bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Processes and Tools for Design and Execution to Optimize Hydraulic Fracturing Treatments in Shale Reservoirs
Authors: Dusterhoft Ron , Kumar Amit , Siddiqui Shameem , Spade Geoff , Schischka Nick , Johnson Bill , Dahl Jeff , Spaid John 
Published: June 2014

Abstract
The use of horizontal drilling and hydraulic fracturing has been credited for much of the success achieved in ultra-low permeability shale reservoirs, making it economically possible to produce natural gas, natural gas liquids, and crude oil. Although thousands of wells have been drilled and completed using these technologies, there are relatively few modeling tools available to the industry designed specifically for these applications, leaving much of the optimization process to trial- and-error techniques that are costly and time-consuming.
A focused effort to develop useful software tools for industry professionals to better design and more reliably predict well performance has resulted in a new generation of hydraulic fracture and reservoir simulation tools built specifically for these complex well geometries and difficult reservoir conditions. These tools have also been designed to provide information that can enable completion engineers to make informed decisions to help ensure the desired results are achieved and well performance maximized.
The workflow is focused on designing stimulation treatments that maximize the stimulated volume of the reservoir around the wellbore and also maximizes the connected fracture area within this volume. This combination can result in increased production rates while also increasing the possible ultimate recovery that can be achieved from a given wellbore, thus having a significant impact on the economic success of a well and an entire asset.
This paper provides details on these new tools and workflows, as well as the results of early trials that have yielded impressive results, even when applied in an established shale field within the US.
Comprehensive Multiple Fracture Pressure Analysis Tests to Appraise and Develop Unconventional Organic-Rich Carbonaceous Shales in North Kuwait
Authors: Fidan Erkan , Darous Christophe , Bloushi Taha , Pradhan San P. , Singh J. R. , Dashti Qasem. M. , Al-Mutairi Mubarak D. 
Published: June 2014

Abstract
A comprehensive diagnostic data-fracturing campaign (Fracture Pressure Analysis: FPA) was undertaken by the Gas Fields Development Group (GFDG) of North Kuwait in January-March 2013. The campaign involved executing FPAs on the primary zone of interest (Organic-rich Carbonaceous Shale: OCS) as well as underlying and overlying carbonates to establish "fraccability" and in particular the hydraulic frac vertical containment aspect, which are much needed for the successful planning of an appraisal program.
This paper summarizes the resuts of those FPA tests and how the acquired data is used to calibrate the wellbore geomechanical model. This initial FPA campaign is the onset of a more comprehensive evaluation program planned for 2013 onwards. FPA sequences were executed on the OCS, underlying and overlying formations with encouraging results. The main concern was whether the OCS would yield hydraulic fracture (fracture initiation) below surface treatment pressure limitation of 13,500 psi (Maximum allowable surface pressure). The fracture initiation was successfully established in all three zones. In addition, multiple "fracture re-opening tests" were performed to evaluate the ranges of the fracture closure stresses during the leak-off. Multiple down-hole memory gauges were utilized to ensure elimination of wellbore effects on treatment pressure. KCl-laden incompressible water-based fluid system enhanced with friction reducer was utilized in all three stages to ensure minimal friction loss and damage. This formation suite has very complex mineralogical attributes as it is a mixture of clastics, carbonates and hydrocarbons, with reservoirs that can be very tight (possibly at micro-Darcy).
This campaign will lead to an optimal selection among the vertical completion options (hydro-fracturing design), and will help to successfully plan for horizontal well completions.
Enhancing Recovery in Shales Through Stimulation of Pre-Existing Fracture Networks
Authors: Urbancic Ted , Baig Adam 
Published: June 2014

