PetroPulse Issue 9 by AAPG SU SC

WELCOME Leave Your Comfort Zone

Sara Al-Mekawy

Editor-in-Chief

«Great things never came from comfort zones» - Ben Francia, when your life goes on a roll where you progressively become inside your comfort zone, having experienced nothing but stagnation, this would wholly transform you and take you to the lowest point of productivity and enthusiasm. Once you decide to stay there for a while, you automatically get involved with routine that kills you, so never hinder yourself from evolute or take new steps. It is normal for the majority of people to go through this during their lives, but it is abnormal to spend your whole life inside the circle of stagnation. So just get out of it instead of the tunnel vision to affect your life experiences or opportunities. Consequently, do not be afraid of change or even if things reached to the complexity and your life become in endless chaos, because this chaos permits you to always live with many alternatives for your life, goals, work etc. Student activities would be a great example of what we have mentioned in the previous paragraph, when you get in the university for the first time and feel like you are lost and do not know anything or anyone on the campus, so in your first days you are trying to adapt, make friends, and have new majors and skills. While student activities might help you integrate into the new university life, but it also keeps you away from stagnation or order stage where you live in an unchangeable routine of studying one major for many years, so do not stay still in the same place and move forward learning more skills from different people, which is very important to prepare you for life after graduation, and this was exactly what I did, and I chose the chapter of “AAPG”. Initially, I was so excited to enroll on the chapter but I was afraid of having extra responsibilities. Furthermore, I was in my first year at the university, and after months it came with a great benefit to me and a lot of students, I have even progressed to become the head of magazine committee, this opportunity has enabled me to learn life skills and experience such as: seeing solutions where others see problems, being able to connect with people, and learning how to selflessly serve others. Our magazine is titled “PetroPulse”, the magazine is concerned with the field of geology and reservoir engineering; the articles present plenty of academic information and serve students who are interested in knowing more about this industry around the world. We work accordance with a balanced plan to learn and show different experiences from different leaders and engineers inside and outside Egypt. As a final piece of advice for the newcomers is to work hard and keep yourself out of your comfort zone and for the students who have enrolled on the AAPG recently, we need your passion and determination to achieve the target goals, whether for short or long term. Nevertheless, this article can not be completed without thanking all members for their amazing commitment and effort, and issue No.9 is an example to highlight that great work.

WELCOME Never Stop Developing Yourself AAPG President Mohamed Ehab It is ordinary to have goals and to have the passion to achieve these goals, but the difficult thing is to stay determined to achieve it, to keep your passion lamp always on so that you can stay focused on developing yourself preparing for your goals, it is not easy, but it is worth it, it surely is worth the fight, the prize is your goal. And learning is an easy tool to use “The beautiful thing about learning is that nobody can take it away from you.”- B.B. King One of the most effective things that help you continue your learning journey is being in an organization supporting this principle and only AAPG SU SC is the one that helped develop myself and taught me every possible skill, even those that I lacked, to the level of mastering them. These days most of the students are focused on being good technically and they neglect the soft skills, while here in AAPG we don’t only help the students improve their technical knowledge but also, we develop their soft skills and their mentality. We are helping the members to break the chains that restrict their abilities and stop them from being creative. Out of all this came our vision, to create visionary professionals who can face the challenges and always be able to achieve what they are looking for. Being a part of AAPG for 4 years, making the best of every possible chance to develop myself, led me to a conclusion that life is based on the desire to achieve. So, it will give you a chance if you have this desire to do and achieve what you want. But never forget to pass your knowledge to the others so that the development wheel never stops, and we applied this to our slogan Aim, Achieve, Prove Guidance. I despise the fact that so few people get to say, “I am satisfied now”. if anyone of our friends says that they are satisfied all of us would envy him for being lucky enough to be satisfied. To me this is madness, everybody should wake up every day and say that they have more to learn they need more knowledge. Learning is your path for a brighter career “If you think education is expensive, try estimating the cost of ignorance.” Howard Gardner, you should also make sure to apply what you learned practically side after this journey of learning as Education without application is just entertainment. «Man’s mind, once stretched by a new idea, never regains its original dimensions.» Oliver Wendell Holmes. this is an example that describes the impact of how a small piece of information can make a huge difference in your life because learning is the most profitable investment. Recently we can measure the education level according to the ability to learn especially in the recent pandemic of corona virus which make it obvious that people who are well learned and learn how to learn themselves are the only ones who can adapt to any sudden changes and come with the best solutions in no time to rule their fields. Life is rules and the first one is to learn; we were children, and we learned to speak, eat, move, we grow up and learn reading and writing. One more step then we learn subjects and so on for all our lives we should spend it learning. Always walk through life as if you have something new to learn and you will as learning is a treasure that will follow its owner everywhere. And be sure that the moment you stop learning is the moment you die, even if you’re still breathing.

Tell us about yourself and your journey to reach such a position. I went to school in Oklahoma State University where I studied biochemistry and molecular biology with minor studies in Business and Marketing. I have been with Halliburton for 20 years and have had the opportunity to work in many different regions around the world. I started in the U.S. in 2001 working in the different shale basins – which was at the height of the unconventional market boom. There were new discoveries such as the Marcellus Shale and the different shale basins in North Texas, Barnett and in the West Texas Permian. I spent a lot of my time travelling around those areas before moving to Saudi Arabia in 2014. During my time in Saudi, I ran the business development and in 2016 moved to Dubai as the Vice President for Business Development for the Middle East, North Africa and Asia Pacific Region. About 3 years ago, I started my current role as vice president for Egypt and Libya living out of Cairo. What is your role as a vice president? My role is to ensure Halliburton collaborates and engineers solutions to help our customers and the Ministry of Oil and Gas maximize their asset value within Egypt and Libya. One of our top priorities is on HSE and we continually push ourselves to align on the safest operations both with our own standards as well as with customers. We also aim to engineer solutions that deliver the lowest cost and to maximize production. From a technology standpoint, we focus on where to drill, how to drill, where to frack, how to frack so we can best understand what we can do to maximize the subsurface and deliver the most production.

What is the role of Halliburton in the oil and gas industry in Egypt? We are an international service company and focus our investments around developing new technologies that optimize production and help customers achieve the lowest cost per BOE. Halliburton is continually focusing on digital transformation which enables our customers to retrieve, analyze, and optimize their operations based on the data collected at the well site. As our focus is on HSE, we are committed to being a good steward of the environment and being a partner with our customers to deliver safe and efficient operations. We are a firm believer that if you do things safely, you also do them correctly and whenever you do things correctly it typically results in success and safety for our operations, customers, and employees. In your opinion, what are the hinders that Halliburton faces to achieve its goal and apply new technologies here in Egypt? I see more opportunities than obstacles when it comes to HSE and financial performance for the country. For example, we have seen big improvements from the ministry and from His Excellency Tarek El-Molla around more HSE focus in the past few years which allow us to jointly have a focus on safe alignment on the well site. We also see the Ministry and EGPC removing obstacles when applying new technology that results in an immediate impact to production increases. When you implement technology, a main opportunity is financial performance and there are two key drivers of this – having the right work environment and workload to keep our assets and people busy. As this industry is cyclical, the oil price and other factors have reduced the overall market

and activity in Egypt, but we see a rebound coming. A strong indication of this is the addition of Exxon and Chevron coming into the new exploration market in 2022. It is important to also share an interesting challenge in Egypt which is around the reservoir. Health, safety, environment, and service quality are a core values for Halliburton. What are the procedures that Halliburton do to raise the awareness of sector workers about HSE especially in the period of covid-19? Key to increasing awareness on Covid and overall safety protocols is our collaboration with local operators and other service companies. I lead the HSE committee for Egypt oil and gas where we work with the local industry to lay out clear covid and overall safety response plans. I often visit local fields and these site visits are important because it shows our employees that our management team cares about what happens in the field and we want to understand the hazards so we can work to make the environment safer. We have joint safety stand downs with local operators and in doing so helps to share lessons learned around what we can all do to operate more safely. What are the upcoming plans for Halliburton to invest more in Egypt? We invest with our customers by delivering the right technologies, equipment, and the right skillsets to increase production. We also invest in our people, one area that helps put Halliburton above our competition is our strong training program – both for technical training and the development of softer skills like communication, collaboration, problem solving and adaptivity. Being a partner in the Modernization program we saw many benefits from our training of

those that participated in the modernization program of the ministry. And finally, we heavily invested in our in-county social commitments. For example, we work with our customers to do donations to local hospitals key medical supplies, volunteer at children’s hospitals with time and toy donations and to local schools where we have transformed dangerous areas with glass and trash to safe playgrounds for the students in a local Katayama school. To me, the right investment means that we drive individual growth as well as industry growth. What is Halliburton looking for when hiring fresh graduates? We look at several areas when hiring recent graduates. First and foremost is integrity – it is the first thing we look at for any potential employee. Halliburton is known in Egypt and globally for ethics and doing things the right way is essential. We look for people who can work as a team – whether that is as a leader or as part of the core team. We focus our hiring on people who have a passion to execute and deliver results both for Halliburton and our customers. We find it vital that having employees who accept new challenges is important and having employees who want to progress throughout their career and constantly improve on their skills. Finally, just as integrity is important, we want people who keep a close eye on safety. Safety is top of the mind at Halliburton, and we want people who focus on it at all times during their day. So, the technical knowledge is not enough for an applicant to be accepted in Halliburton? Correct – technical skills are important but equally so are characteristics that fit within our organization’s culture like integrity, a drive to execute for success and safety minded.

Coming to the end of our interview, what is your impression about AAPG Suez?

I am super impressed with your focus to connect with different people and the community, especially companies like Halliburton. I have meet several from AAPG Suez and the amount of talent and excitement for our industry is an exciting observation. I want to thank the Egypt chapter and the young talent is critical for our long-term success and we are excited to have young and bright talent such as we have in Egypt.

