bluuebunny/crossref_metadata_2025 huggingface dataset:
Causes of and Responses to Abnormal Fracture Pressure on Ultra-Deep Shale in Southern China
Authors: Shan Qinglin , Jin Yan , Chen Mian , Yang Shuai , Zhang Xudong , Wu Jun , Huang Jianyi
Published: November 2015

Shale gas development by hydraulic fracturing in Southern China highlights the features of high fracture pressure and of serious difficulties in proppant placement due to deep burial (over 4000 m). This scenario differs from that in North America.

To solve the problems described above, conventional triaxial tests were conducted on the properties of rock mechanics under a simulated high temperature and high pressure reservoir environment. A full-size 3-D finite element method (FEM) is used to predict the fracture pressure of deep shale formation, taking both the rock deformation behavior of ultra-deep shale and the influence of fracturing fluid filtration into account. Effective engineering approaches are also presented that focus on reducing the friction of fracturing fluid and on the efficiency of acid pretreatment.

The triaxial compressive test results indicate that under the condition of high temperature and increasing confining pressure, the plasticity of the rock is strengthened and the nonlinear characteristic will inhibit fracture initiation. The correctness and reliability of the FEM model are confirmed through a comparison of the FEM model calculation result with the field data. Moreover, preliminary proposals are made for perforation parameter optimization based on this model. An optimal perforation phase angle of 60° and a perforation density of 18 perforations/m are considered appropriate parameters. A long perforation tunnel (more than 1 m) mitigates the state that the majority of the perforation component endures pressure stress. Finally, both laboratory test and field application results show that a refined slick water system design can generate a friction reducing rate of no less than 75% and that a new acid system can lower pressure by 10–15 MPa before fracturing. As a result, fracture pressure is reduced.

This work presents a method of addressing the challenges arising from the abnormal hydraulic fracture pressure on ultra-deep shale, including the causes determined during laboratory tests and the treatments generalized from FEM results and engineering approaches. These solutions are a necessary step toward reducing fracture pressure in deep shale gas development.
Possibility of Bioelectrochemical Conversion of Carbon Dioxide into Methane in Depleted Oil Fields
Authors: Maeda H.. , Ikarashi M.. , Fukushima N.. , Kobayashi H.. , Sato K..
Published: November 2015

As potential CO2 geological storage site in CCS, utilization of depleted oil/gas reservoirs and aquifer has been proposed. The long-term aim of this research is to establish a biotechnological system to microbiologically convert geologically stored CO2 into methane.

Our recent study revealed that methanogen and exoelectrogen inhabiting subsurface reservoir are involved in the recently discovered bioelectrochemical reaction called electromethanogenesis (CO2 + 8H++ 8e− → CH4 + 2H2O). In this reaction, methanogen receives proton from reservoir brine and electron from a solid electrode. As a result, reduces CO2 into methane. Required electricity for the methane conversion can be obtained from renewable energy sources such as wind or photovoltaic power generations. Single-chambered electromethanogenic reactors were used for an evaluation. The reactors were inoculated with reservoir brine anaerobically collected from Yabase oil field in Japan. Each reactor headspace was filled with mixed gases of N2/CO2 (80/20). The reactors were incubated at 55°C with an applied voltage of 0.75 V. The reactors produced methane at a rate of 386mmol/day m−2. The current-methane conversion efficiency was almost 100%. On the other hand, no significant methane production was detected in the reactors without applied voltage.

To investigate the mechanism of electromethanogenic reaction, the phylogenetic diversity of the microbes on the cathode was analyzed.

The result shows, as for archaea, methanogen closely related to Methanothermobacter thermoautotrophicus dominated. On the other hand, as for bacteria, Thermincola ferriacetica, one of the exoelectrogen, was the dominant spices.

Our experimental research demonstrated for the first time that the possibility of bioelectrochemical methane conversion of carbon dioxide by utilizing microbes indigenous to depleted oil fields.

