bluuebunny/crossref_metadata_2025 huggingface dataset:
Multistage Horizontal Well Hydraulic Fracturing Stimulation Using Coiled Tubing to Produce Marginal Reserves from Brownfield: Case Histories and Lessons Learned
Authors: Hassan Amro , ElMeguid Ahmed Abd , Waheed Arshad , Salah Mohamed , ElKarim Essam Abd
Published: February 2021

The Baharyia formation is a common reservoir in the Western Desert of Egypt. It is characterized as a heterogeneous reservoir with low sand quality. It is comprised of fine-grained sandstone, thin, laminated, sand-poor parasequences with shale interbeds. The heterogeneity and low permeability of the Upper Baharyia reservoirs are the primary challenges to maintaining economic well productivity.

The interest in developing low permeability reservoirs stems from favorable economics attributed to advancements in horizontal well drilling and hydraulic fracturing technology, offering methods to increase production by increasing the contact area of the producing interval. Subsequently, it became apparent that wellbore contact alone was not always sufficient for providing production increases expected, thus requiring multistage hydraulic fracturing (MSHF) stimulation treatments to achieve production targets.

Primary well production analysis revealed that the cumulative production from the horizontal well discussed was enhanced from 37 to 70% of recoverable reserve and the recovery factor was doubled. From a production analogy standpoint, these resulted in reduced drilling of three vertical wells and had direct economic benefits by reducing the installed artificial lift strings, related expensive artificial lift equipment repairs, and the number of necessary workovers.

This paper takes a multidisciplinary approach to help understand productivity enhancement of low permeability reservoirs in the Western Desert of Egypt, through a detailed analysis of well performance and successful implementation of MSHF in horizontal wells to maximize drainage volume around the well. It is intended to serve as guidelines to help operators facing similar challenges.
Achieving Cementing Improvement in Horizontal Tight Gas Field Development
Authors: Ariyanto Pungki , Najwani Mohamed A. , Najwani Yaseen , Al Lawati Hani , Pfeiffer Jochen , Al Abri Muna
Published: February 2021

This paper outlines how a drilling team is meeting the challenge of cementing a production liner in deep horizontal drain sections in a tight sandstone reservoir. It is intended to show how the application of existing technologies and processes is leading to performance gain and improvements in cementing quality.

The full field development plan of the tight reservoir gas project in the Sultanate of Oman is based on drilling around 300 wells targeting gas producing horizons at measured depths of around 6,000m MD with 1,000m horizontal sections.

Effective cement placement for zonal isolation is critical across the production liner in order to contain fracture propagation in the correct zone. The first few attempts to cement the production liner in these wells had to overcome many challenges before finally achieving the well objectives. By looking at the complete system, rather than just the design of the cement slurry, the following criteria areas were identified:

- Slurry design

- Mud removal and cement slurry placement

- Liner hanger and float equipment

Improvements have been made in each of these areas, and the result has been delivery of a successfully optimised liner cementing design for all future horizontal wells.
Petrophysical and Fluid Flow Properties of a Tight Carbonate Source Rock Using Digital Rock Physics
Authors: Dernaika Moustafa , Jallad Osama Al , Koronfol Safouh , Suhrer Michael , Teh Woan Jing , Walls Joel , Matar Saad , Murthy Natarajan , Zekraoui Mohammed
Published: February 2021

The evaluation of shale is complicated by the structurally heterogeneous nature of fine-grained strata and their intricate pore networks, which are interdependent on many geologic factors including total organic carbon (TOC) content, mineralogy, maturity and grain-size. The ultra-low permeability of the shale rock requires massive hydraulic fracturing to enhance connectivity and increase permeability for the flow. To design an effective fracturing technique, it is necessary to have a good understanding of the reservoir characteristics and fluid flow properties at multiple scales.

In this work, representative core plug samples from a tight carbonate source rock in the Middle East were characterized at the core- and pore-scale levels using a Digital Rock Physics (DRP) workflow. The tight nature of the carbonate rocks prevented the use of conventional methods in measuring special core analysis (SCAL) data. Two-dimensional Scanning Electron Microscopy (SEM) and three-dimensional Focused Ion Beam (FIB)-SEM analysis were studied to characterize the organic matter content in the samples together with (organic and inorganic) porosity and matrix permeability. The FIB-SEM images in 3D were also used to determine petrophysical and fluid flow (SCAL) properties in primary drainage and imbibition modes.

A clear trend was observed between porosity and permeability related to identified rock fabrics and organic matter in the core. The organic matter was found to have an effect on the imbibition two-phase flow relative permeability and capillary pressure behavior and hysteresis trends among the analyzed samples. The data obtained from DRP provided information that can enhance the understanding of the pore systems and fluid flow properties in tight formations, which cannot be derived accurately using conventional methods.
$40 Billion Learning Curve: Leveraging Lessons Learned to Minimize the Overall Investment in Unconventional Plays
Authors: Fredd C.N.. N. , Daniels J.L.. L. , Baihly J.D.. D.
Published: February 2021

The industry has made significant advances in the way we exploit unconventional resources such as source rock and tight reservoirs. Innovations in horizontal drilling and multistage fracturing have unlocked previously uneconomical plays, and technology has brought a step change in operational efficiency. Lessons learned from unconventional resources highlight collaboration and integrated reservoir-centric workflows as common traits for economic success.

