bluuebunny/crossref_metadata_2025 huggingface dataset:
DFIT Analysis and Interpretation in Layered Rocks
Authors: Zheng Shuang , Manchanda Ripudaman , Wang HanYi , Sharma Mukul
Published: January 2020

Diagnostic fracture injection tests (DFITs) are often used to estimate formation properties such as closure stress, pore pressure, and matrix permeability. These estimations are typically based on analysis of pressure data assuming the closure of simple planar fractures in homogeneous reservoirs. These interpretations are incorrect when dealing with complex reservoir environments such as layered reservoirs with different properties and stresses. This paper investigates the impact of such complex environments on DFIT interpretation and presents a systematic method to analyze the data.

A 3-D implicitly integrated poroelastic fracture-reservoir-wellbore model is used to simulate DFITs. DFIT fracture propagation and well shut-in are simulated with implicitly computed fluid leak-off and fracture closure. The model is validated by simulating a DFIT for a homogeneous reservoir and the implicitly calculated surface pressure is interpreted to obtain the simulation inputs (stress, pore pressure, permeability, etc.). A multi-layer reservoir model is then built in the numerical simulation domain and a DFIT is simulated in the target layer. The properties and thickness of the layers are varied to analyze their impact on the observed DFIT signature.

We analyze the impact of layer thicknesses, layer stresses, pressure and permeability of each layer, stress contrast between the layers, fracture interaction with bedding planes and the rock roughness and hardness of each layer on the DFIT pressure signature. We show that the layer property variations can cause different but characteristic DFIT pressure responses. Fracture propagation into layers with different stresses induces multiple closure events in the observed pressure signature, which provides a quantitative representation of the fracture height growth. The emergence of these closure events in the pressure signature are found to be dependent on the hardness and modulus of the rock layers and the fluid communication between the closing parts of the fracture. The DFIT signature patterns are also found to correlate with the interaction of the fracture with bedding planes (cross/arrest/divert) and provide valuable insights into fracture containment.

In this work we present best practices for performing DFIT analysis in layered reservoirs. Results from simulated DFITs in layered reservoirs clearly show the effect of key heterogeneity parameters on DFIT responses. The results from this work can be used to more accurately determine reservoir closure stress, pore pressure, reservoir permeability, fracture compliance, fracture conductivity, and fracture containment in heterogeneous reservoirs.
The Effects of Down-Spacing in the Delaware Basin Wolfcamp Play: A Case History
Authors: Bommer Peter Anthony , Bayne Marcus
Published: January 2020

The effect of horizontal well spacing on stimulation performance and well results is of keen scientific and economic interest to the industry. The objective of this paper is to demonstrate these effects in a grouping of five horizontal Wolfcamp wells drilled in a down-spaced configuration where inter-well distances were reduced from 1320′ to 660′.

The subject project is located in Ward County, Texas, on a 640 acre lease. A stand-alone Wolfcamp A2 zone well (legacy well) was drilled on the project acreage in late 2016 followed by the drilling of four development wells directly offsetting the legacy well in mid-2018. The four development wells were spaced 660′ apart as opposed to the existing norm of 1320′. This paper presents various pressure, microseismic, tracer, and production data collected during and following the zipper stimulation of the four development wells. This rich data set yielded significant information about the drainage characteristics of the legacy well, the effect of pressure depletion on fracture geometry, the nature of fracture driven interactions (FDI) in down-spaced wells, and the inter-relationship of these factors in their effect on production results. Active well defense was performed in the legacy well and results from these defense operations is also reported.

Inter-well spacing of 660′ between wells in the same zone resulted in significantly diminished production results compared to the base case resulting in lowered projected rates of return for the well group. Depletion in the legacy well resulted in larger fracture geometries in the nearest development wells, but not in wells 990′ away. This resulted in larger stimulated volumes in the nearer wells but also diminished oil production. The inferential conclusion is that localizing stimulation energy in the near vicinity of the treated well yields improved well results. Concerning FDI, the data indicate that wells within 660′ of each other are likely to interfere with each other, while the opposite was true for wells that were 990′ apart.
Real-Time Hydraulic Fracturing Pressure Prediction with Machine Learning
Authors: Ben Yuxing , Perrotte Michael , Ezzatabadipour Mohammadmehdi , Ali Irfan , Sankaran Sathish , Harlin Clayton , Cao Dingzhou
Published: January 2020

During hydraulic fracturing jobs, engineers must monitor the wellhead pressure and adjust the pumping schedule in real time to avoid screenout, optimize the proppant and fluid amounts, and minimize cost. In this paper, we use machine learning to predict wellhead pressure in real time during hydraulic fracturing. The new algorithm can assist engineers in monitoring and optimizing the pumping schedule.