Could you tell us about yourself and your career to reach this position? My career and myself have started in a very young age through up the middle east, I grew up in Saudi Arabia, my parents worked for a lot of companies for many years, so they moved me to some different places and schools. Eventually, I attended my university in Louisiana that is where I met my wife, and from there I graduated with civil engineering degree and then began my career in albert energy area so took my first job in a company in Lafayette-Louisiana, spent three years in and around the Gulf Coast. Then, I spent years working in Muscat-Oman and came back to the US. After another 5 years, I have been internationally resident. So, many countries throughout Asia and many different rules, all of which have allowed me to build my own knowledge space learn from different people around the world, which also put me into the role that I am in today that is the vice president of completion tools which is one of the 14 product service lines in Halliburton organization. Tell us about your responsibilities as a vice president. First of all, I am responsible for providing a safe and inclusive workplace for my entire team like my peers and colleagues around the world, we work hard to provide necessary tools in a work environment that encourages active participation and programs that promote safety, a place that we all want to go work to and perfectly know that we will come back home safely every day, that is probably the most important responsibility I have as a leader in the organization. From business prospective, one of my responsibilities is shaping the vision for the business I run and then collaborating with my teams and others to create a strategy that aligned to that vision and ultimately empower my leaders around the world to execute this

strategy. There are kind of three critical elements on the business side that I find important to insure that we make it successful, we are a service company, so being available to the global market is so important and Halliburton has spent a lot of time focusing on collaboration and actively listening to our customers to work on solutions together. What do you think of the challenges that the industry faces globally? The situation demands better collaboration among all industries, service companies, and operators to address the current challenges as collaboration is core to our value proposition. We are being proactive in preparing for what is coming and there is inspiring work underway to reduce emissions, improve energy efficiency and advance clean energy development. Is it the time for renewable energy? will we see Halliburton invest in renewable energy soon? We recognize the energy landscape is evolving and alternative energy sources are growing. One of the ways we are acting in the energy transition is though Halliburton Labs which is launched in July 2020, located at Halliburton’s Houston headquarters, gives early-stage technology companies in the clean energy space access to our world-class facilities, technical and scientific expertise, and business network, helps us learn and grow as an accelerator of clean energy technologies. Halliburton Labs is a long-term investment in cleaner, affordable energy. We know that alternative energy resources have an important role in the future. But, they have a role along with, not separate from, oil and gas. In addition, oil and gas still help produce basic materials for things we use and need every day, such as: Medicines and life-savingmedical devices, computer components, and raw materials for alternative energy sources.

As you are Halliburton Vice President of Completion Tools, how do you see the future of completions? The future of completions will introduce how we will support our customers and shape the market through the introduction of purposed and innovative technologies, while also providing breakthrough capabilities for future challenges. Digitalization is the future of our future, while also being the reality of today, we have embraced this focus to create the eCompletions ecosystem which fits within the Halliburton 4.0 digital journey. eCompletions is a transformative end to end ecosystem that will advance completions from solution creation through autonomous capabilities that will exponentially change the way we assist our customers in managing their reservoirs. In order to realize the true value of digitalization in the industry, we will continue to innovate and advance solutions with breakthroughs in material science. I remain confident that our focus on the future of completions will create the solutions of tomorrow. What about the coming steps of Halliburton for oil and gas market globally? Our immediate and biggest contribution to the energy transition is to continue helping our customers satisfy the world’s need for affordable and reliable energy. We see the demand for oil and gas growing and believe it will remain steady long into the future. Halliburton Labs is our long-term investment in cleaner, affordable energy. Our value proposition is that we collaborate and engineer solutions to maximize the asset value for our customers. We are doing this in different ways through our digital transformation and the implementation of new technologies. We are focused on Halliburton 4.0 – our digital approach that permeates everything we do. It unlocks the potential to structurally lower costs, shorten time to first

oil, increase optionality in exploration and production, and enhance performance across the entire value chain. When we come to training, how does Halliburton provide students and young professionals with training programs? We attract and retain the best talent by investing in our employees and empowering them to develop themselves and their careers. Halliburton has over 20 training facilities around the world to deliver technical, operational and leadership training for all employees. We offer numerous structured development programs, including fast-track career development programs. We have a comprehensive online learning system that provides a streamlined process for accessing and documenting career development activities, including role-based competencies, competency assessments, technical training, and online courses. We invest in our employees through leadership and competency development, competitive compensation plans, health benefits, work-life programs, and reward and incentive plans. Do you think that it is important to be a part of a student activity? I think so, the reason is that you get the ability to learn from one to another, knowing the proper perspective is incredibly important, respecting other opinions even if you do not agree with them, and that is why communities are so important. You should be aware, remain inquisitive and determine your direction, you will need to remain flexible, understand that life’s challenges remain ahead but that the right balance of focus, determination and perseverance have a way of getting over all hurdles. With that said, find balance and make time for those who are special to you.

What is your impression about us, AAPG Suez? I think what you do is great, you should continue doing it and encourage younger people to come to your place when you move on and you should always look back and help them when they need that.

Let us start with your early life and your career. I graduated from the Faculty of Commerce, Ain Shams University. After that, I completed my study as a certified public accountant in the state of Colorado and throughout that period, I was working in Price Waterhouse. There were lots of development programs that I went through, and I gained the same development on different developing programs with other employers in GE and even in Baker Hughes. I worked also with BG Group, Shell, GE and currently Baker Hughes, I worked in locations in Egypt, Gulf and United States. What is your role as a director and general manager at Baker Hughes? I lead the business agenda for Baker Hughes, and I make sure that our strategy is on the right path and all the businesses are on the right execution plan to make this strategy happen. We have several businesses in Baker Hughes, as you understand, Baker Hughes is an energy technology company, it develops and deploys the most advanced technologies to serve energy and industrial companies looking for more reliable and clean solutions. We have 4 product companies, or operating segments, are organized based on the nature of our markets and costumers and consists of similar products and services. You have worked for companies like PwC, Shell, GE, and Baker Hughes. Could you tell us about the experience you have gained as a leader? I think you get experience by working with leaders, working with different leaders is a good opportunity, and you as a member of any organization, you might be lucky, you might not. But for me, all the leaders I worked with were very supportive, I have learnt a lot from them, especially, the way they manage people because managing people is not an easy thing if you put your brain into it, it is the most important thing

when you are working in an organization, how to manage people, how to create the synergies between people, how to get the team to work together, how to direct them to the objectives and strategy of the organization. So, I take a bit of this and a bit of that till I come up with my own leadership style. What is the role of Baker Hughes in the oil and gas industry? We are an energy technology company, and our aim is to provide a clean and more efficient energy to the people and the planet, and this is a global direction, we have this direction in every country. We believe that we have a role to play within the universe and the planet that we live in. The end user is the people, so we have to make sure that commodities are clean. We invest a lot in our R&D (Research and Development) and our technology, and have a separate budget for that as we believe that our technology will change the entire energy industry. We have invested in artificial intelligence, we invest in low carbon solutions, and we have already committed, maybe before all the major players, to be net zero carbon company by 2050, we have been working on that for the past few years. What do you think of the impact of AI on the industry globally? I think AI is essential, it is now deployed in many things, and the demand on it is increasing. It is also essential for the energy industry, we saw that Shell believed in it few years ago, they made loads of effort in doing that; they just made this statement lately in the annual meeting. So, we need AI in our life in general and in the energy industry for lots of reasons and lots of solutions for deployed and predictive maintenance, production optimization, and reliability solutions. Also, I think it will not replace humans, it supports the human decision making.

In your opinion, what are the difficulties that Egypt faces in the oil and gas industry? I think what faces Egypt is what faces the entire world. We have now global challenges with the gas and oil prices, what happened last year and the global demand. Energy transition and climate changes are hot topics, there is a long-term initiative and commitment for all countries, Egypt itself is a part of the Paris Climate Agreement. And we already, as a country, have nationally determined commitment to become net %50 lower carbon by 2030 and net zero by 2050. The environmental challenge is a long-term process to manage the flare emissions as you have seen the current initiative for the compressed natural gas and transforming some of the vehicles to have a compressed natural gas fuel instead of the real fuel. How do you see the future of oil and gas industry in Egypt? Egypt is moving towards the vision that was said a few years ago, which is becoming the Mediterranean’s gas hub. I think globally oil and gas will always be there but with a different energy mix, and when we say that there will be energy transition, we are not saying there will not be oil and gas and the world will be only dependent on renewables, this will not happen; we will still have oil and gas for long time, it will just be an energy mix. Egypt has been working well on developing the reservoirs that we have here, there is much work that was done even on the downstream, petrochemicals and the refineries, and this business is putting Egypt in the right direction, obviously, midstream and downstream. Egypt has a strong position as a gas hub because we have two energy plants; sea gas and Egyptian energy, and they are both our customers as Baker Hughes provides both energy plants with products and services from our turbomachinery business and our digital solution business.

In your opinion, is the technical knowledge only enough for graduates to depend on? No, regardless of what your profession is, whether you are an engineer, an accountant or anything else, you need to develop some skills, get some exposure, have the intention to learn, develop and work on yourself and learn from others. These are all exposures and learning opportunities that will form who you are, and you need to be always aware; awareness is so important. If you are only aware of what is happening with you, I do not think this is enough; you need to be aware of why we are doing this, what is the purpose of the company you are working in, what is happening in the outer world, what is the strategy of the entire industry. You need to have your own news feed, your own interest and it does not have to be limited to the area. Do you think that student activities play a good role for students? Definitely, as part of the exposure, the activities you do in the university are beneficial to the community; they are not limited to the university. You get exposed to others; they teach you how to manage a certain project, they give you a bunch of skills, you learn how to manage a budget, how to prioritize things because you know that the budget that you have will not cover everything, and you get the experience of working with a team towards a single objective or several objectives. So, any extracurricular activities in college will add to you, and I think that it is an indication that you want to do something; because we have students that only study and other students that want to do more, add and be beneficial to his colleagues. I think this makes students committed, gives them an exposure and adds to their skill set.

What is your impression about us?

You are so smart and committed, I feel lots of enthusiasm and effort. You are the next generation, and you are digitally enabled; you got many things that we did not have when we were your age.