The development of unconventional resources in North America was aided by the readily available infrastructure, water resources, expertise, and a general understanding of potential sweet spots due to numerous well penetrations. Even with these favorable conditions, an estimated 40% of unconventional wells are uneconomical due to spatial variability in reservoir characteristics, lateral heterogeneity along the wellbores, accuracy of well placement, and variability in drilling, completion, and stimulation practices. This non-ideal economic performance also ineffectively consumes local resources such as water and proppant.

This paper provides a retrospective assessment of the Barnett Shale and Eagle Ford Shale to highlight lessons learned and the associated value of those learnings. The impact of applying technology and utilizing a data-driven approach based on measurements will be assessed in terms of the investment required to achieve a given hydrocarbon production. The results indicate that these unconventional plays could have been developed with well counts reduced by the thousands, water consumption reduced by billions of gallons, and investment savings in the billions of dollars if initially exploited by applying the key lessons learned from over the past 30 years. This potential reduction in investment amounts to $40 billion for the Barnett Shale (shale gas) plus the Eagle Ford Shale (oil window) and represents the significant value of moving along the learning curve. Fortunately, there is no need to repeat this learning curve investment, as key lessons learned can be applied to other unconventional plays around the world. This learning curve is of specific value in international plays where local infrastructure, supply, and market conditions may not be as favorable as in North America, hence necessitating a different approach to optimize the overall investment when developing unconventional plays.
Implications of Shale Oil Compositions on Surfactant Efficacy for Wettability Alteration
Authors: Feng Lijie , Liang Xu
Published: February 2021

Surfactant selection is important for oil recovery in a hydraulically fractured reservoir. Two primary mechanisms, ion-pair coupling (cleaning) between surfactant and hydrocarbon and surfactant adsorption onto the rock surface (coating), were previously suggested to explain how surfactants can alter rock wettability, thus improving oil production. Because of the electrostatic interaction, acidic compounds in the oil tend to be adsorbed onto rock surface that is positively charged; whereas basic compounds are preferentially attracted to rock surface that is negatively charged. It has been discussed in previous literature that for wettability alteration for conventional formation rocks, the cleaning mechanism could be more efficient by inducing ion pairs between surfactants and oil compounds that have opposite charges, rather than the coating mechanism that mainly relies on how well surfactant covers the rock surface.

In this research, 90 shale oils from various liquids shale plays, such as the Eagle Ford and the Wolfcamp, were tested for total acid number (TAN) and total base number (TBN). Cationic and anionic surfactants with low interfacial surface tension, along with Berea sandstone and Indiana limestone, were used to investigate the extent that TAN and TBN can be used as criteria to select surfactants. Oil recovery, imbibition, interfacial surface tension, and emulsion tendency were conducted to examine whether the cleaning mechanism holds true for shale oil saturated formation rocks. The results demonstrated that for carbonates with shale oil having a higher TAN, a cationic surfactant provided the potential to sweep more oil than an anionic surfactant. On the other hand, for sandstone with shale oil having a higher TBN, an anionic surfactant performed better than a cationic surfactant. Those observations appear to be consistent with the proposed cleaning mechanism and resonate with production data for thousands of wells from some major liquids-rich shale plays.
The Fresh Water Neutral Challenge: The Need for Protection, Reduction, Innovation, and Conservation
Authors: Greaves R. , Hartstein R. , Lincicome D. , Wehner J. , Beck P. , Lamb J. , Olson K.
Published: February 2021

Southwestern Energy (SWN) is committed to being neutral in regard to the use of fresh water in our operations by 2016. This means that SWN will offset our fresh water footprint by reducing our fresh water usage and by replenishing any fresh water that we do use through conservation projects, which are designed to improve water quality and availability for the environment and communities around us. To meet this “fresh water neutral” commitment, the company launched the Energy Conserving Water (ECH2O) initiative in 2013.

Achieving ECH2O's goals centers on four key elements: 1) protection of water resources; 2) reduction of water used in our operations; 3) innovation to efficiently utilize alternative, non-fresh water sources; and 4) conservation to improve or replenish water resources.

