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Collaborating Authors
Salahshoor, Shadi
Abstract Leveraging publicly available data is a crucial stepfor decision making around investing in the development of any new unconventional asset.Published reports of production performance along with accurate petrophysical and geological characterization of the areashelp operators to evaluate the economics and risk profiles of the new opportunities. A data-driven workflow can facilitate this process and make it less biased by enabling the agnostic analysis of the data as the first step. In this work, several machine learning algorithms are briefly explained and compared in terms of their application in the development of a production evaluation tool for a targetreservoir. Random forest, selected after evaluating several models, is deployed as a predictive model thatincorporates geological characterization and petrophysical data along with production metricsinto the production performance assessment workflow. Considering the influence of the completion design parameters on the well production performance, this workflow also facilitates evaluation of several completion strategies toimprove decision making around the best-performing completion size. Data used in this study include petrophysical parameters collected from publicly available core data, completion and production metrics, and the geological characteristics of theNiobrara formation in the Powder River Basin. Historical periodic production data are used as indicators of the productivity in a certain area in the data-driven model. This model, after training and evaluation, is deployed to predict the productivity of non-producing regions within the area of interest to help with selecting the most prolific sections for drilling the future wells. Tornado plots are provided to demonstrate the key performance driversin each focused area. A supervised fuzzy clustering model is also utilized to automate the rock quality analyses for identifying the "sweet spots" in a reservoir. The output of this model is a sweet-spot map that is generated through evaluating multiple reservoir rock properties spatially. This map assists with combining all different reservoir rock properties into a single exhibition that indicates the average "reservoir quality"of the formation in different areas. Niobrara shale is used as a case study in this work to demonstrate how the proposed workflow is applied on a selected reservoir formation whit enough historical production data available.
- North America > United States > Wyoming (1.00)
- North America > United States > Texas (1.00)
- North America > United States > Colorado (0.89)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.72)
- Geology > Geological Subdiscipline > Geomechanics (0.54)
- North America > United States > Wyoming > Laramie Basin > Niobrara Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- (31 more...)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Data mining (1.00)
- Data Science & Engineering Analytics > Information Management and Systems > Artificial intelligence (1.00)
- Information Technology > Artificial Intelligence > Machine Learning > Neural Networks (0.96)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Clustering (0.69)
- Information Technology > Artificial Intelligence > Representation & Reasoning > Uncertainty > Fuzzy Logic (0.69)
- Information Technology > Artificial Intelligence > Machine Learning > Statistical Learning > Regression (0.48)
Abstract This study presents the application of a data-driven workflow for evaluating the completion design and production performance of the horizontal Wolfcamp wells located in the Midland Basin at the Hydraulic Fracturing Test Site (HFTS1). Leveraging the diverse and comprehensive datasets available at HFTS, the impact of various factors including completion design, reservoir properties, well spacing, and geospatial distribution of more than 400 hydraulic fracturing stages on the well performance is evaluated. The proposed workflow assesses the impact of variations in the reservoir properties and completion design parameters on the formation response to the hydraulic fracturing work as well as production performance. It exhibits that the fracturing gradients calculated based on the measured instantaneous shut-in pressures (ISIP) are good indicators of the formation heterogeneity along the laterals in both the upper and middle Wolfcamp formations. Fracturing gradients are strongly correlated with both reservoir properties and well treatment factors and production performances are highly impacted by the inter-well communications resulted from the fracturing behavior. The supervised multivariate analysis in this work provides an insight into the importance of selecting the optimum completion design on a well by well basis, highlighting the importance of adapting the design of hydraulic fracturing stages to the formation characteristics along the lateral placements of the horizontal wells by adjusting the perforation densities and proppant load. It also indicates that the presence of the offset verticals contributes to the fracture network complexity which positively impacts the ultimate fracturing potential in the nearby stages. Results suggest that aggressive stimulation in the regions with a higher range of fracturing gradient and higher clay content adversely impacted the production performance. It is also observed that the best performing wells, from the oil production standpoint, are those that experienced completion and treatment variations compatible with the formation characteristics along the laterals and improved fracturing techniques. Four main categories of data are used in this workflow including formation parameters, completion design attributes, geospatial distribution of hydraulic fracturing stages, and the formation response to the hydraulic fracturing work. This workflow utilizes data from different disciplines to explain how different parameters can impact the production behavior of a well.
- Research Report > New Finding (0.49)
- Research Report > Experimental Study (0.35)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Midland Basin (0.99)
- (7 more...)
