Han, Heyleem (University of Oklahoma) | Dang, Son (University of Oklahoma) | Acosta, Juan C. (University of Oklahoma) | Fu, Jing (University of Oklahoma) | Sondergeld, Carl (University of Oklahoma) | Rai, Chandra (University of Oklahoma)
Developing tight shale formations, presents additional challenges due to their vertical and horizontal heterogeneities. Many real-time field decisions, such as lateral placement, are made with the understanding of sequence stratigraphy and a well's petrophysical profile. Handheld X-Ray fluorescence (XRF) has been commonly used as a rapid scanning tool for elemental analysis. Complementary to XRF, handheld Laser Induced Breakdown Spectroscopy (LIBS) has recently been developed, and quickly recognized as a useful tool. It captures the light elements, which XRF cannot, such as sodium, magnesium and more importantly carbon (both organic and inorganic), which are essential elements in understanding rich organic sedimentary rocks. LIBS spectra generally have lower emission signal intensities for dark organic rich samples; therefore, it is important to select optimal integration-delay times to capture better signal intensities for all emission lines ranging from the ultraviolet (180-400nm), through visible light (400-780nm) to infrared (780-960nm). Using a partial least square regression (PLS) and signal normalization, an inversion method was developed for rock slab characterization. The trained dataset includes 150 samples from different tight shale formations, such as Meramec, Woodford, Eagle Ford, Barnett, Bakken, Vaca Muerta and Wolfcamp. The inversion provides quantitative elemental concentrations with reasonable uncertainty. The results were validated with another group of 70 samples from different shale plays. XRF was obtained for the same samples and results showed a good correlation between LIBS and XRF for major elements (Al, Fe, Si, Mg, Si, Ca, K). Total carbon measured through LECO® without acidizing was used to verify LIBS total carbon readings. Mineralogy was inverted from the XRF elemental abundances.; this provided carbonate mineral concentration, which was used to calculate inorganic carbon. Total organic carbon (TOC) was later estimated as the difference between total carbon and inorganic carbon. In this study, we demonstrated the complete elemental analysis on 370-ft of core sampled at a 2-inch depth resolution using XRF and 0.5ft depth resolution using LIBS. Trace elements were used to understand formation chemostratigraphy, while major elements were used to invert for mineralogy, TOC, and to compute a brittleness index profile.
Economic hydrocarbon production from organic rich shale has been made feasible by advances in horizontal drilling and hydraulic fracturing. Proppants are pumped to keep the fractures open and provide a high conductive path from the reservoir to the wellbore. Effects of proppant size, proppant crushing, fines migration, rock mineralogy and fluid chemistry on the long-term fracture conductivity have been studied experimentally in detail by Mittal (2017, 2018). This study further investigates the impact of proppant concentration, size and presence of different volcanic ashes on fracture conductivity along with different conductivity impairment mechanisms including proppant crushing, embedment and diagenesis under simulated reservoir conditions.
Experiments have been conducted by varying the proppant concentration of 60/100 mesh Ottawa sand from 2 lb/ft2 to 4 lb/ft2. The proppant pack was placed between metal platens and subjected to axial load of 5000 psi and temperature of 250 °F. Proppant pack conductivity was then measured by flowing 3% NaCl brine for periods of 7-15 days. We observed a sharp decline in permeability, with almost 98% decline within 3 days with low concentration compared to only 60% decline in permeability with higher concentration of proppant. Particle size analysis reveals overall 5% higher percentage crushing at lower proppant concentration, suggesting major crushing occurs at the platen interfaces which reduces with increased proppant pack concentration.
