Anderson, Iain (Heriot-Watt University) | Ma, Jingsheng (Heriot-Watt University) | Wu, Xiaoyang (British Geological Survey) | Stow, Dorrik (Heriot-Watt University) | Underhill, John R. (Heriot-Watt University)
This work forms part of a study addressing the multi-scale heterogeneous and anisotropic rock properties of the Lower Carboniferous (Mississippian) Bowland Shale; the UK's most prospective shale-gas play. The specific focus of this work is to determine the geomechanical variability within the Preese Hall exploration well and, following a consideration of structural features in the basin, to consider the optimal position of productive zones for hydraulic fracturing. Positioning long-reach horizontal wells is key to the economic extraction of gas, but their placement requires an accurate understanding of the local geology, stress regime and structure. This is of importance in the case of the Bowland Shale because of several syn- and post-depositional tectonic events that have resulted in multi-scale and anisotropic variations in rock properties. Seismic, well and core data from the UK's first dedicated shale-gas exploration programme in northwest England have all been utilized for this study. Our workflow involves; (1) summarizing the structural elements of the Bowland Basin and framing the challenges these may pose to shale-gas drilling; (2) making mineralogical and textural-based observations using cores and wireline logs to generate mineralogy logs and then to calculate a mineral-based brittleness index along the well; (3) developing a geomechanical model using slowness logs to determine the breakdown stress along the well; (4) placing horizontal wells guided by the mineral-based brittleness index and breakdown stress. Our interpretations demonstrate that the study area is affected by the buried extension of the Ribblesdale Fold Belt that causes structural complexity that may restrict whether long-reaching horizontal wells can be confidently drilled. However, given the thickness of the Bowland Shale, a strategy of production by multiple, stacked lateral wells has been proposed. The mineralogical and geomechanical modelling presented herein suggests that several sites retain favorable properties for hydraulic fracturing. Two landing zones within the Upper Bowland Shale alone are suggested based on this work, but further investigation is required to assess the impact of small-scale elastic property variations in the shale to assess potential for well interference and optimizing well placement.
The development of unconventional reservoirs require key decisions to be made under uncertainty. We regularly consider multiple variables, such as the number of wells to be placed in a section, their horizontal spacing and vertical staggering, the length and orientation of the laterals, the design of fracturing stages and associated perforations, the quantity and type of fracturing fluid and proppant to use, and geologic variability. These decisions are dependent on the subsurface parameters at each development due to the heterogeneities of rock and fluid properties as well as the nearby historical development. Such complex and dynamic problems combined with the fast pace and large scale of unconventional development pose a significant challenge for classical physics-based reservoir models. We propose a data-driven modeling methodology that is used to support development decisions in the STACK play in Oklahoma.
We utilize multi-variate analytics to model the behaviors of horizontal wells in the STACK (Sooner-Trend-Anadarko-Canadian-Kingfisher) of the Anadarko basin (see Fig. 1 for idealized geologic cross section). The STACK consists of two primary targets, the Meramec shale and the Woodford shale. The Mississippian age Meramec is 200-500’ thick with porosity ranging from 3-6%.The Mississippian/Devonian age Woodford ranges from 75-300’ thick with 3-7% porosity. The Meramec formation consists of several parasequences of fine-grained silts with significant carbonate input in some intervals. Our analysis includes over 500 horizontal wells that target the core intervals in the Meramec. We use these wells in our workflow that predict their production performance impact with respect to both the location of horizontal wells in the STACK trend and multiple engineering variables.
In unconventional resource plays, wells drilled and completed in the same area, within the same target and with the same completions can have results that vary by +/− 50% vs the mean. Without a predictive model to explain this variance, production variability looks like random noise. We chose to use a simple statistical technique called a hypothesis test, and interpret the result using a p-value, a measure of statistical significance. Using the p-value, a trend can be tested to see if the trend in a sample of data is statistically different than the trend that would be expected from a random sample. Several studies have been published on multivariate analytic workflows1,2,3,4.
