Variations In Rock Properties Research Articles

An adjoint-based optimization method for jointly inverting heterogeneous material properties and fault slip from earthquake surface deformation data

SUMMARY Analysis of tectonic and earthquake-cycle associated deformation of the crust can provide valuable insights into the underlying deformation processes including fault slip. How those processes are expressed at the surface depends on the lateral and depth variations of rock properties. The effect of such variations is often tested by forward models based on a priori geological or geophysical information. Here, we first develop a novel technique based on an open-source finite-element computational framework to invert geodetic constraints directly for heterogeneous media properties. We focus on the elastic, coseismic problem and seek to constrain variations in shear modulus and Poisson’s ratio, proxies for the effects of lithology and/or temperature and porous flow, respectively. The corresponding nonlinear inversion is implemented using adjoint-based optimization that efficiently reduces the cost function that includes the misfit between the calculated and observed displacements and a penalty term. We then extend our theoretical and numerical framework to simultaneously infer both heterogeneous Earth’s structure and fault slip from surface deformation. Based on a range of 2-D synthetic cases, we find that both model parameters can be satisfactorily estimated for the megathrust setting-inspired test problems considered. Within limits, this is the case even in the presence of noise and if the fault geometry is not perfectly known. Our method lays the foundation for a future reassessment of the information contained in increasingly data-rich settings, for example, geodetic GNSS constraints for large earthquakes such as the 2011 Tohoku-oki M9 event, or distributed deformation along plate boundaries as constrained from InSAR.

Geomechanical assessment of a large-scale CO2 storage and insights from uncertainty analysis

Geological storage of CO2 provides a feasible solution to curb CO2 emissions to the atmosphere and relieve climate change. However, as CO2 is injected into the reservoir, the increased pore pressure may result in fault reactivations or damaging geomechanical changes to the caprock, which could be detrimental to the containment of injected CO2. On the other hand, uncertainty is inevitable due to the limited information of the complex subsurface system. In this study, we develop a workflow to assess the geomechanical impact of CO2 geological storage and include management of sources of uncertainties associated with the subsurface system. We utilize the hypothetical large-scale carbon sequestration situated in the Southern San Joaquin Valley in California, USA as a case study. We firstly set up a three-dimensional (3D) geomechanical model using a non-linear quasi-static finite element method. The applied workflow has features including: (1) Coulomb friction behavior to model fault slippage, (2) CAD representation of land surface and faults, (3) non-uniform pressure increase based on dynamic reservoir simulations, and (4) variable rock properties for formation layers. We perform uncertainty analyses using a response surface methodology and a Box-Behnken design to assess the significance of subsurface uncertainties to geomechanical responses. We find that the intact caprock will not have a shear failure even considering the subsurface uncertainties. However, the faults can reactivate and give potential flow pathways in the caprock. The presented workflow integrates advanced geomechanical models and uncertainty analysis, which can be readily applied to other CO2 storage projects to mitigate geomechanical sources of risk.

Thermal Magnetic Properties Variation of Rock During In-Situ Combustion Process

Summary In-situ combustion (ISC) has been proven as a promising technique for the extraction of heavy oils. It has been used in oil fields since the 1920s; however, it is still not as widely used as steam injection. One of the difficulties limiting its wide application is monitoring and controlling the movement of the combustion front. This work is aimed at studying the change in the properties of rock during the ISC process, which is expected to be used for developing an effective monitoring method of the combustion front movement. Rock samples before and after the ISC process were obtained from the Xinjiang Oil field (China) where an ISC industrial pilot has been implemented. In the temperature range of lower than 500℃, the minerals may only alter slightly. Therefore, it is difficult to determine whether the rock was heated or not during the ISC processes using general mineralogical or geochemical methods, for example, X-ray diffraction. This work takes a comprehensive approach to study the variation of rock properties. Magnetic analysis was chosen as the primary method since a very tiny change in the mineral composition during heating leads to profound changes in the magnetic properties. We analyzed magnetic susceptibility (MS), natural remanent magnetization (NRM), hysteresis parameters and thermomagnetic data. In addition, we performed differential thermomagnetic analysis (DTMA) for tracing magnetic minerals based on their Curie temperatures as well as for monitoring transformations in magnetic minerals during heating. Simultaneously, X-ray diffractometer (XRD), optical microscope for thin-sections, and organic content measurements were used as assistive methods to get a comprehensive evaluation on the variation of rock. We found that there is a big difference in magnetic minerals between the initial samples (not subjected to the ISC process) and burned samples from different wells and depths in the ISC pilot. Several magnetic clusters with different coercive force and domain structure were found in these samples. Based on the difference in magnetic properties, we found that the burned samples were heated to different temperatures during the ISC process. In addition, for some rock samples, the heating temperature during the ISC process was determined, and an analysis was made of the propagation of the combustion front. The thermal magnetic properties variation of rock during the ISC process is obvious, which makes it promising to be used for monitoring the propagation direction of the combustion front. Theoretical calculations of magnetic anomalies that occur due to changes in the magnetic properties of rocks during the ISC process indicate the possibility of the detection of such anomalies from the Earth’s surface through high-precision magnetic surveys. The findings in this work provide a theoretical base and direction for developing combustion front monitoring technologies.

