2016 SPE Canada Regional Student Paper Contest SPE Canada Regional Student Paper Contest MEMORIAL UNIVERSITY OF NEWFOUNDLAND SPE STUDENT CHAPTER MARCH 24, 2016 • ST. JOHN’S •

2016 SPE Canada Regional Student Paper Contest MEMORIAL UNIVERSITY OF NEWFOUNDLAND SPE STUDENT CHAPTER MARCH 24, 2016 • ST. JOHN’S • NEWFOUNDLAND AND LABRADOR • CANADA

HIBERNIA GRAVITY BASE STRUCTURE (GBS) Photo Credit: Hibernia

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CONTEST LOCATION Room EN 4000 (Faculty Lounge)

Arctic Avenue, S.J. Carew Building

Faculty of Engineering & Applied Science

Memorial University of Newfoundland

St. John's, NL A1B 3X5

CLOSING CEREMONY LOCATION

Bitters Pub Feild Hall, 216 Prince Philip Dr.

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Memorial University of Newfoundland SPE Student Chapter is pleased

to welcome you to the 2016 SPE Canada Regional Student Paper

Contest. This contest brings together energy students from Canada to

discuss technological advances in the oil and gas industry and how

they can be applied to help develop the resources in this region.

Each year, SPE coordinates 14 regional student paper contests at the

undergraduate, master's and PhD level. The students compete against

other students from their region for the opportunity to participate in the

International Student Paper Contest, held during the Annual Technical

Conference and Exhibition (ATCE). Contestants enter with an abstract

of their paper, of which they perform a presentation on the day of the

competition, and then the winners who proceed to the International

contest at ATCE have their papers published in the conference

proceedings and on OnePetro.

The MUN SPE Student Chapter is proud to host the contest for the

second time, which signifies the solid relationship that we have with the

SPE Canada, SPE Atlantic Section and the energy companies active in

the local oil and gas industry. 46 abstracts from 7 Canadian universities

were submitted for presentation at the contest. Following a through

selection process carried out by the contest advisory board, the

accepted abstracts are selected.

The contest includes 9 presentations in the undergraduate division, 10

presentations in the master’s division and 9 presentations in the PhD

division. Topics primarily include the application of basic and

engineering sciences to the finding, development, and recovery of oil,

gas, and other resources from wells as well as safeguarding production

facilities against corrosion and other integrity threats. The 1st, 2nd, and 3rd

place winners will receive $200, $150, and $100 cash prizes, respectively.

In addition, the 1st place winner in each category will be supported by

SPE International to travel to ATCE 2016 on September 26-28, 2016 in

Dubai, UAE and represent the SPE Canadian Region at the SPE

International Student Paper Contest.

We are pleased that you are here to take part in the discussion and the

solutions. We value your participation in the Student Paper Contest and

we are hoping that you will enjoy all that this rewarding experience has

to offer.

Executive Committee

Memorial University SPE Student Chapter

WELCOME LETTER

http://www.onepetro.org/

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ABOUT ST. JOHN’S Rich with history, rife with culture and sprawling with natural beauty, Newfoundland is the

most easterly point in North America, Canada’s youngest province and home to Memorial University.

Considered to be "North America's Oldest City", St. John's is one of the oldest settlements in North

America and is the capital and largest city in Newfoundland and Labrador, Canada. St. John's is a

vibrant city balancing its people strong sense of heritage with the needs of a modern urban population.

From outdoor adventure to annual events and festivals, attractions, scenic drives, shopping, fabulous

restaurants and tours, St. John’s has it all. By day, travelers can easily explore nearby ecological reserves,

world renowned Provincial and National Historic Sites, cultural and interpretative centres and hike

urban and costal nature trails. In the evenings, enticing aromas and lively music drift through the streets

renowned for their exciting nightlife. With easy access to wildlife, marine life, seabirds, whales and

icebergs (in season), it’s easy to lose yourself while discovering St. John’s. The city's proximity to

the Hibernia, Terra Nova and White Rose oil fields has led to an economic boom that has spurred

population growth and commercial development. Learn more about the St. John’s unique history and

culture by visiting www.stjohns.ca.

http://www.stjohns.ca/

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ABOUT MEMORIAL As Newfoundland and Labrador’s only university, Memorial University has a special obligation to the people

of this province. Established as a memorial to the Newfoundlanders who lost their lives on active service

during the First and Second World Wars, Memorial University draws inspiration from these shattering sacrifices

of the past as we help to build a better future for our province, our country and our world. Memorial is a

multi-campus, multi-disciplinary, public, teaching/research university with more than 18,500 students spread

across four campuses and nearly 85,000 alumni active throughout the world. From local endeavors to

research projects of national concern, Memorial’s impact is felt far and wide. Interested in learning more?

Take a deeper look at the people and stories of Memorial at www.mun.ca

ABOUT MUN SPE Chapter Started in March 2002, the Memorial University of Newfoundland Society of Petroleum Engineers Student

Chapter, commonly known as Student Society of Petroleum Engineers (SSPE), was established to be a

valuable resource for students. SSPE has a mission to further Petroleum engineering knowledge amongst

student members while enhancing the professional and social bond between students and the Oil and Gas

industry. SSPE schedule a variety of events each year as part of students’ development, preparing them to

be future petroleum engineers and bringing them closer to the petroleum industry. As of July 2014, SSPE has

more than 150 registered SPE student members who are studying a variety of disciplines related to

petroleum engineering at Memorial University. Learn more at www.mun.ca/sspe

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WORKING COMMITTEE Dr. Lesley James, Contest Chair Assistant Professor, Memorial University

Javad Hashemi, Contest Coordinator President, MUN SPE Student Chapter

Al Amin Secretary, MUN SPE Student Chapter

Elahe Shekari Vice President, MUN SPE Student Chapter

Daniel Sivira Treasurer, MUN SPE Student Chapter

Houssam Ghosn Oil & Gas Engineering Representative, MUN SPE Chapter

Jie Cao Professional Development, MUN SPE Chapter

MODERATORS

Undergraduate

Division

Don Hender Memorial University

Master’s

Division

Saeed Jafari Memorial University

PhD Division Mohammadreza Kowsari Memorial University

JUDGES

Undergraduate

Division

Jamie Hynes Husky Energy

Yusuf Ololade Ahmed Schlumberger (Former Employer)

Don Tulk Maderra Engineering Inc.

Master’s

Division

Babatunde Yusuf Nalcor Energy – Oil and Gas

Stephen Douglas Butt Memorial University

Justin Skinner Suncor Energy Inc.

Shane Halley Schlumberger Canada

PhD Division

Howard Park C-NLOPB (Former Employer)

Jamal Siavoshi Husky Energy

Mohammed Mokhtar Said Independent consultant, formerly with Schlumberger

Cosmas Ezeuko Suncor Energy Inc.

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CONTEST PROGRAM 8:00 am – 9:00 am Registration Faculty of Engineering Lobby

8:00 am – 8:30 am Welcome Reception Coffee EN 4000

8:30 am – 8:45 am Welcome Speech EN 4000

8:45 am – 9:00 am Judges and Moderators Meeting EN 4000

9:00 am – 10:40 am Presentations EN 4032A: Undergraduate Division

EN 4002: Master’s Division

EN 4000: PhD Division

10:40 am – 11:00 am Break EN 4000

11:00 am – 12:15 pm Presentations EN 4032A: Undergraduate Division



12:15 pm – 1:00 pm Lunch EN 4000

1:00 pm – 2:15 pm Presentations EN 4032A: Undergraduate Division



2:15 pm – 2:30 pm Judges, Moderators, and Contest

Chair Meeting to Select Winners

EN 4002

2:45 pm – 4:00 pm Closing Ceremony and

Announcing the Winners

Bitters Pub

Feild Hall, 216 Prince Philip Dr.

