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2014 SPE Canadian Regional Student Paper Contest MEMORIAL UNIVERSITY OF NEWFOUNDLAND SPE STUDENT CHAPTER AUGUST 27, 2014 • 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

(Building Number 18 in the Campus Map)

Faculty of Engineering and Applied Science

Memorial University of Newfoundland

St. John's, NL A1B 3X5

Canada

CONTEST

LOCATION

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Memorial University of Newfoundland Student SPE Chapter is pleased

to welcome you to the 2014 SPE Canadian 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 10 regional student paper contests at the

undergraduate, master's and doctorate 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). Currently, the 10

regional contests are recognized by the Society: Canadian, Russian,

European, US Gulf Coast, US Rocky Mountain/Mid-Continent/Eastern,

Latin American/Caribbean, Western, African, Asian Pacific, and

Middle East. The MUN SSPE Chapter is proud to host the contest for the

first time, which signifies the solid relationship we have with the SPE

Atlantic Section and the energy companies active in the local

projects.

36 abstracts from different 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 12 presentations in the combined undergraduate

/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. The 1st, 2nd, and 3rd place winners will receive

$400, $200, and $100 cash prizes, respectively. In addition, the 1st

place winners in each category will be supported by SPE International

to travel to ATCE 2014 (October 27-29, Amsterdam, The Netherlands)

and represent the SPE Canadian Region at the SPE International

Student Paper Contest.

Aside from the excellent scientific program, we have also prepared

an exciting social program that will provide delegates an opportunity

to explore, indulge and relax during their stay in St. John’s. The

Welcome Reception, Gala Dinner, Closing Ceremony, and St. John’s

sightseeing tour will give participants a chance to network among

colleagues while enjoying the cuisine, culture, and warm hospitality

that the city of St. John’s has to offer.

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 certain that you will enjoy all that this rewarding

experience has to offer.

Executive Committee

Memorial University SPE Student Chapter

WELCOME LETTER

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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 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 SSPE 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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EXECUTIVE COMMITTEE Dr. Lesley James (Contest Chairman) Assistant Professor, Memorial University

Kris Costello (Contest Co-Chairman) Manager - Development & Operations,

Nalcor Energy – Oil and Gas

Javad Hashemi (Contest Coordinator) SSPE, Memorial University

Yusuf Babatunde Reservoir Engineer, Nalcor Energy – Oil and Gas

Elahe Shekari SSPE, Memorial University

Aimiede Okosun SSPE, Memorial University

MODERATORS

Evulukwu Ebubechi Az SSPE, Memorial University

Susan Caines Safety and Risk Engineering Group, Memorial University

JUDGES

Undergraduate

& Master’s

Division

Keith Thomas Hynes Director of Petroleum Engineering,

Provincial Government Department of Natural Resources

Sareddy Escobar Gonzalez Schlumberger

Stephen Broderick Husky Energy

Jamie Hynes Husky Energy

Doctorate

Division

Kris Costello Manager - Development & Operations,

Nalcor Energy – Oil and Gas

Stephen D. Butt Professor, Memorial University

Jamal Siavoshi Husky Energy

Cesar Forero Chevron

Ming Yang Safety and Risk Engineering Group, Memorial University

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CONTEST PROGRAM – AUGUST 27, 2014

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

(Second Floor)

8:00 am – 8:30 am Welcome Reception Breakfast Lounge (EN 4000)

8:30 am – 8:45 am Welcome Speech Lounge (EN 4000)

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

Networking Session

Engineering Boardroom (EN 4002)

Lounge (EN 4000)

9:00 am – 10:40 am Presentations

EN 4002: Undergraduate and

Master’s Division

EN 4008: PhD Division

10:40 am – 11:00 am Break Lounge (EN 4000)

11:00 am – 12:15 pm Presentations


Master’s Division


12:15 pm – 1:15 pm Lunch Lounge (EN 4000)

1:15 pm – 2:30 pm Presentations


Master’s Division


2:30 pm – 2:45 pm Break Lounge (EN 4000)

2:45 pm – 3:35 pm Presentations


Master’s Division

No Presentation in PhD Division

Closing Ceremony – August 27, 2014

6:30 pm – 8:00 pm Gala Dinner and Closing

Ceremony

The Gypsy Team Room

315 Water St, St John's, NL A1C 1B9

St. John’s Sightseeing Tour – August 28, 2014

9:00 am – 3:00 pm

Iceberg Quest, Whale Watching,

St. John’s Historical Sites,

Traditional Fish and Chips Lunch

Arrive by 8:30 am at Faculty of

Engineering Lobby (Second Floor) to

Register. Breakfast will be provided.

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2014 SPE Regional Student Paper Contest Agenda August 27, 2014 – Memorial University of Newfoundland

