Carbonate reservoir rocks of the Najmah formation in Kuwait, with low porosity and low permeability, have been characterized using integrated digital and physical rock analyses methods. High-resolution imaging and analyses determined the microstructural characters of mineral matrix, organic matter (OM) distribution, organic and inorganic pore types, size distribution, and permeability variation within this kerogen-rich Late Jurassic stratigraphic unit.
Considerable heterogeneity of porosity and permeability was observed in the 100-ft studied interval of the Najmah Formation. Two-dimensional scanning electron microscopy (2D-SEM) imaging and three-dimensional focused ion beam SEM (3D-FIB-SEM) imaging highlighted the different types of porosities present within the formation rock. At each depth, several 2D-SEM images were used for characterization and selection of representative locations for extracting 3D FIB-SEM volumes. The 3D volumes were digitally analyzed and volumetric percentages of OM and total porosity were determined. The porosity was further analyzed and quantified as connected, nonconnected, and associated with organic matter. Connected porosity was used to compute absolute permeability in the horizontal and vertical directions in the area of interest.
Porosity associated with OM is an indicator of OM maturity and flow potential. It has been categorized as pendular type, spongy large grain, spongy small grain, fracture porosity within the OM, grain boundary fractures and intergranular porosity covering the entire OM. Permeability is not only influenced by porosity within OM or even apparent transformation ratio (ATR), it is also dependent on pore connectivity, pore sizes, and heterogeneity (e.g., high-permeability streaks). For high porosity samples, almost all pores are connected and contributing to permeability. For low porosity samples with high permeability, the flow is mainly through microfractures. It is possible that intergranular clay pores in highly thermally mature rocks were originally filled with OM and that, during progressive thermal maturation, transformation of OM to hydrocarbon(s) removed much of the pore filling OM.
It has also been observed that, although the total organic carbon (TOC) content of the rocks is significant (up to 18 wt%), and good maturity index (VR0>1), only few examined samples show good connected porosity within the OM. It is essential to evaluate the porosity within the OM thorough high-resolution measurements for pinpointing the prospective layers for future stimulated horizontal wells in this organic-rich source unit. These intervals can be considered as the potential sweet spots after integration with detailed petrophysics and geomechanical parameters for optimized well planning and completion design.
The investigation of the effect of hydration swelling on induced fracture generation and the resulted permeability in shale has considerably expanded in recent years. However, only a few experiments under anisotropic compressive stress conditions have been done in this area. The experiment methodology that was presented in this paper can be used to study the effect of hydration swelling on fracture initiation and propagation, and the change of shale permeability under anisotropic compressive stress conditions. An artificial fracture through a core was created before the test to simulate the hydraulic fracture generated during the fracturing process. Distilled water was used to simulate the hydraulic fracturing fluid. A CT scanner was used to collect the CT images of fracture development. A digital pressure transducer was used to monitor the upstream pressure change, and the downstream pressure was kept at atmosphere pressure. We, for the first time, combined water adsorption, stress anisotropy conditions, and shale permeability change into one test. Five tests were conducted: three tests underwent stress anisotropy, and the other two tests employed stress isotropy. These tests were continuously exposed to working fluids at a constant flow rate. From the results, the increase in the apparent weight of cores showed that water could be adsorbed into shale samples during the tests. In shale samples with stress anisotropy conditions, fractures through the core were generated. More fractures were created under larger differential stress conditions. The upstream pressure decreased when fractures through the core were generated or particle detachment happened. The decrease in pressure indicates that hydration may be beneficial to shale permeability recovery. To differentiate the effect of hydration and stress anisotropy on fracture generation, one sequential imbibition test was conducted (oil, then water). Fractures can be generated if the imbibition fluid changed from oil to water. The results supported the previous result that hydration may induce fractures (
Researchers mapped 251 faults in the North Texas home of the Barnett Shale, the birthplace of the shale revolution, finding that wastewater injection there “significantly increases the likelihood for faults to slip.” Using maglev technology, a new artificial lift system seeks to boost production output by sucking down reservoir pressure from inside the wellbore and from inside the reservoir. Leaders from two large US onshore rig contractors said their expectations that the rig-count slide would hit a second-quarter bottom were off and are now refraining from making new predictions as to when it will end. The Unconventional Resources Technology Conference is like visiting an oilfield theme park for engineers and geoscientists. This year those traveling to the conference for a glimpse of what is possible in exploration and production will also focus on ways to improve short-term profitability.
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.
