bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Approach to Gathering Bottomhole Pressure and Temperature
Authors: Gosney Josh , Lassek John , Hartwell Mark 
Published: January 2023

Abstract
Bottomhole pressure (BHP) is a critical parameter to understand for hydraulic fracture diagnostics but is often difficult to measure due to increased complexity of execution needed for installation of gauges. Surface pressure is often used with a calculated friction and hydrostatic offsets, but these calculations can have significant error (Keck, et al 2000). Many authors of diagnostics such as step-down tests and diagnostic fracture injection tests (DFITs) clamor for the need of accurate, reliable BHP understanding (Cramer 2013, Mondal 2019, Hawkes 2018). A new technology has been developed to embed a pressure sensor in existing hardware that is used in standard fracturing operations. This reduces operational complexity and enables gathering of critical bottomhole measurements including pressure and temperature as a function of time.
This case study will address design and qualification of the technology, field deployment, operational considerations and compare results from the measurement compared to surface pressure derived calculations. It will be useful for completions and production engineers along with anyone who is involved in hydraulic fracture diagnostics.
Nitrogen Foam Fracturing in the Oil Window of the San Juan Basin: A Multi- Disciplined Approach Contributes to Significant Well Results
Authors: Li Ningning , Slowinski Matt , Koenig Don , Weaver Brian , Valenzuela Naomi , Searle Curtis , Reece Adrian , Sullivan Sabrina , Rosenthal Jack 
Published: January 2023

Abstract
The operator has successfully drilled and completed more than fifty horizontal oil wells in the subnormally pressured Gallup Sandstone (Mancos Formation) within the San Juan Basin, New Mexico. All the wells were fracture stimulated using 70% quality Nitrogen (N2) foam with 20/40 sand. N2 fracs are uncommon in modern completions but provide numerous benefits for operations in the San Juan Basin. Benefits of N2 foam fracs include reduced water usage, less proppant settling (improved carrying capacity of proppant), and less parent/child interference. The N2 fluid is high-viscosity and promotes higher height/length growth with improved fracture width relative to low viscosity completion fluids. These properties of N2 foam fluids help prevent damage to parent wells and result in an ideal fracture geometry.
This paper discusses methodologies employed by the operator resulting in significant improvements to well results. Methods include a) fracture design/modeling optimization with N2, b) parent and child well management, c) strategies for mitigating fracture-driven interactions, and d) a presentation of well results. The paper compares the completion parameters used in newly drilled wells versus legacy wells and contemporary offset completions to provide context to well results. Additionally, pressure management is utilized during flowback and production of both parent and child wells, resulting in improvements in oil productivity, load recovery, and minimal proppant returns during flowback. Pressure management incorporates both wellhead choke management and gas injection volume management as methods to maintain reservoir pressure in the short and long term.
The combination of N2 foam hydraulic fracs, pressure management during flowback, and production optimization has led to significant improvements in horizontal Gallup sandstone well production. Incremental improvements have been made to all aspects of the completion, flowback, and production processes. Nitrogen foam fracturing is an understudied completion design that has had limited deployment in oil reservoirs across the oil industry. Strong production results from Gallup Sandstone N2 completions suggest that the technology is worth further consideration and study. This methodology could provide insights for other operators with similar reservoir conditions.
Comprehensive Understanding of Proppant Transport for Slickwater Fracturing via CFD Modeling
Authors: Liu Xinghui , Chang Oliver , Wang Jiehao , Singh Amit , Rijken Margaretha , Reverol Richard , Lazo Antonio 
Published: January 2023