SWN uses water in its operations every day, with the predominant usage for well stimulation through hydraulic fracturing. Our two largest operating divisions, the Fayetteville Shale and Marcellus Shale, use nearly 70 million barrels of water annually to hydraulically fracture over 500 wells. The fresh water use in these major areas, as well as smaller operating areas, and other operational uses of water are all included in the ECH2O imperative.
Numerical Investigation of Complex Hydraulic Fracture Development in Naturally Fractured Reservoirs
Authors: Kan Wu , Olson Jon E.
Published: February 2021

Complex fracture networks have become more evident in shale reservoirs due to the interaction between pre-existing natural and hydraulic fractures. Accurate characterization of fracture complexity plays an important role in optimizing fracturing design, especially for shale reservoirs with high-density natural fractures.

In this study, we simulated simultaneous multiple fracture propagation within a single fracturing stage using a complex hydraulic fracture development model. The model was developed to simulate complex fracture propagation by coupling rock mechanics and fluid mechanics. A simplified three-dimensional displacement discontinuity method was implemented to more accurately calculate fracture displacements and fracture-induced dynamic stress changes than our previously developed pseudo-3d model. The effects of perforation cluster spacing, differential stress (SHmax - Shmin) and various geometry natural fracture patterns on injection pressure and fracture complexity were investigated.

The single stage simulation results shown that (1) higher differential stress suppresses fracture length and increases injection pressure; (2) there is an optimal choice for the number of fractures per stage to maximize effective fracture surface area, beyond which increasing the number of fractures actually decreases effective fracture area; and (3) fracture complexity is a function of natural fracture patterns (various regular pattern geometries were investigated). Natural fractures with small relative angle to hydraulic fractures are more likely to control fracture propagation path. Also, natural fracture patterns with more long fractures tend to increase the likelihood to dominate the preferential fracture trend of fracture trajectory. Our numerical model can provide a physics-based complex fracture network that can be imported into reservoir simulation models for production analysis. The overall sensitivity results presented should serve as guidelines for fracture complexity analysis.
In-Situ Formation of Proppant and Highly Permeable Blocks for Hydraulic Fracturing
Authors: Chang Frank F. , Berger Paul D. , Lee Christie H.
Published: February 2021

Proppants are used to keep hydraulic fractures open, allowing for reservoir fluids to flow back after external pressure is withdrawn. Proppants are carried by the hydraulic fracturing fluid containing multiple components such as polymers, breakers, or friction reducing agent. These proppant systems have certain disadvantages such as formation and fracture permeability damage due to the viscous gel residue, risk of early screen-out and reduced effective propped area due to proppant excessive leakoff or settling, and abrasion to the pumping equipment and tubular.

Acid fracturing is another fracturing technique. It is used in carbonate reservoirs, in which the acid etches the fracture faces to create conductive path. The drawbacks of acid fracturing include short acid etch length due to rapid acid-carbonate rock reaction rate and corrosion to the tubular.

The oil and gas industry has been relying on these hydraulic fracturing techniques to proliferate production from low permeability reservoirs, and has made significantly advancement in tools and chemicals used in the fracturing processes. However, the maximized production and recovery is still unattainable due to the reasons mentioned above. This paper discusses a novel chemical compositions and process to overcome the challenges encountered by the current fracturing techniques. The goal is to convert injected fracturing fluid into a highly permeable proppant pack in-situ. Since the fracturing fluid itself forms the proppant, it can penetrate the entire fracture length, height, and complex network, maximizing the effective fracture area and stimulated reservoir volume. The rendered particle size can be significantly larger than conventional proppants without the concern of screen-out. The in-situ formed proppants have strength sufficient to resist fracture closure stress. In addition, no polymer is required to suspend the proppant; therefore no gel residue will be left to damage fracture conductivity.

Though it is in its preliminary development stage, interesting and encouraging test results have been obtained. Formulations, photos, and mechanical properties of in-situ generated proppants will be presented in this paper.
An Improved Equilibrium-Height Model for Predicting Hydraulic Fracture Height Migration in Multi-Layer Formations
Authors: Liu Songxia , Valkó Peter P.
Published: February 2021

Fracture height is a critical input parameter for 2D hydraulic fracturing design models, and also an important output result of 3D models. While many factors may influence fracture height evolution in multi-layer formations, the consensus is that the so called “equilibrium height belonging to a certain treating pressure” provides an upper limit, at least for non-naturally fractured media. How to solve the “equilibrium height” problem has been known since the 1970s. However, because of the complexity of the algebra involved, published equations are overly simplified and do not provide reliable results.

We revisited the equilibrium height problem, and our theoretical and numerical investigations led to a new model that fully characterizes height evolution amid various formation properties (fracture toughness, in-situ stress, thickness, etc.). The new model, for the first time, rigorously solves the equilibrium height mathematically. With the help of computer algebra software, we applied a definition of fracture toughness, incorporated the effects of hydrostatic pressure, and considered non-symmetric variations of layered formation properties. Results were determined for the classic 3-layer problem and then were extended to 6 layers.