The final goal of this research is to establish the "Subsurface Methane Regeneration" system, combining CCS and biotechnology, in which geologically-stored CO2 is converted into CH4 by bio-electrochemical process called "Electromethanogenesis".
Finite Element Simulation of a Hydraulic Fracture Interacting with a Natural Fracture
Authors: Chen Zuorong , Jeffrey Robert G. , Zhang Xi , Kear James
Published: November 2015

In this paper, the problem of a hydraulic fracture interacting with a pre-existing natural fracture has been investigated by using a cohesive zone finite element model. The model fully couples fluid flow, fracture propagation and elastic deformation, taking into account the friction between the contacting fracture surfaces and the interaction between the hydraulic fracture and the natural fracture. The effect of the field conditions, such as in-situ stresses, and rock and fracture mechanical and geometrical properties, intersection angle and the treatment parameters (fracturing fluid viscosity and injection rate) on the hydraulic fracture propagation behavior has been analyzed. The finite element modeling results provide detailed quantitative information on the development of various types of hydraulic fracture – natural fracture interaction, fracture geometry evolution and injection pressure history, and allow us to gain an in-depth understanding of the relative roles of various parameters. The value of a parameter calculated as the product of fracturing fluid viscosity and injection rate can be used as an indicator to gauge if crossing or diverting behavior is more likely. In addition, using a finite element approach allows the analysis to be extended to include the effects of fluid leakoff and poroelastic effect, and to study hydraulic fracture height growth through a system of nonhomogeneous layers and their bedding planes.
Simulation of Time-Varying Properties of Organic-Shale Nanopores During Gas Production
Authors: Wang Jing , Luo Haishan , Liu Huiqing , Jiao Yuwei , Wang Chaofeng , Sepehrnoori Kamy
Published: November 2015

The apparent permeability and effective porosity of organic-shale nanopores are time-varying under the impacts of gas adsorption/desorption, non-Darcy flow, and stress dependence during gas production. However, the porosity occupied by adsorbed gas is usually disregarded by industry standard. Moreover, the gas flow regimes are not completely described in most models or simulators; the stress dependence of matrix does not draw adequate attention in current studies. Therefore, an appropriate modeling is urgently needed to simulate the dynamics and performances during gas production. In this paper, we developed a coupled model to characterize time-variation properties by considering contributions of gas adsorption, non-Darcy flow, and stress dependence. After that, we verified the model and demonstrated model application, which lead to new insights into the evaluation of rock properties and gas quantities during gas production. We found that taking account of the volume occupied by adsorbed gas can effectively avoid the significant error of OGIP (Original Gas in Place) in the classical models. Meanwhile, the apparent permeability is significantly reduced by adsorbed gas, but the time-varying apparent permeability affected by gas flow regimes increases during gas production. We also studied the complex behaviors of the effects of stress dependence and various flow regimes. This new model provides with a more clear understanding of the time-varying features of organic-shale nanopores during gas production, which is more advantageous than classical models. As the production process can be more accurately forecasted, more insights can be achieved by the improved simulations.
A New Method for the Estimation of Lost Gas During the Measurement of the Gas Content of Coal
Authors: Lu Meng , Pan Zhejun , Connell Luke D. , Lu Ye
Published: November 2015

In this text the authors present a study on the approach of estimating the lost gas during the retrieval process of coal sample within wellbore. A new method is proposed to improve the accuracy of prediction as the traditional methods often give inaccurate predictions. To this end, the major sources of errors with those traditional methods are first analysed. Then the pertinent modifications are made in this proposed method to have these errors minimised. With the present method the following improvements are made. (1) Physically, the transport equation used here for gas flow in the core includes both advection and diffusion effects; in contrast, the traditional methods are fundamentally based on a linear diffusion equation. (2) Geometrically, the present method considers the the actual shape of the core sample (say, a cylinder), while the routine counterparts have to simplify the geometry of the core to be a one-dimensional spherical object. (3) Numerically, the present method employs the actual retrieval history to specify the boundary conditions of the core sample, and uses a neural network technique to best fit the measurements with the numerical solutions obtained. In contrast, the routine counterparts need to assume a constant or a linearly declining boundary condition such that an analytical solution (in a form of a series) can be obtained. When the relevant sorption isothermal curve for the coal is known, the proposed model contains three parameters to be determined, which are related to the effective permeability, the effective diffusion coefficient, and the initial gas content, respectively. These parameters are determined through best-match of the experimental data by the neural network simulations. An application example is presented in this study and it shows that the proposed method can significantly improve the accuracy of prediction for the lost gas volume or the initial gas content than its traditional counterparts.
Creep: A Neglected Phenomenon in Coal Permeability Evolution and Coalbed Methane Production
Authors: Danesh N. N. , Chen Z.. , Aminossadati S. M. , Kizil M.. , Pan Z.. , Connell L. D.
Published: November 2015

