YoungPetro - 4th Issue - Summer 2012 by Young Petro

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We are the world’s largest oilfield services company1. Working globally—often in remote and challenging locations—we invent, 1. design, andlargest apply technology to helpcompany our customers find We areengineer, the world’s oilfield services 1. and produce oil and gas safely. Working globally—often in remote challenging locations—we invent, We are the world’s largest oilfieldand services company design, engineer, and apply technology to help our customers find invent, Working globally—often in remote and challenging locations—we 1. We are the world’s largest oilfield services and produce oil and safely. design, engineer, andgas apply technology to helpcompany our customers find 1. We are the world’s largest oilfield services company Working globally—often in remote and challenging locations—we and produce oil than and gas safely. We need more 5,000 begin dynamic careers in invent, Working globally—often in graduates remote andtochallenging locations—we invent, design, engineer, and apply technology to help our customers find the following domains: design, engineer, and apply technology to help our customers find and produce oil than and gas safely. We need more 5,000 graduates to begin dynamic careers in and produce oil and gas safely. n Engineering, Research and Operations the following domains: We need more than 5,000 graduates to begin dynamic careers in n Geoscience and Petrotechnical the following domains: n Engineering, Research and Operations n WeCommercial need moreand thanBusiness 5,000 graduates to begin dynamic careers in We need more Research than 5,000and graduates to begin dynamic careers in n Operations n Geoscience and Petrotechnical theEngineering, following domains: the following domains: n Geoscience and and Business Petrotechnical n Commercial n Engineering, Research and Operations Engineering,and Research and Operations n Commercial Business n Geoscience and Petrotechnical n Geoscience and Petrotechnical n Commercial and Business n Commercial and Business

Who Who are are we? we? Who are we looking for? Who are we looking for? Who are we looking for? Who Who are are we we looking looking for? for?

What will you be? What will you be? What will you be? What What will will you you be? 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.

This is the message which Phil Rae â&#x20AC;&#x201C; 2011/2012 SPE Distinguished Lecturer is traveling the world with. It is difficult 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 efficient, safe or ethical. The problem is that we wanted a revolution, 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 infinite abilities to improve the industry. Fortunately the first decade of XXI century has brought us a simple and rather overlooked solution â&#x20AC;&#x201C; natural gas, which proved to be cleaner, cheaper, more efficient and with constantly developing E&P technologies just easier to extract. For the first time in more than 100 years we are looking on a candidate which is to become a new primary 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.

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Editor's Letter

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.

SUMMER / 2012

Editor-in-Chief Wojtek Stupka chief@youngpetro.org Editors Julia Brągiel Iwona Dereń Przemysław Gubała Kamil Irnazarow Jakub Jagiełło Alexey Khrulenko Krzysztof Lekki Patrycja Szczesiul Jakub Szelkowski Michał Turek Liliana Trzepizur Barbara Pach Joanna Wilaszek Jan Wypijewski Kacper Żeromski editors@youngpetro.org Art Director Marek Nogiec art@youngpetro.org Social Media Kacper Malinowski social@youngpetro.org Photo KSAF AGH www.ksaf.pl

Published by An Official Publication of

The Society of Petroleum Engineers Student Chapter P o l a n d • www.spe.net.pl

Anna Ropka - Chairman

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

Assessment of Satellite Imaging as Monitoring and 13 Verification Technology in the In Salah CO2 Storage Site Ergene Suzan Muge, Turanli Ayse Merve

Production Optimisation of the Two Phase Flow 2 Reservoir in Secondary Recovery Phase Using Simultaneous Method and Interior Point Optimiser Dariusz Lerch

Research the Processes of Increasing 3 Wells Exploitation Eﬃciency Nazarii Hedzyk

Enhanced Heavy Oil Recovery Methods 1 Ilia Gurbanov

East meets West  Canadian Dream 1

SUMMER / 2012

Necessity of Energy Cooperation

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

Abstract Crises and difficulties in the economies of some of Eastern Partnership countries (especially Ukraine and Belarus) has increased the threat to their independence due to the growing energy dependence on Russia. Because of his fact energy co-operation of the Eastern Partnership countries with the participation of the bordering countries of the European Union is extremely important today. The Eastern Partnership was officially launched in 2009 when the Czech Republic 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 republics: Ukraine, Moldova, Armenia, Azerbaijan, Georgia and Belarus. One of the planned spheres of future cooperation was energy sector. 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 partnership 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. Probably one of the reasons for Russia’s dissatis-

**Belarusian State Economic University ÞÞBelarus askriba@gmail.com  University  Country  E-mail

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 interests 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 projects. However, serious internal political and social problems and contradictions, as well as economic instability, did not allow this country 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 decade of the XXI century Ukraine turned out to be in an uncertain position. On one hand, there are natural obstacles of its desire to cooperate 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-

Andrew Skriba 9

Fig. 1 – Current and proposed oil import system 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 economic 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 level of integration with Russia, in their opinion, would mean a significant limitation of national sovereignty. Belarusian-Russian contradictions 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 Ossetia. Furthermore Belarusian leadership has demonstrated a desire to work more closely with European countries and, moreover, participated in Eastern Partnership. Disputes between Russia and Ukraine and Russia and Belarus have exposed some undesirable consequences of European dependence on Russian energy resources.

In the late 2009 - early 2010, when the Belarusian-Russian energy contradictions reached their peak, cooperation between Belarus and Ukraine in the energy sector came to a qualitatively new level. Against the background of intensification of dialogue between the two countries on the topic of energy security, Belarusian oil contracts with Venezuela and Ukrainian transit infrastructure – Odessa-Brody oil pipeline should be taken into account. 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, Belarusian authorities signed contracts with alternative oil exporters. Our main partner in 2010 became Venezuela, where Belarus had already started oil extraction. The 2010 agree-

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 consumption and processing. Therefore, Belarus signed an agreement on oil supplies from Venezuela and studied the logistics of its transit through Lithuania, Estonia and Ukraine. However, the price of the imported 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 Belarusian-Ukrainian energy dialogue have increased considerably. Firstly, the Belarusian side used railroad oil deliveries through Ukrainian territory more actively than in other states in 2010. Second-

Necessity of Energy Cooperation

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 dutyfree oil. Finally, at the end of 2010 Belarus and Ukraine began to discuss joint projects concerning the construction and use of transit pipeline infrastructure for the supply of Venezuelan oil to Belarus (Odessa-Brody oil pipeline, building a new one from the Kremenchug Oil Refinery (Ukraine) to the Mozyr Oil Refinery (Belarus)). After the European financial crisis in 20102011 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 agreement on free trade zone with the European

Fig. 2 â&#x20AC;&#x201C; Eastern European oil transport routes

Andrew Skriba 11

Union, officially stated that it was also considering such a possibility. Russia clearly demonstrates all the advantages and disadvantages of participation in these geopolitical projects giving Belarus as an example. Thus, in early 2012 the price of natural gas for Belarus was 2.5 times lower than for Ukraine. Russia supplies Belarus with dutyfree 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 circles 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 energy security with Belarus and Ukraine in the framework of Eastern Partnership. Therefore, in addition to the existing pipelines 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 cooperation).

