bluuebunny/crossref_metadata_2025_split huggingface dataset:
Production Forecasting Using Flow Back Data
Authors: Kurtoglu Basak , Salman Ahmad , Kazemi Hossein 
Published: February 2021

AbstractIn unconventional reservoirs, the well life cycle includes drilling, completion, flowback, and production. The analysis of the fracturing pressure, flowback, and production data provides an early estimate of the stimulated rock volume (SRV) and reservoir flow capacity. In this paper, we present a methodology for using the average treatment pressure and hourly flowback data to characterize reservoir connectivity as an early indicator for long-term productivity. We will also show that performing flow regime analysis during the flowback period provides a greater understanding of the initial fracture conductivity (via bilinear flow) and reservoir connectivity (via linear flow). This early time analysis also sheds light on sweet spots (or geologically favorable areas) and effectiveness of the completion practices for business decisions. In this paper, we have modified the well-known single-phase diffusivity equation to include simultaneous flow of oil, water, and gas in the reservoir. Furthermore, we used fracture treatment pressure, flowback and production data from several Eagle Ford and Bakken wells to demonstrate the value of completion and flowback data and their relation to the long-term performance of wells.
Hydraulic Percussion Drilling System with PDC Bit Increases ROP and Lowers Drilling Costs
Authors: Powell Scott W. , Hu Ertai 
Published: February 2021

Abstract
Drilling the Severnaya Truba Field in Aktobe, Kazahkstan, has proved to be a costly and time consuming challenge for operators trying to maximize profits. The formation is typically drilled with roller cone bits that take multiple runs to complete an interval. To increase effectiveness and drilling efficiency, a hydraulically powered percussion drilling system along with a fixed cutter PDC bit were added.
In place of a conventional drilling system, a new energy distribution system was introduced that would induce axial oscillations and percussion impacts while applying the same weight and torsional energy to the bit. In combination with a drilling fluid powered percussion hammer (FPPH), a fit for application polycrystalline diamond compact (PDC) bit with depth of cut (DOC) control features was used to minimize the exposure of the cutting structure and prevent breakage.
The system combines the torsional power of a conventional positive displacement motor with a high frequency axial pulse created with each rotation. The torque is transferred directly to the bit and 100% of the hydraulic flow is utilized by the bit nozzles to maintain hole cleaning and keep PDC cutters cool. The mechanical lifting and falling action creates a rapid variation in weight on bit (WOB), allowing the bit's depth of cut to fluctuate while overcoming different stresses. These variations, along with the percussion pulse created with each stroke, lead to increased rates of penetration.
This system has been used throughout the world on a variety of formations, using both PDC and roller cone insert bits. This paper will focus on an 8½ in interval drilling operation in the Severnaya Truva field, located 60 km from Zhanazhol field in Kazakhstan. The formations consisted of soft to medium siltstone, red/grey clays, sandstone, hard cemented dolomite, limestone, and very dense clay stone. This new technology proved to increase both ROP and interval drilled, saving seven days of drilling compared to offset wells.
Production Performance Analysis of Unconventional Gas Reservoirs with Different Well Trajectories and Completion Techniques
Authors: Erturk Mehmet Cihan , Sinayuc Caglar 
Published: February 2021

