bluuebunny/crossref_metadata_2025_split huggingface dataset:
CFD Modeling of Pseudo-Transient Perforation Erosion in a Limited-Entry Completion Cluster
Authors: Kebert Brent A. , Miskimins Jennifer L. , Soehner Gage , Hunter William 
Published: January 2023

Abstract
Hydraulic fracturing in limited entry (LE) completion designs relies on maintaining a high bottom hole treating pressure (BHTP). LE requires high perforation friction in order to maintain an even distribution of the hydraulic fracturing slurry. As sand exits the perforations, the perforations start to erode. The erosional change in the perforation alters the desired perforation friction and subsequent BHTP. As operators rely on multistage hydraulic fracturing to generate economic production, the issue of perforation erosion becomes inherently repetitive from stage to stage, and cumulatively a significant issue. The industry has seen how a perforation can change from a before-and-after perspective with downhole cameras and imaging techniques before and after treatments. However, a more detailed understanding of the dynamic process of perforation erosion can give a better expectation of perforation performance throughout a hydraulic fracturing treatment and not just pre-treatment compared to post-treatment.
Computational fluid dynamics (CFD) is a quickly emerging tool in the industry. CFD aims to model fluid flow by numerically solving the Naiver-Stokes equations within a specified domain. Along with modeling fluid systems, CFD has the capability to model dispersed particles within the fluid. Once the particles are introduced into the fluid, the domain can also be eroded away within the CFD model. By utilizing the erosional capabilities of CFD, paired with the flow of a hydraulic fracturing slurry, perforation erosion can be investigated transiently throughout an entire hydraulic fracturing stage.
This work presents a better dynamic understanding of perforation erosion rather than just a "before versus after" comparison. The CFD modeling methodology used to achieve the correct erosional pattern observed in the field is presented. Throughout this work, six different hydraulic fracturing completion parameters are investigated to determine the respective roles in perforation erosion. The six parameters include proppant size, proppant concentration, proppant sphericity, fracturing fluid viscosity, initial perforation diameter, and proppant concentration ramping schedules. By investigating the impact that controlled design parameters have on perforation erosion, perforation erosion can be better anticipated to deliver improved completion results.
Parent Well Characterization by Comparative Analysis of Initial and Second Flowback
Authors: Cao Chong , Moussa Tamer , Dehghanpour Hassan 
Published: January 2023

Abstract
Infill drilling is becoming a common practice for more efficient development of tight reservoirs. However, child-well stimulation may lead to a parent-child well interference or a fracture hit. To mitigate the negative impacts of a fracture hit, the parent well is preloaded before the stimulation of child wells. Then, the injected water during the pre-loading period is later produced back to the surface. The preloading flowback (second flowback) data of parent wells may provide an opportunity for fracture charactrization. The main objective of this research is to compare the responses of initial and second flowback to capture the changes in fracture characterstics after production and preload processes.
We construct rate-normalized pressure (RNP) diagnostic plots on both initial and second flowback (IFB and SFB, respectively) of six multi-fractured horizontal wells completed in Niobrara and Codell formations in DJ Basin. In general, the slope of RNP versus MBT during the SFB period is higher than that during the IFB period, except for well 1. We estimate the changes in average effective fracture volume (Vef) by analyzing the changes in the RNP slope and total compressibility during these two flowback periods. Compared to the IFB period, the Vef is generally decreased during the SFB period.
The loss percentage of effective fracture volume (RVef) is estimated at 10-40%. We also compare the drive mechanisms for the two flowback periods by calculating the compaction drive index (CDI), hydrocarbon-drive index (HDI), and water-drive index (WDI). The dominant driving mechanism during both flowback periods is CDI, but its contribution is reduced by 12% in the SFB period. This drop is generally compensated by a relatively higher HDI during this period. Finally, we investigate the effects of duration of production (tp) on RVef. There is a positive correlation between tp and RVef during the two flowback periods. Therefore, the loss of effective fracture volume might be attributed to the pressure depletion in fractures caused by the long production period (more than 800 days).
The Economics of Refracturing in the Haynesville
Authors: Barba Robert , Villarreal Mark 
Published: January 2023

