bluuebunny/crossref_metadata_2025_split huggingface dataset:
The Impact of Multiphase Flow on Well Testing Models in Gas Hydrate Reservoirs without Crossflow
Authors: Kome M.. , Amro M.. 
Published: June 2014

AbstractGas hydrates will dissociate to gas and water at pressures below the equilibrium pressure or temperatures above the equilibrium temperature. Moreover, some hydrate reservoirs have considerable amounts of mobile gas and water coexisting with the hydrates in the formation. This implies, fluid diffusivity in such reservoirs is predominantly multiphase and hence addressing multiphase flow in such reservoirs becomes very vital.Conventionally, most well testing models address diffusivity in porous media by assuming a single/dominant flowing phase or addressing the fluid phases separately. If a huge discrepancy exists between the fluid saturations, the fluid with the highest saturation could denote the dominant flowing phase, depending on the fraction flow model, and the correction with the multiphase model becomes trivial, as also seen with most conventional gas reservoirs with low water saturation. However, if the saturations of the different phases do not vastly differ from one another, multiphase well testing models give a more accurate prediction of reservoir behavior. The definition of the multiphase dimensionless time becomes very essential in predicting the diffusivity of the fluids and for well test designs.The multiphase flow models developed here are based on mass balance and volumetric material balance approaches. The total mobility is derived for both the mass balance and volumetric material balance models, further related to fraction flow models. The total mobility model developed by Perrine, used by most reservoir engineering calculations is not addressed in detail for this work, as this does not fulfill mass conservation considered in this paper. Due to the non-linearity of the diffusivity equation, the multiphase diffusivity model addressed here includes pseudo-pressure and pseudo-time integrals. The solutions to the diffusivity equations for multiphase flow are given for both approaches. The differences between both models and their limitations are addressed and highlighted with illustrative examples.
Sweetspotting of the First Appraisal Campaign of Unconventional Resource Play in Kuwait
Authors: Narhari Srinivasa Rao , Al-Ashwak Samar , Kidambi Vijaya Kumar , Al-Ajmi Neema Hussain , Neog Nilotpaul , Rao Jonna Dayakar , Makki Musaed Yaseen , Narayan Acharya Mihira , Erkan Fidan , Dashti Qasem , Darous Christophe , Chakravorty Sandeep , Miller Stephen 
Published: June 2014

Abstract
Organic rich Kerogen layer of Lower Kimmeridgian to Upper Oxfordian age, deposited throughout Kuwait, is a TOC rich layer with varying TOC content between 2 to 20 wt% (in the vertical section) and having an average TOC of about 8 wt%. The depth of occurrence of this layer favorably places this zone to be having potential in rich gas condensate resource in the northern part of Kuwait. This layer occurs at a depth of 14000–16000 ft with a reservoir temperature of 270°–275°F, pressure of 11000 psi and average thickness of over 50ft. This is one of the main source rocks for majority of the oil and gas fields of Kuwait. This Kerogen section is penetrated through a number of vertical wells, as part of development of deeper reservoirs in this area, which offers an excellent opportunity to evaluate this section through core and open-hole log data. Because of the strong acoustic contrast with the overlying and underlying layers, this reservoir section is a very strong mappable seismic reflector.
As part of appraising the potential of this layer, as a resource play, a comprehensive success criteria has been worked out for location selection. An integration of all available geo-scientific data such as geochemical, 3D seismic attributes, petrophysical analysis, borehole image interpretations, geo-mechanical, core and mud logs has been carried out. The above data integration/analysis was combined with the success criteria, leading to selection of sweet-spots for planning the first dedicated horizontal well targeted on this layer.
This paper presents the success criteria worked out and the integration of data for high grading the locale – sweet-spots, for the first set of horizontal wells for appraising this deep HP-HT unconventional play of Kuwait.
Drainage Estimation and Proppant Placement Evaluation from Microseismic Data
Authors: Neuhaus Carl W. , Ellison Mary , Telker Cherie , Blair Keith 
Published: June 2014

