovery methods due to its high viscosity. As a re-sult, heavy oil production is less profita-ble comparing to light-oil production. But nowadays, the development of heavy oil reserves is increasing in order to meet the future demands for energy. With new tech-nologies implemented, a variety of heavy oil recovery methods is already in use. Most of these methods, and some promising methods that don’t have broad industrial application now, are reviewed in this paper.

�Right now, when the amount of con-ventional oil resources is declining and the world’s energy demands increase, it’s clear that we have to find some other sources of energy. Let’s put aside renewable and nucle-ar power sources and our choice number one will be unconventional hydrocarbon resourc-es. According to Stark et al. [1] the amount of proved unconventional oil resources is more than three times higher than the amount of

conventional oil resources, and heavy oil is a major part of all unconventional oil resourc-es. These reserves are well-known and plenty of methods that allow us to produce heavy oil more economically effective were developed. However, note that all of them are very cost-efficient. I’ll list these enchanted recovery methods as well as their description in this work.

CHOPS�CHOPS – Cold Heavy Oil Production with Sands, widely used in Canada, Kazakhstan, China and Venezuela. CHOPS provides rea-sonable recovery factors (15-20%) and pro-duction rate(20-300 bbl/day), In 2002, Cana-da's oil production from all sources was ~ 2.9 x 106 b/d, of which more than 600,000 b/d was CHOPS production. Heavy oil reservoirs suit-able for CHOPS are located in unconsolidat-ed or weakly consolidated sands where sand mobilization can be easily triggered and sand influx can be easily sustained for the produc-tive life of the well [2]. Of course, this meth-

Enhanced Heavy Oil Recovery MethodsIlia Gurbanov

* Tyumen State Oil and Gas University

Þ Russia

[email protected]


Ilia Gurbanov 51

summer / 2012

od is applicable only when the oil formation is within mineable depth, otherwise, we have to use one of the in-situ methods described below.

Steam drive is a process of injecting steam into the well, which reduces the viscosity of heavy oil. Steam drive provides ROIP up to 70%, 30-60% in general [3]. Th ere are several methods for organizing this process, such as Steam-Assisted Gravity Drainage (2 horizon-tal wells, injector and producer), Cyclic Steam Stimulation (injection-production through one well) etc. Steam driven methods may be combined with other methods, for example ES-SAGD (mixing solvent in steam when per-forming SAGD injection) allows us to recover up to 70% of oil in place [4].

In-situ combustion. Burning some of the oil in situ (in place), creates a combustion zone that moves through the formation toward production wells providing a steam drive and an intense gas drive for the recovery of oil. To provide enough oxygen for the reaction, air or enriched air (with ~35% oxygen) is inject-ed into the well. When used on the horizon-tal well, and operation is going smooth, this method may help us to recover up to 78% oil in place [5]. However, it is not a typical case and, usually, oil recovery index using this method lay between 30-40%.

Th ermal methods are the most eff ective tech-nique for heavy oil recovery. However, many reservoirs' conditions restrict the application of thermal techniques, such as thin pay thick-ness or deep reservoir. Th us, a number of non-thermal in-situ methods were developed.

Carbon dioxide injection – injection of CO2 in-situ, usually during water-and-gas (WAG) pro-cess allows us to add 5-12% of ROIP to antici-pated total production [6]. Besides, it is a way of getting rid of the CO2, which cause green-house eff ect. It may be quite economically profi table sometimes. For example, in Nor-way, due to high emission fees – it’s cheaper to set up a CO2 injection facility than pay an emission fee, plus you receive enhanced oil re-covery.

Alkaline/Surfactant fl ooding - Heavy oils usu-ally have a relatively high content of organic acids, which can be neutralized by alkalis to form in-situ surfactants. With the assistance of these in-situ surfactants, an oil-in-water emulsion with a much lower viscosity than heavy oil can be generated. In this way, the heavy oil is entrained in the water phase and produced out of the reservoir. Tertiary oil re-covery for this method used on heavy oils will be from 20 to 30% ROIP [7].

Polymer fl ooding is a well-recognized tech-nique of mobility control for conventional

�Fig. 1 – Viscosity reduction using Irradiation

52 Enhanced Heavy Oil Recovery Methods

oils, which could be a potential method for enhanced heavy oil recovery by improving the sweep effi ciency and reducing water mobility. According to the lab tests, tertiary oil recov-ery for this method varies from 4 to 12% for heavy oil of 1,450 mPAs.[8].

Not all of these methods are widely used, but the technology behind them is quite clear. However, there are 2 more methods which are quite promising, but do not have broad indus-trial application yet.