TUTORIAL Borehole Imaging Techniques Senior Geologist at Schlumberger

Mohamed Ghanim

Introduction:

The term «well imaging» refers to the recording and data processing techniques used to produce centimeter-scale images of the well wall and the rocks that comprise it and this is done in the wells before encapsulation. Well imaging is one of the fastest advances in wired well recordings where the applications range from detailed description of the drilled and petroleum-bearing layers in terms of rock characteristics and thickness, analysis of small-sized sedimentary features, evaluation of net pay in thin-layer formations, slope and direction of layers, faults and cracks and their types and cross bedding in sandy layers that helps in determining the directions of channel streams during sedimentation and determining the sedimentation environments and basic geological structures formed during sedimentation and the secondary geological structures formed after sedimentation during subsequent geological processes. Types of well imaging: • Optical imaging • Acoustic imaging • Electrical imaging • Methods based on the integration of acoustic and electrical imaging technologies Optical imaging: Well cameras were the first devices that were used to photograph a well, but today they present a true high-resolution color image of the well bore. The main disadvantage is that they require transparent liquid in wells filled with liquid. Unless a clear liquid is injected in front of the lens, the method fails; this requirement limited the application of downhole cameras. Acoustic imaging: Acoustic well imaging devices were known as «wellbeing television viewing devices», they are tools that provide %100 coverage of the well wall. A TV well monitor works by using pulsed sound energy so that it can visualize the well wall in the presence of opaque drilling mud; short bursts of sound energy are emitted by a rotating transducer in pulse-echo mode, the sound pulses travel through the drilling mud and undergo partial reflection at the well wall when the transducer receives the reflected pulses; the amplitude of the reflected pulses forms the basis of the sound image of the well wall.

A well TV monitor provides a -360degree image of the wells, it can operate in all downhole environments other than boreholes filled with gas where the transmission time of the acoustic pulse depends on the distance between the transducer and the well wall as well as the speed of the mud. Modern observation allows for an independent way to measure mud velocity, hence a well bore TV monitor also acts as an audio record of how wide the well bore is. For best results, the tool should be centered, although correction algorithms have been developed for decentralized surveys. An example of a modern photographic tool is Ultrasonic Borehole Imager (UBI ™) from Schlumberger, hence a concentric converter was installed to improve accuracy and a center well tool was added. The tool includes a rotating transducer inside a sub-assembly, the size of the sub-assembly is determined on the basis of the diameter of the borehole to be recorded; the direction of rotation of the sub-assembly controls the direction of the transducer. Standard measurement position with the transducer facing the wall of the well (Figure 1) where fluid property placement with transducer facing a target inside the instrument, applications include: • Identify cracks • Well stability analysis • Identify breakouts

TUTORIAL

Fig. 1 – Principle of the Ultrasonic Borehole Imager (UBI™). The UBI measures reflection amplitude and radial distance using a direct measurement of mud velocity.

Electrical imaging: Micro-impedance imaging devices were developed as advances in the magnitude and directional pitching technology of layers which have often replaced them. Traditionally, they required conductive well fluid, but this requirement will be seen later to have been avoided by oil-based mud imaging tools. The measurement principle for micro-resistivity imaging devices is straightforward as the pads and flaps contain an array of DC-button electrodes (Fig. 2).

The applied voltage causes an alternating current to flow from each electrode into the formation and is then received upon a return electrode at the top of the instrument, the microelectrodes respond to the current density, which is related to the resistance of the local formation. Therefore, the tool has a highly accurate ability to measure differences from button to button. The tool does not provide an absolute measurement of the resistance of the formation, but rather provides a record of the changes in resistance with the ability to calibrate the measurements using the resistance measuring tool in case quantitative data is desired. The accuracy of electric miniature photographic tools is controlled by the size of the buttons, usually a fraction of an inch. In theory, the features of geological formations will be recognized in the size of the buttons, and if it is smaller, it may still be detected, data are presented as the outputs of a vector and contiguous pad as the cylindrical surface of the well wall is flattened. Figure 3 shows a typical data presentation and identifies some key features.

Fig. 3 – Recognition of sedimentary and structural features in microresistivity images. These Formation MicroImager (FMI™) images have been used to generate the dip information in Track 2. The combination of FMI images and dip data clearly differentiates the eolian and interdune sands in this -8.5in. [216 mm] borehole.

Electro-nanoscale instruments have proven their superiority over ultrasound projectors in determining sedimentary properties, stratification tendencies, cross bedding in sandy rocks, and structural features such as natural fractures in sedimentary rocks; it is particularly useful for defining sandy layer thicknesses in both riverine and thin layer sedimentary environments. Conventional microscopy devices require conductive mud to run in. However, drilling with oil-based mud or synthetic fluids increased due to improved drilling efficiency and increased well stability in relation to water-based mud. Instead of having to specifically alter the mud to scan fine-resistance imaging, two other approaches have been taken: The first is the development of new synthetic muds that retain all the stability properties of conventional synthetic clays, but are sufficiently conductive to allow accurate resistance imaging measurements. The second is the development of an electrophoresis device that operates in oil mud, this problem was addressed through so-called oil-based mud scales. These are traditional submersible meters with four arms in which the four electrodes are replaced by fine inductive sensors. Recently, anti-contact methods have been applied in oil-based slurries or synthetic slurries. Acoustic and electrical imaging integration: To some extent, the ultrasound and electrical measurements are complementary to each other because the ultrasound measurements are more influenced by the properties of the rocks, while the electrical measurements respond mainly to the properties of the fluids. Another difference is that the ultrasound image covers 360 degrees, while the electrode image is somewhat less than %80 in wells with a diameter of 8 inches.

EDUCATIONAL Significance of Vertical Permeability Staff Reservoir Engineer at Petronas Carigal

Eghbal Motaei

Introduction All reservoir parameters are spatially dependent property which is called anisotropy. Permeability is one of the key parameters in the reservoir that requires detailed analysis and its nature dependency of the direction which varies in bed plan and perpendicular to the bedding. This permeability anisotropy could be the results of the periodic layering, ordering grains in sandstones or could be fractures or diagenetic process driven in carbonated reservoirs. Measuring vertical permeability is the effort required to address the vertical anisotropy of the rock to fully reflect the heterogeneity in the field studies. The main impact is on the following field studies: • Gas Injection (Figure1-) or Carbon Capture studies • Horizontal well • Eater and gas injection in oil rim reservoirs • Possible water conning or gas breakthrough from gas cap When understanding a vertical permeability, it is critical to track the well and reservoir performance and make simulation models with accuracy to enable them with history matching easier and make the more predictable. In other words, the more accurate data, the less uncertainty parameters in the simulation models, and the more reliable dynamic model can be constructed. Figure 1 shows the effect of vertical permeability variation on gas injection performance. Rarely, it can have the homogeneous rock (top), most common in clastic (mid) and isolated vertical barriers (bottom).

How to Measure Vertical Permeability: Unfortunately, petrophysical log driven approach permeability only estimates the permeability as one scalar value while permeability is a tensor. Therefore, it is required to measure the vertical permeability using two main approaches: direct access to rock at lab and in-situ measurements. Direct rock access such as: • Full core • Side wall core analysis • Whole core analysis • Outcrop analysis In-situ measurement such as: • Wireline Formation Tester analysis • Pressure Transient Analysis known as well test In the first category, the core plugs are analyzed in the lab and vertical permeability is measured through routine core analysis. In the second category, the reservoir is drained through a specific rate and flowing pressure and shut-in pressure are analyzed to estimate the in-situ permeability. The measurement in this category is more representative compared to the lab measurements as they are subjected to change in stress and possible breakouts, loss of porosity and

EDUCATIONAL change in net confining stress, and the main parameter is scale of the rock in lab samples which is very smaller and representing local permeability only [2[ ,]1]. Spherical Flow: Spherical flow happens when the flow from reservoir happens in three dimensions due to limited available entry from reservoir to the wellbore as depicted in Figure 2. The limited entry allows the upper and lower section of restricted interval flow perpendicular to the open entry layer in which the flow is dominated for a period at the beginning of the test by vertical permeability.

Figure 2: Limited entry imposes spherical flow and allows the measurement of vertical flow permeability.

Spherical flow regime happens after wellbore storage in well test or cylinder storage in the wireline formation tester and after it, the radial flow dominates the derivative signature. A schematic of full fluid flow is presented in Figure 3. As shown, the spherical flow happens with -1/2 slope signature on pressure derivative (Red Curve in Figure 3).

To measure vertical permeability on any pressure transient test, it is required to capture the spherical flow on the pressure derivative in the pressure build up test, but it needs to capture the radial or horizontal permeability. The spherical flow has a parameter of all three dimensions permeability at which two dimensions (two-dimensional permeabilities: KX and KY) vertical permeability exist. The spherical permeability is explained in equation (1):

By assuming no anisotropy in redial plane (same Permeability in X and Y directions) and replacing them with horizontal permeability from radial flow (K_h), it is possible to estimate the vertical permeability from spherical flow as demonstrated in equation (2) and Figure4-:

As shown, the horizontal permeability could be measured from radial flow regimen and the spherical permeability is also estimated form spherical flow regime. Then the vertical permeability can be extracted form equation (2).

Figure 4: Workflow of vertical permeability estimation

Recommendation

Figure3-: Full sequence of pressure response and its derivative [Top] flagged for different flow patterns in the limited entry reservoir flow [bottom]. (1) refers to early radial flow (2) refers to the spherical flow with 1-2 slope, and (3) refers to late radial flow for deeper flow inside in the reservoir. Radial flows are recognized by flat line in the derivative [Green Flat lines] and Spherical flow is recognized by -1/2 slope line on pressure derivative [Blue Line].

Understanding the benefit of the vertical permeability for each business case should be quantified using Value of Information (VOI) concept [1[ ,]2] and then start to find the cheapest way to collect the data which is required for the given situation. For instance, if you are drilling a deep water well and rig daily cost is huge, you may collect your data using wireline formation tester data instead of well test for vertical permeability only.

In AAPG, we celebrate the beginning of the new season in an opening party and it is a chance for anyone to know more about us and decide to be a part of our chapter.

We hold interviews with different leaders in many fields to transmit their experience to students, and one of those leaders was Mr. Ahmed Abouzaid, the founder of Droos Online on YouTube.

Our vision is to create well-developed members having the ability to improve themselves without limits, and these programs are the best way to deliver the best value for them.