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

SCHEDULE NAME, DEGREE ATTENDING

UNIVERSITY ABSTRACT

9:00 am – 9:25 am Abhishek Batwara, MSc UNIVERSITY OF CALGARY

Ultrarefined geological and reservoir simulation models of

a mannville

9:25 am – 9:50 am

Mohammedalmojtaba Mohammed, MSc UNIVERSITY OF ALBERTA

Wettability alteration in heavy-oil naturally fractured

carbonate reservoirs: an experimental study

9:50 am – 10:15 am Shiv Shankar Vembadi, MSc UNIVERSITY OF ALBERTA

Real-time feedback control of SAGD wells using model

predictive control to optimize steam chamber

development

10:15 am – 10:40 am Andrew Andrade, BSc UNIVERSITY OF WATERLOO

A multifaceted approach to oil field segment analysis using

artificial intelligence

10:40 am – 11:00 am BREAK

11:00 am – 11:25 am Mahsa Moayedi, MSc MEMORIAL UNIVERSITY

An experimental study on optimization of sag process

utilizing nonionic surfactants and sodium lignosulfonate

11:25 am – 11:50 am Ibrahim Ali, BSc MEMORIAL UNIVERSITY

Factors effecting rate of penetration (ROP) in offshore

drilling

11:50 am – 12:15 pm Jared Pardy, BSc MEMORIAL UNIVERSITY

Model analyses of film thickness, entrainment and pressure

drop of two-phase annular flow in vertical pipes

12:15 pm – 1:15 pm LUNCH

1:15 pm – 1:40 pm Anirudh Nandan, MSc MEMORIAL UNIVERSITY

Robust SISO control of constant bottom hole pressure

drilling

1:40 pm – 2:05 pm Ayub Khezrnejad, MSc MEMORIAL UNIVERSITY

Water enhancement using nanoparticles in water

alternating gas (WAG) micromodel experiments

2:05 pm – 2:30 pm Dan Wang, MSc MEMORIAL UNIVERSITY

High order time discretization of compartmentalized

reservoirs with advanced well completions

2:30 pm – 2:45 pm BREAK

2:45 pm – 3:10 pm Felix Rogers, MSc MEMORIAL UNIVERSITY

Comparison of predicted reservoir simulation results using a

three-dimensional permeability tensor

3:10 pm – 3:35 pm Mohammad Shadadeh, MSc MEMORIAL UNIVERSITY

Comparison of different methods of generating pseudo

relative permeability for simulation of stratified

waterflooding

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2014 SPE Regional Student Paper Contest Agenda August 27, 2014 – Memorial University of Newfoundland

Doctorate Division FACULTY OF ENGINEERING AND APPLIED SCIENCE – ROOM EN 4008

SCHEDULE NAME/UNIVERSITY ABSTRACT

9:00 am – 9:25 am Arash Mirzabozorg UNIVERSITY OF CALGARY

A novel approach to tackle multiple objectives optimization

using fuzzy logic: SAGD numerical tuning case study

9:25 am – 9:50 am Manyang Liu UNIVERSITY OF REGINA

Semi-analytical pressure transient model with boundary

element method

9:50 am – 10:15 am Mammad Mirzayev UNIVERSITY OF CALGARY

Inter-horizontal well connectivity in tight reservoirs

10:15 am – 10:40 am Nan Zhang MEMORIAL UNIVERSITY

A comprehensive evaluation of the accuracy of streamline

simulation

10:40 am – 11:00 am BREAK

11:00 am – 11:25 am Mohsen Keshavarz UNIVERSITY OF CALGARY

Modeling displacement efficiency improvement during

solvent-aided SAGD

11:25 am – 11:50 am Pushpinder Singh Rana MEMORIAL UNIVERSITY

CERCHAR abrasiveness test for synthetic rock specimens

11:50 am – 12:15 pm Hamid Behmanesh UNIVERSITY OF CALGARY

Production data analysis of liquid rich shale gas condensate

reservoirs

12:15 pm – 1:15 pm LUNCH

1:15 pm – 1:40 pm Ali Souri Laki MEMORIAL UNIVERSITY Semi-analytical approach to streamline simulation

1:40 pm – 2:05 pm Xiaoyan Tang MEMORIAL UNIVERSITY

Comparison of streamline simulation methods in the near

well (polar coordinates) region

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Gold Sponsors

Silver Sponsors

Bronze Sponsors

Organizers

Sponsors

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2014 SPE Regional Student Paper Contest

August 27, 2014

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TABLE OF ABSTRACTS

Undergraduate and Master’s Division

Page Author Abstract Title

2 Andrew Andrade Multifaceted approach to oil field segment analysis using artificial intelligence

2 Ibrahim Ali Factors effecting rate of penetration (ROP) in offshore drilling

3 Jared Pardy Model analyses of film thickness, entrainment and pressure drop of two-phase annular flow in vertical pipes

4 Abhishek Batwara Ultrarefined geological and reservoir simulation models of a mannville reservoir for optimized methane production

4 Anirudh Nandan Robust SISO control of constant bottom hole pressure drilling

5 Ayub Khezrnejad Water enhancement using nanoparticles in water alternating gas (WAG) micromodel experiments

5 Dan Wang High order time discretization of compartmentalized reservoirs with advanced well completions

6 Felix Rogers Comparison of predicted reservoir simulation results using a three-dimensional permeability tensor

6 Mahsa Moayedi An experimental study on optimization of SAG process utilizing nonionic surfactants and sodium lignosulfonate

7 Mohammad Shadadeh Comparison of different methods of generating pseudo relative permeability for simulation of stratified waterflooding

7 Mohammedalmojtaba Mohammed

Wettability alteration in heavy-oil naturally fractured carbonate reservoirs: an experimental study

8 Shiv Shankar Vembadi Real-time feedback control of SAGD wells using model predictive control to optimize steam chamber development

PhD Division

Page Author Abstract Title

8 Ali Souri Laki Semi-analytical approach to streamline simulation

9 Arash Mirzabozorg A novel approach to tackle multiple objectives optimization using fuzzy logic: SAGD numerical tuning case study

9 Hamid Behmanesh Production data analysis of liquid rich shale gas condensate reservoirs

10 Manyang Liu Semi-analytical pressure transient model with boundary element method

10 Mammad Mirzayev Inter-horizontal well connectivity in tight reservoirs

11 Mohsen Keshavarz Modeling displacement efficiency improvement during solvent-aided SAGD

11 Nan Zhang A comprehensive evaluation of the accuracy of streamline simulation

12 Pushpinder Singh Rana

CERCHAR abrasiveness test for synthetic rock specimens

12 Xiaoyan Tang Comparison of streamline simulation methods in the near well (polar coordinates) region


August 27, 2014

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MULTIFACETED APPROACH TO OIL FIELD SEGMENT ANALYSIS USING ARTIFICIAL

INTELLIGENCE

Andrew Andrade Undergrad Student, Mechatronics Engineering

University of Waterloo

AbstractToday’s subsurface engineers make sense of large amounts of structured and unstructured data in the form of reports, logs, charts and models. Understanding production patterns and their relation to the reservoir are not possible with current techniques since the correlation between reservoir properties and production data is either nonexistent or poor established.

This paper outlines how to best use this historical data to discover general consistencies and optimize the process of making decisions related to efficient and environmentally friendly production of oil and gas using a hierarchical multifaceted approach based on data visualization, data mining and distributed computing techniques. This paper is limited to the novel applications and process flow for use of new technology first by outlining existing analysis methods, and then outlining cross visualization between methods in a multifaceted hierarchical manner. The methods in this paper are divided into three categories: initial oil in place, well history summaries and fluid flow in the reservoir. The first is divided into material balance and the comparison with the geology & geophysical static model. The second discusses the production, pressure and workover histories over time, the decline forecasting, estimated ultimate recovery and recovery factor in the field segment. The last describes the spatial understanding of fluid flow in the layered reservoir and its relation to identifying improved and enhanced oil recovery techniques. The results of the analysis are presented in the form of field optimization forecasting in the field.