The effects of reservoir and fluid properties on the fracture height growth were investigated. Tip jump is caused by low in-situ stress; tip stability is imposed by large fracture toughness and/or large in-situ stress. If the fluid density is ignored, the result regarding to which tip will grow into infinity could be totally different. For any multi-layer formation problem, two, 3-layer pseudo problems were constructed to create an outer and inner height envelope, in order to assess the potential effects of reservoir parameter uncertainties on height profile. Second solution pair in the 3-layer problem was investigated numerically and analytically, to avoid misleading results in the 3D models.

This improved model can rapidly (in seconds) and reliably calculate the theoretical maximum equilibrium fracture height in layered formations with various rock mechanical properties. Then, the equilibrium height can be used to (1) provide input data for 2D model, (2) improve 3D model governing equations, (3) determine the net pressure needed to achieve a certain height growth, and (4) obtain the maximum net pressure assuring no fracture invasion into aquifers. This model may be incorporated into current hydraulic fracture simulation software to yield more accurate and cost-effective hydraulic fracturing designs.
A Case History: Evaluating Well Completions in the Eagle Ford Shale Using a Data-Driven Approach
Authors: Nejad Amir M. , Sheludko Stanislav , Shelley Robert F. , Hodgson Trey , McFall Riley
Published: February 2021

Unconventional shale resources are key hydrocarbon sources, gaining importance and popularity as hydrocarbon reservoirs both in the United States and internationally. Horizontal wellbores and multiple transverse hydraulic fracturing are instrumental factors for economical production from shale assets. Hydraulic fracturing typically represents a major component of total well completion costs, and many efforts have been made to study and investigate different strategies to improve well production and reduce costs. The focus of this paper is completion effectiveness evaluation in different parts of the Eagle Ford Shale Formation, and our objective is to identify appropriate completion strategies in the field.

A data-driven neural network model is trained on the database comprised of multiple operators' well data. In this model, drilling and mud data are used as indicators for geology and reservoir-related parameters such as pressure, fluid saturation and permeability. Additionally, completion- and fracture-related parameters are also used as model inputs. Because wells are pressure managed differently, normalized oil and gas production is used as a model output. Thousands of neural networks are trained using genetic algorithm in order to fully evaluate hidden correlations within the database. This results in selection of a neural network that is able to understand reservoir, completion and frac differences between wells and identify how to improve future completion/stimulation designs.

The final neural network model is successfully developed and tested on two separate data sets located in different parts of the Eagle Ford Shale oil window. Further, an additional test data set comprised of eight wells from a third field location is used to validate the predictive usefulness of the data-driven model. Under-producing wells were also identified by the model and new fracture designs were recommended to improve well productivity.

This paper will be useful for understanding the effects of completion and fracture treatment designs on well productivity in the Eagle Ford. This information will help operators select more effective treatment designs, which can reduce operational costs associated with completion/fracturing and can improve oil and gas production.
What is More Important for Proppant Transport, Viscosity or Elasticity?
Authors: Hu Y. Thomas , Chung HsinChen , Jason Maxey
Published: February 2021

The contributions of viscosity and elasticity to inhibiting proppant settling in gelled fracturing fluids are quantified and decoupled in this study. The settling velocity of a single particle under orthogonal shear flow was measured in a transparent Couette flow cell using automatic particle tracking, and the local flow field was mapped using particle tracking velocimetry. The settling behavior is correlated with the rheological properties of the fluids.

In carboxymethyl hydroxypropyl guar (CMHPG) crosslinked with borate, particle settling slows as the orthogonal shear rate increases, with settling essentially stopping at sufficiently high shear rates. The authors propose that there are two primary mechanisms for the enhanced particle suspending under the orthogonal shear—shear thickening and elastic lifting. The relative importance of the two factors depends on the shear rate and fluid relaxation time. Specifically, the ratio of the elastic and viscous contribution to particle suspension is γe/v=0.5cλN1(γ˙)η(γ˙), where c is a constant, λ is the stress relaxation time, N1(γ˙)) is the first normal stress difference that depends on the shear rate γ˙, and η(η(γ˙)) is the viscosity.

For the crosslinked CMHPG gel examined in this work, it is determined that γe/v=0.26γ˙2, indicating that the viscosity is more important at γ⋅<2s−1, whereas the elasticity becomes dominant at γ˙<2 s−1 for proppant suspending. For the uncrosslinked CMHPG, γe/v=0.0035γ˙1.3 , indicating that the elastic contribution becomes more important than the viscous contribution only at shear rates > 80 s−1. The understanding of the relative importance of viscosity and elasticity can provide guidance for chemists to develop better fracturing fluids and for engineers to model proppant transport
Application of Extended Finite Element Method (XFEM) to Simulate Hydraulic Fracture Propagation from Oriented Perforations
Authors: Sepehri Jay , Soliman Mohamed Y. , Morse Stephen M.
Published: February 2021

