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.
Objectives/Scope: In order to maximize the recovery of hydrocarbons from liquids rich shale reservoir systems, the cause and effect relationships between production and the stimulation methods need to be clearly understood. In this study, we utilize multivariate regression models to narrow down the variables in flow simulation models and their range. We then use the flow simulation model to understand the fractured well production behavior and field wide well performance in a liquids rich petroleum system in the Duvernay Basin.
Methods, Procedures, Process: Statistical models assume no physical relationship between the model parameters and the response variable, which in this case is produced volumes over a period of time. On the other hand, simulation studies incorporate physical mechanisms of flow to model and predict the production behavior. The simulation models, however, fall short of incorporating all the mechanisms contributing to the production behavior in the complex shale gas reservoir. Thus there is a need for integration of statistical approaches of understanding production behavior along with physics based model and simulation approach. We use the statistical methods to identify the important physical mechanisms that control the production.
Results, Observations, Conclusions: Multivariate linear regression analysis of the 6 month produced volume and its relationship with parameters such as fracture fluid volumes used, proppant weight placed, number of stages fractured provides a model with reasonably good correlation. The 6 month produced volumes correlate with large proppant weights, lower fluid placements and greater density of fracture stages. Use of Random Forests machine learning algorithm on the dataset confirms that the total proppant placed, well length completed with fractures have high importance coefficients. In order to examine the well performance using full physical models, fractured well simulations are performed on particular wells using the trilinear model. The trilinear model predictions are then compared against other production analyses and the regression model results for consistency. The models showed that in the absence of stress dependent permeability, the production forecast was much higher. Thus, stress dependent permeability appears to be an important factor in the modeling and prediction of production from liquids rich shale reservoirs.
Novel/Additive Information: In this study we describe a method to understand the production data from a liquids rich shale reservoir, by integrating multivariate linear regression analysis, machine learning algorithms along with physical model simulations. The results are novel and offer a method to validate either approach to understand cause and effect relationships. This approach may be classified as a new hybrid modeling workflow that may potentially be used to optimize stimulation techniques in liquids rich shale reservoirs.
Oil production from shale and tight formations will increase to more than 6 million barrels per day (b/d) in the coming decade, making up most of total U.S. oil production (> 50%). However, achieving an accurate formation evaluation of shale faces many complex challenges. One of the complexities is the accurate estimation of shale properties from well logs, which is initially designed for conventional reservoirs. When we use the well logs to obtain shale properties, they often cause some deviations. Therefore, in this work, we combine cores and well logs together to provide a more accurate guideline for estimation of total organic carbon, which is primarily of interest to petroleum geochemists and geologists.
Our work is based on Archie's equation. Resistivity log will lead to some incorrect results, such as total resistivity, when we follow the conventional interpretation procedure in well logs. Porosity is another complex parameter, which cannot be determined only by well log, i.e. density, NMR, and Neutron log. Therefore, the flowchart of TOC calculation includes five main parts: (I) the shale content calculation using Gamma log; (II) the determination of shale distributions using Density and Neutron logs and cross-plot; (III) the calculation of total resistivity at different distribution types; (IV) obtaining porosity using core analysis, NMR and density logs; and (V) the calculation of TOC from modified Archie's equation.
The results indicate that the shale content has a strong effect on estimation of water saturation and hydrocarbon saturation. Especially, the effect of shale content is exacerbated at a low water saturation. A more accurate flowchart for TOC calculation is established. Based on Archie's equation, we modify total resistivity and porosity by combining Gamma Log, Density Log, Neutron Log, NMR Log, and Cross-plot. An easier way to estimate porosity is provided. We combine the matrix density and kerogen density together and obtain them from core analysis. Poupon's et al. (1954) laminar model has some limitations when applying in shale reservoirs, especially at a low porosity.
Literature surveys show few studies on the flowchart of TOC calculation in shale reservoirs. This paper provides some insights into challenges of well logs, core analysis in shale reservoirs and a more accurate guideline of TOC calculation in shale reservoirs.
Stephenson, Tim (Flotek Industries) | Oswald, Darin (Flotek Industries) | Dwyer, Pat (Flotek Industries) | Brown, Derek (Flotek Industries) | Ndefo, Emeka (Flotek Industries) | Kiran, Sumit (Crescent Point Energy) | Smith, Jeff (Crescent Point Energy) | Gaffney, Breandan (Crescent Point Energy)
Application of chemistries for waterflooding has traditionally required a significant upfront investment in core flood testing. Investments of this sort equate to money and time spent on a reservoir screening tool which does not guarantee an accurate translation into pilots. The aim of this paper is to explore core flood results in conjunction with pilot results for conventional and unconventional reservoirs where microemulsions are deployed in order to enhance oil recovery.
Microemulsions act as a delivery platform for solvent (terpene) and surfactant mixtures throughout a given rock volume. Their ability to alleviate damage and change the energetics of surfaces is believed to enhance mobilization of oil. They’re optimized for a given reservoir in the laboratory based on fluid-fluid and fluid-rock interactions. This includes adsorption (persistency), asphaltene wash-off, demulsification, drop size, and interfacial tension testing. We in turn label changes in injectivity of water as well as increases in oil production as indicators of success in core floods and pilots.
