bluuebunny/crossref_metadata_2025_split huggingface dataset:
New Toe Sleeve Enables True Casing-Pressure Test in an Eagle Ford Shale Well: A Case Study
Authors: Wellhoefer Ben , Canning Sean , Alkek Travis , Haydell Garner , Smith Molly Wharton 
Published: November 2015

Abstract
The Eagle Ford Shale in the southern part of Texas is a carbonate-rich, oil-producing, organic shale. Typically, wells are drilled horizontally through the target section of the Eagle Ford shale formation. A long string production casing is then run and cemented in place. A plug and perforate completion helps enable hydraulic fracturing of multiple target intervals along the lateral section of the wellbore. Before fracturing the wellbore, pressure testing of the casing string to the maximum fracturing pressure has become an industry best practice. Then, a flow path is created at the toe of the wellbore using tubing-conveyed perforating (TCP) guns run into the wellbore on coiled tubing (CT).
With the constant drive to improve efficiency and lower completion costs, pressure-activated toe sleeves (PATS) have rapidly replaced the TCP CT run to create the initial fluid flow path. The PATS is run as part of the completion casing and cemented in place. Internal casing pressure is then applied to open the PATS and create the flow path. However, to accomplish a casing pressure test, the first generation PATS design must have the activation pressure set higher than the testing pressure. The casing test pressure must then be exceeded to open the PATS which is not ideal operationally for a variety of reasons.
This paper reviews a case study where a new, second generation PATS was used in an Eagle Ford shale well to allow a true casing pressure test and provide the initial flow path. The paper discusses the subject well, design, and operation of second generation PATS technology, and presents the results of the application. The positive economic impacts are also reviewed. The paper draws conclusions based on the results from the subject well, operation of the new PATS tool, and the economic impact experienced.
Preparing for the Tight Gas Steeplechase, Talking to Canadians about Deep, Tight Gas Sand (TGS) Developments
Authors: Pearson Bob 
Published: November 2015

Abstract
In recent years, a number of Basin-Centred, Tight Gas Sands and Shale Gas Exploration Wells have been tested in Australia. Since monetization of the resulting Contingent Resources involves embarking on a multi-year, multi-billion dollar mega-project, most operating companies use a formalized Stage Gate Process to critically review the maturation of the business opportunity.
To obtain adequate resources and time to undertake Appraisal Drilling and Field Development Option Assessments, the project must pass through a Stage Gate-1 Review of the Exploration results and scoping-quality economic screening of the potential development concept. Concept generation often relies on ideas obtained from literature reviews and brainstorming, as well as data gathering trips to somewhat analogous operations.
This paper summarizes observations from a somewhat disappointing data gathering initiative undertaken in 3Q2015 in Calgary to talk with knowledgeable Canadians about learnings from their Deep Tight Gas Sand Developments.
These interviews reconfirmed that many of the field development planning (FDP) issues discussed in the literature and at technical conferences over the last 25 years remain in-play:
Significant resources and time should be allocated to the Appraisal TGS plays. Many existing projects initially suffered from inadequate access to properly preserved and representative core materials and/or rotary sidewall cores. A broad ranging assessment of development alternatives and feasibility studies is recommended in Stage 2, before committing to FEED. There are multiple drivers for the use of large well pads with either integrated facilities or proximal facility hubs. This also facilitates fuel substitution and the re-use of fuel gas, frac fluid handling and power lines for other services later in the field's life. Pilot studies and phased developments are desirable to address a wide range of reservoir uncertainties, completion options and artificial lift methods. However, it may be possible to defer some pilots that address Tactical Issues into Stage-5 to increase hydrocarbon capture. Some operators are now revisiting ideas that were popular more than 25 years ago, including the use of non-aqueous frac fluids and/or stable foams. The FDP, pad and completion designs should anticipate both re-fracturing and infill drilling requirements. Much greater attention is now being paid to fracture effectiveness, rather than simply operational effectiveness and CAPEX reduction.
Numerical Investigations on the Impact of Fracture Characteristics on Elastic Anisotropy in Coal Seam Gas Reservoirs
Authors: Gao Jinfang , Gross Lutz , Tyson Steve 
Published: November 2015

