Today, almost half of Western Canada's natural-gas production comes from the Triassic-aged Montney formation, a sixfold increase over the last 10 years while gas production from most other plays has declined. In the last few years, demand for condensate as diluent for shipping bitumen has driven development of liquids-rich Montney natural gas leading to a surge in gas production and gas-on-gas competition in the Western Canadian Sedimentary Basin (WCSB), which has driven local natural gas prices down. This has had a material effect on the operations and finances of companies active in the Western Canada and is reshaping the Canadian gas industry. A significant portion of this growth has taken place in NE British Columbia and with the planned electrification of the industry in British Columbia, including the nascent LNG operations, will influence tomorrow's power industry in this region. NE British Columbia is a geographically large area with sparse population and the power supply into this region has lagged behind development of oil and natural gas resources. The area was originally served from geographically closer NW Alberta. More recently, supply was established from the BC Hydro power grid with the most significant developments being Dawson Creek-Chetwynd Area Transmission (DCAT) completed in 2016 and the additional 230 kV transmission projects scheduled for completion in 2021.
The seismic inversion method using the seismic onset times has shown great promise for integrating real- continuous seismic surveys for updating geologic models. However, due to the high cost of seismic surveys, such frequent seismic surveys are not commonly available. In this study, we focus on analyzing the impact of seismic survey frequency on the onset time approach, aiming to extend the advantages of onset time approach when infrequent seismic surveys are available.
To analyze the impact of seismic survey frequency on the onset time approach, first, we conduct a sensitivity analysis based on the frequent seismic survey data (over 175 surveys) of steam injection in a heavy oil reservoir (Peace River Unit) in Canada. The calculated onset time maps based on seismic survey data sampled at various time intervals from the frequent data sets are compared to examine the need and effectiveness of interpolation between surveys. Additionally, we compare the onset time inversion with the traditional seismic amplitude inversion and quantitatively investigate the nonlinearity and robustness for these two inversion methods.
The sensitivity analysis shows that using interpolation between seismic surveys to calculate the onset time an adequate onset time map can be extracted from the infrequent seismic surveys. This holds good as long as there are no changes in the underlying physical mechanisms during the interpolation period. A 2D waterflooding case demonstrates the necessity of interpolation for large time span between the seismic surveys and obtaining more accurate model update and efficient data misfit reduction during the inversion. The SPE Brugge benchmark case shows that the onset time inversion method obtains comparable permeability update as the traditional seismic amplitude inversion method while being much more efficient. This results from the significant data reduction achieved by integrating a single onset time map rather than multiple sets of amplitude maps. The onset time approach also achieves superior convergence performance resulting from its quasi-linear properties. It is found that the nonlinearity of the onset time method can be smaller than that of the amplitude inversion method by several orders of magnitude.
Steam Assisted Gravity Drainage (SAGD) is a complex process and often requires more control relative to conventional applications during production operations. Flow Control Devices (FCDs) have been identified as a technology that offers improved efficiency of the process while simplifying the operations. The first FCD completions were installed in SAGD wells in Canada over a decade ago with the intention of improving the steam chamber conformance and reducing the steam-oil ratio (SOR). While it is widely understood that FCD completions, for the most part, have helped achieve the desired uplift for SAGD producers, further optimization could be made on future completion designs and operation strategy by looking at actual performance data from previous installations. The objective of the study was to obtain key design parameters and considerations for future FCD completion designs.
The majority of FCD completions in MacKay River were tubing deployed, installed in previously producing wellbores (retrofit). This study looks at 11 wells that were completed with a Baker Hughes FCDs. The analysis was broken down into 2 segments: production analysis and modelling. Production strategy implemented for each well was taken into account to eliminate variances. The modelling used a combination of steady state simulation (presented in this paper) and numerical simulation (to be presented in part II).
The study showed that TD FCDs improve the performance of SAGD well pairs when implemented in the appropriate candidate wells. An important outcome was the development of a candidate wells’ selection criteria, to ensure the retrofit completion improved performance and did not exacerbate other problems. Furthermore, design consideration were identified to improve the performances of future TD FCD installations.
A sizeable portion of the Athabasca oil sand reservoir is classified as Inclined Heterolithic Stratification lithosomes (IHSs). However, due to the significant heterogeneity of IHSs and the minimal experimental studies on them, their hydro-geomechanical properties are relatively unknown. The main objectives of this study are investigating the geomechanical constitutive behavior of IHSs and linking their geological and mechanical characteristics to their hydraulic behavior to estimate the permeability evolution of IHSs during a Steam Assisted Gravity Drainage (SAGD) operation. To that end, a detailed methodology for reconstitution of analog IHS specimens was developed, and a microscopic comparative study was conducted between analog and in situ IHS samples. The SAGD-induced stress paths were experimentally simulated by running isotropic cyclic consolidation and drained triaxial shearing tests on analog IHSs. Both series of experiments were performed in conjunction with permeability tests at different strain levels, flow rates, and stress states. Additionally, an analog sample with bioturbation was tested to examine the hydro-geomechanical effects of bioturbation. Finally, the hydro-mechanical characteristics of analog IHS were compared with its constituent layers (sand and mud).