Abstract
The significance of unconventional gas reservoirs has been increasing for recent years owing to economic viability of their development, therefore assessment of the challenges and common pitfalls regarding those resources have been gaining importance at the same time. In this regard, the optimization of production performance of these reservoirs with the different well trajectories and completion techniques and identifying the best case scenario become more significant. That is absolutely challenging process due to the several reasons such as ultra-low permeability, desorption effect, and complex geological characteristics. However, it is possible to analyze the various parameters and observe their impact on each system with the help of advances in algorithms, computer power, and integrated software.
The objective of this work is to investigate and understand the effect of some reservoir and completion parameters on the future production performance of shale gas and coal bed methane (CBM) reservoirs. A practical model is constructed with the field and synthetic data for the analysis of gas production rate and cumulative gas production versus time in multi-layered shale gas and CBM reservoirs respectively. Changes in the thickness of various stratified layers, permeability, wellbore position, number of hydraulic fracture stage, and also production profile of each system are studied using different well trajectories. The results are obtained by running a series of reservoir simulation conducted by a commercial numerical simulator with dual porosity model for CBM and shale gas reservoirs.
Evaluation of Synthetic Acid for Wells Stimulation in Carbonate Formations
Authors: AlDahlan Mohammed N. , Obied Marwa A. , Marshad Khalid M. , Sahman Faisal M. , Yami Ibrahim S. , Alhajri Abdullah M. 
Published: February 2021

AbstractAcid treatments of carbonate formations are usually carried out using mineral acid (HCl), organic acids (formic and acetic), mixed acids (HCl-formic, HCl-acetic), or retarded acids. The major challenges when using these acids are their high corrosivity, fast reaction rate and health hazard. The improvement in corrosion inhibitors makes the use of a strong acid as high as 28 wt% HCl possible. The acid reaction rate can be controlled by increasing acid viscosity using gelling agent or emulsifying acid droplets, acid-in-diesel emulsion. While the issues of stimulation acids reaction and corrosion rates are relatively controlled, these acids health hazard rating of 3 by the National Fire Protection Association (NFPA) is a major concern. A health hazard rating of three is defined as an extreme danger where short exposure could cause serious injury.An acid replacement chemical that has no or minimum health hazard rating while still has the ability to dissolve carbonate rock would be a major forward step in stimulation technology. This paper presents the results of the study conducted on a synthetic stimulation acid (Syn-A) chemical, with health hazard rating of one and dissolving power similar to 15 wt% hydrochloric acid (HCl). An extensive experimental scheme including: thermal stability, dissolving power, acidity, compatibility, corrosion rate & inhibition and coreflooding on carbonate formation core plugs was conducted. The Syn-A was found to be thermally stable with similar dissolving power to 15 wt% HCl and lower corrosion rate. In addition, the Syn-A developed a breakthrough on core plugs with an average pore volume (PV) of 2.7 and approximately 3 folds increase in permeability.
Hydraulic Fracture Initiation and Propagation Model Provides Theoretical Ground for Hybrid-Type Fracturing Schedules in Unconventional Gas Reservoir in the Sultanate of Oman
Authors: Briner Andreas , Moiseenkov Alexey , Prioul Romain , Abbas Safdar , Nadezhdin Sergey , Gurmen Nihat 
Published: February 2021

AbstractA recent series of tight gas discoveries in the Amin formation of the greater Fahud area represents some of the most exciting exploration success of this decade in the Sultanate of Oman. The structures have been evaluated as containing very significant amounts of gas locked in a challenging deep and hot environment requiring hydraulic fracture stimulation. Since their discoveries, the two primary challenges have been difficult breakdown of the formation and limited proppant placement during stimulation attempts. The early experience in the exploration and appraisal campaigns from 2009 to 2014 has led to fracture designs with conservative proppant amounts that could limit the full potential of the field. Several geomechanical studies have been commissioned in the past to guide completion strategies in well placement, perforation, and fracture stimulation design.The objectives of this study were to model hydraulic fracture initiation and breakdown in the three Amin zones (upper, middle, and lower) to provide some theoretical understanding of the impact of the different parameters on the observed field breakdown pressures. In agreement with field observations, the model showed that lowering the viscosity of the pad has a major impact in lowering the breakdown pressures. Consequently, current best practices include formation breakdown and hydraulic fracture propagation with low-viscosity fluids followed by proppant placement with high-viscosity fluids. When applied to tight gas formations in the Sultanate of Oman, the hybrid fracturing evolves from conventional designs for the purpose of successful fracture initiation, while still placing a successful job.
Comprehensive Spectral and Thermal Characterization of Oil Shales
Authors: Guven S.. , Akin S.. , Hascakir B.. 
Published: February 2021