The major conclusions in this paper are that a hierarchical strategic approach to data visualization of existing production, geological and petroleum data provides better optimization decisions and an overall increase in the oil and gas production in the segment. Applications of this paper would establish new petroleum software analysis and distributed computing tools.

FACTORS EFFECTING RATE OF PENETRATION (ROP) IN OFFSHORE DRILLING

Ibrahim Ali Undergrad Student


Abstract My research is mainly regarding the drilling operations done offshore in Newfoundland. This research is a part of my learning from one of my Engineering Work term in an Oil and Gas company. The rate of penetration (ROP) is the measure of how fast a Drill bit can penetrate the rock formation while remaining cost efficient and fulfilling all the safety criteria. It can be optimized by several factors such as following.

Type of Drill Bits: The roller cone bits are used to drill softer formation, usually the riser less section of a borehole which is also cost effective as due to the wear and tear the bits are only used once in offshore drilling. The Polycrystalline diamond compact (PDC) bits have small diamond cutters, which increases the shear force onto the rock which directly affects ROP.

Rock Formation, porosity and strength: There are different kinds of rock layers below sea level. Mainly Banquereau, shale, limestone, Ben Nevis, and Hibernia. The benquereau is easy to penetrate hence can result in a faster ROP, whereas limestone usually has a lot of faults in it, which makes the ROP decrease and its more harder to drill through it. Secondly while drilling through a porous rock; there is a loss of drilling fluid which results in decrease of ROP.

Drilling Fluid and Bit nozzle: One of the most important factors which affect the ROP is the drilling fluids. A proper hydraulics and a good mud weight can significantly promote in a faster drilling rate. Also the bit nozzles allow a pressure flow of mud pumped from the rig. Hence by altering the area of the nozzle we can increase the pressure which will help in breaking the rocks and help the bit to penetrate faster.


August 27, 2014

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MODEL ANALYSES OF FILM THICKNESS, ENTRAINMENT AND PRESSURE DROP OF TWO-PHASE ANNULAR FLOW IN VERTICAL PIPES

Jared Pardy

Undergrad Student, Process Engineering Memorial University of Newfoundland

Abstract The presence of liquids in natural gas wells increases the pressure drop within the well due to differences in density of the pressure head. A very common type of two-phase flow is annular flow, which is characterized by a slow moving liquid film along the pipe walls and a fast moving gas in the center of the pipe. In annular flow, liquid may be present in entrained droplets as well as the aforementioned film.

To determine the pressure drop, the density of the two-phase fluid must be determined. The density is a function of the liquid film thickness and the entrained droplets within the gas. The liquid film is characterized in two parts: a base film and a wavy disturbance layer. The amount of entrained liquid is dependent on the behavior of this wavy disturbance layer and its interaction with the gas component. Understanding the fundamentals of annular flow is critical in understanding natural gas production mechanics.

A number of models have been proposed over the past 50 years to predict film thickness, liquid entrained fraction, and pressure drop in pipes with vertical two phase annular flow. Earlier models are based on correlations from experimental data while Schubring & Shedd (2011) proposed a method for determining pressure drop based on fundamental mass balance principles and a two-zone film (base and wave) model. This paper proposes a new pressure drop model that is a modified version of the work proposed by Schubring & Shedd (2011). A method to calculate film thickness is not included in Schubring & Shedd’s (2011) pressure drop model. The proposed modified model includes a new film thickness model developed from a range of experimental data. The data comes from the works of Schubring et al. (2010 & 2008), Bai & Newell (2002), Alamu & Azzopardi (2011), Paz & Shoham (1994), and Butterwoth (1972). The experimental data covers conditions of superficial liquid velocities ranging from 0.6 to 38.8 cm/s; superficial gas velocities ranging from 13.4 to 110.6 m/s; and diameters ranging from 12 to 51 mm. This model is based on Reynold’s, Weber, and Froude dimensionless numbers and requires only diameter, fluid properties, and flowrates as inputs.

Compared with other film thickness models proposed by Elvis et al. (1991), Elamu et al. (2011), and Ansari et al. (1994), the new film thickness model agrees more closely to the experimental data.

The model of Schubring & Shedd (2011) contains calculations for determining the liquid entrained fraction. However, the method is iterative therefore to simplify the calculation an entrainment model proposed by Sawant et al. (2009) is incorporated into the modified model.

Sawant et al. (2009) entrainment model was developed to encompass higher liquid and gas flowrates and higher operating pressures by use of a modified Weber number. To determine suitability, the model was compared against experimental data from the works of Owen et al. (1989) and Sawant et al (2008). The experimental data covers conditions of superficial liquid velocities ranging from 5 to 53 cm/s; superficial gas velocities ranging from 15.7 to 470.3 m/s; and diameters ranging from 9.4 to 31.8 mm. When compared with other models proposed by Steen & Wallis (1964) and Ishii & Mishima (1989), the model of Sawant et al. (2009) agrees more closely with experimental data.

The pressure drop model approach proposed by Schubring & Shedd (2011) is based on mass balance fundamentals and by dividing the model into a base film zone and a wave zone. The argument is that it can therefore be confidently applied to all velocity, diameters, pressure, and fluid property conditions. The model requires rigorous iterations but is based on sound principles therefore a simplified version would be easier to apply and beneficial to industry. Incorporating the new film thickness model and Sawant et al. (2009) entrainment model simplifies the pressure drop computations while still providing results that agree with experimental data from the works of Schubring et al. (2010c). When compared with pressure drop models proposed by Ansari et al. (1994) and Hasan & Kabir (2007), the modified model is in closer agreement with experimental data. The modified pressure drop model helps to understand the fundamentals of annular flow which in turn is beneficial to the natural gas production industry as it further develops the understanding of production mechanics.