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 Poland 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 cooperation 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 technologies of this process, while Poland and Ukraine possess transitional infrastructure and demand for alternative (non-Russian) oil products 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 political will of these countries, European investment in the completion of the Odessa-Brody pipeline to Plotsk and Gdansk. Once accomplished, it could enhance the energy security of all three countries, Central Europe in common and bring the political positions and economic interests of the leadership of Belarus, Poland and Ukraine together.

summer â&#x20AC;&#x2030;/â&#x20AC;&#x2030;2012

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

Ergene Suzan Muge, Turanli Ayse Merve 13

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

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 greenhouse gas is CO2. For this purpose, CO2 capture and storage technology is emerged as an effective option. In Salah CO2 long-term storage project is the world’s largest onshore project in Algeria since 2004. Krechba 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, geomechanical and production techniques are used to monitor CO2 movement in this joint industry project (JIP). In order to assess the satellite imaging as a monitoring technique, the cost-benefit of each technique is considered by using Boston Square decision chart. According to this chart, this monitoring technique is regarded as a feasible alternative. In this paper, overview of all literature surveys 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

**Middle East Technical University ÞÞTurkey mergene@metu.edu.tr merve.turanli@metu.edu.tr  University  Country  E-mail

obtained from satellite imaging with the other monitoring data is indicated to discuss whether satellite imaging is a new approach for monitoring CO2 movement.

Introduction The number of governance and private sectors that consider the dilemma between energy requirements in any part of life and human based environmental problems is increasing rapidly. The most harmful and widespread environmental 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 capture and sequestration technologies, which has accelerated greatly in the past decade, may play an important role in addressing this

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Assessment of Satellite Imaging as Monitoring and Verification Technology

issue. Carbon capture and storage (CCS) is a plan to mitigate climate change by capturing carbon dioxide (CO 2) from large point sources such as power plants and subsequently storing it away safely instead of releasing it into the atmosphere. CCS process includes several steps such as capture sequestration, transportation, storage and monitoring. The 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-effective CO₂ monitoring techniques is satellite imaging, specifically interferometric synthetic aperture 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 successive satellite passes. Besides, InSAR can be used to monitor natural hazards; our survey 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 offshore CO 2 storage project and the world’s largest onshore CO 2 storage project the Krechba site within the InSalah gas field development are conducted (Fig 1). In the world lots of CCS projects are completed with great success while some of them are being conducted even today. One of the hugest and well known CCS projects is InSalah Gas Project which will be evaluated in detail during this project. The In Salah project in Algeria is an industrial scale CO 2 storage project that has been in operation since 2004. There is a limitation for the CO 2 content which should be applied by producers. For this pilot site which have a CO 2 content of 5-10%, CO 2 percentage is targeted to be reduced to specifically 0.3% [5]. In Salah CCS Project is one of the international 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 technology provider private sector around the world. The main objectives of JIP are: to guarantee long term and secure geological storage of CO 2 that can be economically conducted with short term monitoring technologies, to show that geological storage of CO 2 is a good alternative for GHG-mitigation to the stakeholders, and to be a pioneer to create new regulations and verification technologies of the geological storage of CO 2. In order to provide scientific network by sharing the findings with regulators, policy makers and non-governmental organizations, JIP is developed to mitigate the effects of climate change.

Geology Of In Salah Stratigraphy The main units in the region are Carboniferous (C10) Tournasian sandstone, which in Fig. 1 – Location map of In Salah field[5]

Ergene Suzan Muge, Turanli Ayse Merve

Fig. 2 â&#x20AC;&#x201C; Columnar section of Krechba region[2] cludes tight sandstone and siltstone (C10.3) and sandstone (C10.2), and lower caprock composed of silty shale with fractures. Additionally, as it can be seen in the Figure 2 the main reservoir unit is the (C10.2) sandstone whose thickness is 20-25m and placed in 1880m depth. This formation is overlain by tight sandstone and siltstone formation (C10.3) with a thickness of 20m. Carboniferous 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 constituteCO 2 storage complex at Krechba[2]. The injection of CO 2 in the Krechba Field is done into a fractured sandstone reservoir whose porosities ranging from 11-20% and average permeability value is around 10md. This reservoir is capped by nearly 950m Car-

boniferous mudstones. This mudstone is overlain by 900m sandstone and mudstones which includes the regional potable aquifer. The boundary between the Carboniferous and Cretaceous units is Hercynian Unconformity with a thickness of 3m overlain by thin impermeable anhydrite unit. This unit can be considered as a final top seal [6]. There are 3 injection wells (KB-501, KB-502, and KB-503) and5 production wells (KB-11, KB-12, KB13, KB-14, and KB-15). Their locations 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

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Assessment of Satellite Imaging as Monitoring and Verification Technology

Fig. 3 â&#x20AC;&#x201C; Schematic Representation of Krechba [9] to CO 2 migration within relatively low permeability sandstones and shales [4]. The thick mudstone caprock sequence provides an effective flow and mechanical seal for the storage system although fractures at the reservoir/aquifer level. The Krechba site can be characterized by a low relief anticlinal structure without any significant fault systems. On the other hand, small fractures and faults were realized after drilling stage in 2002. CO 2 storage complex in Krechba contains a set of fractures and small faults. Furthermore, in the region as strikeslip stress regime is dominant where the maximum horizontal stress (NW-SE) is greater than the vertical stress. The role of faults and associated fractures is important in controlling the CO 2 plume distribution and the associated pressure development and multi-phase flowprocesses [4]. Injection wells (KB-501, KB-502, and KB-503) and gas production wells are drilled across principal open fracture set (maximum horizontal 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 subsided areas are tried to be observed and, as expected,surface uplift was detected around the injection wells, while subsidence was detected in the gas production area. According to 3D seismic survey, which is conducted to understand the gas reservoirs, minor faults are observed in the northern part of Krechba field (Fig. 5). This is the significant evidence of formation of lobes around the KB502 injection well obtained from the InSAR data which will be explained in detail in the next section. This fault may help to explain an enhanced pathway of migrating CO 2 from the KB-502 injector towards the NW.