It was one of the most important days in our chapter as we met new members, all of us would be there, and it was the first general meeting.

It was an online event; it talked about how to choose the right career for yourself and this event was in cooperation with SPE Al-Azhar as a partner. It consists of 2 camps and each camp consists of 3 sessions.

It was an online event talking about freelancing, and how to start up in freelance. It consisted of three sessions.

An online event talks about English language and how to improve it. It consisted of 2 sessions.

A program that promotes Microsoft Skills of its participants to reach a high level of sustainable excellence and professionalism.

Oil and Gas Industry Conference Oil and Gas Industry Conference (OGIC) is our mega technical event. In the fifth year in a row, we provided more fruitful values and opportunities for all students who are interested in the Oil and Gas Industry.

PetroPave is a technical program in which technical sessions about different topics in the Oil and Gas Industry are provided to the whole chapter members. Through 2 batches, PetroPave was presented over 7 sessions by AAPG Suez Acadmeic Officer.

We make sure to provide technical value to all students, and this event talked about Production Logging Tools (PLT), and it consisted of five sessions.

It was an online event that talked about Directional Drilling and included: Applications, Deflection Tools, Techniques and Directional Surveying at the (Directional Drilling Course). It consisted of 4 sessions.

Software Programs play a vital role in the Oil and Gas Industry, and in this online event, we provided 5 sessions about the most important and efficient software programs in oil and gas industry (Prosper, Techlog, and MBAL).

It was an online event that consisted of 3 sessions. It was talking about geoscience applications and introduced new challenges for machine learning due to several geoscience properties faced in every problem.

An online event that talked about (Process Control and Chemical Engineering Course), and It consisted of 3 sessions.

Through 3 online sessions, PetroUp 6 presented some of the new technologies in the Oil and Gas Industry.

REVIEW Water Injection Management Using Streamline Simulation and Intelligent Wells Reservoir Engineer at Schlumberger Introduction Reservoir uncertainty such as heterogeneities leads to oil displacement issues, trapping of oil, or early water breakthrough due to permeability contrasts, or in homogenous well sections leading to coning or cresting. This leads to reduced oil production and/or large handling costs. Effective water injection management can improve the sweep efficiency of a water flood project, and hence increase recovery. Solutions include well placement optimisation, infill drilling, rate allocation, or intelligent well technology. What is streamline simulation? Muskat and Wyckoff (1934) estimated flood conductivity for well patterns using resultant pressure terms, this introduced the streamline concept to reservoir engineering. Streamline simulators use highly efficient approach where a finite difference solution is computed for pressure on the grids to find the velocity fields. Streamlines are generated tangent to velocity fields, representing a source to sink relationship such as reservoir or injector to producer. What about intelligent wells? While advancements in reservoir simulation and optimisation are practiced, practical solutions are also deployed on a well completion level for vertical and horizontal wells. Leading to intelligent well completions, these solutions control rate on a well level through real-time downhole monitoring by rate and pressure sensors incorporated with valves or devices. Some of which are inflow control devices (ICD)s where the orifice or nozzle size is static and predetermined prior to installation. More sophisticated devices are autonomous flow control valves (AFCV) or (FCV)s which have variable aperture size that can react to changesin viscosity autonomously or controlled from

Omer Khoshnaw the surface using hydraulic or electric lines resulting in no well workover time. This device can increase production after gas or water breakthrough as compared with conventional ICDs. These valves are particularly useful in controlling cresting or coning due to high homogeneity or variation in influx due to heterogeneity, or pressure distribution in horizontal wells due to frictional losses. The ‘heel to toe’ effect is introduced, where the drawdown is restricted towards the end of the horizontal section, reducing production rates to an almost equal pressure loss across the tubing as the reservoir (figure 1,2). These devices solve this issue by redistributing flow inside the wellbore, creating an optimal sandface pressure profile.

Figure 1—Illustration of water coning and gas cresting due to imbalance flux along the horizontal section due to heel to toe effect, and compensated by installation of passive completion.

Figure 2—Schematic of pressure loss across a horizontal well section (Brekke and Lien 1994)

REVIEW Water Injection Management Strategies: Determining the optimal rate control or the best valve aperture has been studied through genetic algorithm, or gradient based optimisation, but often economical or operational problems are faced, so the need for fast and reliable solutions is important. Two main optimisation approaches are presented streamlinebased optimisation and individual well optimisation with a focus on downhole completion. Streamline-based Optimisation: Streamline simulation provides key performance indicators such as pore volumes, sweep and drainage efficiencies, and corresponding off-set producers to injector connections. The Pattern Flood Management (PFM) tool embedded in a commercial streamline simulator uses standard reservoir engineering fundamentals (mass conservation, Darcy’s law, saturation, and pressure equations) to increase the volumetric efficiency by modifying water injection rates, on a well or zone level. This reduces unwanted production issues such as early water breakthrough, high water production or injection, as well as maintaining oil production before decline. Streamline optimization is rapid as it demands less computational time. Waterflood design and its impact on uncertainty can be studied successfully, especially in the presence of aquifers. The rate allocation for key strategies are based on a weighing scheme by Thiele and Batycky (2006): Balancing Potential Oil Recovery (RECOV): this method sweeps mobile oil saturated areas by calculating the remaining oil volume in the streamlines from the injectors, and ranks the injectors to allocate higher injection rates to well pairs based on an injection scheme. This balances the flood pattern and maximises the recovery before water breakthrough. Reducing Water Recycling (INJEFF): this method monitors the oil cut at the offset producers and allocates higher injection rates to producer pairs with high oil cut and vice-versa, based on recommended injection allocations. This minimizes injected water recycling and maximises oil recovery.

Smart Well Optimisation: On a completion level control, FCVs are used in a next generation reservoir simulator, the approach applies to variable orifice sizes of an ICD such as AFCV. The control of the downhole devices can be reactive or proactive and numerous optimisation methods have been investigated previously (Addiego-Guevara et al. 2008; Dilib et al. 2012; Prakasa et al. 2015; Lee et al. 2017). Latest downhole device optimization methods are presented by Ahmed Elfeel et al. (,2019 ,2018 2021). Proactive Injection Valve Control: designed for flux equalisation by injecting water at equal constant rates at the zones, the aim is to balance the water shock front to create a uniform sweep and potentially delay breakthrough in producer wells. Multiple proactive methods are presented by Ahmed Elfeel et al. (2021). Reactive Producer Valve Control: a dynamic producer valve control is implemented based on a correlation; the valve can react to increasing water cut (WC). The relationship is triggered when %5 WC is observed and the valve is shut at an economical limit of %90 WC, the other on/off reactive control is binary and shuts off the zone at %90.

Conclusion The selection for the most feasible waterflood optimisation strategy is highly field specific and dependent on operator requirements. Added value of flow control valves are evident in water injection management; streamline technology in combination with a reactive producer smart well can be described as the ideal time efficient pattern flood management method. The reactive producer optimises water production dynamically on a zone level and is independent of regional well response or global field performance. In contrast, stream li n e - b a s e d o pt i m i s a t i o n , e n ha n ces water injection management by monitoring field connectivity and producer behaviour by proactively managing injector rates.

Figure 3—Schematic illustrating water injection allocation for the PFM strategies using streamline bundles INJEFF.

EVALUATION Lessons Learnt from the first CO2EOR Project in the Middle-East and Future Plans Senior Reservoir Engineer (Simulation) at ADNOC

Mohamed Yousef

Abstract: Experiences gained from CO2 flooding to improve oil recovery worldwide indicates that considerable amount of remaining oil can be recovered with miscible CO2 injection under appropriate conditions. Though it›s performance in the heterogeneous Middle Eastern carbonate reservoirs has not been well demonstrated yet; it is most likely going to be the future hydrocarbons recovery process in Abu Dhabi after the successful implementation of the first miscible CO2-EOR pilot in 2009 by ADNOC Onshore. In 2016, ADNOC Onshore embarked on field scale implementation of CO2 injection, making it an integral to of the company’s overall strategy to utilize CO2 as one alternative option to the expensive HC gas, address related key technical and business aspects. Introduction: The combined total oil production by primary and secondary recovery methods is generally known to be less than %40 of the original oil in place. Therefore, the necessity of application of Enhanced Oil Recovery methods (EOR or tertiary recovery) arises as the potential target from EOR is greater than the reserves that can be produced by other conventional methods. Miscible gas flooding is among the viable and worldwide-adopted EOR mechanisms with reported success in terms of understanding its macroscopic, microscopic displacement mechanisms, field implementation, and additional oil recovery. Miscible CO2 flooding is becoming a widely used EOR mechanism and has been reporting to improve the oil recovery in many oil reservoirs. The leading mechanisms that favor CO-2flooding are: • Oil swelling. CO2 dissolution in oil causes the oil to swell and expand out of dead-end pores. • Reduction of oil viscosity. Viscosity of crude oil decreases as it becomes saturated with CO2 at increasing pressures, and which assists in facilitating oil flow to the wellbore. • Improvement of internal reservoir pressure. • Improvement of oil mobility and capillary number; at high pressures, viscosity of CO2 is greater than that of other gases such as Methane (CH4), Nitrogen (N2) resulting in better mobility control and improved sweep efficiency.

• CO2 density has a density close to that of a liquid at high pressures and is greater than that of either CH4 or N2 gases, which makes CO2 less prone to gravity segregation compared with other gases. • Establishing dynamic miscibility by the ability of the dense-phase CO2 to extract hydrocarbon components from oil, along with the ability of CO2 to dissolve into oil. Miscibility between CO2 and crude oil is achieved through a multiple-contact miscibility process which starts with dense-phase CO2 and hydrocarbon liquid. It requires many contacts, in which components of the oil CO2 transfer back and forth until the oil-enriched CO2 cannot be distinguished from the CO-2enriched oil in terms of fluid properties. The CO2 first condenses into the oil, making it lighter and often driving methane out ahead of the oil bank. The lighter components of the oil then vaporize into the CO-2rich phase, making it denser, and thus, become more easily soluble in the oil. Mass transfer continues between the CO2 and the oil until the two mixtures become indistinguishable in terms of fluid properties i.e. another miscible phase forms where there is no discrete interfacial barrier between the fluids that prevent the interpenetration of their molecules. Based on the above, miscibility can be defined as physical condition between two or more fluids, which permits them to mix in all proportions without any interfaces and consequently without any interfacial tension.