We explored several neural network models. For each hydraulic fracturing stage, we train a machine learning (ML) model with the data from the first several minutes and predict the wellhead pressure for the next several minutes; we then add the data for the next several minutes, train a second ML model and predict the pressure for the next couple of minutes; and so on. We used several performance metrics to compare different models and select the best model for deployment to the Cloud, where a real-time completions platform is developed and hosted.

We selected more than 100 hydraulic fracturing stages from several wells completed in the Delaware Basin and tested several ML methods on the historical data. The wellhead pressure can be predicted with an acceptable accuracy by a slightly nonlinear machine learning model. We tested the ML model on the Cloud, where real-time streaming data such as slurry rate and proppant concentration are gathered. The computation is fast enough that a real-time wellhead pressure can be predicted.
Sound Completion Engineering Techniques Lead to Superior Production of the Codell Sandstone In Laramie County, Wyoming
Authors: Kosters Bryan , Shaw Kevin , D'Souza Shodan , Clark Justin , Besler Monte , Barham Michael
Published: January 2020

In the era of unconventional oil and gas drilling, time constraints often fast-track projects that lack sound completion practices. A multi-year production study of the Codell Sandstone in Laramie County, Wyoming has developed better completion practices that improved production and Estimated Ultimate Recovery (EUR).

Helis Oil and Gas Co., LLC formed a team of experts to identify and execute best completion engineering practices for their horizontal Codell wells. Utilizing data from the production study and leaning on experience, the team identified seven core areas for improving Codell completions. The team (1) recommended performing fracture diagnostics, (2) investigated methods to increase Stimulated Reservoir Volume (SRV), (3) optimized the job size, (4) reviewed proper chemical additive selection, (5) included on-site real-time micromanagement of treating pressure, (6) reviewed wireline procedures, and (7) performed post-fracture treatment analysis.

The Laramie County comparative study included 247 wells completed during the 4-year time period of 2014 to 2018. Helis Oil and Gas Co., LLC completed a total of 13 wells with the enhanced workflow. Considering normalized average cumulative production per well metric, Helis wells outperformed offset wells by 58% in the first 6 months of production. Extending the time frame to the first 12 months of production, on average, the Helis wells produced 75% more oil. A total of 5 Helis wells outpaced the P10 normalized production curve within the first year of production. Examining normalized decline curves, Helis wells continued to outperform. Furthermore, 10 of the 13 Helis wells outperformed the P10 normalized decline curve after 12 months of production.

These techniques help get out of the mindset of the cookie cutter approach with assembly line frac designs. Focusing on these core principles and systematically applying engineered completion techniques to the Codell workflow has helped Helis Oil and Gas Co., LLC achieve superior production and outperform all other operators in the area.
Evaluating Limited Entry Perforating & Diverter Completion Techniques with Ultrasonic Perforation Imaging & Fiber Optic DTS Warmbacks
Authors: Murphree Chase , Kintzing Malcolm , Robinson Stephen , Sepehri Jay
Published: January 2020

The objective of this project was to evaluate extreme, limited-entry perforating and particulate diverter completion techniques with ultrasonic perforation imaging and distributed temperature sensing (DTS). The scope of this project includes multiple, Midland Basin, horizontal wells completed with varied completion designs. Ultrasonic images of the perforations were obtained prior to fracturing and post-fracturing to observe erosion patterns of each design. Fiber optic DTS warmbacks gathered temperature profiles of each wellbore after stimulation to quantify fracture initiation points (FIP) of each design.

Perforation imaging results showed that all perforation clusters were eroded. This indicates that all clusters of perforations received some amount of treatment fluid and proppant. The data collected also suggest that perforation erosion occurs quickly, and the rate of perforation erosion decreases dramatically after a critical mass of proppant is pumped through the perforations, potentially negating high perforation friction designs early in the stage. Despite all clusters showing some level of perforation erosion, fiber optic DTS warmback data only showed fracture initiation points for ∼70% of the clusters (cluster efficiency of 70%). This data suggests that multiple clusters could be receiving fluid and proppant while contributing to a single fracture network and not creating a unique, dominate fracture for each perforation cluster. Another possibility is that although some clusters were receiving treatment slurry, the amount of stimulation was not sufficient to create and sustain a major fracture.

The data gathered in this project should change conventional thought processes on a number of subjects including perforation erosion, limited-entry, diverters, proppant placement, fracture growth, and DTS interpretations.
Case History of Drainage Mapping and Effective Fracture Length in the Bakken
Authors: Cipolla Craig , Litvak Michael , Prasad R. S. , McClure Mark
Published: January 2020

Understanding effective fracture length and characterizing drainage patterns is critical for optimal development of unconventional resources. This paper documents a comprehensive field experiment in the Bakken formation, where several fracture diagnostic technologies and drainage mapping methods were used in a unique project setup to measure effective fracture length and map drainage.