The Devonian-Mississippian STACK/SCOOP Play of the Oklahoma Anadarko Basin is a complex assemblage of tight carbonate and siliciclastic strata and an important oil and gas province. In the last decade, prolific drilling has demonstrated significant heterogeneity in the composition of oils produced from STACK/SCOOP reservoirs. This study discusses possible geoscientific explanations for the heterogeneity observed in produced oils and describes how source, maturation, and migration affect their composition.
Geochemical data from 136 produced oils across 12 counties from 4 producing reservoirs is reviewed. Calculated thermal maturity (Rc%) from alkylated polyaromatic compounds shows excellent agreement with oil thermal maturity increasing with increased depth. Oils produced from overpressured reservoirs exhibit a strong relationship between Rc% and Gas-Oil Ratio (GOR), while normal- to underpressured reservoirs exhibit GORs up to an order of magnitude higher at similar Rc%. Light hydrocarbons show that paraffinicity varies starkly with producing reservoir, suggesting compositional fractionation from diffusive migration through tight and argillaceous strata. Conversely, aromaticity varies geographically by Play Region, indicative of changing depositional environments and organic input across the basin. Isoprenoid and sesquiterpane biomarkers indicate all oils are generated by Type II or Type II/III mixed organic matter, but Springer Group reservoirs are charged by a highly argillaceous, non-Woodford source.
The Anadarko Basin is the deepest sedimentary basin in the cratonic interior of the North America with as much as 40,000 feet of Paleozoic sediments (Johnson, 1989). The Anadarko is an asymmetric basin with the deepest sediments bound against the Amarillo-Wichita Uplift to the southwest. The basin is elongated along its west-northwest axis and bound by the Nemaha Ridge to the east and the Anadarko shelf to the west and north.
In the last decade, drilling of Devonian-Mississippian strata along the margins of the basin have delineated one the continent's most successful petroleum resource plays. These areas are colloquially referred to as the
This paper presents detailed lithofacies identification from the I-35 Sycamore outcrop and predicts the rock properties from wireline logs to propose landing zones within the Mississippian Sycamore rocks in Southern Oklahoma. To achieve these objectives, three types of studies were conducted: (a) field studies (b) lab analysis, and (c) machine learning. In field studies, we measured the complete 450 ft Sycamore stratigraphic section on the south limb of the Arbuckle Mountains along I-35, measured the outcrop gamma-ray profile, calculated the fracture intensity per bed and restored the fracture orientations to the horizontal bedding plane. The contacts with the underlying Woodford Shale and overlying Caney Shale were additionally examined. Lab studies included petrographic analyses, Scanning Electron Microscopy (SEM), Rock Eval Pyrolysis analyses, and X-ray Diffraction (XRD). For machine learning studies, principal component analysis (PCA), elbow method, and self-organizing map (SOM) were used to analyze the electrofacies from the outcrop and an uncored well.
As a result, it was found that the outcrop stratigraphy, lithofacies and electrofacies are tied with the hand-held gamma ray profile and correlated with a nearby subsurface well. Five major outcrop lithofacies are identified from wireline logs. Two fracture sets (N18E and N63W) were observed in the outcrop. Fracture intensity varied from 1.5 to 8 fractures per linear ft. Most fractures are filled with calcite, but some contain bitumen. The Rock Eval Pyrolysis analyses revealed that the I-35 Sycamore intervals are dominated by apparent type II and type III kerogen (oil prone and oil/gas prone) with an average Tmax of 440 °C. Total organic matter ranged from 0.1 to 1.5 wt % in the outcrop.
The reservoir quality was assessed by integrating lithofacies, fracture analyses, and geochemical analyses. The bioturbated shale and/or the sandy siltstone can be a potential target zone for the following reasons: the bioturbated shale is characterized by the highest fracture abundances (avg. 4.4 fractures per linear ft), and clay content is 35%, with 50% quartz, indicating a somewhat brittle rock, with a potential hydrocarbon migration, during production, from the underlying Woodford shale during hydraulic fracturing. The sandy siltstone is characterized by the absence of calcite cement, highest micro-porosity, highest quartz (58%), and potential hydrocarbon migrations from the underlying upper shale section of Mississippian rocks and/or charged from the overlying Caney shale or the underlying Woodford shale. These two lithofacies and other lithofacies can be predicted from well log signatures when uncored wells are unavailable.