CCS Activities In Krechba Krechba CCS pilot site which is not oriented to gain commercial benefit from the CO 2 storage is selected by Carbon Sequestration Leadership Forum (CSLF) as one of the three worldwide industrial scale monitoring and verification site. The scheme of Krechba in-

Ergene Suzan Muge, Turanli Ayse Merve 17

Monitoring technology

Risk to monitor

Wellhead/annulus sampling

Wellbore integrity Plume migration

Twice-montly sampling since 2005

Tracers

Plume migration

Implemented 2006

Wireline logging/ sampling

Subsurface characterization

Soil gas/surface flux

Surface seepage

Preinjection surveys in 2004 Repeat survey in 2009

3D-4D seismic

Plume migration

Initial 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 migration

Not useful at Krechba due to subsurface architecture and logistics Wells too widely spaced

Gravity

Plume migration

Modellingsugests surface response negligible May be tested in 2011 Borehole gravity possible if suitable access available

VSP

Cap rock integrity Plume migration Fracture evaluation

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 seepage

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

InSAR monitoring

Plume migration Cap rock integrity Pressure development

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

Tiltmeters/GPS

Plume migration Cap rock integrity Pressure Development

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

Action

Overburden samples and logs collected in new development wells

Modelling results inconclusive Decision pending 3D VSP into microseismic array

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

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Assessment of Satellite Imaging as Monitoring and Verification Technology

Fig. 5 â&#x20AC;&#x201C; Krechba Field Well Locations [5] jection site where CO 2 is being injected into the aquifer leg of the gas producing field in central Algeria can be observed in Figure 3. As a greenhouse-gas reduction initiative In Salah gas development project takes part in providing experimental and demonstration aspects of a geological storage in deep saline formations[5]. Since 2004 around one million tones of CO 2 per year have been separated from the produced 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 fields separated CO 2 from natural gas is injected into underground at three wells. Since this study field is located in the rocky desert without vegetation, it is suitable for InSAR processing which uses radar signals [8]. CO 2 is separated out due to standardized values for purity, condensed to 185 bar pressure, and transported 14 kilometres by pipeline to the injection wells. Because of high pressure conditions, liquefied form of CO 2 is observed

Ergene Suzan Muge, Turanli Ayse Merve 19

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

enhance public confidence. Furthermore, selection of right technique will save the stakeholders from redundant investment [3].

Monitoring Technologies Used At Some Geological Co2 Storage Sites

In order to select the best monitoring technique in In Salah site, Boston Square Method is used as a decision making tool. Key risks associated with the In Salah storage site is defined as well bore integrity and direction of CO 2 migration to select best monitoring technique. 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 exploration 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 appropriate to use. Moreover, at first glance, the electromagnetic monitoring, which was evaluated as an appropriate technique, could not be applied in this site due to difficult logistics and subsurface architecture at Krechba. When key risks and monitoring technologies were considered together, the table shown below was developed (Table 1).

Monitoring technologies used at some geological CO 2 storage sites were reviewed in the paper of Hannis [3]. In that paper, two pilotscale and two commercial CO 2 storage sites were evaluated in terms of different monitoring technologies. The pilot-scale sites were Ketzin(Germany) and Nagaoka (Japan) and the commercial sites are the Sleipner (Norway) 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 seismic surveys in Sleipner were reviewed in the paper called “Monitoring technologies used at some geological CO 2 storage sites”. The purpose of the author while selecting those specific sites is the range of storage scenarios and the successful results of these specific techniques at those sites. In the light of these results, it can be concluded that useful monitoring techniques are mostly “site specific”. 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 appropriate for Sleipner site where CO 2 is injected into a saline aquifer, it will be useless for the sites where CO 2 is injected into a depleted gas field, because of its difficulty in distinguishing between CO 2 and residual hydrocarbons. Likewise, the satellite imaging technology which uses InSAR to detect surface deformation will not be suitable for off-shore geological storage sites, such as Sleipner. Detection of effective and right monitoring techniques will

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 Krechba field. This chart is divided into four quadrants named as “consider, just do it, park and focused application”. After pre-assessment of it, final version of Boston Square Chart is obtained 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 assessment is over, there are still several monitoring techniques, such as microseismic, tiltmeters and vadose zone wells, that need to be tested. Even In Salah project was emerged as a non-commercial CO 2 storage project, by

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Assessment of Satellite Imaging as Monitoring and Verification Technology

Fig. 5 â&#x20AC;&#x201C; 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] amendment of regulations regarding CO 2 storage, the most feasible monitoring technique will be employed. The red dotted line of the Boston Square Chart (Fig. 8) shows the position where consensus could be obtained between a developer and a regulator. The area under the red dotted line will be cost-effective and site-specific 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 recorded signals, ground images can be created. Since this technique provides the repeated data of the same location even two millimetres change can be detected. Also, satellite imaging is suitable for all weather conditions whether it is day or night due to nature of radio wave and spaceborne SAR systems [1]. Satellite imagery of surface deformations which provide continuous, real-time imaging of CO 2 migration through the water leg of the Krechba Carboniferous Sandstone gas producing reservoir can be considered as the main part of the monitoring program. Interferometric synthetic aperture radar (InSAR) is a successful and cost-effective monitoring technique at In Salah (Fig. 8).

Since this pilot site is currently a gas production field, monitoring activities were carrying on before CO 2 injection to the reservoir. After the start of CO 2 injection, as expected, surface uplift was detected by using InSAR technology 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, migration pathways and surface uplift patterns are formed by the effect of those structural features. CO 2 injection and gas production result in expansion or compaction of the reservoir formation whose effect can be seen as an uplift or subsidence at the surface. The injection wells that cause expansion are KB-501, KB502 and KB-503. As can be seen in Fig. 9, surface uplift around KB-502 injection well, orientation of 2 distinctive lobes is parallel to the direction of maximum principal stress in the region. This technology gives an opportunity to define subsurface CO 2 flow behaviour. Furthermore, 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 fluid flow and geomechanical modelling study of CO 2 injection, it can be inferred that reservoir layer (C10.2) is not able to generate such

Ergene Suzan Muge, Turanli Ayse Merve

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

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

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Assessment of Satellite Imaging as Monitoring and Verification Technology

Fig. 8 â&#x20AC;&#x201C; Surface deformation detected over the CO2 injection and production wells at Krechba using PSInSARtechnique [2] an uplift nearly 2cm over KB-501. The reason of this unexpected uplift generation can be explained by pressure propagation into the other layers (C10.3 and C20.1). The transmitted pressure to overlying units of reservoir cause additional surface uplift with increasing pressure up to 50m above the top of reservoir 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 injection, while subsidence is due to compaction of the reservoir formation caused by production. Surface deformation measurements provide useful information on the subsurface CO 2 flow behaviour and can be used to assess whether the induced volume changes are confined to the target storage complex or not.

History matching and findings of inverse modelling are used to construct reservoir model. In inverse modelling, simplified reservoir properties such as homogeneous reservoir and formation without topography at injection levels are used and continuous pressure distribution is obtained. Furthermore, by using both field observations and pressure distribution data, permeability values can be normalized. History matching is based on, firstly, the assumption of initial reservoir parameters, 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 field data. History matching is applied for field injection pressure and CO 2 breakthrough in the paper of Durucanet. al.[2]. To get bottom hole pressure (BHP), estimated data is added to well head pressure (WHP). Although, as default parameter matrix permeability is sufficient to run the model, the results indicate that a dual permeability model including fracture permeability is needed to reach the real model. Then, the high permeability corri-

Ergene Suzan Muge, Turanli Ayse Merve 23

dor that connects KB-502 and KB-5 is clarified by using the history matching of CO 2 breakthrough.