Abstract
In this case study we outline how microseismic analysis can be used to optimize treatment design and determine the portion of the stimulated rock volume that should be productive. To begin, microseismic data was acquired with a permanently installed shallow buried array of geophones during the hydraulic fracturing of 17 wells in the Marcellus Shale. The processed results were used to conduct a multi-disciplinary study integrating geology, geomechanics, reservoir and completion engineering, and ultimately, production data. A stress inversion from focal mechanisms was performed, and correlations were made between hydrocarbon production and microseismic results. That work, in conjunction with the variability in the stimulation approach, was used to optimize the treatment design on an individual wellbore and on a field development scale. Treatment design analysis indicated optimum wellbore spacing, stage spacing and length as well as evaluated the vertical coverage of the treatment within the Marcellus. Incorporating information from source mechanisms, an event magnitude calibrated discrete fracture network (DFN) was modeled taking into account the seismic energy of the events, rock properties, the injected fluid volume and efficiency. Evaluating the placement of proppant inside the DFN enables distinction between the part of the stimulated rock volume (SRV) that contributes to production in the long term, and the part of the reservoir that was affected by the treatment but may not be hydraulically connected over a longer period of time. Finally, the permeability of the stimulated fracture system was calculated from the microseismic results. This allows for the evaluation of the drainage volume and estimation of production.
World's First Through-Tubing ESP Swap on Electric Line in Highly Deviated Wellbores
Authors: Kuck M.. , Albright J.. , Blount C.. 
Published: June 2014

Abstract
Electric wireline and tractor equipment were chosen to perform through-tubing electric submersible pump change-outs in a remote location with limited access and equipment availability. Electric wireline was available on location where other rigless options such as coiled tubing could not be mobilized. This paper records the retrieval of through-tubing-conveyed electric submersible pumps (TTC ESPs) from three wells and their replacement in two of these wells using a highly adaptable tool string. The application of an existing tool implemented in a novel manner provided benefits to the operator and has potential applications for other operators maintaining through-tubing-conveyed ESPs in deviated wells. The pump assemblies were removed through tubing while the permanently installed equipment, such as seal, motor and cable, remained in situ. All wells contained three individual assemblies to be retrieved including a tubing stop, tubing packoff with check valve and knock-out pressure relief valve, and the pump assembly. The assemblies were re-installed in two wells and the wells placed back in production. The method described herein confirms electric wireline and tractor equipment as a viable alternative for rigless replacement of through-tubing electric submersible pumps.
The Bowland Shale in the Roosecote Borehole of the Lancaster Fells sub-Basin, Craven Basin, UK: a Potential UK Shale gas Play?
Authors: Hough Edward , Vane Christopher H , Smith Nigel J , Moss-Hayes Vicky L 
Published: June 2014

Abstract
A re-evaluation of the Roosecote Borehole, located in the northern part of the Craven Basin (northern England), places the Bowland Shale in a modern geological context and allows an improved understanding of basin evolution and shale hydrocarbon prospectivity. In northern England during the Early Carboniferous, rapidly subsiding sub-basins developed between local highs in the Craven Basin. Subsequently, during the thermal relaxation phase, a period of regional subsidence allowed thick accumulations, locally in excess of 500 m, of hemi-pelagic mudstone to be deposited as a transgressive systems tract.
The Roosecote Borehole is a stratotype section for the Bowland Shale Formation, located close to the northern basin- to- shelf margin of the Craven Basin. The upper part of the Mississippian (Lower Carboniferous) Bowland Shale Formation is the principal potential shale gas play in the British Isles. The Bowland Shale and other argillaceous units of the Craven Group are rich in organic matter, have a similar depositional style to coeval units in the USA including the world-class Barnett Shale of the Fort Worth Basin, Texas, USA. Throughout England, Wales and Ireland it is currently being investigated by several exploration companies, with at least 4 dedicated shale exploration wells now drilled.
Rock evaluation indicates the TOC at between 1.73 – 3.72 %. Many samples indicate a mixture of type III and IV kerogens; there was no evidence for type I or II kerogens found. Thermal maturity for the sequence is within the oil window, with results indicating liquid oil and wet and dry gas have been generated. However, an estimate of the organic matter transformation ratio of 0.36 (36% kerogen conversion to hydrocarbons being possible) compares poorly to the Barnett Shale. Consequently we conclude that the Bowland Shale within the Roosecote Borehole has some, but possibly lower, potential as a shale oil play.
Numerous Technological Improvements Slash Drilling Times in the Horn River Basin
Authors: Zafar Hammad , Ji Yiming 
Published: June 2014

Abstract
Drilling Performance has improved multifold in the Horn River Basin since the start of activity about four years ago. In its early days a typical well would take about 40 days to drill from spud to cementing the production casing. A range of improvements have happened over the course of last four years which have reduced the drilling time by a factor of 3 despite the wells getting more complex.
A number of different technologies have been applied in order to bring these improvements. Some of the examples are pad rig moving system, bigger drill pipe, rotary steerables, managed pressure drilling, high temperature motor elastomers along with time tested project management practices of performance monitoring and improvement by comparison with yardsticks established to challenge the status quo.
One such measure of performance is meters per day average achieved from spud to rig release. Some of the recent wells which were drilled to around 5000m accomplished 438 m/day which is an industry record in the Horn River Basin. This was not just a onetime feat. The same performance was repeated on the next two wells.
Drilling for Gas in Western Canada is challenged by the price of gas in the current economic environment. Cost cutting by performance improvement provides the means of meeting the challenges posed by this environment. In comparison to the early wells the recent performance offers a cost reduction of 40Million dollars over the course of a 20 well pad, which is significant in determining the net present value of the asset.
Logging Solutions for Completion Optimization in Unconventional Resource Plays
Authors: Wigger Eric , Viswanathan Anup , Fisher Kevin , Slocombe Robin , Kaufman Peter , Chadwick Casey 
Published: June 2014