EVALUATION

Figure 1—One dimensional sketch representing the miscibility process between CO2 and oil.

CO2 Injection Project: During the past decade, Abu Dhabi had noticed a growing interest in CO2 sequestration, injection, and storage. This was not surprising knowing the reported worldwide advantages of CO2 injection for light/ medium oil, the additional recovery of remaining oil after conventional water/gas flooding, and the launching of Abu Dhabi Future Energy Company (Masdar) in 2006 for large-scale carbon capturing. Hence and in 2009 to 2011, the first miscible CO-2EOR pilot in the Middle East, as continuous CO2 injection was implemented in one of the major carbonate reservoirs after almost 2 years of in-house studies involving company-wide reservoirs screening for EOR laboratory experimentations and reservoir modeling simulation studies. Given the outcomes and lessons learned from a previous CO2 pilot stage implemented in the period 2011-2009, field-scale implementation of continuous CO2 injection was fully implemented in 2017. The availability of the CO2 supply source for this project is one of the key factors that led to the project implementation. The required CO2 is captured from steel plant byproducts, by which the project entails capturing, dehydrating, compressing, and transporting the CO2 to the oil field for EOR purposes. This project was put in place with several objectives including, but not limited to building flexible CO2 transportation systems to handle the EOR requirement, assessing the efficiency of the development concept in the transition zone for potential of full field implementation in the future, developing an efficient and cost-optimized EOR monitoring program, building experiences in CO-2 EOR for the carbonate reservoir and it›s analogues and carrying out cost and process optimization exercises based on real operations.

The project strategy involves receiving the supplied CO2 and distributing it at the injectors as per their injection allowable rates. The objectives are to achieve miscibility process, voidage replacement ratio (VRR) of 1.0, effective CO2 utilization factor, maximized recovery, and optimized oil production. In case CO2 supply is not sufficient, injection wells are prioritized, oil production is optimized based on VRR, and reservoir monitoring activities are managed accordingly. Figure 2 below shows the CO2 injection history up to date. It is shown from the figure that the CO2 sustainability is one of the key concerns, as the project rarely received its allowable injection rate. Given that, productioninjection optimization along with modeling sensitivity analyses using streamline and numerical simulation are done regularly. Several other related parameters are reevaluated consequently including: • Expected CO2 breakthrough time per well. • Tracer program and sampling frequency. • Correct timing for the installation of CO2 recycling plant. As part of overall CO2 -EOR roadmap, CO2 recycling plant will be installed for the purpose of capturing CO2 from the associated produced gas with a major objective of keeping CO2 levels within the processing plant design limits.

Along with the sustainability concern of the CO2 supply, the currently implemented CO-2EOR project has been injecting CO2 continuously for almost 2 years and facing several complexities and challenges. Some of these challenges include; ensuring achievement of miscibility conditions, reducing of reservoir modeling uncertainties, keeping the CO2 concentration levels within the existing facilities design limits, keep track of potential related flow assurance problems such as asphaltene deposition and corrosion, optimizing the associated operating costs. Based on the lessons learned from the pilot project, the continuous CO2 injection project implemented state of the art technologies and established a comprehensive plan. A number of mitigation plans and actions are put in place to ensure the smoothness of operations and therefore maintain the positive impacts of enhanced oil recovery by CO2 injection.

RESEARCH New Approaches to Fluvial Reservoir Characterization President of Sedimental Services

Jon Noad

Introduction: Fluvial reservoirs make up a significant proportion of the world’s hydrocarbon reserves, yet in many oil and gas fields uncertainty remains relating to the type of fluvial channels at a particular stratigraphic interval, the connectivity of channel sand bodies, net gross values, reservoir quality, and even overall channel orientation and flow direction. However, there are various ways to reduce this uncertainty in producing fields and to increase the chance of success when exploring for new fluvial reservoirs. These include the use of fluvial sequence stratigraphy, the interpretation of wireline logs within a sequence stratigraphic framework, understanding variations in oil water contacts and pressure data in different channel sand bodies within a field, and the use of seismic data (as well as oriented core and FMI data) to identify both channel orientations and channel belt extents through time. A variety of analogue case studies are introduced to explain the use of these techniques. Fluvial sequence stratigraphy: Sequence stratigraphy attempts to subdivide and link sedimentary deposits into unconformity bound units on a variety of scales and explain these stratigraphic units in terms of variations in sediment supply and in the rate of change in accommodation space. These variations relate in part to changes in relative sea level. Non marine settings are complicated because they respond to other allocyclic controls, climate, and tectonism which affect accommodation space as well as autocyclic controls like channel avulsion. The key to interpreting fluvial deposits is to recognize sequence boundaries on a regional scale and then to start building a framework and model that can predict reservoir distribution and quality at the field scale. Lowstand systems tracts (LST) are characterized by low accommodation space (low rate of base level rise) leading to stacked channels and sheet-like sands (Figure 1). As sea level transgresses to seaward (TST), this creates more accommodation space, preserving fine grained floodplain deposits and isolating channels in thick mudstone beds. The TST is capped by a flooding surface after which the highstand systems tract (HST) features a gradual increase in net gross (Figure 2) towards the next sequence boundary (SB).

Figure 1: Idealized sketch showing a full sequence with changing channel character due to changes in relative sea level through time.

Figure 2. Summary section of alluvial depositional sequences based on studies of Mesozoic strata of Argentina. These sequences comprise three recognizable systems tracts.

RESEARCH Wireline correlation of fluvial deposits: We have already seen how fluvial channel style changes through a sequence of deposition. In an idealized sequence, stacked braided or low sinuosity channels pass up into thick mudstone beds with small, isolated, meandering channels capped by a gradual return to more stacked sandstone beds in the highstand. These sequences can also be identified on wireline logs and in core. Blocky gamma ray (GR) logs at the base (LST) will pass up into isolated meandering channels with a fining upward GR signature (TST), capped by a gradual return more sheet-like sandbodies (HST). Other correlation tips and Core character: Two useful tips are firstly to try to correlate mudstones rather than sandstones in fluvial deposits. Sandstones are deposited only within channels or as crevasse splays, and usually channels avulse sporadically through time. Hence it is unlikely that individual channel sands can be correlated, unlike the much thicker, laterally extensive systems tracts. However, the floodplain mudstones will be deposited over a greater area and when they have a recognisable log signature, they provide a far more robust correlation framework. A second feature to look out for on wireline logs is that the channel, deposits within the TST close to the Maximum Flooding Surface (MFS), are typically meandering channel deposits with muddier point bar deposits or Inclined Heterolithic Stratification (IHS). The reservoir quality of these deposits is lower, although there is a chance that crevasse splay deposits may occasionally connect isolated channels. Oil water contacts and Pressure: Variations in the elevation of the oil-water contact (OWC) across an oil or gas field will relate to low connectivity. A fully connected, sheet-like sandstone reservoir, will have a single OWC unless impacted by faulting or diagenetic cementation. It is therefore important to consult with your reservoir engineer to see whether the channel intersections in different wells have the same OWC and are at the same reservoir pressure. Returning to our Omani oil field, Figure 3 shows three channels, each intersected by a separate well. Each channel has a different OWC and reservoir pressure indicating that these channels are not in communication. Width; depth ratios from analogue channels (Gibling 2006) were used to estimate the approximate channel dimensions to use in the Petrel model constructed for the field.

Figure 3: Three interpreted channels intersected by three wells with contrasting oil -water contacts and reservoir pressures: Channel Belt 1 (CB1) with an OWC of 2592- m; Channel Belt 2 with an OWC of 2637- m; and Channel Belt 3 with an OWC of 2620m. T.

Seismic 1: Extrapolating channel orientations from tenuous seismic data Predicting channel distribution in the subsurface relies on an understanding of the channel orientation. An idea of channel orientation can be gained from dipmeter and FMI data. These oriented logs will exhibit cross-bedding (typically trough cross-beds in low sinuosity channels or lateral accretion surfaces in meandering channels) that can broadly be used to estimate flow direction although this introduces considerable uncertainty. Using horizontal slices through a seismic data cube seismic data may provide a far more robust, field-wide distribution of channels and can be enhanced through seismic processing techniques such as spectral decomposition. This technique is particularly important in meandering systems where localized data cannot give an overall trend in flow direction. Seismic 2: Cheetahs and Lions - using horizontal seismic slices to map channel belts On a regional scale, a terrestrial cross-section oriented along strike (perpendicular to flow direction) will typically intersect undulating topography with fluvial channel belts separated by interfluves. The interfluves are located at higher elevations and are less vegetated. The title of this section: “cheetahs and lions” refers to the fact that lions are ambush predators, requiring vegetation for hunting and can usually be best viewed in the river valleys. Cheetahs like open spaces, so colonize the interfluve grasslands.

Figure 4. Google Earth image of part of Kruger National Park in South Africa showing interfluves and fluves, represented by cheetahs and lions respectively.

RESEARCH Calibrating a Fluid Flow Model for a Geothermal Reservoir: Application on the ECOGI Field

Charidimos Spyrou Senior Reservoir Engineer at Schlumberger

Clement Baujard Reservoir Engineer at ES Géothermie

Giovanni Sosio Geoscience Business Development at Celsius Energy

Abstract: Geothermal energy has been used for electrical generation and heating purposes for decades. It is found in underground reservoirs containing hot water or steam where wells can be drilled to produce the thermal fluid, enabling its utilization. As in the oil industry, the efficiency of thermal systems to produce energy can be evaluated using multi-phase reservoir simulators. This article outlines the calibration process of a fluid flow simulation model, constructed in 2016 for the Rittershoffen geothermal plant, as well as its recalibration after new production data become available. In addition, it provides an overview of how the model was used to estimate a forecast scenario for the system. Introduction A geothermal doublet of wells has been drilled in the context of the ECOGI project. The project aims at producing water from the geothermal aquifer and delivering a power up to 25 MWth at a nearby biorefinery to cover part of its heating needs. Specifically, the produced water (170 oC) goes through a heat exchanger and the heat generated is then transported to the refinery. The water is then injected back in the reservoir at a much lower temperature (70 oC) as it displayed in Figure 1.