Two vertical wells (V1 and V2) were drilled 1,000 ft away from a Bakken lateral (H1) with 10 years of production (Fig. 1). The two vertical wells were 200 ft apart. V2 was used for microseismic and deformation (downhole tilt) measurements, while V1 was used for pressure measurements and hydraulic fracture characterization. The project consisted of re-pressurizing the existing lateral (parent well), using microseismic monitoring to map drainage (designated MDD, Dohmen et al. 2013, 2014, 2017). A DFIT was performed in the V1 well before the MDD to measure local stress and pore pressure. Following the MDD, a small propped fracture treatment was pumped in the V1. The H1 well was then produced for 4 months and DFITs pumped in the V1 and V2 wells. This comprehensive fracture diagnostic dataset was integrated with detailed core and log measurements, hydraulic fracture modeling, and advanced reservoir simulation to characterize the hydraulic fracture performance.

The H1 MDD indicated that the major pressure depletion (drainage) was approximately 500 ft on either side of the lateral. H1 BHP showed local reservoir pressure was 1,000 psi. The initial V1 DFIT showed virgin reservoir pressure, but surprisingly, the 20 bbl DFIT injection was detected on the H1 BHP gauge. Microseismic mapping of the V1 fracture treatment (15 klbs, 600 bbl) showed a planar fracture with a half-length of 1,000 ft. The V1 fracture "hit" the H1, measured by microseismic and confirmed by a 1,650 psi increase in H1 BHP. The microseismic showed a symmetrical fracture, suggesting that the H1 re-pressurization mitigated the detrimental effects of parent well depletion that can cause severe asymmetry. Downhole tilt and microseismic showed fracture height quickly extended downward through the lower Bakken shale into the Three Forks. The V1 was not produced. However, the H1 oil rate doubled after the V1 frac hit, indicating significant stimulation. V1 DFIT #2 showed 1,800 psi depletion, while the V2 DFIT showed approximately 1,000 psi depletion, confirming that the V1 fracture is "flowing" into the H1 lateral 1,000 ft away. The reservoir simulation history match indicated low fracture conductivity, but enough to improve well productivity and drain oil over 1,000-ft from the H1 lateral.

This paper details a comprehensive fracture diagnostic dataset gathered in a unique field laboratory where a single hydraulic fracture from a vertical well is used to characterize fracture conductivity and flowing length.
The Effective Cluster Spacing Plays the Vital Role in Unconventional Reservoir Development – Permian Basin Case Studies
Authors: Xiong Hongjie
Published: January 2020

Through near 3000 horizontal producing wells on University Lands in the Permian Basin, we have performed a series of case studies to systematically investigate the most critical parameters to maximize well performance and the value of field development. In addition to summarizing multiple study results, the paper concludes and elaborates that the effective cluster spacing is the most critical parameter that we may be able to control and can influence the most in the unconventional reservoir development.

The paper first shows three observation cases of perforation cluster spacings and their corresponding well performance. To understand why the effective cluster spacing is so vital to well performance, we then illustrate the fundamental theory to understand the pressure propagation timing and depletion patterns in different reservoirs. We compare the mechanistic modeling results of pressure depletion and corresponding recovery efficiencies with different effective cluster spacings by multiple modeling approaches, including single-porosity model, and dual-porosity model, which has validated our case study results and is very insightful for us to optimize perforation cluster spacings.

We then discuss the possible reasons of often-observed well interference. With a large data sample, the paper illustrates the good correlation between well performance and completion effectiveness. The paper presents the EUR and NPV evaluation results of different field development case histories, such as between tight cluster spacing and wide cluster spacing. We will also briefly discuss the current technologies and practices to improve cluster efficiency in the completion process.

Based upon the multiple case studies, theory investigation, and rigorous modeling, we have concluded that the effective cluster spacing is the most critical factor to influence well performance and the field development value.

The workflow illustrated in the paper can be used for operators to systematically optimize their cluster spacings as well as field development plans. To maximize the value of developing unconventional reservoirs, it is vital to optimize cluster spacing and cost-effectively achieve tighter effective cluster spacing.
Diagnosing Multistage Fracture Treatments with Distributed Fiber-Optic Sensors
Authors: Pakhotina Iuliia , Sakaida Shohei , Zhu Ding , Hill A. Daniel
Published: January 2020

Distributed acoustic sensing technology is a diagnostic method that has been implemented in the oil and gas industry for flow monitoring during injection or production. One of the applications is to estimate fluid distribution during hydraulic fracturing treatment. This is an invaluable diagnostic tool for multistage fracture treatments because of the large number of parameters and high uncertainty involved in these fracture treatments. Distributed acoustic sensor (DAS) measurements are based on data extracted from a fiber optic cable installed in a wellbore. Fiber optic cable strain is sensitive to temperature and acoustic variations induced by fluid flow with different fluid properties and fracture geometries. These parameters are evaluated from the back-scattered laser pulse through the fiber using coherent Rayleigh backscattering for DAS and Raman backscattering for distributed temperature sensing (DTS). The DAS interrogation system acquires strain response to acoustic variations along the measured depth of the wellbore for all periods of time.