Presence of volcanics in the major shale plays like Eagle Ford and Vaca Muerta has been reported in literature. To simulate similar environment and study the impact of diagenesis on fracture conductivity, experiments have been conducted by flowing high pH (~10) brine through the proppant pack mixed with volcanics like obsidian and basalt and placing the proppant between Eagle Ford shale platens. Experiments were conducted with 20/40 Ottawa sand mixed with obsidian and 60/100 mesh Ottawa sand mixed with basalt. We observed a sharper decline in permeability with 60/100 sand as compared to 20/40 sand in the first two days. However, the permeability for both the proppant sizes continues to decline with a difference of an order of magnitude even after 30 days. SEM images shows significant particle crushing, embedment and diagenetic growth on the shale surface and verify that these factors are responsible for permeability decline. To further understand the impact of proppant size on permeability, dry crush tests have been conducted on 20/40 and 60/100 Ottawa sand by varying compaction pressure from 1500 psi to 3000 psi and 5000 psi. We observed that 60/100 mesh sand undergo overall higher compaction and crushing compared to 20/40 mesh sand at each compaction pressure.
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
The Meramec Formation in the STACK play has moved to full field development and multiple wells are put on production in a relatively short time. Our results provide asset teams with key geologic, completions, and operations characteristics and their relative contribution to well performance. Depending on the desired economic metric (NPV or ROR), the drawdown strategy and the magnitude of intra-well interference (fracture to fracture) can be optimized. For instance, if the objective is to maximize rate of return, then tighter fracture spacing may be accepted. Results provide guidance to optimal design parameters and operational strategies in the Meramec Formation.
Optimal cluster spacing has eluded reservoir and completions engineers since the inception of multi-stage hydraulic fracturing. Very small cluster spacing could result in fracture to fracture (intra-well) interference and higher completions cost, whereas very large cluster spacing could lead to inefficient resource recovery which is detrimental to the economics of the well.
This study interrogates the relative contribution of rock matrix, completions, and operational characteristics, vis-a-vis short and long term well performance in tight oil reservoirs. Those characteristics include drawdown strategy, cluster spacing, pressure dependent permeability, critical gas saturation, and petrophysical properties. Available geologic data were integrated to construct a geologic model which will be used to history match a well from the Meramec Formation.
The static model covers an area of 640 acres that encompasses a multi-stage hydraulically fractured horizontal well. The well is unique because it is unbounded and has more than two years of continuous production without being disturbed by offset operations. History match was obtained to three-phase production and flowing bottom-hole pressure. By utilizing element of symmetry, numerical models were created to investigate the effect of fractures interference on short- and long-term oil recovery and producing gas-oil ratio.
Observations from diagnostics such as offset pressure gauges, micro-seismic, fiber optics, and radioactive tracers can provide critical insights into optimal fracture spacing. However, those observations remain incomplete without proper integration with physics-based models to predict well performance and optimize fracture spacing.
Findings suggest that drawdown strategy (aggressive versus conservative) is more impactful to short term oil productivity than fracture spacing. Drawdown strategy is even more impactful on short-term oil recovery than a 20% error in porosity, or water saturation. The profile of producing gas-oil ratio depends on fracture spacing and has been interpreted in the context of linear flow theory.
In self-sourced low-permeability reservoirs the efficiency at the interaction between the mudstone matrix and fractures is a key control on well performance. Commonly, the more heterogeneous (interbedded) the reservoir the more complex fracture network is naturally developed or can be achieved during stimulation. In this study, using observations from two different unconventional shale units, we demonstrate that mudstone stratigraphic heterogeneities are scale dependent, and thus capturing their expression at different scales is key to understanding the level to which facies arrangements can affect important petrophysical, geochemical and geomechanical properties. Characteristics from the Duvernay Formation in Alberta-Canada and the Woodford Shale in Oklahoma-USA were compared in this study; both units are Late Devonian in age and are organic-rich prolific reservoirs. Lithologies in the Duvernay mostly vary according to changes in carbonate content, whereas in the Woodford changes are according to quartz content. However, in both cases a systematic alternation of two distinct rock types is evident at the cm-scale in outcrops and cores: organic-rich and calcite-rich facies for the Duvernay, and mudstones and chert facies for the Woodford. By combining high-resolution geochemical and geomechanical data, two distinct trends were evident for both units, and illustrate that variations in organic contents, mineralogy and relative hardness can be grouped by the two main rock types for each unit. In the Duvernay, the calcite-rich facies occur as low-TOC beds, at the microscale these are dominated by pore-filling calcite cements. In the Woodford, chert beds present the lower TOC content and their microfabric consists of microcrystalline aggregates of biogenic/authigenic quartz. In both units, the higher porosity values correlate with the high-TOC beds with abundant interparticle porosity. As for mechanical hardness and natural fractures, the higher calcite and quartz contents positively correlate with stiffer beds which generally are more brittle and have more natural fractures. The interbedded character between high-TOC and low-TOC beds is common for both units but at different frequencies and thickness. Capturing the degree of interbedding using a heterogeneity index suggests that reservoir behavior might be depicted as a multi-layered model in which properties are affected by the thickness, permeability, storage capacity, stiffness and fracture frequency of each bed. Although sometimes neglected, the study of fine-scale variations in reservoir properties can provide significant criteria for the selection of optimal horizontal landing zones.