Abstract The Hydraulic Fracturing Test Site (HFTS) in the Permian-Midland basin has bridged the gap between inferred and actual properties of in-situ hydraulic fractures by recovering almost 600 feet of the whole core through recently hydraulically fractured upper and middle Wolfcamp formations. In total, over 700 hydraulically induced fractures were encountered in the core and described, thus providing indisputable evidence of fractures and their attributes, including orientation, propagation direction, and composite proppant concentration. This fracture data, along with the collected diagnostics, support testing and calibration of the next generation fracture models for optimizing initial completion designs and well spacing. In addition, with a massive number of existing horizontal wells in the Permian, the collected data is also useful for designing and implementing enhanced oil recovery (EOR) pilots to improve resource recovery from the existing wells. It is known from the literature that the primary recovery from the shale wells is typically about 5-10% of the original oil in place. Therefore, tremendous potential exists in the Permian to recover additional hydrocarbons by implementing appropriate EOR techniques on the existing wells. To explore this concept, Laredo Petroleum and GTI have agreed to perform HFTS Phase-2 EOR field pilot near the original HFTS, supported by funding from the U.S. Department of Energy and industry sponsors. The Phase-2 EOR field pilot involves injecting field gas into a previously fracture stimulated well in order to produce additional oil using huff-and-puff technique. During the course of the EOR experiment, a second slant core well was drilled near the injection/production well to capture and describe some of the fractures which served as a conduit for the injected gas field during the injection or "huff" period and the produced fluids during the production or "puff" period. The overreaching goals of the HFTS Phase-2 EOR experiment is to determine the effectiveness of cycling gas injection in increasing the oil and gas recovery from the Wolfcamp shale. Specific objectives included: 1. Drill, core, and instrument a second slant core well to describe the fracture network in the vicinity of an EOR injector/producer well 2. Perform laboratory experiments to determine the phase behavior, including black oil study, slim tube analysis, swell testing, etc. 3. Demonstrate how natural gas and/or CO2 increases the oil recovery from Wolfcamp shale through core flooding experiments 4. Determine if pre-existing stimulated horizontal wells can be re-pressurized above the miscibility pressure using the field gas 5. Perform numerical 3D reservoir simulations to predict EOR injection/production performance 6. Instrument offset wells and collect diagnostic data during the cyclic gas injection and production test. This paper describes the EOR field pilot along with the collected data and performed analyses noted above.
- North America > United States > Texas (1.00)
- Europe > United Kingdom > North Sea > Central North Sea (0.65)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.77)
- Geology > Geological Subdiscipline (0.68)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.54)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.54)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Wolfcamp Formation (0.99)
- (6 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale oil (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Information Technology > Modeling & Simulation (0.66)
- Information Technology > Communications > Networks (0.46)
Stage-Level Data Integration to Evaluate the Fracturing Behavior of Horizontal Wells at the Hydraulic Fracturing Test Site (HFTS): An Insight into the Production Performance
Salahshoor, Shadi (Gas Technology Institute) | Maity, Debotyam (Gas Technology Institute) | Ciezobka, Jordan (Gas Technology Institute)
Abstract Continuous improvement of the completion design in horizontal wells is the key to improve the ultimate recovery from shale resources. Accounting for not only the geological characteristics of the target formation but also the spatial heterogeneity in the target layer is a significant step in achieving the optimum completion design and improving the production efficiency. For this purpose, the present study proposes a comprehensive descriptive data analytics workflow using the completion design and reservoir metrics of more than 400 fracturing stages from the eleven horizontal Wolfcamp wells in the Permian Basin at the hydraulic fracturing test site (HFTS). In this study, fracture gradient, calculated based on the measured instantaneous shut-in pressure (ISIP), is utilized as the reservoir response to the hydraulic fracturing work. The proposed workflow evaluates the impact of variations in the reservoir properties and completion design parameters on the reservoir response to the hydraulic fracturing process. It also facilitates explaining the variations in the production performance of the horizontal wells placed in the same formation. The impact of added fracture complexity in the presence of active or inactive vertical producers located within a certain distance from the horizontal wells is also evaluated. A supervised multivariate analysis is used in this work to provide an insight into the importance of selecting the optimum completion design on a well by well basis, highlighting the importance of adapting the design of fracturing stages to the variations of the formation properties along the lateral placements of horizontal wells. Results indicate that the best performing wells, from the cumulative oil production standpoint, are those that experienced changes in the stage completion and treatment parameters compatible with the inverted reservoir properties variations. It is also observed that in the upper Wolfcamp, formation properties dominantly control the zonal fracture gradients while in the middle Wolfcamp, completion design parameters are the dominant controllers. This workflow is used for the first time to explain the possible causes of variations in the production performance of the similarly designed HFTS wells in the Wolfcamp formation.
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > Permian Basin > Yeso Formation (0.99)
- (31 more...)