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2016 SPE Canada Regional Student Paper Contest Agenda March 24, 2016 – Memorial University of Newfoundland

Undergraduate Division FACULTY OF ENGINEERING AND APPLIED SCIENCE – ROOM EN 4032A

SCHEDULE NAME/UNIVERSITY ABSTRACT

9:00 am – 9:25 am Alex Chow UNIVERSITY OF BRITISH COLUMBIA

Examining the effects of Alberta's Climate Change Plan on

oil sands producers

9:25 am – 9:50 am Kelsey Furey MEMORIAL UNIVERSITY Determining the optimum decline curve exponent

9:50 am – 10:15 am Svetlana Temirova UNIVERSITY OF BRITISH COLUMBIA

A closer look at the bitumen leaks in the Primrose Lake

project

10:15 am – 10:40 am Colin Taylor MEMORIAL UNIVERSITY

Geophysical surveys at Long Pond

10:40 am – 11:00 am BREAK

11:00 am – 11:25 am Victoria Pollard MEMORIAL UNIVERSITY

The impact of normalized relative permeability on

estimated ultimate recovery

11:25 am – 11:50 am Jonathan Muller UNIVERSITY OF BRITISH COLUMBIA

An analysis of the energy intensity of producing petroleum

products from oil sands bitumen against shale and

conventional oil

12:15 pm – 1:00 pm LUNCH

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Mater’s Division FACULTY OF ENGINEERING AND APPLIED SCIENCE – ROOM EN 4002


9:00 am – 9:25 am Ali Chamkalani MEMORIAL UNIVERSITY

A mathematical- graphical window toward diagnosing

drilling effectivity in shaly formations

9:25 am – 9:50 am Armin Afrough UNIVERSITY OF NEW BRUNSWICK

Magnetic resonance imaging of fines migration in Berea

sandstone

9:50 am – 10:15 am Abhay Sablok UNIVERSITY OF BRITISH COLUMBIA

The role of Canadian Oil Sands bitumen in India’s energy

mix

10:15 am – 10:40 am Lili Xin MEMORIAL UNIVERSITY

Numerical modeling of tracer tests

10:40 am – 11:00 am BREAK

11:00 am – 11:25 am Tianjie Qin UNIVERSITY OF CALGARY

Redevelopment of the Pembina Cardium field by CO2-

EOR using existing wells

11:25 am – 11:50 am Jinghan Zhong MEMORIAL UNIVERSITY

DEM simulation of enhancing drilling penetration using

vibration and experimental validation

11:50 am – 12:15 pm Reza Zeinali MEMORIAL UNIVERSITY

Volume averaging of multiphase flows with hydrate

formation in subsea pipelines

12:15 pm – 1:00 pm LUNCH

1:00 pm – 1:25 pm Eugenio Turco Neto MEMORIAL UNIVERSITY

Numerical flow analysis of hydrate formation in offshore

pipelines using computational fluid dynamics (CFD)

1:25 pm – 1:50 pm Han Byal (Jenny) Kim MEMORIAL UNIVERSITY

Technical feasibility of silicon dioxide nanoparticles as

enhanced oil recovery agent with applications in offshore

reservoirs

1:50 pm – 2:15 pm Daniel Sivira MEMORIAL UNIVERSITY

Silicon Dioxide (SiO2) nanoparticle as a wettability modifier

agent for enhanced oil recovery in Ben Nevis formation,

Hebron Field, Offshore Eastern Canada

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PhD Division FACULTY OF ENGINEERING AND APPLIED SCIENCE – ROOM EN 4000


9:00 am – 9:25 am Mohammad Islam Miah MEMORIAL UNIVERSITY

Reservoir quality assessment using wireline log data: A case

study

9:25 am – 9:50 am David Onalo MEMORIAL UNIVERSITY

Validation of a radial flow cell design at Memorial University’s

Advanced Drilling Laboratory

9:50 am – 10:15 am Ali Telmadarreie UNIVERSITY OF ALBERTA

New approaches to the foam enhanced oil recovery in

Canadian heavy oil carbonate reservoirs: Pore scale

visualization

10:15 am – 10:40 am Hossein Khorshidian MEMORIAL UNIVERSITY Oil recovery optimization in gas assisted gravity drainage

10:40 am – 11:00 am BREAK

11:00 am – 11:25 am Hesam Hassan Nejad MEMORIAL UNIVERSITY

Experimental screening of surfactants for the waste drilling

mud remediation

11:25 am – 11:50 am Dongqi Ji UNIVERSITY OF CALGARY

A method of predicting temperature dependency of

irreducible water saturation in heavy oil/oil sand reservoirs

11:50 am – 12:15 pm Sedigheh Mahdavi MEMORIAL UNIVERSITY

The effect of carbonated water injection on residual

trapped oil saturation: Application for pore-scale flow

characterization

12:15 pm – 1:00 pm LUNCH

1:00 pm – 1:25 pm Hashemi Nekouie MEMORIAL UNIVERSITY

Multi-component gas/oil displacement with constant

pressure boundaries

1:25 pm – 1:50 pm Elahe Shekari MEMORIAL UNIVERSITY Evaluation of pitting corrosion in offshore structures

2016 SPE Regional Student Paper Contest

March 24, 2016

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TABLE OF ABSTRACTS

Undergraduate Division Page Author Abstract Title

3 Alex Chow Examining the effects of Alberta's Climate Change Plan on oil sands producers

3 Kelsey Furey Determining the Optimum Decline Curve Exponent

4 Svetlana Temirova A Closer Look at the Bitumen Leaks in the Primrose Lake Project

4 Colin Taylor Geophysical surveys at Long Pond

5 Victoria Pollard The Impact of Normalized Relative Permeability on Estimated Ultimate Recovery

6 Jonathan Muller An Analysis of the Energy Intensity of Producing Petroleum Products from Oil

Sands Bitumen Against Shale and Conventional Oil

6 Michael Cooper Production Logging: Logging-While-Drilling vs. Wire-line Logging

Master’s Division Page Author Abstract Title

7 Ali Chamkalani A Mathematical- Graphical Window Toward Diagnosing Drilling Effectivity in

Shaly Formations

7 Armin Afrough Magnetic Resonance Imaging of Fines Migration in Berea Sandstone

8 Abhay Sablok The role of Canadian Oil Sands Bitumen in India’s Energy Mix

8 Lili Xin Numerical Modeling of Tracer Tests

9 Tianjie Qin Redevelopment of the Pembina Cardium Field by CO2-EOR Using Existing Wells

9 Jinghan Zhong DEM Simulation of Enhancing Drilling Penetration using Vibration and

Experimental Validation

10 Reza Zeinali Volume Averaging of Multiphase Flows with Hydrate Formation in Subsea

Pipelines

10 Eugenio Turco Neto NUMERICAL FLOW ANALYSIS OF HYDRATE FORMATION IN OFFSHORE PIPELINES

USING COMPUTATIONAL FLUID DYNAMICS (CFD)