A Review of Techniques for Measuring the Biot Coefficient and Other Effective Stress Parameters for Fluid-Saturated Rocks

Abstract Predicting the behavior of a saturated rock with variations in pore fluid pressure during geo-energy production and storage, deep geological disposal of nuclear wastes, etc. with skeletal mechanical behavior in the linear elastic range is carried out using the isothermal theory of poroelasticity that incorporates Biot's effective stress principle. For conditions that are not within linear elasticity, other effective stress coefficients are used. Several experimental methods for determining Biot's and other effective stress coefficients have been documented in the literature. The objective of this study is to review the fundamentals of these techniques, their advantages and disadvantages, and to include several case studies. Current techniques for Biot's coefficient are based on different premises: jacketed and unjacketed bulk moduli or compressibility values; volume changes of the bulk and pore fluid from a drained triaxial test on a saturated sample; isotropic-isochoric compression tests on a saturated sample; matching volumetric strains for dry and saturated samples; estimation of the Biot coefficient from other poroelastic parameters; and approximation of the jacketed bulk modulus from ultrasonic wave velocities and/or unjacketed bulk modulus from the mineralogical compositions. Other effective stress coefficients are based on matching failure envelopes for dry and saturated samples and variations of rock properties (such as volumetric strain, permeability, and ultrasonic wave velocities) with respect to confining stress and pore pressure. This article discusses variations in Biot's and other effective stress coefficients produced using the different techniques and how factors such as pore geometry, test conditions, stress path, and test temperature affect the coefficients.

Case Study: Oil Production Optimized With Autonomous Inflow Control Devices Offshore Malaysia

_ Advanced well completions have proven to be an effective method of moderating gas breakthrough while producing a thin oil rim when placed in a heterogenous, carbonate reservoir. In addition, several studies have proven that the application of autonomous inflow control devices (AICDs) acts as a type of insurance policy against geological and dynamic reservoir uncertainties to reduce the risk and variation in the expected oil production profiles. During 2019 and 2020, Sarawak Shell Berhad conducted development campaigns in the central Luconia province in a thin oil rim carbonate reservoir offshore Sarawak, Malaysia. The horizontal, approximately 6,000-ft development wells were expected to intersect with different geological layers with varying rock properties, resulting in an uneven reservoir influx toward the wellbore. Oil production from these wells was expected to suffer severely from early gas and water breakthrough. To produce the oil rim without the risk of early gas production, global production optimization specialist, Tendeka, incorporated FloSure AICDs in the lower completion design at the reservoir interface along the horizontal section of the wells. As an active flow control device, the technology delivers a variable flow restriction in response to the properties of the fluid entering the wellbore and the rate of flow passing through it to help manage gas coning/cusping risks. The fluid is then lifted to surface with natural in-situ gas lift built into the upper completion. A three-phase development was planned for the field, and to date, two phases have been completed. New-Generation ICD The first AICD completion was installed in Norway in 2008 and widely implemented in the Troll field in 2013 with very encouraging results (SPE 159634). However, its use is relatively new to both the Asia Pacific region and this type of application. Similar to a standard ICD which balances the influx of reservoir fluids, the FloSure AICD will delay the production of unwanted effluents prior to their breakthrough (proactive solution). However, once a breakthrough occurs, the device restricts the production of unwanted effluents with lower viscosity, such as gas (in light oil applications) and both gas and water in viscous oil production (reactive solution) (OTC 30403, OTC 30363, SPE 193718). The device delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through it. Flow enters the device through the nozzle in the top plate of the body. This impacts the disk and spreads radially through the gap between the disk and the top plate, then turns around the top plate and is discharged through several outlet ports in the body (Fig. 1). The overall geometry of the device is critical to its ability to balance these forces effectively and create the desired fluid-dependent pressure drop. Field A employed 7.5-mm AICD valves to match the performance of the devices to the potential well flow rate. The oil, water, and gas viscosities are 0.40 cP, 0.27 cP, and 0.018 cP, respectively, at downhole flow conditions.