A powerful new tool for unconformity identification in a range of geological environments is presented together with very strong evidence of its utility.
Commonly in an exploration setting correct sequence interpretation has taken years and multiple detailed studies, now with the new tool it can be done quite easily in near real time.
Recognition of unconformities in boreholes, particularly where correlation with outcrop is not available, traditionally relies on paleontological methods, normally palynology or micropalaeontology and correlations between wells where sections of the observed sequence are missing. Observations in recently drilled wells in Dubai have provided evidence for another useful tool.
While drilling Well A, bulk rock phosphate concentrations were obtained in near real time while drilling using X-ray fluorescence (XRF). These were then plotted against well depth. Phosphate values were taken as indicators of long duration and high intensity of organic production or conversely a low rate of sedimentation. Unconformities were marked by significant and obvious phosphate peaks while drilling in a marine sequence. Higher than average concentration of phosphates in marine environments during periods of non-deposition or very slow deposition have been known for some time but their use as markers for unconformities while drilling has not been widespread due to the practical difficulties with sample analysis. With advances in XRF technology routine wellsite XRF analysis services are now available.
Plots of phosphate concentrations in Well B which was drilled through a sub-aerially deposited sequence also showed phosphate peaks, some of which correlated with known and recognisable unconformity surfaces. Further evaluation, particularly comparison with palynology data, showed that the phosphate peaks which did not correlate with known unconformities indicated previously unrecognised unconformities. Phosphate peaks on unconformity surfaces in sub-aerially deposited sequences have not, as far as the authors can determine, been previously recognised.
Well C is an older well which penetrated a similar sub-aerially deposited sequence to Well B with no XRD analyses available. Correct interpretation of the Well C sequence was not possible until the key points were derived from the more complete Well B data.
Evidence is presented showing that phosphate peaks are practical and useful indicators of unconformities in near real time, especially when interpreted with other geological information. An example is also given of an unconformity which displays no phosphate peak together with an explanation as to why there is no peak.
In an exploration setting analysis of phosphate trends can significantly enhance and simplify sequence and palaeoenvironmental interpretation and understanding of regional tectonics thus providing greater insight when planning follow up wells leading to a higher success rate. As such it is a new and novel exploration tool with a potentially high economic value.
Pan, Xiaohua (Nanyang Technological University) | Oliver, Grahame John Henderson (Nanyang Technological University) | Chu, Jian (Nanyang Technological University) | Goh, Kok Hun (Infrastructure Design & Engineering, Land Transport Authority) | Wei, Xiaoqian (Infrastructure Design & Engineering, Land Transport Authority) | Kumarasamy, Jeyatharan (Infrastructure Design & Engineering, Land Transport Authority)
The Sajahat Formation is considered to be the oldest rock unit in Singapore. However, the age of deposition is uncertain. According to the Geological Map of Singapore, the Sajahat Formation has been found on Pulau Tekong, Pulau Sajahat and at Punggol Point. However, the occurrence at Punggol has not been confirmed due to the lack of present day outcrops. As part of a site investigation, two boreholes were drilled at Punggol. Hornfelsed quartzite (very similar to that found on Pulau Sajahat) cut by diorite and granodiorite dykes were logged in the core samples. Zircons from these rocks were radiometrically dated using the Laser Ablation ICPMS U-Pb method. The results of the analysis of the detrital zircons indicate that the quartzite was deposited at or later than 337±3 Ma (Early Carboniferous) and before the intrusion of a diorite dyke at 285±1 Ma (Early Permian). A granodiorite dyke was dated at 260±3 Ma (Late Permian). Therefore, the quartzite at Punggol can be confirmed to be the Sajahat Formation of Carboniferous age and is the oldest dated rock in Singapore. The engineering implication of identifying the types of formations is discussed.