This study presents a method of interpretation of flow rate distribution from acoustic signals from DAS measurements. Raw acoustic measurements are transformed to energy attribute distribution for all necessary depth locations and timeframe. It allows to calculate energy for each perforation cluster location. This calculation demands proper depth interval consideration for each perforation cluster. Local minimums of time average energy attribute allow to find depth window where integrate DAS channels measurements for each time step occurs. Based on the previous experimental and computational fluid dynamic investigations, the correlation between acoustic signal and flow rate is applied to interpret the measured DAS data to flow distribution.

In this paper, the system of equations which connects acoustic energy response with clusters flow rate distribution during the injection period using these correlations is introduced. The solution of this system allows to calculate cumulative volume for each perforation cluster on each time step and in the end of fracture treatment. As additional verification of flow rate distribution, the results of DAS interpretation were compared with interpretation results of DTS. A field example is used to illustrate the interpretation procedure.

From this work, it is concluded that besides qualitative analysis, the DAS interpretation method provides a quantitative estimation of flow distribution. Based on the current assumptions, the interpretation results from DAS and DTS are comparable with satisfactory agreement. The combined DAS and DTS interpretations help to understand cluster efficiency in multistage fracture treatments.
Field-Scale Computational Fluid Dynamics CFD Modeling of Proppant Transport and Distribution Within a Horizontal Hydraulic Fracturing Stage
Authors: Almulhim Abdulraof , Kebert Brent , Miskimins Jennifer , Hunter William , Soehner Gage
Published: January 2020

Treating every perforation cluster during a hydraulic fracturing treatment is a key element to ensuring the effectiveness and overall success of the well stimulation process. With completion costs being 50% of the total well cost in shale reservoirs and the reliance on hydraulic fracturing as a key technology for development, operators are concerned with maximizing the well performance by optimizing the stimulation design. In multi-stage horizontal well treatments, equal diversion of the fracturing fluid and proppant to all perforation clusters is desired, as bias proppant distribution may cause early screen-out and/or leave some fractures unpropped.

Computational fluid dynamics (CFD) is a branch of fluid mechanics that numerically solves Navier-Stokes equations and predicts the fluid flow behavior within a specified computational domain. CFD also has the capability to model the flow of dispersed particles within a fluid through the use of a discrete phase model (DPM). Recently, CFD has been utilized by various researchers as a tool to model fracturing slurry flow within perforation clusters to predict proppant transport and distribution trends.

This work models the fluid and particle flow using CFD DPM within a single hydraulic fracturing stage to improve our understanding of the proppant transport and distribution between multi-perforation clusters. The paper presents the CFD modeling methodology and results of two main perforation designs including traditional 0° phasing, vertical perforations and modified 45° angled shot perforations. To be able to compare the modeling to actual field conditions and field diagnostics, slickwater fracturing fluid with 40/70 and 100 mesh sand at a varying proppant concentration from 1 to 2 ppg are used in the model to replicate a field-scale 15-cluster stage. The modeling outcomes are then compared and validated to actual well post-job diagnostics; proppant tracers and perforation erosion signs captured by downhole cameras. These field results help to calibrate the CFD models, which then allowed sensitivity analysis and design improvement.
Fracture Sequencing in Multi-Well Pads: Impact of Staggering and Lagging Stages in Zipper Fracturing on Well Productivity
Authors: Manchanda Ripudaman , Zheng Shuang , Sharma Mukul
Published: January 2020

Zipper fracturing is a method of sequencing frac jobs in multi-well pads that helps increase operational efficiency and reduce stimulation time for a pad. This technique involves stimulating several wells in a pad in a prescribed sequence of stages. In this work, we provide a thorough assessment of the various factors impacting the effectiveness of zipper fracturing treatments and provide a methodology for selecting an optimum sequence of fracture stages.

A fully implicit, parallelized, 3-D, pad-scale reservoir-fracturing simulator is used to simulate the dynamic propagation of multiple, non-planar fractures from multiple treatment wells while capturing the stress interference between fractures. This interference is captured both on an intra-well as well as an inter-well scale. Interaction between fractures propagating from different wells is found to be dependent on pad design, completion design, and reservoir parameters. We evaluate the effectiveness of the stimulation operation by comparing the impact of operation decisions on the created fracture geometries and simulated productivity of the propagated fractures using seamless fracturing-reservoir simulations.