Rock Properties and Modelled Stress State Uncertainties: A Study of Variability and Dependence

The safety and sustainability of subsurface applications requires a profound knowledge of the local stress state which is frequently assessed using 3D geomechanical-numerical models. Various factors lead to generally large uncertainties in these models. The variabilities in the rock properties as one of the sources of uncertainties and their influence on the modelled stress state is addressed herein. A generic 3D geomechanical-numerical model is used to investigate the influence of different distributions of variability and their effect on different stress states. The variability in rock properties clearly affects the uncertainties in the stress state in a positive correlation with differences that depend on the affected component of the stress tensor. The basic observation is that largest uncertainties are observed in the normal components of the stress tensor where the variabilities apparently are most effective. The same rock property variabilities affect the shear components uncertainties to a significantly lesser extent. Variabilities in the Young’s modulus and the Poisson’s ratio chiefly affect the uncertainties in sigma _{xx} and sigma _{yy}. The density variability, however, leads to highest uncertainties in sigma _{zz}. In general, variabilities in the Young’s modulus are most effective, followed by the Density and then the Poisson’s ratio. Furthermore, an influence of the tectonic stress regime on how the variability in the rock properties affects the stress state is observed. At the same time only a small effect is observed for different stress magnitudes. The eventual uncertainties in a modelled stress state depend not only on the uncertainties in the rock properties but also whether the uncertainties are found mainly in the Young’s modulus, the Poisson’s ratio or the Density. These findings indicate the importance to regard variabilities in rock properties as a source for significant uncertainties in geomechanical-numerical models. It is proposed to use the derived relations for an inexpensive quantification of uncertainties by means of a post-computation assignment of uncertainties to a stress model.

An advanced computational intelligent framework to predict shear sonic velocity with application to mechanical rock classification

Shear sonic wave velocity (Vs) has a wide variety of implications, from reservoir management and development to geomechanical and geophysical studies. In the current study, two approaches were adopted to predict shear sonic wave velocities (Vs) from several petrophysical well logs, including gamma ray (GR), density (RHOB), neutron (NPHI), and compressional sonic wave velocity (Vp). For this purpose, five intelligent models of random forest (RF), extra tree (ET), Gaussian process regression (GPR), and the integration of adaptive neuro fuzzy inference system (ANFIS) with differential evolution (DE) and imperialist competitive algorithm (ICA) optimizers were implemented. In the first approach, the target was estimated based only on Vp, and the second scenario predicted Vs from the integration of Vp, GR, RHOB, and NPHI inputs. In each scenario, 8061 data points belonging to an oilfield located in the southwest of Iran were investigated. The ET model showed a lower average absolute percent relative error (AAPRE) compared to other models for both approaches. Considering the first approach in which the Vp was the only input, the obtained AAPRE values for RF, ET, GPR, ANFIS + DE, and ANFIS + ICA models are 1.54%, 1.34%, 1.54%, 1.56%, and 1.57%, respectively. In the second scenario, the achieved AAPRE values for RF, ET, GPR, ANFIS + DE, and ANFIS + ICA models are 1.25%, 1.03%, 1.16%, 1.63%, and 1.49%, respectively. The Williams plot proved the validity of both one-input and four-inputs ET model. Regarding the ET model constructed based on only one variable,Williams plot interestingly showed that all 8061 data points are valid data. Also, the outcome of the Leverage approach for the ET model designed with four inputs highlighted that there are only 240 “out of leverage” data sets. In addition, only 169 data are suspected. Also, the sensitivity analysis results typified that the Vp has a higher effect on the target parameter (Vs) than other implemented inputs. Overall, the second scenario demonstrated more satisfactory Vs predictions due to the lower obtained errors of its developed models. Finally, the two ET models with the linear regression model, which is of high interest to the industry, were applied to diagnose candidate layers along the formation for hydraulic fracturing. While the linear regression model fails to accurately trace variations of rock properties, the intelligent models successfully detect brittle intervals consistent with field measurements.

