DTS/DAS applications provide key advantages in surveillance and better understanding of both unconventional and thermal operations in terms of key attributes including but not limited to conformance, wellbore integrity in better spatial and temporal terms. This study investigates the effects of CO2 and Naptha in enhancing the steamflood process while incremental benefits are achieved through improved monitoring of the steamflood injection process using DTS/DAS applications.
A full-physics simulator is used to model the process. The technical as well as economic details of deployment of DTS/DAS as well as the steam-additive process are outlined in detail. Sensitivity study carried out on the model indicates the key attributes along with their significance. Athabasca bitumen properties are used. CO2 additive increases the steam chamber size but lowers the steam temperature while naptha/CO2 additives lower the viscosity, thus optimization study carried out the optimum operating levels of the additives not only in physical production/injection terms but also in terms of economics.
The results indicate better reservoir management with DTS/DAS applications compared to the base case and injection can be monitored and adjusted better with such tools. The objective function built with economic parameters helped to maximize the NPV for the project, providing a more realistic perspective on the projects. DTS/DAS applications prove useful not only in terms of production performance but also in terms of economics. Physical properties of CO2 and naptha indicate that the two have different dominant modes of improving recovery of steam only injection. CO2 increases the extent of the steam chamber while lowering the steam temperature significantly.
This study approaches the delicate process of additive use in steam processes while coupling the additional benefits of use of DTS/DAS applications in optimizing the recovery and the economics outlining the key attributes and the challenges and best practices in operations serving as a thorough reference for future applications.
Temizel, Cenk (Aera Energy) | Balaji, Karthik (University of North Dakota) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (Istanbul Technical University) | Moreno, Raul (Smart Recovery) | Rabiei, Minou (University of North Dakota) | Zhou, Zifu (University of North Dakota) | Ranjith, Rahul (Far Technologies)
Due to complex characteristics of shale reservoirs, data-driven techniques offer fast and practical solutions in optimization and better management of shale assets. Developments in data-driven techniques enable robust analysis of not only the primary depletion mechanisms, but also the enhanced oil recovery in unconventionals such as natural gas injection. This study provides a comprehensive background on application of data-driven methods in oil and gas industry, the process, methodology and learnings along with examples of data-driven analysis of natural gas injection in shale oil reservoirs through the use of publicly-available data.
Data is obtained and organized. Patterns in production data are analyzed using data-driven methods to understand key parameters in the recovery process as well as the optimum operational strategies to improve recovery. The complete process is illustrated step-by-step for clarity and to serve as a practical guide for readers. This study also provides information on what other alternative physics-based evaluation methods will be able to offer in the current conditions of data availability and the understanding of physics of recovery in shale oil assets together with the comparison of outcomes of those methods with respect to the data-driven methods. Thereby, a thorough comparison of physics-based and data-driven methods, their advantages, drawbacks and challenges are provided.
It has been observed that data organization and filtering takes significant time before application of the actual data-driven method, yet data-driven methods serve as a practical solution in fields that are mature enough to bear data for analysis as long as the methodology is carefully applied. The advantages, challenges and associated risks of using data-driven methods are also included. The results of comparison between physics-based methods and data-driven methods illustrate the advantages and disadvantages of each method while providing the differences in evaluation and outcome along with a guideline for when to use what kind of strategy and evaluation in an asset.
A comprehensive understanding of the interactions between key components of the formation and the way various elements of an EOR process impact these interactions, is of paramount importance. Among the few existing studies on natural gas injection in shale oil with the use of data-driven methods in oil and gas industry include a comparative approach including the physics-based methods but lack the interrelationship between physics-based and data-driven methods as a complementary and a competitor within the era of rise of unconventionals. This study closes the gap and serves as an up-to-date reference for industry professionals.
Temizel, Cenk (Aera Energy) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (Istanbul Technical University) | Putra, Dike (Rafflesia Energy) | Asena, Ahmet (Turkish Petroleum Corp.) | Ranjith, Rahul (Far Technologies) | Jongkittinarukorn, Kittiphong (Chulalongkorn University)
Smart field technologies offer outstanding capabilities that increase the efficiency of the oil and gas fields by means of saving time and energy as far as the technologies employed and workforce concerned given that the technology applied is economic for the field of concern. Despite significant acceptance of smart field concept in the industry, there is still ambiguity not only on the incremental benefits but also the criteria and conditions of applicability technical and economic-wise. This study outlines the past, present and the dynamics of the smart oilfield concept, the techniques and methods it bears and employs, technical challenges in the application while addressing the concerns of the oil and gas industry professionals on the use of such technologies in a comprehensive way.