Gong, Yiwen (The Ohio State University) | Mehana, Mohamed (University of Oklahoma) | El-Monier, Ilham (The Ohio State University) | Xu, Feng (Research Institute of Petroleum Exploration and Development Co. Ltd. CNPC / China National Oil and Gas Exploration and Development Corporation) | Xiong, Fengyang (The Ohio State University)
The accurate estimation of the elastic properties of the rock is of great importance for designing a successful hydraulic fracturing. Among these properties, Young's modulus and Poisson's ratio essentially control fracture aperture and conductivity. However, the fissile nature of the shale rock largely challenges the mechanical properties measurement using a cylindrical core sample. While the nanoindentation technology can be applied to measure small chips of rock fragment, but reproducible experiments are required to provide an unbiased estimation. Herein, we are proposing a machine learning approach to predict the elastic moduli. We utilized an ensemble of data mining techniques and a database that include both the mineralogy and pore characteristics. Our results indicate that K-Means clustering yields best performance on data classification than all other tested methods while the elastic moduli estimation from Artificial Neural Network (ANN)is most accurate than Support Vector Machine (SVM), Multivariate Linear Regression (MLR) and Multivariate Adaptive Regression Spine (MARS). The dimension reduction became essential when then input datasets are remarkably correlated. The supervised learning techniques with our proposed approach leverage the usability of the lab experiment data and overcome disadvantages of the traditional elastic moduli measurement. It also further lands the far-reaching guide for the fracturing design.
Machine learning have recently revolutionized the oil and gas industry (Alcocer and Rodrigues 2001, Al-Fattah and Startzman 2001, Kohli and Arora 2014, Okpo et al. 2016, Sinha et al. 2016, Tariq et al. 2017, Luo et al. 2018, Nande 2018, Rashidi et al. 2018, Sidaoui et al. 2018, Xu et al. 2019). As a data-rich industry, machine learning finds applications in every corner ranging from production forecast to drilling efficiency (Hegde and Gray 2017, Fulford et al. 2016). Given the significance of geomechanical properties of the rock, the volume of studies has attempted to leverage machine learning techniques. For instance, Li et al. (2018) developed a workflow implementing various machine learning algorithm to accurately provide an alternative to synthesize the sonic logs and geomechanical properties afterwards. In the same time, Hadi and Nygaard (2018) used Artificial Neural Network (ANN) to develop an empirical model to estimate the shear velocity from conventional logs. Another dimension was presented by Jain et al. (2015) where they proposed an approach to integrate both core and log spectroscopy which provided better estimations of the mineralogy.