Petrophysical analysis and mudstone lithofacies classification of the HRZ shale, North Slope, Alaska

Mudstone is vertically and laterally heterogeneous in terms of variations in mineral composition, organic carbon content, and petrophysical properties. The purpose of this study is to classify mudstone lithofacies within the High Radioactive Zone (HRZ) Shale on the North Slope, Alaska, based upon mineralogy, total organic carbon (TOC), and petrophysical properties to interpret their distributions and depositional/diagenetic environments. We integrate core data from six wells and well logs from 18 wells to analyze the variations in rock properties in the HRZ Shale. Analysis of cores at multiple scales of resolution by techniques, including X-ray diffraction (XRD), trace element geochemistry, pyrolysis, and scanning electron microscopy (SEM) are integrated with conventional and advanced wireline logging suites (including pulsed neutron spectroscopy [PNS]) to map vertical and lateral variation in mudstone lithofacies across the study area. Results show that the HRZ Shale exhibits a high degree of vertical and lateral heterogeneities in mineralogy, TOC, and petrophysical properties. This shale formation is composed of 12 lithofacies: pyritic organic mixed shale, organic mixed shale, pyritic mixed shale, mixed shale, pyritic organic mudstone, organic mudstone, pyritic grey mudstone, grey mudstone, pyritic organic siliceous shale, organic siliceous shale, pyritic siliceous shale, and siliceous shale. Quartz abundance is generally higher in the west, and clay proportions increase from the southwest to the northeast of the study area. The TOC content is variable across the HRZ Shale, ranging from 1.5 to 15 wt%. The lithofacies are influenced by depositional conditions, diagenesis, redox conditions, organic matter productivity, and preservation.

Multistage nonlinear model predictive control for pumping treatment in hydraulic fracturing

AbstractHydraulic fracturing has gained increasing attention as it allows the constrained natural gas and crude oil to flow out of low‐permeability shale formations and significantly increase production. Perilous operating states of extremely high pressure also raise some safety concerns, requiring us to formulate an appropriate dynamic model, and provide a careful engineering control to ensure safe operating conditions. Moreover, uncertainties due to spatially varying rock properties increase the difficulties in control of the fracturing process. In this work, we formulate a first‐principles model by considering the fracture evolution, mass transport of substances in the slurry, changing fluid properties, and the monitored operating pressure on the ground level. Next, we implement nonlinear model predictive control (NMPC) to control the process under a set of final requirements and process constraints. Our results show that the performance of standard NMPC degrades when the rock uncertainty causes the parameter mismatch between the process and the predictive model in the controller. With standard NMPC, designed with a nominal model, the process fails to meet the terminal requirements of fracture geometry, and pressure is violated in one of the parameter mismatch cases. Therefore, we resort to multistage NMPC, which considers uncertainty evolution in a scenario tree with separate control sequences to address constraint violations. We demonstrate that multistage NMPC presents good performance by showing constraint satisfaction whether the uncertain rock parameter realization is time‐invariant or time‐variant. We also simulate the process with multistage NMPC including different numbers of scenarios and compare their control performance. Our investigation demonstrates that multistage NMPC effectively manages parametric uncertainties attributed to non‐homogeneous rock formation, and provides a promising control strategy for the hydraulic fracturing process.

An Adaptive Sequential Fully Implicit Domain-Decomposition Solver

SummaryModern reservoir simulation must handle complex compositional fluid behavior, orders-of-magnitude variations in rock properties, and large velocity contrasts. We investigate how one can use nonlinear domain-decomposition preconditioning to combine sequential and fully implicit (FI) solution strategies to devise robust and highly efficient nonlinear solvers. A full simulation model can be split into smaller subdomains that each can be solved independently, treating variables in all other subdomains as fixed. In subdomains with weaker coupling between flow and transport, we use a sequential fully implicit (SFI) solution strategy, whereas regions with stronger coupling are solved with an FI method. Convergence to the FI solution is ensured by a global update that efficiently resolves long-range interactions across subdomains. The result is a solution strategy that combines the efficiency of SFI and its ability to use specialized solvers for flow and transport with the robustness and correctness of FI. We demonstrate the efficacy of the proposed method through a range of test cases, including both contrived setups to test nonlinear solver performance and realistic field models with complex geology and fluid physics. For each case, we compare the results with those obtained using standard FI and SFI solvers.NOTE: This paper is also published as part of the 2021 SPE Reservoir Simulation Conference Special Issue.

