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Bertarelli, Mario (Repsol) | Duran, Romulo (Repsol) | Tocantins, João Pedro (Schlumberger) | Mendoza, Diego (Schlumberger) | Bijai, Rahul (Schlumberger) | Trunk, Philip (Schlumberger) | Villegas, Cesar (Schlumberger) | Ramos, Aldo (Schlumberger)
As part of an exploration campaign in the Sub Andean region in Bolivia, Repsol faced a unique challenge to reduce well construction costs while drilling through harsh and abrasive Caipipendi Block formations. The Caipipendi Block poses several drilling challenges that often lead to premature bit and underreamer cutting structure damage. Two main points were targeted as fundamental to accomplish this objective: reduce the number of runs to drill the Carboniferous section and improve borehole enlargement efficiency. A multidisciplinary group comprising a service company and Repsol team members conducted a detailed and thorough investigation of previous failure modes to identify an integrated approach to improve the performance. Along with offset history, the team was able to identify lithology characteristics to accurately diagnose the underlying root causes. To tackle the hard and abrasive Upper Carboniferous section, a customized polycrystalline diamond compact (PDC) drill bit was equipped with 3-D cutter (3DC) technology and powered by a combination of an enhanced power section and a robust rotary steerable system (RSS) tool with a new specific steering pad feature. A new reamer concept was also applied in this well to mitigate the anticipated drilling shock and vibration associated with underreaming through the challenging strata—without compromising drilling efficiency. To achieve the desired performance goals, 3DC elements were applied to the drill bit, along with a robust RSS designed with a pioneering steering pad developed to sustain performance in high levels of formation abrasiveness. To increase borehole enlargement efficiency in the Devonian section, a new cutter block was designed. An advanced 4D transient drillstring dynamics modeling package was used to analyze failure modes, design the reamer and drill bit cutting structures, predict the drilling dynamics of drill bit and reamer, and recommend drilling parameters for the run. The objective was successfully achieved where Repsol was able to set a new benchmark for the block, drilling the programmed depth of the well in 350 days, 17% less than AFE curve and 25% less compared with the best result in the block even with a significant change in lithology sequence from the program. The innovative 3DC technology boosted overall drilling performance. The new PowerDrive* rotary steerable system pads enabled the customized drill bit to drill farther and avoid unexpected bottomhole assembly (BHA) trips. The use of a new cutter block equipped with 3DC technology enhanced stability and reduced lateral displacement and vibration.
Paronish, T. J. (National Energy Technology Laboratory / Leidos Research Support Team) | Toth, R. (West Virginia University) | Carr, T. R. (West Virginia University) | Agrawal, V. (West Virginia University) | Crandall, D. (National Energy Technology Laboratory) | Moore, J. (National Energy Technology Laboratory / Leidos Research Support Team)
The Marcellus Shale Energy and Environmental Laboratory (MSEEL) consists of two project areas within the dry gas producing region of the Marcellus shale play in Monongalia County, West Virginia. MSEEL is a collaborative field project led by West Virginia University, with Northeast Natural Energy LLC, several industrial partners, and sponsored by the US Department of Energy National Energy Technology Laboratory. The study areas are drilled approximately 8.5 miles apart to better understand the vertical and lateral changes in stratigraphy over a short distance. Two vertical pilot wells, MIP-3H and Boggess 17H were drilled in the fall of 2015 and spring of 2019, respectively. Core was recovered from the MIP-3H (API: 47-061-01707-00-00) 112 feet (34m) between depths of 7445 to 7557 feet, and from the Boggess 17H (API: 47-061-01812-00-00) 139 feet (42m) between depths of 7908 and 8012 ft. A full suite of triple combo (gamma ray, neutron, density logs), image logs, and advanced logging tools were run in both wells and calibrated to core analysis. Core analysis includes medical computed tomography (CT) scans, mineralogy and chemostratigraphy determined from handheld X-Ray fluorescence (hhXRF) and X-Ray powder diffraction (XRD) measurements, and determination of total organic content (TOC).