Discussion And Conclusion In order to discuss whether InSAR is a useful monitoring technique or not, the principles 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 application 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 deformed interferogram from initial static interferogram (by subtracting one phase image from another, yielding a map of interferometric phase called an interferogram). The precision of InSAR is in millimetre-scale for the measurements of displacement but meter scale for elevation [12]. In this case, main concern is to detect and monitor the deformation due to CO 2 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 considered. When InSAR is compared to other technologies in terms of aspects above, it can be a good alternative technique to understand CO 2 breakthrough in In Salah. Additionally, this technique needs a multi-disciplinary approach such as geochemistry, geophysics, remote sensing, and geomechanics to monitor CO 2 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 satellite imaging technique provides valuable outputs to enhance future monitoring techniques, especially related with remote sensing. This technique enables the detection of some heterogeneities resulted from the CO 2 plume migration and can handle this inconsistency by modelling and characterization of the reservoir in high resolution. Subtle millimetre 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 interpretation of structural features such as faults and fractures by assessing high permeability 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 vegetation (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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Assessment of Satellite Imaging as Monitoring and Verification Technology

References 1. CCS Project. (2010). Retrieved from http://www.insalahco2.com 2. Durucan S., Shi J., Sinayuc C., KorreA., 2011.In Salah CO 2 storage JIP: Carbon dioxide plume extension 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, Innovation 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 CO 2 storage site. EnergyProcedia. 1(1), 2021-2028. Proc. GHGT-9, 16–20 November 2008, Washington DC, USA. 5. Mathieson, A., Midgley, J., Dodds, K., Wright, I., Ringrose, P., Saoula, N., 2010. CO 2 sequestration 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 CO 2 Movement at Krechba, Algeria, Energy Procedia. 7. Onuma T. and Ohkawa S., 2008.Detection of surface deformation related with CO 2 injection byDInSAR at In Salah, Algeria, EnergyProcedia. 8. Onuma T., OkadaaK. and Otsubo A., 2011.Time Series Analysis of Surface Deformation related with CO 2Injection 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 CO 2 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 CO 2 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 CO 2 injection 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 (InSAR) 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 CO 2 Storage Project, International Petroleum Technology Conference.

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

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

Abstract In the world of increasing demand for energy and simultaneously decreasing number of newly found oil fields one can witness the interest for the simulation studies combined with optimisation methods in order to improve secondary recovery phase under water flooding techniques. Since the optimisation on the realistic reservoirs can be prohibitive when it comes to size and computation time a lot of attention was given to single-shooting methods combined with the use of adjoints for gradient computation which reduces the size of the problem. However, there are, other approaches to optimisation of oil reservoirsas multipleshooting 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 optimisation variables. In this paper we investigate the simultaneous approach on direct transcription for optimising oil production in the secondary recovery phase under water flooding. Results are encouraging and suggesting a merit potential of this approach for further investigation.

**Technical University of Denmark ÞÞDenmark dal@kt.dtu.dk  University  Country  E-mail

In the first section we explain the idea of smart well technology in the two phase flow reservoir. Then we introduce the process of reservoir management and picture the location of optimisation algorithms in it.Section III describes the two timescales involved in oil production and resulting challenges. Section IV points out the features of different optimisation methods, 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 particular 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 characterised by 2-phase flow of oil and water in the porous media (e.g. rocks). Conventional meth-

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

present value of oil recovery or another economic objective.

Reservoir Engineering

Fig. 1 â&#x20AC;&#x201C; Schematic view of horizontal smart wells [8] 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 production. Basically, to enhance secondary recovery of the remaining oil after drilling, water is injected at the injection wells of the downhole pipes (figure 1.). This sustains the pressure 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 surface tension, heterogeneity of the porous rock structure leading to change of permeability with position in the reservoir, or high oil viscosity. Therefore it is desired to take into account all these phenomena by implementing a realistic simulator of the 2-phase flow reservoir, which imposes the set of constraints on the state variables of optimisation problem. 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 technology known also as smart fields, or closed loop optimisation, can be used for optimising the reservoir performance in terms of net

In order to maximise reservoir performance in terms of oil recovery or another economic objective, reservoir management process is carried out throughout the life cycle 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 presented in a slightly different way as the reservoir management can be enriched or missing some elements depending on the management strategy e.g. in case of an open loop reservoir management system models are not updated with data from the sensors through data assimilation algorithms and whole optimization is performed offline. Furthermore, some strategies distinguish between low and high order system models, which are responsible for uncertainty quantification. The top element in the fig. 2 represents the physical system constituting reservoir and well facilities. 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 models lies in the fact that each of them has some uncertain parameters which allow to determine uncertainty about the subsurface. The updated models through data assimilation and history matching technique with an uncertainty description give the support to the optimizer. On the right side of the figure, we have sensors, which are responsible for keeping 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 information about the system variables e.g. interpreted well tests, time lap-seismics. On the left-hand side of the figure, one can find op-

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

Fig. 2 – Reservoir Management Process [7] 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 impossible 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 process 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 update is performed more frequently than offline reservoir optimisation as models can easily 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 updating through the data assimilation techniques. 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. Downstream processes refer to e.g. pipelines and export facilities whereas upstream processes are the ones happening in the reservoir e.g. subsurface 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 value 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 production wells. In case of downstream parts

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

of production timescales are much lower and can be in order of minutes or even seconds. In this work we focus on optimisation of upstream production where we model the two phase flow and run so called reservoir simulation. The simulation is based on mathematical 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 optimisation of upstream part of oil production is run off-line whereas downstream part is mostly performed on-line. One of the most challenging aspects in closed loop reservoir engineering involves the combination of short-term production optimisation and long-term reservoir management. An open question is: what is the best way of implementing the found, optimal trajectory that was computed offline into the daily performance of an oil field? Technically, daily valve setting are selected so that they result in instantaneous maximisation 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 instantaneous reservoir performance. What is more, a simple, frequent online feedback control is used for stabilising the flow rates and pressures in the processing facilities to separate 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 involves a layer control structure where longerterm 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 process 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 differential 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 control solution with the feedback of the updated model through data assimilation techniques. There are three main methods (single-shooting, multiple-shooting and simultaneous method) for solving NMPC dynamic optimisation problem and can be categorised based on how they discretise the continuous optimisation problem; see Ringset [10]. So far, the most of attention from academic and industrial oil communities was given to singleshooting method which has been tried out in many works e.g.in Vรถlcker 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 optimisation is executed sequentially to numerical simulation for gradient computation) is because after reformulation it uses only manipulated variables (controls) as optimisation 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 ESDRIK methods equipped with the error estimator which results not only in lower number of discretisation points but also ensures that the model equations are integrated properly.

Dariusz Lerch, Andrea Copolei, Carsten Völcker,Erling H. Stenby, John B. Jørgensen 29

Contrary to single-shooting approach, the simultaneous method, which implementation for optimization of oil reservoirs is the main interest in this work, uses also a discretisation 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 boundary conditions. The transcribed nonlinear program by this method is however, much larger than by single-shooting. Nevertheless, it is very often the case that after direct transcription the problem is very sparse and structured so it is possible to define the sparsity 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 simultaneous 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 discretisation scheme must be applied, which is the case in optimisation of oil production.

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 porosity of the reservoir.