August 27, 2014

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ULTRAREFINED GEOLOGICAL AND RESERVOIR SIMULATION MODELS OF A MANNVILLE

RESERVOIR FOR OPTIMIZED METHANE PRODUCTION

Abhishek Batwara

Master’s Student, Petroleum Engineering University of Calgary

Abstract Background/Problem Statement: The Western Canadian Sedimentary Basin hosts large volume of deep coal seams that are potential targets for methane production. In recent years, there has been significant decline in production from Mannville CBM wells. There are biogenic reactions happening inside these coal reservoirs which is leading to generation of methane and can be potentially stimulated by injecting nutrients to raise our Expected Ultimate Recovery (EUR).

Objective: The focus of my work is to build ultrarefined geological models of these highly heterogeneous reservoir in SLB Petrel and to perform numerical simulations inside CMG STARS in order to check the economic feasibility of this technology.

Methodology: We have used combination of well logs, core analysis and well testing data to build our geological model. A combination of gamma ray and bulk density logs are used for facies modeling. Porosity-Permeability transforms are built using ~ 32000 data points from core analysis data to model permeability in our reservoir.

Key Results: We have observed that our coal seams exists as laterally discontinuous and is interbedded between very fine sandstone and shale layers. They are highly heterogeneous with low porosity values indicating that our coal is micropores dominant with very low permeability values. The mean value of permeability for our formation is 0.44 mD. These low permeability values are very strongly linked to depositional environment and needs to be enhanced by inducing fractures inside these formations. We are currently history matching our model with production data and evaluating biogenic enhancement of gas production in STARS.

ROBUST SISO CONTROL OF CONSTANT BOTTOM HOLE PRESSURE DRILLING

Anirudh Nandan

Master’s Student, Mechanical Engineering Memorial University of Newfoundland

Abstract Constant bottom hole pressure (CBHP) variant of managed pressure drilling (MPD) has been used to deal with kicks and also to enable drilling of wells with tight pressure margins. Control of this process is challenging when done manually. Automatic control is a solution to achieve precise control and to reduce the burden of the drilling operator. The control can only be as precise as the control algorithm. In this work we propose a strategy to control the BHP robustly. Especially, while drilling difficult wells any overshoot in BHP is highly undesirable as that might start a loss – kick cycle. To make it harder the estimates or measurements of BHP are inaccurate at best. The drilling mud density, well lengths, and frictional losses vary. The controller must be able to handle such variations. The considered system can provide around 30 to 60 bar of back pressure through choke manipulation. The variations contributed by the system parameters are lumped together into variations in the parameters of a first order system. The designed controller was found to handle several combinations of system properties and was able to provide substantial back pressure to alleviate the pressure requirements from hydrostatic mud weight, thereby enabling drilling with lighter mud. The controller was also found to work under uncertain pressure measurements. Under no circumstance the overshoot was more than the considered accuracy of the measurements. The controller was also able to handle drill pipe extensions during which the pump flow rate will be ramped down to zero. Robust control of MPD is found to hold great promise to enable precise control of BHP.


August 27, 2014

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WATER ENHANCEMENT USING NANOPARTICLES IN WATER ALTERNATING GAS (WAG) MICROMODEL EXPERIMENTS

Ayub Khezrnejad

Master’s Student, Oil and Gas Engineering Memorial University of Newfoundland

Abstract Nanotechnology has found widespread application in a wide range of industries. Researchers are now investigating whether nanotechnology can be applied to enhance oil recovery (EOR). The goal of enhanced oil recovery is to manipulate the fluid-fluid properties (interfacial tension (IFT), viscosity), and fluid-rock properties (contact angle, relative permeability) between the injected fluid and the residual oil phase to improve pore scale recovery efficiency. Adding nanoparticles to the injected water has been shown to improve oil recovery.

In this study, nanoparticles were added to the water phase of water alternating gas (WAG) and injected into two dimensional glass micromodels to study the effect of the nanoparticles qualitatively on oil recovery at low pressures. Silicon oxide (SiO2) and aluminum oxide (Al2O3) nanoparticles, at different concentrations, were dispersed in the brine and injected as the water phase in WAG followed by air as the gas phase. Response Surface Methodology (RSM) was used to investigate the effect of the factors and interactions between the factors on oil recovery. The results from the micromodel studies indicate that adding a small amount of nanoparticles to the brine can enhance residual oil recovery.

HIGH ORDER TIME DISCRETIZATION OF COMPARTMENTALIZED RESERVOIRS WITH

ADVANCED WELL COMPLETIONS

Dan Wang Master’s Student, Oil and Gas Engineering


Abstract Reservoir tank modeling has traditionally been employed to simplify complicated reservoir simulation models and to reduce computational time whilst maintaining model accuracy. In this paper we refine this concept by replacing a simple tank model by a system of ODEs modeling dynamic changes of well inflow, aquifer influx, fluid compressibility and pore volume effects. This model is transient during a single large time step calculation and represents an enhancement of standard finite difference method formulations.

The reservoir is subdivided possibly into a number of sub volumes, representing individual reservoir compartments and aquifers, which may or may not be in communication. Using the concepts of transmissibility and compressibility, the complex 3D reservoir system is converted into a model that establishes flow into wells and between the compartments. Pressure loss along the well for different flow regimes is also fully integrated in the model. The multiple reservoir units and flowing wellbore are coupled to provide influx and inter-tank fluid transfer. Employing the fourth-order Runge-Kutta Method, the ordinary differential equations generated by the system of reservoir units is solved accurately and efficiently.

Examples are generated to illustrate the results of the method for the prediction of oil/gas production with water encroachment from an aquifer. Results indicate that compressible fluid (gas/ water/ oil) expansion in the oil/gas depletion zone plays a relatively different role in the relationship between fluids withdrawn and reservoir pressure due to reservoir uncertainty. For some low compressible reservoirs, ignoring pore volume reduction and connate water expansion can give a good approximation for the production prediction. This research contributes to the creation of a fundamental tool enabling the estimation of reservoir production using advanced completion technologies, particularly in compartmentalized reservoirs.


