bluuebunny/crossref_metadata_2025_split huggingface dataset:
Shale Gas Boom in the USA Inspires Chinese Operators
Authors: Kang Siwei , Gao Changhong 
Published: June 2014

Abstract
With the depletion of conventional fossil resources and growing demand for energy, unconventional energy is playing a more important role in the world energy market. Nowadays, unconventional gas production contributes to around 50% of total gas output in the USA Shale gas has significantly changed the energy portfolio in the USA and reduced America's dependence on oil and gas imports. The case histories of four major shale gas plays in the USA, Antrim, Barnett, Haynesville, and Marcellus, are discussed in this paper. It is concluded that the phenomenal shale gas success in the USA benefitted from improved horizontal drilling and fracturing technology, positive government policy and tax incentives, and mature surface pipeline system.
China is facing with soaring energy demand and the pressure to cut greenhouse gas emission. These factors have motivated oil operators to explore and exploit the enormous shale gas resources in China, especially in the Sichuan and Tarim Basins. But several factors may hinder the future of shale gas in China. Firstly, Chinese operators have to develop suitable drilling and fracturing technologies. Secondly, lack of water resources may restrain fracturing operations. Thirdly, China lacks mature pipeline system. Fourthly, the Chinese national oil companies may not be interested in producing shale gas due to its low price and low profits. Therefore, it is emergent for the Chinese government to invest in innovations and infrastructure, and allow independent and private companies to engage in the shale gas business.
A Novel Experiment Method of Evaluating the Brittleness of Rock
Authors: Song Lili , Li Yongping , Wang Yonghui 
Published: June 2014

Abstract
The selection of favorable well /layer and the hydraulic fracturing strategy are all based on the rock brittleness in shale gas. Two main methods of evaluation the brittleness of rock have been widely used in field. One is based on the Young's modulus and Poisson's ratio, and the other is based on the brittle mineral component content. But these 2 methods are not good enough in some shale, because the parameter of brittleness is related to the rock failure behavior while the 2 methods can't reveal the failure property. Using the feature points on the complete stress-strain curve is a good option to evaluate the brittleness. But complete stress-strain curve is often hard to be gotten if the stiffness of load frame is not high enough, especially for the shale.
A novel experimental method of rock brittleness evaluation is developed from the nature of rock failure, which is based on the AE (acoustic emission) technology. Because the AE events can reflect the rock failure process, it can characterize the rock brittleness well. More brittle the rock is, more concentrated the AE events occur. That is to say, the concentrated AE events feature shows the rock is brittle, while dispersed AE events feature means the rock is ductile.
Several experiments have been carried with this method on shale and sandstone. The results show that the shale is much more brittle than the sandstone. Meanwhile, the evaluation results are in good agreement with the results from complete stressstrain curve methods and have effectively guided the hydraulic fracturing in field.
This method is easy, accurate, universal and low demand on the load frame. The results can be used to guide the well/layer selection and fracturing design, and to establish the empirical relationship between the rock brittleness and logging data in new region.
Comparison of Empirical and Analytical Methods for Production Forecasting in Unconventional Reservoirs: Lessons from North America
Authors: Dutta Riteja , Meyet Marie , Burns Chris , Van Cauter Frederik 
Published: June 2014

Abstract
The prediction of Estimated Ultimate Recovery (EUR) for a well or group of wells in a development project is critical to accurate reserves estimation. A number of techniques, many of which can be used deterministically or probabilistically, are employed in EUR prediction in mature and maturing unconventional gas and oil plays in North America. These include the use of geological and production data from analogous reservoirs, the use of volumetric methods and recovery factors, analytical models, numerical reservoir simulation and production decline curve analysis (DCA).
Decline curve analysis is arguably the most commonly used method for forecasting reserves in unconventional reservoirs. This paper discusses its basic theory and application, together with the potential pitfalls of using simple empirical production forecasting methods in complex reservoirs. We analyse production data from several US unconventional oil and gas plays and carry out production forecasting using the traditional Arps' methods as a basis for comparison, and newer empirical solutions including the Power Law, Stretched Exponential Decline Model, Duong (and variations thereof). The range of production forecasts provided by these methods is examined, together with methodologies for developing statistically valid type wells in unconventional plays, and how best to determine valid input parameters for the various empirical solutions.
The effect of the variable length of production history available in the various plays, and how it impacts the accuracy of the forecasts is also examined. The results of the analyses are compared with analytical models developed for each play to determine the suitability of each decline curve analysis method: in which plays and under which circumstances they can be applied, and suggest reasonable input parameters and data requirements for each method. Finally, the potential future use of the methods in emerging plays outside of North America is presented.
New Insights From Jurassic Shale Characterization: Strengthen Subsurface Data With Outcrop Analogues
Authors: Zijp Mart , ten Veen Johan , Ventra Dario , Verreussel Roel , van Laerhoven Linde , Boxem Thijs 
Published: June 2014