11 Han Byal (Jenny) Kim Technical Feasibility of Silicon Dioxide Nanoparticles as Enhanced Oil Recovery

Agent with Applications in Offshore Reservoirs

11 Daniel Sivira Silicon Dioxide (SiO2) Nanoparticle as a Wettability Modifier Agent for Enhanced

Oil Recovery in Ben Nevis Formation, Hebron Field, Offshore Eastern Canada


March 24, 2016

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TABLE OF ABSTRACTS

PhD Division

Page Author Abstract Title 12 Mohammad Islam

Miah

Reservoir Quality Assessment Using Wireline Log Data: A Case Study

12 David Onalo Validation of a Radial Flow Cell Design at Memorial University’s Advanced

Drilling Laboratory

13 Ali Telmadarreie New Approaches to the Foam Enhanced Oil Recovery in Canadian Heavy Oil

Carbonate Reservoirs: Pore Scale Visualization

14 Hossein Khorshidian Oil Recovery Optimization in Gas Assisted Gravity Drainage

15 Hesam Hassan Nejad Experimental Screening of Surfactants for the Waste Drilling Mud Remediation

16 Dongqi Ji A Method of Predicting Temperature Dependency of Irreducible Water

Saturation in Heavy Oil/Oil Sand Reservoirs

17 Sedigheh Mahdavi The effect of carbonated water injection on residual trapped oil saturation:

Application for pore-scale flow characterization

17 Hashemi Nekouie Multi-component Gas/Oil Displacement with Constant Pressure Boundaries

18 Elahe Shekari A risk assessment approach for pitting corrosion evaluation


March 24, 2016

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EXAMINING THE EFFECTS OF ALBERTA'S CLIMATE CHANGE PLAN ON OIL SANDS

PRODUCERS

Alex Chow Undergrad Student, Chemical Engineering

University of British Columbia

Abstract This paper will examine implementation of carbon taxes in jurisdictions that produce and import oil. It will focus on Canada to assess the impact of carbon taxes on oil sands producing companies and consumers. A carbon tax is a mandatory payment to the government placed on products which generate greenhouse gas emissions. Products such as motor vehicle fuels and home heating oil are subject to carbon taxes. The purpose of a carbon tax is to increase the cost of carbon emissive products which reduces their consumption.

Creating an economic incentive to reduce carbon emissions is considered one of the most successful ways to combat global warming. However, there are many economic and political challenges. A carbon tax may raise the cost for high emissive industries such as the oil and gas sector. In areas where oil is difficult to extract, adding this additional cost could be significant to producers. Carbon policies should be developed around their respective jurisdictions.

Many details need to be carefully worked out when establishing a carbon policy. The price of carbon emissions needs to be set strategically so energy intensive industries can remain competitive yet have economic incentive to reduce their carbon consumption. Including revenue neutrality into a carbon policy needs to be considered; otherwise a carbon tax simply funds government spending. The products which are subject to the tax must also be carefully considered.

DETERMINING THE OPTIMUM DECLINE CURVE EXPONENT

Kelsey Furey Undergrad Student, Process Engineering


Abstract Understanding how to properly estimate the future performance of a well or reservoir is an essential aspect of petroleum production engineering. Analysis of how a well or field will produce enables us understand the field’s life span as well as its potential in terms of Estimated Ultimate Recovery (EUR). This study involves determining the optimum decline curve exponent for a known field that will provide the most reliable production forecast.

Many methods exist that utilize different techniques at various stages of a reservoir’s life to determine the future performance. Decline Curve Analysis (DCA), one of these methods, is utilized during the mid-to-late life cycle of the field. The studied reservoir is an ideal candidate for DCA due to the sufficient production data available. The oldest producing wells and the entire field were analyzed through decline curves to determine the most representative results by selecting the optimum decline curve exponent. The four different analyses that were conducted on the data were a theoretically-fit, a manually-fit, an average-fit and a synchronized-fit.

Based on the results from all the analyses, it was clear that production was not declining in a straight line. It was observed that the higher the decline curve exponent, the more optimistic the results. Using a decline curve exponent of 0.4 or greater is too optimistic for this particular reservoir.

From this study, it is recommended that when predicting the performance of this field with decline curve analysis, the decline curve exponent should range between 0.25 and 0.3 for the optimum and most representative performance prediction.


March 24, 2016

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A CLOSER LOOK AT THE BITUMEN LEAKS IN THE PRIMROSE LAKE PROJECT

Svetlana Temirova Undergrad Student, Mining Engineering


Abstract The bitumen leak in CNRL’s (Canadian Natural Resources Ltd.’s) Primrose project was investigated by both CNRL and the AER (Alberta Energy Regulator). Initially it was thought that mechanical failures in legacy wells (bad cement jobs) caused the bitumen to leak to the surface. However, further investigation by the AER determined that leakage came from four different locations and shut down operations. It was determined that the pay zones were over-pressured and fractured that cap rock which caused the leaks. The lake was drained and cleaned up. Production has resumed at lower steam pressures. This incident has influenced changes in the regulatory process. Before the incident, an honor code was in place and, the AER tended to accept whatever the operator told them as fact and follow it up with a cursory inspection. As a result of the Primrose incident, when the leaks were first under-reported and followed by persisted leakage, the AER was forced to conduct its own investigation. This lead to a requirement for surveying legacy wells in a development area by the operators before they are given a production permit. This paper will further investigate the causes, effects and mitigation methods used to clean up the Primrose leak, as well as the implications for legacy wells and testing for anisotropic characteristics of cap rock, stringers in pay, and determining steam and hear pressure when designing SAGD programs.

GEOPHYSICAL SURVEYS AT LONG POND

Colin Taylor

Undergrad Student, Geoscience Memorial University of Newfoundland

Abstract SP, DCR, Loop-Loop EM, VLF, and GPR, and magnetic surveys were conducted in Long Pond, Newfoundland and Labrador. The target of investigation was to determine any subsurface features at the survey area by analyzing the data we retrieved from the surveys. The area itself is a hill oriented downwards toward a waterbody. The surveys were conducted along a grid of 7 constructed lines, each with different length that is dependent on the surrounding buildings and pond, with a base line that went along the strike of the incline. Our group was responsible for conducting surveys along line 0, the first line on the grid.

The surveys took place over a period of 6 weeks while the mapping and software analysis took place in the Alexander Murray Building lab during the remainder of the semester using Oasis Montaj. We were able to find Potential Difference (SP), Total Magnetic Intensity (Mag.), Subsurface Resistivity (DCR), Inphase and Quadrature (EM31/VLF), and any layering as well as underlying objects (GEM2/GPR).

From these results, we discovered a magnetic dipolar anomaly. Through the other surveys we were able to detect the all the anthropogenic features buried beneath the ground that stemmed from the buildings, and in some surveys the buildings influenced the results as well.


March 24, 2016

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BRIDGE OVER TROUBLED WATER: KEY ISSUES AND STRATEGIES IN WATER

MANAGEMENT FOR ALBERTA’S OIL SANDS

Nathalie Carson Undergrad Student, Mining and Mineral Processing Engineering


Abstract Oil sands development is contentious in Canada and challenged by environmentalists worldwide. Although oil sands development has driven economic growth in Canada, there are concerns that oil sands development contributes to climate change and for the long-term, ecological health of the region. In 2013 GHG emissions from oil sands represented 2% of Canada’s greenhouse gas emissions and 0.2% of greenhouse gas emissions worldwide. But production has increased 500 000 barrels per day since then and is projected to increase further. Key issues are water use and greenhouse gas emissions. Processing bitumen requires a drawdown of water from the Athabasca River ranging from 1% of flow to 3% of flow in a drought year. Although the emissions intensity of a barrel of oil sands crude decreased by 40% between 1990s and 2013, increasing production means that total greenhouse gas emissions will increase unless additional measures are implemented to mitigate them. However, the use of water is a more immediate and therefore critical environmental concern because reducing water use will have the additional benefit of reducing greenhouse gas emissions. This paper will focus on how the Alberta Energy Regulator and oil sands operations are working together to reduce water use and ghg emissions. Issues regarding water quality and recycling process water are addressed. Water management techniques are identified and described. Their impact in reducing water use and improving water quality while reducing greenhouse gas emissions is explained.

