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This SPE Live focuses on stimulation practices used in Europe, North Africa, and the Middle East. The experts also discuss the potential proppant over-displacement in horizontal well fracturing in conventional tight reservoirs, the biggest challenges for speeding up stimulation of offshore wells, and recent activity in stimulation in the region. "What are your daily limits and limitations at home, at your workplace and on the way between?" With this leading question, Alison Isherwood (SPE London Section, Net Zero Committee) and Joschka Röth (SPE German Section, Gaia Regional Liaison for Europe) started their Gaia Workshop at the Novotel Budapest Danube Hotel in Budapest (Hungary) on 25th September 2021. The ultimate aim of the workshop: participants should be able to communicate confidently with everyone about sustainability and planetary limits.
Legends of Artificial Lift This year, the SPE Artificial Lift Conference and Exhibition–Americas will be held 23–25 August in Galveston, Texas, with the theme “Modern Artificial Lift–Adapting to a Changing Industry.” The event provides opportunities for technical professionals to gain insights into current trends and field experiences and explore innovative solutions. A special Legends of Artificial Lift Luncheon on 23 August will celebrate three individuals for their outstanding contributions to the technical knowledge in this field: Norman Hein Jr., Ken Nolen, and Gabor Takacs. Norman W. Hein Jr. Norman W. Hein Jr. has worked for 45 years in upstream production, his distinguished career spanning from research, development, and testing to ventures in production engineering, manufacturing, onshore and offshore project management, industry standardization, and the principles of artificial lift. Hein joined the industry in 1977 as a research scientist with Continental Oil Company, where he learned about oil and gas production materials, failures, fatigue, and offshore construction. He then worked for Conoco and later ConocoPhillips in various engineering positions. In 2010, he joined the sucker-rod division of Norris Production Solutions as director of research, development, engineering, and quality; later at CONSOL Energy he was promoted to chief technology professional and senior advisor. Currently, Hein is president and managing director of Oil and Gas Optimization Specialists Ltd., which he established in 2003. Kenneth B. (Ken) Nolen Kenneth B. (Ken) Nolen for 62 years has been a key contributor to what he calls “the art and science of artificial lift.” “My college degree in mechanical engineering was largely devoted to science,” he explains, “and that’s a branch of knowledge dealing with the physical world of facts and principles. Art, on the other hand, uses science to create new technology and products—in my field, that is to enhance artificial lift.” His career in optimizing this art and science began after graduating from Texas A&M and serving his country in the US Air Force for a 3-year tour. Nolen joined Shell Oil Company as a production engineer before teaming up with Dr. Sam G. Gibbs to become co-founderand vice president of Nabla Corporation in Midland, Texas—a technical service company that specialized in artificial-lift diagnosis, optimization, design, training on pumping wells, and manufacturing pumpoff controllers and fluid-level sounders. “It was at Nabla that I pursued my long-held passion for optimizing production from artificially lifted wells.” Gabor Takacs Gabor Takacs joins the Legends of Artificial Lift as an internationally recognized consultant with more than 35 years of consulting and teaching experience in the fields of production engineering, with a concentration in artificial lift. “The great honor of being nominated is an absolutely thrilling sensation for me,” he said. “It gives me a special satisfaction to be the first foreigner to join those wonderful people whom I have been privileged to meet and cooperate with during my career.” Takacs is a professor emeritus at the University of Miskolc, Hungary, where he led the petroleum engineering department from 1995 to 2012.