Natural fractures are a ubiquitous feature of unconventional reservoirs as evident from well logs, core studies, and micro-seismic interpretation. Hydraulic fracture (HF) generally intersects natural fractures (NF) leading to relatively complex geometry of the stimulated volume and the complications in proppant transport and deposition. In this paper, we simulate hydraulic fracturing in the presence of natural fractures in 3D and investigate key mechanisms in successfully stimulating and propping naturally fractured reservoirs. To our knowledge this if the first time the problem has been treated in 3D while considering HF/NF mechanical interaction. Several stimulations are considered using the state-of-the-art simulator “GeoFrac-3D” that can consider irregular fracture geometries and non-orthogonal intersection between the HF and NF, thereby realistic flow and proppant transport pathways and deposition sites. The “GeoFrac-3D” is based on the combination the displacement discontinuity method for the rock deformation, and the finite element method for the fracture fluid and proppant transport simulation. The deformation of the natural fractures is implemented using a linear joint model. The proppant transport and deposition within the fractures is modeled by treating the mixture of fluid and proppant particles as slurry. Example simulations are presented to explore the effective stimulation of fractured reservoirs using 100 mesh proppant. When the proppant can enter secondary fractures without extensive settling in the main HF, the propped surface area is maximized. Proppant settling velocities and thus proppant distribution is affected by fluid velocity, micro-proppant size, fluid rheology, fracture aperture, hydraulic and natural fracture interaction and near wellbore tortuosity.
In hydraulic fracturing of unconventional reservoirs, the propagating hydraulic fracture (HF) generally intersects natural fractures (NF) complicating the geometry of the stimulated volume and the estimation of proppant flow and transport. The effectiveness of a hydraulic fracturing job depends on the resultant flow area and proppant pack permeability of the fracture system; therefore, a good understanding of the proppant transport and deposition is an essential component of hydraulic fracturing design. Several experimental studies (Sahai et al., 2014; Tong and Mohanty, 2016) and numerical studies (Weng et al., 2011; Tang et al., 2015; Han et al., 2016; Izadi et al., 2017) have been presented for the proppant transport and deposition in hydraulic and natural fractures (HF-NF) networks. These studies assume a stationary fracture network or a pre-defined propagation path. Recently, Kumar et al. (2019) presented a numerical study of the proppant transport and deposition in the HF-NF network and explored potential benefits of using of micro-proppant in the conductive fracture networks and demonstrated that due to induced stress shadowing effect near the intersections of the HF and NF's, the fracture openings are reduced which creates “choke or bottleneck points” as a resultant the bigger size proppants are prevented to enter into the natural fractures. In this paper, we have extended our earlier work to account for the potential propagation of the natural fracture wings and the impacts of NF's propagation on the proppant transport in the HF-NF networks. The objective is to explore and clarify the potential mechanisms involved in the successful stimulation of naturally fractured reservoirs with proppant deposition. We use the Eulerian-Eulerian approach to simulate proppant transport and deposition using a fully coupled 3D hydraulic fracture network model. We use “GeoFrac-3D” which can consider irregular fracture geometries and non-orthogonal intersection between the HF and NF, thereby capturing realistic flow and proppant transport pathways and deposition sites. A brief discussion of the mathematical formulations and numerical implementation are presented first, followed by several examples to illustrate some important phenomena in the proppant transport in the HF-NF networks in unconventional reservoir stimulation.
Identification and quantification of parasequences remains a key aspect in unconventional reservoir development  demonstrated the importance of gamma ray parasequences (GRP) in unconventional play development. Currently, most of the drilling plans in unconventional plays are executed using a ‘factory made” drilling and completion program. Due to thousands of wells in an unconventional play, it is a very difficult task for operators to incorporate the fine scale reservoir characterization in time for drilling plan.
Currently the upward dirtying and upward cleaning parasequences in shale plays are interpreted qualitatively and manually by a human interpreter on individual well logs. We believe these parasequences hold key information about the underlying geology and their quantification can provide key insights into the depositional environment and hence reservoir quality. Incorporating this information in due time for drilling and completion can aid the decision making process on well placement and hydraulic fracturing design.
In this work, we handle the reservoir characterization challenge on two fronts: we first provide a statistical filtering approach to interpret the parasequences in a well log and then use machine assisted application on other wells in the area of interest. We then use Least-squares fit to obtain slopes of these parasequences. Furthermore, we map these slopes and compare them to the conventional parasequence thickness map to provide quantitative well log attributes to help aid the geologic interpretation.