The Sajahat Formation in Singapore is defined as those variably metamorphosed, unfossiliferous, sedimentary rocks comprising quartzite, sandstone, and argillite (Public Works Department 1976, Sharma et al., 1999; Lee and Zhou, 2009; Zhou and Cai, 2011). Previous studies indicate that it is probably the oldest rock unit in Singapore based on outcrops found in Pulau Tekong, Pulau Sajahat and Sajahat Kechil. Lee and Zhou (2009) proposed that the age of deposition of the Sajahat Formation was probably Lower Palaeozoic based on its complex deformation history and multiple intrusion of dykes. However, a Carboniferous to Permian age cannot be ruled out. The Sajahat Formation is very similar to the Mersing Formation in eastern Johor which is assumed to be Carboniferous in age since it is overlain by fossiferous Permian conglomerates with an angular unconformity (Oliver and Gupta, 2017). The deformed Sajahat Formation was considered to predate the undeformed Gombak Norite which has been U-Pb zircon dated by Oliver et al. (2014) at 260±2 Ma (Late Permian). The Sajahat Formation is therefore probably pre-Late Permian in age (Oliver and Gupta, 2017). However, there is no direct evidence of the age of deposition of the Sajahat Formation so far.
The present paper describes the results of analysis of depositional environment and tectonic setting within Karaton-Tengiz uplift zone in the southeastern part of the Pre-Caspian basin. The main purpose of the study is generalization and interpretation of geological and geophysical data for creation of stratigraphic charts and a description of lithological and tectonic processes for reconstruction of the structural history of pre-salt prospective traps located close to Tengiz field.
It is known that carbonates are "born, not made"; hence, their characteristics can give an insight into their depositional environment. The combination of such factors as availability of the light, warm climate, chemical composition and transparency of the water define the growth of the reef-building organisms. The highest carbonate production takes place close to the water surface; therefore, facies and texture of carbonates may be linked to the sea level changes. This means that understanding of the depositional environment and sequence stratigraphy may be used for a potential reservoir description where no well data is available. As a general understanding of the relative sea level fluctuations and its effect on carbonate growth, comparison of vertical thickness of studied platforms was carried out.
Analysis of regional seismic reflectors P3 (Top of Middle Devonian, tentative), P2D (Top of Upper Devonian), P2 (Top of Carboniferous), P1 (Top of Permian), VI (Kungurian salt deposits), V (surface of unconformity, Triassic), III (Top of Jurassic), II (Top of Lower Cretaceous) was also carried out for understanding of tectonic processes. Dipping of reflectors, thickness and depth variation of time-equivalent units, unconformities may indicate the change in tectonic setting. The shallowest depth of top of carbonates is observed on Tazhigali-Pustynnaya structure, gradually deepening towards Ansagan and Maksat to the south-southeast. Also, post-salt III and V reflective horizons are inclined from the north to the south of Karaton-Tengiz uplift zone.
Tectonic deepening in the south-southeast direction took place in several stages. The first stage, most probably, took place in Late Devonian–Early Carboniferous, as the result of which Ansagan and Maksat structures drowned. In the northern part of the Karaton-Tengiz uplift, the growth of reefs continued up to Late Carboniferous.
Well logging interpretation and published papers were integrated when possible. As the result, a conceptual model of the geological history and stratigraphic charts were created for the studied region.
The 3-D seismic survey over the Pettijohn Ranch reveals a spatially complex system of paleocaves and other karst features in the Mississippian Osage natural gas reservoir. The second derivative curvature map (Figure 3) of the 3D seismic amplitudes details many tens of miles of a major paleocave system with paleocaves and chambers of various shapes, sizes, and lengths.
The 3-D seismic Osage amplitude map (Figure 2) reveals two intriguing patterns. The west pattern is shaped as a dragon. Two caves have over 30 percent porosity at the heart of the Dragon Paleocave Complex (DPC). Both of these caves are located near the apex of a large northeast-trending anticline. These caves are connected to an extensive patchwork of natural-gas-filled paleochambers covering all of the Pettijohn Ranch and perhaps much of the surrounding ranches.