Abstract
The heterogeneous nature of oil shale resources associated to the depositional environments, lithology, and organic content make the reserve estimation complex and unpredictable. However, comprehensive laboratory studies on organic rich shale samples collected from different regions can increase the understanding about the organic content of oil shales, interaction of shale with organic matter and injected fluid used during enhanced oil recovery method. This study investigates the characterization of eight different Turkish and American oil shale samples with several spectral methods and a thermal analysis. The main purpose of this study is to characterize the oil shale samples to increase the understanding about the organic content and interaction of shale with organic matter.
In this study, we used Thermal Gravimetric Analysis/Differential Scanning Calorimetry (TGA/DSC) analysis to estimate organic content of each oil shale sample in air and nitrogen environments. X-Ray Diffraction (XRD) was used to define minerals in oil shale. Fourier Transform Infrared Spectroscopy (FTIR) was used to detect the mineral and kerogen in oil shale before and after the TGA/DSC analysis. Scanning Electron Microscope (SEM) was used to characterize the depositional environment of each oil shale samples. TGA/DSC results verified that oil shale samples have up to 50% of organic matter. XRD and FTIR results helped to identify the organic and inorganic compounds. Effects of minerals and ions were recognized by comparing TGA/DSC curves and FTIR spectra. It was recognized that the more carbonate ion in the oil shale the more increase in weight loss occurred. Diatoms identified from SEM results showed that depositional environments of the some oil shale samples are marine environments.
This study provides insight for the reserve estimation of the eight different oil shale samples with comprehensive spectral and thermal characterization.
Realtime Drilling Geomechanics Service, Case Study, Offshore Malaysia
Authors: Heidari Babak , Leong Sook Ting , Son Nguyen Truong , Aznor M Zafril 
Published: February 2021

Abstract
Real Time Drilling Geomechanics (RTDG) provides relevant real time information and integrated workflow to help clients in reducing operational risk and nonproductive time (NPT) through drilling in marginal economical and technically challenging environments. Dulang-B field is a technical challenge due to its complex structural geological environment. All the existing wells failed to penetrate into deep reservoir F40 sands due to wellbore instabilities issues. Overpressure in F-sands remains always the main concern and challenge which led to unsafe drilling environment and significant nonproductive time in the field. Avoiding drilling surprises means more than being prepared for problems when they occur; it means averting them in the first place. Appropriate safe mud weight to drill each formation, must be defined to overcome different overpressure zones and identify the best position for casing seat of each hole section of the well. With the knowledge acquired through pore pressure and fracture gradient modeling, well behavior could be foretold with enough advance notice to allow drilling team to calmly make technically sound operational decisions that lead to optimal drilling performance.
This study presents the challenges and the main results of the collaborative drilling approach via RTDG (Real Time Drilling Geomechanics) operation in well DL-B28 ST2. This study focuses on the overpressure and narrow safe mud weight window as well as level of uncertainty over prognosis formation tops which has to be managed by integrating LWD seismicVISION* and RTDG which had clear impacts on decision making process. The real time measurement approach by utilizing actual well data provided the best solution to accurately constrain pre-drill pore pressure and fracture gradient model.
Identification of Well Completion and Hydraulic Fracturing Performance Factors of Initial Development Wells within a Tight Oil Project in West China
Authors: Zhang Jing , Jiangwen Xu , Jiang Hong , Judd Tobias , Liu Yuan , Liu Hai , Palacio Juan Carlos 
Published: February 2021

