bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Insights into Shale Fracturing Treatment Design
Authors: Gomaa Ahmed M. , Qu Qi , Nelson Scott , Maharidge Russell 
Published: June 2014

Abstract
Shale has certain characteristic features that make them difficult to evaluate in a traditional laboratory setting. The unique characteristics of shale formations include low permeability, existence of micro fractures, and sensitivity to contacting fluids. Advances in the testing of shale has remained relatively stagnant, which has led to the fact that many current shale fracturing practices and technologies are mainly determined by fracture model simulations, and experiences drawn from the stimulation of conventional formations. Therefore, the objective of this study is to develop an experimental setup to measure the hydraulic breakdown pressure associated with the development of fractures in shale cores, and to use this setup to study the effect of different parameters on the breakdown pressure, fracture shape development, fracture direction, from various fluid types and characteristics, injection rates, shale bedding directions, acid injection, and other variables in different systems.
Shale cores from a Mancos formation outcrop were evaluated in this study. Based on the experimental results, breakdown pressures in shale cores have a strong exponential relationship to fluid viscosity, where increasing fluid viscosity increases the breakdown pressure. Increasing the injection rate will reduce the pressure needed to breakdown the shale formation. Fracture complexity will increase by reducing the viscosity of the fluid. A shale core drilled in the parallel bedding direction was fractured at a lower pressure with a faster propagation compared to a shale core drilled in the perpendicular bedding direction. Additionally, a relationship between closure stress and breakdown pressure has been experimentally established and verified with existing mathematical models. Closure stress increases the breakdown pressure by a factor of 2.8.
Unconventional Well Completion Generates Significant Production Increase in Lateral Wells in Chicontepec Formation
Authors: Gutierrez Guillermo , Medina Eber , Perazzo Gerardo , Sierra Jose , Henriquez Carolina , Salguero Javier 
Published: June 2014

Abstract
Unconventional reservoirs, such as the Chicontepec basin in Mexico, require the stimulation of large volumes of reservoir rock to improve production results. A second horizontal well was completed successfully using multistage fracturing with an unconventional method in the basin. This well will be referred here as Coyotes 2H. Five fracturing stages were performed over the 900 m of lateral, each one using three spaced clusters of hydrajetted perforations. The first two stages were monitored using downhole microseismic monitoring. A 40% increase in production was achieved compared to the first lateral well completed in this field, which will be referred to as Coyotes 1H.
As the design changed from the first horizontal well, the second lateral used three times the number of perforation clusters, but the same number of fluid entry points (perforations) compared to the first completed lateral well. Five fracturing stages were pumped at 60 bbl/min placing a total of 3.2 million lbm of sand white and using 26,000 bbl of fluid; these volumes of proppant and fluid were similar to the first horizontal well. The treatment fluid was designed to improve the coverage of the reservoir using hybrid fluids consisting of linear and crosslinked gel to achieve a better stimulated reservoir volume (SRV). The first lateral was completed using crosslinked gel as the primary fracturing fluid.
Microseismic downhole monitoring allowed measuring the fracture geometry and verifying that the objectives were achieved. The main objectives were to determine if the fracturing treatments would generate upward fracture height growth into the Z-100 formation and compare the SRV measurement of Coyotes 2H to the results of the previously mapped Coyotes 1H lateral. The objectives were achieved during the treatment, and the production results were favorable because of the improvements in the completion process.
Mathematical Model for Stimulation of CBM Reservoirs During Graded Proppant Injection
Authors: Keshavarz A.. , Khanna A.. , Hughes T.. , Boniciolli M.. , Cooper A.. , Bedrikovetsky P.. 
Published: June 2014

Abstract
A modelling-based prediction of well productivity enhancement for recently developed technology for stimulation of natural fracture systems in CBM reservoirs is presented. The proposed technology can also be used for productivity enhancement of gas wells in other unconventional reservoirs, i.e., shales and tight gas reservoirs. Injection of proppant particles with increasing size and decreasing concentration results in deep percolation of proppant into the natural fracture system, expansion of the stimulated zone and increase of well productivity index. A modified mathematical model for well indices during graded particle injection, accounting for stress changes in coal beds, is developed. The model is based on analytical solution for quasi 1D problem with coupling of axisymmetric fluid flow and geomechanics. The results of previous computational fluid dynamic studies have been used to determine hydraulic resistance due to proppant placement in the fractured system. Explicit analytical equations were derived for stress, pressure and permeability distributions, as well as for the well index during injection and production. Results of previous computational fluid dynamics studies were used to determine the hydraulic resistance resulting from proppant plugging in the fractured system. By applying the effect of proppant concentration and fracture deformation, a critical stimulation radius is introduced beyond which proppant placement decreases coal permeability and well productivity index. This model has been applied for a real field case, and the effect of injection pressure on well productivity index and stimulation radius is presented. The results show significant increase in productivity index due to graded proppant injection in CBM reservoirs.
The Application of Well Test Deconvolution to Wireline Formation Tester Pressure Buildup and Falloff Data to Improve Coalbed Methane Reservoir Characterization
Authors: Osman Magdy Samir , Thwaites Schlumberger, N. 
Published: June 2014