Sources of variability in laboratory rock test results

Appropriate rock characterization is beneficial in providing a reliable judgment on rock properties which is crucial for the design process of rock engineering applications. However, it can be difficult to obtain consistent mechanical parameters due to substantial variations in rock properties. In this research, uniaxial compression tests on dolerite specimens collected from a gold mine in Western Australia showed substantial scatter in the results. Rock categorization based on the P-wave velocities is as accurate as the thin section analysis, which suggests that they can be used together to gain a more accurate initial understanding of the rock types before any laboratory testing. The quality of specimen preparation and rock–machine interaction greatly affect the test results. For instance, non-parallelness of loading platens can lead to considerable scatter of the testing results, which would be perceived as rock variability. It is suggested that the current testing standards should be modified towards a better control of the loading machine performance and equipment precision. Finally, the possibility of pre-existing microcracks in rock, neither detected by the thin section analysis nor by the ultrasonic measurement, must be examined by computed tomography (CT) scanning as they can affect the test results. This study will enhance our knowledge about the sources of variability in laboratory test results of rock which is essential for obtaining reliable data.

Free or Bound? Thomeer and NMR Porosity Partitioning in Carbonate Reservoirs, Alta Discovery, Southwestern Barents Sea

The main etrophysical challenges in carbonate reservoirs are often to define meaningful rock types, then to establish robust permeability and saturation models for these rock types, as well as to develop a realistic estimation of irreducible water saturation (Swirr). Realistic Swirr estimation is important for predicting production behavior (expected development of water cut) and thus ultimately for planning the future development scheme of a discovery. In this study, we present the 2014 Alta discovery, located in the southwestern Barents Sea. More than 50% of the expected hydrocarbon resources reside within complex carbonate reservoirs of Permo-Carboniferous age that display highly variable rock properties. The initial screening revealed that primary rock textures and pore geometries were, for a large part, overprinted by diagenetic processes. Hence, better control on the reservoir’s diagenetic evolution will be needed to apply a full-scale rock typing workflow. In the meantime, it was decided to proceed with a simplified reservoir characterization approach based on the main stratigraphic building blocks. Sufficient core coverage allowed for using permeability measurements on core samples as direct input to a 3D reservoir model. A customized core analysis program, using whole-core samples, was designed to characterize the effect of large-scale vuggy pores. For modeling water saturation, a workflow based on the Thomeer hyperbola was developed that describes mercury injection capillary pressure (MICP) curves. The results adequately specify the saturation in all the stratigraphic building blocks. However, saturation uncertainty in the reservoir is high due to a highly variable cementation factor (m), unknown wettability, and the presence of residual oil below the current free-water level (FWL). The Alta structure has been and still is leaking gas, causing the FWL to rise over time. To address the otherwise underestimated volumes in the transition zone above the current FWL, a deeper pseudo-FWL was created and used as input to the saturation height function. Despite log-based water saturation (Archie) and core measurements (Dean-Stark) indicating more than 80% water saturation for less permeable reservoir rocks within the oil leg, production tests did not produce water at normal rates. This clearly demonstrated the need to distinguish “nonproductive” pore systems (with capillary-bound fluids; in this case, water) from pore systems contributing to production (“free” fluids). A large MICP data set confirmed that most reservoir rocks exhibit a mix of different pore types and pore-throat diameters. To model this accurately, porosity partitioning in nonproductive microporosity and movable porosity using the NMR logs was performed. Calibrating appropriate T2 cutoffs by matching core MICP to NMR logs in these heterogeneous rocks is seriously hampered by the large difference in sample size. Applying both MICP and NMR measurements to a subset of core plugs helped to resolve this challenge. Comparing the corresponding movable (“free”) porosity to total porosity revealed near-linear relationships for different reservoir rocks. For irreducible water saturation (Swirr), Swimmobile is calculated using the NMR-based movable porosity. Swimmobile is considered to be a close approximation of Swirr. The resulting full-field simulation showed a significantly improved match between model output and recorded well test data.

