Hurlburt, Maurice (Athabasca Oil Corp.) | Quintero, Jonathan (Baker Hughes, a GE Company) | Bradshaw, Robert (Baker Hughes, a GE Company) | Belloso, Andres (Baker Hughes, a GE Company) | Cripps, Evan (Baker Hughes, a GE Company) | Blakney, Donya (Baker Hughes, a GE Company) | Glass, Darnell (Baker Hughes, a GE Company)
A Canadian oil & gas operator has been setting new benchmarks drilling the vertical and tangent section of Montney horizontal wells in the Placid field of Northern Alberta. Initially, the operator drilled vertical wells to kick off point (KOP) with polycrystalline diamond compacts (PDC) and conventional mud motors. As a result of increasing well density, however, the well plans consistently required a 15° to 30° tangent section. With PDC drilling, toolface and build up rates were problematic and the sliding rate of penetration (ROP) was slow.
A Rotary Steerable System (RSS) was introduced, but despite the improved performance, the technology came at a premium cost and the severity of drilling dysfunctions generated an increase in tool failures. With falling oil prices, a more cost effective solution was required.
Hybrid bit technology, which combines the cutting mechanism of both fixed cutter and roller-cone bits, has been extensively utilized in Canada to drill build sections, providing outstanding results. They have not, however, been commonly used to drill the vertical (drill-out) and tangent sections. The operator combined a state-of-the-art hybrid bit with a mud motor to drill the interval with an 85% success rate. The combination of the hybrid bit and conventional motor, compared to PDC and RSS, resulted in a 30% cost savings to complete the interval.
The present case study outlines how hybrid bit technology development, driven by field data in a continuous improvement cycle, identifies performance opportunities, which have a significant impact on drilling time and cost savings in drill out sections. The overall objective of this current case study is to highlight the results and lessons learned throughout the implementation process.
Xu, Zhengming (China University of Petroleum, Beijing) | Wu, Kan (Texas A&M University) | Song, Xianzhi (China University of Petroleum, Beijing) | Li, Gensheng (China University of Petroleum, Beijing) | Zhu, Zhaopeng (China University of Petroleum, Beijing) | Sun, Baojiang (China University of Petroleum, East China)
Energized fracturing fluids, including foams, carbon dioxide (CO2), and nitrogen (N2), are widely used for multistage fracturing in horizontal wells. However, because density, rheology, and thermal properties are sensitive to temperature and pressure, it is important to understand the flow and thermal behaviors of energized fracturing fluids along the wellbore. In this study, a unified steady-state model is developed to simulate the flow and thermal behaviors of different energized fracturing fluids and to investigate the changes of fluid properties from the wellhead to the toe of the horizontal wellbore. The velocity and pressure are calculated using continuity and momentum equations. Temperature profiles of the whole wellbore/formation system are obtained by simultaneously solving energy equations of different thermal regions. Temperature, pressure, and energized-fluid properties are coupled in both depth and radial directions using an iteration scheme. This model is verified against field data from energized-fluid-injection operations. The relative average errors for pressure and temperature are less than 5%. The effects of injection pressure, mass-flow rate, annulus-fluid type, foam quality, and proppant volumetric concentration on pressure and temperature distributions are analyzed. Influence degrees of these operating parameters on the bottomhole pressure (BHP) for different energized fracturing fluids are calculated. The required injection parameters at the surface to achieve designed bottomhole treating parameters for different energized fracturing fluids are compared. The results of this study might help field operators to select the most-suitable energized fluid and further optimize energized-fluid-fracturing treatments.