Electromagnetic heating is another ther-mal method based on using electromagnetic waves to heat the formation. If the reservoir is shallow, the reservoir pressure may be too low to maintain a steam drive. If the reservoir is too deep, wellbore heat losses become ex-cessive. In-situ combustion does not have the same depth constraints as steamfl ooding, but its success depends on crude composition. Each of the conventional thermal methods requires suffi cient reservoir transmissibility to achieve fl uid injection. EMH has the poten-tial for overcoming some of the limitations of conventional thermal methods. But there is another technology that is applicable for sim-ilar conditions and is more perspective.

And that technology, which deserved a thor-ough description, is hydrocarbon enhance-ment electron beam technology. Ionizing ac-

cidents, as a way to refi ne viscous heavy oil residuals, have been observed to be a promis-ing and effi cient way of providing higher se-lectivity, quality and quantity of treated feed (Aksenova et al.). With current technologies simultaneous heating and irradiation gives us the best result. Th e good thing about elec-tronic beam emission is, it is more eff ective than just heating (Fig. 1) after the treatment oil does not regain part of its viscosity, like it does if we use pure thermal methods (Fig. 2). Note that the tests were made with diff erent fl uid.

Th e crude composition is also better [9]. Th us, this technology is applicable for changing the properties of the oil in-situ as well as the re-fi ning process after production (the way you

�Fig. 2 – Viscosity reduction using Irradiation

�Fig. 3 – Principle of using electron beam technology for oil refi ning

Ilia Gurbanov 53

SUMMER / 2012

References1. The Role of Unconventional Hydrocarbon Resources in Shaping the Energy Future (P.H. Stark,

K. Chew, and Bob Fryklund, IHS; 2007).

2. How Much Oil You Can Get From CHOPS (G. Han, M. Bruno, M.B. Dusseault; 2004)

3. The Efficiency of Enhanced Oil Recovery Techniques: A Review of Significant Field Tests (Vello A. Kuuskraa, Edgar C. Hammershaimb, George Stosur; 1994)

4. ES-SAGD; Past, Present and Future (Bryan Orr, 2009)

5. In Situ Combustion (ISC) Process Using Horizontal Wells (Greaves, M. and Al-Shamali, O.; 1996)

6. Enhanced Oil Resources Inc. website, 2000

7. Alcaline/Surfactant Flood Potential in Western Canadian Heavy Oil Reservoirs (Q. Liu, M. Dong, S. Ma)

8. A Laboratory Study of Polymer Flooding for Improving Heavy Oil Recovery (J. Wang, M. Dong, 2007);

9. Utilization of Charged Particles as an Effective Way to Improve Rheological Properties of Heavy Asphaltic Petroleum Fluids (Masoud Alfi, Paulo F. Da Silva, Maria A. Barrufet, Rosana G. Morei-ra)

10. Laboratory Investigation of E-Beam Heavy Oil Upgrading (D. Yang, J.Kim, P.C.F. Silva et al.)

can see it on the Fig. 4, which is a lot easier to implement.

Here are some specifications of the machine, that can be used for this process, as well as the cost of it’s maintenance and installation [10]. We also should keep in mind that the more money we spend on applying new tech-nology to the field, the less this technology costs for us later. Usually the total expenses drop down to 20-30% after first year since in-troducing new technology to the field and in-dustry

Beam Power, MeV 2,50

Beam Power, kW 100

Beam Current, mA 50

Total Power Consumption, kW 148

Power Efficiency 68

Process Volume bbl/day 760

�Table 1.1

Machine 0,90

Installation 0,10

Shielding 0,35

Total 1,35

�Table 1.2

If we consider drawbacks of other methods written above, we can easily see that these new technologies also have their field of ap-plication and their further development should be economically profitable.

54 Enhanced Heavy Oil Recovery Methods

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Join us!youngpetro.org/[email protected]

�East meets West is an international stu-dent petroleum congress organized by AGH University of Science and Technology SPE Student Chapter. Th e history of it goes back to 2010 when the fi rst edition of the con-gress had place.

East meets West is held in the area of AGH University of Science and Technology in Kra-kow and lasts more or less three days during which students from diff erent countries of the world can present their achievements in the fi eld of petroleum-related study and their own research. Th e congress attracts also many well known professors from foreign universi-ties as well as the representatives of the in-dustry including the biggest world petroleum

56 East meets West

EmW is the most exciting congress I have attended. It’s a place for Young Engineers to show their talent. Within those few days in Krakow, I saw commitment, I saw hard work, I saw friendship, and I left with a message in my heart 'What is worth doing, is worth doing well'.

Congrats to the organizers of the congress. I won't forget the beautiful monumental structures of Krakow city and the hospitality of the host. Many thanks to the nu-merous sponsors and the students of SPE AGH Student Chapter. I look forward to the next edition of EMW.

— Richard Awo (TU Claustahl, Germany)

"

and service companies. Owing to their gener-osity the congress is getting bigger and more professional year by year.