Abstract
Coalbed methane (CBM) reservoirs are a growing source of relatively clean energy in many parts of the world. CBM reservoirs are fundamentally different from traditional hydrocarbon reservoirs. Gas is adsorbed on the surface of the coal cleats and not stored in pores. Still, estimation of the permeability of the coal cleats is important in judging the potential producibility of a given coal seam.
Traditionally, CBM reservoirs are surface tested using injection or production techniques to access reservoir permeability (Clarkson and Bustin 2011). Recently, pressure buildup and falloff tests using the straddle packer module of a wireline formation tester have been used in CBM reservoirs to assess reservoir permeability successfully. However, low permeability, limited station time, or both have, in some cases, reduced the quality of the interpretation results.
Deconvolution techniques have been available for some time; however, few practical examples are available in the literature. The use of deconvolution will generally allow extracting more of the same data. The derivative response uncertainty is normally due to errors in estimating the reservoir pressure and the flow rate. Generally, wireline formation testers provide reliable measurements of the reservoir pressure and flow rate.
We applied deconvolution to pressure buildup and falloff for the first time on data acquired in a CBM environment with a straddle packer. The use of deconvolution has improved the permeability estimation from the different tests. We were also able to identify the limitations of the technique and the uncertainties in the analysis results.
Integrated Assessment of Pilot Performance of Surface to In-Seam Wells to De-Risk and Quantify Subsurface Uncertainty for a Coalbed Methane Project: An Example from the Bowen Basin in Australia
Authors: Zhao Chaobin , Xia Zhaohui , Zheng Kening , Duan Lijiang , Liu Lingli , Zhang Ming , Yang Yong , Lau Hon Chung , Sharma Vikram , Liu Xinying 
Published: June 2014

AbstractThis paper presents a detailed case study of using surface to in-seam wells to develop a major coalbed methane (CBM) field in the Bowen Basin of Australia. This study was novel in that special emphasis was given to quantification of subsurface property uncertainty and modeling of dynamic uncertainty. The result was the generation of recovery factor versus depth correlations which can be used to calculate the estimated ultimate recoverable.In this work, a 3D box model around three pilot wells was extracted from the regional static model. To quantify key subsurface uncertainties such as permeability, both the Percentile and Confidence Interval Methods were used. Trends of laboratory-measured parameters like gas content, ash, Langmuir volume, permeability were established. Reservoir properties without measurements such as cleat porosity, desorption time and relative permeability were estimated based on rules-of-thumb, basin-wide analogue or educated guesses. A reservoir simulation model was built and production data from pilot wells were manually history matched. Parametric analysis was conducted to determine key parameters that significantly affect model history matching and forecasting results. Given the complexities of the coal reservoir and the non-uniqueness of the history match, Experimental Design was used to generate a population of simulation models that sampled the uncertainty range of key reservoir properties. This ensemble was reduced to include only those that matched the pilot wells’ production. With different combinations of reservoir properties thus obtained, recovery factor versus depth correlations were generated.This study is a good example of early resource assessment critical to the field development planning of a major CBM field. It presents a systematic method to handle uneven distribution of often sparse subsurface data over a large geographic area which often confounds the CBM industry. Furthermore, this method may be extended to assess other well architectures like vertical, slant, horizontal, multi-branch, multi-lateral and hydraulically fractured vertical and horizontal wells.
Unlocking the Resource Potential of the Bowland Basin, NW England
Authors: Clarke Huw , Turner Peter , Bustin R. Marc 
Published: June 2014