Ali Akbar, Muhammad Nur (MOL Hungary) | Nemes, István (MOL Hungary) | Bihari, Zsolt (MOL Hungary) | Soltész, Helga (MOL Hungary) | Bárány, Ágnes (MOL Hungary) | Tóth, László (MOL Hungary) | Borka, Szabolcs (MOL Hungary) | Ferincz, György (MOL Hungary)
Abstract An integrated technical study was conducted for a field development project in West-Hungary. This study offers a better solution for estimating petrophysical properties and fracture facies vertically along the well and laterally for 3D static and dynamic models of naturally fractured reservoirs in carbonate rocks. More than 30 wells with 40 years of production history were used in order to build reliable static and dynamic models. The fracture class/facies plays essential role in spatial distribution of petrophysical properties during 3D reservoir modeling. It was defined by integrating the conventional logs, image logs, drilling parameters, and production or well test data. Three fracture facies are defined as macro-fracture (including permeable sub-seismic fault), micro-fracture, and hostrock. Subsequently the fracture-class's spatial distribution is guided by seismic attributes of faultlikelihood combined with geological concept of fault and damage zone. As a result, the established fracture classes along the wells are validated by static and dynamic subsurface data. Spherical self-organizing map (SOM) was also implemented for predicting the fracture location in wells having limited subsurface data. Moreover, fracture lateral distribution follows the distribution of the fault zone of fault core, high-damage zone, low-damage zone, and host-rock. The higher the fault displacement the wider the damage zone and fault core formed. Macrofractures and micro-fractures frequently appear around fault core and high damage zone. While only microfractures are dominantly present in the low damaged zones. In contrast, the unfractured class is dominantly distributed in host rock area. Also, the lithologis considered in distributing the fracture class because the rock mechanic properties and number of fractures are strongly controlled by rock compositions. Once the fracture class is distributed, porosity, permeability, and water saturation are modelled in the 3D geocellular model. Finally, this fracture class also plays a role as a rock typing for reservoir simulation. The saturation height model is built using the fracture class distribution resulting the initialization, history matching process, and production forecast from 20 wells are showing excellent quality. As a novelty, this study offers a better understanding of fracture distribution and accelerates the history matching process with a more confident result of production forecast. In the absence of advanced technologies like image logs and production logging (PLT) measurements, this study still effectively assists us to recognize the fracture presence and its quality in both well-depth interval and 3D spatial space, and successfully guided us in proposing a new infill drilling with strong confidence and delivering on the high-end of expected results.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 206027, “Naturally Fractured Basement Reservoir Characterization in a Mature Field,” by Muhammad Nur Ali Akbar, MOL Hungary. The paper has not been peer reviewed. The complete paper describes an alternative solution for identifying the presence of natural fractures, classifying them into fracture-quality-related ﬂowability, and distributing them vertically within the well interval, and proposes a lateral distribution method for reservoir modeling. The proposed approach, using the machine-learning technique of self-organizing-map (SOM) clustering, eﬀectively assists recognition of fracture presence and quality along the well-depth interval. Field Overview and Data Used The case study was conducted in an oil ﬁeld discovered in the early 1980s in southwestern Hungary. Thirty-six wells penetrated the naturally fractured carbonate in the Triassic formation. The main lithology of this reservoir is limestone and dolomite associated with faults and exhumation breccia and marl/shale. The reservoir is saturated oil (with gas cap) with unlimited aquifer (strong water drive). The gas cap, however, is mainly composed of 85% carbon dioxide and up to 1,800 ppm of hydrogen sulﬁde. Generally, the oil is intermediate to heavy, with a gravity of approximately 20 °API. The reservoir rock properties of this case study are fully complex for both the pore system and its composition. In general, the matrix pore system does not signiﬁcantly contribute to storativity or permeability. The eﬀective porosity is approximately 4.2% on average. This value sometimes directs to the matrix porosity, but in this case study, high intensity of the microfracture presence behaves in a way similar to matrix porosity, a phenomenon the author terms “pseudomatrix porosity.” Moreover, the eﬀective oil permeability value of the studied fractured reservoir is extremely high (up to 70 darcies per well-test interpretation). The permeability ranges from 1 to 2000 md in brecciated fractures or in naturally fractured rock samples. Two types of core samples were used in this study—fractured breccia and naturally fractured rock. Both types have similar behavior in terms of the porosity/permeability relationship. In this study, that relationship is not the one normally observed in clastic reservoir rock. Marl/shale content is one of the more- critical parameters, indicating low fracture quality in terms of permeability. More than 50% of the well-log data for this study were measured by Russian-type well logs, meaning that only simple electrical, gamma ray, and neutron- capture gamma logs were available. Other wells have standard triple-quad combination logs. Image logs are available only from two wells drilled in the 2000s. By considering these log-data limitations, cores, and production-test results, the study aimed to deﬁne the eﬀective fracture locations and intervals.
The complete paper describes an alternative solution for identifying the presence of natural fractures, classifying them into fracture-quality-related flowability, and distributing them vertically within the well interval, and proposes a lateral distribution method for reservoir modeling. The proposed approach, using the machine-learning technique of self-organizing-map (SOM) clustering, effectively assists recognition of fracture presence and quality along the well-depth interval. The case study was conducted in an oil field discovered in the early 1980s in southwestern Hungary. Thirty-six wells penetrated the naturally fractured carbonate in the Triassic formation. The main lithology of this reservoir is limestone and dolomite associated with faults and exhumation breccia and marl/shale.