Abstract
This study shows the first results of an ongoing project on the characterization of variations in lithological and geomechanical properties of targetted gas shale formations. The aim of this study is to get an increased insight into both the fraccability and productivity of a shale formations. Ultimately, this can lead to better localization of shale gas "sweet spots" and prediction of mechanical reservoir behaviour. Since subsurface data is scarce and often widely spaced to achieve this, we did an outcrop study along the Yorkshire (UK) coast on the time and depositional analogue of the Jurassic Posidonia Shale Formation, the Jet Rock Member of the Whitby Mudstone Formation. High resolution (10 cm) sedimentological, geochemical and geobiological sampling, natural fracture analysis and Spectral Gamma Ray measurements are performed.
The mineralogy of the Jet Rock Member is based on geochemical data and thin section point counting and shows more or less equal amounts in Quartz, Kaolinite and Illite with only Pyrite and Calcite changing substantially. Within high TOC layers the percentage of Pyrite increases at the cost of Kaolinite. Fracture analysis of the Jet Rock Member shows a change of fracture density and length on a meter scale and is confined to the bedding. Comparison of the fracture density and mineralogical ratios shows a strong correlation suggesting that identification of the mineralogical signature can be of importance when targeting zones with preferential geomechanical behaviour. Geochemical test show that of the eight meters of black shale studied only one zone of half a meter has a measured TOC value of 15–20%. All other measurements on the other 7.5 meters of the member show an average organic content of 3–5%.
Spectral Gamma Ray (SGR) analysis of the Whitby outcrops shows gradual changes in potassium, thorium and uranium content, while the variation in thorium content is most significant. A direct link between SGR and fracture density is not visible although it is clear that the altering SGR signature is result of the changing minerology and thus possibly linked to the fracture behavior. When comparing the Whitby outcrop results with the SGR results of the Posidonia Formation in the Dutch well Moerkapelle-14 it stands out that the Dutch subsurface values are in general lower than the English outcrop ones. Both thorium and uranium are, for almost the entire formation, lower than the English time-equivalent.
Lower Paleozoic Basins Developed Above the East European Craton in Poland: New Insight from Regional High-Effort Seismic Reflection Data
Authors: Krzywiec Piotr , Malinowski Michal , Lis Pawel , Buffenmyer Vinton , Lewandowski Marek 
Published: June 2014

Abstract
The Lower Paleozoic basin in Poland is located above the southwest edge of the East European Craton, northwest from the Teisseyre – Tornquist Zone which is separating the cratonic plate from the West European Platform (Fig. 1 & 2; Ziegler, 1992; Doornenbal & Stevenson, 2010).
Later Late Paleozoic tectonic movements resulted in compartmentalization of the Lower Paleozoic basin into three sub-basins: Baltic Basin, Podlasie Basin and Lublin Basin (Fig. 3 & 4).
During the Precambrian/Cambrian, the cratonic edge underwent extension and rifting of the Rodinia supercontinent, while Cambrian – Middle Ordovician subsidence was driven by a post-rift lithospheric thermal cooling (Poprawa et al., 1999; Poprawa, 2006a). In the Late Ordovician – Silurian, the cratonic edge was under the strong influence of the Caledonide thrust belt, and was incorporated into its flexural foredeep basin (Poprawa et al., 1999; Nawrocki & Poprawa, 2006). Deposition was dominated by fine-grained organic rich shales, generally derived from the eroded orogenic wedge and deposited in the distal foredeep basin (Poprawa et al., 1999; Poprawa, 2006b). The Silurian Caledonian foredeep basin encompassed vast areas stretching from the present-day Sweden across Estonia, Latvian, Lithuania, Russia (i.e. Kaliningrad District), Poland, Belarus, Ukraine and farther to the southeast (Poprawa et al., 1999; Skompski et al., 2008; Zdanaviciute and Lazauskiene, 2007). Presently available information regarding the Caledonian orogenic wedge is very limited and mostly indirect, based on e.g. provenance studies of the foredeep infill, as it was destroyed and deeply buried during the later tectonic phases (Poprawa, 2006b).
Interpretation of the Silurian Basin of Central and Eastern Europe as a Pro-Foreland Flexural Basin: Implications for Shale Gas Exploration
Authors: Tari Gabor , Poprawa Pawel , Krzywiec Piotr , Popadyuk Igor , Krezsek Csaba 
Published: June 2014