Abstract
The Bowland Basin of NW England is a key part of the Pennine Carboniferous Petroleum System which is estimated by the British Geological Survey to hold over 1300 TCF of total original gas in place (TOGIP) of shale gas resource. The basin is a Lower Carboniferous (Dinantian) extensional basin which underwent at least two major phases of rifting and intrabasinal tectonics. The basin was inverted in late Carboniferous times and subsequent burial continued until mid or late Cretaceous time. The gas-bearing shale section is extremly thick (&gt;6000 ft) intensly naturally fractured and relatively complex structurally. Ongoing geoscience studies are focussed on addressing the the intrabasinal sedimentary architecture of the Bowland Basin, structural configuration, reservoir properties and the current stress regime. The Preese Hall-1 shale gas discovery well provides an opportunity to assess the shale gas characteritics of the Bowland Basin and its resource potential. Based on extensive core and log data the shale gas resource is estimated to be approximately 1 TCF per square mile (29 BCM per square kilometre). The gas is methane rich with little carbon dioxide and the less thermally mature parts of the succession includes significant wet gases. The gas density (gas per unit volume) in the Bowland Basin compares favourably with producing shales in North America, however, the gas saturated succession is significantly thicker.
In this preliminary contribution we describe some of the basic properties of the basin including the stratigraphy and structure, rock properties and structural configuration along with our approach to the modelling the petroleum system and estimation of TOGIP. The gas resources of the Bowland Basin alone could make a significant contribution to UK energy supplies. Unlocking this resource potential requires understanding of the complex set of geological variables and devising a development strategy compatible with the social issues surrounding shale gas development.
An Overview of the Completion Challenges in a Tight-Gas Formation in Saudi Arabia
Authors: Leal Jairo , Duarte Jorge , Soriano Eduardo , Lopez Alfredo , Fatkhutdinov Damir 
Published: June 2014

Abstract
Tight gas refers to natural gas reservoirs that have very low porosities and permeabilities. Most of the tight-gas reservoirs presently being developed are sandstone formations, although carbonate rocks can also be tight-gas producers. The standard industry definition for a tight-gas reservoir is a rock with matrix porosity of 10% or less and permeability of 0.1 millidarcy or less, exclusive of natural fracture permeability. Unconventional gas resources, including tight sands, constitute some of the largest components of remaining natural gas resources in the Middle East and North Africa. Developing unconventional and tight-gas reservoirs will allow Saudi Arabia to better meet rising domestic energy needs.
During the past decade, conventional formations were stimulated successfully in Saudi Arabia using conventional completion techniques. However, as the development of existing fields continues into deeper formations and the exploration of new reservoirs is mainly toward unconventional reservoirs, new challenges are now faced, especially considering that lower permeabilities, higher stresses, and higher temperatures are experienced. An evaluation of the current techniques is necessarily in order to overcome the challenges in these extreme conditions.
This paper reviews the successful application of specific completion techniques and technologies being implemented in the development of tight-gas reservoirs currently being exploited in Saudi Arabia.
Microresistivity Image Driven Inversion of Nuclear Logs for the Evaluation of Unconventional Reservoirs
Authors: Whetton J. A. , Elkington P. A. 
Published: June 2014

Abstract
Density, photoelectric, neutron, and gamma ray logs are key inputs to the evaluation of unconventional resources. Each has a finite spatial resolution, and the properties of beds thinner than this cannot be measured directly but are (in principle) available from inversion if the logs’ response functions are known, and the thickness of each bed is known from an independent high-resolution source. An inversion method is described for beds with apparent dip angles less than about 60 degrees which uses pre-computed response functions from measurement-specific nuclear particle transport code models, combined with bed boundaries picked automatically from high-resolution microresistivity images rendered using a new technique developed for high dynamic range data. The method has application in thinly-bedded formations in general and has particular relevance in coal bed methane reservoirs where multiple thin high-contrast beds are common. Inversion results are known to be sensitive to uncertainty in bed thickness values, and constraining the inversion with information from high-resolution images is found to be highly advantageous in producing reliable results in beds as thin as 0.075m; this compares to the resolution of about 0.6m for standard porosity logs, and 0.2m for the high-resolution field logs. Inverted density logs show good agreement with core density values, and the integrity of inverted photoelectric, neutron porosity and gamma ray logs is judged to be good based on the similarity between field logs and logs reconstructed from inverted results, plus the high degree of agreement with properties of known marker beds. Inverted logs are also shown to provide improved differentiation between litho-types defined from combinations of logs using principal components analysis. The paper addresses an important source of uncertainty in the estimation of reservoir properties - namely finite spatial resolution - and in so doing reduces bias in volumetric calculations and associated net pay calculations.
How Much Does the Borehole Fluid Affect the Cement Impedance Measurement in Ultrasonic Scanner Tools?
Authors: Tello Lucio N. , Azuaje Dimas C. , Roberts Edwin K. 
Published: June 2014