Abstract The ultimate recovery from shale formations is relatively low compared to the total in-place reserves. The important role that these reservoirs have in the future of the oil and gas industry generates a significant need for cost-effective and environmentally-friendly enhanced oil recovery techniques. This study evaluates the application of enzyme EOR in shale reservoirs. Laboratory results of tests conducted on multiple cores taken from Woodford shale outcrops demonstrate an average of 20% improvement in the recovery factors. Enzymes change the wettability of formation rocks and fluid systems by changing the interfacial tension which results in releasing hydrocarbons from the rock. In this study, enzyme solutions with concentrations of 10 and 5 wt.% are used on 6 different cores. Recovery factors of the spontaneous imbibition tests at this concentration were 11 and 22%, respectively, after a soak time of 200 hours. This compares to 2 and 12% recovery factors, respectively, in the control tests. The experiment is performed under static condition, addressing the change in the recovery of crude oil from each sample using spontaneous imbibition tests. A suitable concentration of enzyme is identified to be 5 wt.%. Some of the shale samples used in this study were clay-rich and some were carbonate-rich. There was no significant difference in the EOR performance between the two categories of rocks. Oil recovery in shale formations could be improved up to around 10% using cyclic gas injection. However, this study proves that adding biological enzymes has the potential to improve this recovery factor up to 25%. Moreover, the effect of enzymes is everlasting in the formation because the enzyme dissolved in formation water continues to invade pores and fractures in lower concentrations. Introduction All oil recovery factors from shale and tight formations, in which the permeability is less than 0.1 mD and pore sizes with less than 100 nm in diameter are abundant, are reported to be less than 10% (Sheng, 2017; Salahshoor et al., 2018). The average oil recovery factor of Woodford shale is reported as 8.4% by Energy Information Administration (Advanced Resources International, 2013). Therefore, EOR techniques are massively explored to help with improving the recovery from these formations. However, the complex fluid flow and phase behavior of these formations make them more challenging in many aspects including finding the best EOR practices (Salahshoor and Fahes, 2018; Salahshoor and Fahs, 2018). Common EOR practices in shale and tight formations, including gas injection, water injection, and surfactant injection, are studied in numerous industry and academic research publications.
- North America > United States > Oklahoma (0.72)
- North America > United States > Texas (0.47)
- North America > United States > California (0.46)
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Government > Regional Government > North America Government > United States Government (0.34)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Shale gas (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Reserves Evaluation > Recovery factors (1.00)
- (2 more...)
Abstract Accurate determination of the dew point pressure of gas condensates in nano-porous ultra-low permeability reservoirs is crucial to prevent liquid dropout inside the formation. This paper presents a proof of concept experimental data and procedure to explain the effect of the pore size distribution on the degree and direction of the shift in the saturation pressure of gas mixtures under confinement compared to the bulk behavior. We built a packed bed of BaTiO3 nanoparticles, providing a homogenous porous medium with pores of 5 to 50 nm, providing a volume more than 1000 times larger than typical nano channels. We designed an isochoric apparatus to monitor pressure for a fixed volume of fluid under confinement and bulk conditions simultaneously. A binary mixture of ethane-pentane undergoes an isochoric process with pressures of 10 to 1500 psi and temperatures of 290 to 425 K. The result is a set of Isochoric lines for the bulk and confined sample, plotted on the phase envelope to demonstrate the change in saturation pressure. Many attempts in explaining the shift in saturation pressures of the reservoir fluid confined in the narrow pores of unconventional reservoirs compared to those of the bulk can be found in the literature. However, there are some contradiction between the predicted behavior using different mathematical approaches. Experimental data could be substantially helpful in both validating models and improving the understanding of the fluid behavior in these formations. Contrary to what many published models predict, our results show that confinement effects shift the dew point pressure towards higher values compared to the bulk for a fixed temperature in the retrograde region. In the non-retrograde region, however, this shift is towards lower dew point pressure values for the confined fluid compared to the bulk. Capillary condensation is assumed to be the main source of the deviations observed in the behavior of fluids inside nanopores. We evaluate published models, including those based on EOS modifications, by comparing it to experimental results to provide a quantification of their accuracy in predicting saturation pressure values for confined mixture. This paper provides an alternative approach to examine the effect of pore size on phase behavior over a decent and practical range of pressures and temperatures. The synthesized porous medium is very helpful in uncoupling the effect of pore size from the effect of mineralogy on the observed deviations in behavior. Experimental findings are valuable for validating existing theories and can be used to adjust proposed mathematical approaches towards better predictions of saturation pressures for other systems.