Abstract
The Haynesville organic shale has just under 3600 wells, completed before mid-2016, with cluster spacings over 50 feet. This wide spacing resulted in many wells having missed or bypassed reserve recovery due to inefficient completions. Understandably these wells would be prime candidates for refracturing. Refracs have the advantage of lower up-front capital cost, fewer operational issues that rely on functioning supply chains, and significantly lower carbon footprint than new wells that need to be drilled prior to completion. However, a frequent concern is that refracs in the Haynesville cannot compete with new well economics. We looked at both public and operator refrac data to identify the criteria that makes a good Haynesville refrac candidate. We offer case studies to show the economic performance of 45 Haynesville liner refracs using actual post refrac decline data and current well costs. Both the economic value of the post refrac production is included along with the economic value of protecting infill wells from asymmetric fractures. An analysis of the completion design for a typical Haynesville refrac is also provided to demonstrate that significant upside remains for improvement if "best practices" are applied. These include Extreme Limited Entry (XLE), zero-degree top perforations per cluster, larger diameter expandable liners, and microproppant in the prepad.
In our data set, the typical Haynesville refrac completion has very low pressure drops (520 psi pre-erosion) across the perforations. With average treating pressures of 9500 psi there is limited room for higher pressure drops due to a 10,500-psi surface pressure limit. And so, the available delta pressure for treatment is limited to +/- 500 psi when a 2500 to 3000 psi pressure drop is recommended to maximize cluster efficiency (Hausveit 2020). With the author’s recommended practices, over 2500 psi of excess friction losses can be avoided, providing adequate margin to achieve the recommended pressure drop. With increased cluster efficiency, increased recovery factors should follow. While Haynesville refracs have successfully increased estimated ultimate recovery (EUR), when "best practices" are followed, the economic returns should be highly competitive with new-well completion economics. If the refracs had the 60% average cluster efficiency values from several studies done on poorly diverted treatments (Weddle 2018 and Miller 2011) the total NPV10 for a P50 refrac is equivalent to the new well NPV10 values.
Parent Well Strategies in the Bakken, Trends and Outcomes
Authors: Schmidt Darren , Min Kyoung Suk , Guillot Stephen 
Published: January 2023

Abstract
Significant attention has been placed on well-to-well interactions since the beginning of infill development in unconventional plays. Asymmetry of hydraulic fractures toward pressure-depleted parent wells has been attributed to poor performance of early in-fill completions (Xuyang et al., 2019). Factors include well spacing, timing, and specifics of colocation. Various operators have developed strategies to mitigate these effects and improve production for new spacing units. This paper reviews the historical response to parent–child well development in the Bakken, characterizes trends, and examines the techniques that have been applied and their efficacy. Results provide evidence that development decisions continue to be largely driven by surface constraints, suggesting there is more work needed to improve future child well performance. There is a trend away from refracturing for most operators, particularly as part of drilling spacing unit (DSU) redevelopments involving drilling of multiple child wells. Common mitigation techniques include fracturing the child well closest to the parent well first and increasing well spacing.
Observations, Learnings, and Validation of Conductive Fracture Imaging
Authors: Reshetnikov Anton , Nazarova Anna , Taylor Scott , Haffener Jackson , Langton David , Biholar Alex , Anderson Sloan 
Published: January 2023