Seunghwan Baek and I. Yucel Akkutlu, Texas A&M University Summary Source rocks, such as organic-rich shale, consist of a multiscale pore structure that includes pores with sizes down to the nanoscale, contributing to the storage of hydrocarbons. In this study, we observed hydrocarbons in the source rock partition into fluids with significantly varying physical properties across the nanopore-size distribution of the organic matter. This partitioning is a consequence of the multicomponent hydrocarbon mixture stored in the nanopores, exhibiting a significant compositional variation by pore size-- the smaller the pore size, the heavier and more viscous the hydrocarbon mixture becomes. The concept of composition redistribution of the produced fluids uses an equilibrium molecular simulation that considers organic matter to be a graphite membrane in contact with a microcrack that holds bulk-phase produced fluid. A new equation of state (EOS) was proposed to predict the density of the redistributed fluid mixtures in nanopores under the initial reservoir conditions. A new volumetric method was presented to ensure the density variability across the measured pore-size distribution to improve the accuracy of predicting hydrocarbons in place. The approach allowed us to account for the bulk hydrocarbon fluids and the fluids under confinement. Multicomponent fluids with redistributed compositions are capillary condensed in nanopores at the lower end of the pore-size distribution of the matrix ( 10 nm). The nanoconfinement effects are responsible for the condensation. During production and pressure depletion, the remaining hydrocarbons become progressively heavier. Hence, hydrocarbon vaporization and desorption develop at extremely low pressures. Consequently, hydrocarbon recovery from these small pores is characteristically low. Introduction Resource shale and other source-rock formations with significant amounts of organic matter, such as mudstone, siltstone, and carbonate, have a multiscale pore structure that includes fractures, microcracks, and pores down to a few nanometers (Ambrose et al. 2012; Loucks et al. 2012). The total amount of hydrocarbons stored is directly proportional to the amount of organic matter.
This is the second of a three-part tutorial describing a workflow for evaluating unconventional resources including organic mudstones and tight siltstones. Part 1 reviewed the unique challenges and provided an overview of the proposed workflow (Newsham et al., 2019). Part 2 describes in detail the many components of the workflow and how they come together to determine the storage capacity of the reservoir. Part 3 links the petrophysical results to the production potential in terms of fractional flow and water cut and will present alternate cross-checks of the storage properties to validate the results.
As stated in Part 1, one of the most important functions that the petrophysicist provides is the estimation of accurate storage properties. However, when the authors survey the range of workflows used to estimate the storage capacity of these complex systems, we find a wide range of options. Solutions can vary from simple deterministic to more complex probabilistic approaches. Whatever the method, the objective should be the same: to provide consistent, portable hence reliable estimation of hydrocarbon storage capacity, also known as “Petrophysics CPR.” As mentioned in Part 1, estimation of hydrocarbon storage is more than just the calculation of porosity and water saturation. In this tutorial, we will describe a workflow that has been successfully used to evaluate thousands of wells in the Permian Basin with great consistency. The authors have nearly 100 wells with core data to calibrate the workflow. We will show examples of the workflow’s portability by highlighting examples from the Midland Basin, the Texas Delaware Basin and the New Mexico Delaware Basin. We will show how every property measured in core matches to log-based profiles using a combination of deterministic and the constrained simultaneous solution methods. The workflow also is found to be reliable in other basins throughout the world, however, the examples will be confined to the Permian Basins.
Hui, Mun-Hong (Chevron Energy Technology Company) | Dufour, Gaelle (Chevron Energy Technology Company) | Vitel, Sarah (Chevron Energy Technology Company) | Muron, Pierre (Chevron Energy Technology Company) | Tavakoli, Reza (Chevron Energy Technology Company) | Rousset, Matthieu (Chevron Energy Technology Company) | Rey, Alvaro (Chevron Energy Technology Company) | Mallison, Bradley (Chevron Energy Technology Company)
Traditionally, fractured reservoir simulations use Dual-Porosity, Dual-Permeability (DPDK) models that can idealize fractures and misrepresent connectivity. The Embedded Discrete Fracture Modeling (EDFM) approach improves flow predictions by integrating a realistic fracture network grid within a structured matrix grid. However, small fracture cells with high conductivity that pose a challenge for simulators can arise and ad hoc strategies to remove them can alter connectivity or fail for field-scale cases. We present a new gridding algorithm that controls the geometry and topology of the fracture network while enforcing a lower bound on the fracture cell sizes. It honors connectivity and systematically removes cells below a chosen fidelity factor. Furthermore, we implemented a flexible grid coarsening framework based on aggregation and flow-based transmissibility upscaling to convert EDFMs to various coarse representations for simulation speedup. Here, we consider pseudo-DPDK (pDPDK) models to evaluate potential DPDK inaccuracies and the impact of strictly honoring EDFM connectivity via Connected Component within Matrix (CCM) models. We combine these components into a practical workflow that can efficiently generate upscaled EDFMs from stochastic realizations of thousands of geologically realistic natural fractures for ensemble applications.
