bluuebunny/crossref_metadata_2025 huggingface dataset:
Analysis of Shut-in Pressure Decline for Enhancing our Evaluation of Hydraulic Fracturing Treatments
Authors: Daneshy Ali
Published: January 2023

The focus of this paper is on the analysis of shut-in data immediately after a fracturing treatment and critical information that can be learnt about the created fracture from the magnitude and rate of pressure decline during this period. The selected example data in this paper had two specific features; frac job was injected in two cycles in several stages, and had long shut-in time (more than 10 hrs) in all stages. Review of this data shows that frac growth in each stage continues at a decreasing rate beyond the end of pumping and how many hours of shut-in was needed for the fracture to reach its ultimate stable condition. In this horizontal well with multiple fractures the data also gives direct measure of the relative complexity of the created fractures in each stage and their conductivity.

The paper recommends specific practices that can enhance what can be learnt from the data. These include recording the pressure data continuously during the treatment and for the entire shut-in period, and occasional injection of a small volume of fluid into one or more randomly selected fracture stages to gain better understanding of fracture growth during the stage.

An important conclusion of the paper is that the Instantaneous Shut-In Pressure (ISIP) does not provide a reasonably accurate measure of the least in-situ principal within the fractured formation.
Modeling Case Study: Optimizing Multicluster Stimulation Uniformity in Horizontal Wells
Authors: Kresse Olga , Sinkov Konstantin , Hobbs Brandon
Published: January 2023

The performance and completion efficiency of horizontal multistage hydraulically fractured wells stimulated using the plug-and-perf technique are affected by the uniformity of the multiple perforation cluster treatment. Depending on reservoir heterogeneity, perforation design, and pumping schedule, uneven distribution of fluid and proppant among fractures connected to different perforation clusters can be defined by wellbore proppant transport hydrodynamics, fracture propagation mechanics, or a complex interplay of both. A modeling case study exploring strategies to mitigate nonuniformity of cluster stimulation is presented. Approaches to perforation and treatment optimization are chosen based on consideration of reservoir properties and their heterogeneity. A numerical model coupling a recently developed wellbore flow simulator and an advanced fracture simulator enables comprehensive simulations including both realistic fracture and wellbore modeling for complex perforation designs, treatment schedules, and distributions of reservoir inhomogeneities. The wellbore simulator considers proppant transport and settling, fluid rheology, perforation erosion, rate- and concentration-dependent pressure drop, and variable efficiency of proppant transport to perforations. The fracture simulator models fracture growth, fluid flow, proppant transport inside fractures, and interaction between fracture branches due to stress shadow effect. The interaction between hydraulic and pre-existing natural fractures plays a critical role during fracturing treatments in formations with pre-existing discrete fracture network (DFN). The model considers the effect of formation heterogeneity on fracture propagation, arrest of hydraulic fractures, crossing and opening of natural fractures depending on their properties, fluid viscosity, rate, and stress conditions. Several approaches for optimization of proppant distribution are suggested for cases showing nonperfect proppant transport efficiency caused by high proppant grain inertia. Tapered perforation designs enable achieving more even proppant distribution. However, perforation distribution among clusters providing best stimulation uniformity is sensitive to uncertainties in characterization and heterogeneity of reservoir and discrete fracture network properties. A combination of tapered perforation design and the suppression of inertial effects by increasing carrier fluid viscosity is more robust with respect to reservoir properties variation.
Integration of Fracturing Pressure Diagnostics with Multi-Well Smart Tracer Program for Hydraulic Fracturing Stimulation and Diversion Efficiency Assessment
Authors: Shokanov Talgat , Oliver John , Pena David , Shokanov Adilkhan
Published: January 2023

Multi-stage hydraulic fracturing stimulation and completion programs now account for up to 70% of total well costs (Shokanov et al. 2019). Faced with unprecedented economic pressures on the entire oil and gas industry, upstream operations must take a serious look at increasing their efficiency regarding the use of completion money and ensuring that increased production results warrant the expenditure. Completion operations must develop systems and processes that deepen insight into complex reservoir performance, right-size well spacing, and focus on data-driven stimulation designs that optimize economics.