Lithofacies were determined at core-scale using traditional core description techniques and medical CT-scan images. Log-scale facies are based on mineralogy and TOC data and developed using petrophysical logging data calibrated to core data (XRD and pyrolysis data). Chemostratigraphic analysis utilized hhXRF data to determine the major and trace element trends in the cores.
In the two wells six shale lithofacies were recognized at the core and log scale. Both wells show organic-rich facies (TOC > 6.5%) primarily in the middle and lower Marcellus, with a slight decrease in thickness of this interval in the Boggess 17H. This interval is interpreted as an increase in paleo-productivity (increased Ni, Zn, and V), decreased sedimentation (decreased detrital proxies), and anoxic to euxinic conditions (increased Mo and chalcophile elements). Paleo-redox conditions in both wells are dynamic throughout deposition transitioning between euxinic/anoxic to dysoxic/oxic. This trend is seen through elemental proxies and calcite/pyrite concretion distributions.
The application of crushed rock analysis for unconventional formation evaluation has become standard in core analysis following its introduction for shale gas volumetrics by Luffel and Guidry (1992). Crushing is used to expedite the extraction, drying, and volumetric measurement processes. Critical assumptions of crushed rock analysis include: all pore space is interconnected, crushing should not create entry into any pores that previously were isolated, and the crushed particles are orders of magnitude larger than the representative pore space. The analytical procedures were established to provide reservoir rock and fluid properties, for which log interpretation methods could be developed to match the core and production results.
This study expands on the effect of crushing on core samples beyond the original Devonian shale scope of the Gas Research Institute, GRI, program. Mercury injection capillary pressure (MICP) measurements are incorporated to quantify volumetric and textural changes to the rock fabric from the crushing process. Changes in sample compressibility are also investigated to account for the removal of residual, low compressibility fluids. The objective is to understand potential fundamental changes to the rock to reconcile the crushed, cleaned ambient condition with stressed, subsurface conditions.
Fourteen core samples, at an average frequency of 18’, are selected to represent a variety of lithologies across a 200’ interval of the Wolfcamp A in the Delaware Basin. Each sample was split into three subsamples: one subsample remained intact, one subsample is coarsely crushed to +50-mesh, and the last is crushed and sieved to -20+35-mesh fraction to replicate the particle size common for many crushed rock protocols (Luffel, 1992). All subsamples were cleaned using a sequence of organic solvents and dried at 60°C to remove residual free fluid and interstitial clay bound water (Burger, 2014).
Certain facies showed a higher likelihood for pore alteration with dominant micro-scale pore features flattening, shifting, or re-distributing following the crushing and cleaning process. Mudstone samples experienced increases in compressible pore volume after crushing and extraction as total porosity converged towards GRI helium porosity. The results of this study provide characterization of the connected, effective pore volume using compressibility concepts and comparison to residual fluid volumes. The decision to crush, and the degree of crushing if so, should consider the representative pore sizes of each facies.
This paper was prepared for presentation at the Unconventional Resources Technology Conference held in Austin, Texas, USA, 20-22 July 2020. The URTeC Technical Program Committee accepted this presentation on the basis of information contained in an abstract submitted by the author(s). The contents of this paper have not been reviewed by URTeC and URTeC does not warrant the accuracy, reliability, or timeliness of any information herein. All information is the responsibility of, and, is subject to corrections by the author(s). Any person or entity that relies on any information obtained from this paper does so at their own risk. The information herein does not necessarily reflect any position of URTeC. Any reproduction, distribution, or storage of any part of this paper by anyone other than the author without the written consent of URTeC is prohibited. Abstract The publicly available multi-terabyte dataset of the Marcellus Shale Energy and Environmental Lab (MSEEL) consortium provides a unique opportunity to develop fracture models and analyze the effectiveness of the stimulation of a reservoir on a consistent base. Sonic, microresistivity image and production logs, microseismic data, and raw fiber optic measurements are examples of such data. Abundant core samples supplied demonstrate reservoir complexity and high density of natural fractures. The planar fracture model allows us to compare and contrast multiple stimulation strategies and propose engineered completions that cannot be done solely by data-driven approaches. Conclusions about stage spacing, stimulation design, wellbore placement, and stage isolation are shared. The workflow will be detailed to allow others to use, verify, and critique our findings using the same initial data.