Abstract
Microseismic monitoring has become an attractive option for tracking hydraulic fracture stimulations because, unlike most other monitoring techniques, it can illuminate the behavior of fractures away from treatment wells. However, in most cases, the potential for microseismics in terms of developing an overall picture of fracture interactions within the reservoir is not fully exploited. Based on the analysis of microseismicity associated with stimulations in naturally fractured shale reservoirs, we illustrate how, using advanced seismic signal analysis techniques, namely seismic moment tensor inversion (SMTI) approaches, we can stimulate a pre-existing fracture network. As well, we can identify: 1) the failure type, such as shear or tensile failure associated with rough fracture surfaces, 2) the fracture connectivity related to the number of intersecting fractures in a volume, 3) the fracture intensity based on the developed fracture lengths per volume, 4) the fluid flow pathways and enhanced fluid flow volume as related to the relative degree of open fractures, and 5) the distribution of fracture lengths (power law distribution). Based on our analysis, we identify that most failures observed are mixed-mode failures, typically shear-tensile with either crack opening or crack closure components of failure. The fractures themselves are generally related to the failure of pre-existing natural fractures rather than in the creation of new fractures. Based on the finite sampling (bandwidth limitations), fracture sizes are limited to joint lengths and follow a power law distribution. By examining the spatial and temporal behavior of opening dominated failures, maps of over-lapping zones of potential enhanced fluid flow were identified. In many ways, stress induced fractures during single stages prepared the reservoir for subsequent stages that overall enhanced the interconnectivity and complexity of fractures thereby enhancing fluid flow opportunities. We further discuss, as outlined in these case studies, how, using SMTI, the microseismic data show that the stimulation program as designed achieved its objectives. Overall, we further suggest that these defined seismic parameters can then be used to refine, validate and constrain geomechanical models used as input to reservoir models and further optimize well and stage spacing to effectively drain a reservoir and provide better defined reserve estimates.
Calibration of Well Logs with Mini-Frac Data for Estimating the Minimum Horizontal Stress in the Tight Gas Monteith Formation of the Western Canada Sedimentary Basin: A Case Study
Authors: Lopez Bruno , Yu Guang , Aguilera Roberto , Settari Antonin (Tony) 
Published: June 2014

Abstract
The determination of the minimum horizontal in-situ stress is one of the most important aspects in the characterization of geomechanical behavior of petroleum reservoirs, since a good knowledge of such stress is critical in many activities of practical importance, including design of hydraulic fracturing treatments and estimation of the distribution of minimum horizontal stresses for reservoir simulation purposes.
The main objective of the study is to calibrate well logs with available mini-frac data for estimating the minimum horizontal stress in the tight gas Monteith formation, Nikanassin Group of the Western Canada Sedimentary Basin (WCSB). For deep formations like Monteith, the minimum stress is generally horizontal. Thus, the focus of this research is the minimum horizontal stress of the Monteith formation.
First, actual values of the minimum horizontal stress at different well locations are acquired from the analysis of surface pressure data during mini-frac treatments. Next, the estimates calculated from an existing correlation and from actual mini-frac data are matched for calibration purposes. Finally, Biot's constant values are determined in order to generate a correlation applicable to the Monteith formation. Vertical Biot's constants ranging between 0.1 and 0.2 are obtained in this study. Horizontal Biot's constant is assumed to be equal to 1.0.
Three vertical wells located in the same township with available compressional and shear sonic logs and mini-frac data are selected for this work. Five additional wells in the same general area are selected to assist in the analysis. The Monteith was hydraulically fractured in isolation in these wells. This aspect is important because there are many commingled completions in the area from which selective Monteith data are not available. It is concluded that assuming a vertical Biot's constant equal to 1.0 is not appropriate for the Monteith formation in the study area. The procedure presented in this paper is robust and has the potential to help obtaining more reliable values in other tight formations around the world.
Stimulated Reservoir Volume: A Misapplied Concept?
Authors: Cipolla Craig , Wallace Jon 
Published: June 2014

Abstract
The interpretation of microseismic data was initially focused on hydraulic fracture length and height, providing an important measurement to calibrate planar fracture propagation models. However, microseismic data in the Barnett shale exhibited significantly more complex patterns compared to typical tight-gas sands. The concept of stimulated reservoir volume (SRV) was developed to provide some quantitative measure of stimulation effectiveness in the Barnett shale based on the size of the microseismic "cloud." SRV is now ubiquitous when discussing well performance and stimulation effectiveness in unconventional reservoirs. However, SRV and similar techniques provide little insight into two critical parameters: hydraulic fracture area and conductivity. Each of these can vary significantly based on geologic conditions and fracture treatment design. Hydraulic fracture area and fracture conductivity, combined with reservoir permeability, stress regime, and rock properties, control well performance, not SRV.
The concept of SRV has spawned numerous reservoir engineering models to approximate the production mechanisms associated with complex hydraulic fractures and to facilitate production modeling and well performance evaluations (e.g., rate transient analysis). However, these reservoir engineering models are often divorced from the fracture mechanics that created the fracture network, a significant limitation when evaluating completion effectiveness. Additionally, the interpretation of the microseismic data and the calculation of SRV are poorly linked to the actual hydraulic fracture geometry and distribution of fracture conductivity.
This paper presents detailed numerical reservoir simulations coupled with hydraulic fracture modeling that illustrates the limitations and potential misapplications of the SRV concept. This work shows that simplifying assumptions in many SRV-based rate transient models may lead to estimates of hydraulic fracture length and reservoir permeability that are not well suited for completion optimization. Two case histories are presented that illustrate the limitations of SRV-based well performance evaluations. The paper concludes that using microseismic images to estimate a SRV may not be sufficient for completion evaluation and optimization. However, the simple calculation of microseismic volume (MV) can provide significant insights to guide fracture and reservoir modeling endeavors.
Acid Fracture Treatment Design with Three-Dimensional Simulation
Authors: Oeth C. V. , Hill A. D. , Zhu D. 
Published: June 2014