Abstract
The early development of a systematic approach to well completion practices centralized around multistage hydraulic fracturing treatments is often the critical component to sustainable reservoir exploitation and development. Unfortunately, the exploitation of either exploratory or underdeveloped resources often has a number of issues that include the understanding of geological heterogeneity with different results observed within close proximity and the need to optimize completion techniques to offset the potential rapid decline in well productivity. For these cases, well completion and stimulation practices are of utmost importance with the optimization and evaluation of such designs to include and account for the integration of all reservoir and geomechanical parameters.
Recent vertical well results from initial exploratory wells combined with single-well horizontal pilot wells has accelerated the development plans for the Jimusaer field located in the Junggar basin of western China. This field covers a surface area of 300,000 acres with the targeted reservoir being located between 2,300 to 4,255 m true vertical depth (TVD). The application of horizontal wells from multiwell pads with each well consisting of up to 23 hydraulic fracturing treatments was meant to exploit large volumes of hydrocarbon reserves that were previously thought unattainable. Operationally, the first four wells consisted of 62 hydraulic fracturing stages and were executed within a 28-day period.
The project included the application of an integrated workflow including reservoir characterization along the length of the horizontal well lateral, deployment of novel multistage openhole completion techniques with dissolvable isolation technology, factory fracturing approach with all stages being monitored by microseismic monitoring, and application of chemical tracers on selected stages to identify zonal contribution during flowback and cleanup operations.
This paper describes how the acquisition of crucial reservoir and fracturing data combined with operational performance can identify areas for improvement of future completions while strengthening existing ones.
Refracturing on Horizontal Wells in the Eagle Ford Shale in South Texas - One Operator's Perspective
Authors: Diakhate Mamadou , Gazawi Ayman , Barree Bob , Cossio Manuel , Tinnin Beau , McDonald Beth , Barzola Gervasio 
Published: February 2021

Abstract
This paper outlines a refrac pilot testing program conducted in the Eagle Ford Shale.
As wells in the Eagle Ford accumulate production over time and the pressure around the horizontal wellbore declines, it is important to also consider communication due to offset fracture stimulation. Refracturing trials in older fields, such as the Barnett Shale have yielded a positive enhancement of well performance (Siebrits et al., 2000). This paper evaluates the concept of diverting fluid and proppant along horizontal wells in the Eagle Ford, while considering any communication with older producing wells during refracturing operations.
Pumping data acquired during the refracturing is used to explain some of these concepts. Modeling of induced fracture geometry, considering the effect of current pore pressures, is conducted with a fully three-dimensional hydraulic fracture numerical simulator. The pressure of the subject zone may affect the containment and rate of growth of the new fractures, as well as the re-orientation of the existing fractures.
Refracturing an old horizontal well with 5,000 ft lateral length and more than 800 existing perforation holes in the casing is very challenging and requires a careful integration of reservoir knowledge, completions skills and experience. The technical team at Pioneer Natural Resources has developed an integrated workflow to design and execute a refracturing job for an Eagle Ford well. The work flow includes: 1) identification of the lower pressure areas along the lateral using surveillance data from the well, such as microseismic, tracer logs, and production data. 2) identifying which wells within the drilling schedule are offsetting older wells that have high cumulative production, and 3) designing a single fracturing job with several sub-stages separated by diverting agents. Each sub-stage is intended to target specific areas along the lateral, which were previously identified as low pressure zones. Volumes and pump schedules will be specific for each candidate and are based on but not limited to proximity to an offset well, lateral length, and existence of geological structures such as faults and fractures in the area. The results from this pilot testing program such as the radioactive tracers and the fracture gradient changes before and after refrac will be evaluated upon completion of the field execution.
Re-Fracturing in Eagle Ford and Bakken to Increase Reserves and Generate Incremental NPV - Field Study
Authors: Oruganti YagnaDeepika , Mittal Rohit , McBurney Cameron J. , Rodriguez Alberto 
Published: February 2021