The simulation results are used to understand the impact of well spacing, stage spacing, staggering of zipper-frac wells, lagging of stages during zipper fracturing, size of the frac job, stress contrast in the reservoir and rock properties. Using multi-cluster fracturing simulations and accurate proppant distribution calculations in the wellbore, we consider the impact of various operational decisions mentioned above on the distribution of proppant in the created fractures. We observe that fracture closure during shut-in of a stage impacts the created fracture geometries. This affects the proppant distribution in the fractured stages. The impact of the operational decisions on the fracture conductivity degradation during stimulation is also captured using seamless fracture-reservoir simulations. We show that the results obtained from these simulations can help design pad-scale operations to maximize the fracture-reservoir contact area or improve the productivity of the wells.

In this work, for the first time, we assess the impact of zipper fracturing on well productivity by performing coupled fracturing-reservoir simulations. The software is used to simulate fracture propagation and fracture closure during shut-in and production. The results obtained from these simulations recommend an optimized fracture sequencing, stage lag and staggering strategy to maximize the productivity of the pad.
Rapid Completion Optimization Using Particulate Oil-Soluble Tracers
Authors: Jones Marcus , LaRue Jon
Published: January 2020

Pumping multiple unique stimulation designs in a single multistage lateral combined with particulate oil-soluble tracer chemicals (OSTs) accelerates the traditional trial and error process of optimizing stimulation designs. Applying this methodology to various fracturing sand volumes provides discrete data for stimulation analysis. When compared to a large sample of wells, the data shows that OST tracer recovery may be used as a proxy to estimate oil production.

Altering fracture designs within the same wellbore with OSTs provides significant data that is useful for optimizing stimulation designs. Solid particulate OSTs differ from liquid OSTs in that the particulates remain locked in-situ in the proppant pack after the frac pressure wave has subsided. Formation pressure will not force the solid tracer back into the wellbore as sometimes occurs with liquid tracers. The unique chemistry of OSTs allows the tracing chemicals to dissolve only into produced oil, which is sampled at the surface for laboratory analysis.

Multi-stage lateral wells utilizing alternating stimulation designs with unique OSTs yield data suggesting increased proppant volumes lead to larger oil recoveries compared to lower proppant volumes. Ninety-four horizontal wells within the same bench of the Wolfcamp formation with various proppant volumes show a statistically significant correlation between proppant volumes and estimated ultimate recoveries (EURs). The OST recovery results closely match the trend of the 94 full-well completions, giving evidence that OST recoveries are a quantitative analogy for oil production over time. Increased proppant loading OST tests, beyond the range of full-well data available, show no gain in OST recovery. This suggests that adding more proppant in this specific portion of the reservoir may not add economic value to the operator.

The unique ability of OSTs to generate granular information at the individual stage level accelerates an operator's learning curve as optimizing stimulation design often requires costly investments in reservoir information. Another approach is to optimize stimulation design using empirical data if wells in a similar geological and petrophysical makeup exist. The OST alternating-stage-design methodology can be applied to other variables, providing a rapid trial-and-error process that yields significant empirical data for optimizing completion variables.
Utilizing Discrete Fracture Modeling and Microproppant to Predict and Sustain Production Improvements in Nano Darcy Rock
Authors: Montgomery Carl T. , Smith Michael B. , An Zhongfeng , Klein Hank H. , Strobel William , Myers Roger R.
Published: January 2020

Providing and sustaining fracture conductivity in secondary fracture systems created during the stimulation of very tight unconventional shale plays is critical for sustaining productivity and reducing decline rates. In this paper, a discrete fracture network model which includes proppant transport will be utilized to show the effect that an unsupported vs supported dilated fracture network has on the decline and ultimate recovery of available resources in shale. In addition, the characteristics and properties of a microproppant will be described. The physical properties of the material, the oil and water conductivity of the proppant at various fracture widths along with the resultant Fcd will be presented. Utilizing a bridging factor of 3, a comparison of the surface area propped by various proppants will be made. The proppant transport characteristics will also be described. The production benefits of utilizing very small proppants will be demonstrated utilizing production data from four different rock systems including the Barnett, Woodford, Utica, Permian Basin and Marcellus shale. Several additional operational benefits including reduced pumping pressures and far field diversion to prevent fracture hits will also be discussed. Finally, operational considerations will be described including utilizing liquid slurry's, pump wear evaluations and recommended proppant addition points will be described.
Experimental Investigation on Parameters Affecting the Coefficient of Discharge of a Perforation Hole in Hydraulic Fracturing Treatments
Authors: Loehken Joern , Yosefnejad Davood , Fricke Bernd
Published: January 2020

Hydraulic fracturing is the most popular well stimulation technique for extracting hydrocarbons from unconventional oil and natural gas reservoirs. During this process the stimulation fluid is injected into the reservoir from the wellbore with a pressure higher than the breakdown pressure of the reservoir in order to create fractures in the formation.

