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.
Shoemaker, Michael (Callon Petroleum Company) | Hawkins, James (Callon Petroleum Company) | Becher, John (Callon Petroleum Company) | Gonzales, Veronica (Callon Petroleum Company) | Mukherjee, Sandeep (Callon Petroleum Company) | Garmeh, Reza (Callon Petroleum Company) | Kuntz, David (Callon Petroleum Company)
E&P companies in the Permian Basin typically implement basin-wide development strategies that involve cookie-cutter type methods that use multi-well pads with identical geometric stage and cluster spacing. Such development strategies however fail to recognize and account for subsurface stress heterogeneity, and thus assume similar geomechanical properties that are homogeneous and isotropic which may cause well-to-well interference or “frac hits”, particularly near “parent” wells as fields continue to mature.
Minimum horizontal stress (Sh) is the leading parameter that controls hydraulic fracture stimulation, but is next to impossible to measure quantitatively, especially far field and in 3D space. In-situ stress differences from fluid depletion, combined with stratigraphy and subsequent mineralogy contrasts, control fracture containment vertically and laterally which define fracture propagation and complexity. Far field preference of virgin rock towards brittle vs ductile deformation is governed by mineralogy which defines the elastic moduli or geomechanical behavior of the rock. When integrated with pore pressure and overburden stress, the elastic rock properties are characterized by the Mechanical Earth Model (or MEM) which defines key inputs for calculating Sh using the uniaxial Ben Eaton stress equation. However, implementing this model historically produces incorrect calculated stress, when compared to field measured stress, due to an assumed homogeneous and isotropic subsurface.
Parameterization of fracture geometry models for well spacing, frac hit mitigation, and engineered treatment design in shale (or mudrock) requires an anisotropic in-situ stress measurement that accurately captures subsurface stress states. A method herein is proposed that achieves this using a modified version of the anisotropic Ben Eaton stress equation. The method calculates minimum horizontal stress by substitution of AVO seismic inversion volumes directly into the stress equation, replacing the bound Poisson's ratio term with an equivalent anisotropic corrected Closure Stress Scalar (CSS) defined in terms Lamé elastic parameters, specifically lambda (λ) or incompressibility and mu (μ) for shear rigidity. The CSS volume is corrected for anisotropy using static triaxial core, and is calibrated to multi domain data types including petrophysics, rock physics, completion engineering, and reservoir engineering (DFIT) measurements.
Successful application of said method in the Delaware and Midland sub-basins (of the greater Permian Basin) is shown. Anisotropic minimum horizontal stress (Sh) volumes from 3D seismic defined at 1 ft. vertical log resolution were interpreted quantitatively regionally, particularly as a prevention tool near parent wells prone to frac-hits. Moreover, the method provides an anisotropic measurement of in-situ stress variability (or stress differential) to qualitatively model 3D fracture geometries for engineered treatment optimization. Current stress modeling methods rely on the propagation of geomechanical properties from well control, which do not necessarily represent rock properties and stress states at the area of interest.
Pore pressure prediction plays a critical role in the ability to predict areas of high overpressure and fracture behavior for the exploitation of unconventional plays, which are both correlated with production. Shales in these plays have variable clay content and complex multi-mineral fractions that require a detailed petrophysical assessment reinforced with rock physics modelling as needed. For example, changes in total organic content have a similar elastic response to changes in porosity. Therefore, any pressure-stress property model for unconventional plays must be supported by petrophysically conditioned elastic logs and accurate multi-mineral volume sets calibrated to core data.
A supervised deep neural network approach is introduced as an alternative innovative tool for petrophysical, pore pressure and geomechanics analysis enabling the use of all the previously collected and interpreted data to devise solutions which simultaneously integrate wide ranging well bore and wireline logs. We implement three neural networks, all with similar structure, as each of these networks had a different objective and the outputs from one were the inputs for the other.
