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Collaborating Authors
Hoffman, Todd
Abstract It is vital to increase awareness and knowledge of petroleum engineering and the petroleum industry to the next generation of potential workers. This paper provides information about a program to educate Montana middle and high school math and science teachers about the oil and gas industry. We desire that stakeholders from other states can use this program as a model to create similar courses. The Montana Tech Petroleum Engineering Department organized and implemented a one-week short course with (1) classroom material, including hands-on examples to showcase various aspects of developing and producing oil and gas reservoirs, and (2) field trips to observe field production operations, a CO2 flood, and a refinery. Montana Tech joined with industry partners and regulatory agencies to provide relevant and meaningful content. The various aspects of the petroleum industry were discussed, including exploration, drilling, completions, production, facilities, artificial lift, and reservoir management. In addition, we covered sustainability, energy sources and uses, climate change, and potential solutions (e.g. CO2 sequestration). A previous version of this course ran from 2006-2015 and was supported by our state's oil and gas commission. In 2022, it was restarted and updated with funding from Hess Corporation. It was hosted on the university campus with educational materials, field trips, and room and board provided at no cost to the participants. The new short course was an overwhelming success. The teachers learned about the oil and gas industry and took this knowledge back to their classrooms across the state of Montana. Another benefit for the teachers is that they received continuing education credits, which they need to keep their teaching certificates current. The value for Montana Tech and the petroleum industry is that young adults entering college or the workforce will have more knowledge about oil and gas operations since their teachers are better informed and pass on their experience. Based on the success from 2022, the program is scheduled again for the summer of 2023 and expanded to include high school guidance counselors. This paper will expand awareness of our Teacher's Workshop so it can be easily implemented in other regions where this program could be beneficial. The paper contains the content, workflows, and potential pitfalls so anyone implementing a similar course can use what we have learned as a starting point.
- North America > United States > Montana (1.00)
- North America > United States > Texas > Travis County > Austin (0.29)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.50)
- North America > United States > Wyoming > Bighorn Basin (0.99)
- North America > United States > Montana > Bighorn Basin (0.99)
Abstract Identifying contact angles in porous media is essential for characterizing multiphase flow of fluids in reservoirs. Traditional methods to measure contact angles assume a homogenous structure of reservoir rock; however, microscale pictures by Scanning Electron Microscopes (SEM) show that rock composition varies even inside a single pore. In addition, the preferentiality of oil layer formation is different according to the minerals constituting the reservoir rock. As a result, contact angles have heterogeneous behavior at the pore-scale. For the purpose of this research, contact angles are measured on the pure minerals that make up the main components of a Bakken reservoir rock. Investigations of different minerals show that each mineral has a different contact angle from the other minerals at the same medium properties. Altering medium properties, such as salinity, also shows different contact angle behavior according to the mineral tested. However, these separate contact angles alone do not explain how this heterogeneous mineral composition would affect the reservoir. Therefore, a pore scale network model is utilized to study the effect of heterogeneity of mineralogical content on oil recovery. The model is built to simulate the flow of fluids in a mineralogically heterogeneous pore network system. It incorporates the contact angles measured on the pure components; thus, fractional wettability caused by the changes in mineral composition is integrated into the model. The most practical benefit of the model is that it was used to calculate relative permeability and capillary pressure curves, which are difficult to obtain for unconventional reservoirs. In general, this research calls more attention to the mineral properties of reservoir rock, which leads to a better understanding and characterization of the reservoir. It became clear that the mineralogical content plays a significant role in low salinity flooding where contact angles generally decreases with water compared to contact angles measured in brine. These results will lead to better understanding of heterogeneous reservoir behavior, as well as the effect of Improved Oil Recovery (IOR) projects, such as waterflooding, on oil production in shale formations.
