bluuebunny/crossref_metadata_2025_split huggingface dataset:
A New Look on Fracture Injection Test for Shale Gas: Marcellus Case
Authors: Farinas Mauricio , Fonseca Ernesto 
Published: June 2014

Abstract
Fracture injection testing has been used in the Oil & Gas industry for decades. In conventional reservoirs fracture injection testing has been a standard practice since important information related to the fracture job design is directly dependent on the outcome of the test (fluid efficiency & leak off coefficient). In this testing method, commonly known as a MiniFrac, fracturing fluid is pumped at typical treatment rates, with a total injection volume of approximately 200 bbls, and pressures are recorded during injection and after pump shut-in.
This study examines the results of a Minifrac conducted in a vertical well in the Marcellus Shale and illustrates how MiniFrac testing can play a useful role in fracture diagnostics in the Marcellus Shale and possibly in other shale formations. In the test case, a volume of 160 bbls of water was pumped at 10 bbls/min; and fracture height growth was infered using wireline temperature logs. The temperature logs showed fracture height containment and these results were validated using pressure response data generated throughout the test. Closure time was estimated to be 6 min and the onset of radial flow was determined to be 4.6 days using a combination of standard fracture diagnostics plots and the pressure derivative. Moreover, a numerical and analytical match of the test was performed and it was interesting to see how the results showed excellent agreement with the field data. Finally, a sensitivity evaluation to pump rate & job volume was performed using a calibrated analytical model, and these results showed fracture closure time is more sensitive to the type of fluid injected and less sensitive to job volume. These results are encouraging and suggest the application of MiniFrac testing in the Marcellus shale, and possibly other shale formations, may be an effective tool in hydraulic fracture diagnostics.
Innovative Use of NMR to Study the Fracture Fluid Propagation in Shale Formation
Authors: Gomaa Ahmed M. , Zhang Boyang , Chen Jinhong , Qu Qi , Nelson Scott 
Published: June 2014

Abstract
The breakdown of shale and the created fracture complexity are greatly dependent on the flow behaviors of fracture fluids just before fracture initiation. Because of the unique characteristics of shale formations—including low permeability, existence of micro-fractures, and sensitivity to contacting fluids—it is difficult to evaluate fluid flow with traditional laboratory methods. NMR technology has been explored to study the propagation of fracture fluid inside shale core before fracture initiation. All fluids were injected at pressures less than fracture pressure. Cores from three different shale formations (Eagle Ford, Marcellus and Mancos) were evaluated with the new methods. Variations such as fluid types (slickwater, acid and oil), injection pressure were evaluated.
Based on experimental results, the volume of fracture fluid that propagated inside shale cores has a strong relationship with fluid viscosity, where increasing fluid viscosity reduced this volume. NMR confirmed that slickwater or a higher-viscosity fracture fluid did not propagate inside the small shale pores (less than 0.01 μm as an average estimation) but did propagate inside larger pores and inside the existing microfractures. High-viscosity fracturing fluid was only able to fill the larger shale pores, while slickwater fracture fluid filled the large pores and connected them to increase the microfracture density. This allows the slickwater fluid to break the shale formation with lower pressure and produce more complex fractures than high viscosity fluids. Reactive fluids, such as HCl acid solution, were also studied and found to leak into the shale core by increasing the contact time, even for shale with low HCl solubility (less than 2 wt%).
Multiphysics Investigation of Diagnostic Fracture Injection Tests in Unconventional Reservoirs
Authors: Wallace J. , Kabir C. S. , Cipolla C. 
Published: June 2014