Understanding fracture initiation and propagation from perforated wellbores is essential to designing a perforation scheme to achieve an efficient hydraulic fracture stimulation treatment. The effect of perforation design on hydraulic fracture propagation has been extensively studied using experimental and analytical methods. Because the experimental investigation of hydraulic fracture is complicated, expensive, and often returns limited results, numerical methods can be applied as an efficient way to simulate fracture propagation from perforations. An Extended Finite Element Method (XFEM) was used to develop a model to investigate the effects of various parameters on fracture propagation from a set of perforations. These parameters included perforation orientation, perforation length, stress anisotropy, and elastic properties of the formation. Fracture propagation patterns from the XFEM model were first matched against published experimental studies and exhibited good agreement. The model was then used to broaden the study of perforation effects. Results of the modeling proved the effects of perforation orientation and length on hydraulic fracture propagation pattern. Horizontal stress anisotropy and rock mechanical properties were observed to strongly influence fracture propagation. It was also observed that, when two or more perforations are positioned at different orientation angles at the same depth, a fracture tends to propagate from the less deviated perforation. In these cases, the more deviated perforation can develop a short fracture, following a propagating pattern that could be caused by stress shadowing/interference. Stress interference between two perforations positioned closely together results in either perforation breakdown or fracture propagating away from one another. The simulation results from this study offer methods to enhance perforation design for hydraulic fracture treatment, particularly in the case of high stress anisotropy and high uncertainty in a preferred fracture plane. Analyzing competing perforations suggests that a technique based on this concept can be applied when high uncertainty exists regarding the direction of the principal horizontal stresses through increasing perforation density.
The Third Dimension: Productivity Effects From Spatial Placement and Well Architecture in Eagle Ford Shale Horizontal Wells
Authors: Holcomb William , LaFollette Randy F. , Zhong Ming
Published: February 2021

Eagle Ford shale formation exhibits highly variability hydrocarbon production rates and EUR within small areas, indicating a highly heterogeneous reservoir. Attempts to determine performance drivers among geological, production or completion data points have produced inconclusive results. For example, production for one cluster of nearby wells may be strongly correlated with proppant quantity, while the trend is not valid for a group of similar wells a short distance away. A more widely valid set of correlations could improve engineering efficiency and productivity across the play.

Multivariate statistical modeling has indicated that wellbore architecture factors influence well performance. Such models have determined relative influence of such factors as fracturing fluid type and volumes, proppant sizes and volumes, etc. On the wellbore architecture side, prior studies found that surface latitude and longitude are among the strongest drivers. However, these studies largely omitted consideration of the third dimension (relative vertical location in the reservoir).

This study evaluates productivity influences from azimuth, dip, porpoising, and TVD from heel to toe (vertical zone coverage). It also reconsiders previously studied factors (such as fracturing fluids and proppants) with a considerably larger body of data—especially longer-term production data—than was available for the prior studies. The goal is to determine geological, wellbore architecture, and completion factors that show statistical significance as performance drivers, and where they are applicable if the results vary across the play.
Field Determination of Fracture Propagation Mode Using Downhole Pressure Data
Authors: Daneshy Ali , Touchet Chad , Hoffman Fred , McKown Mike
Published: February 2021

This paper presents the analysis results of 60 single stage fracturing treatments performed in a horizontal well using cemented casing sleeves and a coiled tubing deployed frac isolation system as the completion method. In this carefully set-up and executed treatment, separation between the toe stages was 97 feet, and near the heel it was 55 feet. Pressure data was collected above and below the retrievable plug used for stage isolation. This data was used for analysis of fracturing treatment data which included mode of propagation, completion efficiency, and a rough estimate of fracture orientation. The analysis showed that; There was no interaction between adjacent fractures during five of the sixty fracturing stages. None of these was in the well interval with shorter fracture spacingFracture shadowing occurred during six fracture stages, again none in the shorter spacing intervalMinor cement defects (micro-annuli) caused some fluid migration into the passive segment of the well. This happened in 27 stages. Of these; In eleven cases the cement defects were plugged after a while, causing the migration of fracturing fluid into the passive interval to stop.In sixteen other cases the fluid migration through cement micro-annuli continued during fracturing.During ten stages, defective zone isolation and fluid migration caused a pressure increase of several hundred psi in the passive segment of the well. But this did not result in extension of passive fractures.The volume of migrated slurry due to inadequate zone isolation was mostly a very small fraction of the injected volume.During five stages poor cement quality hampered stage isolation and caused immediate link between adjacent active and passive intervals and extension of passive fractures.The data indicate possible connection between the active and one passive fracture in four stages.Shorter spacing between stages increased the incidents of fluid migration due to poor cement qualityThe fracturing pressure variations during the treatments did not indicate presence of large stress shadowingA rough estimation of fracture orientation indicates that they were likely to be vertical and nearly perpendicular to the wellbore.The fracture growth pattern can best be described as off-balance.