Experimental Investigation of Depletion- and Injection-Induced Changes in Poromechanical, Transport, and Strength Properties of High-Porosity Sandstone

Summary In this paper, an extensive series of experiments was performed to investigate the evolution of poromechanical (dry, drained, undrained, and unjacketed moduli), transport (permeability), and strength properties during reservoir depletion and injection in a high-porosity sandstone (Castlegate). An overdetermined set of eight poroelastic moduli was measured as a function of confining pressure (Pc) and pore pressure (Pp). The results showed larger effect on pore pressure at low Terzaghi’s effective stress (nonlinear trend) during depletion and injection. Moreover, the rock sample is stiffer during injection than depletion. At the same Pc and Pp, Biot’s coefficient and Skempton’s coefficient are larger in depletion than injection. Under deviatoric loading, absolute permeability decreased by 35% with increasing effective confining stress up to 20.68 MPa. Given these variations in rock properties, modeling of in-situ-stress changes using constant properties could attain erroneous predictions. Moreover, constant deviatoric stress-depletion/injection failure tests showed no changes or infinitesimal variations of strength properties with depletion and injection. It was found that failure of Castlegate sandstone is controlled by simple effective stress, as postulated by Terzaghi. Effective-stress coefficients at failure (effective-stress coefficient for strength) were found to be close to unity (actual numbers, however, were 1.03 for Samples CS-5 and CS-9 and 1.04 for Sample CS-10). Microstructural analysis of Castlegate sandstone using both scanning electron microscope (SEM) and optical microscope revealed that the changes in poroelastic and transport properties as well as the significant hysteresis between depletion and injection are attributed to the existence and distribution of compliant components such as pores, microcracks, and clay minerals.

Basin-wide empirical rock-physics transform and its application in Campeche Basin

Rock properties in the subsurface are of major importance for evaluating the petroleum prospectivity of a sedimentary basin. The key rock properties to understand are porosity, density, temperature, effective stress, and pore pressure. These rock properties can be obtained or calculated when borehole data are available. However, borehole data are usually sparse, especially in frontier basins. We propose some simple rock-physics transforms for converting P-wave velocity to other rock properties. We found that these rock-physics transforms are predictive in the east and west sides of Campeche Basin. The proposed rock-physics transforms can be used to obtain laterally varying rock properties based on information derived from seismic data.

Varying least principal stress along lithofacies in gas shale reservoirs: effects of frictional strength and viscoelastic stress relaxation

Compositional variation of rock properties in unconventional shale reservoirs impacts not only hydraulic fracturing stimulation but also the variability of induced shear slip on pre-existing fracture networks. Lithological layering is also responsible for varying stress states in various unconventional reservoirs subjected to normal, strike-slip, reverse or hybrid faulting regime (a combination of any two of them). Three possible mechanisms are considered to evaluate the layer-based stress profile in the sub-surface, that is viscoelastic stress relaxation, elevated pore pressure and variation in rock frictional strength. We conducted multistage triaxial deformation tests with varying strain rates (5×10−7 to 10−5s−1) on shale sample originating from three lithological units of the Goldwyer shale formation, that is G-I, G-II and G-III in the Broome platform of onshore Canning basin. Additionally, pore pressure was estimated from wireline logs, and tectonic stress accumulation was modelled using time-dependent deformation (creep) data. The above analysis suggests that varying frictional strength alone could not explain the variation of the least principal stress; however, the inclusion of stress relaxation also contributes, whereas elevated pore pressure has no effect. Using this approach, we could also relate the changes in minimum principal stress (Shmin) from one lithofacies to the other and anticipate how this will impact the optimum design of landing zone during horizontal drilling and completion in unconventional field development.

Exploring for the Future geomechanics: breaking down barriers to exploration

Exploring for the Future (EFTF) is an Australian Government initiative focused on gathering new data and information about potential mineral, energy and groundwater resources across Australia. The energy component of EFTF, initially focussed on northern Australia, aims to improve our understanding of the petroleum potential of frontier Australian basins. Building an understanding of geomechanical rock properties is key to understanding both conventional and unconventional petroleum systems as well as carbon storage and sedimentary geothermal systems. Under EFTF, Geoscience Australia has undertaken geomechanical work including stress modelling, shale brittleness studies and the acquisition of new rock property data through extensive testing on samples from the Paleo- to Mesoproterozoic South Nicholson region of Queensland and the Northern Territory, and the Paleozoic Kidson Sub-basin of Western Australia. Work in these regions demonstrates regional stress orientations in broad agreement with previously modelled, continent-scale stress orientations and stress magnitudes that vary through the basin with depth and by lithology. Rock testing highlights potentially brittle shales and demonstrates variable rock properties in line with lithology. These analyses are summarised herein. Providing baseline geomechanical data in frontier basins is essential as legacy data coverage can often be inadequate for making investment decisions, particularly where unconventional plays are a primary exploration target. As EFTF increases in scope, Geoscience Australia anticipates expanding these studies to encompass further underexplored regions throughout Australia, lowering the barrier to entry and encouraging greenfield exploration.