We first consider a simple waterflood example to illustrate our fracture upscaling to obtain coarse (pDPDK and CCM) models. The coarse simulation results show biases consistent with the underlying assumptions (e.g., pDPDK can over-connect fractures). The preservation of fracture connectivity via the CCM aggregation strategy provides better accuracy relative to the fine EDFM forecast while maintaining computational speedup. We then demonstrate the robustness of the proposed EDFM workflow for practical studies through application to an improved oil recovery (IOR) study for a fractured carbonate reservoir. Our automatable workflow enables quick screening of many possibilities since the generation of full-field grids (comprising almost a million cells) and their preprocessing for simulation completes in a few minutes per model. The EDFM simulations, which account for complicated multiphase physics, can be generally performed within hours while coarse simulations are about a few times faster. The comparison of ensemble fine and coarse simulation results shows that on average, a DPDK representation can lead to high upscaling errors in well oil and water production as well as breakthrough time while the use of a more advanced strategy like CCM provides greater accuracy. Finally, we illustrate the use of the Ensemble Smoother with Multiple Data Assimilation (ESMDA) approach to account for field measured data and provide an ensemble of history-matched models with calibrated properties.
For thermal heavy oil recovery, conventional steam injection processes are generally limited to reservoirs of relatively shallow depth, high permeability, thick pay zone and homogeneity. An alternative approach of applying Electromagnetic (EM) energy may be used to generate heat in reservoirs that are not suitable for steam injection or to improve the economics of the heavy oil recovery compared with steam injection. EM in-situ heating of oil reservoirs, in the form of EM energy absorption by dielectric materials, leads to an increase in temperature, a reduction in oil viscosity and an improvement in oil mobility. Recent studies have shown that EM heating is capable of reducing carbon emissions and water usage. However, the existing EM field simulators are limited to modeling of homogeneous media with respect to dielectric properties, which affects EM wave propagation and in-situ heat generation. For oil sands recovery where reservoir heating by EM energy is promising, it is desirable to simulate reservoirs in inhomogeneous formations, in which dielectric properties vary according to specific location. In this work, important background information regarding the EM wave propagation in inhomogeneous media is provided. A Helmholtz equation for the magnetic field by deformation of Maxwell's equations is presented that makes it feasible to find EM field solutions for such inhomogeneous media. Solution of only the magnetic field makes this work execution faster than the classical methods in which both magnetic and electric fields need to be calculated. By solving the equations of EM wave propagation and fluid flow in oil sands reservoirs simultaneously, this work provides a fully-implicit modelling method for the EM heating process. The feasibility of EM heating in oil sands is examined in two case studies: a) a horizontal well containing an antenna within and b) a horizontal well-pair with an antenna located in the upper well.