Reservoir Model

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

The model for two-phase, completely immiscible flow comprises partial differential equations representing the mass conservation for water and oil phase of the following form: ∂Cw ∂N = − w + Qw ∂t ∂x ∂C0 ∂N = − 0 + Q0 [1] ∂t ∂x which state that the rate of change of water/ oil concentration( / ) with respect to time is

Cw = φρw ( Pw )Sw Co = φρo ( Po )So [2] The porosity is the fraction of the void space that can be occupied by the fluid and is assumed 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 reservoir contains only oil and water and two phases fill the available volume, saturations satisfy the following equation: Sw + So = 1 [3] Densities of each phase are pressure dependent and are represented by the following equations of state: rw = rw 0 e cw ( Pw −Pw 0 ) ro = ro0 e co ( Po −Po 0 ) [ 4] cw, co

– are compressibilities of each fluid assumed to be constant in the given range of interest rw0=rw(Pw0 ), – are the densities at the reference ro0=ro(Po0 ) pressures rw0 and ro0

N w = rw ( Pw )uw ( Pw , Sw ) N o = ro ( Po )uo ( Po , So ) [5] uw, uo

– are linear velocities and are defined as the velocities that a conservative tracer would experience if taken by the fluid of the given phase through the porous formation

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

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: uw = −k

krw ( Sw ) ∂Pw µw ∂x

uo = −k

kro ( So ) ∂Po [6] µo ∂x

Where k=k(x) denotes the absolute permeability of the porous medium, which is dependent only on the spatial position in the reservoir. krw=krw(Sw) and kro=kro(So) are relative permeabilities 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. Sor ≤ So ≤ 1 − Swc Swc ≤ Sw ≤ 1 − Sor [7] Then the reduced saturations can be modelled as: sw =

Sw − Swc 1 − Swc − Sor

so =

So − Sor [ 8] 1 − Swc − Sor

Due to the surface tension and curvature in the interface between two phases the oil pressure 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 Berenblyum [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 dimensions. Each grid block is given an index i which indentifies its position in the reser-

voir.The absolute permeabilities ki are assumed 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 average of the absolute permeabilities of those blocks. What is more, the relative permeabilities krw,ij , kro,ij , at the interfaces between neighbouring 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) having a highly combinatorial character which is more complex than a regular NLP.

General Formulation and Time Discretisation In optimisation problems involving process 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 proposed by Völcker et al. [14] mass preserving, spatially discretised reservoir model has the following form: d g ( x( t )) = f ( t , x( t )) x( t0 ) = x0 [9] dt In which x( t ) Î  m represents the states (pressures and water saturations), g ( x( t )) Î  m are the properties conserved, whereas the right hand side function f ( t , x( t )) Î  m has the usual interpretation. Then with the use of eq. 9 we can formulate the water flooding problem as a continuous Bolza problem

min ò J(t, x(t ), u(t ))dt t

[ x ( t ),u ( t )]tf

s.t

d g ( x( t )) = f ( t , x( t )) x( t0 ) = x0 dt

umin £ u( t ) £ umax umin £

d u( t ) £ umax [10] dt

Dariusz Lerch, Andrea Copolei, Carsten Völcker,Erling H. Stenby, John B. Jørgensen 31

d   The constraints umin £ u( t ) £ umax should dt be understood as movement ones and model the physical limitations on the controls (water injection rates and bottom whole pressures). In order to transcribe the infinite dimensional problem into numerically traceable one we use direct collocation method and fully discretise the optimal control problem by approximating the controls and states as piecewise polynomial functions on finite elements by applying implicit first order RungeKutta method (Implicit Euler). This enables to represent to optimal control problem as a nonlinear program (NLP).

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:

Production Scenario

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

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 horizon 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 located 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 analysed 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 sensitive to this parameter, e.g. Capolei [5]. The physical model data, as well as fluid properties and economic data that we used for this

Figures 10 and 11 present the values of the manipulated controls (bottom whole pressures 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 distinctly demonstrate that the maximum npv (46 million dollars) was reached after injecting 1.08 pvat on the 1000th day of the production, which means that the value of oil produced after this time did not compensate for the prices of water injection and water separation that also contribute to the economic potential of the reservoir. Consequently, according 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 mathematical model of the two phase flow reservoir with the use of two point flux approximation (TPFA) and the single point upstream

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

Fig. 3 – Oil Saturations after 100 Days

Fig. 4 – Oil Saturations after 300 days

Dariusz Lerch, Andrea Copolei, Carsten Völcker,Erling H. Stenby, John B. Jørgensen 33

Fig. 5 – Oil Saturations after 500 days

Fig. 6 – Oil Saturations after 700 days

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

Fig. 7 – Oil Saturations after 900 days (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 respectively. 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 optimisation 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 potential for solving real case problem as the results obtained in this work make physical sense. This is very important as in this approach model is not solved in a conventional 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 algorithm terminates before converging. The relatively steep transition in the saturations between the neighbouring grid blocks is a suggestion for incorporating the mathematical term representing sweep efficiency in the objective cost function or reducing the size of the grid blocks. In the future work, real life

Dariusz Lerch, Andrea Copolei, Carsten Völcker,Erling H. Stenby, John B. Jørgensen 35

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

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 accomplished by deriving and implementing analytical expressions for second order derivatives constructing the Hessian of the Lagrangian matrix. At the current stage, this matrix is approximated 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 contributing to this work are given to Associate Professors at Centre For Energy Resources Engineering (CERE): Wei Yan, Alexander Shapiro, as well as PhD students: BjørnMaribo – Mogensen andHao Yuan.

Dariusz Lerch, Andrea Copolei, Carsten Völcker,Erling H. Stenby, John B. Jørgensen 37

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

References 1. Aziz, K. and Settari, A. Petroleum Reservoir Simulation. London, first edition: Applied Science Publishers Ltd,, 1971. 2. Berenblyum, R.A., Shapiro, A.A., Jessen, K. and E.H. Stenby. "Black oil streamline simulator with capilary effects." SPE Annual Technical Conference and Exhibition. Denver, Colorado, 2003. 3. Biegler, L.T., Martinsen, F. and Foss, B. A. "Application of optimisation algorithms to nonlinear mpc." Department of Chemical Engineering, Carnegie Mellon University, Department of Engineering Cybernetics, Trondheim, Norway, 2004. 4. Byrd, R.H., Hribar, M.E. and Nocedal, J. "An interior point algorithm for large scale nonlinear programming." Siam J. Optimisation 9 (1999): 877-900. 5. Capolei, A., Völcker, C. and Frydendall, J. and Jørgensen, J.B. Oil reservoir production using single-shooting and esdrik methods. Kongens Lyngby, Denmark: Department of Informatics and Mathematical Modelling (IMM), Centre for Energy Resources Engineering (CERE), Technical University of Denmark (DTU), 2011. 6. Di Oiliveira, N. M. C. and Biegler L.T. "An extension of newton-type algorithms fon nonlinear process control." Automatica 31(2), 1995: 281-286.