The continuous demand for energy and advancement in technology has accelerated the research in the areas of unconventional petroleum resources. The Devonian Three Forks Formation consisting of carbonate and clastic sediments is an unconventional reservoir with about 3.73 billion barrels of technically recoverable oil. However, major gaps remain in the knowledge of how mineralogy, structures and fabrics within the various lithofacies have influenced the hydrocarbon storage and transport capacity. This work integrates petrographic (physical rock description, XRD bulk mineralogy and thin section) and petrophysical (Helium pycnometry and NMR) studies in characterizing the reservoir potentials of the Three Forks lithofacies. Physical core description and wireline logs were utilized to identify and correlate seven (7) lithofacies within the Three Forks Formation. They are: 1) green - grey massive mudstone; 2) tan massive dolostone; 3) grey - tan laminated mudstone and dolostone; 4) tan - dark brown mottled dolostone; 5) grey and tan mottled mudstone; 6) grey and tan mudstone conglomerates; and 7) grey and tan brecciated mudstone. Diverse pore types were identified within various lithofacies, with microporosity pores dominating the mudstone rich lithofacies and interparticle pores dominating the dolostone rich lithofacies. Preliminary results showed the dolostone lithofacies have relatively lower total porosities while the mudstone lithofacies have relatively higher total porosity values.
Mackey, Justin (LRST / National Energy Technology Laboratory) | Gardiner, James (LRST / National Energy Technology Laboratory) | Lackey, Greg (LRST / National Energy Technology Laboratory) | Kutchko, Barbara (National Energy Technology Laboratory) | Hakala, J. Alexandra (National Energy Technology Laboratory)
Chemical profiles of produced water submitted to the Pennsylvania Department of Environmental Protection (PA DEP) in residual waste reports often remain unused after submission. However, these data are valuable and can potentially be used to recognize or predict changes in reservoir properties, cross-formational flow, mineral scale formation, and permeability. In this study, we use computer science (data mining and analytics) techniques to extract data from produced water chemical assay reports submitted to the PA DEP. Geochemical modeling techniques are applied to create a high resolution (well-pad scale) spatio-temporal snapshot of changes in mineral saturation indices of produced water within the northeast and southwest production regions of the Marcellus Shale in Pennsylvania over a 5-year timespan (2012-2017). This approach combines multidisciplinary faculties in computer science and geoscience to generate valuable insight for stakeholders from publicly available, though disparate data sources.
The Marcellus Formation is a prolific natural gas field that lies underneath significant portions of Pennsylvania, West Virginia, New York, and Ohio. In Pennsylvania, natural gas is produced from the shale members of the Marcellus in a number of counties. However, the majority of production (by volume) occurs in northeast (NE) and southwest (SW) sections of the state. The formation is a black, organic-rich shale with a varying carbonate composition (de Witt et al., 1993; Werne et al. 2002; Lash, 2008). Organic material and carbonate content, along with other geologic characteristics, vary spatially between NE and SW regions of Pennsylvania (Carter et al., 2013). These regional geologic characteristics as well as differing post-depositional histories result in varying produced water characteristics (Barbot et al., 2013).
Heterogeneity in production water composition could exert a spatial control on production challenges experienced by operators. Specifically, regional variations in analyte concentrations could increase the frequency of mineral scale occurrence at certain well pad locations. Additionally, temporal variations in produced water chemistry could suggest different water-rock reactions occurring in the subsurface. These can include reactions related to well completion or stimulation techniques. For example, temporal variations in produced water composition could be the result of a fracture extending outside of its intended target zone. Another potential issue is cross-formational flow, which can happen after periods of extended production lower pressure in the targeted reservoir. Dilution effects observed in the produced water of a nearby pre-existing well could also suggest a parent-child relationship, where newer wells negatively impact production in existing wells. Likewise, production water reuse can pose issues as well when these fluids are combined with other incompatible fluids, such as produced water from another region or oxygenated surface waters. These phenomena combined with pressure changes within the reservoir are often related to mineral scale occurrence that can impede production from a well.