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COMPARISON OF PREDICTED RESERVOIR SIMULATION RESULTS USING A THREE-DIMENSIONAL PERMEABILITY TENSOR

Felix Rogers

Master’s Student, Oil and Gas Engineering Memorial University of Newfoundland

Abstract Reservoir simulation is becoming increasingly important in the oil and gas industry. Simulation results are used to help make large capital decision, to estimate reserves, and to diagnose and improve the performance of producing reservoirs. Therefore, better understanding of the variability of reservoir properties is needed. One of the most important properties governing fluid flow is permeability, which is a directionally, spatially and scale dependent variable. This research focuses on the directional variability, or anisotropy, of permeability and its effect on predicting oil production rates.

Current reservoir simulators align the principal permeability directions with the reservoir grid coordinate system. This creates an easy to simulate diagonal permeability tensor. The challenge arises when the well path does not align directly with one of the coordinate directions. In this case the permeability should be represented by a full tensor. By rotating the principal permeability coordinates to align one of the axes with the well path we create a more realistic flow into the well bore.The full tensor created after the rotation is tested against current practices using a commercial reservoir simulator. Results from a single grid block and a slight rotation of the well path have shown a decrease in oil production when using the fu ll tensor. These results show that further investigation into full field examples need to be examined.

AN EXPERIMENTAL STUDY ON OPTIMIZATION OF SAG PROCESS UTILIZING NONIONIC

SURFACTANTS AND SODIUM LIGNOSULFONATE

Mahsa Moayedi Master’s Student, Oil and Gas Engineering


Abstract The addition of surfactants to the water phase in water alternating gas injection, called SAG injection, may produce in-situ foam in porous media. If foam is produced, the process called foam assisted water alternating gas injection (FAWAG) reduces the mobility by increasing the displacement fluid (gas) viscosity. Furthermore, the surfactant generated foam has been shown to block high permeability zones as well as reduce the interfacial tension between the water and oil phases to increase recovery.

Two challenges in foam generation during SAG injection is foam stability and the loss of surfactant by its adsorption to the rock’s surface which are directly affected by the surfactant type. Many studies have proven the significant role of using anionic surfactants such as alkylbenzene sulfonates and lauryl sulfates in improving SAG process efficiency. However, further experimental work is needed to understand the behaviour of nonionic surfactants as they account for 45 % of the overall production of industrial surfactants.

This paper reports a comparative laboratory study of two nonionic surfactants commonly used in soil washing environmental remediation (Ivey-Sol 108 and TX-100) in a series of SAG tests examining factors such as surfactant concentration (at and above the critical micelle concentration CMC), water salinity, and injection scheme. The aforementioned parameters were examined experimentally to evaluate the mobility reduction factor and overall recovery factor.

To address some of the foam stability challenges, we conducted bottle shake tests to evaluate the volume and stability of both nonionic surfactants at different concentrations. From bottle shake tests, in the presence and absence of oil, it was found that foam longevity for TX-100 was higher simply since it generates large volume of foam but the decay rate for Ivey-Sol 108 was smaller at the same concentration and water salinity.

The surfactant adsorption losses were investigated through the addition of sodium lignosulfonate (SLS) as a sacrificial additive to preferentially adsorb onto the rock’s surface. Previous work investigating the effect of sodium lignosulfonate addition to anionic SAG injection showed an improvement in ultimate oil recovery, as we also expected.


August 27, 2014

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COMPARISON OF DIFFERENT METHODS OF GENERATING PSEUDO RELATIVE

PERMEABILITY FOR SIMULATION OF STRATIFIED WATERFLOODING

Mohammad Shadadeh Master’s Student, Oil and Gas Engineering


Abstract A common method for approximating the effect of vertical permeability variation in displacement projects such as waterflooding is to assume that the reservoir is stratified. Using a convenient pseudo relative permeability, a two-dimensional numerical model can be used for simulating reservoir performance, in certain cases. Pseudo relative permeability implies the generation of a relative permeability curve that can be used to represent the entire reservoir thickness, rather than a specific layer during reservoir simulation, thus saving computational time.

This paper presents a comparison between different methods of generating pseudo relative permeability for simulation of a stratified waterflooded reservoir using either constant flow rate or constant pressure at reservoir boundaries. The generated pseudo relative permeability curve is used in a 2D areal reservoir model in an ECLIPSE simulator to predict the behavior of the full layered 3D reservoir model, and reservoir performance is compared to the results of the corresponding 3D reservoir model. Results from the 2D reservoir model are also compared to the same model using pseudo relative permeability curves generated by other methods.

WETTABILITY ALTERATION IN HEAVY-OIL NATURALLY FRACTURED CARBONATE

RESERVOIRS: AN EXPERIMENTAL STUDY

Mohammedalmojtaba Mohammed Master’s Student, Petroleum Engineering

University of Alberta

Abstract With continuous depletion of conventional oil reservoirs around the world, increasing attention has been drawn to unconventional oil resources with an eye towards 536 billion barrels of bitumen located in carbonate formations in Alberta, Canada. An efficient technology to unlock these promising resources is yet to be discovered. The application of primary and secondary recovery processes in this Naturally Fractured Carbonate Reservoirs (NFCRs) containing heavy-oil/bitumen usually results low recovery factor and an Enhanced Oil Recovery method (EOR) is mostly needed at early stages.

Most of the oil in NFCRs is often contained in oil-wet matrices and capillary imbibition controls the rate and the ultimate oil recovery over the other mechanisms such as gravity and viscous forces. As a result, changing the characteristic of Rock /Fluid System becomes critically essential. This study investigates a suggested two-phase recovery process in which the properties of oil-wet NFCRs containing heavy-oil/bitumen are changed leading to a considerable oil recovery up to 85 % of original oil in place (OOIP). In Phase-1, different types of rocks were soaked in solvent. Aged Berea cores sandstone were used to represent weakly water-wet system while limestone cores were used as strong oil-wet surfaces. Phase-2 was applied using wettability modifiers including high pH solutions, surfactants and nanofluids, as well as Ionic liquids. One of the key benefits that encouraged testing ionic liquids was that they are environmentally friendly and they can be customized for each particular Rock/Fluid System.

After initial experiments with aged sandstone and limestone, the same process was tested on preserved Grosmont samples. The results revealed that cationic surfactants and ionic liquids can alter the wettability of heavy oil/bitumen NFCRs if pre-solvent phase is applied. The optimization of the process in term of the type of solvent, solvent soaking period, and concentration of wettability modifier was also discussed.