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

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. 8. Jansen, J.D., Bosgra, O.H and Van Den Hof, P.M.J. "Model-based control of multiphase flow in a subusrface reservoirs." Journal of Process Control 18 (Journal of Process Control 18), 2008: 846-855. 9. Li, W.C. and Biegler, L.T. "Multi-step, newton-type control strategies for constrained nonlinear processes." Chem. Eng. Res. Des. 67, 1989: 562-577. 10. Ringset, R., Imsland, L. and Foss, B. "On gradient computation in single-shooting nonlinear model predictive control." Proceedings of the 9th Internation Symposium on Dynamics and Control of Process Systems. Leuven, Belgium, 2010. 11. Saputelli, L., Nikolaou, M. and Economides, M.J. "Real-time reservoir management: a multiscale adaptive optimisation and control approach." Computational Geosciences, 2006. 12. Schenk, O., Wächter, A. and Hagemann, M. "Combinatorial approaches to the solution of saddle point problems in large-scale parallel interior-point optimisation." Comp. Opt. Applic. 36 (Comp. Opt. Applic. 36 (2007), 321--341 ), 2007: 321--341 . 13. Suwartadi, E., Krogstad, S. and Foss, B. "On state constraints of adjoint optimisation in oil reservoir water-flooding." Reservoir Characterisation and Simulation Conference. Abu Dhabi, UAE, 2009. 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 twophase 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 linesearch algorithm for large scale nonlinear programing." Springer-Verlag. 2006.

Nazarii Hedzyk 39

̂̂Research the processes of increasing wells exploitation efficiency Nazarii Hedzyk

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 increased significantly in comparison to the previous gas production.

Introduction

**Ivano-Frankivsk National Technical University of Oil and Gas ÞÞUkraine merve.turanli@metu.edu.tr  University  Country  E-mail

lection system plays an important role at this stage of many gas fields development. To overcome complications during well exploitation comprehensive approach was considered.

Problem solving Model of a gas field was built in Schlumberger program PipeSim. It includes gas collection system and wells construction.

A lot of natural gas deposits associated with the water system and developed on water drive mode condition.

Field parameters

As a result there are many complications during their operation:

ÈÈreservoir ÈÈdepth

coning

850m

pinching

ÈÈinitial

ÈÈWater ÈÈGas

ÈÈinitial

ÈÈLiquid

ÈÈHydrates

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-

ÈÈdaily

reservoir pressure 7.23 MPa temperature of about 300 K

of the formation ranges from 300 to gas reserves 1.742 bln m3

output of the deposit is 215103 m3/d

ÈÈpressure

at the entrance of gas conditioning system equals 0.56 on the low pressure comb and 1.5MPa on the high pressure cumb

ÈÈcurrent ÈÈat

gas extraction ratio is 50%

this stage of development it has 12 wells

summer / 2012

Research the processes of increasing wells exploitation efficiency

Fig. 1 – General view of the model

Fig. 2 – Geological section of the Luybeshivske gas field

Nazarii Hedzyk

Fig. 3.1 â&#x20AC;&#x201C; Graph of the dependence of liquid loading velocity ratio on the distance to other wells

Fig. 3.2 â&#x20AC;&#x201C; Graph of the dependence of liquid loading velocity ratio on the distance to other wells

SUMMER / 2012

Research the processes of increasing wells exploitation efficiency

ratio of the speed required for removal of water 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 model liquid loading velocity ratio value. As figure 3 shows, most wells have problems with fluid removal.

Fig. 4 – Scheme of forces acting on a drop of liquid in the gas flow in the borehole After running calculations we got the basic performance of wells, which is the same as the actual, after model fitting. Pressure, MPa

Gas rate, msm3/d

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

Low pressure comb

Total gas rate

215,34

Table 1 – Results of calculation The main complication during the operation of wells is adgewater admission. Therefore, one of the factors to pay attention to is lifting water from the bottomhole to the surface. Control of fluid accumulation in bottomhole includes Liquid Loading Velocity ratio – the

First of all let’s have a look at the processes which take place in the well. To confirm the critical gas velocity required for removal of liquid droplets to the surface was considered to study the forces acting on a drop of fluid in the gas flow in the hole. A drop will be in equilibrium if the forces are equal to each other. FDrag = FGravity [1] g ( ρl − ρ g ) rl , rg g=9,81 j A=pd2/4 Vc Vc2 =

πd 3 1 = ρ g ⋅ ϕ ⋅ A ⋅ Vc 2 [2] 6 2 – density of liquid and gas, kg/m3; – gravity, m/s2; – aerodynamic coeﬃcient for drop of water j = 0,44; – drop area, m2; – critical gas velocity, m/s.

4 g ( ρ l − ρ g )d 3ϕ ⋅ ρ g

[3]

Weber number (We) is a criterion of similarity in hydrodynamics, which determines the ratio of inertia to the fluid surface tension. It can be defined as: Vc2 ⋅ ρ g ⋅ d

We =

= 30 [ 4] σ σ d = 30 2 [5] Vc ⋅ ρ g

Vc2 =

4 g ( ρl − ρ g )

Vc = 4

3ϕ ⋅ ρ g

σ [6] V ⋅ ρg

40 gσ( ρl − ρ g ) ϕ ⋅ ρ 2g

2 c

[7]

Nazarii Hedzyk 43

Vc = 2, 7046 4

rl − r g r

2 g

[ 8]

Gas density in bottomhole conditions can be calculated as: Pwf ⋅ Tst r g = r0 [9] zwf ⋅ Pat ⋅ Twf Substituting the values of atmospheric pressure, standard density and temperature we obtain: Pwf ⋅ 293 P = 6, 968 wf [10] r g = 0, 72279 zwf ⋅ 0, 1013 ⋅ 300 zwf P rl − 6, 968 wf zwf Vc = 2, 7046 4 Pwf 2 (6, 968 ) zwf

[11]

Similar to the dependence 12 is Turner (13) and Coleman (14) equation: 1

(67 − 0, 0031P ) 4 1

, ft / s [13]

(0, 0031P ) 2 1

Vc ,water = 4, 434

Critical velocity using equation, m/s

Critical velocity using PipeSim, m/s

11,504

9,0

6,134

5,49

6,36

5,3

6,757

5,23

6,931

5,6

6,664

5,3

9,946

7,6

11,27

8,3

10,101

9,0

1-Sh.Lb.

6,254

5,75

3,955

3,54

3,56

3,2

Table 2 – Results of the critical velocity calculation

As we know the density of fluid equal 1100 kg/m3 obtains an equation for the critical velocity: P 157, 864 − wf zwf m Vc = 4, 3942 4 , [12] Pwf 2 s 6, 968( ) zwf

Vc ,water = 5, 321

Well #

(67 − 0, 0031P ) 4 1

, ft / s [14]

(0, 0031P ) 2 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.