Salehi, Amir (Quantum Reservoir Impact International LLC) | Hetz, Gill (Quantum Reservoir Impact International LLC) | Olalotiti, Feyisayo (Quantum Reservoir Impact International LLC) | Sorek, Nadav (Quantum Reservoir Impact International LLC) | Darabi, Hamed (Quantum Reservoir Impact International LLC) | Castineira, David (Quantum Reservoir Impact International LLC)
An integral aspect of smart reservoir management of oil and gas fields is the process of identifying and performance forecasting of the remaining, feasible, and actionable field development opportunities (FDOs). In the present work, we introduce an adaptive full-physics simulation-based forecasting framework that applies a series of cutting-edge technologies to provide short- and long-term forecasts for both field- and well-level performance. Our workflow can be applied to a comprehensive opportunities inventory including behind-pipe recompletion, infill drilling, and sidetrack opportunities. In our approach, we begin with a model order reduction technique, which involves a parsimonious elimination of redundancies existing in a given geologic model. This involves an adaptive model upscaling strategy that retains fine details in the vicinity of critical geological features by locally varying the resulting model grid resolution. Reduced models, which are validated using streamline-based flow metrics, are passed into an automated sensitivity study and model calibration engine for efficient reconciliation of observed production trends in the field. Here, we apply a recently proposed Ensemble Smoother robust Levenberg- Marquardt (ES-rLM) method to generate plausible model realizations that replicate the reservoir energy. Representative models are further improved in a sensitivity-based local inversion step to match multiphase production data at the well level. An approach alternative to streamlines, which is compliant with a general unstructured grid format, is utilized to directly compute production data sensitivities on the underlying grid in the local inversion module. Finally, calibrated models are directly passed to the optimization and forecasting engine to assess and optimize field opportunities and development scenarios. This framework has been successfully applied to several giant mature assets in the Middle East, North America, and South America. A case study for one of the giant reservoirs in Latin America is presented where hundreds of field development opportunities are initially identified. We then apply our forecasting framework to the various scenarios including all opportunities to deliver the optimum field development plan. We propose a systematic workflow for field-scale modeling and optimization using an adaptive framework. Our approach facilitates a flexible framework to rapidly generate reliable forecasts and quantify associated uncertainties in a robust manner. This advantage in flexibility and robustness is tied to our fast and automated two-stage model calibration module that leads to substantial savings in computational time. This makes it an efficient method for quantifying the uncertainty as demonstrated through improved estimation of the faults’ connectivity, permeability distribution, fluid saturation evolution, and swept volume.
Cold heavy oil production with sand (CHOPS) is a non-thermal primary process that is widely adopted in many weakly consolidated heavy oil deposits around the world. However, only 5 to 15% of the initial oil in place is typically recovered. Several solvent-assisted schemes are proposed as follow-up strategies to increase the recovery factor in post-CHOPS operations. The development of complex, heterogeneous, high-permeability channels or wormholes during CHOPS renders the analysis and scalability of these processes challenging. One of the key issues is how to properly estimate the dynamic growth of wormholes during CHOPS. Existing growth models generally offer a simplified representation of the wormhole network, which, in many cases, is denoted as an extended wellbore. Despite it is commonly acknowledged that wormhole growth due to sand failure is likely to follow fractal statistics, there are no established workflows to incorporate geomechanical constraints into the construction of these fractal wormhole patterns.
A novel dynamic wormhole growth model is developed to generate a set of realistic fractal wormhole networks during the CHOPS operations. It offers an improvement to the Diffusion Limited Aggregation (DLA) algorithm with a sand-arch-stability criterion. The outcome is a fractal pattern that mimics a realistic wormhole growth path, with sand failure and fluidization being controlled by geomechanical constraints. The fractal pattern is updated dynamically by coupling compositional flow simulation on a locally-refined grid and a stability criterion for the sand arch: the wormhole would continue expanding following the fractal pattern, provided that the pressure gradient at the tip exceeds the limit corresponding to a sand-arch-stability criterion. Important transport mechanisms including foamy oil (non-equilibrium dissolution of gas) and sand failure are integrated.
Public field data for several CHOPS fields in Canada is used to examine the results of the dynamic wormhole growth model and flow simulations. For example, sand production history is used to estimate a practical range for the critical pressure gradient representative of the sand-arch-stability criterion. The oil and sand production histories show good agreement with the modeling results.
