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Abstract Theia Energy discovered a prospective unconventional hydrocarbon resource in the Ordovician Lower Goldwyer Shale (LGS) located on the Broome Platform of the onshore Canning Basin. The collation, processing, analysis and interpretation of all available regional data culminated in a successful exploration well, Theia-1 (drilled in 2015), which intersected a 230 ft gross oil column between 4,910–5,140 ft (based on slim-hole log and core analyses). Theia-1 recovered continuous core and wireline log data required to analyse and assess the geological properties necessary for a commercially viable shale oil and gas resource and quantify the volumes of hydrocarbons in-place. Petroleum system modelling carried out in the basin confirmed the prospectivity of the LGS and a potential additional mature hydrocarbon resource in the deeper Nambeet Formation some 2,000 ft below the LGS. The Nambeet is believed to exhibit higher maturity and extensive thickness reaching over 2,000 ft across a significant region of the Broome Platform. The Nambeet Formation adds substantial wet gas prospective resources in addition to those already discovered in the LGS. This paper outlines Theia Energy's exploration strategy in the onshore Canning Basin utilizing shale specific play elements from which the early exploration program was designed and assessed following the drilling of Theia-1. Subsequent specialized testing of core and independent expert analysis have confirmed the reservoir quality, charge, completion quality and producibility of the LGS. In particular, proppant embedment and fracture conductivity tests indicate exceptional flow characteristics of the LGS. The abundance of oil and gas prospective resources in the onshore Canning Basin is significant to the northwest region of Western Australia. The establishment of an unconventional petroleum resources industry would bring pivotal increased activity to its vacillating economy which is currently relying on mining, offshore petroleum development and tourism. Whilst the development and export of the resource would substantially add to economic opportunity for the region, the establishment of much-needed infrastructure would kickstart further economic opportunity such as: mining, downstream manufacturing including fertilisers, irrigated agriculture and cattle farming. Plans are under development for the implementation of major renewable energy projects in the region which can co-exist with an unconventional resource project.
Cornelio, J. (University of Southern California) | Razak, S. Mohd (University of Southern California) | Jahandideh, A. (University of Southern California) | Cho, Y. (University of Southern California) | Liu, H-H. (Aramco Americas) | Vaidya, R. (Aramco Americas) | Jafarpour, B. (University of Southern California)
Abstract A physics-assisted deep learning model is presented to facilitate transfer learning in unconventional reservoirs by integrating the complementary strengths of physics-based and data-driven predictive models. The developed model uses a deep learning architecture to map formation properties to their corresponding production responses using a low-dimensional feature space representation. Transfer learning is accomplished by first training the network weights using production data from a mature shale play and combining the learned weights with limited data from a new unconventional field to generate a predictive model. The simulated data provides approximate production predictions for input parameters of the target field, for which the source data may not provide a good prediction. The resulting model has a superior performance to simulation-based and data-driven predictions alone. The results indicate that (1) physics-based simulated data can facilitate production predictions when out-of-range (unseen) input parameters have to extrapolate from data, and (2) transferring the weights learned from the source field to the target field can add valuable information to enhance the prediction performance of the target field. Introduction There has been a significant increase in the development of unconventional reservoirs in recent decades, particularly tight oil reservoirs in the United States. These tight oil formations often have extremely low permeability and are not economically exploitable using traditional drilling and completion techniques used for conventional high permeability reservoirs. Fortunately, due to the advancement in key technologies, in particular hydraulic fracturing and horizontal drilling, these low permeability shale formations can be stimulated to induce the production of hydrocarbons (King, 2010). However, the traditional flow equations that are well documented and studied for conventional wells have not been applied to tight oil reservoirs. Traditionally, the development of conventional reservoirs relies heavily on numerical reservoir simulators (Altman et al., 2020, Aziz et al., 1979). These simulators provide a reliable prediction that assists in decision-making for resource development. They are built using well-studied and trusted physics-based analytical expressions that are solved during the simulation to provide prediction responses. Since these physics-based simulation models are based on analytical equations, they have the advantage of being able to produce a prediction response for any possible range of input variables, and this allows them to easily extrapolate to any range of data. Additionally, simulation models can be run for any combination of input variables and enable the collection of large amounts of simulated data for all possible scenarios. However, the equations used in simulation models are not able to provide dependable predictions for unconventional tight oil resources since the complex physical relation of flow from tight formations and fractures along with the fracture generation is poorly understood. Additionally, there are various components in the field that are not always accounted for when building simulation models (Fung et al., 2016). These limitations make simulation models unreliable to be used to develop unconventional reservoirs.