Abstract
A novel diagnostic processing technique called Conductive Fracture Imaging (CFI) measures hydraulic and conductive fractures using microseismic events as a source. The method was applied to three datasets located in onshore unconventional formations in the United States. CFI results were in all cases first delivered independent of any external diagnostic data and only subsequently compared to multiple diagnostics such as microseismic, fiber cross-well strain (CWS), 3D seismic, and recovered core under supervision of Devon Energy’s Subsurface Team.
The comparison reveals a reasonable agreement of the CFI results with cross-well strain for both height and transverse conductive fracture growth. CFI was able to image fractures out 1 mile from the observation lateral, with fractures imaged in areas of no microseismic activity. Furthermore, CFI successfully quantified the height growth of fractures aligned with the pre-existing faults and how natural structures influence conductivity fracture distribution.
CFI reveals a valid relationship with cored & interpreted conductive, hydraulic, and natural fractures. The method provides dynamic images showing fracture morphology from the near-wellbore into the far-field reservoir. Complimentary analytics of relationships between CFI and reservoir properties, limited entry perforation designs, stress shadowing, and depletion effects may generate significant new observations and key learnings to industry as this technique is more broadly adopted.
The Effect of Casing Deformation on Frac Plug Sealing Element Performance
Authors: Yoshida Hiroaki , Jafri Syed , Okura Masayuki , Takahashi Shinya , Li Wei 
Published: January 2023

Abstract
Sealing element of frac plugs have crucial roles to isolate target zones of the well in hydraulic fracturing. If the zonal isolation by the sealing element is not adequate, it can result in erosion of the casing. The effect of casing deformation on sealing performance of sealing element is not well researched or understood. To study the effect of casing deformation on sealing performance, finite element analysis of sealing element in deformed casing was conducted in this study to assess the effect of casing deformation on sealing performance. In this study, finite element simulation of a full frac plug with three different casings ovalities (0%, 2%, and 5%) and three different sealing element designs (O-ring type, short type, traditional long type) was conducted to evaluate deformation behavior and sealing performance of the sealing elements in the deformed casings. Compression pressure on the casing by sealing element after the plug is set in the casing and the risk of leak were discussed and compared for each design. In the casing with 0% ovality, all the sealing element designs established contact with inner surface of the casing when setting force is applied. However, for the O-ring type design, area in contact with the casing was small and it may result in leak and erosion in the actual well if there is a small dent or deformation on the casing. When there is deformation and ovality in the casing, the minor ID has a smaller ID and a major ID has a larger ID compared to nominal ID of the casing. In the casing with 2% and 5% ovality, neither O-ring type nor short type sealing element could contact the major ID of the casing and there was a gap between inner surface of the casing and the sealing element. This gap can cause erosion of the frac plugs and casing when fluid passes through the gap. In contrast, traditional long type sealing element contacted both major and minor IDs of the casing and no gap was observed. This result indicates that there is a potential risk of insufficient isolation of target zones and erosion of casings in actual well condition if frac plugs with small sealing element is used. Since there are various types of frac plugs with different sealing element designs, this study helps to select proper frac plugs with good sealing element design and mitigate the risk of erosion of casings and plugs.
Probabilistic Quantification of Size Segregation and Screen-Out of Microparticles Subject to Electrostatic Forces
Authors: Leonardi Christopher R. , Di Vaira Nathan J. , Laniewski-Wollk Lukasz , Aminossadati Saiied M. , Johnson Raymond L. 
Published: January 2023