During gas production, coalbed experiences compaction over time when effective stress increases as a result of pressure depletion triggered by escaping gas from micropores through desorption and diffusion. It is deemed that time-dependent compaction deformation (compaction creep) and deterioration of coal structure lead to a decrease in coal permeability. Alteration of compaction rate and permeability of coalbed depends on factors such as coal properties, pore pressure, time, and temperature. Thus far, little studies have been conducted to investigate the impact of compaction creep, viscoelastic, and viscoplastic behavior of coal on permeability. Creep may have such significant impact on coal permeability that its negligence may result in overestimation of Coalbed Methane (CBM) production. Appreciation of creep phenomenon, coal properties such as viscoelasticity and viscoplasticity, and their impact on the interaction of coal permeability and gas production borehole enables optimisation of CBM production. In this study, we aim to examin permeability models and highlight the significance of creep as a factor influencing the evolution of coal permeability and CBM production.
Pore Network Investigation in Marcellus Shale Rock Matrix
Authors: Goral Jan , Miskovic Ilija , Gelb Jeff , Kasahara Jack
Published: November 2015

The ever-growing energy demand and recent discoveries of vast unconventional oil and gas reservoirs have brought significant attention to shale oil and gas resources as potential game-changers for the petroleum industry and energy markets worldwide. The complex structural features and mineralogy of shale has broad implications on the development of the unconventional oil and gas industry. Although shale reservoirs are large in scale and offer the potential for long-lived production, extremely low matrix porosity and permeability, as well as complex heterogeneity, pose major challenges in obtaining economically viable oil or gas. A lack of predictive understanding of microstructure-based heterogeneity in shale limits the effectiveness of currently used production technologies. Hence, addressing the challenges of shale oil and gas production requires an in-depth understanding of microstructural features that control the oil and gas storage, release, and transport mechanisms.

Because anisotropy of shale exists across multiple scales, determining changes in pore distribution has proven to be difficult. Recent studies have indicated that shale pores significantly vary in number, size (from nano- to micropores), and classification (organic and nonorganic pores). Thus far, the role of pore network and, more specifically, what pores contribute the most to the gas and/or oil storage or to the production process, is not well understood and remains largely unknown. Hence, it is vital to determine how well different pores are connected and how they create possible flow pathways for hydrocarbon migration.

Here we present a comprehensive digital rock physics (DRP) framework for pore network investigation in a Marcellus Shale rock matrix using nano X-ray microscopy (nano-XRM) and focused ion beam scanning electron microscopy (FIB-SEM) data. Pore networks within both organic and nonorganic matter are reconstructed from FIB-SEM images of the shale specimen. Through this process, porosity, pore size distribution, pore connectivity, and mineralogy – organic-matter-hosted and nonorganic-matter-hosted pores – of the sample are obtained. The impact of obtained parameters on fluid flow in shale is analyzed.
Reservoir Characteristics for Unconventional Shale Play of Huai Hin Lat Formation in Northeastern Thailand
Authors: Chumkratoke C.. , Dunn-Norman S..
Published: November 2015

Recent trends in petroleum production have focused on developing unconventional gas reservoirs such as tight gas and shale gas. Considering worldwide shale gas resource potential, the largest resources exist in the former USSR and in North America, while for China, Central and Southeast Asia the estimated shale gas resource is 1115 TCF. Despite the smaller resource projection, this unconventional resource is of great interest for future development. In Thailand, the primary energy source is oil and natural gas, with 77% of electricity generated from natural gas (EIA, 2011). Yet current production is not enough to support the growing energy demand in Thailand, and there is increasing emphasis in exploring potential unconventional resources to meet this demand.

A study has been conducted to improve reservoir knowledge of the Huai Hin Lat formation, believed to be an important source rock for the gas fields in northeast Thailand. The Huai Hin Lat formation consists of fluvio-lacustrine sediments of Late Triassic. The formation is exposed along the margin of the Khorat Plateau. Petroleum exploration in Khorat Plateau has been ongoing since 1962 and two gas fields have been discovered and commercially produced in the Khorat Plateau since 1988.

Seven shale samples were taken from the Huai Hin Lat formation. All samples are the organic rich fine-grained rocks. The MicroCT technique was measured for porosity parameter. The average porosity of the samples was approximately 4.9%, and a pore size distribution was found. In addition, geochemical analysis was performed to determine total organic content (TOC) of the shale samples. The average TOC was found to be approximately 4.9%.

