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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.
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.
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
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.
Abstract The primary aim of this study was to develop robust methods aimed at detecting and quantifying the subsurface proppant distribution as it relates to the completed wells in both the upper and the middle Wolfcamp formations at the HFTS site. There were two sources of proppant deemed useful for this task. The first source was the actual scrapings from the fracture faces that were collected during the core description work. The second sample source was the scrapings and sludge from the cut core tubes collected during core handling. This study highlights the analysis done on the second set of sludge samples. Apart from developing a method for detection and quantification of proppant and other particles contained within this sludge, the study was aimed at the following broad objectives:Determine the spatial distribution of proppant in the created SRV along the cored interval, including size distribution and proppant concentration. Determine if pay zones of interest are sufficiently propped/ stimulated. Determine if fracture and cluster spacing is optimal for thorough lateral reservoir coverage. Determine if well spacing is optimal based on propped SRV length. Introduction A significant part of the HFTS data collection effort was the collection of substantial through fracture cores from both the upper and the middle Wolfcamp formations (UWC & MWC). In total, almost 600 ft. of core was collected using a slant core well. The location of the 11 new horizontal laterals as well as the slant core well is shown in Figure 1. The individual core barrels contain sludge from drilling, coring and core handling operations. The basic premise of our study lies in the assumption that in zones where proppant is present, a significant portion of it should show up within the core barrels. Understanding how this proppant is distributed along the cored section of the slant core well, can be instrumental in understanding fracture communication as well as propped fracture growth along the cored interval of the slant core well. Moreover, the results can then be compared with some of the other independent data available from other datasets collected as part of the HFTS program with the intention of validating or improving our understanding of said data and also helping us with our analysis. The steps followed in our analysis of the proppant are as follows:Weighing, washing, sieving, sub-sampling and various other sample preparation steps before they are imaged at high resolution using a transparency scanner. These images are then run through an automated proppant detection workflow to identify how much proppant and possible natural calcite is within the sampled material. A post picking QC step is also utilized to make sure that the final reported numbers are relatively accurate. Picked objects are segregated to classify size fractions. Post QC numbers are validated at random using direct sample observation under microscope. Two hundred and thirteen core sludge samples scraped from the interior of core barrel sleeves and exterior of the core itself were collected. This extended over all six cored sections as highlighted in Table 1. Each sample is from a 3' core tube barring a few cases where they are smaller. Table 1 displays the core section starting depths, final depths, and number of samples (tubes) recovered from each, etc. Samples varied in volume, weight and consistency. The largest sample received weighed 587g and the smallest sample weighed 7.5g. Samples contain drilling mud, shale particles, aluminum shards (from the process of milling open the core barrels to access the core), natural cement and calcite, other particles and proppant. We note that as part of this study, colored proppant was also pumped to trace the movement of proppant within the SRV. However, tests with autoclave on fresh resin coated proppant showed that under high temperature, resin itself changes color (from reddish to yellowish hue, etc.). Therefore, detection and analysis of colored proppant was not taken up as part of this study.
Abstract Typical hydraulic fracturing designs in shale utilize a predetermined fluid pump rate, which once achieved is held constant throughout the treatment, excluding situations when surface pressure limitations or other conditions disallow. We propose a method of pumping hydraulic fracture stages where the fluid pump rate is rapidly changed from the predetermined maximum rate, to some significantly lower rate, and then rapidly increased back to original maximum rate. This rapid change in the flow rate produces a pressure pulse that travels up and down the wellbore and has the capacity, together with the pump rate change, to open previously unopened perforations, while increasing fracture complexity through fluid diversion. We observed increased microseismicity during hydraulic fracturing in stages with frequent pump rate changes. Regardless of their type and nature, seismic signals are indicative of fragmentation of the treated zone. This could be from shear shattering or dilatational opening. One can also assume that high signal density is a good measure of fracturing efficiency. To further investigate these observations, we implemented a variable pump rate fracture design in a Marcellus shale well. More specifically, we implemented the variable pump rate frac design in every odd stage, while implementing a constant rate design in every even stage. This was done in order to account for changes in the reservoir along the horizontal lateral. Production log results showed on average a 19% increase in production for the variable pump rate stages versus the constant pump rate stages. A lower treating pressure was often encountered after the rapid rate changes, leading to the conclusion that unopened perforations were opened with the aid of the induced pressure pulses. Total well production decline was much slower for test well that included variable pump rate changes versus the offset horizontal well which did not include the variable pump rate frac design. And finally water hammer frequency decay analysis shows a predictable trend in well with variable pump rate stages. Throughout the variable pump rate stages, no proppant transport issues were encountered and the frac stages were completed without any major issues. Rapid rate changes applied throughout the fracture treatment enhance microseismicity, which could be interpreted as additional fracture complexity. Surface fracturing pressure data shows that rapid pump rate changes open additional perforations without physical flow diverters such as ball sealers or frac balls, while production log data shows higher production. Implementation of the Variable Rate hydraulic fracturing method results in no additional costs while it increases stimulation efficiency.
Microseismic surveys typically involve surface deployments, wellbore arrays or a combination of the two. Surface microseismic surveys are often very resource intensive due to their large apertures and receiver count. On the other hand, downhole arrays are often deployed within existing wells in the field which leads to constrained design apertures and failure of imaging algorithms traditionally used with surface deployments for characterizing the observed microseismicity. At the same time, hypocentral inversion algorithms used with wellbore arrays have many well understood limitations and their use leads to many valid events being discarded. We introduce a simple emission mapping approach which can be applied on microseismic data from either borehole or surface arrays and provides a temporal energy emission profile as observed during treatment. We share an actual field example and demonstrate the applicability of this attribute for better understanding of reservoir behavior during hydraulic fracturing and validate the analysis through independent observations from production log data.
Many methods have been proposed in the past to look at optimizing passive seismic arrays based on wide variety of design criteria. These have varied from ray illumination methods to error minimization within various inversion algorithms in use. There are many factors that come into consideration when dealing with array design problem. These may include operational factors, local geologic and structural attributes, resource constraints, etc. There is a need to approach this problem in a holistic fashion and to design and implement a method which caters to multiple design criteria comprehensively. In this work, we have designed and implemented a generalized workflow with the flexibility of adding any number of design elements as per requirement depending on the specific problem at hand. While the method draws upon optimization techniques that have been used in the past, the aim is to optimize for multiple design criteria simultaneously and to do so for relatively complex multi-array sensor networks. We demonstrate the validity of the developed algorithm by implementation on various models and highlight potential advantages as well as pitfalls involved with such complex optimization issues. Finally, we provide broad recommendations for simple multi-array design optimizations based on tests on our synthetic models.