bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Back-Of-The-Envelope Model to Estimate Dimensions for Every Shale Frac
Authors: Weijers Leen , Agarwal Karn , Lolon Ely , Fontana DK , Mayerhofer Mike , Defeu Cyrille , Haustveit Kyle , Haffener Jackson 
Published: January 2023

Abstract
Creating a reliable, calibrated frac model used to be a long and expensive task in frac optimization. Today, with the proliferation of fracture diagnostics to calibrate models, simple frac dimensions can be calculated from indirect measurements on most North American shale fracs.
Through the US Shale Revolution, fracturing operations have increasingly focused on pumping efficiencies. "Factory mode" operations today often allow little time for what used to be a lengthy optimization process of estimating fracture dimension sensitivity to job design changes for well placement selection and optimization of production economics. While some new fracture diagnostics have been designed to do measurements without interfering with frac operations, the calibrated models that harness these measurements remain cumbersome.
We have developed a practical engineering tool that can extend the use of direct measurements to all shale horizontal well frac jobs. Unlike complex models that require lots of inputs and that are only routinely run on a few stages in a limited fraction of all North American shale wells, this Back-of-the-Envelope (BoE) model can be run effectively on every horizontal well stage. To date, it has been run on almost a quarter million stages. The BoE model provides two main advantages: (1) utilization of average basin diagnostic feedback and model calibration for more realistic results, and (2) augmenting more complex models on a much larger scale through a simpler workflow.
The BoE model incorporates key fundamental processes in elliptical-shaped hydraulic fracture growth, including conservation of mass; limited entry-driven cluster distribution into simultaneously growing equal-sized multiple fractures; and Sneddon width profile with calibrated coupling over the fracture height. The physical model is further constrained by assuming a fixed half-length-to-height ratio from direct observation of hydraulic fracture growth.
The BoE fracture model can be described with a few different rock mechanical fracture design and treatment parameters and ISIP measurements at the end of each fracture treatment stage. A key feature of the BoE model is that direct measurements are directly incorporated as an inherent calibration step. The model is anchored to basin closure stress measurements from DFITs and calibrated with past fracture geometry measurements, for example from Volume-to-First-Response data provided through Sealed Wellbore Pressure Monitoring (SWPM), or from other direct fracture diagnostics.
In our paper, we present the results of this simple model and compare it with more complex fracture modeling efforts and fracture diagnostic results in a few major US shale basins.
Redefining Recoverable Reserves in the Eagle Ford: Refracs and Infill Development Lessons Learned From the Hydraulic Fracturing Test Site 1 (HFTS) Phase 3
Authors: Brinkley Kourtney , Thompson Cameron , Haffener Jackson , White Sarah , Ketter Chris , Borell Jarret , Comisky Joe , Hart Eric , Haustveit Kyle , Herrin Matthew , Jones Peter , Pelton Kevin , Pfau Ken , Price Buddy , Roberts Jon , Turko Molly 
Published: January 2023

Abstract
This paper presents a multidisciplinary approach to evaluating reservoir drainage patterns and hydraulic stimulation interactions among a development of both existing and new wells. Analysis of an extensive diagnostic package focuses on the potential to capture stranded reserves via refracs and infill drilling within the black oil window of the Lower Eagle Ford Shale, DeWitt County, Texas.
The project consists of a unique setup of primary (parent) wells, new infill wells, and a horizontal well devoted exclusively to observation. Liner refracs were performed in two of the primary wells, with the remainder receiving preloads. It also included the collection of a horizontal core, formation imaging and advanced lateral logs, sealed wellbore pressure monitoring (SWPM), downhole fiber-optics (both permanent and deployable), seven downhole pressure gauges, time-lapse geochemistry, and iterative production interference tests. This substantial dataset provides vital calibration for well spacing, completion strategy, and field development.
With the ability to measure the impacts of completion design, order of operations, refracs, re-pressurization, and infill drilling, detailed knowledge has been gained into improving redevelopment around a depleted parent network. The monitor well acquired 420 ft of horizontal core through the Eagle Ford target interval and is positioned between parent wells 225 ft laterally adjacent on either side. A significant number of hydraulic fractures were encountered, but only 8% contained proppant, indicating the original 2013 vintage completions had a very low conductive to hydraulically stimulated rock volume ratio. Fiber-optic and downhole pressure gauges on the monitor well also indicated that less than half of the parent laterals were effectively preloaded prior to infill completions, and these re-pressurization efforts were not sustained through time. SWPM was employed during refrac and infill completions to observe the stimulation of 156 stages, and over 750 treatment-to-monitor well pairings were captured. These interactions, coupled with findings from fiber and other diagnostic tools, were used to rank 6 different completion designs and define the optimal approach for future activity.
Understanding depletion networks and parent/child well interaction is crucial to the future viability of the oil and gas industry. The diagnostic data collected during this project yields important insight into capturing stranded reserves from sub-optimally designed fields, bolstering new well results with higher unit recovery factors, and ultimately achieving a more effective and economic development strategy.
Initial Observations From a Bakken Microproppant Field Trial
Authors: Palisch Terry , Lorwongngam Apiwat Ohm , Kalfayan Leonard , Giesbrecht Jon 
Published: January 2023