Permeability was measured for the seven samples using transient pressure pulse decay. The permeability range of the samples was found to be 90 (D to 280 (D and the average permeability of sample was approximately 180 (D. Permeability varies significantly because the shale is somewhat heterogeneous. Natural fractures present in the formation may also affect the value of effective permeability.

This paper provides details regarding the analysis of the Huai Hin Lat samples and the shale's rock properties as they relate to other commercial unconventional gas resources. The work is significant because there are few existing petrophysical evaluations of this formation. Results from this study will identify and highlight key reservoir parameters necessary to further assess the commercial potential of the Huai Hin Lat shale as a shale gas reservoir.
Depth Distribution of Gas Rates From Temperature and Pressure Profiles in Unconventional Gas Wells
Authors: You Z.. , Bedrikovetsky P..
Published: November 2015

Estimating flow rate distribution along the depth in the wellbore is very important for reservoir and production management purposes, because it provides information for distinction of the production rates from different layers. This is critical for optimizing well performance and maximizing recovery of reserves. The temperature and pressure sensors in the well are small and inexpensive, while flowmeters are cumbersome and expensive, and affect the flow in the well. In this study, a mathematical model for pressure and temperature profiles along a gas well has been developed, which is readily used for prediction of flow rates in different layers. Temperature and pressure measurements from gas well in field C (Australia) have been matched with the mathematical model to determine the flow rates from different layers in the well. The proposed model considers the variables as functions of thermal properties at different depth, which is more accurate than previous methods. A simple and effective method is developed for fast estimation of rate distribution along the depth. The proposed approach has been applied to field case for determining gas flow rate in the wellbore and thermal conductivity of the formation from the acquired pressure and temperature data. It allows for recommending well stimulation of layers with low production rate.
Pore-Filling Nature of CH4 Adsorption Behavior in Kerogen Nanopores: A Molecular View Based on Full-Atom Kerogen Models
Authors: Sawa Y.. , Liang Y.. , Murata S.. , Matsuoka T.. , Akai T.. , Takagi S..
Published: November 2015

Organic rich shale contains kerogen nanopores with characteristic lengths typically less than 100 nm. Adsorption behavior of hydrocarbon gas in the nanopores and the adsorption amount need to be considered for accurately calculating gas-in-place of this type of reservoir. We investigated CH4 behavior in kerogen nanopores under 350 and 400 K. A slit-like pore is constructed with full-atom kerogen models. The corresponding aromaticity is 0.71 and the structure is similar to coal. Two different cases are considered: Pressure and temperature are fixed with isobaric-isothermal ensembles, and different pore sizes from 2 nm to 40 nm (as mesopore models) are obtained by changing the number of CH4 molecules (Case 1); pore size and temperature are fixed with canonical ensembles, in which pressures are ranged from 5 MPa to 70 MPa by changing the number of CH4 molecules (Case 2). For case 2, four different pore sizes from 7.5 nm to 20 nm are useed. It was found that the density of the bulk region in an approximately 40 nm pore was almost the same as that of the bulk phase at the same pressure. However, it becomes higher as the pore size becomes smaller. Because the kerogen molecule is large in terms of size, the packing of kerogen molecules always leaves some cavities, which are capable of hosting CH4 molecules. This is similar to the micropores in activated carbons. The mono-molecular layer model, like the Langmuir model, may not be appropriate. On the other hand, the extended Dubinin-Radushkevich (DR) equation is ready to be implemented to acquire adsorption isotherms for those micropores. The DR model was developed to describe pore-filling state of adsorption behavior in micropores, which has been extended to supercritical conditions by assuming saturated vapor pressures. As anticipated, it was found that the adsorption isotherms were described by the extended DR equation better than the Langmuir model for all pore-size systems that we have studied. Moreover, we show that it is possible to apply the DR equation to describe the gas status in the "bulk region" inside the mesopores. Our work offers a better understanding in the calculation of gas-in-place in organic rich shales providing that we have the pore size distribution and constituents of a certain kerogen.
Modified Hybrid Fracturing in Shale Stimulation: Experiments and Application
Authors: Yin Congbin , Li Yanchao , Wang Subing , Qin Guan , Xu Ben , Zeng Rongke
Published: November 2015

Slick-water fracturing has been widely used in shale stimulation, which provides relatively long fracture length and large-scale complex fracture network without cross-linked gel. The shortcomings of slick-water fracturing are the proppant setting and bridging, which result in low sand concentration that compromises long-term fracture conductivity. A hybrid fracturing strategy is formulated with the combination of slick-water prepad followed with linear gelled, or cross-linked gel to balance the fracture network and long-term fracture conductivity. Compared to common hybrid fracturing, a modified hybrid fracturing is proposed by modified pumping schedules with alternating injection of slick-water, linear gelled fluid, or cross-linked gel, which is used for well stimulation in shale formations with high pressure and temperature.