In many CHOPS or post-CHOPS modeling studies, constant wormhole intensity is commonly assigned uniformly throughout the entire domain; as a result, the ensuing models are unlikely to capture the complex heterogeneous distribution of wormholes encountered in realistic reservoir settings. This work, however, proposes a novel model to integrate a set of statistical fractal patterns with realistic geomechanical constraints. The entire workflow has been readily integrated with commercial reservoir simulators, enabling it to be incorporated in practical field-scale operations design.
This paper describes the interaction between hydraulic fractures and the multi-porosity system of matrix porosity and natural fracture porosity in shale reservoirs. During the process of hydraulic fracturing, a complex fracture network consisting of primary and secondary hydraulic fractures as well as natural fractures is created. It is postulated that only shale porosities connected with this network will contribute to hydrocarbon production. Furthermore, we propose a way to maximise well productivity by injecting microsized proppants that are less than 150 μm (100 mesh) into the natural fractures and secondary hydraulic fractures to prevent them from closing and thereby increasing the stimulated reservoir volume. The size of the micro-sized proppant should be designed to be between one-seventh and one-third the aperture size of the natural fractures. In addition, various materials for micro-sized proppants are proposed and discussed. Of these, hollow glass microsphere shows more promise because of its light density and track record of being used as an additive material in the oilfield. Although limited laboratory experiments and field tests have shown encouraging results of using micro-sized proppants to enhance the productivity of Barnett shale, more research is warranted to optimize the use of these micro-sized proppants in production enhancement in various shale formations.
Mustafa, Ayyaz (King Fahd University of Petroleum and Minerals) | Abdulraheem, Abdulazeez (King Fahd University of Petroleum and Minerals) | Abouelresh, Mohamed Ibrahim (King Fahd University of Petroleum and Minerals) | Sahin, Ali (King Fahd University of Petroleum and Minerals)
The lower Silurian Qusaiba Shale is one of the major source rocks for Paleozoic petroleum reservoirs in Saudi Arabia and is considered a potential shale gas resource. The study aims to evaluate the prospectivity and improve the production potential of Qusaiba shale by defining the lithofacies and mineralogy as controlling factors for brittleness and other mechanical parameters.
The continuous 30 feet subsurface cores and log data of Qusaiba Shale from Rub’ Al-Khali Basin were utilized for the study. Geological characteristics on the core were fully demonstrated in terms of size, mineralogy, color, primary structures and diagenetic features to identify lithofacies. In addition, 30 thin sections were used to study micro scale geological characteristics. The powder X-ray diffraction (XRD) was used to determined the mineralogical compositions. Surface morphology visualization and elemental analysis were performed using the scanning electron microscope supplemented with energy dispersive spectroscopy (SEM-EDS). Acoustic velocity measurements and compressive strength tests were performed on 15 core plugs (5 from each lithofacies).
Based on the above-mentioned analyses, three lithofacies were identified: (1) Micaceous laminated organic-rich mudstone facies (Lithofacies-I), (2) Laminated clay-rich mudstone facies (Lithofacies-II), and (3) Massive siliceous mudstone facies (Lithofacies-III). Mineralogical composition resulted in variable amounts of quartz ranging from 39 to 40, 45-55 and 60 to 78% for Lithofacies-I, II and III, respectively. Lithofacies-I having relatively lower quartz and higher clay percentage and total organic content (12% by volume) exhibited low stiffness. Mineralogy- and elastic parameters-based brittleness indices exhibited ductile behavior of this lithofacies. Lithofacies-II with relatively higher quartz (45 to 55%) and lower clay contents and TOC (3-5%) than Lithofacies-I resulted in relatively higher stiffness and brittleness. The brittleness index exhibited brittle behavior for silica rich Lithofacies-III (low TOC< 3%) as reflected by Young's modulus (average 32 GPa) and low Poisson's ratio (average 0.25). Hence, it is concluded that mineralogy and geological characteristics are the main controlling factors on mechanical properties and brittleness. The integration of three essential disciplines i.e. geology, mineralogy and geomechanics, plays the key role to better evaluate the production potential by highlighting the sweet spots within the heterogeneous shale gas reservoirs.