Shale gas is becoming increasingly important globally. The nature of these reservoirs pose special considerations in reserves estimation. What follows was written in 2001 and needs to be updated based on current experience. Nonetheless, some of the considerations mentioned remain appropriate. As reported in mid-2000, natural gas produced from shale in the US has grown to be approximately 1.6% (0.3 Tcf annually) of total gas production.
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.
Peng, Sheng (The University of Texas at Austin) | Liu, Yijin (SLAC National Accelerator Laboratory) | Ko, Lucy Tingwei (The University of Texas at Austin) | Ambrose, William (The University of Texas at Austin)
Oil production from the subsurface is essentially a process of multiphase flow; however, this process is poorly understood in shale because of the complex properties of its surface and structure of its pore systems. Where unrecovered fracturing fluid goes and how it displaces the in-situ oil in the shale matrix remain open questions. Understanding of wettability, an important factor influencing multiphase flow, is still vague for shale. In this study, an integrated tracer imbibition and multiscale imaging method is adapted for direct visualization of water/oil displacement by spontaneous imbibition, a process mimicking what occurs in the subsurface after hydraulic fracturing. Oil removal ratio by water spontaneous imbibition is quantified through image analysis. Five Wolfcamp Shale samples are used in this study. The major pore type in all the samples is identified via imaging to be clay mineral pores coated with organic matter. Water/oil displacement results indicate that the samples are water-wet, an opposite conclusion to the common concept for shale that organic matter is oil-wet. The sessile drop method, a commonly-used method for contact angle measurement, measures surface wettability, which may not be relevant to pore wettability and thus fluid flow in shale.
Water imbibition is an important process in the early phase of oil production in unconventional reservoirs (“shale” for simplicity) after hydraulic fracturing. A major fraction of the injected fracturing fluid, on average ~90% or even higher, remains in the formation (Vidic et al., 2013; Lu et al., 2018). However, where the unrecovered fracturing fluid goes and how it displaces the in-situ oil are still open questions. Previous research on spontaneous imbibition using inch-scale plug samples (Dehghanpour et al., 2013; Roychaudhuri et al., 2013; Dutta et al., 2014; Alvarez and Schechter, 2017) can explain, in part, the fluid loss after fracturing. However, for a shale rock that can contain significant heterogeneity in the pore system, understanding the spatial distribution of water uptake or water/oil displacement in a smaller scale (e.g., microscale) and its correlation with local mineralogy or organic matter distribution is more meaningful.
One of the major challenges associated with the exploitation of unconventional hydrocarbon resources is determining the optimal stimulation design. In this sense, it is necessary to understand how the parameters and variables involved in the completion process impact on production performance; the purpose is to act on such controllable variables and, consequently, maximize production and field development efficiency. Whereas physical driven tools frequently used in the oil industry are very helpful, they always imply a set of assumptions and simplifications regarding the system or phenomenon they try to model; they also require a large amount of unavailable or expensive data to calibrate them. Generally, different combinations of model parameters could explain well production behavior and for each of these solutions the way to optimize completion and development may be different.
Because of these drawbacks, and the big number of unconventional wells available, data-driven workflows have gained popularity in the last years. These models represent an excellent complement to physical driven tools in the attempt to optimize the completion and development strategy in shale plays. Several publications used both parametrical and non-parametrical models in the search of the Holy Grail: a statistical model capable of predicting how stimulation design affects productivity. The aim of this paper is to develop a novel methodology to understand the relation between formation parameters, completion design variables and production performance. An artificial neural network model (ANN) was chosen for this study.
Public production and stimulation data was merged with geological and petrophysical properties maps for almost 13.000 horizontal wells landed in Eagle Ford formation. A back propagation ANN algorithm was trained with this data-set and a cross-validation criterion was used for hyper-parameters optimization. Once the optimal model was selected, a bootstrap algorithm was run to assess for uncertainty in model prediction; these models were trained to determine which part of the input space presented enough data to get a clear signal and in which part the amount of data was not enough to differentiate signal from noise.
ANN models proved to be a fine method for this purpose obtaining R-Squared values between 0.5 and 0.7 for cross-validation sets. Significant relations were observed between production performance and lateral length, true vertical depth, porosity and fracture fluid intensity.