THE IMPACT OF NORMALIZED RELATIVE PERMEABILITY ON ESTIMATED ULTIMATE

RECOVERY

Victoria Pollard Undergrad Student, Process Engineering


Abstract A typical hydrocarbon reservoir consists of multiple rock types or facies. In reservoir modelling, capturing the properties of each rock type is essential. Relative permeability data, which describes rock-fluid and fluid-fluid interactions, is often a tuning parameter in History Match (HM). The objective of this project is to analyze the effect of applying normalized relative permeability data to model the reservoir. The effect is examined using both manual and automatic HM, and then predicting an Estimated Ultimate Recovery (EUR) in two scenarios.

Relative permeability curves for each rock type are prepared using appropriate saturation function equations. The normalization phase requires using separate sets of equations, after which the normalized curve will be de-normalized for input into the simulation model. Then, the resulting relative permeability curve is used in HM by applying manual and automatic methods. The resulting matches are used to predict recovery. The reservoir simulation output using the normalized relative permeability curve is compared to the base case scenario.

Reservoir simulation outputs from normalized relative permeability curves were found to compare very well with outputs using individual rock type relative permeability, with improved efficiency, for the field under study. Normalized relative permeability data, when used with sound engineering judgement, can be very efficient. Mostly desired as part of HM, having a single representative set of relative permeability data for the reservoir can improve efficiency and save costs.


March 24, 2016

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AN ANALYSIS OF THE ENERGY INTENSITY OF PRODUCING PETROLEUM PRODUCTS

FROM OIL SANDS BITUMEN AGAINST SHALE AND CONVENTIONAL OIL

Jonathan Muller Undergrad Student, Chemical Engineering


Abstract The purpose of this report is to provide a detailed analysis and comparison of the energy intensity of refined petroleum products (mainly gasoline and diesel fuels) processed from Canadian Oil Sands bitumen, US tight oil (Shale Oil) and conventional oil. In addition, a comparison regarding emission intensity of carbon dioxide for these resources is made. Overall, the degree of climate change associated with oil production is proportional to the production method’s energy intensity. The effect of oil sands and shale oil extraction on climate change is a major factor in the approval of pipelines. Based on energy return on investment (EROI), oil sands have only a slightly higher energy intensity than shale oil. However, the public perception that the oil sands are a huge emitter of green house gases prevents pipelines such as Keystone and Energy East from getting approval. In fact, oil sands green house gas emissions account for less than 0.15 % of global emissions. With worldwide population expected to grow as high as 11 billion by 2050, global energy demands will continue to rise. It is important to meet these demands in an environmentally responsible way. America’s recent shale oil boom has displaced most foreign imports except for oil sands bitumen. But, President Obama has allowed producers in the US to export oil and it is likely that oil sands bitumen will continue to be imported at the same or even higher rates of production in future years.

An energy life cycle assessment is conducted on oil sands processing, from extraction to refining. A similar approach is taken for shale and conventional oil processing. The life cycle analysis of these resources includes upstream costs. With upstream costs taken into account, the difference in energy intensity between oil sands bitumen and shale oil diminishes or is eliminated entirely.

PRODUCTION LOGGING: LOGGING-WHILE-DRILLING VS. WIRE-LINE LOGGING

Michael Cooper Undergrad Student, Mechanical Engineering


Abstract Production logging is a cased-hole operation used in oil production to gain insight into well characteristics and the geology of a reservoir. By running production logs operators are able to determine which reservoirs contain hydrocarbons and present viable well potential. Oil recovery operations primarily use 2 logging methods, including: Logging while Drilling (LWD), and Wire-line Logging. LWD is the most commonly used operation off the coast of Newfoundland but has discrepancies when compared to the data of wire-line logging. Should it be necessary for operators to conduct wire-line logs in addition to an LWD upon completion of a new well?

This report will analyse how the function of multiple measurement tools differ between the LWD and Wire-line logging methods and why discrepancies exist between their data. Analysing production logs of an undisclosed oil field will test the effectiveness of these methods. Data from 15 wells will be analysed, each well protruding multiple reservoirs. First the results of an LWD will be analysed to determine which reservoirs in each well contain hydrocarbon potential. Next, the same 15 wells will be analysed using wire-line logging data. The standard for hydrocarbon potential will remain constant by selecting a range for each type of measurement data (ie. GR, Resistivity, Porosity, etc.). If each data set is within it’s specific range, the reservoir will be classified as either “hydrocarbon bearing” or “non-hydrocarbon bearing”.

Upon comparing which reservoirs contain hydrocarbon potential through the use of both logging methods, we will conclude whether the discrepancies between the logging tools are large enough to affect the analysis of a reservoir. For example, if the 2 logging methods indicate that the same well holds different potential for Hydrocarbon amongst it’s reservoirs, we can conclude that both logging techniques should be used for a deeper analysis of the well.

*Note data collection and analysis is not yet complete.


March 24, 2016

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A MATHEMATICAL- GRAPHICAL WINDOW TOWARD DIAGNOSING DRILLING EFFECTIVITY

IN SHALY FORMATIONS

Ali Chamkalani Master’s Student, Oil and Gas Engineering


Abstract The problem of slow drilling in deep shale formations occurs worldwide causing significant expense to the oil industry. Bit balling is widely considered as the main cause of poor bit performance in shale, especially deep shale which are being drilled with water-based mud. Therefore, efforts have been made to develop a model to diagnose drilling ineffectivity/effectivity. In our study, we introduced a graphical approach which acquires rate of penetration, depth of cut and specific energy as well as cation exchange capacity so as to provide a user-friendly and visual tool for drilling engineer by which a screening can be made before and during drilling operation.

This paper describes a promoted version of support vector machine (SVM) methodology that offers noticeable performance for drilling engineering problems whether drilling efficiency in shaly formations or other operations. To reinforce the basis of technique, we incorporated least square support vector machine and Coupled Simulated Annealing optimization as LSSVM-CSA technique. This hybridization will bring out an efficient tuning of SVM hyper parameters.

Each of the three parameters i.e., rate of penetration, depth of cut and specific energy was separately accompanied by cation exchange capacity to yield a graphical window so that each of them will predict the drilling operation effectivity. As each of the plots can be distinctly interpreted, the decision made by wrapping up the three plot will be more reliable. Also, we performed Receiver Operating Characteristic as a performance indicator for classifiers evaluation. Receiver Operating Characteristic (ROC) profile represented a close creep to upper-left corner and proved the high accuracy and reliable behavior of LSSVM classifier. Performance analysis showed that LSSVM classifier noticeably performed with high accuracy, and adapting such intelligent system will help petroleum industry to dealing the well drilling consciously.

MAGNETIC RESONANCE IMAGING OF FINES MIGRATION IN BEREA

Armin Afrough Master’s Student, Chemical Engineering

University of New Brunswick

Abstract Fines migration is a phenomenon of practical importance in the petroleum production and drilling industry. The movement of clay particles, induced by incompatible aqueous phase chemistry or high flow rate, obstructs pore throats downstream of the fluid flow leading to permeability reductions that can be as large as two orders of magnitude. Magnetic resonance imaging (MRI) methods based on Carr-Purcell-Meiboom-Gill (CPMG) can map T2 distributions in porous rocks, hence showing the spatial variation of the pseudo pore size distribution.

The traditional water-shock experiment is employed to mobilize clay particles in the aqueous phase flowing in a Berea core plug. Spin Echo - Single Point Imaging (SE-SPI), a phase encoding MRI method based on the CPMG method, is employed to determine spatially resolved T2 spectra of the sample, and therefore the pseudo pore size distribution.