The pressures needed for hydraulic fracturing depend on many factors such as injection pressure and flow-rate, fluid density, fluid viscosity and the perforation hole. One of the important factors affecting the perforation pressure loss is the Coefficient of Discharge (Cd). This work looks deeper into the factors, which determine the magnitude of this value. Especially for a perforation hole, many of these factors are still not fully understood today and need further research.

As part of this study a new high pressure, high flow test vessel was built, which is compatible with our API19B Section IV test setup, in order to investigate some of the factors that could affect the Cd and subsequently the perforation pressure loss in the fracturing treatment. CFD simulations have been carried out to compare our experimental results with numerical models. In addition, we investigate the effect of the perforation hole size (area) by using different charges, the length of the fluid flow path, the hole geometry (shape), the effect of injecting high viscous fluid and finally the effect of Burr and Cement on the magnitude of the Cd magnitude for the perforated holes.

We developed a simple setup to deduce Cd values from perforations which were created in API19B Section II or Section IV test vessel. The values were measured for different pressure differentials, back-pressures and flow rates. The results show that the above-mentioned parameters directly affect the Cd value and subsequently the near wellbore pressure loss near the perforated hole. The values measured for real perforation holes differ significantly from simple drilled bores. Burrs on the inside and outside of the casing effect the magnitude as well as the length of the flow path.

Our new data sheds new light on the benefit of accurate measurements of Cd values for every shaped charge which helps to efficiently design the hydraulic fracturing stimulation treatment for oil and gas well.
Conventional and Eco-Friendly Hydraulic Fracturing Fluid Additives: A Review
Authors: Al-Hameedi Abo Taleb , Alkinani Husam H. , Dunn-Norman Shari , Trevino Hector A. , Al-Alwani Mustafa A.
Published: January 2020

The purpose of this paper is to create a starting point for research into using friendly and biodegradable waste material as supportive items for hydraulic fracturing fluids and additives. Conventional fluids and additives, although they can be effective, they pose serious threats to work personnel and public health and to the environment. Conventional fluids and additives can also be very costly. These risks and concerns should drive the oil and gas industry to pursue alternative options, safer and cheaper options, from conventional fracturing fluids and additives. Some waste materials provide this opportunity. It is apparent through many forms of research that waste materials are readily available globally making it easy and cheap to obtain. A driving force for this research was research previously done on finding alternative additives for drilling fluids. Researchers have proven that some of the waste materials, such as food waste, grass waste, palm tree waste, among many others, can and should replace or at least boost conventional drilling fluids and additives through a series of experiments and tests. Not only are these materials easier and cheaper to obtain, but they are also efficient and safer for both the environment and people. The same could be said for alternative hydraulic fracturing fluids and additives if proper research is done. The strides made in finding alternatives for drilling fluid additives have pushed the revolutionizing of the oil and gas industry, acting as a catalyst for the research into alternative hydraulic fracturing fluids and additives. In this work, a more thorough investigation into conventional fracturing fluids and their downfalls regarding price and health and environmental concerns are illustrated as well as the function of the main fracturing fluids; water fracs, linear gels, crosslinked gels, oil-based fluids, and foam/poly-emulsions. Throughout this paper, it becomes apparent that the oil and gas industry should attempt replacing or decreasing conventional fracturing fluids additives because of the negative influences they have on profit, people's health and safety, and the environment.
Pulsed Power Plasma to Enhance Near Wellbore Permeability and Improve Well Performance
Authors: Rezaei Ali , Siddiqui Fahd , Callen Nicole , Gordon Peter , House Waylon , Soliman Mohamed
Published: January 2020

Unconventional reservoirs suffer from an ultra-low permeability, causing their drainage area to be limited to tens of feet. An efficient technique that can be used in combination with conventional hydraulic fracturing to increase the drainage area is pulse power plasma. In this study, we used an experimental approach to study the effect of pulsed power plasma discharge on the permeability change around wellbore under tri-axial confining stress conditions.

We designed and used equipment, allowing for the generation of the shock wave in a true tri-axial cell to perform the analysis in this study. The equipment has a capacity for rock samples of 14 in on each edge with 1.5 in diameter well in the center. Using the equipment, the stored electrical energy in capacitors is instantaneously released into a fusible link creating a thermite reaction, which creates a shock wave in the wellbore and is transmitted to the rock afterward. The shock wave affects the permeability of samples, even in situations where the generated stress loading is below rock strength.