The methodology presented in this paper introduces a novel feature in comparison to previous publications regarding model uncertainty assessment. The coupling of the ANN model with the bootstrap re-sampling technique allowed to better understand which conclusions were statistically significant and which not, a fact that proved to be vital to correctly interpret results. It was demonstrated that such methodology is a good complement to physical-driven models in the aim to comprehend the relation between formation parameters, completion design variables and production performance.
The objective of our research is to reconcile the differences, in both age and relative stratigraphic position, between the Woodbine and Eagle Ford Groups in the outcrop and subsurface of the East Texas Basin. In the outcrop belt, organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Eagle Ford Group, where they overlie, and are separated by a regional unconformity from Early Cenomanian, organic-poor, and clay-rich mudstones of the Woodbine Group (Pepper Shale). In southern portions of the East Texas Basin, however, these same organic- and carbonate-rich Middle Cenomanian mudstones are mapped within the Maness Shale, which in turn, is overlain by Late Cenomanian to Turonian-aged mudstones (Pepper Shale) and sandstones (Dexter Formation) mapped as the Woodbine Group. Our approach to reconcile the lithostratigraphic juxtaposition between the two regions was to use chemo-stratigraphic and petrophysical data collected from the outcrops, as well as an adjacent shallow research borehole, in order to define key sequence stratigraphic units/surfaces, and then correlate the key units/surfaces from the outcrop belt into the subsurface.
Our research indicates that the Woodbine Group, is an older unconformity-bounded depositional sequence which is Early Cenomanian, whereas the Eagle Ford Group, is an overlying (younger) unconformity-bounded depositional sequence, which is Middle Cenomanian to Late Turonian. The unconformities that bound these units can be mapped from the outcrop belt into the subsurface of the East Texas Basin, to define coeval depositional sequences. As defined in this study, marine mudstones of the Woodbine Group, are clay- & silica-rich, TOC-poor, and characterized by low resistivity on geophysical logs. In general, the Woodbine Group thins, as well as transitions to more mudstone-prone facies, from northeast to southwest within the basin. While beyond the scope of this study, the Woodbine Group contains numerous higher-frequency sequences, which are stacked in an overall progradational (highstand) sequence set. The depositional profile of the unconformity which forms the top of this progradational succession sets up the relict physiographic (depositional shelf/slope/basin) profile for the overlying Eagle Ford Group.
Within the Lower Eagle Ford Formation, two high-frequency sequences, defined as the Lower and Upper Members, were defined. Within the Upper Eagle Ford Formation, three high-frequency sequences, defined as the Lower, Middle, and Upper Members, were defined. The Lower and Upper Members of the Lower Eagle Ford Formation, as well as the Lower Member of the Upper Eagle Ford Formation range from Middle Cenomanian to Early Turonian. These three high-frequency sequences contain marine mudstones that are carbonate- & TOC-rich, as well as clay- and quartz-poor, and are characterized by high resistivity values on geophysical logs. Furthermore, they are interpreted as a transgressive sequence set, with sequences that sequentially onlap, from older to younger, the inherited relict physiographic (depositional shelf/slope/basin) profile of the underlying Woodbine Group. In stark contrast, mudstones within the Middle and Upper Members of the Upper Eagle Ford Formation, which are Middle to Late Turonian, are clay-rich, TOC-poor, and characterized by low resistivity on geophysical logs. These two sequences, which are interpreted as a highstand sequence set, are sandstone-prone, and contain petroleum reservoirs that previously were incorrectly included within the Woodbine Group. Based on these correlations, updated sequence-based paleogeographic maps can be constructed for the first time across the East Texas Basin. These maps can in turn be used to define a robust portfolio of conventional, as well as unconventional tight-rock and source-rock, plays and play fairways, which are now based on a modern sequence stratigraphic, versus the traditional archaic lithostratigraphic framework.
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.