Abstract
The Bakken production system is well established as a premier oil producing basin. Over the last 20 years improvements in drilling and completion designs have led to significant improvements in well productivity and increased EUR. One recent design change has been the incorporation of microproppant in the fracture design, which was deployed in a multi-well field study and shown to improve production, and is the subject of this paper.
As the industry continued to move to smaller size proppant, microproppants have been introduced as another potential improvement in the fracture design, supplementing the benefits of 100 mesh sand. It is theorized that microproppant can provide two primary benefits to well productivity – propping open microfractures, which reduces the production decline, and assisting in the breakdown of the perforations, thereby improving cluster efficiency. Production improvement has been documented in various basins across North America, leading one operator to design and implement a multi-well field trial to evaluate the production impact of microproppant in their Bakken completions.
This paper will provide a brief overview of microproppant technology and recent deployments across other basins, illustrating both productivity improvement as well as enhanced proppant placement. It will then focus on the multi-well field study performed in the Bakken in late 2021. In this trial, seven wells included the use of microproppant and are compared to 13 offset wells which deployed a comparable completion design, but without the microproppant. In the study area, the lateral lengths and proppant deployed per foot of lateral were held constant, and the wells/results are segregated between the Middle Bakken and Three Forks benches. To date, wells deploying microproppant show an average overall production uplift sufficient for the operator to pursue a larger scale field trial. This paper will discuss the completion design including details on how the microproppant was deployed. It will also include the general, initial production comparison between the trial and control wells.
This paper will continue to challenge engineers thinking on the role of proppant and how to best engineer the completion and fracture design to maximize recovery and return on investment. It will review a field study deploying the use of microproppant, as well as the design details, making it beneficial for completion engineers who desire to deploy microproppant. It will also be valuable for reservoir engineers searching for ways to improve cluster efficiency and overall hydrocarbon recovery.
Overflush and Fracturing: Playing Poker with your Completion
Authors: Rylance Martin 
Published: January 2023

Abstract
Since the inception of hydraulic fracturing, the industry has wrestled with the concept of over/under- flushing, and has always pitched this as a binary philosophy, attempting to determine/define that this is either a fundamentally good or a bad approach. This schism simply grew with the extensive development of unconventionals; the use of overflush being an inherent and fundamental requirement for an effective and economic unconventional completion sequence. This paper will demonstrate that the true answer, as any engineer would expect, is that a detailed assessment is what is required and on a case-by-case basis.
The paper will describe and reference several fracturing case histories, in both the Conventional and Unconventional environments, where the application of an overflush, an underflush or an engineered approach have been assessed or applied. Rather than taking an easy headline grabbing route to perpetuate the myth that the process is a major paradigm, or simply either a good or a bad thing. This paper will discuss some of the key aspects that impact the suitability of one approach over another; and how engineering the implementation can lead to a broader range of applicability/suitability for the most economically effective outcome. This includes an appreciation of the production/economic profile and exposure to risk, which is hugely different in say an ultra-deep-water five well offshore development vs. a field development with some 100s – 1,000s of wells in a lower-cost onshore environment.
The paper will describe and demonstrate some of the fundamental variables that need to be considered; attempting to elaborate on a few of the key parameters which can influence the effective outcome. The paper will also indicate that there are several different scenarios whereby any form of overflush can result in a detrimental impact on the production rate and EUR, and that these must be fully appreciated. Subtleties, related to reservoir characteristics and fracture geometry; should be examined and appreciated. Additional aspects such as how the production, drawdown and pore-pressure will be managed can also have an impact. All these considerations, and more, will be discussed, described, and referenced.
While there is no doubt that the overflush debate will continue unabated, the intent of this paper is to reduce the damage (or uncertainty), one way or the other, that will result. It is an attempt, at a minimum, to ensure that the debate becomes solely a technical one related to the approaches to be taken rather than a black and white one of right or wrong. Ultimately, the paper will advise, and inform, that the approach should be fully considered, engineered in detail and tailored to each and every application and that as a result is no longer simply considered a binary question.
Optimization of Perforation Efficiency in the Delaware Basin Through XLE Perforating and Innovative Perforating Charge; A Case Study
Authors: Churchwell Phil , McQueen B. Adam , Weddle Paul M. 
Published: January 2023