Abstract
Successful United States shale plays are often used as a template for the drilling and completion strategies for newly emerging shale plays around the world. However, studies of production logs in the Barnett Shale, the Marcellus Shale, and the Eagle Ford Shale have shown that a significant percentage of perforations clusters are not producing quantifiable amounts of fluid or gas (Miller, 2011). Case studies designed to address this have shown that addressing the heterogeneity experienced near the wellbore (Wutherich, 2012) in combination with more focus on landing and staying in the best quality reservoir rock (Baihly, 2010) lead to more productive wells with a higher degree of perforation performance.
Many operators face the challenge of incorporating a completion optimization workflow into their completions that is both technically and cost effective. The desired completion system is one that incorporates as much information as needed for successful completion while being operationally unobtrusive. Refined techniques used to convey dipole sonic tools in cased laterals have been supplemented by a new generation of easily deployed tools capable of making density, neutron, resistivity, and sonic measurements in open hole. This gives operators a wide array of options that can fit into a completion optimization program.
This paper reviews the concept of optimized plug and perforation style completions as compared to the more frequently used approach of geometrically spacing stages and perforations. Reservoir quality and completion quality variables were used to design engineered completions in a multi-well study of Eagle Ford shale wells. The study used a cost effective work flow that is repeatable and portable in order to increase the effectiveness of hydraulic fracture treatments. The workflow is shown to improve overall production and well economics by increasing perforation efficiency.
Production Data Analysis of Multi-Fractured Horizontal Wells Producing from Tight Oil Reservoirs – Bounded Stimulated Reservoir Volume
Authors: Qanbari F.. , Clarkson C. R. 
Published: June 2014

Abstract
Multi-fractured horizontal wells (MFHWs) are the most widely used technology for producing tight oil and gas reservoirs. Production data from a MFHW may exhibit multiple linear flow periods including linear flow within the fracture, linear flow in the stimulated reservoir volume (SRV), and linear flow in the unstimulated region of the reservoir. This study focuses on an SRV containing infinite-conductivity hydraulic fractures and no fluid flow contribution from the unstimulated region. The existing analytical models for these flow periods have been developed based on the linearized form of the flow equation. However, these models introduce considerable errors in permeability estimation and production forecasts for tight oil reservoirs if they do not account for stress-sensitivity.
In previous work by the authors, the stress-sensitivity of permeability was incorporated into rate transient analysis (RTA) of tight oil reservoirs during transient flow period for wells containing a single hydraulic fracture. In this paper, the effects of stress-dependent formation permeability on the production data of MFHWs are studied. A new model is used to correct the conventional RTA techniques for these effects to improve permeability estimation and oil production forecasting.
This study shows that the conventional methods that do not account for stress sensitivity give less accurate results for MFHWs producing under a high pressure drawdown. The results show that the new method reduces the error of the conventional techniques significantly and provides a reliable strategy for RTA of MFHWs.
This study fulfills two important requirements of the tools for RTA of MFHWs; simplicity and accuracy. The strategy is to keep the conventional analysis routine unchanged, with a correction factor applied to account for the effects of the stress-sensitivity of permeability. The value of the correction factor is that it shows how far the conventional analytical methods are from the exact solutions. Further, the correction factor is used to remove the considerable error in conventional analyses.
Microseismic Waveforms and Velocity Heterogeneity: Towards Full-Waveform Location Algorithm
Authors: Angus D.. , Aljaafari A.. , Usher P.. , Verdon J.. 
Published: June 2014

Abstract
Seismic forward modeling is an integral component of microseismic location algorithms, yet there is generally no one correct approach, but rather a range of acceptable approaches that can be used. Since microseismic signals are band limited, the length scale of heterogeneities can significantly influence the seismic wavefronts and waveforms. This can be especially important when subsurface heterogeneity is strong and/or vary on scales lengths equivalent of less than the dominant source wavelength. In this paper, we show that ray-based approaches are not ubiquitously suitable for all microseismic applications and hence we argue that for advanced imaging techniques in unconventional reservoir settings, ray-based algorithms may not be suitably accurate. Here we focus on exploring the feasibility of using one-way wave equations as forward propagators for full waveform event location techniques. One-way wave equations are capable of modeling the evolution of important and observable wave phenomena and could represent efficient full waveform modeling tools. As a feasibility study, we focus on the acoustic wave equation to explore efficiencies and compare traveltime and amplitude errors. However, the results have implications for one-way wave equations for elastic and anisotropic media.
Integrated Well Construction Approach for Exploratory Shale Gas Horizontals
Authors: Yadav Anurag , Qureshi Ahmad Shakeel , Khan Safdar 
Published: June 2014