Abstract
Unlike high-viscosity fluids, proppant transport with slickwater inside fractures is complex, but most fracture models do not adequately describe it. These models solve proppant transport based on simplified continuity equations. They assume that the average proppant velocity is the same as the fluid velocity and proppant settling in the vertical direction is always incorporated using Stokes’ law or similar equations. Some models also include proppant bridging and trapping effects, and velocity slippage between proppant and fluid, using empirical correlations. None of these commercially available models consider proppant momentum and interactions of particles with other particles, fluids, and fracture walls. In addition, turbulent flow near wellbore is completely ignored in these models. Slot tests used for proppant transport in laboratory studies are too small and too simplified to upscale properly to realistic field conditions. CFD (computational fluid dynamics) modeling can bridge some of these gaps. The main objective of this study was to use CFD modeling for a comprehensive understanding of proppant transport with slickwater and improve proppant and fluid selections for unconventional fracturing.
Several lab-scale CFD models were constructed and calibrated using experimental proppant transport data from slot flow tests. Field-scale CFD simulations were performed to evaluate the impact of key parameters on proppant transport and placement, including pumping rate, fracture width, fluid viscosity, proppant size and density, fluid leakoff, fracture height growth, perforation orientation and size, multiple fractures near wellbore, and pre-existing dunes, etc. Field-scale CFD model results show that proppant with wider size distribution provided more favorable placement, as larger proppant particles settle quickly to create a proppant dune and generate sufficient fracture conductivity near the wellbore. Smaller proppant particles travel deep into the fracture to increase partially propped fracture surface area in the far-field. CFD model results further show that the distance that larger proppant could reach inside the fracture is small, especially in the vertical direction, and that proppant height coverage can be improved by dune formation.
CFD model results confirm that proppant placement inside the fracture is significantly affected by pumping rate, fracture width, fluid viscosity, proppant size and density. CFD model results suggest that horizontal wells should always be landed close to the bottom section of the expected fracture where the proppant dune is located. Proppant with wider size distribution, for example 40/140- and 40/200-mesh sand, is expected to provide improved proppant placement.
Effect of Proppant Settling in the Wellbore on Proppant Distribution in Perforation Clusters
Authors: Aijaz Muhammad Jahanzaib , Sharma Mukul Mani 
Published: January 2023

Abstract
Our goal in this paper is to quantify the impact of proppant settling in the wellbore on the efficiency and distribution of proppant into perforation clusters. This phenomenon has been experimentally studied on the lab scale in the past but no field-scale simulations have been performed to quantify the amount of proppant settled in the wellbore and its impact on proppant placement.
Critical velocity correlations are used to estimate the velocity at which proppant settling can occur and incorporates them into a numerical simulator for simulating proppant transport in multiple perforation clusters. The proppant distribution in each perforation cluster and the amount of proppant settling in individual wellbore sections is computed. Comparisons made with cases where no settling is considered clearly show that the total proppant mass entering individual perforation clusters is impacted when proppant settling is considered. A parametric study is then conducted to determine which parameters (number of perforation clusters, flow rate, proppant size etc.) have the largest impact on proppant placement.
Our results show that proppant settling occurs primarily at the toe-side of the stage where the wellbore fluid velocity drops below the critical velocity. Wellbore settling occurs mainly near the last cluster as the fluid leaks off into all the heel-side perforations. Proppant wellbore settling cannot continue indefinitely because as proppant deposits in a wellbore section, the flow area is reduced and this in turn increases the flow velocity to above the resuspension velocity. The effect of proppant settling becomes more pronounced as the number of clusters in the stage increases. It is most pronounced in refracturing scenarios where a large number of perforations are open to flow. The settling progresses towards the upstream clusters as the toe side clusters are plugged and the critical velocity in that region drops below a threshold value. The injection rate, fluid viscosity, proppant diameter, proppant density and fluid density also have a significant impact on the total amount of proppant that settles.
This paper quantifies proppant placement in perforation clusters and proppant settling in wellbore sections during a fracturing stage. It provides a quantitative estimate and an explanation for the combined effects of proppant inertia, perforation bridging and proppant wellbore settling. The results suggest many ways to minimize the impact of proppant settling in the wellbore.
Investigation and Optimization of Pre-Loading Strategy in Parent Well for Fracture Driven Interaction Mitigation
Authors: Wu Ruiting , Ramsaran Keith , Cai Yuzhe , Madara Ben , Chen Yuguang , Singh Amit , Prouhet Jeremy , Banki Reza , Lannen Christopher , Rijken Peggy , Liang Baosheng 
Published: January 2023

Abstract
Inter-well Fracture Driven Interaction (FDI), aka Frac Hit, has gained visibility as more high intensity events (pressure increase in parent wells). Severe production performance impact (parent and child wells) are observed in depleted and tightly spaced wells in unconventional reservoirs. Various strategies, including water pre-loading in parent wells, adjusting well completion design of child wells, optimizing development plans, etc., have been tried in the industry to mitigate the negative impact of FDIs on production performance. However, mixed results have been observed in some pilot tests utilizing a water pre-loading mitigation strategy. Hence, it is critical to understand the driving mechanisms and key parameters impacting pre-loading performance in order to quantify the expected benefit of pre-loading in different well scenarios and optimize the pre-loading design.
A novel integrated and coupled geomechanics / fluid flow / fracturing propagation modeling workflow is applied to simulate the FDI (including pre-loading) on the pad scale. The workflow is capable of simulating the entire life cycle of the FDI interaction, (a) stimulation of parent wells, (b) production of parent well, (c) pre-loading of the parent well, (d) stimulation of the child wells, and (e) production forecasting of both parent and child wells. The workflow includes calibration with field observations of fracture geometry, production performance, pre-loading pressure behavior, etc. Geomechanics and reservoir simulation coupling captures the stress change due to the depletion at the parent well and re-pressurizing from pre-loading.
The workflow was applied to one pre-loading pilot test in the Permian Basin. The goal of the study is to identify the key parameters that contribute to the pre-loading success and optimize the pre-loading design. History match of parent and child wells production performance using the integrated and coupled geomechanics / fluid flow / fracturing propagation modeling workflow was conducted to calibrate and validate the model. Then, a sensitivity study was performed on various key parameters, including pre-loading volume and level of depletion at the parent well to understand its impact on the production performance at the parent and child wells. Learnings from this study provided guidance to the operation team in order to optimize FDI mitigation strategy.
One Shot Wonder XLE Design: A Continuous Improvement Case Study of Developing XLE Design in the Bakken
Authors: Lorwongngam Apiwat Ohm , McKimmy Michael , Oughton Evan , Cipolla Craig 
Published: January 2023