"What are your daily limits and limitations at home, at your workplace and on the way between?" With this leading question, Alison Isherwood (SPE London Section, Net Zero Committee) and Joschka Röth (SPE German Section, Gaia Regional Liaison for Europe) started their Gaia Workshop at the Novotel Budapest Danube Hotel in Budapest (Hungary) on 25th September 2021. The ultimate aim of the workshop: participants should be able to communicate confidently with everyone about sustainability and planetary limits. Most of the mentioned concepts on the left side are representing resources and most terms on the right side are related to individual behavior and budgeting of resources. Joschka continued to describe the concept of Gaia, which originates in the ancient Greek primordial goddess (Gaia Mother of all life / Earth), developed to the Gaia Hypothesis (Earth synergistic and self-regulating, complex system) and today – from SPE's perspective – represents the dramatic tension created between the parts of the earth's system: human life on the surface that depends upon high intensity sub-surface energy resources.
Hydraulic proppant fracturing is an effective tool in mature, low-permeability reservoirs found in the Pannonian Basin. Fracture-geometry-control (FGC) techniques limit increases in water cut. The complete paper describes the first implementation of a solution to control fracture height for conventional wells in the Pannonian Basin.
Brian Sullivan, SPE, joined IPIECA as executive director in 2011 following a 23-year career with BP. He graduated in metallurgy and materials science from Imperial College, London, and was recruited into BP’s Refining and Marketing international graduate program in 1986. Sullivan’s career with BP included assignments in London, Copenhagen, Budapest, Athens, and Johannesburg and business experience in more than 60 countries. During his time with BP, he has had a varied career of technical, commercial, financial, and leadership roles across the downstream value chain including crude and products trading, marine fuels, lubricants, and alternative energy.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 200588, “Fracturing With Height Control Extends the Life of Mature Reservoirs: Case Studies From the Pannonian Basin,” by Ruslan Malon, SPE, Independent, and Jonathan Abbott, SPE, and Ludmila Belyakova, SPE, Schlumberger, et al., prepared for the 2020 SPE Europec featured at the 82nd EAGE Conference and Exhibition, originally scheduled to be held in Amsterdam, 1-3 December. The paper has not been peer reviewed. Hydraulic proppant fracturing is an effective tool in mature, low-permeability reservoirs found in the Pannonian Basin. However, for wells already producing with high water cut, even a small fracture extension into a water-bearing zone offsets the gains in hydrocarbon production. Fracture-geometry-control (FGC) techniques limit increases in water cut. The complete paper describes the first implementation of a solution to control fracture height for conventional wells in the Pannonian Basin. An integrated engineering approach was applied, including a new proppant-transport model to predict fracture geometry improvement using the FGC solution. Decreased Recovery in A and B Fields Oilfield A began producing in 1984. In addition to an interruption by the war in Yugoslavia in the 1990s, production has been in decline, and most wells are at risk of being shut in because of low production rates. During the last 10 years, propped fracturing was integrated into the production strategy for this mature field. Field A comprises Lower Pontian (Miocene) sandstones. Another sandstone formation exists between 5 and 15 m below the production target reservoir, with high water saturation as confirmed by log analysis and well testing. The proximity of the oil target to the water-bearing interval still presents a risk to production considering that hydraulic fracturing is required to extend field life. An impermeable shale streak that may act as a geomechanical barrier exists below the target formation. With a lower risk of fracture propagation into the water zone, Field A was one of the first candidate fields for propped fracturing and was later considered for advanced fracture-height-control techniques to prevent the increase of water cut after stimulation. Hydraulic fracturing would not be trialed in Field B—the characteristics of which are provided in the complete paper—until the advanced height-control techniques had been proved on the basis of experience with Field A. Oilfield A: Early Fracturing Results Early campaigns proved the economic feasibility of propped fracturing, resulting in a 2.1-fold average increase in oil production during the first 6 months of production. Unfortunately, production after this early period declined rapidly. Increases in water cut, seen in several fracturing campaigns, clearly were related to hydraulic fracture growth. Although the resulting uplift in oil production warranted continued fracturing, avoiding water was a key issue to address before expansion of propped fracturing further in this field and to other fields with an even higher risk of water.
Understanding of formation damage is a key theme in a waterflood project. An integrated multidisciplinary approach is required to determine an optimal design and strategy. An operator has developed a suite of tools to tackle these issues and help in adequate design and optimization of waterfloods. Many waterfloods in the operating phase do not perform as expected. Often this is because of well-injectivity issues where the required water quality for the injected water is either not properly defined (i.e., by the subsurface disciplines) or not properly managed (i.e., at the surface facilities).