Abstract
A growing number of hydraulic fracturing stimulation treatments rely solely on the deployment of 100-mesh (i.e. 150μm) proppant. Further, these may be preceded by post-pad injection of microparticles (i.e. 5-75μm) with the intent of activating natural fractures. The objective of this work is to describe fundamental new insights on the behaviour of polydisperse microparticle suspensions in hydraulic fractures in terms of screen-out and leak-off.
This study was undertaken using a high-fidelity computational model of suspension transport based on the lattice Boltzmann method (for fluid mechanics) and discrete element method (for particle mechanics). The approach has been previously validated against analytical solutions and experimental data for suspension flows in channels, and applied to study fundamental aspects of size segregation and clogging (i.e. screen-out) of microproppant. This fully-resolved modelling approach captures two-way hydrodynamic coupling, electrostatic interactions, fracture roughness and tortuosity, and non-Newtonian fluid rheology. The sole assumption of significance is that particles are assumed to be perfectly spherical.
One of the challenges of deploying micron-scale proppant in hydraulic fracturing stimulation treatments is poor control of the particle size distribution. This inevitably results in a proportion of the injected proppant being small enough to be susceptible to electrostatic (rather than just mechanical and hydrodynamic) forces. This study clearly demonstrates the increased probability of screen-out that results as a consequence of electrostatic particle-particle and particle-wall interactions, and shows how this effect reduces as the minimum particle size increases. Analysis of particle leak-off off into transverse cleats also demonstrated how the combination of cleat width and particle size result in the formation of occlusions at cleat intersections, the reduction of leak-off rates in cleats, and the retardation of proppant transport in the primary fracture. These findings are significant because tight size control is not economically feasible for microproppant, and so hydraulic fracture engineering must accommodate their characteristic behaviours. This will result in more effective stimulation of coalbeds, but is applicable to all jobs where small proppant is proposed for injection into natural fracture systems.
Integrating Pulsar Technology with Reservoir Centric Fracturing Approach to Restore the Production in a Mature Tight Oil Field
Authors: Slimani Karim , Khetib Tayeb , Monfared Hashem , Lamali Rabah , Bendali Amor Nasrine , Skender Mohamed Semch-Eddine , Mezali Farid , Chekou Hakim , Belaifa Lotfi 
Published: January 2023

Abstract
Tight oil reservoirs are of paramount importance for an operator holding several fields with important oil potential in Illizi basin, southeastern Algeria. Formation tightness, the presence of nonconnected sand lenses, and the lack of a geological model made it very difficult to maintain the oil production in the studied Devonian reservoir. Consequently, the service company and operator adopted an integrated approach to devise solutions that could restore production in a mature tight oil field that had been closed in 2011.
Construction of a geological model for the studied reservoir was challenging because of the high uncertainty in water saturation interpretation caused by the formation water properties (fresh water). A multifunction pulsed neutron service was proposed to provide standalone cased-hole formation evaluation and reservoir saturation monitoring. A unique modeling approaches was applied to characterize the studied tight reservoir and evaluate the reserves based on advanced uncertainty analysis. A hydraulic fracturing design workflow in a reservoir centric stimulation to production software was developed using an integrated approach (geological and geomechanical models) to place the fracture in the optimum reservoir quality and connect the sand lens bodies.
Two existing wells were selected to run with the pulsed neutron service, resulting in acquisition of comprehensive reservoir rock and fluid content data. The interpreted logs served to reduce the uncertainty in water saturation modeling and to enable perfect history matching of the producing wells. The constructed geological model was the basis for improving the stimulation designs and maximizing production for future wells. With significant oil initially in place (STOIIP) estimated from the model, the field showed more promise than the previous recorded recovery factor of less than 1%. The field development plan (FDP) identified the location of 20 new infill drilling wells targeting the sweet spots and considering the optimal well spacing. In addition, the plan specified a systematic hydraulic fracturing stimulation job for each newly drilled well to connect and produce the sand body lenses. Recently, a successful campaign of hydraulic fracturing operations was executed on four wells, allowing the operator to resume production from the field. The fracturing performance minimized water cut despite the water-oil-contact (WOC) proximity, and it enhanced the oil recovery.
The developed integrated approach has already shown its effectiveness in returning a field to production and improving oil recovery. The approach can be replicated on subsequent wells in the field as well as on similar tight reservoirs all over the world.
Single Well Chemical Tracer Application for Chemical EOR Pilot Project: Principles and Best Practices
Authors: Khanifar Ahmad - , Abdul Manap Arif Azhan 
Published: January 2023