The shift in the T2 spectra of the core inlet and outlet showed opposite trends. The pore size distribution of the inlet and outlet, inferred from T2 distributions, were shifted to larger and smaller values respectively. Mean T2 permeability model and transverse relaxation rate in the fast exchange regime were employed to calculate permeability and surface area ratios along the core after and before the flooding.

While permeability increased in the first half of the core plug—twofold at 10 mm from the inlet end—it decreased from approximately the mid-point of the core to its outlet end. The surface area ratio was 0.90 and 1.1 near the inlet and outlet ends of the core respectively. This method, not only can demonstrate permeability impairment, but also has the capability of testing the remedial processes. In a broader perspective, this method presents a new quantitative approach to non-invasively study different formation damage processes spatially and temporally.


March 24, 2016

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THE ROLE OF CANADIAN OIL SANDS BITUMEN IN INDIA’S ENERGY MIX

Abhay Sablok Master’s Student, Petroleum Engineering


Abstract This report will look at India’s reliance on imported oil to meet its energy needs. Specifically, it will look at the role Canada may play as a supplier of oil sands synthetic crude to India. India has the largest refinery in the world today, with a capacity to refine 1100000b/d. Presently India has a higher rate of economic growth than China.

Historically, a country’s economic growth has been measured by its energy consumption, which today is still predominantly fueled by oil. Although technological advances and innovation is reducing the reliance of economic development on energy consumption, it continues to be a key indicator of economic growth in the foreseeable future. India is the fourth largest consumer of crude oil in the world.

The decline in crude oil prices globally from November 2015 to date has marked effects on importers as well as exporters. This report will look at the role of oil in India’s energy mix for the next 20 years, the likelihood of Canadian Oil Sands synthet ic crude being exported to India and the role of the Indian Government and other companies (NOC’s integrated oil companies and independents) in acquiring reserves to meet India’s future energy needs. It is noted that oil and gas properties in the Sudan were acquired from Talisman resources (a Canadian oil and gas company) to secure downstream oil supplies. An overview of this acquisition, and others; as well as future scenarios are discussed.

NUMERICAL MODELING OF TRACER TESTS

Lili Xin Master’s Student, Oil and Gas Engineering


Abstract Wettability is an important reservoir characteristic when optimizing oil recovery. The wetting preference of the rock influences oil productivity during all stages of oil recovery from primary to tertiary or enhanced oil recovery. The wettability obtained from reservoir scale tracer tests can avoid the disadvantages of laboratory measurements: small core samples that may not be representative of the larger scale and wettability changes that may occur during handling and storage. Previous research on investigating wettability using tracer tests is based on linear adsorption tracer models. However, a tracer model using Langmuir adsorption is closer to reality. In this paper, the tracer concentration distributions from Langmuir adsorption tracer model for the water-wet reservoir, intermediate-wet reservoir and the oil-wet reservoir are compared with the results from linear adsorption model and zero adsorption model. The differences between Langmuir adsorption model, linear adsorption model and zero adsorption model are discussed for cases which have different partitioning coefficients. It is illustrated that the tracer peak concentration arrives earlier for the oil-wet reservoir than for the water-wet reservoir for all cases. The Langmuir adsorption tracer model does not show much difference with the linear adsorption model and the zero adsorption model when the partitioning coefficient is large; however, when the partitioning coefficient is small, the differences are severe and it is better to use Langmuir adsorption tracer model.


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REDEVELOPMENT OF THE PEMBINA CARDIUM FIELD BY CO2-EOR USING EXISTING

WELLS

Tianjie Qin Master’s Student

University of Calgary

Abstract CO2-EOR combined with multi-stage fractured horizontal wells has been considered as the most promising and environmentally friendly technique for unlocking tight oil resources. With more than 2,500 horizontal wells drilled in Pembina Cardium field, utilizing existing wells and infrastructures for future CO2-EOR development is economically attractive. Nevertheless, the drilling, completion and hydraulic fracturing design and practices can vary greatly as a result of different geological conditions, operator preferences as well as technology advancements through the years. In this study, an effective workflow that selects hydraulic fractured horizontal wells suitable for CO2-EOR in consideration of both reservoir and completion qualities is presented. The process of identifying refracturing candidates and potential risk associated with CO2-EOR performance is also developed.

Two groups of parameters, reservoir quality group (remaining oil in place, permeability, reservoir depth and fluid type) and completion quality group (well lateral length, well spacing, fracture spacing, SRV and skin factor) are first defined. A fully compositional simulator is applied to study the effects of these parameters on reservoir response to CO2 injection. Fuzzy Analytic Hierarchy Process (F-AHP) is then employed to rank candidate horizontal well pads for CO2-EOR.

Great agreement is obtained in the ranking results and simulated oil recovery factor for each candidate. In addition, with the help of cross plot, the horizontal wells with below average completion quality but relatively good reservoir quality are selected as refracturing candidates. Risk analysis reveals that the presence of conglomerate on top of the Cardium formation,

permeability heterogeneity and purity of injected CO2 agent can influence CO2-EOR performance at different levels.

This work provides an integrated approach to select existing horizontal wells for future CO2-EOR development as well as the identification of refracturing opportunities. It is reliable with consideration of both well completion and reservoir qualities. Moreover, this approach is efficient without establishing simulation model for each candidate well pad.

DEM SIMULATION OF ENHANCING DRILLING PENETRATION USING VIBRATION AND

EXPERIMENTAL VALIDATION

Jinghan Zhong Master’s Student, Oil and Gas Engineering


Abstract This paper details a study of Discrete Element Method (DEM) simulation of drilling penetration and is part of a broader investigation of the influence of bit vibration and rock-cutter compliance on enhancing drilling performance. It has been shown from laboratory experiments and field drilling trials that axial bit vibration (induced by modulated bit-rock compliance) can play a positive role in improving drilling rate of penetration (ROP), and the Drilling Technology Laboratory (DTL) at Memorial University of Newfoundland has incorporated this into passive Vibration Assisted Rotational Drilling (pVARD) technology and drilling tools. This paper focuses on DEM simulation of PDC bit penetration and experimental validation of drilling with and without the pVARD technology, all other factors being equal, as a means of both evaluating the pVARD technology and understanding the basis of enhancing drilling performance. Simulated axial vibration properties such as amplitude and frequency were adjusted with different settings of spring compliance and dampening layers, simulating the physical configuration of the pVARD tool used for laboratory experiments. Analysis of Mechanic Specific Energy (MSE), Material Removal Rate (MRR) and Depth of Cut (DOC) are calculated to evaluate drilling performance and efficiency, and are used to compare the pVARD and non pVARD drilling results. In general, the DEM simulations agree with the experimental drilling results, and both indicate improved drilling performance using the pVARD technology.


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VOLUME AVERAGING OF MULTIPHASE FLOWS WITH HYDRATE FORMATION IN SUBSEA

PIPELINES

Reza Zeinali Torbati Master’s Student, Mechanical Engineering


Abstract In oil and gas pipeline operations, the gas, oil, and water phases simultaneously move through pipe systems. The mixture cools as it flows through subsea pipelines, and forms a hydrate formation region, where the hydrate crystals start to grow and may eventually block the pipeline. The potential of pipe blockage due to hydrate formation is one of the most significant flow-assurance problems in deep-water subsea operations. Due to the catastrophic safety and economic implications of hydrate blockage, it is important to accurately predict the simultaneous flow of gas, water, and hydrate particles in flowlines. Currently, there are few or no studies that account for the simultaneous effects of hydrate growth and heat transfer on flow characteristics within pipelines.