August 27, 2014

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REAL-TIME FEEDBACK CONTROL OF SAGD WELLS USING MODEL PREDICTIVE

CONTROL TO OPTIMIZE STEAM CHAMBER DEVELOPMENT

Shiv Shankar Vembadi Master’s Student, Petroleum Engineering

University of Alberta

Abstract Data from surface and downhole sensors and other intelligent hardware in oil fields provide opportunities for real-time production monitoring and optimization as part of integrated smart field operations. Such an opportunity in Steam Assisted Gravity Drainage (SAGD) is explored in this work. SAGD is an effective method of producing the huge bitumen deposits in Alberta. Its efficiency depends on developing a uniform steam chamber and maintaining a certain temperature difference (subcool) between the injector and the producer along the length of the well pair. Several works have reported on using reservoir simulation models to find optimum SAGD operating points by using optimization algorithms like genetic algorithms. However, since formation heterogeneity has a significant impact on SAGD, directly using optimum rates obtained from these uncertain reservoir models in the field will not yield good results. On the other hand, SAGD wells instrumented with fiber optic cables provide real-time temperature and pressure data. Based on real-time temperature and production data along with other well and surface constraint information like steam availability, real-time feedback-control of injection and production rates in SAGD well pairs can be implemented to optimize subcool and steam chamber development. Model Predictive Control (MPC), which is a multivariable constrained controller, provides a framework for such control. In this framework, the reservoir simulation models provide “set points” for the MPC controller.

To evaluate the use of MPC for real-time control of SAGD wells, a case study is done using a 3D heterogeneous reservoir model with a single pair of dual tubing horizontal wells. A set of porosity and permeability realizations are created and ranked based on Net Present Value (NPV). One of the realizations is considered as the “synthetic” (virtual) reservoir after reducing the maximum time step size and grid refinement. Also, two realizations are selected to represent two different cases of uncertain reservoir models. For each of the two reservoir models, a proprietary reservoir simulator is used to find optimum rates and subcool. Using MPC to control the well pair in synthetic reservoir leads to 9 and 11 % improvements in NPV compared to direct application of optimum rates from the reservoir models.

SEMI-ANALYTICAL APPROACH TO STREAMLINE SIMULATION

Ali Souri Laki

PhD Student, Oil and Gas Engineering Memorial University of Newfoundland

Abstract The use of streamline and stream-tube modeling to predict fluid displacement in porous media is increasing in reservoir simulation due to its simplicity and calculation efficacy. This method defines the stream-tubes by generating the streamlines using Pollock’s method where the geometry of stream-tube is calculated and kept constant during the computation. Fluid displacements simulation is done inside each one-dimensional stream-tube using the new constant pressure boundary fractional flow theory for different mobility ratios. A novel semi-analytical model combining the constant pressure boundary fractional flow theory and stream-tube simulation is conducted for gas injection process. The new method is conducted for displacement of three pseudo components and two-phase fluid in two-dimensional heterogeneous reservoirs. The results show good accuracy and fast computation. This semi-analytical method is conducted for a two-dimensional heterogeneous porous media model and the results are compared to conventional finite difference method such as IMPES. The recovery curves and flow rates are obtained for different mobility ratios, and there is a good agreement between the stream-tube method and the IMPES and also the accuracy of results is sensitive to number of stream-tube. One of the main advantages of stream-tube model that is shown by this results is that the computation speed is much faster for the stream-tube method compared to the conventional finite difference method as the number of grid blocks is increased, while the accuracy of results have a good agreement with finite difference method.


August 27, 2014

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A NOVEL APPROACH TO TACKLE MULTIPLE OBJECTIVES OPTIMIZATION USING FUZZY

LOGIC: SAGD NUMERICAL TUNING CASE STUDY

Arash Mirzabozorg PhD Student, Petroleum Engineering

University of Calgary

Abstract Population-based stochastic optimization algorithms have recently attracted the attention of history matching and optimization research groups because of the ability of these algorithms to find an ensemble of optimal solutions when compared with other optimizers. The approach used by existing algorithms during history matching and optimization workflows is to minimize or maximize a single global objective function which is an aggregated summation of all local objective functions, to find optimal solutions.

There are many situations, however, where the local objective functions conflict to each other in a way that to get an optimal solution, improving one may come at cost of worsening the other one. Numerical tuning, where the goal is to have a fast simulation run with minimum material balance error, is a case where this may be encountered, particularly for large scale reservoir models.

To tackle this problem, we applied the Multiple Objective Particle Swarm Optimizer (MO-PSO) to simultaneously reduce simulation run time and material balance error. Results showed that MO-PSO provides multiple optimal solutions in the form of Pareto front compared with the Single Objective Particle Swarm Optimizer (SO-PSO), where an aggregated global objective function is optimized, yielding solutions that would be biased by inappropriate weighting factors.

The question is how the engineering knowledge (in the form of Fuzzy IF THEN rules) can guide the population-based optimization algorithms towards a Pareto front with better optimal solutions. In this study, a Fuzzy Inference System (FIS) was coupled with Differential Evolution (DE) to numerically tune a complex real-field reservoir model with 19 tuning parameters. The results demonstrate that the application of FIS + DE can yield optimal solutions that form a better Pareto than those obtained by MO-PSO.

PRODUCTION DATA ANALYSIS OF LIQUID RICH SHALE GAS CONDENSATE RESERVOIRS

Hamid Behmanesh PhD Student, Petroleum Engineering


Abstract Unconventional resources have become a substantial source of hydrocarbon supply in North America. Among these plays, low natural gas prices is caused to significantly accelerate exploration of unconventional liquid rich plays (LRS). Efficient production from such reservoirs necessitates understanding and modelling of flow mechanisms. This is mainly due to two-phase flow occurrence in these tight formations, which complicates the production analysis in these challenging environments.