Abstract
Chemical injection has been emerged to be one of the processes that can improve oil recovery from major Malaysian offshore oilfield which is currently under waterflooding. Alkali-surfactant (AS) process was identified to be an optimized chemical system for this application. The chemical recipe and formulation for the field trial tests were obtained from comprehensive laboratory experiments studies. Pilot tests were designed and executed to evaluate the effectiveness of this chemical injection prior full field-scale implementation.
Single well chemical tracer (SWCT) technique has been utilized to determine the residual oil saturation (Sor) before and after chemical injection in a one-spot pilot and cost-effective manner approach. Two wells and two different chemical formulations were investigated for AS injection responses and four tests were conducted in sequence. The objectives were to validate the laboratory results, assess the critical chemical process parameters such as Sor reduction, adsorption, injectivity, and obtain an operating experience at a harsh offshore environment with high reservoir temperature. Sea water treatment and softening process was needed to protect chemical slug from high-salinity and high-hardness environment.
Favorable results achieve where successfully mobilized substantial amounts of Sor, chemicals easily mixed with no injection problems encountered, and no measurable dilution effects that indicated fluids travelling outside of test zones. The initial Sor waterflooding observe to be 0.16 and 0.27 for well 1 and well 2 respectively, while, interestingly, both wells show a 0.04 increase in Sor after first pilots were completed. It is most likely due to a shift in rock wettability toward more water wet. Competing reactions of alkaline was a major concern. Pre-flush and post-flush buffer of soft water was designed to minimize these reactions and allow surfactant to work in more favorable lower salinity water. Fortunately, Sor results show that the competing reactions were not severe enough to prevent the AS systems from working. The lowest Sor were 0.06 and 0.08 in the case of 1.5 PV and 1.0 PV soft-water buffer, respectively. It shows that Sor was not significantly reduced with additional 50% PV buffer. Even in the case of 0.15 PV buffer and 23,000 ppm salinity, Sor decreases only by 25%. It demonstrates that some degree of success will be gained even in the worst case where the salinity was reduced by 60%.
This paper presents the principals of SWCT pilot application for a chemical EOR (CEOR) project case study and share the best practices and lessons learnt were achieved from these field trail tests. This paper can be used as a technical reference and guideline for upcoming CEOR projects and promote a detailed development plan which can potentially address various challenges that are often encountered in implementing chemical flooding, particularly at offshore oilfields.
Permeability Prediction of Carbonate Cores With Gaussian Process Regression Model
Authors: Bu Xingang , Saleh Hassan , Han Ming , AlSofi Abdulkareem 
Published: January 2023

Abstract
Machine leaning (ML) methods are widely adopted in predictions affected by various factors. This paper presents a step-by-step workflow of applying a ML approach to develop a heterogeneous permeability prediction model from the CT images of core samples. In this work, over ten thousand 3-D sub-image were randomly extracted from the CT images of two heterogeneous carbonate core samples. The permeability of each sub-image is simulated using pore network modeling (PNM) method. Ten features including porosity, pore size, surface area, specific surface area and connection coefficient etc. are extracted from sub-image by a statistical method. Three training datasets were built with features and permeability. Each set of training data is input into a ML model pool, which contains 19 regression models of 5 types including linear regression models, regression trees, support vector machines, Gaussian process regression models and ensembles of trees. Then, regression models are trained to identify the one that can yield the best permeability prediction. The trained model with the highest R-Squared value is selected for permeability prediction from binary CT images. Overall, comparing the training outputs indicate that Gaussian Process Regression models (GPR) correlate features and permeability well. For the tested heterogeneous core plugs, the exponential Gaussian Process model performs the best. The R-Squared values of the three sets of training data are 0.88, 0.87 and 0.91 respectively. Afterwards, the selected ML model was tested with additional data, and the R-squared value of each test dataset was greater than 0.85, confirming a strong predictive performance. The trained model based on ML method eliminates the conventional time-consuming operations including distance transformation and watershed segmentation. It also avoids excessive memory consumption, which makes the method suitable for images with large size. The paper provides a way to develop an alternative approach of PNM simulation method for permeability prediction from CT images.