ABSTRACT: Hydraulic fracture height is one of the most difficult parameters to measure yet understanding height growth is becoming increasingly salient in the economic success of unconventional wells in multi-layer structures, particularly for projects with increased well density development. Downhole tiltmeter fracture mapping by passive monitoring of elasto-static microdeformation offers high sensitivity to fracture height. This work aims at presenting a workflow to integrate advanced microseismic analysis and tiltmeter fracture mapping to resolve dimensions of fracture with a non-uniform opening. The algorithms are implemented in a real-time fracture monitoring program which selects the best fit and superposes final-state and transient models on measured micro-deformation. We apply the presented technique to synthetic and field case studies and, for the first time, present transient tilt characteristics using heatmap visualization of slow deformation (tilt waterfall). Our motivation for the present study is to take advantage of the newly developed downhole instruments that convey a combined array of geophones and tiltmeters and can be installed at greater depth and temperature to monitor and evaluate fracture to as hot as 177°C (>12000ft). 1. Introduction Hydraulic fracturing in unconventional reservoirs is a complex process controlled by the pumping parameters, rock mechanical properties, in-situ stress state, and multi-scale discontinuities (e.g., layering and interfaces, faults, natural fractures). Thereby it is poorly characterized by standard models unless discrepancies are resolved by introducing fudge factors (Warpinski et al. 1994). Downhole Tiltmeter Fracture Mapping (DTFM) is a unique technique that measures induced microdeformation near the fracture face and unravels the evolution of the volumetric distribution of fluid-driven fracture during treatment as well as after pumping stops. Fracture height, dip, volume, azimuth, opening, horizontal components, and complexity are among the parameters that impact the tilt response and can be potentially determined by DTFM if enough tiltmeters are located optimally. As depicted in Fig.1, the field deployment of DTFM to monitor the underground operation entails placement of at least one vertical, linear and wireline-conveyed array of tiltmeters in an offset well (Wright et al. 1998b). The array of tiltmeters is conveyed to the same depth range targeted by the treatment well. It is carefully deployed to ensure that enough data can be recorded from above and below the fracture depth. The acquisition unit samples tilt sequentially in time at each tiltmeter normally with a sampling rate of < 5 HZ.