The Middle Devonian Marcellus shale play has emerged as a major world-class hydrocarbon accumulation and represents one of the largest and most prolific shale plays in the world. According to many outcrop studies in the region, natural fractures are well developed in the Marcellus Shale. However, evaluating fractures in the subsurface is often a significant challenge due to a lack of sufficient data. Therefore, in the Marcellus Shale Energy and Environment Laboratory (MSEEL) consortium project, significant efforts have been made to acquire high-quality image logs in the Marcellus laterals. The project provided tremendous opportunities to characterize the natural fractures and sub-seismic faults and to evaluate their impact on well stimulation.
In this study, about 70,000 ft of acquired high-resolution logging while drilling (LWD) acoustic images from five long laterals located in Monongalia County, West Virginia, were processed and interpreted. In addition, the study used high-quality micro-resistivity images from a pilot well, allowing the evaluation of natural fractures in the entire Marcellus vertical sequence. Based on the available acoustic images, the natural fractures were classified into three basic categories: high-amplitude fractures, low-amplitude fractures, and faults. Further, larger open fractures can also be determined when a low-amplitude fracture is evident on caliper images. The fractures in the Marcellus usually have a medium to high angle dip; however, multiple fracture sets in terms of strike orientation were clearly observed in all the laterals. The fracture set with a strike at NE-SW (or 60-240 deg) seems to be the predominant one in all the wells. A few other sets, including those with N-S, NWW-SEE, and E-W strikes, were also observed. Several sub-seismic faults, with mostly a low dip angle and a NE-SW strike, have also been seen in two of the laterals. The fracture density is variable across all the laterals, ranging from very low (or none) to very high (up to 5 fractures per ft). The average fracture density for all the laterals is about 1 fracture per 10 ft. In the vertical sequence, the natural fracture development showed a clear preference for shale or shaly facies over carbonate-rich or thin limestone layers. The interpreted fracture and fault data were used as input data for the stimulation design with the purpose of better understanding the fractures' impact on well stimulation. Production data from the laterals were also used to evaluate the natural fractures’ influence on well performance. The quality image database and the consistent interpretation results for the entire project enabled a systematic approach to characterizing fractures and, more importantly, to evaluating the impact of fractures on well stimulation and production.
Fedorovich, M. O. (A.A. Trofimuk Institute of Petroleum Geology and Geophysics, Siberian Branch of RAS) | Kosmacheva, A. Yu. (A.A. Trofimuk Institute of Petroleum Geology and Geophysics, Siberian Branch of RAS) | Pospeeva, N. V. (Siberian Research Institute of Geology, Geophysics and Mineral Resources)
The PDF file of this paper is in Russian.
The paper is aimed at the one-dimensional petroleum system modeling in a well section of the Tolonskoye gas-condensate field. Tectonically, it is confined to the Khapchagai megalithic bank located in the central part of the Vilyui hemisyneclise. The modeling identifies burial and thermal history of the sediments in the Paleozoic, Mesozoic and Cenozoic, quantitive evaluation of generation power and oil-window- and gas-window-entry time of the source rocks. According to the present research, the Kuonam source rock reached up to the oil window 449 Ma in the Katian age and gas window 410 Ma in the Pragian age. The Permian source rock top reached up to the oil window 249 Ma in the Olenekian age. The Permian source rock middle did to the gas window 258 Ma in the Wuchiapingian age. The Kuonam source rock had already been beyond the oil and gas windows by ending the sedimentation of the Nedzhelin and Monom seal rocks for the Upper Permian and Lower Triassic reservoirs. There was consequently no appropriate environment for the hydrocarbon accumulations generated by marine organic matter to be preserved. The Permian source rock top and middle are found to be in the oil and gas windows at the present time, respectively. The hydrocarbon accumulations principally generated by terrestrial organic matter can therefore be in the Upper Permian and Lower Triassic reservoirs. Maximum temperature values and rapid change in organic matter maturity in the Late Permian and Early Triassic imply trap rocks in the sediments. Generation power of the Kuonam source rock and Permian source rock bottom is completely exhausted. The Permian source rock top, by comparison, is of significant generation capability. The generation balance of the source rocks is 18.942 BT of hydrocarbons (hydrocarbon equivalent), with the Permian source rock contribution being essential. The remaining source rock potential is 5.187 BT of hydrocarbons (hydrocarbon equivalent). Complying with the initial commercial reserves of the Tolonskoye field the reservoir balance is up to 0.7 % in relation to the generation balance.