This paper highlights one such effort in the Tennessee Colony Field project in East Texas. A novel ultra-high-resolution nanoparticle tracer played a key role in delivering useful data that led to a comprehensive understanding of the reservoir response to stimulation efforts at a stage level. Additional multi-well studies in turn led to developing a full reservoir plan and optimizing well spacing.

The state-of-the-art ultra-high-resolution nanoparticle tracers were added before and after each diverter stage for flow profile mapping and diversion efficiency assessment. In addition, a sampling campaign of adjacent wells was initiated to identify potential communication between old and new wells. The tracers’ data integration with fracturing pressure diagnostics helped to improve the target reservoir development approach and provided a live performance flow profile for the entire field. This data was used to optimize completion and workover strategies, achieve the best well productivities, and significantly enhance the understanding of the reservoir geology for the entire field.

This paper describes the project results including the hydraulic fracturing pressure diagnostics with a multi-well tracer program integration. Since tracers were analyzed over several months from numerous wells, the operator has gained insight into continuous flow profiles leading to optimizing well performance on a regular basis as new production-diagnostic results are received.
Results from a Collaborative Industry Study on Parent/Child Interactions: Bakken, Permian Basin, and Montney
Authors: McClure Mark , Albrecht Magdalene , Bernet Carl , Cipolla Craig , Etcheverry Kenneth , Fowler Garrett , Fuhr Aaron , Gherabati Amin , Johnston Michelle , Kaufman Peter , MacKay Mason , McKimmy Michael , Miranda Carlos , Molina Claudia , Ponners Christopher , Ratcliff Dave , Rondon Janz , Singh Ankush , Sinha Rohit , Sung Anthony , Xu Jian , Yeo John , Zinselmeyer Rob
Published: January 2023

This paper presents results from a collaborative industry study involving ten high-quality pad-scale datasets from the Delaware Basin, Midland Basin, Bakken, and Montney. The study had three primary goals: (a) compare/contrast observations between each dataset, (b) identify general strategies that can be used to mitigate parent/child impacts, and (c) provide concrete recommendations to optimize fracture design and well placement. For each dataset, an integrated hydraulic fracturing and reservoir simulation model was constructed and history matched to the observations. The models were calibrated to production data and pressure measurements, as well as to diagnostics such as: distributed acoustic sensing (DAS), microseismic, downhole imaging, chemical tracers, geochemical production allocations, and pressure observations from offset wells. History matching was performed by varying formation properties and model inputs to ensure consistency with the observations. Once the models were calibrated, the same set of approximately 120 sensitivity analysis simulations was performed on each model. Finally, an automated algorithm was used to quantitatively optimize fracture design and well placement to maximize economic performance. At each step in the process, the results were analyzed to identify the similarities and differences between the datasets and to explain why. The results show how differences in stratigraphy, well configuration, fracture design, and formation properties drive differences in parent/child phenomena. Optimal strategies to mitigate challenges depend on these site-specific conditions. Negative impacts from parent/child interactions cannot be entirely avoided. There is no strategy that can prevent the most important cause of child well underperformance – that wells are attempting to produce hydrocarbons from rock that has already been significantly depleted by parent well production. However, strategic design choices and quantitative economic optimization can significantly improve net present value and return on investment.
Combined Video and Ultrasonic Measurements for Fracture Diagnostics – Greater than the Sum of the Parts
Authors: Tymons Tobben , Roberts Glyn , Troup Duncan
Published: January 2023

Downhole imaging technology has been widely utilized in recent years to help diagnose proppant distribution during hydraulic fracturing operations. Abrasion leading to entry hole enlargement provides strong evidence of proppant placement into individual perforations, and treatment volume can be inferred by measuring the magnitude of this erosion. Results from individual perforations are easily aggregated to cluster and stage level to provide information on overall treatment distribution.

Two different technologies have been deployed for this purpose – an array of downhole video cameras able to capture a full 360˚ view of the borehole and, more recently, multi-transducer ultrasonic instruments. These services have been considered competitors, and arguments for and against both technologies have included their relative measurement resolutions and how this impacts result accuracy, along with sensitivity to 'stick and slip' effects on toolstring motion. Both technologies are also affected to differing degrees by the well fluid and the presence of diverters and proppant in perforations. The recent introduction of a toolstring able to simultaneously acquire images from both sensor types affords the opportunity to objectively compare results acquired under identical conditions and establish their merits and limitations.