Kazak, Ekaterina S. (Lomonosov Moscow State University) | Kazak, Andrey V. (Center for Hydrocarbon Recovery, Skolkovo Institute of Science and Technology) | Bilek, Felix (Dresden Groundwater Research Centre)
Summary In this study, we aim to develop a new integrated solution for determining the formation water content and salinity for petrophysical characterization. The workflow includes three core components: the evaporation method (EM) with isotopic analysis, analysis of aqueous extracts, and cation exchange capacity (CEC) study. The EM serves to quickly and accurately measure the contents of both free and loosely clay-bound water. The isotopic composition confirms the origin and genesis of the formation water. Chemical analysis of aqueous extracts gives the lower limit of sodium chloride (NaCl) salinity. The CEC describes rock-fluid interactions. The workflow is applicable for tight reservoir rock samples, including shales and source rocks. A representative collection of rock samples is formed based on the petrophysical interpretation of well logs from a complex source rock of the Bazhenov Formation (BF; Western Siberia, Russia). The EM employs the retort principle but delivers much more accurate and reliable results. The suite of auxiliary laboratory methods includes derivatography, Rock-Eval pyrolysis, and X-ray diffraction (XRD) analysis. Water extracts from the rock samples at natural humidity deliver a lower bound for mineralization (salinity) of formation water. Isotopic analysis of the evaporated water samples covered δO and δH. A modified alcoholic ammonium chloride [(NH4Cl)Alc] method provides the CEC and exchangeable cation concentration of the rock samples with low carbonate content. The studied rock samples had residual formation water up to 4.3 wt%, including free up to 3.9 wt% and loosely clay-bound water up to 0.96 wt%. The latter correlates well to the clay content. The estimated formation water salinity reached tens of grams per liter. At the same time, the isotopic composition confirmed the formation genesis at high depth and generally matched with that of the region's deep stratal waters. The content of chemically bound water reached 6.40 wt% and exceeded both free and loosely bound water contents. The analysis of isotopic composition proved the formation water origin. The CEC fell in the range of 1.5 to 4.73 cmol/kg and depended on the clay content. In this study, we take a qualitative step toward quantifying formation water in shale reservoirs. The research effort delivered an integrated workflow for reliable determination of formation water content, salinity lower bound, and water origin. The results fill the knowledge gaps in the petrophysical interpretation of well logs and general reservoir characterization and reserve estimation. The research novelty uses a unique suite of laboratory methods adapted for tight shale rocks holding less than 1 wt% of water.
Abstract With advancements in technology such as horizontal drilling and hydraulic fracking, operators are able to pursue reserves in unconventional mudrock reservoirs. Brittleness, one of the many pre-screening considerations, is an important parameter because it determines whether a mudrock can be effectively stimulated via hydraulic fracking. The industry currently uses several geochemical signals (e.g. Si/Al and Si/Zr) to identify authigenic silica phases present in an unconventional reservoir. Cemented horizons are prime candidates for placing hydraulic fracks due to the strengthening effects of mineral cements on the rock frame. A similar geochemical method for readily indicating the occurrence of authigenic carbonate has not been identified. This study documents trace element geochemical differences between biogenic (detrital) carbonate phases and associated cements so that chemical proxies may be used to differentiate authigenic carbonate phases using bulk geochemical data. Both carbonate-rich formations (e.g. Eagle Ford and Niobrara) and argillaceous formations (e.g. Haynesville and Marcellus) are examined to gain insight into reservoir brittleness, using bulk and trace elements such as Ba, Mg, Mn, Fe, Sr, and Ca. The goal is to develop a technique that can be implemented real-time by the mudlogging unit at the wellsite and during the initial core analysis phase. This method will allow a more targeted placement of hydraulic fracking zones to increase permeability and hydrocarbon production in mudrock reservoirs. Electron probe micro analysis (EPMA) on several types of carbonate was conducted on low (0.45 %Ro) and high (2.5 %Ro) thermal maturity Eagle Ford and Haynesville Formation samples, respectively. The EPMA reveals that Sr is the primary elemental signature of the authigenic carbonate phase within the low maturity Eagle Ford. The Haynesville EPMA reveals higher variability of Fe, Mn, Sr, Mg, and Ba trace element concentrations, however the dominant elemental signature associated with the authigenic phases is elevated concentrations of Fe and Mn. Utilizing XRF, Sr/Ca and Ca-Fe-Mg cross-plots can be used as proxies to identify authigenic carbonate in the Eagle Ford and Haynesville Formations respectively, and can be used to indicate brittle zones for target adjustments at the wellsite.