Abstract
Due to the tight nature of the matrix in shale plays, the drainage area does not extend far into the reservoir and is defined by the shape and size of the hydraulic fractures. As a consequence of this, wells typically exhibit steep decline rates and one of the prevalent ways to arrest the decline of a field is to drill and complete more wells. However, re-fracturing is slowly gaining a foothold in the industry, and our study has shown tremendous re-frac potential in the Bakken and Eagle Ford. In this study, we analyzed horizontal wells from the Bakken and Eagle Ford to identify existing re-fractured wells and estimated incremental recovery, followed by an economic analysis, to show re-fracturing as a viable alternative to drilling new wells.
Production and completions data was retrieved from public sources for all horizontal wells in the Bakken and the Eagle Ford formations, and a proprietary algorithm was applied to identify wells with a production signature that is consistent with a recompletion event. These wells were individually screened and confirmed as being re-fractured or not. Production metrics were defined to understand the performance of the wells before and after re-fracturing. Cross plots were made between these parameters to understand trends between the ratios of production decline rates and b-factors before and after re-fracturing, taking into account the time of re-completion. Decline curves were fit to the production of these wells to estimate the incremental estimated ultimate recovery (EUR) upon re-fracturing, and a net present value (NPV) analysis was done to determine commercial viability.
A majority of the identified potentially re-fractured wells had positive incremental NPV based on the EUR increase, which was 53% and 69%, on an average, for the Eagle Ford and Bakken respectively. From the existing re-fractured wells that were analyzed, it was found that there was no discernible correlation between the time an operator produces a well before being refractured and the various performance metrics that were analyzed. Also, good decline curve fits were found without changing the b-factors post-refrac and secant decline rates were typically lower after re-fracturing.
The results show the potential of re-completing wells and increasing reserves without drilling new wells based on actual field examples, showing an alternative field development strategy to the current practice of replacing older wells with newly drilled ones. Also, if re-fracturing is to be implemented on a larger scale, wells must be completed so as to make subsequent recompletions much easier, thereby encouraging use of novel casing and diverting agent technologies. Positive economics shows the huge potential of cost savings with re-stimulation and makes a ‘second wave’ of Eagle Ford/Bakken production possible.
Water-Induced Fracture Conductivity Damage in Shale Formations
Authors: Zhang Junjing , Zhu D. , Hill A. D. 
Published: February 2021

Abstract
Shale fracture conductivity can be reduced significantly due to shale-water interactions. Factors that may influence shale fracture conductivity include shale mineralogy, proppant embedment, shale fines migration, proppant fines migration, brine concentration, longer term rock creep, and residual water in the fracture. The study of excessive proppant embedment has been reported in our previous work (Zhang et al. 2014a). This paper presents the studies of the rest of these factors.
Laboratory experiments were run to understand each of these factors. To study the effect of rock mineralogy, recovered fracture conductivities after water damage for the Barnett Shale, the Eagle Ford Shale, and Berea Sandstone were measured. During conductivity measurements, water flow directions were switched to study the effect of shale fines migration. The size of shale fines was measured by microscopic imaging techniques, and scanning electron microscopic observations are also presented. Proppant fines migration was examined by placing two colors of sand on each half of the fracture surface and a microscope was used to identify the migrated crushed sands of one color mixed in the other color sand. Fresh water and 2% KCl were injected to study the effect of brine concentration. After water injection, the proppant pack was either fully dried or kept wet to investigate the damage by residual water.
Results showed that clay content determines the fracture conductivity damage by water. Fines generated from the shale fracture due to fracture face spalling, slope instability, and clay dispersion can migrate inside the fracture and are responsible for approximately 20% of the conductivity reduction. There is no evidence of crushed proppant particle migration in this study. Longer term rock creep accounts for a 20% reduction of the fracture conductivity. Fresh water does not further damage the fracture conductivity when initial conductivities are above 65 md-ft. Removal of the residual water from the fracture by evaporation helps recover the fracture conductivity to a small extent.
A theoretical model of propped fracture conductivity was extended to include the effects of water damage on fracture conductivity. An empirical correlation for the damage effects in the Barnett shale was implemented in this model.