Abstract
The present day collage of various Silurian basin fragments in Central and Eastern Europe (CEE) is the result of several orogenic and rifting/drifting episodes. The proper paleogeographic reconstruction of a single, very large Silurian foredeep basin in the context of regional geology has a major impact on the ongoing unconventional shale gas exploration efforts in the region, including Poland, Ukraine, Romania and Moldova.
The distal segments of a large Silurian foreland basin associated with the Caledonian collisional orogene, along the perimeter of the East European Craton, can be reasonably followed along strike from NW to SE, from Poland all the way to the Ukrainian Black Sea coast. The foredeep basin sequence onlaps to the NE the various pre-Silurian and crystalline basement units. The Silurian basin of the CEE is interpreted here as a pro-foreland basin, with short-lived (less than 15 m.y.) and extremely rapid (locally more than 1,500 m per m.y.!), accelerating subsidence histories recording a portion of the orogenic history of the broader Caledonian orogeny. Besides the typical subsidence curves and the very prominent onlap of successive Silurian lithostratigraphic units onto the craton, the flexural origin is also supported by the general lack of normal-faulting within the basin, contradicting some interpretations suggesting deposition on the extensional continental margin of the Rheic Ocean. The map-view distribution of the lithofacies within the basin, such as clastic turbidites in the southwestern perimeter of the basin, deepwater shales in the center and neritic carbonates on the northeastern foreland margin, is also consistent with the flexural basin interpretation.
Unconventional Reservoirs: Proper Planning and New Theories Meet the Challenges of Horizontal Cementing
Authors: Pavlock Cole , Bratcher Jason , Leotaud Lennox , Tennison Brad 
Published: June 2014

Abstract
Horizontal wells can present special challenges for cementing operations. Extended-reach lateral sections, unconventional mineralogy, and high-pressure/high-temperature (HP/HT) environments can cause failures during and after the cement job. The high clay content and ductility of these formations force operators to use oil-based mud (OBM) to drill the curve and lateral section. A narrow pore-pressure/fracture-gradient window and tight annular clearance create higher than usual equivalent circulating densities (ECDs) and can affect mud displacement efficiency and cement placement. As unconventional reservoirs become more prevalent, increased focus on the cementing process will be vital to the long-term success of the well. New theories and proper planning will help decrease the probability of an irregular cement job and increase the chances of having zonal isolation for the life of the well.
In this paper, many aspects of the cement job design are discussed and recommendations are provided for horizontal cementing in unconventional reservoirs. New testing methods and additive composition help ensure the compatibility and thermal stability of the cementing fluids while creating more realistic wellbore hydraulic modeling and job optimization. Improved casing attachments and plug sets help increase displacement efficiency, while formation-specific cement designs increase effectiveness of the stimulation method. As multistage sliding-sleeves completion tools become more prevalent and increase efficiency, the cementing operation should align with the overall goal of the completion procedure. With the entire lateral section in one formation, it is not only critical to isolate the target formation from shallower zones but to also create a good annular seal between fracture stages. Without isolation, communication between stages can cause fracture treatments to migrate to unwanted areas. Modeling the expected temperatures, forces on the formation, displacement efficiency, and stress on the set cement sheath allows for a design that meets the expectations during the life cycle of the well. Complex temperature profiles create unfavorable design criteria, so accurate temperature determination is an important element to the cement design. With a renewed focus on the fundamentals of cementing, sufficient planning, and new technology, these unconventional reservoirs can become a manageable and sustainable resource for many years.
Successful Alternating Sequential Hydraulic Multifrac in Two Parallel Horizontal Wells in a Low-Permeability Turbidite Oil Reservoir
Authors: Gutiérrez Guillermo , Perazzo Gerardo , Medina Eber , Sierra Jose , Henriquez Carolina , Salguero Javier 
Published: June 2014

Abstract
A multistage fracturing treatment was performed in two adjacent horizontal wells (Escobal 197 and Escobal 195) in Chicontepec basin. The alternating sequential hydraulic multifrac in two parallel horizontal wells was planned and performed to create a high-density system of low-complexity planar fractures between the horizontal wells, to maximize the contact area with the reservoir and increase the stimulated reservoir volume (SRV). The wells were drilled perpendicularly to the expected fracture azimuth in Pechi-B formation and were completed as openhole using a ball-and-sleeve completion strategy. Thirty-two fracturing stages (16 stages per well) were selected based on an integral analysis of geological, petrophysical, and geomechanical disciplines. This completion technique has been the first stimulation treatment of its kind in Mexico. The fracturing entails adjacent wells in sequence, enabling one well to hold fracture pressure while the adjacent well is being fractured and it also maximizes the exposure of new reservoir rock. The fractures then avoid each other because of the stress pattern set up in the pressured well. The two adjacent horizontal wells were successfully stimulated in 108 hours of continuous work, pumping 95,000 bbl of fracturing fluid and 8.6 million lb of ceramic proppants. The stimulation technique reduced the stimulation cycle time to just four days, and the initial production of the two wells was more than 8,320 B/D, which was more than 10 times the average initial production in the area. The production later stabilized at 2,517 and 1,011 BOPD, respectively. The two horizontal wells produced 240,000 barrels in 90 days of cumulative production, which exceeds 14 times the average of cumulative production from the conventional wells in the field. The application of this completion technology was considered successful, and now it is extending to other fields located in the basin of Chicontepec.
Fractured Reservoir Modeling: Effects of Hydraulic Fracture Geometries in Tight Oil Reservoirs
Authors: Lin M.. , Chen S.. , Chen Z.. , Xu J.. 
Published: June 2014