In this paper, we present an in-house experimental device to simulate fluids and proppant flow in complex fracture network that contains two clusters, main fractures and several secondary fractures, which allows us to separately simulate hydraulic fractures and natural fractures. We have conducted a series of experiments on the slick-water fracs, the hybrid fracs, and the modified hybrid fracs. Compared with conventional hybrid fracs, the modified hybrid fracs with alternating injection of slick-water and cross-linked gel exhibit two advantages. (1) The modified hybrid fracs can form more flow channels in main fracture for viscous fingering, (2) the modified hybrid fracs enhance secondary fracture conductivity because slick-water pad between cross-linked gels reduces inflow rate of slurry into secondary fractures.

Based on the experimental results, an experimental method of fracture conductivity prediction is proposed with data regression method, which can be used for characters selection of pumping schedule in modified hybrid fracturing. Several shale well cases of the same shale gas field in Sichuan basin, Southern China, separately using the slick-water fracs, the hybrid fracturing and the modified hybrid fracturing are illustrated. The stimulated treatment pressure characteristics, long term well production performance of these three scenarios are discussed.

The modified hybrid fracturing has several advantages in shale stimulation, but there are also some difficulties in preventing sand screen out. This paper illustrates some basic experimental mechanisms of field applications of hybrid fracturing. In the future, we will present more field scenarios that are planned to carry out in other shale well pads.
New Models of Brittleness Index for Shale Gas Reservoirs: Weights of Brittle Minerals and Rock Mechanics Parameters
Authors: Hu Yuan , Gonzalez Perdomo M. E. , Wu Keliu , Chen Zhangxin , Zhang Kai , Yi Jie , Ren Guoxian , Yu Yanguo
Published: November 2015

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 ignore the weights of these two factors. Also, it is imprecise to calculate BI by considering quartz (or dolomite) as the only brittle mineral in mineralogy-based BI prediction. Shale gas reservoirs like Eagle Ford are rich in carbonate minerals. If the carbonate minerals are ignored in those reservoirs, the value of BI will be greatly underestimated. On the other hand, brittle minerals like quartz, dolomite and calcite play different roles in BI calculation. If we equally treat them without weighting in BI prediction, the BI being calculated will be inaccurate as well. This paper analyzes the influence of calcite on rock mechanics parameters and BI comparing with quartz and clay. Then new models of BI prediction are built to characterize the weight of each brittle mineral and rock mechanics parameter. Based on the least squares method, optimal values of weight coefficients will be obtained by iteration. The results show that calcite improves rock brittleness and should be considered as a brittle mineral in BI prediction. However, the weight of calcite is less than quartz. From the statistics results, quartz > dolomite > calcite > clay occurs in improving BI. The results also show that Young's modulus plays a more important role in BI prediction than Poisson's ratio.
An Experimental Method to Determine the Fracture Toughness of Brittle and Heterogeneous Material by Hydraulic Fracturing
Authors: Too Jun Lin , Falser Simon , Linga Praveen , Khoo Boo Cheong , Cheng Arthur , Palmer Andrew
Published: November 2015

In this paper, a method is proposed to determine the fracture toughness of brittle and heterogeneous material through hydraulic fracturing. The intent of the proposed method is to deploy it on materials whose are not easily determined by standard test. One example of such a material is hydrate-bearing sand, which is unstable under atmospheric pressure and temperature. The pressure-time record, injection flow rate and total volume injection are necessary information to determine the fracture toughness of the material using the classical linear elastic fracture mechanics approach. To verify the method, frozen sand is used as a substitute material and its fracture toughness found using the standard test. Frozen sand has similar composition as natural hydrate-bearing sediment except for the absence of methane gas and high pressure. Then, this method is applied on the hydrate-bearing sand.
X-Ray Micro-Computed Tomography Imaging for Coal Characterization
Authors: Ramandi Hamed Lamei , Armstrong Ryan T. , Mostaghimi Peyman , Saadatfar Mohammad , Pinczewsk W. Val
Published: November 2015