Abstract
Coal seams are embedded into other sedimentary structures, such as sands, clays and shales. In coal seam gas reservoir engineering, structures such as layering, fractures, cleat orientations, porosity and fluids within the cleats have an important effect on production. The interpretation of 3D seismic surveys in terms of these fractures characteristics is of great interest.
Weak anisotropy is commonly described using Thomsen-style parameters. From seismic survey data, values for Thomsen-style parameters are determined, usually through non-hyperbolic normal moveout (NMO) and azimuth gathers. The interpretation of the parameters in terms of fracture characteristics is based on restrictive assumptions; sparse, non-interacting, disk-shaped fractures are commonly assumed in cases where fracture geometry is not required. This paper investigates the effect of 3D fracture geometry in coal seams on the effective 3D anisotropic elasticity parameters using a numerical approach. We show some first results to verify existing, commonly used elastic models for fractured media, derived under restrictive assumption and then test their validity for more realistic scenarios; fracture distributions and densities, and material-filled cleats. Our study will help to provide a more reliable interpretation of Thomsen-style parameters obtained from seismic survey data.
The impact of cleats, and other small-scale structures, on the elastic properties of coal is investigated using the discrete element method (DEM). The method is capable of simulating complex fracture distributions, surface roughness and orientations on different spatial scales. Firstly, DEM is calibrated by performing uni-axial compression testing and shearing testing on a virtual coal sample, to determine values for macroscopic model parameters for intact coal. Then, cleats with different fracture densities and occupying materials are added. From these tests, we are able to validate commonly-used elasticity models for fractured media (e.g., Linear-slip models and Hudson's model), which is of first order in fracture density.
Hydrodynamic Modelling of Hydraulic Fracturing Fluid Injection in North Perth Basin Shale Gas Targets
Authors: Palat Sankar , Torbatynia Mina , Kanadikirik Kerem , Varma Sunil 
Published: November 2015

Abstract
Recent discussions on potential Australian shale gas developments have raised public concerns regarding groundwater protection. This paper presents the results of modelling the movement of the hydraulic fracturing (HF) fluid after injection in north Perth Basin shale targets (Carynginia Formation). The model is also used to predict the migration of HF fluid along an imaginary adjacent fault. Similar studies are rare, both in terms of the technique applied and the geographical area covered.
A 3D model of a part of the North Perth Basin was constructed extending 100 km (East-West) by 10 km (North-South) by 5 km (in depth) with local grid refinement in the target zone to represent the fractured zone having higher hydraulic conductivity and higher specific storage. The fracture extent was determined by 2D fracture propagation modelling (PKN/GDK models). The model was run using the multispecies, density and temperature dependant MODFLOW-SEAWAT code, which simulates HF fluid injection and migration and the post-injection flow-back. The injection rate and the concentration of the additives in the HF fluid are based on field data, and the modelled flow-back rate is calibrated to the observed flow-back data of about 62% of the injected volume.
The simulation indicated that the HF fluid plume was contained in close proximity to the injection well and was reduced to a very small fraction of the original injection concentration (0.1 mg/L) within a distance of less than 250 m. Simulation also showed that injecting near the fault did not influence the flow of the HF fluid along the fault, with concentrations decreasing rapidly with height. A model sensitivity analysis was carried out, which showed that the plume extent is mostly sensitive to the rate of HF fluid injection.
The model shows that the HF fluid is contained within the target formation and that fluid intersecting a fault of high transmissivity results in the concentrations dissipating faster. The maximum concentration of the HF fluid declined to well below the human risk-based concentration of the critical constituents (within &lt;1 year), based on several guidelines such as US EPA, European Chemicals Agency and Institute of Medicine.
This study indicates low impacts of hydraulic fracture stimulation during shale and tight gas development on potable groundwater sources in the north Perth Basin.
Adsorption Behavior Study of Shale Gas: Models and New Combination Approach
Authors: Jianchao Li , Zhang Lie Hui , Chen Yulin 
Published: November 2015

Abstract
Comparison of different adsorption models in the application of shale reservoir is performed, adsorption capability of shale is reconstructed by the combination of pure mineral adsorption capability with adsorption potential theory. Results are tested by experimental study of specific shale samples in China.
The research is based on the high pressure adsorption experiment of methane, in the same time X-ray diffraction experiment is performed to get the mineral information of the shale samples, which are taken from Lungmaxi formation in China. With the experiment, different adsorption models including monolayer Langmuir model, multilayer BET model and D-A model are used to match the data. Also, adsorption capability of pure minerals is combined by adsorption potential theory, which is used to study the contribution of different minerals on the total adsorption capability of shale.
Results show that Langmuir curve fits can be used to describe the adsorption behavior of shale, but BET curve fits give more accurate results, D-A curve fits make the best match. The use of characteristic curve can provide further information of the adsorption behavior, by which the unknown isothermal data can be forecasted. The adsorption capability with combination of pure mineral through adsorption potential theory (according to the mineral composition of each sample) gives reasonable results to indicate the total adsorption capability of shale, which means the new approach to get the adsorption information is applicable if the mineral composition and adsorption capability of each mineral are known.
Experimental Research on the Shale Imbibition Characteristics and Its Relationship with Microstructure and Rock Mineralogy
Authors: Yang Liu , Ge Hongkui , Shen Yinghao , Ren Kai , Sheng Mao , Gao Zhiye , Qin Xiaolun , Su Shuai 
Published: November 2015