Abstract
Tight oil production is emerging as an important new source of energy supply and has reversed a decline in U.S. crude oil production and Western Canadian light oil production. At present, combination of the multistage hydraulic fracturing and horizontal wells has become a widely used technology in stimulating tight oil reservoirs. However, the ideal planar fractures used in the reservoir simulation are excessively simplified. Effects of some key fracture properties, such as facture geometry distributions and permeability change, are usually not taken into consideration during the simulation. Over simplified fractures in the reservoir model may fail to represent the complex fractures in reality, leading to significant errors in forecasting the reservoir performance. In this paper, we examined the different fracture geometry distributions and further discussed the effects of geometry distribution on well productions. All fracture geometry scenarios are confined by the microseismic mapping data. To make the result more reliable and relevant, a geo-model was first constructed for a tight oil block in Willesden Green oil field, AB, Canada. The simulation model was then generated based on the geo-model and history-matched. A horizontal well was drilled in the simulation model and different fracture geometry scenarios were analyzed. Results indicate that the simulation results of simple planar fractures overestimate the oil rate and lead to relatively higher oil recoveries. In addition, the effect of hydraulic fracture geometries under the higher fracture conductivity is more significant compared to those under lower fracture conductivity.
Automatic Processing of Microseismic Data: Determination of Hypocenter Position and Estimation of Focal Mechanism
Authors: Vicek J.. , Fischer T.. , Vilhelm J.. 
Published: June 2014

Summary
We present an automatic method of processing microseismic monitoring data acquired at the surface with star-like array using the back projection approach that allows simultaneous determination of hypocenter position of events and an estimation of their focal mechanisms. Location coordinates are searched in a grid using two norms for seismogram stacking: STA/LTA for location and stack of real amplitudes corrected by the radiation pattern to estimate the focal mechanisms. From each point of the given grid we compute travel times to all geophones on the surface through the assumed velocity model. Afterwards we do migration of each trace using the computed travel time and stack the STA/LTA ratios of all traces. This process is repeated for each point of the grid. The most probable location corresponds to the maximum of the stack. In the second step a small and fine grid with center in the approximate location is used to refine the hypocenter position. In order to find source mechanisms we use additional grid search in source mechanism angles – strike and dip to find focal mechanism and correct polarity of seismograms according to computed theoretical polarities of the found focal mechanism. We test this method on real dataset of hydraulic fracturing monitoring of a shale gas play. We obtain similar hypocenter positions and focal mechanisms as provided by other methods applied to the same dataset.
Design Optimization of Horizontal Wells with Multiple Hydraulic Fractures in the Bakken Shale
Authors: Saputelli Luigi , Lopez Carlos , Chacon Alejandro , Soliman Mohammed 
Published: June 2014

Abstract
Hydraulic fracturing is currently the completion method of choice in most tight reservoirs; however, the ultimate performance of fractured wells is severely affected by the interfering effects inside the fracture and interfractures. Previous simulation studies investigated the effects of well spacing and fracture length on well productivity in low-permeability oil and gas reservoirs. It was shown that the most important parameters for determining the optimum fracture length are the formation permeability and the stimulated reservoir volume (SRV).
Although a number of studies have examined the performance of horizontal fractured wells and the fracture geometry effect, fracture spacing and intersecting angles in vertical and horizontal wells should be further investigated. This study presents the results of a tight oil reservoir analogy. Reservoir parameters considered include local rock stresses, rock compressibility, absolute and relative permeability, and porosity. The well-completion parameters included fracture length, height, width, conductivity, number and spacing between fractures, fracture intersecting angle, and cased- vs. openhole completion. Fracture modeling considered rigorous description of the hydraulic fracture properties and finite difference reservoir modeling.
Economically attractive reserves recovery was modeled through multiple fracture placements in a 10,000-ft horizontal well. Numerical simulation showed that oil recovery increased between 8 to 15%, while net present value (NPV) increased 8 to 24%, as the number of fractures increased. Based on the critical assumptions in the study (permeability, natural fracture distribution, and stress orientation), an optimum number of fractures was identified. Openhole completions provided better performance in most cases, and recovery was greater for a higher number of contributing perpendicular vs. longitudinal fractures.
The results of the study hopefully can be used to improve the understanding of the role of fracture geometry, spacing, and open/cased-hole completion strategy to enhance an operator's optimum completion design.