The main objective of this work is to gain a detailed understanding on the performance of tight gas condensate reservoirs during transient linear flow period under various operating conditions. A mathematical framework is set up to gain a practical insight on the impact of different parameters on the reservoir performance. In particular, the governing flow equation is linearized using two-phase pseudopressure and a newly defined pseudotime function where the liquid analogy can apply. The solution to the diffusivity equation provides a robust approach to compute the linear flow parameter, xf√k. Furthermore, as a part of the solution approach, an analytical expression for the pressure-saturation relationship is derived using the Boltzmann transformation. It is shown that the saturation and pressure are unique functions of the Boltzmann variable. This newly developed relationship is central to the evaluation of pseudovariables and is used to explain the constant behaviour of GOR during constant bottomhole production.

Our approach for production data analysis is validated against multiple compositional and black oil simulations for both synthetic and measured fluid models and relative permeability data. The new workflow presented in this paper assists in better understanding of performance prediction and production analysis of the wells in tight gas condensate systems.


August 27, 2014

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SEMI-ANALYTICAL PRESSURE TRANSIENT MODEL WITH BOUNDARY ELEMENT METHOD

Manyang Liu PhD Student

University of Regina

Abstract Background: A review of numerical reservoir simulators indicates that finite difference approximation and finite element method are the most common numerical modeling technique in petroleum engineering. On the contrary, the analytical based boundary element method (BEM) is used to a lesser extent. However, only the BEM applies a mathematical function that is related to the analytical solutions for the PDE.

Objectives: The main objective of this work is to provide a general, semi-analytical model to simulate single-phase fluid flow in homogeneous porous media with complex well configurations, such as horizontal and fractured wells. Our objectives include the validation of the semi-analytical model and discussion of its advantages and weaknesses for reservoir engineering applications.

Methodology: The method of this research is based on the Green's function formulation of the solution for the diffusion equation. Because the domain boundaries are discretized and the solution is defined in terms of the boundary values of the problem, this approach is closed related to the Source and Sink method. The main difference between our approach and the Source and Sink method is the use of free space Green's functions for bounded domains instead of the source functions in the Source and Sink approach.

Results: The semi-analytical model was developed using the BEM for realistic description of the performance of vertical (fully perforated and limited entry) wells, fracture and horizontal wells. The validation cases study shows that this approach is relatively accurate and computationally efficient. The extension of this study to heterogeneous porous media is promising.

Conclusions: The model is able to flexibly handle both no-flow and constant pressure boundary conditions, and can accurately simulate transient tests, thus it can serve as a powerful tool for the analysis of well tests for both non-stimulated and stimulated wells.

INTER-HORIZONTAL WELL CONNECTIVITY IN TIGHT RESERVOIRS

Mammad Mirzayev PhD Student, Petroleum Engineering


Abstract Drilling horizontal wells in economically marginal fields, such as heavy oil reservoir, tight oil reservoir etc, is a common practice. Estimating the inter-HW (horizontal well) connectivity is vital for the future of a field, when secondary and tertiary recovery methods are applied. Numerical simulators, such as Streamline Simulator (SS), needing a geological model, are employed to evaluate the connectivity between the wells in a reservoir model. Constructing the geological model honoring uncertainties may take months to have a satisfactory one. In this paper, we show Capacitance Model (CM) is capable of estimating the inter-HW connectivity using solely production- and injection-rate fluctuations.

We successfully tested the model with various heterogeneous cases. The CM can identify inter-HW heterogeneities and differentiate them spatially. The model accuracy is based on the history-match quality, which is the correlation between historical rates and CM-predicted rates. The CM accuracy for all cases is almost faultless (R2 ≥ 0.99). The inter-HW connectivity evaluated by the CM during unsteady state flow periods is key information to make a favorable decision at the early stage of flooding. We observed that in some cases the CM performs better than the SS while calculating production

allocation factors (AFs); ∑𝐴𝐹𝑆𝑆−𝑖𝑛𝑗 = 1 and ∑𝐴𝐹𝐶𝑀−𝑖𝑛𝑗 ≤ 1. The CM detects whether all injected fluid volume goes to

producers.


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MODELING DISPLACEMENT EFFICIENCY IMPROVEMENT DURING SOLVENT- AIDED SAGD

Mohsen Keshavarz

PhD Student, Petroleum Engineering University of Calgary

Abstract Coinjection of small amounts of hydrocarbon solvents with steam has the potential to improve the oil recovery efficiency while reducing the energy intensity of conventional SAGD (steam assisted gravity drainage). A number of studies have reported lower residual oil saturations inside the coinjection chamber compared to SAGD. There is, however, no mathematical model available to predict the extent of such displacement efficiency improvement or to compare it during the coinjection of different solvents.

This paper presents a mathematical procedure for the estimation of local displacement efficiency improvement in the coinjection process. Displacement efficiency is modeled as a function of local solvent accumulation, upon the arrival of chamber interface, and the temperature, as the region is swept by the chamber. The model is used to investigate the interaction of displacement efficiency improvement, ultimate bitumen recovery and, solvent retention inside the swept region, the last of which is of significant concern in large scale applications.

The complex interaction of mass and energy flow is simplified without loss of the fundamental mechanisms and phase behavior details. Initially, phase equilibrium equations are solved to find the thermodynamic conditions inside and at the boundary of the coinjection chamber. Then, the residual saturation of the oleic phase as well as the retained amount of solvent are estimated along the temperature profile inside the chamber by making reasonable assumptions.

Results indicate that coinjection can achieve improved displacement efficiency even without modifying the relative permeability curves or considering the possible interfacial tension (IFT) reduction as a result of solvent coinjection. Eventually, results are validated by using numerical simulations for the coinjection process. It is demonstrated that a robust understanding of phase behavior interaction with heat and solvent transport is critical to explaining the recovery mechanisms involved in solvent-aided SAGD.

A COMPREHENSIVE EVALUATION OF THE ACCURACY OF STREAMLINE SIMULATION

Nan Zhang PhD Student, Oil and Gas Engineering Memorial University of Newfoundland

Abstract The application of streamline simulation in reservoir simulation has increased significantly in recent years. Engineers use it as an efficient tool to solve complex optimization problems related to history matching and optimal well placements. This paper comprehensively discusses the accuracy of the most widely used commercial streamline method based on the work by Pollock. First, we evaluate the basic assumptions. Secondly, we estimate the errors involved in calculating the streamline location, streamline length and the time of flight. We found that the errors are significant when the grid block resolution is low. These errors are mainly caused by the basic assumption made by Pollock, this paper proposes a new basic assumption that can improve the simulation results.