Abstract The objective of this research was to identify hydraulic fracturing regulations from a range of jurisdictions, verify the grounds for regulatory intervention within the scientific literature and categorize the statements according to the geospatial application. Specific regulations constraining aspects of hydraulic fracturing activities from jurisdictions across the world were collated to identify common features relating to environmental protection, administrative requirements and grammatical structure. Regulations from 55 jurisdictions including states in the US, provinces in Canada, Australian states, European countries, Africa and South America were assessed and common focus areas identified, allowing for the development of a regulatory suite of universal application. Regulations could be ascribed to partitions of the environment including the lithosphere, the atmosphere, the hydrosphere, biosphere and the social framework. Some 32 distinct elements were identified as frequent constraints to hydraulic fracturing located in three geospatial zones: off-site; wellsite; and, wellhead. The scientific literature for each of these areas was critically assessed and summary reviews developed as a comprehensive and wide ranging review of environmental impacts. The specific use of open ended risk regulation as part of control documents (a permit or regulatory framework) appears to have been promoted as a catch-all in the absence of knowledge within the regulatory agency as if there is a lack of evidence supporting directed regulation. As an output of this research a Driver-Pressure-State-Impact-Response model was developed reflecting the substantial literature base that extends well back into the 1970s, with the initial development of coalbed methane in the Rockies and the Southern States and since the 1990s with shale. The paper calls into question claims of "We don't know enough".
Summary We built a 3D geomechanical model using commercially available finite-element-analysis (FEA) software to simulate a propagating hydraulic fracture (HF) and its interaction with a vertical natural fracture (NF) in a tight medium. These newly introduced elements have the ability to model the fluid continuity at an HF/NF intersection, the main area of concern. We observed that, for a high-stress-contrast scenario, the NF cohesive elements showed less damage when compared with the lowstress-contrast case. Also, for the scenario of high stress contrast with principal horizontal stresses reversed, the HF intersected, activated, and opened the NF. Increasing the injection rate resulted in a longer and wider HF but did not significantly affect the NF-activated length. Injection-fluid viscosity displayed an inverse relationship with the HF length and a proportional relationship with the HF opening or width. We observed that a weak NF plane temporarily restricts the HF propagation. On the other hand, a tougher NF, or an NF with properties similar to its surroundings, does not show this type of restriction. The NF activated length was found at its maximum in the case of a weaker NF and at nearly zero in the case of a stronger NF and an NF that has strength similar to its surroundings. In this study we present the results for a three-layered 3D geomechanical model with a single HF and NF orthogonally intersecting each other, using newly introduced cohesive elements for the first time in technical literature. We also conducted a detailed sensitivity analysis considering the effect of stress contrast, injection rate, injection-fluid viscosity, and NF properties on this HF/NF interaction. These results provide an idea of how the idealized resultant fracture geometry will change when several fracture/fracture treatment properties are varied. Introduction The issue of HF and NF interaction has been numerically examined using software packages at both the laboratory and field levels. Warpinski and Teufel (1987) experimentally found that the HFs propagated through joints and formed a multistranded and nonplanar fracture network. The presence of a similar network was also observed in core samples from tight-sandstone reservoirs. Warpinski (1993) and Fisher et al. (2002) interpreted some of the Barnett Shale microseismic data and found that the HF propagation and orientation was affected by the already existing NFs. Lancaster et al. (1992) conducted a core study and found that the HF can propagate along an NF, resulting in propped NFs.
Newby, Warren (Total SA) | Abbassi, Soumaya (Total SA) | Fialips, Claire (Total SA) | D.M. Gauthier, Bertrand (Total SA) | Padin, Anton (Total SA) | Pourpak, Hamid (Total SA) | Taubert, Samuel (Total SA)
Abstract The Upper Jurassic (Oxfordian to Late Kimmeridgian) Diyab Formation has served as the source rock for several world-class oil and gas fields in the Middle East. More recently it has become an emerging unconventional exploration target in United Arab Emirates (UAE), Saudi Arabia, Bahrain and its age-equivalent Najhma shale member in Kuwait. The Diyab is unique in comparison to other shale plays due to its significant carbonate mineralogy, low porosities, and high pore pressures. Average measured porosities in the Diyab are generally low and the highest porosity intervals are found to be directly linked to organic porosity created by thermal maturation. Despite low overall porosities, the high carbonate and very low clay content defines an extremely brittle target, conducive to hydraulic fracture stimulation. This coupled with a high-pressure gradient facilitates a new unconventional gas exploration target in the Middle East. However, these favorable reservoir conditions come along with some challenges, including complex geomechanical properties, a challenging stress regime and the uncertainty of whether the presence of natural fractures could enhance or hinder production after hydraulic fracture treatment. Only recently has the Diyab been studied in detail in the context of an unconventional reservoir. This paper presents an integrated approach allowing a multidisciplinary characterisation of this emerging unconventional carbonate reservoir in order to gain a better understanding on the plays’ productivity controls that will aid in designing and completing future wells, but already encouraging results have been observed to date.