The paper considers the underlying physical principles of each of the measurements and reviews in detail the real world results from North American wells that have been logged using both technologies.

The aim of the paper is to provide a more complete understanding of the technologies involved, and how they can be viewed as complementary rather than competitive when they are run simultaneously, allowing potential users to make fully informed decisions on when, why and how to deploy them. We will also demonstrate how the information derived from simultaneous application is of greater value than that derived from the individual technologies in isolation, and how this can be applied to further enhance completion design and frac execution for unconventional wells.
Towards A Net-Zero Future: Decarbonizing Hydraulic Fracturing Operations
Authors: Narang Rishika , Joshi Vaibhav , Goyal Rajat
Published: January 2023

This study discusses sensor-based, real-time detection and monitoring of emissions generated at a wellsite during a hydraulic fracturing treatment. The sensors recorded live data, which was visualized on dashboards and generated alarms whenever the threshold levels were reached beyond the normal emission rate to tell when the workers were being exposed to unsafe levels of greenhouse gas (GHG) and other noxious elements. Algorithms were also developed to check for fuel adulteration and equipment health, identifying low-performing assets that might have undergone wear and tear.

The sensing device detected emissions using multiple electrochemical sensors that can identify particulate matter (PM2.5, PM10, PM1), carbon monoxide (CO), carbon dioxide (CO₂), sulphur dioxide (SO₂), nitrogen dioxide (NO₂), ozone (O₃), hydrogen sulfide (H₂S), and methane (CH4), along with temperature, humidity levels, and GPS coordinates. These readings were then transferred via an Application Programming Interface (API) to a cloud server, where they were stored in a database along with a timestamp. Advanced data visualization and analytics dashboards were created so that users could monitor direct emissions in real-time.

The sensing device was deployed at various locations: near the pump exhaust (keeping wind flow in mind) to capture outdoor job-related emissions as well as in a closed space to study exhaust efficiency. The sensor successfully captured and transmitted live data of all the gases emitted, without manual calculation. Increased levels of NO₂ were observed after sunset (because NO₂ converts into other derivatives and ozone in sunlight). Algorithms were leveraged to interpolate readings that might be missed by the sensor, due to a power cut or human mishandling, for continuous visualization of emissions taking place. Because the sensor device is customizable to measure emissions data for each type of gas, it will be extremely useful for leak detection for both supplied and produced oil and gas and for checking corrosion in pipelines or wellsite facilities.

Such sensor devices are intrinsically safe, portable, easy to install, scalable, nationally certified, and have GPS tracking enabled. To contribute to environmental sustainability and for the world to see a net-zero emissions future, the oil and gas industry has transformed itself using advanced digital technologies. This pilot study, aimed at directly measuring and visualizing emissions in an industrial setting, is one of the major steps toward more pervasive emission monitoring and helping the industry achieve its net-zero goals.
Understanding the Shear History of Various Loadings of Friction Reducers and the Associated Impact on the Fluid's Stability, Pipe Friction Reduction, and Effect on Proppant Transport and Deposition in Both Fresh Water and Brine Base Fluid.
Authors: Anschutz Don , Wildt Pat , McGill Mark , Lowrey Terry , Contreras Kevin
Published: January 2023

The industry is constantly looking for ways to increase completions efficiency, increase well production, and reduce cost. Unconventional completions, on average, use around 4.5 million gallons of water carrying up to 10 million pounds of frac sand. Volumes vary greatly, from under 1 million gallons of water carrying a couple million pounds of frac sand to greater than 10 million gallons of water carrying up to 20 million pounds of frac sand. Changes in the loading of additives can greatly impact the completion costs. Understanding the advantages, or disadvantages, of any changes made to the frac design can help with efficiency and costs, if implemented correctly. The research in this paper highlights how shear stress, proppant transport, and the deposition profile change based on various loadings of commonly used Friction Reducer (FR) mixed in fresh water and brine water.