To our knowledge, this is the first time existence of direct communication between adjacent fractures has been observed through actual pressure interference data.
Can We Engineer Better Multistage Horizontal Completions? Evidence of the Importance of Near-wellbore Fracture Geometry from Theory, Lab and Field Experiments
Authors: Lecampion B. , Desroches J. , Weng X. , Burghardt J. , Brown J.E.
Published: February 2021

There is accepted evidence that multistage fracturing of horizontal wells in shale reservoirs results in significant production variation from perforation cluster to perforation cluster. Typically, between 30 and 40% of the clusters do not significantly contribute to production while the majority of the production comes from only 20 to 30% of the clusters.

Based on numerical modeling, laboratory and field experiments, we investigate the process of simultaneously initiating and propagating several hydraulic fractures. In particular, we clarify the interplay between the impact of perforation friction and stress shadow on the stability of the propagation of multiple fractures. We show that a sufficiently large perforation pressure drop (limited entry) can counteract the stress interference between different growing fractures. We also discuss the robustness of the current design practices (cluster location, limited entry) in the presence of characterized stress heterogeneities.

Laboratory experiments highlight the complexity of the fracture geometry in the near-wellbore region. Such complex fracture path results from local stress perturbations around the well and the perforations, as well as the rock fabric. The fracture complexity (i.e., the merging of multiple fractures and the reorientation towards the preferred far-field fracture plane) induces a strong nonlinear pressure drop on a scale of a few meters. Single entry field experiments in horizontal wells show that this near-wellbore effect is larger in magnitude than perforation friction and is highly variable between clusters, without being predictable. Through a combination of field measurements and modeling, we show that such variability results in a very heterogeneous slurry rate distribution; and therefore, proppant intake between clusters during a stage, even in the presence of limited entry techniques. We also note that the estimated distribution of proppant intake between clusters appears similar to published production log data.

We conclude that understanding and accounting for the complex fracture geometry in the near-wellbore is an important missing link to better engineer horizontal well multistage completions.
Coiled Tubing Horizontal Well Fracturing in the Low Young's Modulus, Low Permeability Belridge Diatomite: Challenges Faced and Lessons Learned
Authors: Malhotra Sahil , Merrifield Tom , Lynch Cynthia , Larue Dave , Madding Angela , Collins Jye
Published: February 2021

Coiled tubing fracturing has been successfully applied in multi-stage vertical well stimulation in the Belridge diatomite in the Lost Hills field. This same methodology was used to complete two northwest-trending horizontal wells drilled on the northeast flank of the Lost Hills anticlinal structure that targeted thinner higher oil-saturation strata, separated by thicker low oil-saturation intervals. The target reservoir is comprised of high porosity, low matrix permeability Opal A diatomite.

The perforations were jetted by pumping sand slurry down the coiled tubing and the frac job was pumped down the annulus. The stages were isolated by setting sand plugs. Nine and twelve stages were pumped in the two wells respectively. The perforation locations for different stages were selected in areas with: 1) high resistivity and inferred high oil saturations, 2) absence of hydraulic fractures from nearby wells, 3) excellent cement bonding, and 4) low intensity of natural fractures. These assessments followed logging while drilling (LWD) gamma ray, induction resistivity and azimuthally focused resistivity (image) logs and cased-hole ultrasonic image tool (USIT) run with the aid of a tractor. The hydraulic fractures were monitored using surface tiltmeter sensors. Oil and water soluble tracers were pumped to determine the relative production contribution from the stages and fracture fluid cleanup, respectively, from the stages. All the jobs could be successfully pumped without any screen outs. Challenges were faced in setting sand plugs and isolating stages. Large fracture widths and low leak-off into the formation led to difficulty in forming sand bridges at the perforations and concentrating sand in the wellbore for the plugs. Surface tiltmeters showed excessive fracture height growth. Tracer results showed that 20-30% of the stages contributed to 50-60% of the production. Stages with higher treating pressures contributed less towards production. This could be attributed to near wellbore tortuosity in these stages. Proppant flowback was encountered in one well, and after an effective clean up the production rose.

The study illustrates how integration of various aspects such as completion design, fracture pressure analysis and diagnostics combined with geologic and reservoir information can help in identifying challenges and finding potential solutions of hydraulic fracturing. The findings highlight that the technology most suitable for vertical well stimulation might not be favorable for horizontal well stimulation.
Treating and Permitting of Produced Water for Discharge to Surface Water
Authors: Dan Mueller P.E.
Published: February 2021