An Australian bituminous coal is imaged at high resolution of 16.1 μm with (wet) and without (dry) X-ray attenuating fluids present in the pore space using a large-field three-dimensional microfocus helical X-ray computed tomography (micro-CT) instrument. Scanning Electron Microscope (SEM) is conducted on slices of the specimen to visualize coal micro-features up to resolution of about 15 nm. Two- and three-dimensional image registration techniques are used to precisely overlay micro-CT tomograms of the core plug in dry and wet conditions and SEM images to yield detailed three-dimensional visualizations of the geometry and topology of the fracture systems in coal. SEM images are also used to produce a calibration curve based on the relationship between the micro-CT intensity values and the true apertures of fractures within coal. This eliminates the need for two sets of imaging. Advanced filtering algorithms are applied to segment the micro-CT image into four distinct phases: resolved fractures, sub-resolution pores and fractures, macerals, and minerals. The application of micro-CT in determination of relative age relationships between adjacent geological features is presented. The distribution of resolved aperture size within the coal sample is investigated and the variation of permeability and porosity in several sub-samples of the coal is plotted. The analysis suggests that coal permeability is independent of porosity and is likely affected by other petrophysical properties such as lithotype. To include the effects of mineral phase on coal properties, we remove the segmented mineral phase and merge it to the resolved fracture phase. This analysis affirms that minerals are deposited in highly connected regions.
DFN Model for Flow Simulation in Hydraulically Fractured Wells With Pre-Existing Natural Fractures Using Unstructured Quadrilateral Grids
Authors: Wang Keke , Peng Xiaolong , Du Zhimin , Haghighi Manouchehr , Sayyafzadeh Muhammad
Published: November 2015

Multiphase flow simulation of hydraulically fractured wells with pre-existing natural fractures is a challenging task. Discrete fracture network (DFN) is an effective method to simulate a system of anisotropic fracture network. In DFN method unlike double porosity approach, fractures can be defined in different scales and in different apertures and directions such that all details of fractures will be included in the simulation. Also all the interactions and fluid flow in and between the fractures and within the matrix are modelled in a unified manner, using the same computational grid.

We developed software based on DFN model in which both induced fractures and pre-existing natural fractures can be placed at any location and direction in the geological model. Then, quadrilateral unstructured grids are generated using Paving method. Quadrilateral grids are more efficient and more flexible than triangular grids such that the number of quadrilateral grids is reduced to half. A drawback of algorithm in this mesh generation process is that very small grids are generated in the intersection of fractures and in the ends of the fracture grids due to the size difference between the fracture and the matrix. In order to avoid severe time-step restrictions associated with small cells, an endpoint transformation method is used to replace the quadrilateral grids with the triangular grids at both ends of the fracture. As a result, the number of very small grids at the ends of fractures is notably decreased.

In this paper, the results of two-phase flow simulation in a hydraulically fractured well with pre-existing natural fractures are presented. For solving the pressure and saturation equations in each grid, the inter region of quadrilateral mesh is taken as a control volume cell and the governing equations are solved using MPFA (Multi-Point Flux Approximation) technique which is designed to give a correct discretization of the flow equations for general non-orthogonal grids. Finally the results of our software are tested to verify its validity in theory, algorithm, and efficiency in calculation.
Optimizing Shale Resource Field Developments by Systems and Drilling and Completion Operations Modeling
Authors: Mitschanek M.. , Prohaska M.. , Thonhauser G..
Published: November 2015

Efficiency is driving the cost for shale resource developments. Thus modeling of drilling and completion operations is key for increasing the pace of development in tough economic conditions. The objective is to develop an operational strategy that minimizes downtime on single pads, as well as to manage operations efficiently amongst multiple well pads.

As various options to move equipment are possible, simulation serves as viable tool to analyze the entire process. Field data build the basis for model formulation and calibration. Further, an operations, equipment and scheduling tool was developed to find solutions that allocate resources best possibly along the development.

What is found is that the industry has come quite a long way already in improving the operational sequence and the corresponding logistics of a development. It can be shown that batch drilling is a very successful way of improving efficiency when done correctly and when interdependencies of variables are targeted. To go beyond what is done today, the approach to de-bottleneck operations among all pads in one field of one operator has shown to decrease the time and cost to deliver even further. Through simulation, it is expected that the learning curve is increased and operators can benefit faster.