A 1,500-foot, 0.62-inch internal diameter flow loop is utilized to develop a shear history based on a shear rate equivalent of 100 barrels per minute (BPM) down 11,000 feet of 4.5-inch internal diameter (ID) casing/pipe. FR and High Viscosity Friction Reducers (HVFR) are evaluated at 0.75, 1.5, 3.0 and 5.0 gallons per thousand (gpt) loadings in fresh water and brine as well as guar with a loading of 5.0 gpt in brine (effective polymer loading 20 lbs./1000 gals). Pre-shear and post-shear viscosity readings are recorded for each gel concentration.

The shear conditioned fluid is then utilized to construct the test slurry for the subsequent transport/deposition test. The test slurry is injected into a large slot flow apparatus (10′H × 20′L), with a transverse fracture configuration (top-middle-bottom injection points along the vertical centerline) with an average 0.375-inch width tortuous slot flow path. A typical test entails approximately 750 lbs. of proppant, comprised of 80% by weight of 100 mesh proppant 1.5 pounds of proppant added per gallon (PPA) and 20% by weight of 40/70 mesh proppant at 1.5 PPA. Slurry test pump rate target is 13 gallons per minute (gpm) to simulate the lower shear rate in a far-field fracture environment. Fluid viscosity measurements are recorded post blender and post slot flow apparatus. A deposition profile is generated for each FR loading and job design.

The data are compiled to demonstrate the effects of shear history on the carrier fluid viscosity, as well as to document transport and deposition behavior based on the various loadings of the different friction reducers and pump schedules.
Please Fill in Your Manuscript Title. Impacts of Perforating and Hydraulic Re-Fracturing on Expandable Casing Patches
Authors: Kraynek Michael , Miskimins Jennifer , Eustes Alfred , Joshi Deep , Balderston Mark
Published: January 2023

Re-fracturing is a common technique to ensure the maximum recovery from low-permeability, unconventional reservoirs. Generally in such reservoir systems, optimal gains are made from treating new areas of the reservoir that were unstimulated during the initial completion. To be successful under such circumstances, diversion away from depleted sections of the wellbore is critical. This paper discusses laboratory testing and subsequent finite element modeling (FEM) of full-length expandable casing patches deployed in several refracturing treatments in the Denver-Julesburg Basin, Colorado.

Short sections of casing patches were deployed in 4.5′, 13.5# casing. These sections included unanchored and anchored patch components. One type of each section (anchored and unanchored) was then perforated with a full-size perforating gun, 4 shot each section, 90° phasing. The perforating took place at the Edgar Mine Testing Facility in Idaho Springs, Colorado. Both the anchored and unanchored, perforated and unperforated, patch/casing sections were then push/pull-tested to determine friction factors and the impacts of the perforating on the patch/casing interface. These results were then incorporated into FEM modeling to determine the ability of the full-size, field-deployed patch to remain stationary and the impact such would have on perforation alignment during treatment conditions.

Both the push/pull tests and the subsequent FEM modeling suggest that the full-length casing patch exhibits only a minimal shift during the application of the forces associated with the hydraulic fracturing process. Some miss-alignment of perforations may occur but not to the level that they negatively impact the treatment success. These results align with the field trials which indicate positive re-fracturing treatment results. This unique project tested the viability of full-length casing patches in the refracturing process and incorporated laboratory testing of the casing-casing patch interfaces under both perforated and unperforated into FEM modeling, with comparison to field results. This process provides a full cycle analysis of the re-fracturing process using this diversion technique.
Simul-Frac Candidate Wells Identified in the Delaware Basin via Remote Operations
Authors: Completions Team Matador , Street Jesse
Published: January 2023

The efficiencies observed in simul-frac operations are commonly associated with a singular, four-plus well pad containing an even number of wells. These efficiencies yield significant savings and reduction in overall completion time, expedite first-production and substantially reduce the time in which offset wells are shut in during frac operations. The introduction of remote simul-frac operations in the Delaware Basin, proven by Matador Resources Company in their Stateline asset, has removed this operational single-pad limitation by connecting adjacent multi-well pads and opening the opportunity to capitalize on ‘traditional’ simul-frac efficiencies on multiple pads simultaneously.