The recycling and reuse of produced water (defined as hydraulic fracturing flowback water and formation water) is an increasing practice driven by competing demands for water sources and limited options for produced water disposal. The final disposition of reused/recycled produced water dictates the level of treatment with typically minimal treatment required when produce water is reused for fracturing subsequent wells and higher levels of treatment required when produced water is recycled for other purposes or potentially discharged to surface water bodies. The latter scenario, discharge of treated produced water is specifically addressed. Clean Water Act National Pollutant Discharge Elimination System (NPDES) permits for direct discharge of oil and gas generated discharge are currently prohibited east of the 98th meridian. West of the 98th meridian, direct discharge of treated oil and gas wastewater is allowed under specific conditions. Regardless of location (east or west of the 98th meridian), centralized wastewater treatment facilities (CWTs) can be permitted to treat and discharge oil and gas wastewater or CWT discharge may be accepted for further treatment and ultimate discharge at publically owned wastewater treatment facilities (POTWs). The EPA is currently developing effluent limitation guidelines (ELGs) for pretreatment of oil and gas wastewater sent to POTWs for treatment and discharge and recently submitted for comment Final 2012 and Preliminary 2014 Effluent Guidelines Program Plans; both addressed in this paper. Discussed are the various treatment technologies currently deployed and permitting issues associated with the treatment facilities. When treating produced water for discharge, constituent levels in the effluent stream and the waste side streams (consisting of a concentration of constituents removed as part of the water treatment processes) must be monitored to ensure proper management.
Revolutionary Particle Fluid System Unlocks of Fractured Reservoir Potential
Authors: Zhou Jia , Carman Paul , Sun Hong , Wheeler Richard , Brannon Harold , Gupta D.V. Satya , Starks Ray
Published: February 2021

Post-treatment production analyses for hydraulic fracturing treatments with conventional crosslinked gel or slickwater often indicate that the treatments do not achieve the designed stimulation effectiveness, which could be attributed to non-optimal proppant placement and/or significantly damaged fracture conductivity. Although conventional crosslinked fluids are observed to provide good proppant suspension in laboratory environments, they might not provide the desired proppant transport under downhole conditions. Crosslinked fluids are known to be difficult to clean up, and thus are notorious for imparting gel damage to proppant pack and formation. Slickwater can be used to mitigate gel damage by reducing the effective polymer loadings, but consequential extreme proppant settling and banking problems reduce the chance of achieving fracture performance. Several proppant placement techniques have been developed to generate highly conductive paths for hydrocarbons to flow from an unconventional reservoir to the wellbore, such as hybrid fracturing, reverse hybrid fracturing, and channel fracturing, each of which predominantly rely upon high viscosity fluids to carry the proppant to the designated location.

This paper presents a non-traditional fracturing fluid system and application technique with near perfect proppant suspension and transport, high fracture conductivity, and self-diverting characteristics. The revolutionary fracturing fluid system employs engineered packing of particle domains for proppant suspension mechanics that are significantly different from crosslinked polymer systems which use polymer chain overlap and inter-chain crosslinking to generate viscosity governed proppant transport. The unique gel particle structure perfectly suspends proppant for several hours at reservoir conditions to facilitate better transverse and vertical placement of proppant in the fracture and significantly increases the fractured surface area, which is one of most important factors in unconventional reservoir production. The self-diverting tendencies offer the potential to maximize created fracture area while simultaneously reducing the treating fluid volumes without the addition of costly diverting additives. The degradability of the fluid can be controlled at reservoir conditions by fluid pH and/or breaker loading to yield near 100% regained proppant pack conductivity.

This paper discusses the evolution of the technology, and laboratory results for this unique fluid system. The system can unlock reservoir potential in areas requiring high fractured surface area and high regained conductivity, such as unconventional liquid-rich formations.
Chemical Compatibility of Mixing Utica and Marcellus Produced Waters - Not All Waters are Created Equal (A Case Study)
Authors: Woodward F.B. , Schulmeister B.E. , Caldwell C. , Seeman R. , Hudson R.S.
Published: February 2021

Operators have many options to consider and factors they must evaluate in developing a successful water management plan. The re-use and mixing of produced waters during fracturing operations to help mitigate the continued use of fresh water, or even simply for the disposal of produced water, is critical in maintaining the oil and gas industry's social license and streamlining operations. When recycling waters (especially when mixed together) there are a number of concerns that need to be assessed, including scale precipitation (barite, calcite, iron sulfides, etc.), the ability to effectively treat the water for re-use, reservoir compatibility, and the achievement of acceptable friction properties for pumping operations. All of these considerations require a series of laboratory tests and other engineering analyses to ensure the best chance for success.

This paper outlines the steps required to successfully implement a water management program from both the economic and technical perspectives, using a case study from the Marcellus and Utica Shales. It describes the reservoir analysis; the Friction Flow Loop experiments using synthesized versus actual produced waters; the modeling and subsequent Dynamic Tube Block (scale loop) experiments to optimize scale inhibition; and ultimately, the field results, which tie together the work required for optimal outcomes. Based on all of the testing and analysis done in the case study, it was determined that the use of fresh and Marcellus produced waters, when mixed with Utica water or individually, present no incompatibilities with the Utica formation, and with proper lab testing, a successful chemical suite can be achieved for fracturing treatments with these waters.
Subduction-Zone Fluids
Authors: Manning Craig E. , Frezzotti Maria Luce
Published: February 2021

