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Shale asset investment decisions are difficult to model because they are portfolios of options under complex and time-evolving uncertainties. Sequential development decisions must balance short-term cash flow with long-term value creation. Typical assets consist of thousands of locations, making exact analysis impossible. Consequently, most decision-support tools are deterministic, or rely on simplified problem structures that significantly distort the decisions facing companies. In this paper, we present a new decision-support tool that improves decision quality by accounting for the full decision structure under uncertainty.
Take Back Control of Your Capital Project with an EPC 4.0 Strategy Stratigraphical - Sedimentological Framework For The Thamama Group Development In The Western Uae Based On The Legacy Core Data: How The Key To The Future Is Found In The Past. Performance Comparison Of Two Different In-house Built Virtual Metering Systems For Production Back Allocation. Innovation In A Time Of Crisis: How Can The Upstream Industry Develop New, Fit-for-purpose Technology? How To Meet Operational Challenges In An Extreme VUCA Environment By Adaptive Process Control. Challenges In Drilling & Completion Of Extended Reach Drilling Wells With Landing Point Departure More Than 10,000ft In Light/ Slim Casing Design.
The growth and evolution of offshore drilling units have gone from an experiment in the 1940s and 1950s with high hopes but unknown outcome to the extremely sophisticated, high-end technology and highly capable units of the 1990s and 2000s. In less than 50 years, the industry progressed from drilling in a few feet of water depth with untested equipment and procedures to the capability of drilling in more than 10,000 ft of water depth with well-conceived and highly complex units. These advances are a testament to the industry and its technical capabilities driven by the vision and courage of its engineers, crews, and management. From an all-American start to its present worldwide, multinational involvement, anyone involved can be proud to be called a "driller." Since the beginning in the mid-1800s until today, the drilling business commercially has been very cyclic. It has been and still is truly a roller-coaster ride, with rigs being built at premium prices in good economic times and ...
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 goal of this work is to present a new type of unconventional play (carrier bed/halo) that is developing in the Powder River basin. This play is being developed via the combined technologies of horizontal drilling and multistage hydraulic fracturing.
The Turner sandstones of Turonian age is a target of exploration and development in the Powder River basin. The sandstones are interpreted to be marine shelf sands.
The Turner Sandstone is a prolific reservoir in the Crossbow area of the Powder River Basin. The area is being developed with horizontal wells at vertical depths of 9400 to 12000 feet. Initial production from horizontal wells ranges from 500 to 1700 BOPD and 1000 to 4000 MCFGPD. The carrier bed (halo) play is downdip and an extension from older vertical Turner production in the School Creek, Porcupine, and Tuit Draw fields. The Crossbow area is overpressured with no known water contacts (updip or downdip). The Crossbow area includes the Crossbow, K bar, Mary Draw and Horse Creek fields which have now merged into a larger producing area.
Source beds for the Turner Sandstone include the overlying Niobrara, and Sage Breaks shales and underlying Mowry, Belle Fourche, Greenhorn, and Poole Creek shales. Source bed maturity occurs in the deeper part of the basins. Oil and gas migration into the carrier beds results in regional pervasive hydrocarbon saturation. Discrete traps that have been previously developed are part of a more extensive hydrocarbon system and ultimately may merge into an extremely large area of continuous production.
The Powder River Basin is one of the most prolific hydrocarbons producing basins in the Rocky Mountain Region. Cretaceous producing formations include the Dakota, Muddy (Newcastle), Turner, Frontier, Niobrara, Shannon, Sussex, and Parkman. Permian age Minnelusa sandstones are also productive in the northern Powder River Basin. Recent horizontal drilling activity is targeting the Mowry, Frontier, Turner, Niobrara, Sussex, Shannon, and Parkman.
The PDF file of this paper is in Russian.
In 2019, RN-Shelf-Arctic LLC, a subsidiary of Rosneft Oil Company, carried out a regional project on Cretaceous deposits (structural and depositional environment reconstruction) in the Russian territory of the Barents Sea in order to explore new potential objects and increase the resource base at Rosneft. The algorithm of the studies included the interpretation of seismic data, the analysis of well data and outcrops of the islands within the Barents Sea, the identification of typical seismic facies and their depositional interpretation, the choice of palaeoenvironmental reconstruction intervals, the analysis of thickness and seismic facies maps and finally, facies-palaeogeographic reconstructions. Sequence stratigraphy was used as the main interpretation method. Thus sequence boundaries and maximum flooding surfaces were justified and correlated as a chronostratigraphic framework. As a result, seven sequences were identified in the Lower Cretaceous interval: five sequences in the Neocomian interval (approximately the third order) and 2 sequences in the Aptian-Albian interval (2 orders). Mapping was carried out at two levels: combined LST + TST and HST. One of the most interesting results of the study is the recognition and mapping of stepped-dipping steeply falling clinoform bodies associated with forced regression in three Neocomian sequences. These bodies were interpreted as deposits of deltas of shelf edges. According to the literature data, deposits of a similar genesis are characterized by a high content of sand material and have good reservoir properties. The results of this study can significantly reduce the risks associated with the reservoir properties for the objects within the zone of distribution of these deposits.
