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SPE and International Association of Drilling Contractors (IADC) University of North Dakota student chapters built a strategic partnership to host two collaborative events in the past 3 months. Energy transition and net-zero became the main subject of the sessions. In January, the team organized an integrated virtual workshop on Carbon Capture Utilization and Storage (CCUS). The event hosted 12 workshop presentations from 11 distinguished speakers covering theoretical and practical aspects of CCUS as part of the efforts to net-zero CO2 emissions. The virtual workshop discussed current CCUS initiatives and challenges, including subsurface geologic storage; CO₂-EOR/EGR; reservoir monitoring and risk assessment; case studies; policy and infrastructure; and non-technical considerations.
Temizel, Cenk (Saudi Aramco) | Canbaz, Celal Hakan (Ege University) | Palabiyik, Yildiray (ITU) | Hosgor, Fatma Bahar (Petroleum Experts LLC) | Atayev, Hakmyrat (ITU) | Ozyurtkan, Mustafa Hakan (ITU) | Aydin, Hakki (METU) | Yurukcu, Mesut (UTPB) | Boppana, Narendra (UTPB)
Abstract Hydraulic fracturing is a widely accepted and applied stimulation method in the unconventional oil and gas industry. With the increasing attention to unconventional reservoirs, hydraulic fracturing technologies have developed and improved more in the last few years. This study explores all applications of hydraulic fracturing methods to a great extent. It can be used as a guideline study, covering all the procedures and collected data for conventional reservoirs by considering the limited parameters of unconventional reservoirs. This paper intends to be a reference article containing all the aspects of the hydraulic fracturing method. A comprehensive study has been created by having a wide scope of examinations from the applied mechanisms to the technological materials conveyed from the different industries to utilize this technique efficiently. Furthermore, this study analyses the method, worldwide applications, advantages and disadvantages, and comparisons in different unconventional reservoirs. Various case studies that examine the challenges and pros & cons of hydraulic fracturing are included. Hydraulic fracturing is a promising stimulation technique that has been widely applied worldwide. It is challenging due to the tight and nanoporous nature, low permeability, complex geological structure, and in-situ stress field in unconventional reservoirs. Consequently, economic conditions and various parameters should be analyzed individually in each case for efficient applications. Therefore, this study provides the primary parameters and elaborate analysis of the techniques applied for a successful stimulation under SPECIFIC circumstances and provides a full spectrum of information needed for unconventional field developments. All the results are evaluated and detailed for each field case by providing the principles of applying hydraulic fracturing technologies. Many literature reviews provide different examples of hydraulic fraction methods; however, no study covers and links up both the main parameters and learnings from real cases worldwide. This study will fill this gap and illuminate the application of the hydraulic fracturing method.
Abstract The cluster spacing was considered up to 700 ft in Barnett and Bakken shale formations. At this time, tight cluster spacing has been used up to 15 ft apart in Eagle Ford and DJ Basin. The drive for applying tight fracture spacing is to increase the initial production rate. However, a higher initial production rate is at the expense of higher operation and completion costs in addition to operational complexity. This study presents an integrated workflow to investigate the effect of cluster interference on well performance. Analytical rate transient analysis (RTA) was combined with reservoir numerical simulation to calculate the effective fracture surface area for hydrocarbon production. The ratio of the effective fracture surface area from RTA analysis to the actual stimulated fracture area from the numerical simulation will be correlated to the cluster spacing. The economic study was added to investigate the optimum spacing based on the profitability of the well. The results showed that the well with a higher stage number and tighter cluster spacing will have high cluster interference with low effective to actual fracture surface area ratio. In addition, the well will drain the production area near the wellbore faster with the high initial production rate but with high production declining rate. Increasing the cluster spacing, with the same injected proppant volume, shows an increase in the effective to actual fracture surface area ratio, and low cluster interference. A lower initial rate was observed with a low production declining rate. From the economic study, spacing of 60 ft was found to be the optimum spacing based on the formation properties, capital cost, and gas price. As the interest rate and gas prices increases, or low capital costs, the optimum completion tends to be with tighter spacing to accelerate the production. The results from this study will assist the completion and help reservoir engineers to optimize the cluster spacing to maximize the well revenue.
Cryptocurrency is not the only game in town when it comes to using natural gas at the wellhead to reduce flaring. There are self-driving cars, the coming "metaverse," language processing, chat bots, and more, all of which require advanced computing and a lot of energy. The demand is driving an expansion of services for Crusoe Energy, which has been highlighted before both for its cryptocurrency mining facilities in the Bakken, and for its donation of computing services to research scientists modeling COVID-19 during the pandemic. CEO and cofounder of Crusoe Energy Chase Lochmiller said the company plans to grow employment in the Bakken from the 40 or so employed today to nearly 100 people in the near future. A lot of it will be Silicone Valley types of super computing that is in such demand today.