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 deliquification. z ⋅ Pat ⋅ Twf 4 ⋅Q Q z⋅ P ⋅T ⋅ Vc = ⋅ at wf = 2 p ⋅ d ID Pwf ⋅ Tst ⋅ 86400 F Pwf ⋅ Tst Vc = 14, 74 ⋅ 10−6

Q z ⋅ Pat ⋅ Twf ⋅ 2 d ID Pwf ⋅ Tst

d ID = 3, 5 ⋅ 10−3

Q z ⋅ Pat ⋅ Twf ⋅ Vc Pwf ⋅ Tst

2 d ID ⋅ Vc ⋅ Pwf ⋅ Tst

14, 74 ⋅ 10−3 ⋅ z ⋅ Pat ⋅ Twf

[15]

[16]

[17]

To calculate those parameters we used Adamov’s equation and minimum required gas rate.

summer / 2012

Research the processes of increasing wells exploitation efficiency

ID, sm Well #

Using eq. 12

Adamov’s eq.

PivKavNDIgas eq.

VNDIgas eq.

IFTUOG eq.

3,571

3,153

3,715

4,56

5,756

1-Sh.Lb.

1,505

1,58

1,549

2,28

1,838

0,585

0,74

0,602

1,1

0,784

6,825

6,224

7,6

9,9

4,443

4,369

4,586

5,4

5,468

6,901

6,989

7,126

7,71

9,995

4,307

4,198

4,44

5,29

6,969

5,239

4,016

5,451

6,2

8,559

5,228

4,187

5,433

6,18

8,52

1,058

1,14

1,09

1,72

1,642

3,548

3,154

3,593

4,52

5,689

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

20,044

22,287

17,279

9,049

19,607

27,576

37,383

42,455

32,341

17,011

36,923

51,938

36,073

40,921

31,221

21,311

37,801

48,599

33,984

38,377

29,353

27,185

38,062

45,904

33,141

37,39

28,626

19,559

34,63

44,275

34,449

38,917

29,75

16,112

34,154

46,601

23,166

25,873

20,007

10,523

22,741

32,047

20,457

22,839

17,7

9,31

20,106

28,508

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

57,352

67,225

49,879

22,427

55,489

76,726

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 dependencies are in the same range. Tables 4 and 5 show the results necessary for the wells stabilization and improve the fluid removal – we need to change the tubing.

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

Nazarii Hedzyk

At this time the pressure on high pressure combs is about 1.5MPa, and on the low pressure combs – 0.56MPa. Let’s consider the effect 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

71,78

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

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

284,27

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

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

Fig. 5 – Graphical dependence of flow rate for pressure on low pressure comb

SUMMER / 2012

Research the processes of increasing wells exploitation efficiency

Fig. 6 â&#x20AC;&#x201C; Graphical dependence of flow rate for pressure on high pressure comb

Fig. 7 â&#x20AC;&#x201C; Graphical dependence of absolute rate increased low pressure comb from the pressure of this combs

Nazarii Hedzyk

Fig. 8 – Graphical dependence of absolute rate increased high pressure comb from the pressure of this combs To determine the optimum value of pressure drop at comb graphs of the absolute rate increased on combs for pressure were built.

Well #

Initial gas rate, msm3/d

Gas rate after pressure reduction, msm3/d

8,52

12,04

53,48

77,47

19,12

29,93

48,73

71,46

19,03

34,22

19,48

28,33

16,24

23,06

1,53

1,88

1-Sh.Lb.

2,72

3,1

23,15

24,51

2,91

14,91

0,44

0,63

After solving equation systems:  y = 12, 16 x + 0, 407   y = 23, 9 x − 2, 952  y = 9, 060 x + 1, 937 [18]   y = 3, 004 x + 6, 374 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. Production rate will increase by 73.42 msm3/d compared with the current value.

Low pressure comb

45,76

65,31

High pressure comb

169,58

256,24

TOTAL

215,34

321,55

Table 9 – Results of the rate increased after pressure reduction

SUMMER / 2012

Research the processes of increasing wells exploitation efficiency

Fig. 9 â&#x20AC;&#x201C; Graphical dependence of the liquid loading velocity ratio 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 development is justified due to gas compression installation operation which entered in 2011. Reduced pressure at the entrance to gas conditioning system allows us also to improve the removal of fluid from the bottom to the surface. Figure 9 shows that in wells 5, 25, 26, 17 and 1-Sh.Lb. fluid has still been accumulating at the bottom. Therefore, it is proposed to replace tubing on pipes with smaller diameters in these wells, the value of which is given above, or to consider the possibility of twostage column in these wells. Well #

Fig. 10 â&#x20AC;&#x201C; Scheme design of two-stage tubing column

L1,m

L2,m

d1,m

d2,m

1-Sh.Lb.

51,692

289,445

188,308

0,062

0,0503

280,505

0,0403

0,0352

86,842

178,508

0,0352

0,0264

Table 11 â&#x20AC;&#x201C; Results of the two-stage tubing column calculation

Nazarii Hedzyk

Fig. 11 â&#x20AC;&#x201C; The value of erosional velocity ration for the wells

SUMMER / 2012

Research the processes of increasing wells exploitation efficiency

As a result of pressure reducing on the heads of wells and the installation of two-stage tubing 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

8,52

11,77

53,48

77,59

19,12

29,87

48,73

71,47

19,03

34,15

19,48

28,34

16,24

23,06

1,53

1,88

1-Sh.Lb.

2,72

3,1

23,15

20,26

2,91

15,28

0,44

0,63

Low pressure comb

45,76

65,05

High pressure comb

169,58

252,36

TOTAL

215,34

317,41

Table 12 â&#x20AC;&#x201C; 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 field Nowadays, 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 obtained. Also, there was found an algorithm of the minimum required gas flow and an internal tubing diameter. Calculation results were confirmed by modeling in Schlumberger program PipeSim. Using this software optimum pressure in combs was defined, which allows us to increased production rate and improve the process of fluid removal. In those wells where the above actions failed to produce the desired effect, the establishment of two-step tubing column was proposed. 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.

Ilia Gurbanov 51

̂̂Enhanced Heavy Oil Recovery Methods Ilia Gurbanov

Abstract Heavy oil is generally defined as unconventional oil resources that have high viscosity (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, sulphur and nitrogen, thus it requires special refining process as well as special recovery methods due to its high viscosity. As a result, heavy oil production is less profitable 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 technologies 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 conventional 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 nuclear power sources and our choice number one will be unconventional hydrocarbon resources. According to Stark et al. [1] the amount of proved unconventional oil resources is more than three times higher than the amount of

**Tyumen State Oil and Gas University ÞÞRussia ilyagurbanov@gmail.com  University  Country  E-mail

conventional oil resources, and heavy oil is a major part of all unconventional oil resources. 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 costefficient. 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 reasonable recovery factors (15-20%) and production rate(20-300 bbl/day), In 2002, Canada'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 suitable for CHOPS are located in unconsolidated or weakly consolidated sands where sand mobilization can be easily triggered and sand influx can be easily sustained for the productive life of the well [2]. Of course, this meth-

summer / 2012

Enhanced Heavy Oil Recovery Methods

Fig. 1 – Viscosity reduction using Irradiation 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]. There are several methods for organizing this process, such as Steam-Assisted Gravity Drainage (2 horizontal 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 performing 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 injected into the well. When used on the horizontal 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%.