The above strategy has led to microemulsion optimization in Taylorton Bakken (which is more conventional) and Lower Shaunavon (which is more unconventional) in SE and SW Saskatchewan, Canada. These are characterized by changes in permeability, temperature, mineralogy (quartz vs calcite), oil (paraffinic vs asphaltenic) and water (high vs low salinity). This study demonstrates a beneficial core flood and pilot response in conventional reservoirs using microemulsions. What’s however interesting and noteworthy is that the core flood response is negligible in unconventionals (<5% incremental oil recovery) due in part to asphaltenes plating out on the core’s exterior surface during restoration of wettability, whereas the pilot response is quite positive.
The major highlight of this work is the need to address the discrepancy in core flood testing and pilot results in unconventional reservoirs. This is required before core flood testing can be used as a reliable screening tool for unconventional reservoirs. We’ve furthermore demonstrated the beneficial impact of microemulsions in both conventional and unconventional reservoirs as well as the need for optimization based on fluid-fluid and fluid-rock interactions.
Hansen, Mary (McDaniel & Associates Consultants) | Hamm, Brian (McDaniel & Associates Consultants) | Wynveen, Jared (McDaniel & Associates Consultants) | Schlosser, Tyler (McDaniel & Associates Consultants) | Jenkinson, David (McDaniel & Associates Consultants) | Dang, Hoang (McDaniel & Associates Consultants)
Unconventional reservoirs with low permeability shales and siltstones are currently being developed using horizontal wells in multiple layers. As this development technique has become more common, accurately understanding well-to-well communication is increasingly critical. Well positioning, reservoir thickness and well interference effects are important factors in the success of multi-layer development. Traditional well density metrics such as wells per section and lateral well spacing do not account for the multi-layer nature of these plays. This paper introduces readily derived metrics that enable a three-dimensional (3D) quantification of multi-layer well density.
Unlike traditional analysis which considers pad development from a bird’s eye view, this paper considers the vertical cross-section of a pad which enables the 3D drainage to be quantified. The metrics Cross-Sectional Drainage Area (XDA) and Three-Dimensional Proppant Intensity (3DPI) are defined. XDA quantifies the well density relative to the thickness of the reservoir. 3DPI represents completion intensity and reservoir stimulation relative to the cubic volume of gross rock attributed to the multi-layer development. Once introduced, these two metrics are correlated to well and pad level performance. Examples from the Montney Formation in Western Canada and the Bakken Formation in North Dakota, USA are studied in detail.
Ultimate hydrocarbon recovery factors, early time well performance and production profiles are analyzed and compared to the XDA and 3DPI metrics using visual analytics and multivariate machine learning models. In both the Montney and Bakken examples, XDA correlates with well performance and 3DPI correlates with pad hydrocarbon recovery factors.
This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken. An 18-well numerical-simulation model was built to represent an operator’s Lower Shaunavon waterflood-pilot area. Numerical simulation was used, and a history match on the pilot area was performed.
This paper evaluates the incremental benefit of water injection in a conventional gas reservoir when compared with gas compression. This paper presents the performance results from one of the waterflood pilots in the Viewfield Bakken. Understanding of formation damage is a key theme in a waterflood project. An integrated multidisciplinary approach is required to determine an optimal design and strategy.
Achieving high hydrocarbon recovery is challenging in unconventional tight and shale reservoirs. Although EOR/EGR processes could potentially improve the recovery factor beyond the primary depletion, large-scale field application of these processes are not yet established in these reservoirs. This session will focus on the latest research trends, modelling and experimental work to better understand issues involved in improved economic recovery from such reservoirs.
Cold heavy oil production with sand (CHOPS) is a relatively recent technology. As such, only a few case histories of its application over a number of years have been published. Nonetheless, those that are available provide insight into the application of this technology. A detailed Luseland field case history has been published.
The amount of trapped oil in hydrocarbon rich shale reservoirs recoverable through Enhanced Oil Recovery methods such as low salinity water flooding has been an ongoing investigation in the oil and gas industry. Reservoir shales typically have relatively lower amounts of swelling clays and in theory, can be exposed to a higher chemical potential difference between the native and injected fluid salinity before detrimental permeability reduction is experienced through the volumetric expansion of swelling clays. This fluid flux into the pore spaces of the rock matrix acting as a semi permeable membrane is significant enough to promote additional recovery from the extremely low permeability rock. The main goal of this paper is to determine how osmosis pressure build up within the matrix affects geomechanical behavior and hydrocarbon fluid flow. In this study we investigate Pierre shale samples with trace amount of organic content and high clay content as an initial step to fully understanding how the presence of organic content affects the membrane efficiency for EOR applications in shales using low salinity fluid injection. The same concept is also valid when slickwater is utilized as fracturing fluid as majority of the shale reservoirs contain very high salinity native reservoir fluid that will create large salinity contrast to the injected slickwater salinity.
The organic-rich reservoir shales typically have a TOC content of approximately 5 wt% or higher with TOC occupying part of the bulk matrix otherwise to be filled up by clays and other minerals. With less clay within the rock structure, the amount of associated clay swelling arising from rock fluid interaction will be limited. The overall drive of water into the matrix brings added stress to the pore fluid known as osmotic pressure acting on the matrix that also creates an imbalance in the stress state. The native formation fluid with salinity of 60,000 ppm NaCl has been used while 1,000 ppm NaCl brine is utilized to simulate the low salinity injection fluid under triaxial stress conditions in this phase of the study reported here. A strong correlation is obtained between the osmotic efficiency and effective stress exerted on the shale formation. The triaxial tests conducted in pursuit of simulating stress alteration under the osmotic pressure conditions and elevated pore pressure penetration tests indicated that the occurrence of swelling directly impact the formation permeability. These structural changes observed in our experimental results are comparable to field case studies.