Abstract
Acid fracture stimulation generates higher well production but requires engineering design for treatment optimization. To quantify the cost and benefit of a particular acid fracture treatment an engineer must predict the resulting fracture's conductivity distribution. Current practice is to estimate conductivity distribution utilizing two-dimensional models. Unfortunately, these models can misrepresent the amount of acid etching upon which the conductivity estimation is based.
A new modeling tool has been developed to estimate fracture conductivity and is used to evaluate different acid fracture treatment designs. The tool uses three-dimensional flow simulation to resolve acid transport in a fracture. This approach includes resolution of the three-dimensional fluid velocity throughout the fracture, fluid pressure, the acid concentration profile, and the acid-etched width. By using a fine grid in the direction of transport to the fracture surfaces, convective and diffusive transport of acid to the fracture surfaces are modeled. The acid-etched width distribution and other formation information are used to calculate the resulting conductivity distributions for different treatment designs.
The output acid-etched width and conductivity distributions for different acid fluid systems, fracture geometries, geologies, and completion designs are calculated. The industry lacks a reliable tool for acid fracture treatment design. The modeling tool presented in this paper attempts to address this problem with rigorous simulation of acid transport and etching in a fracture. The parametric study illustrates the benefits and drawbacks to this approach.
Improvements in Downhole Chemical Delivery: Development of Multifunctional Proppants
Authors: Duenckel Robert J. , Leasure Joshua G. , Palisch Terry 
Published: June 2014

Abstract
Ceramic proppants can provide the highest fracture conductivity under most conditions relative to natural frac sand and resin coated sands. However, regardless of proppant type or the state of fracture conductivity at the of the hydraulic fracturing treatment, the fracture conductivity and well performance can be impaired and jeopardized by production related events including inorganic scaling (i.e. barium sulfate, calcium carbonate, etc.) or hydrocarbon depositions ( i.e. paraffin, asphaltenes). Current solutions to these post-hydraulic fracture related production problems include liquid inhibitor additions to the frac fluid, solid inhibitor additives to the proppant slurry, post frac chemical squeezes, downhole chemical injection and periodic clean-outs, among others.
An improved chemical delivery method has been introduced which utilizes porous ceramic proppants to function both as a proppant and chemical delivery system. Standard ceramic proppants are manufactured to eliminate internal pellet porosity to the greatest degree possible as the presence of porosity can reduce pellet strength and thus negatively impact conductivity – the primary purpose for choosing a ceramic proppant in the first place. Previous uses of porous ceramic proppants for chemical delivery have in many cases sacrificed conductivity. However by tailoring the type of substrate and degree of porosity present in the proppant grain, an addition of porous proppant to standard proppant can be achieved that does not negatively impact conductivity. This porous component of the proppant pack can then be infused with a chemical – such as a scale inhibitor – to provide a multi-function proppant that provides both designed conductivity and efficient chemical delivery.
This paper will describe how pellet porosity and substrate type can be tailored to avoid negatively impacting conductivity along with the benefits of using a chemically infused ceramic proppant as a vehicle for downhole chemical delivery relative to other established chemical treatment methods. Types of chemicals that may be considered for use in this fashion include scale, paraffin and asphaltene inhibitors as well as others. The chemically infused proppants are designed to facilitate a slow release of the desired chemical in order to provide long term effective application. This type of delivery system has distinct advantages over other approaches to chemical treatment.
A New Method for Fracture Diagnostics Using Low Frequency Electromagnetic Induction
Authors: Basu Saptaswa , Sharma Mukul M. 
Published: June 2014