AbstractField researches conducted on the multi-stage hydraulic fracturing measurements manifest that a large proportion of fracturing fluid retains in tight reservoirs, and the flow-back efficiency is usually lower than 30%. The publications have demonstrated that the spontaneous imbibition plays a significant role in large volumes of water loss, which is caused by high capillary pressure of tight rocks. Nevertheless, the imbibition characteristics of tight rocks are quite complex and still need further research owing to the complex pore structure, mineral constituent and strong microscopic heterogeneity.Comparative imbibition experiments were carried out on 12 core samples, which are seclected from tight sandstone formation from Ordos Basin, tight volcanic formation from Songliao Basin and shale formation from Sichuan Basin. Hence, a new method is proposed to demonstrate the imbibition characteristics and estimate fracturing fluid intake in tight gas formation. Moreover, the authors study the water imbibition capacity and characteristics of tight rocks, which holds diverse mineralogy, pore-size distribution and pore connectivity. The experimental data of tight rock samples in different size and shape can be normalized by using the new characterizing method, which exhibits the imbibition capacity, initial imbibition and late imbibition rate. The imbibed water volume increases with the clay content, and smectite and illite/smectite tends to strong water imbibition. Due to the water absorption on clay surface, the ratio of imbibed water volume to pore volume measured by Helium exceeds 100%. In addition, a general observation shows that each imbibition curve of tight rock can be divided into an initial imbibition region, a non-linear transition region, and a late imbibition region. However, the imbibition characteristics of different tight rocks vary greatly, which could be attributed, at least in part, to the complex pore connectivity, pore-size distribution and mineral composition. Well-developed macropores tend to have well pore connectivity and large time exponent at the initial imbibition region. Well-developed mesopores and micropores tend to have poor pore connectivity and large time exponent at the late imbibition region. These studies can be used to evaluate the fracturing fluid imbibition characteristics, and to understand its relationship with pore connectivity and pore-size distribution in tight reservoir rocks.
A Novel Model of Brittleness Index for Shale Gas Reservoirs: Confining Pressure Effect
Authors: Hu Yuan , Perdomo M. E. , Wu Keliu , Chen Zhangxin , Zhang Kai , Ji Dongqi , Zhong He 
Published: November 2015

Abstract
Brittleness indices (BI) commonly used in the petroleum industry are based on elastic modulus or mineralogy that can be calculated from well logs. However, they both ignore the effect of confining pressure. Shale is usually distributed at different depth under different confining pressure. Models without considering the influence of confining pressure will directly lead to inaccuracy in BI calculation, thus resulting in the failure of hydraulic fracturing. In this work, we compared confining pressure with rock mechanics parameters and the microcrack quantity of a core, introduced "fracture toughness" to explain how confining pressure influences BI, and finally developed a new model to correct the effect of confining pressure in BI calculation. Fracture toughness is an important parameter that characterizing a rock’s resistance to a fracture. It increases with confining pressure, since an increase of confining pressure may close preexisting cracks and restrict the crack propagation. The results show that BI is usually larger at low confining pressure than at high pressure. Also, higher content in brittle mineral does not necessarily mean brittler. The results calculated by the new model, which considers the influence of Young’s modulus, Poisson’s ratio, tensile strength, confining pressure and fracture toughness in BI calculation, match well with experimental results.
Evaluation of Microwave Heating on Fluid Invasion and Phase Trapping in Tight Gas Reservoirs
Authors: Wang Hongcai , Rezaee Reza , Saeedi Ali 
Published: November 2015