Geochemical data measured on oil samples produced from wells landed in the Austin Chalk, the Eagle Ford Formation, and the Buda Formation and on petroleum samples sequentially extracted from Upper Eagle Ford and Lower Eagle Ford marl and calcareous shale core pucks using several solvents were used to estimate the amount and properties of producible oil, immobile adsorbed/dissolved oil, and non-producible bitumen in those core samples. Crushed core samples obtained from two monitor wells located on the San Marcos Arch where Eagle Ford source-rock beds have reached different levels of maturity were sequentially extracted using a weak solvent (cyclohexane; CH), two stronger solvents (toluene and DCM), and a very strong solvent (chloroform-methanol; CM). Similar geochemical data were measured on the core extracts (after heating them to evaporate the solvents), and on native and topped oil samples. The CH extracts exhibit n-alkane profiles characteristic of crude oil, but extracts obtained using stronger solvent do not resemble oil. C15-C35 HC compounds present in produced oils are more abundant in CH extracts (which principally contain producible oil and adsorbed/dissolved oil) than in extracts obtained using stronger solvents (which principally contain bitumen). The SARA composition of topped oil samples also is more similar to the composition of core extracts obtained using CH than extracts obtained using stronger solvents (which contain significantly more resins and asphaltenes). The extract obtained from lower-maturity marl core pucks using CH contains much more sulfur (≈4.4 wt%) than the CH extract obtained from more thermally mature marl core pucks (≈2.0 wt%). Calibrations between the API gravity, C7 temperature, and sulfur content of native and topped oil samples were used to estimate the gravity and sulfur content of core extracts obtained using different solvents. The amount of resin-rich immobile oil in the core extracts was estimated using reasonable assumptions about the composition of that component. The Lower Eagle Ford marl at the higher-maturity monitor well contains ≈0.35 wt% of ≈30-31°API producible oil and ≈0.27 wt% of non-producible bitumen. That reservoir contains only ≈0.12 wt% of ≈27°API producible oil and ≈0.38 wt% of non-producible bitumen at the lower-maturity monitor well. The LEF calcareous shale contains approximately the same amount of producible oil as the overlying marl at the more mature monitor well, but it contains much less non-producible bitumen (≈0.12 wt%).
Baek, Seunghwan (Texas A&M University) | Akkutlu, I. Yucel (Texas A&M University) | Lu, Baoping (Sinopec Research Institute for Petroleum Engineering) | Ding, Shidong (Sinopec Research Institute for Petroleum Engineering) | Xia, Wenwu (Harding Shelton Petroleum Engineering & Technology Limited)
Routine history-matching and reservoir calibration methods for horizontal wells with multiple hydraulic fractures are complex. Calibration of important fracture and matrix quantities is, however, essential to understand the reservoir and estimate the future recoveries. In this paper, we propose a robust method of simulation-based history-matching and reserve prediction by incorporating an analytical solution of production Rate Transient Analysis (RTA) as an added constraint. The analytical solution gives the fracture surface area contributing to the drainage of the fluids from the matrix into the fractures. The surface area obtained from the RTA is the effective area associated with the production—not total area. It is the most fundamental and the most significant quantity in the optimization problem. Differential evolution (DE) algorithm and a multi-scale shale gas reservoir flow simulator are used during the optimization. We show that the RTA-based optimization predicts the quantities related to completion design significantly better. Further, we show how the estimated total fracture surface area can be used to measure the hydraulic fracturing quality index, as an indication of the quality of the well completion operation. The most importantly, we predict that the fractures under closure stress begin to close much sooner (100 days) than the prediction without the RTA-based fracture surface area constraint. The deformation continues under constant closure stress for about 20 years, when the fractures are closed nearly completely. This work attempts to use the traditional reservoir optimization technologies to predict not only the reserve but also the life of the unconventional well.
Cudjoe, Sherifa (University of Kansas) | Barati, Reza (University of Kansas) | Marshall, Craig (University of Kansas) | Goldstein, Robert (University of Kansas) | Tsau, Jyun-Syung (University of Kansas) | Nicoud, Brian (Chesapeake Energy) | Bradford, Kyle (Chesapeake Energy) | Baldwin, Amanda (Chesapeake Energy) | Mohrbacher, David (Chesapeake Energy)
Microscopic analysis including transmitted light, UV epifluorescence, BSE, and FIB-SEM carried out on Lower Eagle Ford (LEF) shale samples, selected from similar depths, show complex depositional fabrics, kerogen, migrated organic matter, and diagenetic history. It is well known that LEF samples contain depositional kerogen and migrated organic matter. Much of the migrated organic matter occupies diagenetically reduced primary porosity. Some of this organic matter is not porous, while some contains large pores and other contains a fine network of nanopores. Where thermal maturity is one control on porosity in organic matter, there is also a control of composition and origin. This paper investigates the chemistry of organic matter in-situ using Raman spectroscopy, to begin to understand what, other than thermal maturation, leads to porosity in both depositional kerogen and migrated organic matter. This is used to evaluate the nature of the pores in LEF, and to assess the impact of hydrocarbon gas injection on organic porosity.
