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Abstract In this case study, we apply a novel fracture imaging and interpretation workflow to take a systematic look at hydraulic fractures captured during thorugh fracture coring at the Hydraulic Fracturing Test Site (HFTS) in Midland Basin. Digital fracture maps rendered using high resolution 3D laser scans are analyzed for fracture morphology and roughness. Analysis of hydraulic fracture faces show that the roughness varies systematically in clusters with average cluster separation of approximately 20' along the core. While isolated smooth hydraulic fractures are observed in the dataset, very rough fractures are found to be accompanied by proximal smoother fractures. Roughness distribution also helps understand the effect of stresses on fracture distribution. Locally, fracture roughness seems to vary with fracture orientations indicating possible inter-fracture stress effects. At the scale of stage lengths however, we see evidence of inter-stage stress effects. We also observe fracture morphology being strongly driven by rock properties and changes in lithology. Identified proppant distribution along the cored interval is also correlated with roughness variations and we observe strong positive correlation between proppant concentrations and fracture roughness at the local scale. Finally, based on the observed distribution of hydraulic fracture properties, we propose a conceptual spatio-temporal model of fracture propagation which can help explain the hydraulic fracture roughness distribution and ties in other observations as well.
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.
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.
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.
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.
In this paper, we introduce a novel fracture imaging method which uses high resolution 3D laser scanning to develop detailed surface maps of the core fracture faces. The digital maps are then used to analyze fracture surface characteristics wherein observed variations provide us with meaningful insights into the fractures. We share a mathematical approach for roughness evaluation to identify morphological properties for individual fractures within rock samples. The approach is tested on core extracted at the Hydraulic Fracturing Test Site (HFTS - 1) in the Permian Basin. We characterize the roughness variations with depth across the cored section. In addition, we compare results obtained previously from core sampling and analysis to demonstrate that proppant entrapment observed within the cored interval is strongly correlated with the changes in fracture morphology. We also use calculated roughness along with the the changing behavior of roughness radially away from the center of fracture faces to predict roughness "types" such as propagational features or textural roughness characteristics. Based on the specific fracture characterization work shared here as well as other potential uses, our paper highlights significant advantages such scanning and digital imaging of fractures may have over traditional cataloging using photographic imaging. Furthermore, as demonstrated in this study, data sampled from these detailed maps can be used to further characterize and analyze these features in a more systematic and robust manner when compared with the more traditional geological analysis of cores.
Summary We collected more than 500 ft of through‐fracture core in the Upper Wolfcamp (UWC) and Middle Wolfcamp (MWC) formations in the Permian Basin. As part of core characterization, we analyzed the core‐sludge samples for the presence of proppant and natural‐calcite particles. Apart from sample preparation and imaging, we designed and developed a novel image‐processing work flow to detect and classify the particles. We used the observations from the identified particle distribution within the stimulated rock volume to understand proppant‐transport behavior. We used relative distributions of smaller 100‐mesh‐ and larger 40/70‐mesh‐proppant particles to interpret proppant placement in relation to perforation clusters. Finally, we used the relative distribution of particles to understand the interaction between natural and hydraulic fractures. We observe that stress variations and the degree of natural fracturing have a bearing on local proppant‐screenout behavior. Smaller 100‐mesh proppant seems to dominate at larger lateral offsets from the hydraulically fractured wells. We also observe indications of heel‐side bias according to lateral proppant distribution. We share our work flow for particle detection and classification, which can serve as a template for proppant analysis in the future if significant through‐fracture cores are collected in similar field experiments.