This thesis presents new and more accurate predictive models of multiphase flows in undersea pipelines to describe the simultaneous flow of gas, water, and hydrate particles through a pipeline. A growth rate model for the hydrate phase is presented and then used in the development of a new three-phase model. The conservation equations are solved based on an analytical/numerical approach using Newton-Raphson method for the nonlinear equations. An algorithm was developed in Matlab software to solve the equations from the inlet to the outlet of the pipeline. The developed models are validated against a single-phase model with mixture properties, and the results of comparative studies show close agreement.

This model predicts the volume fraction and velocity of each phase, as well as the mixture pressure and temperature profiles along the pipeline. The results from the hydrate growth model reveal the growth rate and location of the first hydrate. Finally, parametric studies have been conducted. The results show the effect of a variation in the pipe diameter, mass flow rate, inlet pressure, and inlet temperature on the flow characteristics and hydrate growth rates.

NUMERICAL FLOW ANALYSIS OF HYDRATE FORMATION IN OFFSHORE PIPELINES USING

COMPUTATIONAL FLUID DYNAMICS (CFD)

Eugenio Turco Neto Master’s Student, Oil and Gas Engineering


Abstract Hydrate formation is one of the major challenges faced by the Oil and Gas industry in offshore facilities due to its potential to plug wells and reduce production. Several experimental studies have been published so far in order to understand the mechanisms that govern the hydrate formation process under its thermodynamic favorable conditions; however, the results are not very accurate due to the uncertainties related to measurements and metastable behavior observed in some cases involving hydrate formation. Moreover, thermodynamic models have been proposed to overcome the latter constraints but they are formulated assuming thermodynamic equilibrium, which such condition is difficult to achieve in flow systems due to the turbulence effects. Due to the low solubility of methane in water, the mass transfer effects can possibly control several mechanisms that are still unknown about the hydrate formation process. Also, reaction kinetics plays a major rule in minimizing hydrate formation rate. The objective of this work is to develop a mechanistic Computational Fluid Dynamics (CFD) model in order to predict the formation of hydrate particles along the pipeline from a hydrate-free gas dominated stream constituted by methane and water only. The transient simulations were performed using a commercial CFD software package considering the multiphase hydrate chemical reaction and mass transfer resistances. The geometry used was a straight pipe with 1 m length and 0.0254 m diameter. A sensitivity analysis study was done in order to track the main process parameters that could be manipulated to minimize the hydrate formation process under offshore operating conditions. The results have shown that during the hydrate formation process, mass transfer and reaction kinetics controlled regions are formed along the flow, which such behavior is typically found in most chemical reactors.


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TECHNICAL FEASIBILITY OF SILICON DIOXIDE NANOPARTICLES AS ENHANCED OIL

RECOVERY AGENT WITH APPLICATIONS IN OFFSHORE RESERVOIRS

Han Byal (Jenny) Kim Master’s Student, Oil and Gas Engineering


Abstract Enhanced Oil Recovery (EOR) entails extraction of post-production oil residing in a reservoir after water or gas has been injected. The use of nanoparticles is a novel method of chemically enhancing the oil recovery. Nanoparticles are believed to improve the efficiency of the recovery at the pore scale by reducing the interfacial tension between the water and oil. Unfortunately, a serious impediment to employing nanoparticles is their instability in a high salinity environment, such as seawater used in offshore production. Unstable nanoparticles are undesirable as they agglomerate, reducing their ability to reduce interfacial tension, and potentially blocking the pores.

This study focused on the behaviour of silicon dioxide (SiO2) nanoparticles in concentrated salt solutions. Nanoparticle sizes were measured using Zetasizer Nano ZS to determine the stability in different types and concentrations of synthetic seawater. The synthetic seawater was prepared to contain permutations of cation and anion pairs of the notably abundant ions in a typical seawater, such as Na+, Ca2+, Mg2+, Cl-, and SO42-.

The results indicate that the stability of SiO2 nanoparticles are predominantly compromised by the divalent cations (Ca2+ and Mg2+), even at low concentrations. The anions (Cl-, and SO42-) and monovalent cation (Na+), on the other hand, had minimal effect on the SiO2 nanoparticle stability. These results suggest that previous studies on the potential of SiO2 nanoparticle as an EOR agent in synthetic seawater composed of monovalent ions (Na+ and Cl-) are invalid. Further investigations are needed to obtain stable SiO2 nanoparticles in more complex synthetic seawater to emulate offshore reservoir conditions which may require utilization of a stabilizing agent.

SILICON DIOXIDE (SIO2) NANOPARTICLE AS A WETTABILITY MODIFIER AGENT FOR

ENHANCED OIL RECOVERY IN BEN NEVIS FORMATION, HEBRON FIELD, OFFSHORE

EASTERN CANADA

Daniel Sivira Master’s Student, Oil and Gas Engineering


Abstract The Hebron Project is the fourth major offshore development in the province of Newfoundland and Labrador, with an estimated 2620 MBO in place but only 30 percent is considered recoverable. The Ben Nevis Formation is anticipated to produce approximately 80 percent of the Project’s crude oil. Considering the rising energy consumption, there is a need to produce more crude oil. Hence the attention is required to more efficient and innovative technologies for recovering more oil.

The goal of this research was to evaluate the effects of SiO2 nanoparticles on the wetting characteristics of the synthetic cores. It is known that during waterflooding in water wet cores total oil recovery increases. Based on the mineralogical composition found in the Ben Nevis formation, two different synthetic cores that best represented facies of the Ben Nevis formation were selected. One challenge was forming a stable nanoparticle-water solution in seawater from the offshore eastern Canada. Since salinity directly affected the stability of the nanofluid, a stabilizer was employed. The core plugs were then aged in the stable nanofluid solution at different periods of time to determine the nanoparticles ability to alter the wettability of the core.

After the aging process, preliminary contact angle experiments were conducted under the reservoir condition (62 °C and 2755 psia) with IFT 700 equipment. The results concluded that soaked core plugs in SiO2 nanofluid produced a significant alteration in contact angle compared to the initial contact angle of the core plug. The reduction in the interfacial tension between oil and water was observed as well, proving the potential of SiO2 nanoparticle as an enhanced oil recovery agent.


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RESERVOIR QUALITY ASSESSMENT USING WIRELINE LOG DATA: A CASE STUDY

Mohammad Islam Miah PhD Student, Oil and Gas Engineering Memorial University of Newfoundland

Abstract The quality of a hydrocarbon reservoir is defined by its hydrocarbon storage capacity and deliverability. The hydrocarbon storage capacity is characterized by the effective porosity and the size of the reservoir, whereas the deliverability is a function of the permeability. Porosity and permeability are key parameters that are readily measured on rock samples, from well logs and well testing. This study shows the shaly sand reservoir assessment using wireline log data. Reservoir zone is detected by Resistivity and Porosity logs with helping by Lithology logs and Caliper log. Lithology identification and sand thickness is calculated from well logs. Effective porosity has been estimated from neutron-density combination formula. Water saturation is estimated from Archie’s formula, Simandoux model and Indonesia Equation. The gross reservoir areas have been estimated at three different structure depth cases like Gas Down To (Lowest Known Gas), Spill point and common Gas Water Contact of this field. Reserve is estimated from volumetric method using aforementioned parameters then compared with material balance method. Reservoir quality is good. These results are more reliable for further analysis of reservoir studies.