The first network was trained to predict petrophysical volume logs (shale, sand, dolomite, calcite, kerogen and also porosity) simultaneously from compressional velocity (Vp), Gamma ray, density (rho), resistivity and Neutron logs. The second neural network, cascaded from the first, was then designed to match the manually predicted pore pressure. The inputs were Vp and shear velocity (Vs), Rho, resistivity, Neutron logs as well as the results of the first network. The third network focused on predicting various properties of interest, in this case pore pressure, minimum horizontal stress (Shmin), maximum horizontal stress (SHmax), and volume of kerogen, based on only Vp, Vs, and Rho logs which is an example building a neural network capable of predicting key rock properties directly from seismic inversion results to produce meaningful 3D interpretations.
The volumetric pore pressure model was also positively correlated to cumulative production values from blind long horizontal wells. The results show a promising outlook for the application of deep learning in integrated studies such as those shown in this paper.
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).
A new approach that uses logs derived from wireline and surface drilling data to extract an interface proxy is presented and illustrated in the Montney. The derived interface proxy logs are propagated in the entire reservoir volume using artificial intelligence-based reservoir modeling. Blind wells confirm the ability to predict the interface proxy at any reservoir location. The derived interface proxy propagated in 3D was validated with moment tensor showing that the microseismic shear plane events occur mainly where the presence of the interfaces is the highest.
Using the derived interface proxy as an input, the Material Point Method (MPM) and Anisotropic Damage Mechanics (ADaM) are used to solve the geomechanical modeling of a hydraulic fracture propagating in a layered medium containing any type of interfaces including the weak interfaces. The geomechanical simulation confirms the major impact these weak interfaces could have on the fracture height growth.
The geomechanical analysis confirmed the importance of mapping in 3D the interfaces and modeling their effects in an accurate manner to better capture their effect on fracture height growth and the resulting proppant placement. The application of the new geomechanical workflow was illustrated on two Montney wells and was able to provide some explanation on their production differences that could be attributed to interfaces.
There is an ongoing paradigm shift in the processes and technologies employed in making field development decisions in unconventional reservoirs. Expensive trial and error exercises in multiple reservoirs have returned the verdict: there is no single prescribed treatment for a given reservoir, which always maximizes production and eliminates risk of frac hits and well interferences. In many situations, lateral growth of hydraulic fractures has been the major concern amongst operators, but as the economics of unconventional production shift, and the industry moves to more wine-racking and cube development plans, it has become abundantly clear that current hydraulic fracturing design software have multiple shortcomings such as not being able to fully account for natural fractures and predicting the subsequent frac-complexity as well as including the critical effects of weak interfaces. One of the consequences of this poor representation of the physics occurring during hydraulic fracturing of unconventional wells is the overprediction of hydraulic fracture heights. All commonly used industry frac design software are neither able to predict microseismicity to prove their ability to reproduce the observed frac complexity nor capable of including the effects of weak interfaces, or bedding and laminations (geologically speaking) on hydraulic fracture propagations in the vertical direction. Since microseismicity has been successfully predicted to capture the lateral stress gradients created by the natural fractures, the focus in this study is quantifying at any well the characteristics of the interfaces and their impact on the fracture height. Geomechanical logs derived from commonly available surface drilling data are used to capture zones of high interface potential and their characteristics. The resulting interface positions and their mechanical properties are input in a geomechanical simulator using the Material Point Method (MPM) to simulate the effect of the weak interfaces on hydraulic fracture height growth. These simulations provide the necessary information required by frac design software that now can incorporate not only the lateral stress gradients created by the natural fractures but also the vertical complex effects created by the weak interfaces. The results of this fast-practical decoupled workflow are a better estimate of the spacing needed for wine-rack systems and more realistic fracture geometries inputs to fluid flow models which can provide realistic geometries of depletion profiles affecting well interference potentials driven by production.