Abstract
Currently, microseismic monitoring is widely used for fracture diagnosis. Since the method monitors the propagation of shear failure events, it is an indirect measure of the propped fracture geometry. Our primary interest is in estimating the orientation and length of the ‘propped’ fractures (not the created fractures), since this is the primary driver for well productivity. This paper presents a new Low Frequency Electromagnetic Induction (LFEI) method which has the potential to estimate not only the propped length, height and orientation of hydraulic fractures but also the vertical distribution of proppant within the fracture.
The proposed technique involves pumping electrically conductive proppant (which is currently available) into the fracture and then using a specially built logging tool that measures the electromagnetic response of the formation. Results are presented for a proposed logging tool that consists of three sets of tri-directional transmitters and receivers at 6, 30 and 60 feet spacing respectively. The solution of Maxwell's equations shows that it is possible to use the tool to determine both the orientation and the length of the fracture by detecting the location of these particles in the formation after hydraulic fracturing. Results for extensive sensitivity analysis are presented to show the effect of different propped lengths, height and orientation of planar fractures in a shale environment. Multiple numerical simulations, using a leading-edge (FEKO) electromagnetic simulator, indicate that we can detect and map fractures up to 250 feet in length, 0.2 inches wide, and with a 45 degree of inclination with respect to the wellbore. Special cases, such as proppant banking and wells with steel casing in place, were also considered.
Re-fracturing Horizontal Shale Wells: Case History of a Woodford Shale Pilot Project
Authors: French S. , Rodgerson J. , Feik C. 
Published: June 2014

Abstract
Multi-stage horizontal well stimulation treatments have been the key completion approach driving the recent US shale revolution. This approach has transformed the industry, making it possible to economically stimulate reservoirs that were previously deemed uneconomic.
In attempting to deploy such multi-stage fracture treatments, several tools and processes have been employed during the completion phase. Most popular among these approaches, has been the ‘plug and perf’ technique, which permits multiple treatments to be performed along a horizontal wellbore. This widespread completion approach has allowed these fracturing operations to be rapidly executed, but with the short elapsed time between stages and wells, it has become increasingly challenging for the Completion Engineer to effectively close the evaluation cycle.
As many of these shale plays now mature, it is becoming increasingly apparent that the majority of the wells have not been effectively stimulated. Fracture interference and cluster efficiency being among the key concerns with the completion approach, with high efficiency rarely being achieved resulting in only partial coverage. In fulfilling the desire to complete these wells in a timely manner, it is now apparent that there likely remains a significant portion of un-stimulated pay in a typical well post completion.
In this paper we will not attempt to address the "Optimized Completion Design", but instead explore techniques that can be used to recomplete some of these wells and recapture a portion of this bypassed pay. The paper will present the planning, the execution and the results of a five well re-fracturing Pilot programme in the Woodford Shale; including a number of reservoir simulation studies. The discussion will also address the well selection process, the re-fracturing approach and the resulting improved production rates.
Gulf of Mexico Frac-Pack with a 10% Loading of an Intermediate Strength, Chemical-Infused Proppant-Sized Particle Designed to Provide Long Term Inhibition for Barium Sulfate Scale
Authors: Szymczak Stephen , Satya Gupta D. V. , Shen Dong , Steiner William , Langlinais Kevin 
Published: June 2014

Abstract
A new substrate, based on nanotechnology, that has strength greater than an intermediate strength proppant and a high surface area for chemical adsorption has been introduced and applied in deep water well in order to inhibit barium scale deposition for a prolonged period of time and/or a desired cumulative water production.
The subsea oil well in 1700 feet of water in the Gulf of Mexico was completed with a frac-pack using a total of 14,881 pounds of proppant. This includes a 10% (1,488 pounds) loading of the solid scale inhibitor product. The well was put on production following the completion. The field design calls for a sea water flood (containing sulfate). The scale inhibitor is designed to desorb into the connate water (containing barium) and to inhibit the formation of barium sulfate scale.
The solid product placement with the proppant was monitored to assure a homogeneous distribution of solid chemical particle in the proppant bed. Upon the onset of water production samples were analyzed for the presence of residual scale inhibitor. A residual indicates there is still sufficient chemical in the formation to inhibit scale. When the scale inhibitor residual falls below the minimum inhibitor concentration, and if the water still shows a scaling tendency, the operator has two choices. At that point he can initiate surface treatment through a chemical injection mandrel or perform a scale inhibitor squeeze. A squeeze onto this chemical-laden proppant substrate will last longer than a conventional squeeze that is placed onto the native formation rock.
The cost of a well intervention for a deep water sub-sea well can exceed ten million dollars. The cost for an intervention in a deep water dry tree will be less but still significant. By placing a long lasting scale inhibitor into the propped zone, the operator will realize an economic benefit far in excess of the cost of the application. By extending or possibly eliminating the need for a future intervention, the application of this technology can have a significant impact on the well economics.