August 27, 2014

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CERCHAR ABRASIVENESS TEST FOR SYNTHETIC ROCK SPECIMENS

Pushpinder Singh Rana PhD Student, Oil and Gas Engineering Memorial University of Newfoundland

Abstract Characterization of abrasive index of rocks is an important component for predicting drilling performance, in particular the rate of penetration (ROP), wear rate and bit run lengths. The traditional CERCHAR test for estimating rock abrasivity was developed for coals, which are much weaker than most rocks drilled for oil and gas exploration or production. This study was undertaken to apply the conventional CERCHAR test to a range of rocks encountered for oil and gas drilling. To study wear and performance of PDC drill bits in lab synthetic rock samples (i.e. samples of concrete) can be used. The beauty of using synthetic samples is that, factors like UCS, CCS, porosity and abrasiveness can be precisely controlled by controlling curing time, ambient temperature and water-cement ratio. To study the abrasiveness of synthetic rock specimens, CERCHAR abrasiveness test was successfully used. Tests were performed on three synthetic rock types (low, medium and high strength concrete) and two natural rock types (siltstone and granite). Synthetic rock specimens were casted using same aggregate mix and hence the only difference in abrasiveness was due to cement and aggregate bonding strength. This gives a better insight of how abrasive minerals present in a rock and its UCS value affects the abrasiveness of a rock. Also effect of confined pressure on abrasiveness of rock specimens was studied. Effect of styli hardness, length of scratch and re-finishing the styli were also tested. Rockwell Hardness test (type C) was used to measure styli hardness. Also micro hardness tests (Vicker's and Knoop hardness tests) were performed on styli tip, revealing a higher hardness at the tip of styli as compared to shank. Some modifications are proposed in the traditional test, so as it can be effectively used on synthetic rocks with accuracy and precision.

COMPARISON OF STREAMLINE SIMULATION METHODS IN THE NEAR WELL

(POLAR COORDINATES) REGION

Xiaoyan Tang

PhD Student, Oil and Gas Engineering Memorial University of Newfoundland

Abstract Streamline simulation has been applied in reservoir simulation for many years. It is used in a variety of areas such as water flooding management, flow visualization and history matching. Most streamline simulations have been applied at the full field scale (Cartesian coordinates); this research performs the streamline simulation in the near wellbore region (polar coordinates). All previous streamline applications have been performed using a constant flow rate condition. In this research, the streamline simulation is performed under the condition of constant pressure boundaries which is novel for streamline simulation. Since reservoirs can be produced under constant injection and well producing pressures respectively, the constant pressure boundaries condition is more consistent with these operating conditions.

In this research, a new semi-analytical streamline simulation method and the traditional streamline simulation method (Pollock’s method) are applied to the two-dimensional near well region. The time of flight (TOF) difference comparison for a homogeneous reservoir and the streamline path comparison for a heterogeneous reservoir are presented. The streamline pattern varies in the heterogeneous reservoir when using these two different methods. The saturation profile from Eclipse can then be used to analyze results to determine which is more realistic.


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As production peaks offshore Newfoundland, Enhanced

Oil Recovery (EOR) can further increase recovery of post

water or gas flood residual oil. Even in more simple

reservoirs of homogeneous unconsolidated sandstone,

recovery of residual oil is challenging due to the physics

of mobilising disconnected oil droplets trapped in the

smaller pores and pore throats of the rock. Complex

reservoirs with lateral or vertical segregation,

heterogeneous layers of varying pressure, permeability

and/or wettability all pose more challenging to

enhancing recovery factors.

In July 2014, a state-of-the-art Enhanced Oil Recovery

Laboratory was inaugurated at Memorial University of

Newfoundland. The laboratory will perform experimental

investigations of fluid-fluid and fluid-rock interactions

during the recovery of oil. The new lab facility aids to

experimentally and mathematically investigate and

compare the use of CO2, and other gases of interest, for

oil recovery considering offshore Newfoundland specific

conditions. In particular, the following two experiments

are being performed in this lab:

COREFLOODING: The core-flooding experiment will be

carried out using the high-pressure/high-temperature,

two phase and three-phase steady-state core-flooding

apparatus located within the Hibernia EOR laboratory.

The apparatus is capable of handling experiments with

pressures up to 10,000 psi and temperatures up to 200° C.

The critical wetted metal parts of the experimental set-

up are made of highly corrosion resistant material called

Hastelloy. This ensures the equipment is rust free and

corrosion resistant even under high temperature

environments with high chloride concentrations. The

experimental set-up consists of quizix pumps controlling

the flow of oil, gas and brine, high resolution pressure

transducers, two/three phase acoustic separators,

oscillating back pressure regulator (internally designed)

and inline viscometers. The flow system is capable of

carrying out simultaneous injection and recirculation of

fluids at reservoir conditions. A range of analytical

equipment is also available to provide fluid behaviour

data.

VISUALISATION STUDIES: The new facilities will allow for

observations at the pore scale (um to mm) and the core

scale (mm to cm) at reservoir conditions (10,000 psi and

200 oC). In particular, it will focus on the pore scale

physics observed and the change in the three phase

relative saturations while recovering post water flood

residual oil in 2-D micromodels/pore network models and

core samples.

HIBERNIA ENHANCED OIL RECOVERY LAB


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SSPE: YEAR AT A GLANCE 2013-2014

SSPE PHOTO CONTEST 2013 (SELECTED PHOTOS)

ACTIVITIES PLANNED FOR YEAR AHEAD

2014 SSPE Ping Pong Tournament

2014 SSPE Photo Contest

2015 SPE Student Paper Contest

2015 Energy Awards

2015 SPE Quiz for Engineering Students

Field trips

SPE ambassador lecture visits

Providing travel supports to student members to particpiate SPE events

Industrial information sessions/seminars

Community involvement

For sponsorship opportunities, please contact [email protected] or visit our website:

www.mun.ca/sspe

mailto:[email protected]

http://www.mun.ca/sspe


August 27, 2014

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I explore the world’s energy resources

I protect the environment

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2014 spe canadian regional student paper contest€¦ · · 2014-09-092014 spe canadian regional...

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