Klie, Hector (DeepCast.ai) | Klie, Arturo (DeepCast.ai) | Rodriguez, Adolfo (OpenSim Technology) | Monteagudo, Jorge (OpenSim Technology) | Primera, Alejandro (Primera Resources) | Quesada, Maria (Primera Resources)
The Vaca Muerta formation in Argentina is emerging as one of the most promising resources of shale oil/gas plays in the world. At the current well drilling pace, challenges in streamlining data acquisition, production analysis and forecasting for executing timely and reliable reserves and resource estimations will be an overarching theme in the forthcoming years. In this work, we demonstrate that field operation decision cycles can be improved by establishing a workflow that automatically integrates the gathering of reservoir and production data with fast forecasting AI models.
We created a data platform that regularly extracts geological, drilling, completion and production data from multiple open data sources in Argentina. Data cleansing and consolidation are done via the integration of fast cross-platform database services and natural language processing algorithms. A set of AI algorithms adapted to best capture engineering judgment are employed for identifying multiple flow regimes and selecting the most suitable decline curve models to perform production forecasting and EUR estimation. Based on conceptual models generated from minimum available data, a coupled flow-geomechanics simulator is used to forecast production in other field areas where no well information is available. New data is assimilated as it becomes available improving the reliability of the fast forecasting algorithm.
In a matter of minutes, we are able to achieve high forecasting accuracy and reserves estimation in the Vaca Muerta formation for over eight hundred wells. This workflow can be executed on a regular basis or as soon as new data becomes available. A moderate number of high-fidelity simulations based on coupled flow and geomechanics allows for inferring production scenarios where there is an absence of data capturing space and time. With this approach, engineers and managers are able to quickly examine a feasible set of viable in-fill scenarios. The autonomous integration of data and proper combination of AI approaches with high-resolution physics-based models enable opportunities to reduce operational costs and improving production efficiencies.
The integration of physics-based simulations with AI as a cost/effective workflow on a business relevant shale formation such as Vaca Muerta seems to be lacking in current literature. With the proposed solution, engineers should be able to focus more on business strategy rather than on manually performing time-consuming data wrangling and modeling tasks.
The East Duvernay shale basin is the newest addition to the list of prolific reservoirs in Western Canada. Over the last 3 years, horizontal drilling and multistage hydraulic fracturing have increased significantly. Because much of the play is still relatively new, much of the drilling has been limited to single wells or two wells per pad. Due to the low permeability of the matrix, hydraulic fracturing is required to unlock the full potential of the East Duvernay field. Because geomechanics is a critical factor in determining the effectiveness of hydraulic fracture propagation, we examined how varying the pore pressure profiles affects modeled in situ stresses, hydraulic fracture geometries, and overall field optimization.
The pore pressure varies across the East Duvernay shale basin with the depth of the reservoir and other geomechanical parameters. The stresses in the Ireton, Upper Duvernay, Lower Duvernay, and Cooking Lake reservoirs also varies from the West to the East shale basins. High-tier logging, core measurements, and field data were used to build a mechanical earth model, which is then input for hydraulic fracture simulations. Whole core images and image logs indicate the Duvernay to be a naturally fractured reservoir. Because pore pressure is a direct input into the interpretation for in situ stresses, we sensitized on seven pore pressure profiles through the Ireton, Upper and Lower Duvernay, and Cooking Lake reservoirs. Typical pumping design currently being implemented in the Upper Duvernay was used to determine hydraulic fracture geometry based on the various in situ stress profiles. Black oil PVT models were built to run numerical reservoir simulation production forecasts to understand the effect of variations in geomechanical properties on well production performance. The effect of the varying hydraulic fracture properties on well spacing was also investigated for the seven pore pressure profiles, by combining the complex hydraulic fracturing and reservoir simulation.