- Geology > Mineral (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.92)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.46)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > Montana > Williston Basin > Bakken Shale Formation (0.98)
- North America > United States > North Dakota > Williston Basin > Three Forks Group Formation (0.89)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (1.00)
Experimental and Numerical Study on Spontaneous Imbibition of Fracturing Fluids in the Horn River Shale Gas Formation
Zhou, Zhou (China University of Petroleum, Beijing) | Hoffman, Todd (Montana Tech) | Bearinger, Doug (Nexen Energy) | Li, Xiaopeng (Colorado School of Mines) | Abass, Hazim (Colorado School of Mines)
Summary After hydraulic fracturing, only 10 to 50% of the fracturing fluids is typically recovered. This paper investigates how the remaining fracturing fluids are imbibed by shale as a function of time, and it investigates the influence of various parameters on the imbibition process that include lithology, reservoir characteristics, and fluid properties. In addition, on the basis of experimental results, a numerical model has been developed to estimate the volume and rate of spontaneous imbibition over the entire fracture face. The rock samples are from the Horn River formation onshore Canada. The fracturing fluids used in the experiments included 2% KCl, 0.07% friction reducer, and 2% KCl substitute. In the experimental control group, distilled water was used. Through spontaneous-imbibition experiments, the relationship between imbibed fluid volume and time indicated that clay content was the most important factor that affected the total imbibed amount. Shale matrix with high clay content could imbibe more fracturing fluids than its measured porous space because of the clay's strong ability to expand and hold water. According to contact-angle-test results, the strongly water-wet shale samples had a faster imbibed rate. Total organic carbon (TOC) and porosity had no influence on imbibed volume and rate. These experimental findings can contribute to an improved fracturing-fluid design for different shale-formation conditions to reduce fluid loss. The experiment showed that 2% KCl and 2% KCl substitute fracturing fluids were imbibed from 10 to 40% less than 0.07% friction reducer in the shale formation with high clay content, whereas in the shale formation with low clay content, the opposite occurred. In the low-clay-content shale, 0.07%-friction-reducer test fluid was imbibed from 10 to 30% less than 2% KCl fluid, but had an imbibed amount similar to that of 2% KCl substitute fluid. The numerical-model result was matched with the experimental result to estimate a relative permeability in the model that could represent the rock properties. This model could be used to estimate the total imbibed volume along fracture faces through spontaneous imbibition.
- North America > United States (1.00)
- Asia (1.00)
- North America > Canada > British Columbia (0.64)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Mineral > Silicate (1.00)
- North America > United States > West Virginia > Appalachian Basin (0.99)
- North America > United States > Virginia > Appalachian Basin (0.99)
- North America > United States > Tennessee > Appalachian Basin (0.99)
- (8 more...)
Summary There is tremendous potential for shale oil reservoirs such as the Bakken formation, Eagle Ford and Niobrara to have a lasting impact on the U.S energy situation due to the multi-billion barrel resource base that these formations contain. Horizontal drilling and multi-stage hydraulic fracturing technologies have allowed significant oil to be produced; however, the primary recovery factors are still less than 10%, which means enhanced oil recovery methods needs to become the next big push in shale oil research. Miscible gas injection may become the most effective method in such lower permeability fields, because conventional water flooding may result in extremely lower injectivity. This work expands on previous research from Shoaib and Hoffman (2009) which focused on the Elm Coulee field in Eastern Montana and showed miscible gas injection may be a possible solution for shale oil reservoirs. The wells in their study had longitudinal hydraulic fractures, whereas today most wells have transverse fractures. The significance of this research is to evaluate the reservoir performance of the CO2 flooding with different hydraulic fracture orientations and recommends the best hydraulic fracture orientation which can maximize the oil production. In this paper, separate simulation models with multiple transverse hydraulic fractures wells and longitudinal hydraulic fractures wells have been built based on a sector of the Elm Coulee field. Two different grid models (uniform grid models and local grid refinement (LGR) models) have been applied for the two types of hydraulic fracture for primary recovery and secondary recovery. Breakthrough time, total oil production, ultimate recovery factor and injection effectiveness for different cases have been determined and compared to find the best hydraulic fracture orientation in Elm Coulee field. Hydraulic fracture permeability sensitivity and bottom hole pressure (BHP) sensitivity analysis have also been made based on the LGR CO2 injection models. Results show that both transverse and longitudinal fractures produce similar amounts of oil, but with transverse fractures, the CO2 breakthrough time is much earlier, and the CO2 production rate and cumulative production are much higher. Thus, the injection quantities are much greater for the transverse cases, and its overall injection efficiency is less. This work forms the foundation to begin understanding how to best perform CO2 injection enhanced oil recovery (EOR) in Bakken shale oil reservoirs. URTeC 1580226
- North America > United States > North Dakota > Mountrail County (0.76)
- North America > United States > Montana > Richland County (0.76)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.88)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.47)
- North America > United States > Montana > Williston Basin > Elm Coulee Field > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.91)
- North America > United States > North Dakota > Williston Basin > Bakken Shale Formation (0.91)
- (4 more...)