Figure 1: The ECOGI fluid transfer network concept.

Model Initialization: The Rittershoffen geothermal plant is located in the Upper Rhine Graben in eastern France. The shallow sedimentary layers (from 0 to between 1500 m and 2000 m depth) overlie the crystalline basement,

which consists of altered and fractured granitic rocks. Large normal faults, corresponding to the extension regime of the Rhine Graben, cross the site. The 3D grid constructed to represent the structure covered a radius of approximately 5km around the producer (GRT-2) and injector (GRT-1)wells, it included the reservoir units Muschelkalk, Buntsandstein and Granite. A fracture network model has been generated based on the image logs from the 2 boreholes leading to the population of the reservoir static properties, mainly porosity and permeability. Since the analysis of the reservoir engineering data supported the assumption that matrix contribution to flow and fluid storativity could be neglected, a single porosity system was modeled with homogeneously distributed thermal conductivity and heat capacity. Water was modelled as a single component excluding the presence of any free gas. The salt concentration was reflected in the resulting fluid density which varied between 1072 kg/m3 and 890 kg/m3 at 20oC (surface conditions) and 200oC respectively (maximum reservoir temperature). To converge to the initial thermal distribution in the reservoir, measured temperature logs for the wells were extrapolated to the grid using the kriging algorithm including some regional trends close to the main fault of the structure.

RESEARCH First Phase Model Calibration: Production only started in the field after the construction of the fluid flow model, thus only limited data were available for its calibration. Specifically, these included a production and an injection test, each lasting for a short period of time (few hours). Therefore, the focus of the model’s history matching process was the interference test between September and October 2014. According to the test, 200 kg of a tracer agent (naphthalene) were mixed with 1000 liters of water and injected from GRT-1 at a concentration of 200g/L. Following that, GRT-1 continued injecting pure water with an average daily rate of 2470 m3/d, throughout the length of the test, GRT-2 production was approximately 2130 m3/d. In addition to its significantly longer period comparing to the other tests, matching the tracer breakthrough time and production concentration increases the confidence that the fluid flow in the interface between the 2 wells has been represented adequately. The simulation study confirmed the initial hypothesis that the water flow from the injector to the producer is predominantly governed by the main fault intersecting the 2 wells. For this reason, emphasis was given in adjusting the permeability profile alongside the fault in the efforts to validate the model against the observed data. After an iterative process, the resulting permeability updates assisted in matching the historically recorded data for the available tests satisfactorily. Figure 2 displays the match achieved for the interference test.

Figure 2: Tracer breakthrough and production concentration matching in GRT-2.

Second Phase Model Calibration: While the model has undergone some modifications since the original calibration in 2016 its reservoir fluid flow simulation capacity was not quality checked against the more recently acquired production data from the field. As the thermal system was fully operational since July 2016, a new study has been carried out in May 2020 to identify possible deviations of the original model from the actual field’s observed production behavior and update it if necessary.

Ultimately, the objective was to increase confidence in the model and perform a forecast scenario to ensure the reservoir’s heat generation efficiency. The observed productions and temperatures covering the period between May 2016 and Jan 2020 were incorporated in the existing hydrodynamic simulation model to quality check its response. In general, the simulation data match the observations reasonably, especially in well GRT-2. While the results for well GRT-1 can be considered acceptable, however, the tubing head pressure appears to be underestimated in the first year of simulation (Figure 4). In addition, the graph displays an upward trend which contradicts the generally stable response expected based on the observed data.

Figure 4: Observed vs simulated injection profile for GRT-1 using the model constructed in 2016.

Conclusion A fluid flow simulation model has been constructed to represent the heat production behavior of a geothermal doublet of wells. Initially, the model was calibrated based on limited data, mainly focusing on replicating the tracer breakthrough time and production concentration reported during an interference test. Following approximately 4 years of operations, a new study was performed to quality check the model’s response against the acquired production data and make appropriate modifications in case of any deviation. Further adjustments to compressibility and permeability variations were made to the model, leading to its successful calibration. Finally, the model was utilized to estimate the system’s behavior for the forecasted period. The results imply that the system can preserve its energy efficiency during the investigated timeframe.

NEW TECHNOLOGY Using RTA and DCA to investigate soaking process in shale gas wells Senior Reservoir Engineer at ShearFRAC Introduction The multistage hydraulic fracturing process is the main stimulation technique to develop tight gas and shale formations. This process involves pumping large volumes of water with different types of proppants, depending on reservoir conditions and other additives into the rock at high pressures. Up to %70 of the injected fluid leaks off to the formation in the stimulated area, which increases the water saturation around the wellbore. Hence, gas productivity decreases due to the water blockage around the wellbore. Shutting in the well after hydraulic fracturing tends to have a negative impact on the tight gas formation. However, recently, some shale formation operators shut in the wells after the fracturing process for pipeline restrictions. Accidently, they found an improvement in gas recovery and a reduction in water production, that process is called “the soaking process”. Experimental results for shale gas and oil formations showed that imbibition and capillary forces could redistribute the leak-off water away from the frac face. Hence, the water blocking effect decreased and the relative gas permeability increased. By using lowsalt-concentration fracturing fluid compared to the formation water, osmotic forces could be induced, and formation wettability could change to more water-wet. In addition, swelling clays in the formation matrix could induce stresses creating microcracks. These parameters could contribute to increasing the well performance. This behavior was observed in some wells in Marcellus shale with an increase in gas recovery and reduction in water production after shut-in the wells for a few weeks.

Ahmed Ibrahim

Fig. 1 shows the common stages in the well life after hydraulic fracturing. The well may have two different shut-in periods; one before flowback and the other one after. The first shut-in period leaves the formation in direct contact with a large volume of fracturing fluid which may cause a worsening effect on the well performance. Well flowback first removes most of the movable water. Then, the imbibition forces during the shut-in period help to clear the frac face. As a result, the gas productivity increases, and water production decreases.

Effect of Soaking on Well Performance: Different wells were shut in after the flowback stage for facility construction. Fig. 2 shows the gas and water production rates for a gas well completed in Barnett shale formation with the same events as in Fig. 1. Gas production increased by %27 of its value before shut-in. The increase in the production was calculated by Eq. 1.

Where q_g is gas rate, and the subscripts r, AS, BS are the improvement ratio after soaking and before soaking, respectively.

NEW TECHNOLOGY

Fig. 2: Gas and water production rates versus time for a gas well showing the sequence events after fracturing until production.

Methodology Gas Production RTA: Bottom-hole pressure, pwf, was converted to pseudopressure, m(pwf). The pseudopressure difference was then normalized using gas production rate. The normalized pseudopressure difference and linear superposition time (super-t) were used to plot the RTA for Ac characterization. Normalized pseudopressure and linear superposition time were calculated as follows:

Where pi, and pwf are the initial reservoir and bottomhole pressures, respectively. μ and z are the gas viscosity and compressibility factor, respectively. n is the time step at which Super-t is calculated, and j is the time step from 0 to n.

Fig. 3 – RTA diagnostic plot of pseudopressure difference divided by rate, [m(p_i)-m(p_wf)]/q_g, versus time.

Fig. 4 – RTA specialized for linear flow regime.

A similar analysis was conducted for water production data before and after soaking (Fig. 6). EURw was estimated in both cases assuming a minimum water rate of 5 stb/d. EURw decreased by 19 % of its initial value before well shut-in.

Where EURw is the expected ultimate water recovery, and the subscripts r, AS, BS are the reduction ratio, after soaking and before soaking, respectively.

Fig. 3 shows a diagnostic plot that identifies the linear flow before and after soaking. Fig. 4 is a specialized and more definitive plot to identify the linear flow behavior. Two straight lines were found in the cartesian plot with a different slope (m). √k A_c can be calculated from the line slope (m) (Eq. 5). With assuming properties

constant

formation

and

fluid

where are the formation porosity, gas viscosity and total compressibility, respectively. T is temperature, k is the formation permeability and A_c is the stimulated area. The change in √k A_c due to soaking was calculated from Eq. 7, and it was found to be %31.

Fig. 6 – DCA for the water rate before and after the soaking stage.

Conclusion: • The well shut-in after flowback increases the gas productivity and decreases water production. • Higher potential benefits from soaking can be expected for formations with low water saturation, high-pressure gradient, and high thermal maturity. • Formation pressure, gas gravity, and initial water saturation are the highly effective parameters on the well performance with the soaking process.

NEW TECHNOLOGY Heavy Oil Development Using Microbiology Applications Reservoir Engineer, New Technology Lead – GUPCO

Noureldien Darhim

Introduction: Crude oil is composed of four chemical groups: saturates (paraffins), Aromatics, Resins, and Asphaltene. Fractions of these group dictate the fluid properties of the crude especially, oil viscosity and API (Figure 1). From subsurface point of view, the main challenge of heavy oil is not being “heavy” but being “viscous”, and “immobile” to flow/move through reservoir pores. In this regard, it is good to differentiate between a few terminologies: Heavy Oil, Extra Heavy Oil, and Bitumen. In Industry, there are many definitions available for heavy oil based on different entities guidelines. According to World Energy Council, heavy oil is any crude having 20 – 10 API. Extra heavy oil has less than 10 API with oil viscosity up to 10,000 cP, and in case oil viscosity is not measured, extra heavy oil is defined down to 4 deg API. Bitumen is the thickest form of crude oil at which the oil viscosity is more than 10,000 cP and it is not mobile at reservoir condition. (note that natural bitumen can also be called Tar Sand or Oil Sand) Figure 1: Oil viscosity and API relation for heavy oil. Heavy Oil Recovery Methods: Historically, and from subsurface perspective, heavy oil can be produced whether by thermal recovery (Figure 2), and/or miscibility methods. Thermal recovery mechanism increases oil mobility by reducing oil viscosity, thermal expansion, and swelling. There are many techniques/ set-ups available to achieve the same goal: cyclic steam stimulation (CSS), steam flooding, steam assisted gravity drainage (SAGD), In-situ combustion (ISC), and conductive heating. There are also many versions and customizations can be done for each method of those. Miscible/Immiscible methods (Figure 3) involve using gases to alter oil properties, whether by vaporizing oil into gas phase or condensing gas into liquid phase. This can be done using carbon dioxide, nitrogen, flue gas, or light gases such as Methane…etc.