Abstract
This case study looked to identify a perforation design and a perforation charge that measurably increases Perforation Efficiency (PE) and reduces PE variability from stage to stage. Achieving these goals allows for more economic fracture surface area generation as well as more informed decisions toward frac design and full field development.
Primarily relying on industry-standard pre-fracture Step-Down Tests (SDT) to estimate number of perforation holes open, a variety of strategies and technologies were tested by altering perforation friction, orientation, entry hole diameter (EHD), perforations per cluster (PPC), and charge type. The trial was performed across multiple horizons in the Delaware Basin, consisting of over 4,500 stages from 193 wells across 13 horizons from the 1st Bone Spring Sand to the Wolfcamp C in Lea and Eddy Counties, New Mexico.
With the legacy perforation strategy and technology, the operator historically achieved a probability 50 (P50) using the cumulative distribution function (CDF) of 47% of perforations open pre-fracture. Utilizing eXtreme Limited Entry (XLE), 0 degree-oriented perforating, larger EHD, single perforation clusters, and a shaped charge which increases the reservoir contact area, the operator was able to increase the CDF P50 to 93% of perforations open pre-fracture.
This straightforward trial allowed the operator to meaningfully reduce the cost of operations while type curves were met or exceeded. Contributing to the success of this field trial was a clear and restricted design of the experiment in combination with a special shale-optimized perforating charge designed for greater near wellbore reservoir contact area.
A Novel Multi-Modal System for Delivering Wet Frac Sand
Authors: Oehler Matt , Fisher Kevin , Dorfman Brian 
Published: January 2023

Abstract
A novel system has been developed to provide the transport, storage and delivery of wet (3-10% moisture by weight) sand for hydraulic fracturing operations. Pumping service efficiency and frac sand throughput remain the two key factors used to measure both a frac service provider's performance and an operator's need to maximize returns. Recent technology advancements in wet sand handling capability have been introduced to the market, which facilitates these operational goals while adding additional benefits such as improved ESG scorecard performance along with reduced cost.
This is the second-generation of wet sand technology, designed from the ground up with all new equipment and methodology. It is designed to enable varied storage options and incorporates improved flow capacity and sand metering capability. It has been extensively tested at sand mines and trialed on fracturing operations in multiple basins since early 2021. This system has proven to be a simple and reliable system for the handling and transfer of wet sand under a wide range of conditions and sand throughput demand. Importantly, this new equipment package permits multi-modal sand delivery and is a significant step forward in addressing the multiple aspects and challenges of wet sand delivery.
Delivering wet sand to a Frac Service Provider (FSP) blender presents challenges at every step. The first-generation wet sand systems in operation since 2019 evolved from containerized dry sand wellsite equipment and have proven very effective. However, after several years of operation, additional improvements have been envisioned that further facilitate the storage, movement and metering of wet sand. This paper explores the needs, methods, and benefits of this radically different second generation of wet sand handling equipment that will enable better, more reliable wet sand storage and mobility from mine to wellhead.
The benefits of utilizing wet sand have been well documented. These include significant cost and emissions savings, the ability for high throughput operations and simplification of the supply chain. Data will be presented illustrating on site performance, throughput and various delivery options along with quantified savings regarding cost and emissions. This novel system continues to expand new sand mine sourcing opportunities and improves storage capability. It also reduces equipment complexity, non-productive time risk (NPT) and onsite headcount, while improving ESG and HSE metrics throughout the supply chain.
First Ever in Kuwait, Successful Application of CO2 Foam Acid Fracturing Enables Paradigm Shift in Stimulation Strategy of Kuwait Jurassic Depleted Reservoirs
Authors: Al-Muhanna Danah , Ahmed Abdul-Samad Zamzam , Al-Qallaf Aliah , Fidan Erkan , Al-Awadhi Mansour , Al-Salali Yousef , Abdel-Basset Mohamed 
Published: January 2023