Abstract
Diagnostic fracture injection tests (DFIT) are commonly used to characterize stress and reservoir properties in unconventional reservoirs. Although simple in concept, interpreting DFIT results can be difficult because several factors can cause results to deviate from ideal DFIT behavior. Some examples of nonideal DFIT behavior include steep pressure declines after shut-in, absence of pseudolinear and pseudoradial flow, and excessive storage indications. Such deviations from ideal DFIT behavior challenge our ability to estimate formation properties reliably. Potential drivers of nonideal behavior include heterogeneous rock properties, complex rock/fluid interaction, thermal effects, phase entry, and natural fractures.
The objective of this study is to investigate how these factors can impact DFIT results and interpretations. A comprehensive approach was taken using a combination of pressure transient analysis, frac modeling, analytical leakoff modeling, and detailed numerical simulation of DFIT behavior. The application was for a horizontal well, completed in a shale gas reservoir, which included an actual field DFIT. Detailed modeling included full wellbore transients and storage, hydraulic behavior through induced fractures, as well as complex interactions between rock, fluids, and natural fractures. It was determined that the actual DFIT showed indications of a complex network created by the pump-in. Closure pressure estimates were found to be reliable, between the simulation cases and DFIT analysis. However, a consistency check on initial reservoir pressure had to be used to obtain reasonable estimates compared to the simulation input. Finally, estimates of reservoir conductivity were highly uncertain compared to the actual simulation inputs. Furthermore, the actual DFIT estimates of reservoir pressure and conductivity were found to be overoptimistic. Estimated ultimate recovery using DFIT-based estimates of reservoir quality was shown to be more than twice the estimated ulterimate recovery using reservoir quality estimates made with integrated core, log, and a pressure build-up test.
Evaluation of Multi-Fractured Horizontal Well Performance: Babbage Field Case Study
Authors: Al-Shamma Basil , Nicole Helene , Nurafza Peyman R. , Feng Wei Cher 
Published: June 2014

Abstract
This paper presents the analyses of well tests and production logging carried out on three multi-fractured horizontal wells in the Babbage tight gas field, UK Southern North Sea. The actual performance observed in these wells was compared to the forecasts made based on open-hole well data and the data gathered during hydraulic fracturing operations. Some of the drawbacks in analysing well test data are discussed along with the uncertainties in modelling hydraulic fractures.
Horizontal wells with multiple hydraulic fractures are used to increase productivity and recovery in tight reservoirs. Understanding and predicting fracture performance is essential to the field commerciality considering the associated high development costs, especially in the North Sea.
The results of this study indicate that based on several pressure transient analyses, the clean-up time can be up to several months, which was observed in the form of gradual skin reduction over time. The PLT data also confirmed that there is cross flow during the shut in periods, usually flowing from the outer fractures into the inner fractures. This was believed to have an impact on the interpretation of the build-ups. Moreover it was shown that during build-up tests of more than 500 hours, linear flow was the dominant flow regime and therefore the final radial flow stabilization had not yet been reached.
There are many studies in the literature on the design, operations, characterization and numerical modelling of similar multifractured horizontal wells. However there are not many publications presenting real field data and the performance of these wells. This paper covers the well performance data in addition to the design, modelling and operations of the multi-fractured horizontal wells.
Performance of Mixed Proppant Sizes
Authors: Schmidt Darren , Rankin P.E. Russell , Williams Brandon , Palisch Terry , Kullman John 
Published: June 2014

Abstract
Many well stimulation designs in the Bakken Petroleum system of the Williston Basin include hybrid treatments in which multiple fluid types and proppant types are incorporated into the pumping schedule. The industry at the present time is generally focused on cost competitiveness and efficiency. Given the changing trend, a convergence of well stimulation techniques might be expected, however stimulation design and strategies among operators have diverged (figure 1) relative to fluid choices, proppant, and pump rates [Robart et al 2013].
This paper presents an investigation that was conducted to ascertain the potential effect of the mixed proppant sizes relative to fracture conductivity. It is common in hybrid completion designs to mix various sizes of proppant based on stimulation design assumptions and criteria. It is expected that a high concentration of the least conductive proppant is likely to dominate the overall fracture conductivity, but to what degree and to what extent was the question. Also, proppant size distribution is likely to vary throughout the fracture. Depending on the treatment fluids, viscosity, and expected settling rates, proppant may be segregated by tail-in, evenly blended, or blended with dominant concentrations of one particular size.
These potential scenarios were simulated in conductivity cell experiments to gain an understanding from laboratory results. The results include a number of interesting conclusions regarding the selection of tail-in proppants and the performance relative to smaller sizes of sand and light weight ceramic.
Achieving a more Efficient Frac Network for Horizontal Development of the Bone Spring Sandstone
Authors: Carrasco Arturo , DeGeare Joe , Hunter John 
Published: June 2014