В статье рассмотрено одномерное моделирование нефтегазоносных систем в разрезе скважины Толонского газоконденсатного месторождения. Месторождение в тектоническом плане приуроченного к Хапчагайскому мегавалу, который осложняет центральную часть Вилюйской гемисинеклизы. Моделирование выполнялось с целью восстановления истории погружения и тепловой истории осадочных комплексов в палеозойское, мезозойское и кайнозойское время, количественной оценки генерационного потенциала нефтегазоматеринских толщ и определения времени их вхождения в главные зоны нефте- и газообразования. Установлено, что нефтегазоматеринские отложения куонамской формации вошли в главную зону нефтеобразования 449 млн лет назад в катийское время, в главную зону интенсивного газообразования – 410 млн лет назад в пражское время. Нефтегазоматеринские отложения перми кровлей вошли в главную зону нефтеобразования 249 млн лет назад в оленекское время, центральная часть нефтегазоматеринских отложений перми погрузилась в главную зону интенсивного газообразования 258 млн лет назад в вятское время. На конец формирования основных флюидоупоров, неджелинской и мономской свит, для залежей верхней перми и нижнего триаса нефтегазоматеринские отложения куонамской формации уже вышли из главных зон нефтеобразования и интенсивного газообразования, и залежи углеводородов, генерированные аквагенным органическим веществом, не сохранились. В настоящее время верхняя и центральная части нефтегазоматеринских отложений перми находятся в главных зонах нефтеобразования и интенсивного газообразования, и залежи углеводородов, генерированные преимущественно террагенным органическим веществом, могли накапливаться в резервуарах верхней перми и нижнего триаса. Максимальные температуры и скачок катагенетической преобразованности органического вещества, приуроченные к границе перми и триаса, свидетельствуют о наличии трапповых тел в разрезе осадочного бассейна. Нефтегазоматеринские отложения куонамской формации и породы в основании нефтегазоматеринских отложений перми полностью исчерпали свой нефтегазогенерационный потенциал, тогда как породы в кровле нефтегазоматеринских отложений перми обладают значительными генерационными возможностями. Общее количество генерированных углеводородов составляет 18,942 млрд т условных углеводородов, подавляющая часть которых образована породами нефтегазоматеринских отложений перми. Нереализованный углеводородный потенциал нефтегазоматеринских отложений перми составляет 5,187 млрд т условных углеводородов. Количество аккумулированных углеводородов в ловушках достигает 0,7 % генерированных, что соответствует начальным запасам углеводородов промышленных категорий в пределах Толонского месторождения.
Neudachin, N. A. (RN-BashNIPIneft LLC, RF, Ufa) | Khannanova, G. R. (RN-BashNIPIneft LLC, RF, Ufa) | Mironov, R. V. (RN-BashNIPIneft LLC, RF, Ufa) | Lukanova, P. A. (RN-BashNIPIneft LLC, RF, Ufa) | Vakilova, A. Z. (RN-BashNIPIneft LLC, RF, Ufa)
The PDF file of this paper is in Russian.
The majority of oil fields discovered in carbonates reservoirs are controlled by single and barrier organic buildups located in starved basins. Within the Republic of Bashkortostan new highly promising exploration areas can be identified through the study and analysis of trends and patterns in the development of reefs. Reefs and bioherms tend to both accumulate oil and gas and form draping structures for trapping hydrocarbons in the overlying deposits. Currently such build-ups are underexplored. In the case of 2D seismic lines are usually too sparse for identification and mapping of all such features hence additional thorough investigation of the regional geology is required before an exploration program can be formed with new recommendations. The study presents the updated conceptual depositional model of the Late Frasnian to the Late Tournaisian. The analysis reveals the causes of carbonate sedimentation and formation of build-ups as well as trends in their development. The distribution of oil deposits controlled by organogenic buildups has been analyzed. Within the South-Tatar and Bashkir uplifts patterns of the distribution of organic buildups are noted. An analysis of the conditions of sedimentary cover formation in the Late Devonian era allowed us to determine the area of mass distribution of reefs and bioherms, as well as to identify unfavorable zones for the existence of carbonate buildups. The understanding of the patterns in the regional development of carbonate build-ups over time, their correlation with reservoirs and seals is useful in identification of new licensing and seismic exploration opportunities. It is also important while choosing oil deposits for drilling and refilling the hydrocarbon resource base.