Detailed simulation of that aspect of a field development has often been neglected, but is applied on the regular basis in various other manufacturing industries world wide. A whole new generation of process modeling in the petroleum industry is started with this approach.
Predicting the Fracture System in Shah Structure in Onshore Abu Dhabi Using Analogue Modeling Approach
Authors: Sirat Manhal , Koyi Hemin
Published: November 2015

This paper aims at predicting the fracture system associated with the structural development of the Shah Structure in relation to a deep-seated basement fault. It discusses the possible geometry, frequency and fracturing modes, and the development mechanism of the fracture system revealed throughout a set of analog models, which emphasize the link between the basement fault and the sedimentary cover in a timely manner construction.

A 3D seismic data was used to construct a series of systematic scaled analogue models to reconstruct the structural evolution of Shah Anticline in association with an oblique sinistral strike-slip movement along basement fault, which induced both a strike slip movement in- and shortening of the cover sand layers. The deformation that was made by moving one of the basement plates in an oblique slip along the basement fault, resulted in an open anticline (box fold), which resembles the Shah Structure.

Analog modeling results presented here reveal that fractures associated with the asymmetric anticline have developed in different locations, and possessed different geometries and modes. As anticipated, both tensile and shear fractures have developed in different areas within both the crestal parts of Shah Structure and within its limbs. However, the asymmetrical geometry of the model-anticline is reflected in the fracture distribution, trend and frequency. The steeper limb of the anticline bear more developed fractures than the gently dipping limb. The asymmetry of the anticline is not equally well displayed by the post-erosional units above the unconformity "model Simsima", where a gentler anticline is displayed. Hence within this gentle part of the model-anticline the fracture pattern is less developed, less frequent and evenly distributed. Such vertical and horizontal asymmetries in fracture pattern (geometry, frequency and mode) seen in these analog models are expected to have in reality developed in the Shah Structure.

This new modeling approach has helped predicting the occurrence of different fracture system including geometry, frequency and fracture mode in different areas within Shah Structure. The predicted fractures have significant implications for exploration and field development plans of Shah Structure and those situated at the vicinity within Onshore Abu Dhabi.
Tackling Interbed Multiples with High Density Surveys, a Case Study Over the Rumaila Field
Authors: Ourabah Amine , Grimshaw Martin , Ernst Sabrina , Tough Kenneth
Published: November 2015

Interbed multiples have always presented a big challenge to interpreters of land seismic data, especially in Middle East basins where impedance contrasts can be quite high and appear at different levels of the subsurface. These interbed multiples not only affect the stack image, making the structural interpretation very uncertain, but also the pre-stack data, making the extraction of reliable AVO and azimuthal AVO attributes at the contaminated interfaces extremely difficult, if not impossible. Attempts at tackling these interbed multiples on conventional data using deconvolution techniques, 1D modelling or moveout-based methods are common practices (Berkhout & Verschuur, 1999; Jakubowicz 1998; Alvarez & Larne, 2004); while these methods can improve the stack image, their impact on the AVO response is often limited, especially on noisy land seismic. Recently, we are seeing more and more high density surveys being acquired thanks to new acquisition techniques such as simultaneous sourcing acquisition (Rozemond, 1996; Bouska, 2008; Howe et al., 2008); it has already been shown how this new generation of dataset can have a huge impact on the quality of the processing products and pre-stack attributes (Ourabah et al, 2014 & 2015). In this study, we demonstrate how we can also use high density dataset to remove interbed multiples by applying an innovative workflow to the Rumaila high density field trial dataset.
The Impact of Surface-Wave Separation on Seismic Survey Design
Authors: Ishiyama Tomohide , Blacquiere Gerrit
Published: November 2015

3-D seismic survey design should provide an acquisition geometry that enables imaging and amplitude-versus-offset applications of target reflectors with sufficient data quality under given economical and operational constraints. However, in land or shallow water environments, surface waves are often dominant in the seismic data. The effectiveness of surface-wave separation or removal significantly affects the quality of the final result. Therefore, the need for surface-wave separation imposes additional constraints on the acquisition geometry.

Recently, we proposed a method for surface-wave separation that can better deal with aliased seismic data than classic filtering methods such as in the wavenumber-frequency domain. This will impact survey design. Here, we investigate how the choice of a particular surface-wave separation affects the selection of survey parameters and the resulting data quality. To quantify the latter, we introduce a measure that represents the estimated signal-to-noise ratio between the desired subsurface signal and the surface waves that are deemed to be noise.