Fluids are essential to the physical and chemical processes in subduction zones. Two types of subduction-zone fluids can be distinguished. First, shallow fluids, which are relatively dilute and water rich and that have properties that vary between subduction zones depending on the local thermal regime. Second, deep fluids, which possess higher proportions of dissolved silicate, salts and non-polar gases relative to water content, and have properties that are broadly similar in most subduction systems, regardless of the local thermal structure. We review key physical and chemical properties of fluids in two key subduction-zone contexts—along the slab top and beneath the volcanic front—to illustrate the distinct properties of shallow and deep subduction-zone fluids.
Silver nanoparticles in disinfection
Authors: PEJSAK ZYGMUNT , TARASIUK KAZIMIERZ
Published: February 2021

Infectious diseases, now especially African swine fever (ASF), represent a major challenge for swine production in Central and Eastern Europe. In the absence of other methods, biosecurity plays the most important role in control of infectious diseases in swine population. Among biosecurity methods, disinfection proved to be one of the most effective and economically viable tools. Nanotechnology is an important, rapidly evolving multidisciplinary field. Achievements of nanotechnology are being used in many areas of science, such as biology, chemistry, physics, etc. Nanoproducts have been widely adopted for practical use in everyday life. For example, silver nanoparticles (AgNPs), thanks to their intrinsic antipathogenic properties and their ability to inactivate bacteria, viruses and fungi either photothermally or by photo catalysis (induced reactive oxygen generation), can offer methods alternative to classical disinfection protocols. It has been proved, both under laboratory conditions and in field veterinary practice, that AgNPs are very useful and efficient as a disinfectant of farm facilities.
Carbon Dioxide Level in Neonatal Incubator: A Comparative Study of Two Baby Air Flow Input Methods in Incubator Chamber
Authors: Vardanjans R. , Cirule L.
Published: February 2021

Preterm neonates often have to spend a long time in incubator which simulates necessary enviromental conditions to maintain patients in stable condition. Authors have found neglected problem with Carbon Dioxide (CO2) concentration in newborn inhaled gas when using “oxygen hood” into infant incubator that has not been studied very closely. Methods in this experiement were carried out as condition monitoring while changing some parameters and positions. Results have shown that CO2 level is letally high in some aspects. Situation is alarming as CO2 level in incubator is not limited by current regulation, as IEC60601-2-19: 2009 +A1:2016. Currently the Incubator manufacturers declare that CO2 maximal concentration should be periodically checked by users, which are hospitals. Some commercially available incubators have the maximum allowed CO2 level 8000 ppm, which is much higher than recommended 2000 ppm CO2 level in indoor working place. There is no limitation of maximal level of CO2 using “oxygen hood”, which are specified in incubator operation manual. This paper goal is to show the correlation of CO2 level versus gas flow into oxygen hood.
Some parameterized Hermite-Hadamard and Simpson type inequalities for co-odinated convex functions
Authors: Ali Muhammad Aamir , BUDAK Hüseyin
Published: February 2021

In this paper, we first obtain an identity for twice partially
differentiable mappings involving some parameters. Moreover, by
utilizing this identity and functions whose twice partially derivatives
in absolute value are co-ordinated convex, we establish some
inequalities which generalize several inequalities, such as trapezoid,
midpoint and Simpson’s inequalities.
Evaluation of anxiety in patients who admitted to an ophthalmology outpatient clinic during COVID-19 pandemic.
Authors: Budak Elif Ateş , Karahan Mine , Han Çağla Çilem
Published: February 2021

Purpose Many studies revealed that stress, anxiety and depressive
symptoms are increased during the pandemic in both healthcare workers
and the general public. In our study, we aimed to evaluate anxiety
levels in patients who applied to an Ophthalmology outpatient clinic
during the COVID-19) pandemic. We thought that close contact requirement
in eye examination might lead to the anxiety of COVID-19. Methods This
is a cross-sectional descriptive study conducted in Dicle University
Ophthalmology department outpatient clinic. Data were collected for
COVID-19 fear and safety measurements and all the patients were applied
Hamilton Anxiety Scale (HAM-A). Results A total of 223 voluntary
participants were recruited. Of the participants, 101 were female and
122 were male. HAM-A total score mean was found 9.28 ± 8.717 and
approximately half of the patients (51.6%) had a score of higher than 6
which means clinical significance. Women and single participants had
higher anxiety levels compared with men and married/partnership
respectively. Age, educational level and fear of COVID-19 when visiting
the hospital were found to be related to HAM-A levels. 41.7% of the
patients had postponed the hospital admission because of the pandemic
and this was also significantly associated with the anxiety levels.
Conclusions This is the first study that investigates anxiety
specifically in an eye clinic specifically during the COVID-19 outbreak.
This study, apart from supporting the increased anxiety levels in the
pandemic, highlights that anxiety must have caused a problem of proper
access to health services. Key words: COVID-19, anxiety, pandemic,
ophthalmology