History of smart/intelligent oilfield development, types of technologies used currently in it and those imbibed from other industries are comprehensively reviewed in this paper. In addition, this review takes into account the robustness, applicability and incremental benefits these technologie bring to different types of oilfields under current economic conditions. Real field applications are illustrated with applications in different parts of the world with challenges, advantages and drawbacks discussed and summarized that lead to conclusions on the criteria of application of smart field technologies in an individual field.
Intelligent or Smart field concept has proven itself as a promising area and found vast amount of application in oil and gas fields throughout the world. The key in smart oilfield applications is the suitability of an individual case for such technology in terms of technical and economic aspects. This study outlines the key criteria in the success of smart oilfield applications in a given field that will serve for the future decisions as a comprehensive and collective review of all the aspects of the employed techniques and their usability in specific cases.
Even though there are publications on certain examples of smart oilfield technologies, a comprehensive review that not only outlines all the key elements in one study but also deducts lessons from the real field applications that will shed light on the utilization of the methods in the future applications has been missing, this study will fill this gap.
Temizel, Cenk (Aera Energy) | Canbaz, Celal Hakan (Schlumberger) | Tran, Minh (USC) | Abdelfatah, Elsayed (University of Calgary) | Jia, Bao (University of Kansas) | Putra, Dike (Rafflesia Energy) | Irani, Mazda (Ashaw Energy) | Alkouh, Ahmad (College of Technological Studies)
Petroleum in general is found in sub-surface reservoir formation amongst pores existent in the formation. For several years due to lack of information regarding production and technology, free-flowing, low viscosity oil has been produced known as conventional crude oil. Fortunately, in recent times, due to advancement of technology, high viscosity with higher Sulphur content-based crude has been produced known as heavy oil. There are also exists significant difference in volatile materials as well as processing techniques used for the two types of crude. (
Heavy Oil can be used by definition internationally to describe oil with high viscosity (Although the Oxford dictionary might have several variations of the same, within the contents of this paper, we refer to heavy oil as high viscosity crude). Heavy oil generally contains a lower proportion of volatile constituents and larger proportion of high molecular weight constituents as compared to conventional crude oil (often referred to as light oil, we shall describe the characteristics of the types of oil further in the introduction). The heavy oil just doesn't contain a composition of paraffins and asphaltenes but also contains higher traces of wax and resins in its composition. These components have larger molecular structures leading to high melting and pour points. This makes the oil a bad candidate for flow profiles and adversely affects the mobility of the crude. ( Recovery: Low viscosity and high melting points Processing: Higher Resin, Sulphur and aromatic content Transportation: Low Viscosity
Recovery: Low viscosity and high melting points
Processing: Higher Resin, Sulphur and aromatic content
Transportation: Low Viscosity
These all together impact the economics related to E&P (Exploration and Production) of heavy oil resources. These resources generally have a higher of production associated with them and are one of the first candidates to be affected by reduction of crude prices as seen in 2014 and early 2015. Crude oil can generally be classified into its types by using its API values that are generally obtained through lab testing.
Temizel, Cenk (Aera Energy) | Irani, Mazda (Ashaw Energy) | Canbaz, Celal Hakan (Schlumberger) | Palabiyik, Yildiray (Istanbul Technical University) | Moreno, Raul (Smart Recovery) | Balikcioglu, Aysegul (USC) | Diaz, Jose M. (VCG O&G Consultants) | Zhang, Guodong (China Petroleum Eng and Construction Corp.) | Wang, Jie (College of Technological Studies) | Alkouh, Ahmad
As major oil and gas companies have been investing in renewable energy, solar energy has been part of the oil and gas industry in the last decade. Originally, solar energy was seen as a competing form of energy source as a threat that may replace or decrease the share of fossil fuels as an alternative energy resource in the world. However, oil and gas industry has adapted to the wind of change and has started investing and utilizing the solar energy significantly. In this perspective, this study investigates and outlines the latest advances, technologies, potential of solar both as an alternative and a complementary source of energy in the Middle East in the current supply and demand dynamics of oil and gas resources.
A comprehensive literature review focusing on the recent developments and findings in the solar technology along with the availability and locations are outlined and discussed under the current dynamics of the oil and gas market and resources. Literature review includes a broad spectrum that spans from technical petroleum literature with very comprehensive research to non-technical but renowned resources including journals and other publications including raw data as well as forecasts and opinions of respected experts. The raw data and expert opinions are organized, summarized and outlined in a temporal way within its category for the respective energy source.
Solar energy is discussed from a perspective of their roles either as a competing or a complementary source to oil and gas. In this sense, this study goes beyond only providing raw data or facts about the energy resources but also a thorough publication that provides the oil and gas industry professional with a clear image of the past, present and the expected near future of the oil and gas industry as it stands with respect to renewable energy resources.