Abstract Forecasting production from unconventional reservoirs is challenging because of the uncertainty that arises from intricate fracture networks, complex transport mechanisms, and convoluted flow configurations. The accuracy of decline curve analysis for such reservoirs has been questioned due to the limited amount of long-term production data available. That being so, some unconventional reservoirs, such as the Bakken and the Barnett, have produced for 15-20 years, providing an adequate amount of data to validate the accuracy of the hyperbolic decline curve method, shed light on proper parameters – b and Di, and determine the amount of production history necessary to trust regression techniques. To test this, an extensive and versatile regression analysis model was built in Python using least squares optimization to match specific durations of production data – first 6 months, first year, first two years, etc. The model outputs the optimal parameters – b and Di –to match the specific duration. Additionally, fixed b values from 0.5 to 1.5 are tested where only Di is optimized through the model. To understand how accurately the models predict production, they are validated against the most recent 5 years of data, which was not included in the matching period. For a statistically significant sample size, around 700 wells in the Bakken and 1800 wells in the Barnett with start dates between 2005 and 2010 were used. The results show that in order to have confidence in the model's ability to predict production, more than 3 years of production data must be available. If 3 years of data is not available, the hyperbolic exponent, b, should be set close to 1.0 for Bakken wells (and likely other unconventional liquid rich wells) and between 1.0 and 1.2 for Barnett wells (and likely other unconventional gas wells). Additionally, the initial nominal decline rate, Di, should be chosen in accordance with the hyperbolic exponent. Not only do these guidelines result in satisfactory, long-term predictions, but they mitigate any significant error influenced by the underlying relationships between b and Di. These curve-altering relationships induce both positive and negative impacts on the predictions. If b is improperly chosen, overestimation in late-life production profiles may ensue. Alternatively, if Di is improperly chosen, early-life production may be too high. Since production forecasting is a necessity for a company to determine its present value, this paper provides knowledge and guidance regarding forecasting procedures and parameter settings for North American unconventional operators. Using decline curve analysis to accurately predict oil and gas rates is pertinent to the longevity of these unconventional reservoirs.
Abstract Horizontal drilling and multistage hydraulic fracturing applied in shale formations over the past decade. Economic productivity was achieved by generating a large fracture surface area. The cluster spacing was considered up to 700 ft in Barnett and Bakken shale formations. At this time, tight cluster spacing has been used up to 15 ft apart in Eagle Ford and DJ Basin, moreover, the operators are trying even closer cluster spacing. The drive for applying tight fracture spacing is to increase the initial production rate. However, a higher initial production rate is at the expense of higher operation and completion cost in addition to operation complexity. This study presents an integrated workflow to investigate the effect of cluster interference on well performance. Analytical rate transient analysis (RTA) was combined with reservoir numerical simulation to calculate the effective fracture surface area for hydrocarbon production. The ratio of the effective fracture surface area from RTA analysis to the actual stimulated fracture area from the numerical simulation will be correlated to the cluster spacing. A proxy model was built to estimate the effective to actual stimulated fracture area as a function of completion and reservoir parameters. Finally, the integrated workflow was applied in actual field data for two gas-shale wells. The results showed that the well with a higher stage number and tighter cluster spacing will have high cluster interference with low effective to actual fracture surface area ratio. In addition, the well will drain the production area near the wellbore faster with the high initial production rate but with high production declining rate. Increasing the cluster spacing, with the same injected proppant volume, shows an increase in the effective to actual fracture surface area ratio, and low cluster interference. A lower initial rate was observed with a low production declining rate. The results from this study will assist the completion and reservoir engineers to optimize the cluster spacing to maximize the well revenue.