Abstract
Ultrasonic scanner tools measure the cement acoustic impedance at higher radial and vertical resolution than standard cement bond and sector bond tools. The impedance is affected by variations of the borehole fluid contained in the well. This is not problematic for most wells as the tool is typically calibrated in the same fluid as the main logging section. Also, small variations in the well fluid between the bottom and the top of the logging section can go undetected in the computed cement impedance as these variations are continuous and not abrupt.
In the past, ultrasonic tools estimated the value of the fluid impedance by measuring the slowness and multiplying this value by the density. The fluid density is taken as a constant reading at the surface. Sometimes the slowness measurement is done during a logging down pass. An error is introduced when the fluid changes from one type to another because both slowness and density changes; however, density changes in larger percentages than slowness, causing the fluid impedance to have a substantially different value than the estimated one. This difference in fluid impedance causes the cement evaluation to be different also.
In the present paper we introduce a modified mud chamber for the ultrasonic radial scanner tool that measures the fluid impedance directly, in situ, while logging and with greater accuracy. In addition, we present an algorithm to compute the influence of changes in the cement impedance due to variations of the impedance in the fluid column. Laboratory tests are presented using static logs and logs obtained during field testing, corroborating the methodology and algorithm. Most of the time the tools give a correct reading but in instances where stratigraphic fluid columns with vastly different densities are present, if no correction is applied; it can mean the difference in detecting the presence or the absence of cement.
Impact of Formation Softening and Rock Mechanical Properties on Selection of Shale Stimulation Fluid: Laboratory Evaluation
Authors: Das Prasanta , Achalpurkar Manojkumar , Pal Omprakash 
Published: June 2014

Abstract
For low-permeability formations, such as oil- and gas-bearing shales, hydraulic fracturing stimulation is necessary to obtain commercial production. One of the key parameters for helping ensure successful stimulation and prolonged production is the proper selection of stimulation fluid. The selection and optimization of the fracturing fluid is greatly dependent on reservoir rock properties as well as formation softening attributed to fluid-formation interaction.
A slickwater treatment fluid has often been adopted in the past in tight shale plays for creating a complex fracture network for maximum production yield. Most often, the slickwater recipe is driven by formation fluid sensitivity analysis (e.g., effect of fresh water, salt, or acids on formation). While this might work for some formations, the rock mechanical properties, such as Young's modulus and Poisson's ratio, will determine the fracability and whether it is advantageous to use a slickwater, linear, or crosslinked gel. Similarly, analysis of formation softening using Brinell hardness testing and proppant embedment testing will help ensure the formation does not completely close on treatment completion and will have conductive flow channels. The formation rock, proppant, and fracturing fluid interaction can also result in diagenetic growth on proppant and formation faces, resulting in formation softening and large decrease in fracture conductivity. This paper describes test processes involving fluid sensitivity tests, formation softening, and rock mechanical tests, and compares data from a few representative shales to demonstrate the impact of choosing the proper fluid formulation for hydraulic fracturing.
This paper focusses on careful optimization of the stimulation fluid based on rock parameters to help ensure prolonged production in tight-oil and gas shale plays.
New Models for Reserve Estimation and Non-Darcy Gas Flow in Shale Gas Reservoirs
Authors: Haghshenas B.. , Clarkson C. R. , Chen S.. 
Published: June 2014

Abstract
Organic-rich shale gas reservoirs have various complexities related to the physics of gas storage and transport. Traditionally, the OGIP in shales has been calculated as the sum of the adsorbed gas and the free gas, using CBM reservoirs as an analog. However, as recently noted in the literature, the free gas volume must be corrected for presence of adsorbed gas, assuming all gas storage occurs in kerogen. Even with these corrections in place, shales are still complex reservoirs in terms of flow characteristics. The contribution of viscous, diffusive, and slip forces in nano-scale conduits cause the permeability calculated from Darcy's Law to be higher than the value for liquids.
A new model is developed to address the effect of the adsorbed gas volume on the nanopore storage capacity. The relative fraction of adsorbed gas volume is treated as a sorbed-phase saturation. The initial free gas volume is then calculated by subtracting any non-free gas saturation from the effective void volume. We have extended this concept to a gas material balance equation through which the free gas volume is dynamically adjusted during depletion. The Simplified Local Density (SLD) adsorption model is used to evaluate sorbed-phase density and volume. To address the complexity in gas flow, permeability of the reservoir model is assumed to be a function of pressure in order to determine the impact of advection, slippage and diffusion mechanisms. The permeability is calculated via a multi-mechanism flow model. Finally, we utilized the dynamically-corrected permeability in parallel with dynamically-corrected porosity to simulate the primary recovery of a shale gas reservoir.
The new models successfully describe the unique characteristics of shale reservoirs and correct the conventional methods for overestimation of reserves and underestimation of permeability. The format of the final material balance equation and flow model used here preserves the conventional reservoir engineering framework, but with some important modifications.