В 2019 г. в рамках регионального проекта дочернего общества компании ПАО «НК «Роснефть» ООО «РН-Шельф-Арктика» выполнялись работы по изучению геологического строения, условий формирования и фациальной диагностики меловых отложений российского сектора Баренцева моря с целью поиска в них новых перспективных объектов и наращивания ресурсной базы компании ПАО «НК «Роснефть». В статье рассмотрены результаты исследований, которые включали интерпретацию сейсмических данных, анализ материалов изучения разрезов скважин и обнажений островного обрамления Баренцева моря, выделение типовых сейсмофаций и их фациальную интерпретацию, выбор интервалов построения карт, анализ карт толщин и карт сейсмофаций и собственно, фациально-палеогеографические реконструкции. В качестве основного интерпретационного метода использовалась секвенсная стратиграфия, в качестве хроностратиграфического каркаса обосновывались и коррелировались границы секвенций и поверхности максимального затопления. В результате в изучаемом нижнемеловом интервале разреза выделены семь секвенций: пять из них (третьего порядка) в неокомской и две (второго порядка) в апт-альбской частях разреза. Картопостроение выполнялось по двум уровням: объединенному (нижний (LST) и трансгрессивный (TST) системные тракты) и верхнему (HST). Одним из наиболее интересных результатов работы является выделение в течение формирования нижних системных трактов трех секвенций эпизодов форсированной регрессии и связанных с ними ступенчато-погружающихся крутопадающих клиноформных тел. Эти тела по ряду ярких признаков интерпретированы как отложения дельт бровок шельфа. Отложения подобного генезиса отличаются высоким содержанием песчаного материала и представляют собой толщи-коллекторы с улучшенными фильтрационно-емкостными свойствами. Результаты исследования позволяют существенно снизить риски, связанные с выявлением коллекторов на объектах, расположенных в зонах распространения рассмотренных отложений.
Moharana, Abhishek (Schlumberger) | Mahapatra, Mahabir Prasad (Schlumberger) | Chakraborty, Subrata (Schlumberger) | Biswal, Debakanta (Adani Welspun Exploration Limited) | Havelia, Khushboo (Schlumberger)
Petroleum Geologists typically study hydrocarbon bearing reservoirs, understand the geology, and build numerical models to help better produce hydrocarbon. On the other hand, conventional sedimentologists try to simulate the natural process of sedimentation in laboratory through miniature sand box models to better understand such processes. But a proper integration of the laboratory-based techniques in developing subsurface reservoirs models was always lacking in the industry.
Petroleum geologists developed computer based geostatistical techniques based quantitative statistics like variograms, histograms to develop stochastic models of reservoirs which could be used to put a number and range on the geological uncertainty. However, geostatistics deals more with regularly sampled data, describing their spatial variability and directionality. In development oil fields with many wells sampling the reservoir, geostatistics helps us to create a more predictive subsurface reservoir model. However, in the exploratory state of a field with few drilled wells, the data for geostatistical analysis reduces and a robust conceptual geological is needed to build a predictive subsurface geological model where a proper integration of sedimentology and petroleum geology is required.
Different approaches like conceptual block diagrams of depositional models, average sand distribution maps, training images from present day analogs were tried. However, these were less than optimal, deterministic with a long turnaround time for any robust subsurface reservoir model.
A relatively recent addition to the geologist's set of quantitative tools has been Geologic Process Modeling (GPM), also known as Forward Stratigraphic Modeling (FSM) technique. This technique aims to digitally model the natural processes of erosion, transport and deposition of clastic sediments, as well as carbonate growth and redistribution based on quantitative deterministic physical principles (
In the current study a 3D reservoir model for a field in Western Offshore India was built based on the results of Geological Process Model (GPM) for the thin deltaic reservoir sands as understanding reservoir continuity from seismic data was not possible. With only 4 wells available in the field, traditional geostatistics based reservoir models were inadequate in explaining the reservoir distribution. GPM based techniques helped not only in mapping the reservoir continuity but also opened up new areas for exploration in the area.