Numerical investigations on two-phase fluid flow in a fractured porous medium fully coupled with geomechanics

A fully coupled two-phase fluid flow and geomechanical model has been used to investigate the impact of injection fluid flow and geomechanics on reservoir pressure, effective stresses and strain, vertical displacements, viscous fingering instability, and viscous dissipation during the displacement of a viscous oil by water in a heterogeneous fractured porous medium. Porosity and permeability in the matrix and fracture have been considered as functions of generated strain. Elastic modulus has been considered as a function of updated porosity in the matrix and fracture. These dynamic variations will improve the accuracy in the predictions of its associated hydrodynamic behavior. The coupled model was validated with the existing works. From the present work, it can be critically concluded that the pressure, effective stress and strains, vertical displacement, viscous fingering instability, and viscous dissipation are highly dependent on (a) the fracture aperture, the orientation of fracture (dip), and arrangement of fracture; (b) involved geomechanical load; (c) production pressure, and (d) Biot-Willis coefficient. The numerical models have been examined both in the existence and absence of fractures and geomechanical impact. The Biot-Willis coefficient sensitivity was found on the pressure, water saturation profiles, effective stress, and strain from the numerical results. Viscous fingering instabilities like splitting, shielding, and spreading are observed explicitly in the fractured reservoir. Maximum viscous dissipation occurred in the heterogeneous medium when geomechanics was considered. The breakthrough of injected water was observed earlier in the reservoir with a geomechanical load scenario and the maximum viscous dissipation. The fracture and its orientation affect the viscous fingering instability phenomena and viscous dissipation in a porous medium with fractures after the addition of geomechanical loads. The numerical model extended to the multiple fracture scenarios on the same scale and further scaled up to 200 m by 200 m with different fracture orientations. In the upscaled model, fracture orientations varied from 45° to 135° with the x-axis, fracture lengths ranged from 5 m to 21.2 m, and with diverse fracture aperture and its arrangements. It has been found the fracture orientations 45° and 60° are improving the transportation of injected fluid via the smooth passage, and 120° and 135° are limiting the injecting fluid flow towards the production well. From the numerical results, it was found that viscous fingering instability is more sensitive to the fracture aperture and the complexity of its arrangement. Finally, it was concluded that the number of fractures and their arrangements in the reservoir flow behavior critically influences the model results. Thus, the developed numerical model with variable rock properties can be used to predict the flow behavior. Furthermore, its associated variations in the rock matrix and fractures during the two-phase flows in a reservoir improve reservoir behavior prediction and reduce the uncertainty.

Investigating the role of diffusion in hydrocarbon gas huff-n-puff injection- an Eagle Ford study

Fracture complexity, variation in fluid properties, variations in rock types and diffusion of gas from the fracture into the oil-saturated nano-pores are the main contributing factors in oil recovery using gas huff-n-puff injection. Limited research has been conducted to define diffusion coefficients coupled with rock tortuosity resulting in calculation of effective diffusion. The objective of this work is to conduct a comprehensive experimental and simulation study on lower Eagle Ford rock samples to measure diffusion coefficients for different injection cycles in three representative rock samples from the main flow unit.Three representative rock samples were selected based on their differences in petrophysical properties. Saturated volumes were measured using a low-field nuclear magnetic resonance (NMR) measurement and confirmed with material balance for cores saturated at reservoir conditions. Pressure was recorded during a one-day diffusion process before it was dropped linearly at the end of each cycle for production, and effluent oil and gas compositions were measured. NMR measurement was repeated at the end. Three compositional simulation models were set up for three different samples using tortuosity values from FIB-SEM analysis to simulate experimental diffusion and production. For history matching, relative permeability curves, fracture properties, and tortuosity were tuned to match pressure and production results for three representative samples.Pressure profiles vary significantly between different cycles caused by invasion of the gaseous phase into a new section of the pore network during each cycle. Effective diffusion coefficients were calculated using representative tortuosity values. Diffusion was represented by pressure drop during soaking time. This pressure drop varies across different lithofacies and for different rock samples. For produced oil, the concentration of lighter oil components declined from the first to the last cycle of gas injection while the concentration of the intermediate components increased.Gas huff-n-puff injection into shale oil reservoirs were being investigated from the point of view of diffusion and variations in rock properties for the first time and measurements were validated using numerical simulation. The huff-n-puff experiments, conducted using a constant volume diffusion cell with locally produced hydrocarbon gas and stock-tank oil, show favorable results. Recovery factors for samples A, B, and C are 57.5%, 56.7%, and 51.7%, respectively.