Abstract
As development of shales and other tight formations has evolved, it has become clear that the key to optimum reservoir drainage is systematic well placement and an efficient fracture network that delivers maximum connectivity to the reservoir. That typically means the greatest number of wells and stages per well as is practical for a given acreage, without risking communication either between stages or between wells.
The most efficient fracture network, however, requires consistent stage spacing and uniform fracture volume, neither of which has been achievable using plug-and-perforate (PnP), the most common multistage completion technology. The limitations of PnP are well known and documented. Because the technique relies on stimulating multiple perforation clusters simultaneously, and because breakdown pressures vary widely across any lateral stage section, there is no control over which clusters actually fracture. Studies using radioactive tracers and production logs have revealed that a third or more of all clusters are not stimulated at all, while others receive varying amounts of treatment. That leaves only a few clusters to account for almost all of the proppant placed, indicating uncontrolled fracture volume as well as unpredictable placement.
When multiple adjacent and parallel wellbores are completed using PnP, the effects of the random fracture pattern are multiplied, with large areas of the formation unreached by the stimulation. One operator developing the Permian Bone Springs sandstone estimated that as much as 60% of producible reserves were stranded as a result of incomplete reservoir stimulation using PnP.
This paper compares those PnP completions with a subsequent completion using full-drift, cemented casing sleeves and a coiled-tubing-deployed frac-isolation assembly to achieve exact fracture location and uniform fracture volumes, regardless of varying formation breakdown pressures. This well was on the same lease property and was drilled in the same manner as those completed with PnP. The operator typically runs 44 evenly spaced full-drift casing sleeves in the completion string instead of 48 perforation clusters in 12 stages.
Throughout the stimulation operations, the operator was able to confirm the volume of proppant placed at every stage. This paper describes how the comparison wells were drilled and completed and presents production data that indicates a much more efficient fracture network across the entire lateral using the cemented casing sleeves. The paper also compares the operating advantages and disadvantages of the two completion methods.
Quantifying Proppant Transport in Thin Fluids - Theory and Experiments
Authors: Mack Mark , Sun Juan , Khadilkar Chandra 
Published: June 2014

Abstract
In conventional fracturing fluids, proppant transport is governed by settling, described by Stokes Law. In thin fluids, saltation and reptation (creep) may dominate proppant transport. Past slot tests have shown that a proppant bank forms in the fracture and that proppant pumped later may overshoot previously-pumped proppant. If this occurred in full-scale hydraulic fractures, it could negate the benefits of pumping tail-in stages of more conductive proppant.
Proppant banks can also migrate in a manner similar to wind-blown sand dunes. Although some qualitative results have been derived from past slot tests, there is very limited quantitative data on proppant transport via saltation and reptation. This paper outlines the theory behind these two transport mechanisms and identifies the key parameters governing them. The relative importance of a high coefficient of restitution and low friction coefficient are demonstrated.
The methodology and results of experiments to measure the material properties governing saltation and reptation are presented for both conventional and advanced ceramic proppants and compared with those for sand. Advanced ceramic proppant has both a high coefficient of restitution and a low friction coefficient. Although sand has a higher coefficient of restitution than conventional ceramic proppant, it transports poorly due to the high friction associated with a rough, irregular surface.
Both qualitative and quantitative testing has been performed in two large-scale slots. Qualitative testing has shown the development of dunes and demonstrated the impact of friction on dune shape. Results of tests pumping larger (30/40) proppant after smaller (50/60) show that larger proppant can fill the entrance (near-wellbore) area as opposed to passing over the smaller proppant, and flow through a slot representing a complex network has shown how proppant can "turn the corner" from a primary fracture to build a dune in a secondary fracture. Finally, quantitative testing has validated the theory and experimental measurements related to the initiation of proppant transport from a static bank.
Some criteria to select the optimum proppant for slickwater fracturing are provided.
Spatial and Statistical Analysis of Hydraulic Fracturing Activities in US Shale Plays and the Effectiveness of the FracFocus Chemical Disclosure System
Authors: Arthur J. D. , Layne M. A. , Hochheiser H. W. , Arthur R. 
Published: June 2014

Abstract
The FracFocus chemical disclosure registry provides public disclosure of hydraulic fracturing chemical additives used in more than 55,000 wells by over 600 companies in the United States. The large number of well sites that have been entered into the registry present a rich population of hydraulic fracturing jobs over a wide geographic area and spanning a period of almost three years. As FracFocus evolved, the authors conducted an internal project to compile the disclosures into a database format more suited to analysis. This has entailed considerable resources to capture the PDFs available, assess the quality of the data in FracFocus, detect and correct data errors and inconsistencies, and convert PDF submittals to a database format. The resulting database can be used to analyze a number of research questions about hydraulic fracturing and related environmental concerns and public disclosure issues.
This paper will demonstrate the effectiveness of the FracFocus database in investigating a variety of questions concerning hydraulic fracturing, including: water use trends across plays, among plays, among companies, and over time; chemical makeup of fracturing jobs, again within and between plays, and among companies; geographic distributions of disclosures (where are submissions being made?); company distributions of disclosures (who is making them?); how the volume of fluids and the number and type of fracture fluid additives vary by company, by region and play, and even within plays. The analysis of the data from FracFocus can help bring a scientific, data-driven approach to addressing many of the concerns expressed by the public, non-profit organizations, and regulatory agencies regarding hydraulic fracturing.
Cement Sheath Integrity during Hydraulic Fracturing: An Integrated Modeling Approach
Authors: Wang W. , Dahi Taleghani A. 
Published: June 2014