The compressibility factor (Z) of a gas inside a nanosize conduit depends on the conduit's characteristic size, in contrast to wide conduits whose dimensions have no effect on the gas compressibility. Nanofluidics, which is a field of study concerned with the fluid flow in nanosize conduits, can quantify the gas compressibility factor in a simple topology, such as a uniform tube with a circular cross section, but it is not apparent how those results are relevant to a complex pore space in the matrix of a shale at the core scale. This study determines the compressibility factor of a shale gas by accounting for the effective connectivity of the pore space at the core scale. We use effective pore-throat and pore-body sizes, which are interpreted using an acyclic pore model applied to the core-scale measurements and not high-resolution images. Eleven shale formations whose data are available in the literature are investigated (Bakken, Barnett, Eagle Ford, Haynesville, Marcellus, Monterey, New Albany, Niobrara, Utica, Wolfcamp, and Woodford). The results, which have applications in developing realistic models based on petrophysical measurements, show the compressibility factor (Z) of the shale formation at the core scale as a function of gas pressure.
Abstract Production from organic-rich shale petroleum systems is extremely challenging due to the complex rock and flow characteristics. An accurate characterization of shale reservoir rock properties would positively impact hydrocarbon exploration and production planning. We integrate large-scale geologic components with small-scale petrophysical rock properties to categorize distinct rock types in low porosity and low permeability shales. We then use this workflow to distinguish three rock types in the reservoir interval of the Niobrara shale in the Denver Basin of the United States: The Upper Chalks (A, B, and C Chalk), the Marls (A, B, and C Marl), and the Lower Chalks (D Chalk and Fort Hays Limestone). In our study area, we find that the Upper Chalk has better reservoir-rock quality, moderate source-rock potential, stiffer rocks, and a higher fraction of compliant micro- and nanopores. On the other hand, the Marls have moderate reservoir-rock quality, and a higher source rock potential. Both the Upper Chalks and the Marls should have major economic potentials. The Lower Chalk has higher porosity and a higher fraction of micro-and nanopores; however, it exhibits poor source rock potential. The measured core data indicates large mineralogy, organic-richness, and porosity heterogeneities throughout the Niobrara interval at all scale. Introduction Unconventional petroleum systems are highly complex hydrocarbon resource plays both at the reservoir scale and at the pore scale (Aplin and Macquaker, 2011; Loucks et al., 2012; Hart et al., 2013; Hackley and Cardott, 2016). These organic-rich sedimentary plays, generally described as shale reservoirs, are composed of very fine silt-and clay-sized particles with grain sizes < 62.5 μm (Loucks et al., 2009; Nichols, 2009; Passey et al., 2010; Kuila et al., 2014; Saidian et al., 2014). They undergo extensive post-depositional diagenesis that transforms rock composition and texture, hydrocarbon storage and productivity, and reservoir flow features (Rushing et al., 2008; McCarthy et al., 2011; Jarvie, 2012; Milliken et al., 2012). Although some shale rock facies can retain depositional attributes during diagenesis, many critical reservoir properties, such as, mineralogy, pore structure, organic richness and present-day organic potential, etc., are significantly perturbed (Hackley and Cardott, 2016).