Abstract
Many operators have been working on optimizing stage spacing or clusters per stage to maximize production and reduce completion capital investment in unconventional wells. The operator has successfully proved that eXtreme Limited Entry (XLE) design works well in the Bakken. This paper uses a continuous improvement concept to improve on the paper presented in 2020 URTeC: 2796. The objective of this study is to push the boundary of perforation design that has been used as a standard design since 2020 to evaluate the optimum Shots Per Cluster (SPC), the minimum Rate Per Cluster (RPC), and the maximum Clusters Per Stage (CPS) that can still further maximize well production and provide optimum fracture cluster efficiency and Uniformity Index (UI). This paper will also address the comparison between XLE design and other diversion techniques.
Through the 3-year journey of understanding and optimizing XLE design, the operator had a total of 4 pads planned as a part of this study. The first 2 pads used to prove the XLE design concept utilized Radio Active (RA) tracer, deployable fiber optic, step down tests, downhole camera, perforation acoustic imaging tool, and production data. The other 2 pads are the observation lateral project [Cipolla et al. 2022] and a permanent fiber project; both projects include lateral bottom hole gauges, offset well fiber optic strain, and permanent fiber along the lateral. This paper uses part of the data from these projects to help validate fracture morphology, rate per cluster, and maximum clusters per stage. The operator uses the Lean continuous improvement and plan-do-check-adjust process to work from the planning to the standardization of the design.
RA tracer, step-down test, and deployable fiber optic results show that XLE with 1 Shot Per Foot (SPF) yields high production cluster efficiency of more than 90%, high uniformity index, and comparable production data to the non-XLE design while lowering the completions cost. From the permanent fiber optic data, the results show that the minimum rate per cluster to yield a uniformity index of more than 80% in the Bakken is ~ 5 BPM for 4-1/2" liner and ~6 BPM for 5-1/2" liner.
Using a continuous improvement process, the operator adopted the XLE design with 1 SPF as the current completion design standard. This design is proven to yield high productivity and increase asset value by lowering the cost of completions by more than 12%. In the high oil price environment, the XLE design can also be used to maximize asset value by increasing entry points in the well. This leads to an increase in short-term production. Throughout the data gathering and trial process, the operator also gathered novel pressure data allowing for direct measurement of perforation friction, and near-wellbore friction Limited Entry and Extreme Limited Entry Designs
Can You Feel the Pressure? Strain-Based Pressure Estimates
Authors: Haustveit Kyle , Haffener Jackson 
Published: January 2023

Abstract
Pressure measurements have long been vital to evaluating fracture interactions and well performance in both conventional and unconventional formations. Pressure responses during stimulation can be used to evaluate characteristics such as fracture geometry and net pressure. Dynamic pressure changes which occur during drawdown, both near wellbore and far-field, provide insight into the effective geometry being drained and how it evolves over time.
The combination of horizontal wells and hydraulic stimulation have been key in unlocking vast unconventional resources across North America and beyond, but there is still much left to understand regarding how the reservoir is drained across the miles of laterals accessing the resource. The density of pressure gauges required to accurately measure the drainage pattern from a horizontal multi-stage stimulation is currently not realistic economically or technologically. In this case study, the authors will describe a method of monitoring the drainage profile of a horizontal multi-stage stimulation using optical fiber.
Optical fiber was installed on an observation lateral in combination with six reservoir-sensing pressure gauges as part of the Hydraulic Fracture Test Site I, Phase 3 in the Eagle Ford, funded by the Department of Energy (DOE). The lateral observation well was positioned approximately 225 feet away from the nearest stimulated and producing horizontal well. Using Raleigh Frequency Shift Distributed Strain Sensing (RFS-DSS), the strain change was measured in the far-field as the offset well was stimulated and first produced. RFS-DSS provides a spatial resolution of 20 cm, allowing for the monitoring of strain changes much smaller than we can accurately sense with Low Frequency Distributed Acoustic Sensing (LF-DAS) (Ugento et al., 2019). The strain change measured during the offset fracturing strongly correlates to the strain change measured during the production period.
The combination of RFS-DSS and six externally sensing pressure gauges provided a strong correlation between the total strain change and total pressure drawdown, where gauges positioned in regions of large negative strain change interpreted as drawdown showed large pressure declines and gauges in areas of small strain change saw small pressure declines. The correlation was applied to the total length of strain change, including areas without pressure gauges, to generate an estimated pressure profile for the entire length of the optical fiber.
This is the first attempt known to the authors where RFS-DSS monitored during production in a far-field observation well was translated to an estimated pressure profile. The technique will continue to be evaluated, trialed, and improved upon as additional data is collected from the pilot.
A Bullhead Refrac Application - Using Active Acoustic Pulses to Measure Diverter Effectiveness
Authors: Bourgoyne Steven , Murray David 
Published: January 2023