Abstract
Recent arguments about the possibility of underground water pollution in particular regions have raised significant concerns regarding wellbore integrity during hydraulic fracturing in shallow formations. In this paper, we take a look at the containment of annulus cracks that might develop during hydraulic fracturing treatments. Wellbore integrity is highly dependent on the integrity of the bonding between the cement and the formation as well as the bonding between casing and cement. Cement heterogeneity resulted from unsmooth borehole surfaces, complex geological conditions, mud cakes, and cement contamination. Excessive fluid pressure during hydraulic fracturing could provide the driving force not only for initiation and propagation of fractures in longitudinal and transverse directions, but also in cases of low confining pressure, it may lead to fracture propagation around the casing, i.e. annulus cracks. A coupled three-dimensional poroelastic model with embedded cohesive zones is used to simulate different fracture propagation scenarios that may occur in vertical and horizontal wells during hydraulic fracturing stimulations. The cohesive layer theory is utilized to model initiation and propagation of transverse, longitudinal and delamination fractures. Using the numerical analysis provided in this paper, few hydraulic fracturing cases were simulated by taking the advantage of the treatment pressure data and petrophysical logs, and the results were compared with the post-treatment radioactive tracer logs available for these wells.
Development of the Wolfbone Formation Using Open Hole Multistage Vertical Completion Technology
Authors: Lohoefer Darrell , Keener Brett , Snyder DJ , Ezeldin Saiff 
Published: June 2014

Abstract
The Permian Basin is one of the top five resource plays in the United States and consists of a number of stacked pay zones. Two of these formations, the Wolfcamp shale and Bone Spring (Wolfbone), together deliver a pay zone thickness of 1,000 to 1,500 ft. They are made up of several different layers of organic rich shales intermingled with sandstone and siltstone. Horizontal completions in the shales are just beginning and have yet to be proven; however, operators are successfully exploiting the reserves through vertical wells.
While a mature exploration area, the completion of the thick shale intervals is a new target formation. To date, two vertical completion methods have been utilized to gain access to hydrocarbons: open hole multistage systems (OHMS) and the conventional cemented liner, "plug and perf" (CLPP) method. This paper compares 30-, 60-, and 90-day production results from 12 vertical wells in Reeves County, Texas completed with OHMS systems and 44 offset wells completed with the CLPP method. The system details, fracture methods used, as well as the cost and operational differences are discussed.
By comparing these two methods, this paper highlights OHMS as a long-term solution for operators completing vertical wells in stacked pay. The production, operation and cost comparisons of the two completion methods will provide theoretical and practical arguments to assist in designing a completion. The results of this study contribute to the technical conversation of how to economically produce a vertical well.
Reducing Proppant Flowback From Fractures: Factors Affecting the Maximum Flowback Rate
Authors: Shor Roman J. , Sharma Mukul M. 
Published: June 2014

Abstract
Proppant flowback under confining pressures is not well understood and difficult to reproduce in a laboratory setting. Improper management of proppant flowback leads to flow restrictions near the well bore, poor fracture conductivity and costly production equipment damage. A simple, scalable model is developed using a discrete element method (DEM) particle simulator, to simulate representative cubic volumes consisting of fracture openings, fracture walls and the confining formation. The effects of fracture width, confining stress, fluid flow velocity and proppant cohesion are studied for a variety of conditions. Fracture width is found to be dependent on confining stress and fluid flow velocity while proppant production is also dependent on cohesion. Three regimes are observed, with complete fracture evacuation occurring at high flow rates and low confining stresses, fully packed fractures occurring at high confining stresses and open but mostly evacuated fractures occurring inbetween. From these observations, a recommended flowback rate can be estimated for a given set of conditions. A slow and controlled well flowback is recommended to improve proppant pack stability. The rate ramp-up time is dependent on the leak-off coefficient.