Among the few existing studies that shed light on the current status of the oil and gas industry facing the development of the renewable energy are up-to-date and the existing studies within SPE domain focus on facts only lacking the interrelationship between solar energy and oil and gas such as solar energy used in oil and gas fields as a complementary green energy.
Temizel, Cenk (Aera Energy) | Irani, Mazda (Ashaw Energy) | Canbaz, Celal Hakan (Schlumberger) | Palabiyik, Yildiray (Istanbul Technical University) | Moreno, Raul (CSmart Recovery) | Diaz, Jose M. (VCG O&G Consultants) | Tao, Tao (Texas Southern University) | Alkouh, Ahmad (College of Technological Studies)
Along with the advances in technology, greener technologies that help to minimize carbon footprints are becoming more common in oilfield applications as well as other areas. Electrical heating is one of the relatively more environmentally-friendly heavy oil recovery technologies that is not new but has gained more popularity with the advances in electrical heating equipment and the technologies within the last decade offering longer and reliable operations that led to its use as a standalone recovery method rather than only a preheating method. In this study, a comprehensive investigation of the production optimization is outlined that includes not only the reservoir aspects but also the production and facility aspects of electrical heating in heavy oil reservoirs. A full-physics commercial simulator has been coupled with an optimization/uncertainty tool to understand the significance of uncertainty and control variables that influence the production function in addition to the analysis of normalized type curves in different real field cases. The challenges encountered during implementation of electrical heating processes in terms of production, reservoir and facilities engineering are outlined in order to provide a comprehensive and practical implementation perspective rather than only theoretical and/or simulation work. It is observed that electrical heating can be promising when applied in the right place and can bring lots of benefits not only in terms of low water-cut recovery, but also low carbon footprint and low costs associated with environmental fees. The significant parameters are listed for a robust and successful implementation of an electrical heating project. There are studies on electrical heating, but they are either outdated reflecting the old technology, or only focusing on simulation/theoretical work or only case focusing only reservoir or production aspects. This study fills the gap and provides a comprehensive look in detail in the theory, real-field practical problems and solutions from source of electricity to production of the heavy oil illustrating the costs associated that can serve as a solid reference for future implementations. 2 SPE-193707-MS
Temizel, Cenk (Aera Energy) | Zhiyenkulov, Murat (Schlumberger) | Ussenova, Kamshat (Schlumberger) | Kazhym, Tilek (Embamunaygas) | Canbaz, Celal Hakan (Schlumberger) | Saputelli, Luigi Alfonso (Frontender Corporation)
Optimum well placement in intelligent fields, using previously developed optimal control methods to maximize net present value (NPV), is becoming practical with recent advances in technologies as well as their applications to the petroleum industry. To efficiently use these methods in an intelligent field, an assessment of its economic aspects and its performance, especially in reservoirs with high degree of heterogeneity (uncertainty), must be made. By using such integrated workflows, mature and new field can be developed better. The workflow could be used as a reliable tool for improving the decision-making process.
There are multiple optimization techniques used in the industry for optimizing well placement (e.g. direct and gradient optimization). With the use of reservoir simulation case study, this paper aims to provide a comparative performance analysis of multiple optimization techniques. To make the evaluation stronger and more application to a real-world problem, the model selected for this study has a high degree of geological uncertainty and constraints for computation time, infrastructure and complexity to decide on optimal well placements.
Having a better understanding on the uncertainties in geology lead to more robust decisions in reservoir management. Right strategy especially helps in optimizing larger scale, million-cell model simulations enabling practical implementation of reservoir simulation coupled with optimization.
Optimum well placement in complex reservoirs requires a complete grasp of optimization methods, key factors and constraints but most importantly the effect of geological uncertainty. A lack of awareness of optimization algorithms and their applications by engineers is a drawback in this process. In addition, complete evaluation of geological uncertainty is another challenge. This study provides an understanding and clarification to serve as a guideline on optimization practices by outlining the significant components in the process.
Several studies have indicated polymer flooding to be an optimal enhanced oil recovery (EOR) strategy in fields with oil viscosities between 10 – 150 mPa.s. In the current oil price environment maximizing the output from exisiting fields, using the ideal EOR operation pertinent to each reservoir, is of increased importance. In addition, with almost half of the total global oil production for the coming decades projected to come from EOR operations, it is essential to select the right strategy for each field. For fields that have oil viscosities above 150 mPa.s, mobility ratio of the polymer containing injectant is an inhibiting factor to the polymers injectivity and pumping efficiency, and hence polymer flooding is not a viable EOR strategy in such fields.
Supramolecular systems are a viable alternative to conventional polymers used in polymer flooding, mainly due to their high resistance to temperature and salinity. A unique feature of these systems is its reversible viscosity, using which system viscosity can be adjusted from low values during injection to high values prior to oil contact within the reservoir. Supramolecular systems are highly resistant to degradation from shear and temperature due their inherent property of disassembling, when exposed to high shear and/or temperature, and re-assembling. This property is useful in restrictive environments such as flow through narrow channels, where supramolecular systems disassemble (molecular scission) and reassemble, thereby maintaining its molecular properties in a “self-healing” manner.