Figure 2: SAGD Application (Thermal Methods).

Figure 3: CO2 Flooding (Miscible/Immiscible) Flooding.

NEW TECHNOLOGY What are Microbes? Microbes are tiny micro-organisms that can be found everywhere around us. Some microbes can be healthy for human, others can be pathogenic (i.e. cause diseases). Microbes can be divided into bacteria, fungi, algae, protozoa, and viruses. In Exploration and Production (E&P) Industry, bacteria are mainly used in various applications such as treating reservoirs from being sour to sweet reservoirs, formation of bio-chemical (e.g. bio-polymers), conformance (e.g. perforation shut-off), and EOR agent (our main focus in this article). Mechanisms: One of the key applications of microbiology is Microbial Enhanced Oil Recovery (MEOR) at which it can promote one or more EOR mechanism (in reservoir ‘in-situ’). Bacteria can induce many EOR mechanisms by creation of in-situ bio-polymer, biosurfactant, bio-gases, or by bio-degradation. Biopolymers can be used to increase sweeping efficiency which is usually needed in case of heterogeneous multi-zonal reservoirs with wide discrepancy between layers’ permeability. Bio-polymers can be very stable in harsh environment such as high pressure, or high temperature reservoirs but, it is attackable by microorganisms. Bio-surfactant can be used to reduce residual oil saturation by reducing interfacial tension between oil molecules and rock grains. Bio-surfactant is potentially applicable in strong oil-wet reservoirs at which residual oil saturation is usually relatively high. Bacteria Types: Bacteria can be divided and subdivided based on many criteria (Figure 4) such as their morphology, metabolism, functions, gram strain, components, and others. Bacteria classifications and naming are not easy, and there are different international entities maintain worldwide rules for this (e.g. International Committee on Systematic Bacteriology, ICSB). To accommodate reservoir engineering applications, bacteria can be classified into indigenous bacteria (microbes living within specific system), and exogenous bacteria (microbes living outside the system).

In heavy oil development, we can rely on both indigenous, and/or exogenous bacteria however, indigenous bacteria will be more encouraging in terms of project feasibility. In case of having indigenous bacteria (i.e., bacteria already live in the reservoir), some nutrients (called fertilizers) are injected from surface to induce bacterial specific bacterial action so they can give specific desirable metabolites. These metabolites can be in-situ bio-surfactant or bio-gases; for example, which can help in recovering heavy oil (as explained earlier). Bacteria Fertilizers: In this regard, it is important to know that bacteria nutrition can lead whether to bacterial reproduction/ replication or bacterial growth. Bacterial reproduction causes number of bacteria to exponentially increase forming clogging substance. That bio-clogging can be used as a shut-off mechanism, and if it is not intended, it is very critical since it can damage reservoir entirely. On the other hand, Bacterial growth results in a lot of metabolites with minimum replication rate possible. Case Study from Egypt: A technical paper was presented [Darhim, N. et al., 2019] addressing field application for developing heavy oil resource using microbial EOR. The application involved a single-well huff-and-puff treatment at which API changed from 24° to 38°-32°, oil viscosity decreased from 630 cP down to 390 cP, Asphaltene decreased from %14.5 down to %9.6, and consequently, WC decreased from %99 to average %83 due to oil mobility increase.

Conclusion At last, dealing with unconventional resources especially, heavy oil is not an easy task. It requires a lot of work and analysis. Sometimes having all of your homework done may not be enough, you have to search and benefit from other industries’ technology especially when it comes to such huge potential at which only %1 recovery of heavy oil means billions of oil barrels worldwide.

Figure 4: Example of Bacteria Types.

CASE STUDY A Proxy Based Approach for the Preliminary Evaluation of New Gas Condensate Field for Development Senior Reservoir Engineer with NewcrossEP Nigeria

James E. Omeke

Abstract: With increase in gas demand to meet both export and domestic gas obligations, amidst oil price volatility, it is imperative that oil and gas companies embarks on activities that will minimize investment risk and initiate robust development plans. It becomes a very big challenge at the onset of new gas condensate field development owing to limited geological and engineering data. To ascertain the technical feasibility and economic attractiveness of a gas condensate field, a very lengthy study work is required to unravel the complex interplay of subsurface uncertainties; hence, a quick screening tool is therefore required for quick decision making and investment prioritization. A proxy of recoverable reserve for the new field was developed for this purpose using design of experiment (DOE) and response surface model (RSM). However, although DOE was initiated in the industry to reduce computation, it remains computationally expensive especially in compositional simulation were many degrees of freedom exist in the uncertainty parameters. Introduction: Uncertainty analysis using DOE and RSM has been a well-established approach for uncertainty management in most oil and gas industries today. With the availability of very limited data and large uncertainties, questions arise on how to effectively proceed with a new field development plan. With current advances in 3D seismic, a certain level of confidence is placed on mapping of reservoir surfaces. The bulk of uncertainties lie in the fact that few exploratory wells cannot provide detailed information about subsurface reservoir internal architecture in addition to uncertainties associated with flows and fluid properties. Compositional reservoir simulation models are strongly recommended and adopted for gas condensate field simulation. Due to the complex nature of the fluid description (PVT properties expressed as a function of pressure, temperature, and composition), it will be computationally expensive to implement the traditional Ad-hoc ”one-variable-ata-time” sensitivity analysis, which involves setting one variable at the P10 or P90 level while keeping others at P50 level in a simulation run in a bid to assess all possible uncertainty space while carrying out a field development followed by economic analysis consequently leading to bias in ranking of independent variable.

Case study: The case study was carried out on a gas field onshore Niger – Delta. The field is located in the eastern part of Northern Delta Depobelt, and in the north-eastern fringe of Niger Delta Basin. It lays onshore Nigeria (Inland Basin) in the northern-most part of the Niger Delta Depobelt which contains the Akata-Agbada Petroleum System. Structurally, the field reservoirs are typical simple four way closed roll-over anticlines formed at the downthrown side of a major North-West (NW) – South-East (SE) synthetic fault. The shallow reservoir is a four way dip closure; both intermediate and deep reservoirs are mostly four way dip closure assisted with a major fault. The top structure of the reservoir is shown in Fig. 1.

Figure 1: Reservoir Top structure map

CASE STUDY Three exploratory/appraisal wells have been drilled, encountering fourteen (14) hydrocarbon-bearing zones. The field has an estimated recoverable reserve of 214Bscf of non-associated gas and 6.8 MMbbls of Condensate. Properties of the reservoirs and fluids in the field are highly uncertain as the field is still in its appraisal phase. Production is yet to commence. The major source of some engineering data came from Drill stem test results and PVT data for very few reservoirs. Out of the 14 hydrocarbon-bearing sands only 6 have been tested with PVT Laboratory report available for 4 reservoirs. Additional wells are planned to be drilled in the short term which will affect decision making especially in the surface facilities sizing and design. With the absence of core data, an earth model was constructed for the entire field by integrating well logs, 3D seismic and cores from the analogue field (Fig. 2).

Figure 2—Modelled structured surfaces (Field modelled horizons)

Uncertainty Parameters: One of the uncertainty parameters considered for this subject study is PVT uncertainties captured by the EoS. PVT uncertainties: The two major issues pertinent to gas condensate reservoirs are: (a) variation of condensate yield with the life of the reservoir and (b) Effect on gas productivity due to near wellbore two-phase flow (condensate banking). These two major phenomena are controlled by PVT data and relative permeability. The most critical sets of PVT properties as highlighted by Whitson include: Gas viscosity, Z-factor, Compositional (C+7) variation with pressure, Oil viscosity, and liquid dropout. The properties result from complex functions that are difficult to be explicitly represented. For example, viscosity is determined separately with correlation because it is a flow property that cannot be predicted with an EOS since EOS

predicts more of static equilibrium properties. When PVT laboratory data is provided, these properties are measured experimentally and matched with a tuned EOS model. For every process involved in PVT experiment and analysis, the first step is to determine the compositions of the various components that make up the fluid system. How representative the fluid sample will become the major challenge to face. Two-phase flow in the wellbore can cause significant errors for sampling downhole. Surface sampling technique is less error-prone. Gas within the formation is more mobile than liquid; consequently, the surface GORs might appear higher than for the native fluid, which will make the sample non representative if recombined with the surface observed GOR. Accuracy in the determination of the GOR to be used for separator liquid and gas sample recombination becomes very critical. The field under study showed some relatively unstable flow condition revealed by the DST carried out. This complicates the accurate determination of GOR. To holistically encapsulate the impact of all PVT data that is directly or indirectly affected by the target GOR for separator fluid recombination, GOR becomes a major uncertainty in the study. From DST results, full field GOR was observed to range from 8.7Mscf/ stb to 55 Mscf/stb. See Fig. 3.

Figure 3: CGR vs GOR

The PVT laboratory reports available for the 4 reservoirs were matched with an EOS model for each reservoir. For reservoirs that had not yet been sampled but had been tested, the separator gas and oil samples of the closest or adjacent reservoir were mathematically recombined to the tested GOR of thereservoir.

CASE STUDY Abu Gharadig Basin Hydrocarbon Source Rock. Case Study: Khatatba Formation, Lower Safa Reservoir Senior Geoscientist and GeoModeler at Bapetco Introduction

Shrief Shafik

V. The uppermost clastic depositional cycle includes the Upper Eocene-Oligocene, Miocene, and younger section.

Abu Gharadig basin lies in the northern part of the Western Desert of Egypt. It lies between Latitudes 29° N and 30° N, Longitudes 53° 27° E and 7° 30° E (Figure 1) and located about 350 km to west from Cairo and 200 km to south from the Northern Mediterranean Coast. It represents about %3.6 680,000( Km2) of the area of the Western Desert of Egypt.

Figure 1: Location Map of Abu Gharadig Basin. (Khaled, 1999).