Abstract
During well drilling, completion, stimulation and fracturing, moisture invasion and phase trapping lead to a drastic permeability reduction, which prevent the tight gas reservoir producing at an economical rate. To eliminate such formation damage, the power of microwave was considered. As an effective heating technique, the application of microwave heating in removing moisture in the near wellbore area is relatively novel and thus lack of experience. This paper simulates effects of microwave heating on the formation damage and gas production rate of a tight gas reservoir in Western Australia and demonstrates its effectiveness. The well information for a tight gas well in Western Australia was obtained to simulate the actual gas production in numerical model. Finite Element Analysis (FEA) software and industry standard reservoir simulation software were coupled to simulate microwave heating at borehole scale. The electrical conductivity was extracted from well logs and the dielectric constant and loss factor of the reservoir rock was calculated using the empirical equations and proven mixing law. Two cases studied are in non-fractured well and fractured well. In each study, same water amounts were injected for 5days followed by a same period of clean-up and gas production, the difference is one model has microwave heater while the other not. The effects of microwave heating on water saturation and relative permeability to gas were made between two scenarios of gas production with heating and without heating. The electric filed and magnetic field distributions and the heat generation rate in the near wellbore area were calculated based on the actual petrophysical properties of the reservoir rock and Maxwell's Equations. Based on the results from FEA, the heat generated by microwave was applied on the well models respectively. After microwave heating started, gas relative permeability increased and water saturation decreased through the heated zone. In all the cases, microwave heating seems to be an effective way to remove moisture and to recover the gas productivity back to a high rate. But in non-fractured reservoir, the gas production rate has achieved the most improvement. The present paper focuses on the interaction of microwave and trapped moisture in the reservoir. By simulating the heating assisted gas production, illustrate how microwave heating was able to increase gas well productivity by reducing water saturation. More factors need to be considered in the future, and the suggestions have been given in this paper.
Downhole Naturally Convective Hydrocarbon-Separating Production System to Avoid Unnecessary Water and Sand Production
Authors: Surjaatmadja Jim B. , Lewis Bryan J. 
Published: November 2015

Abstract
In the production of oil and gas, operators are usually faced with undesirable by-products: water and sand (or particulate matter). Bringing these unwanted materials to the surface requires additional energy and cost and reduces the total flow of hydrocarbons to the surface. Once water and sand are brought to the surface, additional energy-intensive processes are required to separate them from the oil and gas. Once separated, properly disposing of unwanted materials also can be challenging and costly. Eliminating, or at least reducing, their production is therefore economically beneficial.
Downhole separators are often used to separate fluids and particulate matter. While these devices are effective, they require a substantial amount of energy. Passive, conductive separation based solely on static weight is a relatively slow process and not practical, as the weight difference of water and oil is approximately 10%. This paper discusses the use of a long angular conduit, or deviated wellbore, to passively create convective forces that enhance the separation. In the deviated section, as the heavier water and sand move to the bottom side of the conduit, the net forces push the heavier water and sand to the bottom, resulting in a convective motion pushing the lighter fluid to the top of the conduit. The weight differences in the produced mixture are amplified by the extended length of the conduit, and the heavier liquids and solids quickly separate from the lighter-weight fluids without any additional energy input as the mixture flows through the deviated section.
Laboratory tests show that convective separation can occur more than 10 times faster than natural static conductive separation. Additionally, the convective separator is capable of effective operation with production flow rates up to 6,000 BOPD with a 6 in. production casing. At higher flow rates, the separation is incomplete because of turbulent mixing, and some unwanted materials could be produced at the surface.
Using this approach, no energy is wasted for producing water, as it can be injected in lower strata after separation. The separated water also can be used for water drive in the formation. Sand, on the other hand, might need to be removed periodically. However, such periodic sand removal can be performed without damaging wellhead equipment.
Development and Verification of Degradable Sealing Elements for Fully Degradable Frac Plugs
Authors: Takahashi Shinya , Okura Masayuki , Kobayashi Takuma , Takahashi Takeo 
Published: November 2015

Abstract
The continuing growth in demand for hydrocarbons has led to the increase in the stage count of hydraulic fracturing in unconventional reservoirs. A typical stimulation method is the plug-and-perf system, which uses frac plugs for zone isolation. Conventional plug-and-perf requires milling out to recover the flow path for hydrocarbons after fracturing is complete. Fully degradable frac plugs are in great demand to eliminate milling out, reducing the cost and risk of well completion, and extending the lateral length of wellbores. A key material for fully degradable frac plugs is a sufficiently degradable rubber with good sealing properties for the sealing elements of the plugs. This paper provides an overview of the material properties of the degradable rubbers that were developed by a comprehensive study of materials, and their suitability as sealing elements for degradable frac plugs. Nonlinear, three-dimensional multi-body contact analysis and qualification testing were integrated to design and test the sealing elements. The results indicate that the resulting sealing element will function at over 100 MPa without failing.