Abstract
During a bullhead refrac treatment, an Eagle Ford operator utilized active acoustic pulses to measure diverter effectiveness while continuously pumping. The goal was to determine if the fluid point of entry along the lateral would change after the diverter material seated on the perforations.
The bullhead refrac treatment consisted of 52 sand ramps with planned diverter drops after each ramp. Active acoustic pulses were taken at the end of every sand ramp to identify if fluid point of entry was changing along the wellbore as a result of the diverter material. The acoustic pulses and return signals were captured with a hydrophone sensor for optimal signal quality. The return signal comes from the first encountered, lowest impedance point and represents fluid point of entry in the well. Subsequently, forward acoustic modeling was conducted to simulate acoustic responses from different fracture sizes and their corresponding acoustic signatures.
Over 300 acoustic pulses were taken throughout the refrac treatment. Analysis of all the acoustic return signals indicated that a dominant fracture system was created or previously existed around the heel segment of the lateral and the fluid point of entry did not change throughout the duration of the refrac, indicating diverter was not effective. This paper will show that the use of acoustics gives an operator real-time ground truth about the location of the fluid point of entry and will allow them to make changes to optimize the refrac operation during a stage.
Real-Time Monitoring of Fracture Dynamics with a Contrast Agent-Assisted Electromagnetic Method
Authors: Ahmadian Mohsen , Haddad Mahdi , Cui Liangze , Kleinhammes Alfred , Doyle Patrick , Chen Jeffrey , Pugh Trevor , Liu Qing Huo , Wu Yue , Mohajeri Darwin 
Published: January 2023

Abstract
In collaboration with the Advanced Energy Consortium, our team has previously demonstrated that the placement of electrically active proppants (EAPs) in a hydraulic fracture surveyed by electromagnetic (EM) methods can enhance the imaging of the stimulated reservoir volumes during hydraulic fracturing. That work culminated in constructing a well-characterized EAP-filled fracture anomaly at the Devine field pilot site (DFPS). In subsequent laboratory studies, we observed that the electrical conductivity of our EAP correlates with changes in pressure, salinity, and flow. Thus, we postulated that the EAP could be used as an in-situ sensor for the remote monitoring of these changes in previously EAP-filled fractures. This paper presents our latest field data from the DFPS to demonstrate such correlations at an intermediate pilot scale.
We conducted surface-based EM surveys during freshwater (200 ppm) and saltwater (2,500 ppm) slug injections while running surfaced-based EM surveys. Simultaneously, we measured the following: 1) bottomhole pressure and salinity in five monitoring wells; 2) injection rate using high-precision data loggers; 3) distributed acoustic sensors in four monitoring wells; and 4) tiltmeter data on the survey area.
We demonstrated that injections into an EAP-filled fracture could be successfully coupled with real-time electric field measurements on the surface, leading to remote monitoring of dynamic changes within the EAP-filled fracture. Furthermore, by comparing the electrical field traces with the bottomhole pressure, flow rate, and salinity, we concluded that the observed electric field in our study is influenced by fracture dilation and flow rate. Salinity effect was observed when saltwater was injected. EM simulations solely based on assumptions of fracture conductivity changes during injection did not reproduce all of the measured electric field magnitudes. Preliminary estimates showed that including streaming potential in our geophysical model may be needed to reduce the simulation mismatch.
The methods developed and demonstrated during this study will lead to a better understanding of the extent of fracture networks, formation stress states, fluid leakoff and invasion, characterizations of engineered fracture systems, and other applications where monitoring subsurface flow tracking is deemed important.