The stratigraphic section consists of alternating depositional cycles of clastics and carbonates (Figure 2). Five cycles have been recognized as follows: I. The first cycle of clastic facies dominates the oldest sedimentary rocks and includes the entire Paleozoic and Lower Jurassic formations. II. A carbonate section of Middle and Upper Jurassic formations. III. The second cycle of clastic comprises the Lower Cretaceous up to the Upper Cretaceous Early Cenomanian. IV. From Upper Cenomanian and up to the Middle Eocene, carbonate deposits are again distributed throughout northern Western Desert.

Figure 2: Stratigraphic column of the North Western Desert.

Geochemical Analysis: Generation of oil from a potential source rock, as well as maturation of the proto-oil, is controlled largely by temperature, which is a function of depth of burial, time, and tectonic history. The longer the source rocks are subjected to overburden pressure and the higher the temperatures affecting the transformation, the simpler becomes the molecular structure of the oil. Therefore, a hydrocarbon source rock can produce different types of oil at different stages of maturation and basin development.

CASE STUDY The geochemical analyses were carried out on core or ditch cutting samples based on the screening analysis of TOC Wt.% and Rock-Eval pyrolysis. TOC determination is performed using analyzer instruments in the laboratory for determination of carbon content. Simply, a total organic carbon analyzer determines the amount of carbon in a water sample. By acidifying the sample and flushing with nitrogen or helium the sample removes inorganic carbon, leaving only organic carbon sources for measurement. The Rock-Eval pyrolysis started is a technique that involves passing a stream of Helium through 65 mg of pulverized rock heated initially at 300oC for 3 minutes. The temperature is then programmed to increase about 25oC/min, up to 650oC, and hold for 3 minutes. The vapors are analyzed with a flame ionization detector (FID), resulting in the peaks (Figure 3). S1 represents any free hydrocarbons in the rock that either were present at the time of deposition or generated from the kerogen since deposition that can be volatilized out of the rock without cracking the kerogen. Heating at 300oC simply distills these free hydrocarbons out of the rock, between about 350ºC and 650oC. hydrocarbons S2 are generated by cracking the kerogen until only residual nongenerating carbon remains. In addition, any free highmolecular-weight bitumen that was not distilled out in S1 is cracked into smaller molecules at the higher temperatures. The carboxyl groups in the kerogen are cleaved by heat, yielding (CO2) S3, which is analyzed using a thermal conductivity detector (TCD).

Case Study: The Khatatba Formation describes as a clastic section made up of sandstone and shale, has a few limestone interbeds. These limestone interbeds become thicker, argillaceous, and more frequent near the upper part of the section especially, in the eastern and northeastern parts of Western Desert. Thin coal seams are present at different levels of the section. Geochemical analysis was carried out on ditch cutting and core samples of the Well-X (Table. 1 and Figure 4) based on the screening analysis – TOC and Rock-Eval pyrolysis the source rock potentiality is mixed oil/gas-prone (Figure 5).

Figure 4. Summary of geochemical analysis of Khatatba core and ditch cutting samples of Well-X.

Figure 3: Cycle of analysis and example of record obtained by the pyrolysis method.

Figure 5: Rock-Eval HI versus OI diagram showing the three main types of kerogen and analyzed samples of Well-X.

Eni Announces 3 New Discoveries in Egypt’s Western Desert The Egyptian Ministry of Petroleum and Mineral Resources announced that Italy’s energy giant Eni has discovered new oil and gas resources in the Meleiha and South West Meleiha concessions, in the Western Desert of Egypt. Eni said that “The discoveries in the Meleiha development lease were achieved through the Jasmine W1-X and MWD21- wells, while in South West Meleiha exploration concession the discovery was made through SWM4-X well, located 35 km south from the Meleiha oil center”. Egypt Eyes Oil Products Self-Sufficiency by 2023 Egypt will be self-sufficient in refined oil by 2023, Minister of Petroleum and Mineral Resources Tarek El Molla said in an interview with Bloomberg at the Saudi in Riyadh where he was attending a climate conference. Due to a 7$ billion project to upgrade of existing refineries and construct seven new ones, Egypt’s goal of selfsufficiency is now within reach. H.E El Molla noted that the new facilities will have the capacity to produce 6.2 million tons per year (mt/y) of products, such as gasoline and diesel. Shell Completes Sale of Western Desert Assets in Egypt Shell Egypt N.V. and Shell Austria GmbH, subsidiaries of Royal Dutch Shell plc., have completed the sale of their upstream assets in Egypt’s Western Desert to a consortium made up of subsidiaries of Cheiron Petroleum Corporation and Cairn Energy PLC for a base consideration of $ 646 million and additional payments of up to 280$ million between 2021 and 2024, contingent on the oil price and the results of further exploration.

Kuwait Energy Receives Operational Excellence in Brownfield Award For the second year in a row, Kuwait Energy Egypt won the Operational Excellence in Brownfield Award for “Rejuvenation of the Area A fields, Egypt: Challenges, Plans and Results”. The award was given during the 4th Upstream Technical Convention opening that was organized by Egypt Oil & Gas. It recognized Kuwait Energy’s activities in Area A fields in Eastern Desert as a role model in brownfield management. The company managed to respect Health, Safety, Security & Environment (HSSE) standards and forestall the decline in production while optimizing CAPEX and OPEX by enabling new technologies, thorough analysis of the old data in the light of the recent advancement in reservoir analysis and seismic interpretations. TGS, Schlumberger to Conduct New 3D Multi-Client Seismic Survey in Egyptian Red Sea TGS, in partnership with Schlumberger, revealed news about its new 3D seismic survey in the Red Sea. The project will involve approximately 6,800 square kilometers. It will be acquired with long offsets and processed using a Pre-Stack Depth Migration (PSDM) workflow to enable sub salt imaging. EGPC Launches HSE Digital Application This new application will make HSE measurements available to all employees in their sites all of the time. It includes the HSE rules according to standards and codes of the International Association of Oil and Gas Producers (IOGP), and EGPC operation management systems (EGPC OMS). Moreover, the application comprises HSE guidelines, lifesaving guidelines, lessons learnt from previous incidents, the essentials for safe operations according to the American Chemical Process Safety Center (CCPS), awareness campaigns and various trainings for hard missions.

Shell Signs Agreement to Acquire Landmark Retail Sites in U.S. Shell Retail and Convenience Operations (a subsidiary of Shell Oil Products) revealed that it has signed an agreement to acquire 248 fuel and convenience retail sites from the Landmark Group. The statement elaborated that the agreement also includes supply with an additional 117 independently operated fuel and convenience sites. This acquisition enables Shell to boost its presence in the U.S. and strengthen its ongoing business relationships. It will help Shell to enhance its Powering Progress Strategy. Iraq’s INOC to Negotiate with Chevron for Developing Oil Fields in Dhi Qar The Iraqi Cabinet has assigned the Iraq National Oil Company (INOC) with the task of negotiating with Chevron for developing oil fields located in Nassiriya province in Dhi Qar. The statement elaborated that the Nassiriya project includes the development of four exploratory blocks in the province. It added this project will enhance sustainable national production of oil, which will boost the national economy. ADNOC to Spend 6$ Billion to Enable Drilling Growth The Abu Dhabi National Oil Company (ADNOC) announced investments worth up to almost 6$ billion to boost drilling growth and help increase its crude oil production capacity to 5 million barrels per day (mmbbl/d) by 2030. This is also promotes gas self-sufficiency for the UAE. The company explained that these investments include procurement awards to world class contractors for Wellheads and related components, Downhole Completion Equipment (DCE) and related services, and Liner Hangers and Cementing Accessories. It is estimated that up to %60 of the total value of the awards could flow back into the UAE’s economy.

Halliburton Launches iStar™ Intelligent Drilling and Logging Platform Halliburton announced the release of the iStar™ Intelligent Drilling and Logging Platform, a cutting-edge measurement platform that features multiple services offering enhanced control of drilling and logging operations. The platform provides optimized subsurface insight, superior drilling performance, and consistent well delivery through its digital architecture. This platform gives professionals real-time visibility of the type and quantity of reservoir fluids, using a data science approach to improve well placement and enhance reserves calculations. Eni to Develop Decarbonization Projects in Congo Eni has signed a memorandum of understanding (MoU) with Congo’s government to help enhance the country’s agro-biofuel sector. The MoU covers industrial scale production of castor oil in order to supply feedstock for Eni’s bio-refinery system. A pilot phase will commence in October with castor bean sowing activities on over 200 hectares of land, and up to 1,000 estimated beneficiaries. Moreover, the industrial phase is expected to be executed over 150,000 hectares with 90,000 estimated beneficiaries by 2030. Baker Hughes, MHWirth Complete Subsea Drilling Systems Merger Baker Hughes has completed its Subsea Drilling Systems business (SDS) merger with Akastor ASA’s subsidiary MHWirth AS (MHWirth), forming a global offshore drilling equipment company called HMH. With both companies in the merger having equal equity in HMH, the newly formed company will have the ability to combine skills and expertise in the field, enabling them to offer a wide range of world-class offshore drilling equipment products and packages.

Persian Gulf (Heart of World Energy)

Geographically, it is situated in the Middle East and shared among Iran, Iraq, Kuwait, Saudi Arabia, Bahrain, Qatar, United Arab Emirates and Oman. Geologically, the basin is a depocenter, which is bounded by the Zagros Fold Belt to the north, by the Arabian shelf to the south, by Hegab Thrust and Dibba Fault to the east and Burgan-Azadegan high to the west. It is a shallow marine basin with average water depths of 50m and an area of 251,000 km2. It contains approximately %20 and more than %10 of total proven world’s gas and oil reserves, respectively. North Dome/South Pars fields (1260 tcf) is world’s largest gas accumulation, located in this basin. Safaniya (50 bbl) and Upper Zakum (50 bbl) fields is the world’s largest offshore field. The Ghawar and Burgan fields which ranked as the first and second world’s biggest oil fields is placed near this basin.

The main producing zones are found in oolitic shoal and dolomitized facies of Khuff and Arab formations, reefal and karstified facies of Shuaiba and Mishrif formations and deltaic sands/sandstones of Burgan Formation.