Thin sections of the lower Eagle Ford shale samples are examined with transmitted light microscopy to select samples for Raman spectroscopy, after studying with FIB-SEM to analyze distribution of porosity in organic matter. In the Raman spectra, the separation between the D and G bands, the width of the G-band, and the intensity ratio of the D-to-G-bands are typically ascribed to maturity-related changes. However, composition and origin of the organic matter may also have an effect. The Raman spectra are analyzed to characterize the different types of porous and non-porous organic matter at the same depth. Then, samples are subjected to gas injection in the laboratory in preparation for a gas huff-n-puff operation, and changes in Raman spectra are analyzed once again.
BSE images show depositional kerogen is found as isolated bodies, lamellar forms, and fine material disseminated in the matrix. Transmitted light and UV microscopy reveal that some of this is non-fluorescent and some is fluorescent. Cement-reduced intraparticle pores, other primary pores, intercrystalline pores, and micro-fracture and micro-breccia pores contain migrated organic matter (OM), none of which fluorescences in UV. FIB-SEM images show the migrated OM has either spongy nanopores, larger bubble/meniscate pores, or no pores, all in the same sample. Raman spectroscopy analysis on the different types of organic matter show examples where both G- and D- bands are visible with distinctive separation, intensity ratio, or width, or where the D-band is absent. Moreover, the effect of gas injection on the different types of organic matter is inferred from the G- and D- bands.
This work improves our understanding of organic pore generation and modification, which influences pore size distribution and pore tortuosity, the underlying factors in gas huff-n-puff recovery in shales. It expands the utility of Raman micro-spectroscopy as a tool in understanding the evolution of pore systems and organic constituents in shale. It also presents an in-situ molecular structural study of the effect of hydrocarbon gas huff-n-puff on the different types of organic matter.
Organic-rich shales are often found to be strongly anisotropic. Their dynamic and static elastic properties depend on their intrinsic anisotropy and the anisotropic in-situ stress field. We report pseudo-triaxial tests on Eagle Ford shales with axial load normal and parallel to beddings, respectively. From the experimental data, regardless of being from dynamic or static measurements, the elastic parameters present strong angular dependences: a much higher Young's modulus and a higher Poisson's ratio in the bedding-parallel direction. The deviatoric load orientation with respect to beddings leads to different nonlinearity and hysteresis in the stress-strain curves. From the microstructural point of view, the deviatoric load induces elastic compaction as well as some non-elastic processes such as frictional sliding and crushing of asperities at crack surfaces or grain boundaries. Hence, the statically derived parameters are sensitive to the anisotropic stress state and load-unload history. However, those microstructural alternations bring very small effects on the dynamic parameters. The dynamic Young's moduli are systematically higher than the static Young's moduli, whereas the dynamic Poisson's ratios are lower in the loading process and higher in the unloading process than the static Poisson's ratios. When the load is initially reversed, the static parameters approach the corresponding dynamic parameters, reflecting the rock bulk properties without any frictional sliding effects.
Shales comprise more than 70% of the drilled formations in most sedimentary basins and form the seal or source rocks of many hydrocarbon reservoirs (Vernik and Nur, 1992). As the unconventional oil and gas boom, the organic-rich shales have drawn global attention in the past fifteen years. These shales serve as both source rocks and reservoirs in resource shale plays. Because of the extremely low porosity and permeability, extracting economic hydrocarbon flows from such reservoirs requires the applications of horizontal drilling and hydraulic fracture stimulation techniques (Rickman et al., 2008). To this end, their geo-mechanical properties, such as Young's modulus and Poisson's ratio, require a better understanding in consideration of the importance in predicting the in-situ stress profile, evaluating brittleness, and optimizing horizontal well and hydraulic fracture designs (Higgins et al., 2008; Rickman et al., 2008).