Abstract There is an uncertainty over the production contribution from the Upper and Lower (U&L) Bakken Shale to the Middle Bakken reservoir. For the Bakken system, reservoir studies involving the fluid flow and recovery mechanism cannot be fully understood without resolving this uncertainty. Performance-anomalies in the GOR trends of the production-history of the Middle Bakken wells in the Reunion Bay, Sanish, Parshall and the Elkhorn-Ranch fields indicate the possibility of the anticipated contribution. Quantifying the U&L Shale contribution requires knowledge of the mechanism of fluid storage and flow in the liquid rich shale systems. For the U&L Shale, adsorption is considered as the significant mode of fluid storage, and the process of diffusion is considered crucial for the matrix-to-fracture fluid transfer. The governing mathematical equations for desorption and diffusion was adopted from the shale gas systems. These equations are utilized in CMGโข's compositional simulator GEMโข to propose a reservoir simulation-based quantification scheme for the U&L Shale contribution. Through the sensitivity analyses, the effect of variation in the parameters of the U&L Shale, the Middle Bakken layer and the hydraulic fracture is investigated. Utilizing the ranges of these parameters, the U&L Shale layers are found to contribute from 12% to 52% of the cumulative production from a Middle Bakken well, whereas, the mean contribution is 40%. Relative sensitivity study suggested that the U&L Shale production contribution is the most sensitive to the U&L Shale matrix parameters, such as total organic carbon (TOC, wt.%) and molecular diffusion coefficients. The TOC controls the desorption-parameters; therefore, the findings suggest that the phenomena of desorption and diffusion are expected to play a crucial role in the anticipated production-contribution. Introduction The Bakken Formation lies within the oil-window of the vast Williston Basin, which extends over the regions of North Dakota, Montana and the Canadian province of Saskatchewan (Figure 1). The production history of the Bakken wells in Figure 2 suggests that before year 2000, most Bakken wells provided marginal economic success, partially because of extremely low matrix permeability (0.0001-.01 mD) and meager chances of exploiting the many localized natural fractures with a vertical well. Commercial production and development activities have become increasingly economically viable in recent years with the advances in horizontal drilling and the use of multi-stage fracture stimulation. In the month of March, in 2013, the Bakken play in North Dakota alone produced with an average daily rate of 0.71 Million BOPD and 681 MMSCF of gas per day. URTeC 1581459
- North America > United States > Montana (1.00)
- North America > Canada > Saskatchewan (1.00)
- North America > United States > North Dakota > Mountrail County (0.47)
- North America > United States > South Dakota > Williston Basin > Bakken Shale Formation (0.99)
- North America > United States > North Dakota > Williston Basin > Three Forks Group Formation (0.99)
- North America > United States > Montana > Williston Basin > Elm Coulee Field > Bakken Shale Formation > Middle Bakken Shale Formation (0.99)
- (7 more...)
From reservoir exploration to field abandonment, reservoir modeling plays a central role in understanding and predicting the reservoir key geologic, geophysical, and engineering components. Reservoir models, either as a simple layer cake or as a complex, fully 3D description of structural components, rock and fluid properties, are ideal gateways for aggregating data and expertise from different sources and disciplines. The complexity of such models should be driven by the practical reservoir management question raised, be it the estimation of OOIP (reserve question) or the development and planning of wells/surface facilities and recovery strategies (flow question). At the same time, the limitation of reservoir models should be well understood: reservoir models can only mimic the reservoir's true complexity; they can never fully (nor need they) represent the actual subsurface heterogeneity.
- Africa (0.86)
- North America > United States > California (0.28)