The microscopic study showed that the layers’ integration and grain size distribution are similar in analog and in-situ IHS specimens. The results also revealed that geomechanical properties of IHSs, such as shear strength, bulk compressibility, Young's modulus, and dilation angle, are stress state dependent. In other words, elevating confining pressure could significantly increase the strength and elastic modulus of a sample, while decreasing the compressibility and dilation angle. In contrast, the friction angle and Poisson's ratio are not very sensitive to changes in the isotropic confining stress. An important finding of this study is that the effect of an IHS sample's volume change on permeability is contingent on the stress state and stress path. Volume change during isotropic unloading-reloading resulted in permeability increases and sample dilation during compression shearing resulted in permeability decreases, especially at high effective confining stresses. Moreover, the tests revealed that the existence of bioturbation dramatically improves permeability of IHSs in comparison to equivalent non-bioturbated specimens but has negligible effects on its mechanical properties, which remain similar to non-bioturbated specimens. The results also showed that bioturbation has minimal impact on permeability changes during shearing. Lastly, experimental correlations were developed for each of the parameters mentioned above.
For the first time, specialized experimental protocols have been developed that guide the infrastructure and processes required to reconstitute analog IHS specimens and conduct geomechanical testing on them. This study also delivered fundamental constitutive data to better understand the geomechanical behavior of IHS reservoir and its permeability evolution during the in-situ recovery processes. Such data can be used to accurately capture the reservoir behavior and increase the efficiency of SAGD operations in IHS reservoirs.
Baek, Seunghwan (Texas A&M University) | Akkutlu, I. Yucel (Texas A&M University) | Lu, Baoping (Sinopec Research Institute for Petroleum Engineering) | Ding, Shidong (Sinopec Research Institute for Petroleum Engineering) | Xia, Wenwu (Harding Shelton Petroleum Engineering & Technology Limited)
Routine history-matching and reservoir calibration methods for horizontal wells with multiple hydraulic fractures are complex. Calibration of important fracture and matrix quantities is, however, essential to understand the reservoir and estimate the future recoveries. In this paper, we propose a robust method of simulation-based history-matching and reserve prediction by incorporating an analytical solution of production Rate Transient Analysis (RTA) as an added constraint. The analytical solution gives the fracture surface area contributing to the drainage of the fluids from the matrix into the fractures. The surface area obtained from the RTA is the effective area associated with the production—not total area. It is the most fundamental and the most significant quantity in the optimization problem. Differential evolution (DE) algorithm and a multi-scale shale gas reservoir flow simulator are used during the optimization. We show that the RTA-based optimization predicts the quantities related to completion design significantly better. Further, we show how the estimated total fracture surface area can be used to measure the hydraulic fracturing quality index, as an indication of the quality of the well completion operation. The most importantly, we predict that the fractures under closure stress begin to close much sooner (100 days) than the prediction without the RTA-based fracture surface area constraint. The deformation continues under constant closure stress for about 20 years, when the fractures are closed nearly completely. This work attempts to use the traditional reservoir optimization technologies to predict not only the reserve but also the life of the unconventional well.
Proper characterization of heterogeneous rock properties and hydraulic fracture parameters is essential for optimizing well spacing and reliable estimation of EUR in unconventional reservoirs. High resolution characterization of matrix properties and complex fracture parameters requires efficient history matching of well production and pressure response. We propose a novel reservoir model parameterization method to reduce the number of unknowns, regularize the ill-posed problem and enhance the efficiency of history matching of unconventional reservoirs.
Our proposed method makes a low rank approximation of the spatial distribution of reservoir properties taking into account the varying model resolution of the matrix and hydraulic fractures. Typically, hydraulic fractures are represented with much higher resolution through local grid refinements compared to the matrix properties. In our approach, the spatial property distribution of both for matrix and fractures is represented using a few parameters via a linear transformation with multiresolution basis functions. The parameters in transform domain are then updated during model calibrations, substantially reducing the number of unknowns. The multiresolution basis functions are constructed by eigen-decomposition of an adaptively coarsened grid Laplacian corresponding to the data resolution. High property resolution at the area of interest through the adaptive resolution control while keeping the original grid structure improves quality of history matching, reduces simulation runtime and improves the efficiency of history matching.
We demonstrate the power and efficacy of our method using synthetic and field examples. First, we illustrate the effectiveness of the proposed multiresolution parameterization by comparing it with traditional method. For the field application, an unconventional tight oil reservoir model with a multi-stage hydraulic fractured well is calibrated using bottom-hole pressure and water cut history data. The hydraulic fractures as well as the stimulated reservoir volume (SRV) near the well are represented with higher grid resolution. In addition to matrix and fracture properties, the extent of the SRV and hydraulic fractures are also adjusted through history matching using a Multiobjective Genetic Algorithm. The calibrated ensemble of models are used to obtain bounds of production forecast.