The results clearly indicated the need to better understand, quantify, and constrain the in situ stress profiles variations with changes in pore pressure models. Hydraulic fracture length is greater within the Upper Duvernay when a constant pore pressure is modeled in the Ireton, Duvernay and the Cooking Lake, which leads to an overestimation of production. If a normal pore pressure is modeled in the Ireton with overpressure in the Duvernay, the hydraulic fracture grows into the Ireton and gives a more realistic production forecast. When the modeled pore pressure is gradually ramped up from the Lower Ireton into the Duvernay, slightly greater fracture length is created in the Duvernay but not enough to make a huge difference in forecasted production. These varying results for the modeled hydraulic fracture geometries impact the optimum number of wells per section.
As more wells come on production and the economic viability of the play is proven, operators will drill more wells per section. Thoroughly understanding the variations in geomechanics across the formations above and below the Duvernay is important. This objective of this study was to drive the conversation about the data that need to be collected and tests that should be run to support the optimization of economic development of the play for years to come.
Publicly-available fault data for the Delaware basin is used to simulate a detailed map of maximum stress direction at a scale of 1000ft x 1000ft throughout the Delaware basin. The resulting maps highlight the complexity of stress fields in the Delaware basin and the importance of accounting for the interaction of entire fault systems with regional stresses. This underscores a dire need for the industry to better quantify structural features in and around unconventional reservoirs. When commercially-available seismic data is used for a refined interpretation of the structural features that affect the stress field, geomechanical models can be refined to provide valuable information at the well and pad scale to influence and optimize well spacing and completion decisions to minimize frac hits and other undesirable well interferences. Multiple data collected at the wells are used to validate the predicted stress orientation and their impact on the performance of hydraulic fracturing jobs. These results were enabled by the use of validated geomechanical modeling that is able to easily handle the faults and natural fractures. This is implemented by using the material point method to address the computational challenges introduced by the presence of these earth discontinuities in the general continuum mechanics equations representing the static and dynamic variations of stress in unconventional reservoirs.
Production of unconventional wells is dictated by both the geological (resource) and geomechanical (recoverability) properties of the reservoir. The geomechanics of a reservoir can be broken down into the rock mechanical properties, which near the wellbore primarily control fracture initiation potential, and the current stress state, which away from the wellbore controls the propagation of successfully induced hydraulic fractures and their interaction with natural fractures and layer interfaces. The consequential properties of the stress state can be further refined and represented as the differential stresses and the maximum horizontal stress orientation. In the Permian basin where a normal fault regime is common, it is critical that an unconventional horizontal well be drilled nearly perpendicular to the maximum horizontal stress direction (MHSD) in order to induce transverse hydraulic fractures and thereby maximize its stimulated reservoir volume (SRV). Additionally, maximum horizontal stress orientation is a major control on fault stability and a primary concern when quantifying the induced seismicity potential in a given area. Stress rotations have been documented at regional, basin, field, and pad scales (Umholtz & Ouenes, 2015, Umholtz & Ouenes, 2016, Ouenes et al., 2016). What cannot be ignored, is the reciprocal relationship between fault networks and stress fields. While fault quantification is readily available at field scales (when seismic data exists), operators rarely disclose these interpretations to be used in comprehensive regional studies. This study will initially focus on quantifying stress rotations at basin and county scales using publicly-available data, and further refine these estimates by integrating interpreted fault information from readily-available seismic data.