VALIDATION OF A RADIAL FLOW CELL DESIGN AT MEMORIAL UNIVERSITY’S ADVANCED

DRILLING LABORATORY

David Onalo PhD Student, Oil and Gas Engineering Memorial University of Newfoundland

Abstract Background/problem statement: The movement of fluids in the near well-bore region was formerly characterized as a linear flow but more recent advances in the understanding of wellbore (Thomas W. Engler, 2010) flow suggests a radial flow in the near well-bore region. Simple representation, simulation and prediction of this phenomena and associated effects remain a challenge in the industry.

Objectives: The information provided in this paper will validate that the radial flow cell developed at Memorial University can adequately simulate radial flow from the wellbore to the far-field region of a reservoir. This validation will mean that typical formations can be predicted from the rate of flow, direction (convergent or divergent), the permeability, pore throat and grain size of the core sample in the radial flow cell.

Methodology: The radial flow cell is made up of an external shell through which external pressures of up to 3000psi can be applied to simulate the confining pressure of the reservoir. There is a permeable membrane (sand formation) to simulate the porous media through which the pressure/ stress is transferred to the cylindrical core sample to simulate the wellbore. The work carried out involved setting boundary conditions from the pressure and flow direction in the near wellbore region to far-field region to simulate typical production and injection operations in the field. Using laboratory data to monitor and set pressure and flow in the cell, it was possible to predict and tell the flow direction, the rate of flow, determine the type of formation through permeability and pore throat size readings. In order to validate the results of the experiments conducted with the flow cell, core samples from known formation with known parameters were used. If the results from the flow cell were similar to the known parameters, validation and verification of the radial flow cell was accomplished.

Key Results:

pressure and stress profiles in the wellbore, near wellbore region and far-flied region

the flow pattern, direction and chart in the wellbore, near wellbore region and far-flied region

Validation of parameters with other proven equipment

Numerical calculation of the permeability of the core sample.

Conclusions: The results show the consistency with the parameters of the know core sample thereby validating the radial flow cell and its use for further experiments. Preliminary analysis of the core suggest regions of increased stress and reduced permeability, this will be studied extensively in the next stage. The radial flow cell design is valid and sufficient to simulate and conduct experiments to further study effects in the wellbore region.

http://wiki.aapg.org/Porosity

http://wiki.aapg.org/Permeability


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NEW APPROACHES TO THE FOAM ENHANCED OIL RECOVERY IN CANADIAN HEAVY OIL

CARBONATE RESERVOIRS: PORE SCALE VISUALIZATION

Ali Telmadarreie

PhD Student, Mining and Petroleum Engineering University of Alberta

Abstract A significant reserve of conventional light to heavy crude oil in the Western Canadian Sedimentary Basin (WCSB) is located in the carbonate formation. Besides thermal methods, chemical, gas, water, and solvent injections can be used for carbonate heavy oil recovery. However, many advantages of these production methods are usually contrasted by their low recovery factor due to the high viscosity of oil and the fractured nature of carbonate formations. Foam injection has gained interest in conventional oil recovery in recent times; however, its potential for heavy oil recovery is less understood. The challenge is to understand how foam can help us to improve the sweep efficiency of high viscous oil in heterogeneous reservoirs.

This study introduces three new approaches to access the heavy oil from fractured carbonate reservoirs: (1) Polymer enhanced foam (PEF) flooding, (2) foam/PEF after solvent injection, and (3) solvent based foam (SBF) injection. The performance of these methods was also compared with that of CO2 gas and solvent injections. A specially designed fractured micromodel was used to visualize the pore scale phenomena during the heavy oil recovery process. A high definition camera was utilized to capture high quality images.

Observation through this study (in all three approaches) proved that stable foam/PEF bubbles can significantly push the injected fluid toward untouched parts of the porous media and increase the oil recovery. In the first case (PEF), the effectiveness of PEF in heavy oil sweep efficiency was much higher than that of conventional foam due to the liquid viscosity enhancement and bubble stability improvement. PEF bubbles generated an additional force to divert surfactant/polymer into the matrix. In the second case, foam was injected after solvent injection when the solvent reduced the viscosity of heavy oil. Besides increasing oil recovery, the main advantage of foam after solvent injection is reducing the amount of solvent injected into the reservoir as well as formation damage caused by asphaltene precipitation as observed in this study. In the third case, solvent in the foam structure diffuses and mixes with viscous oil and reduce the viscosity. Later, foam bubbles improve the sweep efficiency by diverting the solvent toward untouched part of the porous media.

Successful application of foam can significantly improve the heavy oil recovery in reservoirs with high heterogeneity and oil-wet matrix. Cooperation of diffusion/dispersion, mobility reduction, and fluid diversion mechanisms will result in faster oil production and lesser amount of oil will leave behind improving the sweep efficiency.


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OIL RECOVERY OPTIMIZATION IN GAS ASSISTED GRAVITY DRAINAGE

Hossein Khorshidian PhD Student, Oil and Gas Engineering Memorial University of Newfoundland

Abstract Background and Objective: Oil recovery during Gas Assisted Gravity Drainage (GAGD) is controlled by the capillary and gravity forces, which are determined by the fluid and formation properties. One of the controllable parameters in GAGD is the type of the injected gas. The objective of this research is to understand the effect of the gas-oil interfacial tension and differential density on the oil recovery mechanisms.

Methodology: In this study, oil recovery parameters, including the gas properties and wettability, were theoretically examined in a non-circular capillary tube. Experiments were also conducted in oil-wet and water-wet pore network micromodels to evaluate the pore scale oil recovery during CO2 GAGD.

Results: It is shown that the residual oil saturation during GAGD is affected by the interfacial tensions between pairs of gas, oil and water phases. In addition, the porous media heterogeneity and state of wettability influence the GAGD oil recovery mechanisms. The wettability and interfacial tension determine the shape of contacts between phases. The pore-scale heterogeneity controls the path of draining fluids and residual saturation of liquid phases. In GAGD, the presence of micro-capillaries enables the liquid phases to maintain a stronger capillary continuity. The gas-oil differential density, under the force of gravity, increases the gas-oil capillary pressure behind the gas-oil contact front, which reduces of the residual oil saturation by carrying it downward through thick film layers. The gravity force can increase the gas-oil capillary pressure up to a threshold value beyond which the oil film ruptures and no further contributes to oil recovery. The threshold capillary pressure is the result of geometric constraints.

Significance: A gas type selection criterion is developed to minimize the post GAGD residual oil saturation in smaller pore structures. The criterion illustrates that how reduction of the interfacial tension and differential density between gas and oil improves the oil recovery in GAGD operations.


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EXPERIMENTAL SCREENING OF SURFACTANTS FOR THE WASTE DRILLING MUD

REMEDIATION

Hesam Hassan Nejad

PhD Student, Oil and Gas Engineering Memorial University of Newfoundland

Abstract Waste drilling mud is the second largest waste volume produced in the oil and gas exploration and production industry which cannot be discharged into the environment without proper treatments. Strict environmental regulations are in place regarding the disposal of the waste drilling mud to minimize its effect on the environment. Different technologies have been proposed for waste drilling mud remediation; however, surfactant-enhanced washing can be considered as one the most efficient, cost-effective, and environmentally-friendly processes. Selection of the best possible surfactant is the most significant step towards a successful waste drilling mud remediation. Various surfactants have been suggested for the drilling mud remediation; however, a detailed experimental screening of the potential surfactants is missing from the literature. Furthermore, there is no research conducted on the surfactant performances based on the interfacial tension and soil sorption analysis. The ability of surfactants to reduce the oil-water interfacial tension is a significant indication of their ability to remediate the waste drilling mud.