Spatial Variation of b-Values and Their Relationship with the Fault Blocks in the Western Part of the Tibetan Plateau and Its Surrounding Areas.

The Tibetan Plateau is considered to be one of the best natural laboratories for seismological research. This study sought to determine the spatial variations of b-values in the western part of the Tibetan Plateau, along with its surrounding areas, and the relation with the region’s fault blocks. The study region lies within 27–36.5° N, 78–89° E, and its fracture structure consists of strike-slip faults, as well as normal and thrust faults. A catalog record from 2009–2019 provided 4431 well-centered earthquakes that varied in magnitude from 0.1 to 8.2 M. The record was obtained from China’s seismological network, which is capable of recording low magnitudes to analyze b-values in the study area. The key findings of this study are as follows: (1) the range of earthquake depth in the region was 0–256 km, with the depth histogram showing a high frequency occurrence of shallow earthquakes in the area; (2) a time histogram showed that the major earthquakes occurred between 2014–2015, including the notable 2015 Gorkha earthquake (M = 8.2); (3) the b-value computed in the study area was 0.5 to 1.6, but in most of the study area, the b-value ranged from 0.6 to 0.9, which was a low to intermediate value, due to the presence of strike-slip faults in the central part of the study area and underthrusting in the region (south of the study area); and (4) a high b-value was found in the northwestern and eastern regions of the area, which proved that the area is prone to small earthquakes in the near future. The study also showed that the central and southern areas of the study region had low to intermediate b-values, meaning that it is prone to destructive and massive earthquakes with high magnitudes, such as the Gorkha earthquake (southern part of the study area). Low b-values revealed the degree of variation in rock properties, including large stress and strain, a fractured medium, a high deformation rate, and large faults. Small b-values were observed when the stress level was high in the investigated region, which might be used to predict a massive high-magnitude earthquake in the near future.

New Fracture Diagnostic Test Delivers Tight Reservoir Data in 2 Hours or Less, Bolsters Future of Engineered Completions

One of the grand challenges facing the oil and gas industry’s global quest to improve the potential of tight reservoirs involves designing horizontal-well completions that match the often-complex heterogeneity of the target formations. This sums up the general concept most call the “engineered completion.” In theory, tailoring a stimulation job to the varying rock properties found along the lateral section of a horizontal wellbore should result in better production for less capital. In practice, the industry has never attempted to do this on a meaningful scale. Among other reasons, the detailed subsurface data required to shake the bonds of geometric, or “cookie cutter,” designs have long been considered too costly to gather or too time-consuming to analyze. A shift is underway though. This is thanks in part to a number of innovations that have hit the market in recent years to meet rising demand for real-time completions-monitoring services. By interpreting pressure signals and other reservoir responses, the new tools aim to give operators the competency they need to adjust fracture designs as the stimulation progresses. But there is another route to the engineered completion. It begins before the well is hydraulically fractured. This effort to predetermine different fracture-stage designs has established its own distinct arena of innovation. Behnam Zanganeh, a former research student at the University of Calgary, was part of a team that developed one of the latest approaches. It is notable in part because it requires no new technology - just new ways of thinking about some old ideas. In a paper published last month during the virtual Unconventional Resources Technology Conference, Zanganeh and his fellow petrotechnical researchers showed how multiple points in a wellbore can be tested for different reservoir-quality parameters quickly and simply relative to traditional methods (URTeC 2838). This is done by combining and fundamentally altering a test known for being slow: the diagnostic fracture injection test (DFIT). The biggest change it calls for is to start flowback after the injection cycle for flowback analysis (FBA), thus eliminating the lengthy falloff cycle associated with the DFIT. The paper outlines a validation study done with Sydney-based Origin Energy which used the blended DFIT-FBA method in a vertical open hole to test two previously untested horizons in the Beetaloo Basin, a frontier unconventional gas play in the center of Australia’s Northern Territory. The results were integrated into the models Origin ultimately used to select its landing target for its subsequent horizontal program.