The northeast pattern (shaped as a scorpion) has a one acre, 35-foot-tall open paleochamber near the middle with 100% porosity and 100% gas saturation (Figures 2, 3). The larger Scorpion Paleocave Complex (SPC) covers over 40 acres of high porosity (50%–100%) limy dolomite caverns.
A synthetic seismogram study developed numeric relationships between the seismic amplitudes, rock porosities, natural gas saturations, and rock compositions within the Mississippian Osage Reservoir under the ranch (Figure 1). These numeric relationships demonstrate that the paleochamber at the center of the Scorpion Paleocave Complex contains natural gas. This paleochamber is located near the lowest structural position on the ranch. Subsequently, natural gas must be present updip in the Osage reservoir over the entire ranch and much of the surrounding ranches.
The mathematical equations developed from the synthetic seismogram study allow a 3-D “seismic porosity” map to be generated over the ranch. Three geologic facies are recognized from this seismic porosity map. Firstly, the limestone facies was the original deposition of low porosity (less than five percent) limestone. Secondly, the dolomite facies (porosities between five and fifteen percent) was a later diagenetic transformation of the original limestone into dolomite. Thirdly, the “karst and paleocave” facies (with porosities greater than fifteen percent) was a dissolution event during the last half of the Mississippian period. This facies covered, to some extent, much of rest of the ranch, but is most prominently seen in the two ends of the ranch as the “dragon and scorpion” amplitude patterns.
The seismic porosity map and the thickness map of the Osage were also used to compute the natural gas volumetric recoverable hydrocarbons. Nearly five billion cubic feet of natural gas (5 BCF) is producible from the Osage reservoir alone on the ranch. Log analysis of the Pettijohn #1 well indicates gas resources throughout the Mississippian Formation and into the top one hundred feet of the Arbuckle Formation. The total recoverable natural gas resources, from both the Mississippian and Arbuckle Formations from only the Pettijohn Ranch could exceed twenty billion cubic feet (20 BCF) of natural gas and helium.
Presentation Date: Thursday, October 18, 2018
Start Time: 8:30:00 AM
Location: 210A (Anaheim Convention Center)
Presentation Type: Oral
Baiburina, G. F. (BashNIPIneft LLC, RF, Ufa) | Sharipov, R. F. (BashNIPIneft LLC, RF, Ufa) | Dushin, A. S. (BashNIPIneft LLC, RF, Ufa) | Minigalieva, G. I. (BashNIPIneft LLC, RF, Ufa) | Akhmetzyanov, R. V. (BashNIPIneft LLC, RF, Ufa)
The PDF file of this paper is in Russian.
The lithological typification of the section was carried out, the conditions for the formation of deposits were identified, and maps of facies heterogeneity for each horizon of the terrigenous thickness of the Lower Carboniferous within the Republic of Bashkortostan were constructed. Using the data of wells with high core removal, microscopic description of the thin sections and granulometric studies of the samples, structural-lithological typification of terrigenous and carbonate deposits of the terrigenous thickness of the Lower Carboniferous was carried out. The granulometric composition and textural features revealed in the visual description of the core are taken as a basis for isolating lithotypes. Based on a detailed analysis of the core for the depositions of the terrigenous thickness of the Lower Carboniferous, a number of facies features were identified that allowed these deposits to be assigned to a delta complex of river type. The main diagnostic features that characterized this type of sedimentation environment have been identified. The main facies zones are the delta channels and secondary channels of the promontine, the delta plain, the delta dying, the mouth bars, the delta front, the prodelta and the shallow-marine carbonate sediments. Descriptions are given for each facies zone, its core characteristics that are characteristic for it, which make it possible to identify these complexes with confidence. In order to increase the detail of the maps of facies heterogeneity, wells with a GIS complex were involved in the wells with a core, for which an electrofacial analysis was performed, based on the methods of spontaneous potential log and Gamma ray log. The created geological framework will serve as the base for petrophysical typing of deposits. Facies features revealed during the work can serve as a basis for constructing conceptual models of local objects, and also will allow to compare different objects according to the conditions of their formation at the regional level.