Abstract
Horizontal wells with multi-stage fracturing are typically drilled in shale gas plays for them to become economically feasible to produce gas. Drilling long laterals in shale ushers wellbore stability challenges especially in build section due to hole packoff, tight hole, stuck pipe or lost circulation. These challenges result in considerable amount of nonproductive time (NPT) which needs to be minimized or effectively controlled for the play to be economically exploitable. In this paper, the authors present a multi-disciplinary integrated workflow to optimize well construction. Practical use and verification of this workflow was demonstrated by field examples where well-construction time was optimized by more than 50% on the first batch of horizontal wells drilled.
Direct and Inverse Methods for Determining Gas Flow Properties of Shale
Authors: Lorinczi Piroska , Burns Alan D. , Lesnic Daniel , Fisher Quentin J. , Crook Anthony J. , Grattoni Carlos , Rybalcenko Konstantin 
Published: June 2014

AbstractGas flow in shale is a poorly understood and potentially complex phenomenon. It is currently being investigated using a variety of techniques including the analysis of transient experiments conducted on full core and crushed shale using a range of gases. A range of gas flow mechanisms may operate including continuum flow, slippage, transitional flow and Knudsen diffusion. These processes, as well as gas sorption, need to be taken into account when interpreting experimental data and extrapolating the results to the subsurface. Several models have been published that attempt to account for these different processes. Unfortunately, these have a large number of unknown parameters and few studies have assessed the extent to which transient experiments may be used to invert for the key unknowns or the errors that are associated. Here we present a methodology in which various inversion techniques are applied to assess the viability of deriving key unknowns which control gas flow in shale from transient experiments with a range of noise. A finite volume method is developed based on the model of Civan (2010, 2011a,2011b) to mathematically model the transient gas flow in shale. The model is applicable to non-linear diffusion problems, in which the permeability and fluid density both depend on the scalar variable, pressure. The governing equation incorporates the Knudsen number, allowing different flow mechanisms to be addressed, as well as the gas adsorption isotherm. The method is validated for unsteady-state problems for which analytical or numerical solutions are available. The method is then applied for solving a pressure-pulse decay test. An inverse numerical formulation is generated, using a minimisation iterative algorithm, to estimate different number of unknown parameters. Both numerically simulated noisy and experimental data are input into the formulation of the inverse problem. Error analysis is undertaken to investigate the accuracy of results. A good agreement between inverted and exact parameter values is obtained for several parameters. However, it was found that the strong correlation between intrinsic permeability and tortuosity meant that it was not possible to accurately invert simultaneously for these two parameters. The workflow presented here can be readily applied to other gas flow models to assess the extent to which they can be applied to invert experimental data.
Assessing Mechanical and Petrographic Properties of Fine-Grained Formations From Samples Collected in Deep Oil Wells
Authors: Descamps F.. , Tshibangu J.-P.. -P. , da Silva N.. , Regnard S.. 
Published: June 2014

Abstract
Gas shales are fine grained fissile detrital sedimentary rocks. But shale is often used as a catch-all term including different rocks with a non-negligible clay minerals content which leads to typical physical-chemical characteristics.
Several properties are generally assessed for shale gas plays (TOC, porosity…). However, regarding the access to the reservoir, drilling into the formations implies a good knowledge of their mechanical and petrographic properties. As classical cores are quite difficult to collect from deep wells, unconventional techniques using small samples are useful (Tshibangu et al. 1999). When dealing with hydraulic fracturing, the formation brittleness is to be assessed. Several estimators exist among which we propose the so named plasticity index determined from punching tests.
In the framework of a collaboration of more than fifteen years between the university and the drill bits manufacturer, samples coming from all over the World and associated with difficult drilling conditions have been collected and processed in the laboratory. This work involved thin section characterization and mechanical tests like FPMs abrasiveness, Shore hardness and punching tests. Recently, a database was then built in order to analyze the cumulated information (Descamps et al. 2013).
In the context of gas shales, this database includes various fine grained rocks like shales, claystones, fine grained sandstones (i.e. grain or crystal size below 125 microns). In this paper, two main axes are developed. First, we describe typical properties of fine grained rocks, especially when they are associated to difficult drilling environments. Then, we look to how those properties can be linked together. Particular interest will be taken on abrasiveness regarding the selection of drilling bits and on brittleness assessment in relation to hydraulic fracturing.