The aim of the current study is to experimentally investigate the capability of different surfactants to determine their potential ability to remediate the waste drilling mud. One anionic, one non-ionic, and one non-ionic biosurfactant were all studied and two screening analysis were employed for the selection of the best surfactant among them. The interfacial tension values were measured and the behaviours of surfactants were compared at different temperatures. Since the surfactant’s sorption onto soil is a key factor in surfactant-enhanced washing processes, the sorption of each surfactant onto the waste drilling mud sediments was also analysed. It was suggested that TX-100 is the most effective surfactants based on its low sorption to the solid particles of the waste drilling mud as well as its capability to reduce the water-oil interfacial tension.


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A METHOD OF PREDICTING TEMPERATURE DEPENDENCY OF IRREDUCIBLE WATER

SATURATION IN HEAVY OIL/OIL SANDS RESERVOIRS

Dongqi Ji

PhD Student, Petroleum Engineering University of Calgary

Abstract In the two-phase flow (water and oil) through a water-wet porous medium, the flow of the water phase will cease when the water saturation reaches the irreducible saturation. The irreducible water saturation is mainly present in pendular rings between grain particles. The effect of temperature on irreducible water saturation in a porous medium has great influence on two-phase displacement and oil production, especially for the recovery of heavy oil/oil sands by steam injection. In a steam injection the irreducible water saturation can be significantly increased due to a large temperature variation from the initial reservoir temperature to saturated steam temperature. In this study, the increase of contact angel with temperature in thermal processes for heavy oil/oil sands recovery is theoretically predicted and explained.

In the mathematical modelling, a porous medium is approximated by using the pack of equal-sized hydrophilic spheres. Between any two contacted spheres a water pendular ring is formed and oil exists in the central space between the spheres as shown in Figure 1. The irreducible water saturation, which is determined by the geometry and the volume of pendular rings associates with the contact angle and interfacial tension. Based on the principle of minimum interfacial free energy, a thermodynamic criterion is proposed to determine the geometry of the pendular rings .

Both the contact angle, which is related to water-oil and liquid-solid interactions, and the interfacial tension, which is determined by fluid-fluid-solid system energy, are critical to the irreducible water saturation. The method developed in this study can be used in reservoir simulation to predict irreducible water saturation, and to optimize a thermal process for heavy oil/oil sands recovery.

Figure 1 Schematics of irreducible water in the volume of pendular ring, revolution of shape O3P1P3P2 along x-axis


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THE EFFECT OF CARBONATED WATER INJECTION ON RESIDUAL TRAPPED OIL

SATURATION: APPLICATION FOR PORE-SCALE FLOW CHARACTERIZATION

Sedigheh Mahdavi


Abstract The effectiveness of an enhanced oil recovery process depends on vertical, horizontal, and pore scale sweep efficiencies. Vertical displacement is an important indicator of every EOR flooding performance. Carbonated water injection (CWI) is an EOR method that has been recently given considerable attention. Although the effects of many parameters have been studied, the effect of gravity displacement on trapped oil extraction and fluid flow pattern are deficient in the current literature.

This paper outlines some of the qualitative results of an ongoing research project to study the applicability of CWI process for oil extraction. This work provides new insights into pore-scale displacement phenomena occurring in the presence of CWI in a water-wet glass micromodel. To evaluate the potential use of of CWI for vertical displacement, a series of experiments in a medium pressure glass micromodel have been designed accounting for phase behavior and solubility of CO2 in the water and oil. The oil saturation profile, fluid flow pattern, pore scale mechanisms and trapped oil mobilization were analyzed during the experiments. Results are compared to simple water flooding using the same micromodel apparatus.

Results of CWI show increased vertical sweep efficiency compared to simple water flooding. Furthermore, the higher density of the carbonated water phase shows improved mobility ratio and reduces unstable frontal movement during injection. The fluid flow pattern in both water flooding and carbonated water flooding shows that carbonated water phase has a greater capability to distribute evenly in all directions to contact the bypassed oil in pore channels. Hence fingering is reduced and higher recovery factor is achieved.

MULTI-COMPONENT GAS/OIL DISPLACEMENT WITH CONSTANT PRESSURE BOUNDARIES

Hashemi Nekouie


Abstract This paper presents the analytical solution of multi-component gas/oil displacements under constant pressure boundary

conditions. Previous research in gas/oil displacement problems have been completed under the assumption of constant flux

boundary conditions. In practice however, gas flooding projects are often conducted with constant injection pressure and

constant producing well pressure, where the total volumetric flux is no longer a constant value. In this work, a novel

generalization of the Buckley-Leverett classical fractional flow theory is applied to solve the problem of multi-component

gas/oil displacements under constant pressure boundaries. The mass balance in a one-dimensional, dispersion-free medium,

for a multi-component gas/oil displacement leads to a set of partial differential equations. The solution of the corresponding

initial value problem under constant flux boundaries reveals the physical displacement mechanism occurring in the porous

medium. The analytical solution indicates the chromatographic separation of components caused by a complicated

interaction between the components in the oil and the injection gas. However, in systems with constant pressure boundaries,

the total volumetric flux is a function of time and hence, the classical Buckley-Leverett theory is not valid. Yet, the solution

obtained from the constant flux boundary condition problem can be used in the solution of the associated problem with

constant pressure boundaries by determining the flux analytically as a function of time. In this work, a case study of multi-

component systems is presented, and it is indicated how the solution of the problem with constant flux boundaries can be

used to determine the time dependent volumetric flux in associated problem with constant pressure boundaries. A numerical

solution is also obtained for the problem. Comparison of the analytical and numerical solutions indicates that the numerical

solution converges to the analytical solution as the number of grid blocks increases. However, the analytical approach is

three orders of magnitude faster than the numerical approach, as a very fine grid is needed to achieve an acceptable solution

in the numerical technique.

http://www.glossary.oilfield.slb.com/en/Terms/r/recovery.aspx


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EVALUATION OF PITTING CORROSION IN OFFSHORE STRUCTURES

Elahe Shekari


Abstract Pitting corrosion is an extremely dangerous form of localized corrosion since a perforation resulting from a single pit can

cause complete in-service failure of equipment. The issue of pitting is more serious for offshore facilities, due to the harsh

corrosive environment. The ability to predict pitting behaviour is the key to designing and maintaining susceptible assets in

offshore structures to decreased costs and increase safety and productivity. Risk assessment using predictive models can

help risk practitioners to determine riskier components/area affected to pitting corrosion and make an appropriate decision in

order to reduce, prevent, pitting.

This paper presents a predictive risk assessment method to study the failure of equipment in offshore structure affected by

pitting corrosion. First the pit characteristics such as pit density and maximum pit depth are modeled. The reliability analysis

is then performed to estimate the failure probability of an affected offshore structure component using the first order second

moment method. Loss functions are used to estimate the economic consequences of affected equipment due to its failure.

Finally, integrating the failure probability with consequences, a risk assessment model is proposed. The model uses risk

profiles as a criterion to make run-repair-replace decisions. The practical application of the proposed model is demonstrated

using a piping case study in an offshore process facility affected by pitting corrosion.


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MUN SPE CHAPTER: YEAR AT A GLANCE (APRIL 2015-MARCH 2016)


March 24, 2016

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MUN SPE CHAPTER: YEAR AT A GLANCE 2015-2016


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PHOTO CONTEST FALL 2015 - WINNERS


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of Newfoundland

SPE Student Chapter www.mun.ca/sspe

Documents

2016 SPE Canada Regional Student Paper Contest SPE Canada Regional Student Paper Contest MEMORIAL UNIVERSITY OF NEWFOUNDLAND SPE STUDENT CHAPTER MARCH 24, 2016 • ST. JOHN’S •