In this study, modeling and simulation of these “self-healing” supramolecular systems have been conducted to compare its displacement efficiency compared to conventional polymer systems. They have the potential to be applied to multiple types of reservoirs including those with thin layers and permafrost conditions. From the results of this study it is evident that supramolecular systems offer field operators considering polymer flooding a cost-effective, smarter and technologically feasible EOR strategy.
Reservoir wettability has direct impact on the relative movement of reservoir fluids and oil displacement efficiency by EOR techniques. The industry standard wettability laboratory techniques of Amott, USBM and modified Amott/USBM are very time demanding due to its complex experimental setup and procedure.
This paper describes the theory and experimental setup and procedure of a new wettability laboratory technique. Rise In Core, RIC, technique is based on a modified version of the Washburn Equation. The modified equation could be solved for the wettability contact angle by only substituting the slope of a fitted straight line of the square line of the square of core sample mass change with time, resulting from either water imbibition into oil saturated core sample, and.or vice versa. A constant of the equation, that is characteristic of the rock type, needs to be determined prior, however, by conducting an imbibition experiment of a reference liquid into air saturated twin core sample. The reference liquid completely wets the core sample with zero contact-angle.
The new technique was applied to measure the wettability of Berea sandstone core samples. The wettability of natural outcrop cores was found to be weakly water wet. Experiments conducted on neighboring samples, produced similar wettability result, indicating good repeatability. The applicability of the RIC in other wettability regions was also tested, resulting in repeated strong wetness for standards that were artificially treated to be either strongly water wet, and oil wet. The technique was also compared to the existing industry technique and proved to provide equivalent and more consistent wettability measurements for more than ten twins of carbonate core samples.
RIC technique is theoretically sound, and requires simple experimental setup and procedure. Moreover, it determines wettability in terms of contact angles rather than wettability index. It is more consistent and applicable to all wettability regions.
Ghedan, Shawkat G. (The Petroleum Institute) | Canbaz, Celal Hakan (The Petroleum Institute) | Boyd, Douglas A. (ZADCO Petroleum Co) | Mani, George M. (Core Laboratories) | Haggag, Marwan Khamis (ADCO Producing Co. Inc.)
The evaluation of the reservoir wettability is fundamental to the understanding of fluid flow in porous media. Wettability has direct impact on saturation end points and the shape of capillary pressure and relative permeability curves. This will, in turn, directly affect the relative movement of the reservoir fluids and eventually affect the displacement efficiency of oil by the different injected fluids. Having reliable wettability data deems very necessary for reliable predictions of expected oil
recoveries under different development options.
The Amott and the USBM tests are the most commonly used methods for quantifying reservoir wettability. Combination of the two methods is also in use. In addition to the elaborate experimental effort and time required for these methods, the USBM method does not recognize very strongly water or oil wet systems, while Amott method fails to distinguish between important degrees of strong water and oil-wetness.
This paper describes a new technique, the Rise in Core (RIC), wettability characterization method based on a modified form of the Washburn equation. It enables relatively quick, accurate measurements of wettability in terms of contact angle and not wettability index as the other methods do. The method is easy to use and requires no complex equipment. During the RIC experiments, core samples saturated with one reservoir fluid are subjected to imbibitions from a second reservoir fluid. As the imbibition process takes place, the core samples weight changes continuously due to adjustments in relative saturations of the two fluids. Monitoring the square of the core mass change with time using a high precision balance, the acquired data is analyzed with modified Washburn equation to determine the cores wettability.
For the sake of assurance, RIC wettability measurements were compared to ambient conditions modified Amott-USBM measurements for a thick limestone oil reservoir using core plug pairs from different heights above the free water level. The results compare well. The RIC technique proved to be much simpler to construct, much faster to perform and much easier to analyze and interpret than traditional methods. Moreover, the method gives the operator a chance to evaluate the uncertainty in the wettability data.
Wettability is the relative preference of a solid surface to be coated by a certain fluid in a system1. In a rock/oil/brine system, it is a measure of the preference that the rock surface has for either the oil or water2. When the rock is water-wet, there is a tendency for water to contact the majority of the rock surface. Similarly, in an oil-wet system, the rock is preferentially in contact with the oil; the location of the two fluids is reversed from the water-wet case, oil will contact the majority of the rock surface2. When the rock surface does not display a preference for oil or water contact, intermediate wettabiltiy exists. Cases where water coates the surface of small pores while oil coates the surface of large pores are fractional or mixed wet if continous paths of oil and water wet rock are present.