Большая часть залежей в карбонатных коллекторах нефтяных месторождений контролируется одиночными и барьерными органогенными постройками, приуроченными к бассейнам некомпенсированного осадконакопления. В пределах Республики Башкортостан изучение закономерностей и прогноз распределения рифов являются актуальными задачами для определения новых направлений нефтепоисковых работ. Рифы и биогермы контролируют формирование залежей как в самом карбонатном комплексе, так и в структурах их облекания. Кроме того, такие постройки являются в настоящее время недоизученными. При проведении сейсморазведочных работ 2D методом общей глубинной точки (МОГТ) плотность профилей является недостаточной для выявления всех органогенных построек. В связи с этим необходимо детальное геологическое изучение региона с целью выдачи рекомендаций на постановку дальнейших геолого-разведочных работ. В статье актуализирована принципиальная модель осадконакопления с конца франского по конец турнейского веков. Уточнены причины формирования органогенных построек и закономерности их распространения. Проведен анализ распределения залежей, которые контролируются рифами и биогермами. В пределах Южно-Татарского и Башкирского сводов отмечены закономерности распределения органогенных построек. Анализ условий формирования осадочного чехла в позднедевонскую эпоху позволил определить области массового распространения рифов и биогермов, а также выделить неблагоприятные зоны для существования карбонатных построек. Изучение развития органогенных построек во времени и в пространстве, их взаимосвязи с положением коллекторов и пород-флюидоупоров позволит определить наиболее перспективные области для лицензирования, проведения сейсморазведочных работ, поиска залежей нефти, выбора структур для бурения и пополнения ресурсной базы углеводородов.
Mahmoud, Ahmed Abdulhamid (King Fahd University of Petroleum & Minerals) | Elkatatny, Salaheldin (King Fahd University of Petroleum & Minerals) | Ali, Abdulwahab (King Fahd University of Petroleum & Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum & Minerals) | Abouelresh, Mohamed (King Fahd University of Petroleum & Minerals)
Total organic carbon (TOC) is an important factor for the characterization of unconventional shale resources; which is currently evaluated by either conducting extensive laboratory work, using empirical correlations developed based on linear regression analysis, or applying artificial intelligence (AI) techniques. The AI models approved their efficiency for TOC estimation compared to the use or empirical correlation and they have the advantage of providing a continuous TOC profile compared to the laboratory-based evaluation.
This study is aimed to evaluate the predictability of the TOC using two AI models namely functional neural networks (FNN) and support vector machine (SVM). The AI models were trained to estimate the TOC based on well log data of gamma ray, deep resistivity, sonic transit time, and bulk formation density, more than 500 datasets of the well logs and their corresponding core-derived TOC collected from Barnett shale were used to train and optimize the AI models. The predictability of the optimized AI models was then tested on other data from Barnett shale and validated on unseen data from Devonian shale. The ability of the optimized AI models to estimation the TOC for Devonian shale was compared with Wang's density-based correlation (WDC) which was developed recently to estimate the TOC for Devonian formation.
The results showed that the AI models predicted the TOC with high accuracy, and they overperformed WDC in estimating the TOC for Devonian formation. For the validation data, FNN model overperformed SVM in estimating TOC with average absolute percentage error (AAPE) of 12.0% and correlation coefficient (R) of 0.88, while SVM model predicted the TOC with AAPE and R of 14.5% and 0.86, respectively, and WDC estimated the TOC with high AAPE of 34.6% and low R of 0.61.