Simul-frac is the use of a singular frac crew to simultaneously stimulate two separate wells. In most cases, the frac crew is equipped with an increase in hydraulic horsepower to be able to achieve rates ranging from 120 – 160 barrels per minute. The backside equipment in a Simul-Frac operation remains relatively unchanged, with the crew still utilizing only one blender. In earliest trials, wells completed via simul-frac operations were on the same pad and potentially receiving an uneven split of the fracturing slurry. By splitting the flow on the low- and high-pressure side of the frac, Matador and Universal Pressure Pumping were able to evenly meter the flow of slurry to two separate banks of pumps on location. One bank led to a zipper manifold on the same location that directed flow accordingly. The other bank directed flow along a 1,500′ high-pressure flanged-pipe frac line to an adjacent location to stimulate its "partner" well. Remote, satellite-communicating pressure gauges were used to monitor pressures on the adjacent pad.

Matador has reported savings of up to ~7.5% of total completion spend per well and increased completed lateral footage per day by upwards of 50% on four well simul-fracs. Six of eleven batched wells in the Stateline asset were selected as a pilot location in Q4 of 2021 for remote simul-frac operations. Two three-well pads, Pad A and Pad B, were to be connected via high-pressure frac line and simultaneously stimulated. A Universal frac spread capable of 160 bpm was rigged up on Pad A and successfully stimulated wells on both Pad A and Pad B, via a high-pressure remote frac line throughout the job. The remote frac operations were a success; 6 wells, 407 stages, and over 73,000 lateral feet were completed in just under 33 days. In addition to the ~7.5% total completion spend per well savings, Matador was able to reduce total completion time by roughly 20 days, which brought forward production on the 11 well batch by 20 days and simultaneously reduced shut-in time of 16 offset wells.

Successful remote simul-frac operations have enabled Matador to revisit a much wider variety of planned pads as candidates for simul-frac activity. After successful implementation in Q4 2021, Matador was able to increase its 2022 simul-frac activity by 91% due to remote operations.
Extended-Time Conductivity Testing of Proppants at 0.5 lb/ft2 Used for Slickwater Multi-Stage Horizontal Completions
Authors: Pearson C. Mark , Green Christopher A. , Milton-Tayler David , Trevino Viviana
Published: January 2023

The American Petroleum Institute testing Standard 19-D (2008) is the current industry standard for conductivity testing of proppants used in hydraulic fracturing. Similar to previous standards from both the API and ISO, it continues the practice of measuring a "reference" conductivity obtained under 50-hours of time at a given stress. The fracture design engineer is then left to estimate a damage factor to apply to the long-term design of the well completion.

This study takes three 40/70 mesh proppants commonly used for multi-stage horizontal well slickwater completions in North America and presents 0.5 lb/ft2 test data over 1000-hours of "extended time" at stress and temperature conditions representative of the Bakken formation of North Dakota. Results presented give clear insight to the degree of damage occurring in the reservoir due to time at stress and temperature. To the authors knowledge, there has never been any extended time conductivity data published at proppant concentrations representative of slickwater fracturing - despite the obvious need for this understanding to optimize the performance of unconventional slickwater well stimulation designs.

The API Standard 19-D procedure for conductivity testing was followed for the tests presented in this paper, but with the proppant concentration loaded at 0.5 lb/ft2 to represent a slickwater proppant pack, and all tests run at 250°F regardless of the proppant material type. The extended time test was run for 1000-hours duration for three commonly used 40/70 mesh proppants used in North American Unconventional Slickwater Well Completions: 40/70 mesh mono-crystalline "white" sand (WS), 40/70 mesh multi-crystalline "brown" sand (BS), and 40/70 mesh light weight ceramic (LWC). The results are presented as conductivity curves as a function of time for the period of testing. Logarithmic Conductivity Degradation Factors (LCDF) were calculated for each proppant type. Degradation for all materials is extrapolated to the point of zero residual conductivity, and compared to previous extended term testing for 1# and 2# proppant packs.
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

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

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

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

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

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

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

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

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.