Connectivity of the pore system is crucial for production of hydrocarbons from unconventional resources. In shales, pore throats critically control and limit permeability. Even if larger pores are the dominant pore size, small pores throats could ultimately control the access to that pore space. Mercury injection capillary pressure (MICP) measurements are commonly made to determine pore throat size distributions. Results for shales usually show large injection volumes associated with pore throats just several nanometers in diameter. The existence of these small pore throats has also been confirmed by Focused Ion Beam/Scanning Electron Microscope (FIB/SEM) analysis. One of the unique properties of mercury is that it is non-wetting to both matrix phases present in organic-rich shales; therefore, it can access pore systems in both organics and inorganics. MICP measurements dynamically alter the pore structure through pore compressibility which intrinsically depends on the aspect ratios of the pores; crack like pores, with very high aspect ratios, may close at low pressures and may not be sampled by MICP. The connectivity of the pore space and how much of it is accessed by MICP remains poorly understood.
Here we report on shale samples that have undergone MICP followed by Micro X-ray Computed Tomography (μXCT) and FIB/SEM imaging. μXCT results show that not all regions of the shale samples were accessed uniformly by MICP. Mercury is observed going into fractures and penetrating into the shale matrix. The distance away from the fractures and the percentage of the sample volume accessed by mercury has been calculated. Some samples, such as the Tuscaloosa Marine Shale, showed mercury penetration throughout specific layers in the sample, whereas Eagle Ford samples showed mercury penetration more uniformly and on average of almost 150 μm away from the fractures with almost 60% of the entire sample volume accessed by the mercury. These μXCT results suggest that mercury is not fully accessing all the pore space of the sample even at 60,000 psi which corresponds to a pore throat radius of 1.8 nm.
Cryo FIB/SEM was used to further investigate mercury intrusion into the shale matrix at the nanometer scale. Frozen droplets of mercury were observed in pores as small as 30 nm which corresponds to an injection pressure of 6,000 psi. The mercury clearly accessed the organic pores and remained after pressure was reduced. This is also reflected in the hysteresis observed in the MICP spectra captured during pressurization and depressurization. The magnitude of the hysteresis is a consequence of the differences between pore bodies and pore throats. Like the μXCT, SEM results show that intrusion of mercury into the sample is not uniform indicating that many of the pores are not connected to the outside of the sample. These results suggest that pore connectivity in shales may be very limited, and the volume accessible may not extend far from fractures in the shales.
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.
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).
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.
The results of an investigative research study on the impact of the in-situ stress, shale matrix composition, maturity, amount of organic matter and clay composition affecting the anisotropy level of the geomechanical properties have been discussed in this paper. These parameters are among the key factors known to control the geomechanical properties in organic-rich shale formations. Organic-rich shale formations with different mineralogical compositions and organic matter maturity have been measured under uniaxial and triaxial stress state along with the field data from limited number of the wells in these shale basins where the core samples are obtained to investigate the role of each factor on the level of geomechanical anisotropy.
The field data has been analyzed to compare the trends obtained from the laboratory data collected under customized controlled field conditions to the field data trends. Artificial Neural Network (ANN) analysis was used in wells without full log suits to obtain the anisotropic geomechanical parameters. The results highlight the maturation, organic richness and clay composition effect on the recorded field data as well as the geomechanical properties obtained from the laboratory measurements.
The stress and fluid sensitivity of shale formations have been well recognized since the early days of conventional reservoir drilling, completion and production operations as they typically require special attention for minimizing wellbore instability during drilling and maintaining high integrity wells throughout the life cycle of these wells. Shales are highly heterogeneous and anisotropic formations and their source rock characteristics also have introduced further complexities with the organic matter and compositional variations throughout the areal extent of the reservoirs. These variations and their alterations as a function of the level of maturity of the organic matter require further study for better understanding of the differences and similarities between the seal shales and reservoir shales and the role of the organic matter and its maturity level in these differences. One of the critical aspects of the organic matter presence is in quantification of shale mechanical properties and strength and their direction dependence for successful field development. The level of maturity of the organic matter also influences the mechanical, acoustic, petrophysical and failure properties of organic rich shale formations. The mineralogical composition typically deviates from carbonate rich to quartz rich in the rock matrix with clay and organic matter amount and distribution heterogeneity in the reservoir. The layered structure introduced by the depositional history of the formation along with the heterogeneity in the distribution of organic matter result in various degree of anisotropy in reservoir properties (Sondergeld and Rai, 2011; Vernik and Milovac, 2011). A better understanding on the anisotropic characteristics of the shale formations and key parameters impacting the anisotropy is essential for field operational success from exploration studies for seismic attributes to reservoir characterization, drilling and hydraulic fracture design and production optimization.