Thermal methods are the most effective technique for heavy oil recovery. However, many reservoirs' conditions restrict the application of thermal techniques, such as thin pay thickness or deep reservoir. Thus, a number of non-thermal in-situ methods were developed. Carbon dioxide injection – injection of CO 2 insitu, usually during water-and-gas (WAG) process allows us to add 5-12% of ROIP to anticipated total production [6]. Besides, it is a way of getting rid of the CO2, which cause greenhouse effect. It may be quite economically profitable sometimes. For example, in Norway, 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 recovery. Alkaline/Surfactant flooding - Heavy oils usually 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 recovery for this method used on heavy oils will be from 20 to 30% ROIP [7]. Polymer flooding is a well-recognized technique of mobility control for conventional

Ilia Gurbanov

Fig. 2 â&#x20AC;&#x201C; Viscosity reduction using Irradiation oils, which could be a potential method for enhanced heavy oil recovery by improving the sweep efficiency and reducing water mobility. According to the lab tests, tertiary oil recovery 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 industrial application yet. Electromagnetic heating is another thermal 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 excessive. In-situ combustion does not have the same depth constraints as steamflooding, but its success depends on crude composition. Each of the conventional thermal methods requires sufficient reservoir transmissibility to achieve fluid injection. EMH has the potential for overcoming some of the limitations of conventional thermal methods. But there is another technology that is applicable for similar conditions and is more perspective. And that technology, which deserved a thorough description, is hydrocarbon enhancement electron beam technology. Ionizing ac-

cidents, as a way to refine viscous heavy oil residuals, have been observed to be a promising and efficient way of providing higher selectivity, quality and quantity of treated feed (Aksenova et al.). With current technologies simultaneous heating and irradiation gives us the best result. The good thing about electronic beam emission is, it is more effective 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 different fluid. The crude composition is also better [9]. Thus, this technology is applicable for changing the properties of the oil in-situ as well as the refining process after production (the way you

Fig. 3 â&#x20AC;&#x201C; Principle of using electron beam technology for oil refining

SUMMER / 2012

Enhanced Heavy Oil Recovery Methods

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 technology to the field, the less this technology costs for us later. Usually the total expenses drop down to 20-30% after first year since introducing new technology to the field and industry Beam Power, MeV

2,50

Beam Power, kW

100

Beam Current, mA

Total Power Consumption, kW

148

Power Efficiency

Process Volume bbl/day

760

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 application and their further development should be economically profitable.

Table 1.1

References 1. 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. Moreira) 10. Laboratory Investigation of E-Beam Heavy Oil Upgrading (D. Yang, J.Kim, P.C.F. Silva et al.)

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East meets West

East meets West is an international student petroleum congress organized by AGH University of Science and Technology SPE Student Chapter. The history of it goes back to 2010 when the first edition of the congress had place. East meets West is held in the area of AGH University of Science and Technology in Krakow and lasts more or less three days during which students from different countries of the world can present their achievements in the field of petroleum-related study and their own research. The congress attracts also many well known professors from foreign universities as well as the representatives of the industry including the biggest world petroleum

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

EmW – 212 edition This year, 25-27th April in Krakow, Poland had place the World biggest student petroleum

Owing to our chapter members’ involvement small groups were formed and our guests were shown round the wonderful city of Krakow. 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 first challenge was to make our guests feel free in the company of each other.

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 numerous sponsors and the students of SPE AGH Student Chapter. I look forward to the next edition of EMW. — Richard Awo (TU Claustahl, Germany)

congress. Once again it was organized by AGH UST SPE Student Chapter. The congress attracted almost 90 students from all over the world including countries of Europe, Asia and South America. It also gathered many professionals from different companies of the petroleum industry who could present their latest technologies, explain the companies’ policy and goals and show us their engagement 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. They were accommodated in Olimp dormitory at our University campus.

That’s why the evening before the official congress 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 different corners of the world who came to take part in East meets West congress. On 25th April everything started with Leadership Workshops – Student Chapters Approaching Pivot Point. Then, there was an official opening ceremony. We could hear the speech of our special guest – SPE International President 2011 – Alan Labastie. There 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

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– Andrzej Gonet and AGH UST SPE Student Chapter President 2011/2012 – Anna Ropka. In the evening, after the official 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. The second day of the congress – Thursday 26th April – was partly devoted to HR Presentations of our sponsor companies including Schlumberger, Halliburton, United Oilfield Services, Orlen Upstream, San Leon Energy and National Oilwell Varco. The representatives 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 presented their ways of dealing with challenges

they face every day. They also presented some new advanced technologies applied recently in the industry. In the evening everybody gathered in front of the congress hall and left for Manor House in Tomaszowice for the Official Banquet of East meets West congress. The 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, everybody seemed to have a really great time. 27th April. The last day of the congress was the most meaningful to all the participants. The main feature was a Student Paper Contest which gave the students a significant chance to present their research results to a very wide audience including their future potential employers. They also competed with colleagues from other universities and in the end the best performances were chosen and awarded with prizes. The topics of presentations varied from geological and mineralogical issues

through consumption of energy, exploration 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 research with others as well as their views and opinions on certain topics. They could elaborate on their posters and defend their ideas to our jury whose task was to choose the best pieces of work. It was a difficult task because the level of presented knowledge and interest was quite high. The awards for the best posters and papers were presented during the Official Closing Ceremony by AGH UST SPE Chapter's president 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 final party in Diva club where we could take rest after three days of

hard work, new experiences and lots of emotions. We could write dozens of reports like this but, believe it, or not, it is just impossible to describe with words the extraordinary ambience 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 industry 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 find it really rewarding that so many people – both students and professionals – shown up and enjoyed the congress. 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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SPE AMERICAS 2013 E&P HEALTH / SAFETY SECURITY / ENVIRONMENTAL CONFERENCE

Environmental Student Symposium

LET’S SHAPE THE FUTURE TOGETHER

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

Society of Petroleum Engineers

www.spe.org/events/hsse

Canadian Dream In June, Polish chapter have visited Calgary to attend Global Petroelum Show 2012 – one of the world’s biggest drilling exhibition. 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 population 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. The city perfectly joins the new west rodeo tradition with modern, developing lifestyle. Calgary strikes as a very friendly, multicultural and multinational place open for everyone.

The very first 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 filled with allover-the-world drilling companies presenting their achievements and offers 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 several companies really interested in ‘East meets West’ and YoungPetro projects, which makes opportunities to establish our presence also

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in North America, where our chapter didn’t act so far. Three 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, experiences and points of view regarding the future of oilfield 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 field engineer in Fracturing Department. Thanks to Kuba’s courtesy we were able to see the Schlumberger base and learn how the day of a field engineer looks like. Moreover we’ve

seen the tools used by Schlumberger in Canada 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 drilling contractor Ensign Energy has its office. Thanks 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 descriptions simultaneously. Apart from the rig itself, we have also visited factories belonging to the company to see how the rig components are made from the very beginning. Af-

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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-maintained parks and try local, Canadian cuisine. One of the most impressing experiences was the rodeo organized at Stampede Park together with the Global Petroleum Show. It might be a little surprising, but rodeo is a very important 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. The 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 profitable 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 You We 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! The 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 papers@youngpetro.org For more information visit youngpetro.org/papers