Our proposed method is designed to calibrate reservoir and fracture properties with higher resolution in regions that have improved data resolution and higher sensitivity to the well performance data, for example the SRV region and the hydraulic fractures. This leads to a fast and efficient history matching workflow and enables us to make optimal development/completion plans in a reasonable time frame.
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.
Olalotiti-Lawal, Feyi (Texas A&M University) | Onishi, Tsubasa (Texas A&M University ) | Kim, Hyunmin (Texas A&M University ) | Datta-Gupta, Akhil (Texas A&M University ) | Fujita, Yusuke (JX Nippon Oil & Gas Exploration Corporation) | Hagiwara, Kenji (JX Nippon Oil & Gas Exploration Corporation)
We present a simulation study of a mature reservoir for carbon dioxide (CO2) enhanced-oil-recovery (EOR) development. This project is currently recognized as the world’s largest project using post-combustion CO2 from power-generation flue gases. With a fluvial formation geology and sharp hydraulic-conductivity contrasts, this is a challenging and novel application of CO2 EOR. The objective of this study is to obtain a reliable predictive reservoir model by integrating multidecadal production data at different temporal resolutions into the available geologic model. This will be useful for understanding flow units along with heterogeneity features and their effect on subsurface flow mechanisms, to guide the optimization of the injection scheme and maximize CO2 sweep and oil recovery from the reservoir.
Our strategy consists of a hierarchical approach for geologic-model calibration incorporating available pressure and multiphase production data. The model calibration is performed using regional multipliers, and the regions are defined using a novel adjacency-based transform accounting for the underlying geologic heterogeneity. The genetic algorithm (GA) is first used to match 70-year pressure and cumulative production by adjusting pore volume (PV) and aquifer strength. Water-injection data for reservoir pressurization before CO2 injection is then integrated into the model to calibrate the formation permeability. The fine-scale permeability distribution consisting of more than 7 million cells is reparameterized using a set of linear-basis functions defined by a spectral decomposition of the grid-connectivity matrix (Laplacian grid). The parameterization represents the permeability distribution using a few basis-function coefficients that are then updated during history matching. This leads to an efficient and robust work flow for field-scale history matching.
The history-matched model provided important information about reservoir volumes, flow zones, and aquifer support that led to additional insight compared with previous geological and simulation studies. The history-matched field-scale model is used to define and initialize a detailed fine-scale model for a CO2 pilot area that will be used to study the effect of fine-scale heterogeneity on CO2 sweep and oil recovery. The uniqueness of this work is the application of a novel geologic-model parameterization and history-matching work flow for modeling of a mature oil field with decades of production history, and which is currently being developed with CO2 EOR.
The Lower Cretaceous McMurray Formation in western Canada has over 1.8 trillion barrels of bitumen resource in place. Due to the bitumen in its natural state having a very low API (6-12°) and corresponding high viscosity, traditional primary (pump jacks) and secondary (water flood) recovery techniques cannot be used. Instead, economic extraction of the bitumen occurs via surface mining and subsurface steam-assisted gravity drainage (SAGD). Using the Pike and Jackfish oil sands project areas as a case study, it will be shown that successful SAGD operations requires a thorough understanding of the depositional fabric and stratigraphic architecture of the reservoir.
Within the study area, reservoir intervals in the form of cross-bedded sandstones and sandy inclined heterolithic strata (IHS) are present within both the middle and upper McMurray. Overlying the middle McMurray are upper McMurray parasequence cycles reflective of brackish bays and deltaic embayment deposits. In many areas, however, these parasequences are absent and instead substituted by fluvial channels with brackish water overprint. The facies within these fluvial channels are very similar in character to the those seen within the middle McMurray. To help progress our understanding of baffles and barriers to flow within these aforementioned reservoir facies, dip meter and seismic data are presented as data that can be used. From this, a better understanding of the complex interplay of facies and stratigraphic relationships can be made. More importantly, clearer insights into SAGD performance (pre- and post-steam) can also be achieved.
Using the McMurray Formation as an underpinning, the wider implications of understanding fluvial sedimentation will be addressed by using reservoirs from the Middle East as examples. For example, many siliciclastic reservoirs in locations such as Kuwait (Wara Formation) and Iraq (Zubair Formation) are also influenced to a large degree by fluvial sedimentation. Not unlike SAGD, any successful secondary recovery techniques applied within these reservoirs will also require a detailed characterization of the channel stacking patterns and channel orientations prior to implementation.
Energy sources are vital to sustain and grow the world economy. As of today, the world mainly relies on fossil fuel as the source of energy for transportation, power generation, chemicals manufacturing, and other industrial applications. The conventional sources of hydrocarbon are steadily declining; however, the oil and gas industry has been successful in finding unconventional hydrocarbons, such as heavy oil and shale gas. There are distinct challenges in producing and processing the hydrocarbons from unconventional sources into usable end products. Reducing the footprint during the production of oil, refined products, and gas will benefit the industry by reducing the overall cost and improving the health, safety, and environmental impact.