Проведена литологическая типизация разреза, выявлены условия формирования отложений. Построены карты фациальной неоднородности для каждого горизонта терригенной толщи нижнего карбона (ТТНК) Республики Башкортостан. С использованием данных скважин с высоким выносом керна, микроскопических описаний шлифов и гранулометрических исследований образцов керна осуществлена структурно-литологическая типизация терригенных и карбонатных отложений ТТНК. За основу выделения литотипов приняты гранулометрический состав и текстурные признаки, выявленные при визуальном описании керна. По результатам подробного анализа керна для отложений ТТНК установлен ряд фациальных признаков, позволяющих отнести их к дельтовому комплексу речного типа. Выявлены основные диагностические признаки, характерные для данного типа обстановки осадконакопления. Основными фациальными зонами являются дельтовые каналы и второстепенные каналы промоин, дельтовая равнина, отмирания дельты, устьевые бары, фронт дельты, продельта и мелководно-морские карбонатные осадки. Дано описание каждой фациальной зоны, ее характерных признаков по керну, позволяющих достоверно идентифицировать данные комплексы. Для увеличения детальности карт фациальной неоднородности, кроме скважин, для которых имелись данные исследования керна, рассмотрены также скважины, в которых проводился комплекс геофизических исследований (ГИС). По скважинам, в которых был выполнен комплекс ГИС, проведен электрофациальный анализ. За основу принимались методы самопроизвольной поляризации потенциалов и гамма-каротаж. Созданный геологический каркас послужит базой для проведения дальнейших работ по петрофизической типизации отложений. Фациальные особенности, выявленные в ходе работы, могут служить основой для построения концептуальных моделей локальных объектов, а также позволят сравнивать разные объекты по условиям их формирования на региональном уровне.
Unconventional completions in North America have seen a paradigm shift in volumes of proppant pumped since 2014. There is a clear noticeable trend in both oil prices and proppant volumes – thanks to low product and service costs that accompanied the oil price crash in early 2015. As the industry continues to recover, operators are reevaluating completion designs to understand if these proppant volumes are beyond what is optimal. This paper analyzes trends in completion sizes and types across all major unconventional oil and gas plays in the US since 2011 and tracks their impact on well productivity.
Completion and production data since 2011 from more than 70,000 horizontal wells in seven major basins (Gulf Coast, Permian, Appalachian, Anadarko, Haynesville, Williston and Denver Julesburg basins) and 11 major oil/gas producing formations were analyzed to examine developments in proppant and fluid volumes. Average concentration of proppant per gallon of fluid pumped was used to understand transitional trends in fracturing fluid types with time. Production performance indicators such as First month, Best 3 or Best 12 months of oil and gas production were mapped against completion volumes to evaluate if there are added economic advantages to pumping larger designs.
In general, all major basins have seen progressive improvements in average well performance since 2011, with the Permian Basin showing the highest improvement, increasing from an average first-six-months oil production of 25,000 bbl in 2011 to 75,000 bbl in 2017. The Gulf Coast basin, where the Eagle Ford formation is located, has seen a 6-fold increase in proppant volumes pumped per foot of lateral since 2011 while the Permian and Appalachian basins hit peak proppant volumes in 2015 and 2016 respectively. In Permian and Eagleford wells, higher proppant volumes in general have resulted in better production up to a certain concentration. In Williston and Denver basins, most operators are moving away from gelled fluids, and reduced average proppant concentration per fluid volume pumped shows inclination toward hybrid or slickwater designs. While some of these observations are tied to reservoir quality, proppant volumes have begun to peak as operators have either reached an optimal point or are in the process of reducing volumes.
Demand for proppant is expected to nearly double by 2020. As oil prices continue to recover, well AFEs continue to increase, despite multiple efforts to improve capital efficiency. The need for enhanced fracture conductivity and extended half-lengths on EURs are been discussed by combining actual observed production data and sensitivities using calibrated production models. The industry is moving toward large-volume slickwater fracturing operations using smaller proppants, but he operating landscape is expected to see a correction when such designs become less economical.