EmW – 212 editionTh is year, 25-27th April in Krakow, Poland had place the World biggest student petroleum

congress. Once again it was organized by AGH UST SPE Student Chapter. Th e congress at-tracted almost 90 students from all over the world including countries of Europe, Asia and South America. It also gathered many pro-fessionals from diff erent companies of the petroleum industry who could present their latest technologies, explain the companies’ policy and goals and show us their engage-ment in current oil and gas issues. And, of course, through all that, encouraged students to search for some further information and, maybe, one day also for work.

Although the congress started on 25th of April most of our guests came to Krakow a day or two earlier. Th ey were accommodated in Olimp dormitory at our University campus.

Owing to our chapter members’ involvement small groups were formed and our guests were shown round the wonderful city of Kra-kow. East meets West is mainly focused on students. We really try to do our best to make everybody feel comfortable when coming to us. So the fi rst challenge was to make our guests feel free in the company of each other.

Th at’s why the evening before the offi cial con-gress time we organized the Ice Breaker party. It gave all the participants the opportunity to get to know each other a bit better so as they could feel less stressed the following days. We really appreciate the number of young people from diff erent corners of the world who came to take part in East meets West congress.

On 25th April everything started with Lead-ership Workshops – Student Chapters Ap-proaching Pivot Point.

Th en, there was an offi cial opening ceremony. We could hear the speech of our special guest – SPE International President 2011 – Alan La-bastie. Th ere was also a couple of words by the vice-rector of AGH UST – Jerzy Lis, the dean of AGH UST Faculty of Drilling, Oil and Gas

57

SUMMER / 2012

– Andrzej Gonet and AGH UST SPE Student Chapter President 2011/2012 – Anna Ropka. In the evening, after the offi cial opening part, there was East meets West Gala Dinner which had place in ‘Pod Wawelem’ Restaurant near Krakow main square. Our guests could taste a number of traditional polish cuisine delicacies and spend nice time on chatting.

Th e second day of the congress – Th ursday 26th April – was partly devoted to HR Pres-entations of our sponsor companies includ-ing Schlumberger, Halliburton, United Oil-field Services, Orlen Upstream, San Leon Energy and National Oilwell Varco. Th e repre-sentatives of the companies told us what the work looks like, what it demands and what we can expect when we decide for this kind of job. It was a great opportunity for students to get a bit closer to the topic of their future. After the lunch there was a Technical Panel Session during which the professionals pre-sented their ways of dealing with challenges

they face every day. Th ey also presented some new advanced technologies applied recent-ly in the industry. In the evening everybody gathered in front of the congress hall and left for Manor House in Tomaszowice for the Offi -cial Banquet of East meets West congress. Th e Banquet proceeded even better than we could have expected. We were conversing, watching the live performance of one invited singer and even dancing to some old school pieces, eve-rybody seemed to have a really great time.

27th April. Th e last day of the congress was the most meaningful to all the participants. Th e main feature was a Student Paper Contest which gave the students a signifi cant chance to present their research results to a very wide audience including their future potential em-ployers. Th ey also competed with colleagues from other universities and in the end the best performances were chosen and awarded with prizes. Th e topics of presentations var-ied from geological and mineralogical issues

58

through consumption of energy, explora-tion and fracturing to the technical aspects of drilling concerning equipment and safety rules. Before the paper contest started, there had been a poster session which also gave the students an opportunity to share their re-search with others as well as their views and opinions on certain topics. Th ey could elabo-rate on their posters and defend their ideas to our jury whose task was to choose the best pieces of work. It was a diffi cult task because the level of presented knowledge and interest was quite high.

Th e awards for the best posters and papers were presented during the Offi cial Closing Ceremony by AGH UST SPE Chapter's presi-dent and the Chairman of “Drilling, Oil, Gas – Science and Traditions” foundation with which our chapter cooperates very closely. In the evening all the participants were invited to take part in our fi nal party in Diva club where we could take rest after three days of

hard work, new experiences and lots of emo-tions.

We could write dozens of reports like this but, believe it, or not, it is just impossible to describe with words the extraordinary am-bience which accompanied those couple of days when so many entirely strange people turned out to have so much in common at the end. We believe that East meets West congress is a great opportunity for students to exchange knowledge with the peers, to get acquainted with what is going on in the in-dustry and to talk with the representatives of petroleum companies. Needless to say, it also gives the opportunity to meet new valuable people and to form a lot of lasting friendships. We fi nd it really rewarding that so many people – both students and profes-sionals – shown up and enjoyed the con-gress. With a support like this we are sure that it is really worth our dedication and we will try to do our best in coming years.