Abstract
The first ever CO2 foam fracturing new technology in Kuwait Oil Company (KOC) history was executed flawlessly in late 2021. Three treatments were executed. Co2 Foam Fracturing proved its significant added value of improving productivity in deep depleted tight carbonate Jurassic reservoirs, enhance flow back, reduce water consumption and carbon emission, and enable early production plus improving operation efficiency and cost saving. The stimulation operation has proven to be a huge success for all multidisciplinary teams involved as preliminary results showed over 50-70% production increase compared to offset wells.
The main challenges of acid fracturing stimulation in depleted reservoirs are the need for extended formation cleanup to flow back the injected fluids via prolonging Nitrogen lift that add higher operational costs and intervention operations. Therefore, energetic high foam efficiency frac fluid becomes essential to assist flowback and retrieve pumped frac fluids from reservoir. To tackle these challenges, Carbon Dioxide CO2 is pumped in liquid phase as energetic fluid together with normal frac fluids. Due to CO2 liquid nature, high foam efficiency can be reached (40 – 50%) at much lower friction losses. So, it enables achieving pumping frac at high rates and high foam efficiency. The main benefits of CO2 Foam frac are better fracture cleanup due to expansion of the stored compressed gas in the liquid CO2, fluid loss control that is provided by foam, minimized fracture conductivity damage, and the increase in hydrostatic pressure while pumping that translates to lower surface pressures during injection.
The selected pilot well is in depleted deep tight carbonate reservoir area of North Kuwait Jurassic gas fields. The executed acid fracturing operation required close planning starting from Q1-2021. Many challenges faced from logistical issues, lack of infrastructure and CO2 resources for the multi-faceted operation due to COVID-19 pandemic limitations. These challenges were tackled ahead with the integration of technical and operations teams to bridge the knowledge gap and to enable executing the operation safely.
The pilot well's net incremental production gain is estimated at 50-70% compared to offset wells, with improved flowback and formation cleanup with less well intervention. The resulting time and cost savings as well as the incremental well productivity and better operation efficiency confirmed high perspectives for the implemented foam acid fracturing approach. Another two CO2 Foam acid fracturing wells were executed with good results too.
This paper will demonstrate the value of CO2 foam fracturing in depleted reservoir and KOC experience post first application and its plans to expand CO2 Foam Fracturing application across KOC different fields.
Tip Screen Out Fracturing Delivering Optimum Performance in Conventional Applications for 40 Years: Case Histories and Lessons Learned
Authors: Rylance Martin , Kogsbøll Hans-Henrik , Cipolla Craig , Montgomery Carl T. , Smith Michael B. , Norman W. David , Olson Karen E. , Pearson C. Mark 
Published: January 2023

Abstract
The focus on unconventional technology and operations, has been relentless during the last 15 - 20 years, while conventional operations have continued to tick along delivering their effective solutions globally. However, with unconventional operations dominating, it is inevitable that we run the risk of a fading knowledge base regarding the valuable contributions and hard lessons that have been learned with conventional techniques such as Tip Screen Out (TSO). This paper will present a global update on the development and application and continued success of this very specialised technique.
The paper will describe the original development of the TSO process, design, deployment, refinement, and its broader application. A suite of case histories will demonstrate that every major operator in every major basin worldwide has successfully applied this technique to enhance production, where its use was both applicable and conditions made it possible. From highly specialised applications in North Sea chalks, to field developments in higher and medium permeability in Alaska and Siberia. From utilisation as an enabling solution in gas-condensates of South America, Middle East, and South-East Asia; and additionally, with the development of the Frac-Pack technique, delivery of a key sand-control completion method, crucial to GoM, Brazil and Global soft-rock oil production delivery.
The paper will describe a range of requirements behind each consideration of deployment of the TSO technique, as well as specific in-situ characteristics that are required to support such application. It will describe the nuances of fracture design, material utilisation and adjustments that may be required to ensure effective delivery. The paper will also outline examples where the TSO process was the difference between success and failure. Finally, the paper will also cover some of the surveillance approaches utilised allowing a direct confirmation of the TSO process. All the extensive supporting evidence for this application will show how invaluable this technique has been to the Oil & Gas industry.
In summary the paper will demonstrate the value which this technique has delivered in all its varied forms of application. It will enshrine the knowledge and lessons learned over 40 years of application and ensure that any short-term technical direction does not run the risk of disregarding the previously hard- won experiences of previous decades. Enshrined as an option in conventional fracturing techniques, the TSO process demonstrates the longevity that is associated with fundamentally sound engineering.