Swami, Vivek (CGG) | Tavares, Julio (CGG) | Pandey, Vishnu (CGG) | Nekrasova, Tatyana (CGG) | Cook, Dan (Bravo Natural Resources) | Moncayo, Jose (Bravo Natural Resources) | Yale, David (Yale Geomechanics Consulting)
In this study, a state-of-the-art seismic driven 3D geological model was built and calibrated to a petrophysical and geomechanical analysis, 1D-MEM (Mechanical Earth Model), on chosen wells within the Arkoma Basin of Oklahoma. The well information utilized in this study included basic wireline logs and core analysis, including XRD (X-Ray diffraction) data. The traditional petrophysical analysis was augmented with advanced rock physics and statistical techniques to generate the necessary logs. Hydrostatic, overburden and pore pressures were calculated with a petrophysical evaluation model. The 1D-MEMs were based on the Eaton/Olson/Blanton approach with the HTI (Horizontal Transverse Anisotropy) assumption. The 1D-MEMs were calibrated to laboratory data (triaxial tests) and field observations (mud logs, wellbore failure, frac pressures). Therefore, a very good confidence was achieved on Biot's coefficient, tectonic components, anisotropy and dynamic to static conversion factors for Young's Modulus and Poisson's Ratio. Seismic inversions were performed in different time windows and merged to generate high resolution P- and S-Impedance attributes from surface down to the target interval after careful AVO compliant gather preconditioning. A density volume estimate was calibrated to well data, accounting for different geological formations, to decouple P- and S-Wave components as a 3D volume, as well as dynamic Young's modulus (E) and Poisson's ratio (PR). Dynamic E and PR were converted to static parameters using results from 1D-MEMs; and 3D models of Biot's coefficient (α) and tectonic components were built to compute 3D fracture pressure volumes calibrated to well data. The final products were seismic-driven 3D pore pressure and fracture pressure calibrated to 1D-MEMs. The correlation between measured/estimated well logs and corresponding seismic-derived pseudo logs was more than 80%, which indicates good quality of seismic inversion results and hence 3D-MEM. Also, stress barriers, anisotropy, and brittleness indices were calculated on well scale which would help to identify best zones to place hydraulic fractures. The 3D geological model will aid in identifying sweet-spots and optimizing hydraulic fractures.
Growth in a number of newly drilled wells in unconventional reservoir development results in tightly spaced horizontal wells, which consequently creates well interference (fracture hits) between parent and infill wells as a result of stress redistribution from localized pressure sink zone in parent wells. This directly affects the production performance of both parent and infill wells. In order to minimize this effect, it is sometimes more preferable to place an infill well in a different pay zone. However; due to poroelastic effect, pressure depletion from the parent well also affects stress distribution in different pay zones and yet only a few literatures focus on this effect. The main objective of this paper is to predict temporal and spatial evolution of stress field for Permian basin using an in-house 3D reservoir-geomechanics model and propose guidelines for determining lateral and vertical drilling sequence of infill wells to mitigate well interference.
Embedded discrete fracture model (EDFM) is coupled with a sequentially coupled reservoir-geomechanics model to gain capability in simulating complex fracture geometries and high-density fracture system. Different scenarios with and without natural fractures were studied including a case where two parent wells are located in different layers (Wolfcamp A2 and B2) and a case where two parents are located in the same layer (Wolfcamp A2 and B2). Stress redistribution is then observed to determine the completion sequence of infill wells in different layers.
Producing two parent wells in the same pay zone results in large stress redistribution mostly in the area close to fracture tips at an early time. As time progresses, stress redistribution area becomes larger and covers almost entire infill well zone in Wolfcamp B2. Stress changes can also be observed in Wolfcamp A2 and A3 despite producing wells are only located in Wolfcamp B2. However, when producing two parent wells in different pay zones, stress redistribution can only be observed near fracture tips in both Wolfcamp A2 and B2 with minimum stress change in the infill zone even at a later time in all Wolfcamps A2, A3, and B2. This allows the possibility of producing infill well in the un-depleted layers (i.e. A3) enhancing efficiency of infill well completion. Fracture penetration and larger fracture length also play a significant effect in stress reorientation and evolution. Presence of natural fractures causes stress reorientation to occur at an earlier time due to higher depletion rate. This paper presents the possibility of changing the sequence of stacked pay from lateral well layout to vertical well layout in order to mitigate well inference and improve production performance of both parent and infill wells. Less stress change in the infill zone for vertical well layout makes it become superior to lateral well layout in which large stress redistribution can be observed.