AGH UST SPE Student Chapter

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SUMMER / 2012

18–20 MARCH 2013 / GALVESTON, TEXAS, USAGALVESTON ISLAND CONVENTION CENTER

E&P HEALTH / SAFETYSECURITY / ENVIRONMENTAL

SPE AMERICAS 2013

CONFERENCE

www.spe.org/events/hsseSociety of Petroleum Engineers

Environmental Student Symposium

LET’S SHAPE THE FUTURE TOGETHER

Canadian Canadian Canadian DreamDreamDream�In June, Polish chapter have visited Cal-

gary to attend Global Petroelum Show 2012 – one of the world’s biggest drilling exhibi-tion. Calgary is the biggest city of Alberta and is located in the southern part of the province.

Shortly after landing in Canada, we were very surprised with the size of the city – the popu-lation is comparable to Krakow, but the city is much more spread and covers much larger area, what makes Calgary seem bigger than it really is. Th e city perfectly joins the new west rodeo tradition with modern, developing life-style. Calgary strikes as a very friendly, mul-ticultural and multinational place open for everyone.

Canadian Canadian Canadian Canadian Canadian Canadian Canadian Canadian DreamDreamDreamDreamDreamDreamDreamDreamTh e very fi rst point of our stay in Canada was the Global Petroleum Show, which took place at Calgary Stampede Park from 12th to 14th June. Several huge halls fi lled with all-over-the-world drilling companies presenting their achievements and off ers looked far more than impressing. Especially the outside part of the exhibition, where drilling rigs, trucks and many other tools used in drilling industry have made this event worth to visit.

Apart from admiring the exhibition, we’ve also managed to present our SPE Student Chapter’s achievements. We’ve found sever-al companies really interested in ‘East meets West’ and YoungPetro projects, which makes opportunities to establish our presence also

SUMMER / 2012

in North America, where our chapter didn’t act so far. Th ree days of exhibition allowed us to meet plenty of cordial and open people, who very eagerly presented their company services as well as their knowledge, experi-ences and points of view regarding the future of oilfi eld industry both North America and for Europe as well.

During our stay in Canada, we also managed to visit our colleague Kuba Witek, who has graduated from AGH University and is now working for Schlumberger in Red Deer as a fi eld engineer in Fracturing Department. Th anks to Kuba’s courtesy we were able to see the Schlumberger base and learn how the day of a fi eld engineer looks like. Moreover we’ve

seen the tools used by Schlumberger in Can-ada already, with an extra attention paid to these which are used in fracturing, what was very interesting for us, as the fracturing jobs are about to start in Poland soon.

Our group was also invited to Nisku – a small city located close to Edmonton, where a drill-ing contractor Ensign Energy has its offi ce. Th anks to Mr Ron Pettapiece we had a great opportunity to see one of the company’s rigs. Our guide has shown us each section of the rig, giving us complex comments and descrip-tions simultaneously. Apart from the rig it-self, we have also visited factories belonging to the company to see how the rig compo-nents are made from the very beginning. Af-

63

summer / 2012

Thank Thank Thank YouYouYou

terwards we paid a short visit to Edmonton – the capital city of Alberta Province.

Trip to Calgary, apart from enjoying very rich technical part, allowed us to taste a little bit of Canada and do some sightseeing. Spending several days in Calgary let us explore the city and admire the modern architecture of the downtown, walk through calm and well-main-tained parks and try local, Canadian cuisine.

One of the most impressing experiences was the rodeo organized at Stampede Park togeth-er with the Global Petroleum Show. It might be a little surprising, but rodeo is a very im-portant part of Canadian culture – moreover – it has 100 year old tradition in Calgary already.

Trip to Calgary ZOO is also worth mentioning, as the ZOO has recently been chosen as the best in the whole Canada. Located partially on a huge island, the ZOO is divided into several sections, showing animals from all over the world living in small ecosystems similar to the natural. Th e undeniable attraction of the ZOO – especially for kids – is a dinosaur park with real-sized dinosaurs sculptures.

Each of us highly enjoyed our stay in Canada. What is more – we truly believe that it will also turn out to be profi table soon. We would like to seize the opportunity and once again thank to our generous sponsors, but for whom we would not be able to arrange this trip.

Thank Thank Thank YouYouYouWe would like to thank ORLEN Upstream for covering the costs of our flights, to Schlumberger for paying for our accommodation in Calgary and Ensign Energy for a great hospitality and technical support. We hope that the maintained cooperation and the gained experience will help to continue our chapter’s development and our students will be permanent visitors events, such as the Global Petroleum Show.

Call for Papers�YoungPetro is waiting for your paper!

Th e topics of the papers should refer to: Drilling Engineering, Reservoir Engineering, Fuels and Energy, Geology and Geophysics, Environmental Protection, Management and Economics

Papers should be sent to [email protected]

For more information visit youngpetro.org/papers

youngpetro - 4th issue - summer 2012

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