Several types of material, such as limestone, sandstone, and concrete are tested in this study. Samples were investigated before and after the electrohydraulic discharge to find the extent and magnitude of the induced fractures (permeability enhancement) and their relationship with the released energy. Also, the effect of repetitive low-magnitude shock waves for creating micro-cracks in rock is studied. It is observed that even under sub-critical loading conditions, micro-cracks are generated in the rock samples that might be a result of the main shockwave or reflection of the stress wave from the boundary. These fractures were less controlled by the stress orientation as compared with hydraulic fractures. However, they contributed to the permeability enhancement around the wellbore that can be up to orders in magnitude. Finally, the optimum discharge energy for the maximum permeability enhancement is suggested.

In this study, for the first time, we tested the rock under confining stresses and imaged them using computer tomography (CT) scanning. Also, change of permeability around the wellbore using pulse power plasma is a novel use of pulse fracturing technology that can effectively be mixed with hydraulic fracturing treatment in unconventional reservoirs and maximize the stimulated reservoir volume (SRV). The results of this paper can help to maximize the EUR from the reservoir.
A Data Analytics Framework for Cored Fracture Imaging and Novel Characterization Workflow - Application on Samples from Hydraulic Fracturing Test Site HFTS in the Midland Basin
Authors: Maity Debotyam , Ciezobka Jordan
Published: January 2020

In this paper, we introduce a novel fracture imaging method which uses high resolution 3D laser scanning to develop detailed surface maps of the core fracture faces. The digital maps are then used to analyze fracture surface characteristics wherein observed variations provide us with meaningful insights into the fractures. We share a mathematical approach for roughness evaluation to identify morphological properties for individual fractures within rock samples. The approach is tested on core extracted at the Hydraulic Fracturing Test Site (HFTS - 1) in the Permian Basin. We characterize the roughness variations with depth across the cored section. In addition, we compare results obtained previously from core sampling and analysis to demonstrate that proppant entrapment observed within the cored interval is strongly correlated with the changes in fracture morphology. We also use calculated roughness along with the the changing behavior of roughness radially away from the center of fracture faces to predict roughness "types" such as propagational features or textural roughness characteristics.

Based on the specific fracture characterization work shared here as well as other potential uses, our paper highlights significant advantages such scanning and digital imaging of fractures may have over traditional cataloging using photographic imaging. Furthermore, as demonstrated in this study, data sampled from these detailed maps can be used to further characterize and analyze these features in a more systematic and robust manner when compared with the more traditional geological analysis of cores.
Determination of Stimulated Reservoir Volume SRV During Fracturing: A Data-Driven Approach to Improve Field Operations
Authors: Rahman Mohammad , Sankaran Sathish , Sankaran Sathish , Molinari Diego , Ben Yuxing
Published: January 2020

The commerciality of unconventional field development depends on generating highly productive stimulated reservoir volumes (SRV) in an economical manner, but there is no reliable method to estimate SRV consistently during or immediately after fracturing operations. The SRV achieved during fracturing can be inferred through multiple techniques, including production data analysis, modeling (analytical or numerical, including various treatments of geomechanics), and/or microseismic monitoring, all of which have several limitations. Using production data, we need at least several months of well production history to establish a pseudo-boundary dominated flow regime. Additionally, the production-derived total SRV is a composite of all the stages lumped together, as it is difficult to evaluate the performance of individual fracture stages due to the reservoir heterogeneity. Furthermore, production rates are measured as a total aggregate for all the fractures, while production contributions from each stage cannot be obtained pragmatically for most wells. Full physics modeling, besides being time-consuming and requiring specialized expertise, requires proper reservoir characterization including geomechanical parameters and calibration, which are not routinely captured for most wells, and even when they are acquired, they are difficult to measure accurately. Microseismic, though informative, doesn't indicate actual SRV, and often it is only available for a small percentage of the wells. It is desirable to have a scalable method to estimate SRV evolution consistently during injection using commonly available fracture treatment data for all wells, and it should be practically applicable in a typical unconventional field.