Abstract Production wells within the northeast (NE) Elm Coulee experience significantly higher water cuts than wells within Elm Coulee Proper. The increased water production has a negative economic impact on Bakken operators seeking to maximize profitability within the area. A reservoir engineering-based research project has been conducted to determine the source of the increased water production within the NE Elm Coulee, and to identify recommendations for operators to mitigate the water production related expenses in the area. One option for the increased water production is from the water saturation within the matrix of the Middle Bakken Shale, and another possibility is from the Three Forks formation by vertical migration through natural fracture networks. Previous work has identified the presence of natural fracture systems within the Bakken that may be creating flow networks between stratigraphic layers. Numerous flow simulation models of the NE Elm Coulee were constructed to determine the source of the produced water. The reservoir models consist of three hydraulically fractured horizontal wells within the Middle Bakken Shale, and it incorporates the naturally fractured state of the Bakken through a discrete fracture network (DFN). Various reservoir parameters were altered within the envelope of uncertainty to obtain a history match for the reservoir model to both scenarios, and the resulting parameters from the Middle Bakken saturation case are more realistic and produce better history matching results than the Three Forks water migration case. The Three Forks fracture model produces an unrealistically high volume of water, and the breakthrough pattern is not consistent with field measurements. Thus, the source of the increased water production appears to come from matrix water saturation within the Middle Bakken Shale. Many relevant aspects of unconventional reservoir simulation are incorporated into the project; therefore, the methodology used in the research can help assist reservoir engineers that are modeling unconventional petroleum reservoir with stacked stratigraphic intervals. Modeling natural fractures and complex completion fracture networks using a DFN, pressure dependent permeability, and history matching in unconventional reservoirs are important topics that are discussed in the paper. Operators within the Bakken can use this information to better understand the geologic implications of producing in the area.
A year ago, a different kind of pipeline project was announced in the Midwest. Most pipelines pick up oil or gas from a well and deliver it to customers who burn it, emitting carbon dioxide into the atmosphere. This one would run almost in reverse. A company called Summit Climate Solutions planned to capture carbon dioxide from ethanol refineries in Iowa, Minnesota, Nebraska, and the Dakotas, and then transport it via the proposed pipeline to a site in North Dakota where the CO2 would be buried deep underground. In the months since, two more companies have proposed similar CO2 pipeline projects in the Midwest, and another wants to expand an existing pipeline in the South.
Abstract As the unconventional shale development matures, the industry has been actively seeking new ways to unlock incremental value beyond primary depletion. In particular, the miscible gas injection EOR via huff-and-puff technique has garnered interest in recent years. However, the pilot tests in the field have shown lower recoveries than initially predicted by laboratory and simulation studies. The objective of this study was to develop a systematic approach to upscale the EOR results from laboratory scale to field scale and better predict recoveries. One of the issues with existing laboratory and modeling studies is the assumption of constant-pressure or constant-rate boundary conditions at the fracture interface during the soaking stage, which is rarely achieved. A mathematical model is developed to represent this scenario better by modeling mass diffusion of a limited volume of well-stirred fluid in a non-porous body (remaining injected gas in the fracture network at the end of injection phase as compressed gas) into a porous medium (matrix). The matrix is characterized as an ensemble of rock pillars separated by fracture discontinuities to represent field conditions better. The rock pillars are of different thicknesses, with their thickness gradually increasing, moving away from the main fracture cluster. And finally, the concept of Dynamic Penetration Volume, which controls the amount of contacted oil by the EOR agent, is explored further as a function of the micro-fracture distribution function. Ultimately, this information was used to derive an updated a priori equation to better predict recovery factors of EOR processes in the field. For upscaling, we integrated concepts from both geomechanics and fluid flow. We used an existing correlation relating the fracture frequency & distribution observed in the lab-scale experiments to the fracture density in the field. By doing so, we can upscale the micro-fracture distribution to their field-scale counterparts. Although diffusion is the main transport & recovery mechanism, this study found that the fracture geometry created near-wellbore, i.e., fracture spacing & distribution, has a first-order effect on the efficacy of the huff-and-puff process in the field. It was also observed that by varying the soaking times of each cycle, the issue of penetration length could be resolved (as it increases as a function of √time). Additionally, focusing on understanding the near-wellbore fracture geometry would help operators optimize their gas injection schemes. The updated upscaling equation will help understand the huff-and-puff process better and predict the expected recoveries in the field more accurately. Additionally, it would help operators adjust and optimize soaking times for the process using a mechanistic approach.
The Bakken and Three Forks formations have been treated as isolated pay zones since shale development took off in North Dakota more than a decade ago. Operators of the ultratight plays have acted on this thinking through drilling and completion programs that targeted each rock layer independently. One of the companies to lead such programs is Hess Corp. However, subsurface specialists within the regional stalwart have acquired new subsurface information over the past year that may steer the company toward drilling horizontal wells into just one of the two intervals--the more prolific Middle Bakken. Craig Cipolla boiled it down this way: "I think the big takeaway here is that the data suggest the Middle Bakken wells can drain the Three Forks from 450 ft away."