It is standard practice to use a coating system as the primary defense in preventing external corrosion on pipelines. Additionally, pipelines installed by Horizontal Directional Drilling (HDD), also require special coatings which have high abrasion resistance to minimize damage during pull through. However, given the aggressive nature of the installation method, some degree of compromised coating is inevitable. It is speculated that corrosion at the coating holidays will be suppressed through application of cathodic protection (CP). Considering the uncertainty of effective CP at HDDs, it is important to be proactive and consider additional measures to prevent any detrimental effects that the HDD drilling fluid may have on the pipeline. Being proactive supports the development of leading practices and reinforces a focus on safe operation and improved safety performance. This paper presents a case study on the evaluation of the effectiveness of environmentally benign and biodegradable enzymes in drilling fluid associated with HDD against Microbiologically Influenced Corrosion (MIC) associated biofilms. Corrosive biofilm formation on pipeline surfaces can have serious impacts on the safety and reliability of energy infrastructure. Once initiated, biofilms are extremely difficult to remove. It is also well known that the application of biocides alone does not completely remove the protective slime layer of biofilms.1 To enhance the effectiveness of biocides, research into using enzymes to target the protective extracellular polymeric substances (EPS) of biofilms has been studied.2 This case study will discuss the methodology to decrease the amount of biocides needed to mitigate corrosive biofilms by increasing its effectiveness, ultimately reducing the threat of corrosion to HDD pipelines from potential MIC.
Horizontal Directional Drilling (HDD) accounts for 10% of new pipe construction and is primarily used in high consequence areas (HCA) such as roads, lakes, buildings, railroads, and rivers. This method of installation requires special pipeline coatings with high abrasion resistance as it exposes the coatings to aggressive mechanical action. Cathodic protection (CP) and casings add additional layers of corrosion protection but since they are not the primary layer of defense they should not be relied upon to protect the pipeline asset.3 Developing and implementing strategies for protecting the pipeline coating is an important consideration for pipeline owners and HDD drilling operators so that inaccessible areas of pipe have the greatest corrosion protection.
Microseismic data is being routinely collected as part of large pad scale hydraulic fracturing developments. The large lateral and sometimes, vertical spread of the pad wells allow the possibility of correlating observations made from the microseismicity during treatment phase with known properties of the reservoir from 3D seismic as well as well log data. This study from the Permian Basin looks at the microseismic data from the treatment of 11 well laterals in both the upper and the middle Wolfcamp formations (UWC & MWC) and proposes the use of frequency magnitude or "b-value" distributions to understand fracturing behavior within the reservoir. Based on analysis of fractures from image logs and through fracture cores from target reservoir, we correlate the direct observations with the indirect measurements made though microseismic data analysis. Our work provides a valid, reproducible approach towards improved understanding of presence of natural fractures in the subsurface and their interaction with hydraulic fracturing operations using microseismic measurements.
Presentation Date: Wednesday, October 17, 2018
Start Time: 1:50:00 PM
Location: Poster Station 12
Presentation Type: Poster
Maity, Debotyam (Gas Technology Institute)
Abstract Microseismic data can be used as a tool to help understand fracturing behavior during hydraulic stimulation. Recent studies have validated complex fracture growth and interaction during fracturing process and there is a need to better utilize microseismic data as a way of improving our understanding of this complexity. Moreover, significant stress variations along the laterals and various formations of interest can be better interpreted by making use of b-value distribution as a proxy measure for stress. In this study, we tie the Frequency Magnitude Distributions (FMD) from microseismic with the 3D seismic and petrophysical data to understand stress variations within the upper and middle Wolfcamp formations. We also look at how temporal microseismic FMD variance can be used as a tool to help understand fracturing behavior with time. Our results highlight the utility of microseismic FMD as a valuable hydraulic fracturing diagnostic tool post fracturing operations and as a validation for observations made during treatment including relevant treatment parameters. Introduction The Hydraulic Fracturing Test Site (HFTS) is located on the eastern part of the Midland Basin, between the Central Basin Platform and the Eastern Shelf. The test wells are located in Reagan County, Texas and are operated by Laredo Petroleum (Figure 1 left panel). The test site includes a high quality 3-D seismic survey and it is surrounded by many producing wells. There are many wells with open- and cased-hole petrophysical, production and image logs, as wells as whole and sidewall cores. Additionally, microseismic surveys were collected during stimulation of selected wells (Figure 1 right panel). There are a total of 11 new wells drilled in the Upper and Middle Wolfcamp formations as part of this study, with five wells in the Middle Wolfcamp and six in the Upper Wolfcamp. The new wells are all horizontal with extended reach lateral sections (~ 10,000 feet), drilled from north to south, and normal to the predicted maximum horizontal stress orientation.