Abstract The shift in critical properties of the confined gas has been explored in many studies through several mathematical methods, from modification of the existing models to developing new ones. All these studies confirm that the properties of the confined gas inside nanopores are altered from properties of the bulk gas. However, limited experimental data are available in the literature to evaluate and validate these mathematical models and correlations. The present study provides an experimental insight into this effect for gases entrapped inside minute pores of nanoscale porous media. A semi-automated apparatus to monitor and compare the behavior of gases confined in nanopores and the bulk gases is used in this study. A well-packed bed of barium-titanate nanoparticles with pore sizes of fifty to a few nanometers is synthesized in the laboratory to represent a tight formation. While heating the system through an isochoric process, pressure responses of the gas inside this nanoporous bed are obtained simultaneously with the pressure responses of the bulk sample that is undergoing the exact same process. Pressure-temperature measurements are then used to demonstrate the deviation of the gas behavior inside the nanopores. These experimental data are utilized to evaluate various modifications on equations of state from the literature and compare their accuracy in estimating the pore size effect on gas behavior and illustrate their deficiency in capturing the extent of this effect. Both hydrocarbon and non-hydrocarbon gases, including methane, ethane, nitrogen, and helium are used in exploring this effect. The data and analysis presented in this study provide an alternative approach to capture the pore size effect on confined gases that is anchored in experimental findings. It also helps with understanding existing models and evaluating the accuracy of mathematical correlations in quantifying the confined fluid behavior. Introduction Equations of state (EoS) are thermodynamic tools to interconnect macroscopically measurable properties of a system in simple ways allowing us to calculate pressure, volume, temperature (PVT) of the system (Haider, 2015).
- 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 > Fluid Characterization > Phase behavior and PVT measurements (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract A robust high precision experimental approach to determine dew point pressure of gas condensates in the laboratory is proposed in this study. Gas condensate reservoirs have been the center of attention for numerous numerical and experimental studies for decades. Their perplexing fluid flow and phase behavior results in various production challenges including condensate banking and compositional changes due to retrograde condensation accompanying production from these reservoirs. Therefore, accurate prediction of dew point pressure (DPP) is crucial in developing long-term production plans for these reservoirs. Isochoric method, an indirect high precision way of DPP and phase transition condition determination, is commonly used in other disciplines where a clear non-visual determination of phase transition of a fixed volume of fluid is needed. This study provides an insight into this approach in determining DPP for a binary mixture of hydrocarbons. A semi-automated apparatus for measuring and monitoring equilibrium conditions along with fluid properties is designed based on the isochoric method. The apparatus provides constant volume, variable pressure (0 to 1500 psi), and variable temperature (290 to 410 K) experimental conditions. Pressure and temperature measurements are used to detect the phase transition point along the constant mole-constant volume line based on the change in the slope of this line at the transition point. Results are plotted on the phase envelope (P-T diagram) of the same mixture using different equations of state and the accuracy of each of these equations of state in providing the most reliable prediction of DPP is analyzed. Reproducibility of the data is examined and error estimation for the entire experiment is provided. This experimental method is inexpensive, less time consuming, and more accurate compared to other PVT experiments and is applicable for multicomponent systems. It does not require gas expulsion or sample recombination throughout the procedure and could be identified as the only reliable way of quantifying the effect of porous media on phase behavior.
- North America > United States > Texas (0.28)
- North America > United States > California (0.28)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (6 more...)
Abstract Laboratory measurements of gas permeability are used in many petroleum engineering studies, from core analysis for reservoir formation characterization to research work on reservoir engineering, formation damage, and various enhanced recovery techniques. The value of this data depends on how well they translate from one measurement condition to another. In this study, several factors affecting laboratory permeability measurements are investigated. Experimental results show that negligence of these factors may result in errors exceeding fifty percent. Permeability measurements are performed for limestone and sandstone samples using a conventional steady-state technique. The effect of variations in core length, gas type, pressure of gas supply, and the flow rate and pressure of the flowing gas is systematically studied. An accurate mass flow meter for gas is built in-house to eliminate the calibration error of commercially available flow meters that depend on the gas type. Nitrogen, helium, and ethane are used in these measurements. Temperature variations of the flowing gas are recorded, and gas slippage and inertia effects are also taken into account. Our study shows a significant reduction, bordering 25%, in permeability values measured for some shorter cores compared to the permeability value of the original whole core. This difference is more pronounced in highly permeable sandstone samples but is till significant in low permeability carbonates, bordering 20%. Permeability values measured using helium are higher than those measured using nitrogen. The difference is more pronounced in shorter cores, bordering 50%. It is important to note that this variation in permeability between nitrogen and helium exists even when corrections for the gas slippage or Klinkenberg effect are considered. Gas slippage effects are more pronounced for helium compared to nitrogen and for shorter samples compared to longer ones. The effect of length on the non-Darcy permeability and the high-velocity coefficient can also exceed 50% even when the same gas type is used. To the best of our knowledge, almost all laboratory permeability measurements neglect the temperature effect by considering an isothermal process. The effect of length on measured permeability is hinted in a few publications but no systematic study is reported. Our data show that models accounting for the effect of gas type are not accurate. We conclude that permeability measurements need to be corrected for the core length and flowing gas type effects, which vary with rock type and experimental conditions.
- Research Report > New Finding (1.00)
- Research Report > Experimental Study (1.00)