Unconventional play development has key differences to that of a conventional play development. In a conventional porosity, permeability etc. are the key drivers for production. Well spacing and landing the best zone and hydraulic fracturing guide the production performance in horizontal wells. As the well is completed with hydraulic fracturing operation, the geomechanical properties of the layer become of utmost importance (-6]).  proposed that the layered properties of the shale reservoir are highly complex and is composed of alternating brittle and ductile geological sequences also known as brittle-ductile couplets . The optimal landing zone depends on a tradeoff between the brittleness and rock properties such as total organic carbon(TOC). The good rock from the reservoir perspective which is high in TOC is generally more ductile and not a suitable candidate for hydraulic fracturing operation and vice versa.
Diagenesis encompasses many processes after deposition that are responsible for the dynamic evolution of the pore system. Understanding the role of diagenetic events on the connectivity and distribution of pores and migration pathways is vital for proper characterization of the rock. In this study, we critically examine diagenetic signatures in the Woodford Shale focusing on rock-fluid interactions that cause precipitation and dissolution and assess their impact on reservoir quality via multi-physics models.
Evidence of diagenesis in shales have been extensively investigated by some of the authors in active and previous research. In this study, we focused on capturing the distribution of diagenetic features in the Woodford Shale using multiphysics models. Our methodology establishes a multi-disciplinary framework to incorporate multi-scale multi-physics data from various sources to investigate the impact of diagenesis on the alteration of petrophysical properties. Data incorporated include thin sections, scanning electron microscopy, and mineralogy. We first analyze and quantify the diagenetic signatures in the Woodford Shale. Examining the depositional history of the basin, mineralogy, the different pore types and the associated minerals. We then construct representative 3D pore-scale models and employ multi-component coupled fluid-flow and reactive-transport models to critically investigate these processes. Numerically, this entails concurrent solution of fluid-flow equations for pressures and fluxes, changes in fluid and mineral composition and conservation of solute mass for each component in the pore-network. We analyze porosity occlusion and the changes in migration pathways.
This framework allowed us to determine the influence of chemical diagenesis (precipitation and dissolution) processes on the pore structure, connectivity, and fluid flow, in order to quantify the reservoir quality. Our initial pore-scale simulation effort yields promising results and is able to reproduce major diagenetic features. Future research efforts will include incorporating complex reactive kinetics and geomechanical stress-strain modules in the pore scale simulator that will enable us to examine more complex scenarios.
Recent studies of core extracted adjacent to fractured wells show evidence of multi-stranded fractures as opposed to the conventional expectation of a single fracture per cluster. The cores show that fractures propagate as tightly spaced network of parallel strands and their number exceeded the number of perorations/clusters by a large amount. Previously (Sesetty and Ghassemi, 2019), we examined the conditions for the formation of multiple fractures from a perforation by focusing on the near wellbore region. In this work, we study hydraulic fracture segmentation and its impact on the net pressure. Furthermore, an advanced, rigorous P3D model is used to simulate multi-cluster multi-stage field scale planar hydraulic fracture propagation. In our modeling, we use the displacement discontinuity method (DD) to incorporate stress shadow between the parallel fracture strands. Depending on the regime of fracture propagation viscous/leak-off/toughness tip solutions are employed. A number of numerical simulations are considered for each stimulation concept, under varying field conditions with emphasis on the resultant treatment pressures and fracture conductivities. Results indicate that traditional modelling approach even when accounting for natural fractures cannot explain very high ISIP's (>1000 psi) that are often observed in field. On the other hand, simulations of multi-stranded hydraulic fractures considered under different geometric configurations can explain tight fracture spacing and high ISIP's. Also, formation of multi-clusters or stranded fractures adversely impact fracture apertures (especially the inner fractures) due to high stress shadow effect between the fractures, which poses a challenge to effective proppant placement. The fracture segment or strand height is the controlling parameter that dictates the minimum spacing allowed between the parallel strands for them to propagate simultaneously to very large distances from wellbore. Results show that accounting for the effects of multi-stranded fractures in numerical models can capture the field observed phenomena of high net pressures, multiple hydraulic fractures, and less than optimum proppant placement without resorting to ad hoc variation of natural fracture and rock properties. The novel numerical models used in this study have a computation time comparable to the conventional single fracture models, while handling a large number of interacting fractures.