The expansion of unconventional petroleum resource exploration and production in the United States has led to an increase in source rock characterization efforts, particularly related to bulk organic and mineralogical properties. To support the analytical and research needs of industry and academia, as well as internal work, the U.S. Geological Survey (USGS) has collected and prepared shale geochemical reference materials (GRMs) from several major shale petroleum systems in the U.S. The sources of these materials are the Late Cretaceous Boquillas (lower Eagle Ford-equivalent) Formation (roadcut near Del Rio, TX), Late Cretaceous Mancos Shale (outcrop near Delta, CO), Devonian–Mississippian Woodford Shale (outcrop near Ardmore, OK), Late Cretaceous Niobrara Formation (quarry near Lyons, CO), Middle Devonian Marcellus Shale (creek bed in LeRoy, NY), and Eocene Mahogany zone oil shale of the Green River Formation (oil shale mine near Rifle, CO). Of particular interest in the development of these GRMs has been the examination of variability between laboratories and specific methods or instruments in commonly made measurements, including major- and trace-element concentrations, X-ray diffraction (XRD) mineralogy, total organic carbon (TOC) content, and programmed pyrolysis (PP) parameters. For the component concentrations and parameters we measured, the techniques and instrument types included: (1) elemental analysis by X-ray fluorescence, inductively coupled plasma mass spectrometry, and instrumental neutron activation analysis; (2) XRD mineralogy with various preparatory methods (spray drying or micronizing with or without internal standard); (3) TOC by combustion with infrared detection after carbonate removal or the PP approach; (4) PP by Rock-Eval 2 or more recently developed instruments (Rock-Eval 6, Source Rock Analyzer or SRA, and Hydrocarbon Analyzer With Kinetics or HAWK). Overall, the results showed that the selected shales cover a wide range of source rock organic and mineralogical properties. Major- and trace-element chemistry results showed low heterogeneity consistent with other USGS GRMs. Comparison of TOC results showed coefficients of variation (COV) of around 5% and the most consistent organic geochemical results between different laboratories and methods. Arguably the most relevant PP measurement, S2 or kerogen hydrocarbon-generating potential (mg-HC/g-rock), showed a somewhat wider range of variability than TOC (COV ~10%), but was consistent between the three modern instruments and the industry-standard Rock-Eval 2. Major phase mineralogy (mineral concentrations ≥10 wt. %, organic-free basis) were comparable between laboratories, but variability in minor phase identification and quantification was observed. Utilization of these shale GRMs as quality control samples and testing materials is expected to help support analytical and experimental efforts in the continued development of unconventional petroleum resources.
Berawala, Dhruvit Satishchandra (Department of Energy and Petroleum Technology, University of Stavanger, Norway and The National IOR Centre of Norway) | Østebø Andersen, Pål (Department of Energy Resources, University of Stavanger, Norway and The National IOR Centre of Norway)
Only 3-10 % of gas from tight shale is recovered economically through natural depletion, demonstrating a significant potential for enhanced shale gas recovery (ESGR). Experimental studies have demonstrated that shale kerogen/organic matter has higher affinity for CO2 than methane, CH4, which opens possibilities for carbon storage and new production strategies.
This paper presents a new multicomponent adsorption isotherm which is coupled with a flow model for evaluation of injection-production scenarios. The isotherm is based on the assumption that different gas species compete for adsorbing on a limited specific surface area. Rather than assuming a capacity of a fixed number of sites or moles this finite surface area is filled with species taking different amount of space per mole. The final form is a generalized multicomponent Langmuir isotherm. Experimental adsorption data for CO2 and CH4 on Marcellus shale are matched with the proposed isotherm using relevant fitting parameters. The isotherm is first applied in static examples to calculate gas in place reserves, recovery factors and enhanced gas recovery potential based on contributions from free gas and adsorbed gas components. The isotherm is further coupled with a dynamic flow model with application to CO2-CH4 substitution for CO2-ESGR. We study the feasibility and effectiveness of CO2 injection in tight shale formations in an injection-production setting representative of lab and field implementation and compare with regular pressure depletion.
The production scenario we consider is a 1D shale core or matrix system intitally saturated with free and adsorbed CH4 gas with only left side (well) boundary open. During primary depletion, gas is produced from the shale to the well by advection and desorption. This process tends to give low recovery and is entirely dependent on the well pressure. Stopping production and then injecting CO2 into the shale leads to increase in pressure where CO2 gets preferentially adsorbed over CH4. The injected CO2 displaces, but also mixes with the in situ CH4. Restarting production from the well then allows CH4 gas to be produced in the gas mixture. Diffusion allows the CO2 to travel further into the matrix while keeping CH4 accessible to the well. Surface substitution further reduces the CO2 content and increases the CH4 content in the gas mixture that is produced to the well. A result of the isotherm and its application of Marcellus experimental data is that adsorption of CO2 with resulting desorption of CH4 will lead to a reduction in total pressure if the CO2 content in the gas composition is increased. That is in itself an important drive mechanism since the pressure gradient driving fluid flow is maintained (pressure buildup is avoided). This is a result of CO2 being found to take ~24 times less space per mol than CH4.