A novel asymptotic analysis of the diffusivity equation has been proposed by other researchers like Datta-Gupta et al. (2011), Yang et al. (2015), and King et al. (2016) to estimate the production drainage volume in unconventional reservoirs based on diffusive time of flight (DTOF). We have extended this methodology to estimate injection SRV (iSRV) quickly from routinely collected fracture treatment data after each stage has been pumped. Further, we have benchmarked stage-wise stimulated reservoir volumes to other available production performance measures or aggregated stage volumes with total well production drainage volume.
Understanding the Role of Well Sequencing in Managing Reservoir Stress Response in the Permian: Implications for Child-Well Completions Using High-Resolution Microseismic Analysis
Authors: Chittenden Hannah , Cannon Dave , Jeziorski Katie , Bowman-Young Sheri , Smith-Boughner Lindsay
Published: January 2020

In this case study, three sequential well pads were designed, stimulated and monitored to evaluate 1. Treatment order of stacked wells across multiple benches, 2. Completions optimization in proximity to a parent well and 3. The efficacy of treatment sequence in proximity to parent wells. Microseismic data were evaluated in conjunction with tracer and pressure data to provide a more detailed understanding of reservoir deformation and well connectivity using statistical approaches that consider the collective behavior of seismicity. High-resolution microseismic involves analyzing spatio-temporal trends in seismicity rather than reliance on microseismic event clouds to provide more meaningful assessment of hydraulically-linked seismicity vs. stress-driven seismicity. The findings of the first two case studies were applied to the stimulation of the third well pad to demonstrate the role of well sequencing in proximity to depleted zones and the impacts of completions design in managing well communication. Here we discuss the benefit of high-resolution microseismic in assessing perceived well interference by delineating the difference between hydraulically-linked and stress-driven seismicity recorded during multi-well hydraulic fracturing programs. In applying knowledge of reservoir deformation processes to customize stimulation programs, operators have additional tools to help manage reservoir stress, limit unwanted well communication and optimize production.
Experimental Study of Proppant Transport in Complex Fractures with Horizontal Bedding Planes for Slickwater Fracturing
Authors: Chun Troy , Zhu Dawei , Zhang Zhuo , Mao Shaowen , Wu Kan
Published: January 2020

The use of hydraulic fracturing has taken off over the past decade, and the importance of efficient proppant placement in fractures has increased accordingly. Connection with weak-formation bedding planes brings about distinctive fracture propagation and development. This might hinder hydraulic fractures from extending in a vertical direction, yet they might instead propagate in a horizontal direction after the existing bedding planes. The bedding plane introduces additional hydrocarbon flow path during the recovery process. This naturally leads to proppants traveling in the horizontal section of the fractures. Optimal proppant delivery and conductivity in bedding planes directly relate with effective fracture height and well performance. This paper focuses on understanding horizontal movement and delivery of proppants and their distribution in vertical and horizontal fractures on the basis of experimental work.

The size of proppants is one of the key determining parameters when calculating uplift and settling velocity. They travel farther into the fracture because they settle slower with less gravitational effect. Fine mesh is highly recommended to effectively deliver proppant to the horizontal bedding plane. Large proppants have to rely on the critical bed height to move into the bedding plane sitting on top of the vertical fracture. A higher injection rate promoted bedding-plane proppant delivery in the inverted T-shape case because it opened up a longer and larger area for particles to settle. Excessively strong turbulent flow generated by two inlet cases prevented proppants from settling and seeping into the bedding plane. Continuous mixing and agitation disturb proppants from settling. They limited additional coverage area expansion in the bedding plane. Moreover, inlet design shows little effect in the T-shape, yet having more injection points improves proppant placement in the bedding plane. Direct injection to the bedding plane surprisingly did not affect much in the T-shape case. Overall, only a small percentage of proppant can travel into the bedding plane for both T-shape and inverted T-shape-fracture geometries.
A Fast Measurement of Asphaltene Onset Pressure
Authors: Sullivan M. , Smythe E. J. , Fukagawa S. , Harrison C. , Dumont Hadrien , Borman C.
Published: January 2020

A technique to quickly determine the asphaltene onset pressure (AOP) of a crude oil from low-volume, nonequilibrium measurements is presented. The pressure at which the optical signature indicative of asphaltene aggregation is first detected in recombined crude oils is found to decrease strongly with the rate of depressurization and can be well-described with a modified power law. This technique exploits this rate dependence and uses two separate decompressions at highly disparate depressurization rates to determine the AOP. Benchmarking with this technique was performed with recombined crude oils that were characterized with conventional pressure/volume/temperature analysis. Using this technique, measurements enabling the determination of the AOP of a live crude oil can be obtained in minutes with a nominal uncertainty of 500 psi. This is a significant reduction in time compared with the multihour process used for conventional equilibrium-based measurements. Onset-time data from these studies are consistent with conventional aggregation theories, but there is insufficient range to differentiate between reaction-limited aggregation (RLA) and diffusion-limited aggregation (DLA).
Non-compliance and its associated factors among hypertensive patients taking anti-hypertensive treatment visiting Gimbi general hospital,Western Ethiopia:cross-sectional study
Authors: Bekele Firomsa , Fekadu Ginenus , Dugassa Dinka , Bekele Kumera
Published: January 2020

The authors have withdrawn this preprint from Research Square