Piane, Claudio Delle (CSIRO Energy, Perth, Australia) | Clennell, Ben (CSIRO Energy, Perth, Australia) | Josh, Matthew (CSIRO Energy, Perth, Australia) | Dewhurst, Dave (CSIRO Energy, Perth, Australia)
Recovery of hydrocarbons from organic-rich shales has played a significant role in changing the distribution of reserves worldwide and has also impacted on carbon dioxide emissions where extracted gas has been used to replace coal to power electricity grids. Such extraction is predicated on a good understanding of local and regional geological history as well as close examination of the rocks involved from seismic to nano-scale. This study looks at the impact of thermal maturity on the organic and diagenetic mineral fabrics observed in gas shales from different parts of the world, highlighting similarities and differences in their impacts on rock properties. Organic fabrics can present as pore filling migrated bitumen visualized in scanning and transmission elctron microsopy and the degree of thermal maturity directly impacts for example on the electrical properties, shown by contrasting examples from the Marcellus (ultra-high maturity) and Utica (moderately high maturity) shales; the former has extremely low resitivity while the latter extremely high. Dielectric properties are shown to be useful for rock typing in the Utica shale where standard resistivity logs are off the scale as the material is so resistive. Such properties have also been shown to be useful for estimating water saturation in the Roseneath-Epsilon-Murteree Formations of the Cooper Basin. Mineral diagenesis and its timing are also shown to be important for quartz cementation and pore structure modification in the Marcellus, Bongabinni and Goldwyer formations, with the latter two contrasted in terms of elastic and strength properties. Overall, micro-structural, laboratory and wireline log studies combined have given significant insights into the interplay between organic and diagenetic fabrics and resultant rock properties.
The West Delta Deep Marine concession (WDDM) lies offshore in the Deep water of the present day Nile delta. WDDM consists of many Pliocene submarine channel complexes. The Serpent field is one of those slope marine channels and consists of two separate channels namely channel 12 and channel 13. Channel 12 is divided into three compartments by gravitational faults and channel 13 is composed of two compartments separated by stratigraphic barrier. Gas water contact (GWC) in channelized turbidities reservoir might create an intricate reservoir relationship. Gas water contact becomes complicated when the faults and the facies lateral change provide seals. Those hydrocarbon contacts depths become unpredictable without a distinct system to understand the cause of those variable contacts. Water break-through occurred earlier than expected in Serpent production wells as there was no proper modeling for reservoir facies heterogeneity and facies associated petrophysical parameters. A further compartmentalization of channel 12 arose as the sealing capacity of the gravitational faults cast a doubt over channel-12 compartmentalization and the connected gas initial in place (GIIP). The geological foreknowledge of Serpent field, the production issues and the dire need for further development plans in Serpent field were the motives to initiate this study. Integrated study was designed to answer the unsolved challenges of characterizing the reservoir heterogeneity and faults' sealing capacity. 3-D (three dimensional) high quality seismic data and different seismic attributes were integrated with different well data to build a robust 3-D static model. Static model was the way to elaborate the facies accurate distribution and the different petrophysical parameters in Serpent reservoir. In addition, the 3-D static model was used in the prediction of the faults' sealing capacity through the fault rock facies, fault rock petrophysical properties and transmissibility. In a nutshell, the resultant static model answered the field's issues regarding the early water production, facies heterogeneity and Successfully isolate the different reservoir compartments then run into prediction to assess the potential of the existing well-stock and any future development plans in Serpent field.
Omotosho, Yetunde A. (Department of Petroleum Engineering, University of Ibadan) | Falode, Olugbenga A. (Department of Petroleum Engineering, University of Ibadan) | Ojo, Temilola I. (Covenant University, Canaanland, Otta)
Enhanced Oil Recovery (EOR) methods continue to be dominant in improving world’s oil reserves as producing fields mature. Global growth of 18% was recorded in proved reserves between 2007 and 2017 (BP Statistical Review, 2018), with North America, which has invested in several EOR techniques, contributing about 14% to this growth. This proves that EOR stands as a long-term solution to the menace of dwindling reserves. Recently, nanotechnology has been gaining attention for application in the petroleum industry. It has been established that nanoparticles dispersed in base fluids such as water, brine or certain organic solvents (nanofluid) exhibit some special properties proved to be advantageous for EOR purposes. Additional recovery of about 30% has been recorded. However, permeability damage, which has been widely reported, is yet to be critically studied and analysed.
The objective of this research was to investigate how two important properties; concentration and injection rate of the nanofluid, affect oil recovery, and as well establish the thresholds of conditions which lead to permeability impairment and injection fluid loss during nanoflooding with silica nanoparticles. The permeability impairment layer which is gradually formed at the rock pore surface is termed nanoskin (a concept introduced by the author).
Four core samples were flooded with brine followed by silica nanofluid of four different concentrations viz; 0.01, 0.5, 2.0 amd 3.0% wt/wt respectively. The flooding process was accompanied with changing injection rates viz; 0.5, 1.0, 2.0, 3.0 cm3/min.
The result indicated that concentration of 2.0% wt/wt and injection rate of 2.0 cm3/min were threshold levels that guaranteed optimal oil recovery from the Niger Delta core samples. The overall result demonstrates that nanoflooding is a viable EOR technique and establishes a combination of parameters that will minimize nanoskin formation during nano-EOR process.