In a case study, we applied surface-wave separation and signal-to-noise ratio estimation to several data sets with different survey parameters. The spatial sampling intervals of the basic subset are the survey parameters that affect the performance of surface-wave separation methods the most. Finer spatial sampling will reduce aliasing and make surface-wave separation easier, resulting in better data quality until no further improvement is obtained. We observed this behaviour in our results as a main trend that levels off at increasingly denser sampling. With our new method, this trend curve lies at a considerably higher signal-to-noise ratio than with a classic filtering method. This means that we can obtain a much better data quality for given survey effort, or the same data quality as with a conventional method at lower cost.
IFL™ - A Novel Approach to the Rehabilitation of Sub-Sea Hydrocarbon Pipelines Using High Performance Solef PVDF Flexible Kevlar Reinforced Liners
Authors: Walters Robert A.
Published: November 2015

PETRONAS Carigali (PCSB) is the owner and operator of an extensive network of sub-sea pipelines which are situated offshore from main land Malaysia, in the South China Seas. Many of these pipelines run from platform to platform and platform to onshore facilities over distances of between several hundred meters to several kilometers and in varying depths of water.

Severe internal corrosion, due in large part to Sulfate Reducing Bacteria (SRB) has caused some of the pipelines to have a drastically reduced life span which has historically resulted in the replacement of pipelines becoming necessary within a time period as short as four years. Historically, there has not been a viable methodology that could be utilized to install such a corrosion barrier within a sub-sea pipeline, thus the project for the design and development of InField Liner™ (IFL™) system was instigated and within three years brought to a highly successful conclusion incorporating the full rehabilitation of an 8" pipeline carrying Crude media and which was due to been decommissioned within six months had the installation not gone ahead. This particular pipeline is now fully anticipated to provide a further 25 years of operational use to PCSB.

Robert A. Walters, IFL™ Global Project Director and Chairman of Anticorrosion Protective Systems (APS), discusses the innovative InField Liner Technology, its offshore deployment within the PETRONAS pipeline network and the strategic plans for future global expansion. The company APS is a globally recognized pipeline rehabilitation specialist engineering and contracting company which is head-quartered in Dubai, U.A.E.
Reinvent Recruitment By Using Innovative Technologies
Authors: Kannankutty Manoj , Narayan Sumy Shankar
Published: November 2015

The objective of this paper is to discuss modern trends in technology to complement and improve recruitment cycle in the petroleum industry. The areas of focus are:

Sourcing and attracting talent using social media Mobile Apps Video screening interview

Social media

The largest social media networks are having a wider reach to audience around the world. Organization's presence in social media shall be very useful for social networking, references and recruitment.

Mobile apps

Mobile recruitment apps can help candidates view open positions, file their applications and receive notifications from recruiters using mobile devices like smartphones and tablets.

Video screening interview

Video screening interviews requires the candidate to record their video responses to a set of preset questions asked by the recruiter. Recording is done using a computer, laptop, tablets or mobile device without any break allowed during the interview.
Feasibility Study for An Unpiggable Subsea Pipeline
Authors: Stewart J. , Yablonskikh I.
Published: November 2015

Objective/Scope

Managing the long term integrity of a critical 10″ subsea crude oil pipeline is dependent on being able to use the correct inspection technologies, however, the current structure of the pipeline does not allow for any in-line inspections. Consequently managing the short term integrity of the pipeline becomes a priority until the pipeline is made piggable. This paper describes where and how to investigate along the pipeline to determine the current internal condition of the pipeline.

Methods/Procedures/Process

A desktop feasibility study was completed in order to determine the locations and the confidence in the use of an external ultrasonic scanning survey (auto-UT) to determine the short term integrity of the pipeline. This comprised the following: Technical identification of the points along the length of the pipeline that is most susceptible to internal corrosion.Confidence in evaluating condition of pipeline based on auto-UT

In addition a review of the current sacrificial anode protection of the pipeline was completed to ensure that any investigative works completed would not result in any external corrosion issues.

Results/Observations/Conclusions

For a product velocity of 0.28m/s, using the approach in NACE SP0208 (Appendix A), an inclination angle of 2° is critical for water accumulation. Review of the vertical profile of the pipeline indicated that there are nine sections exhibiting critical angle in excess of 2°. In addition 4 further sections of the pipeline are characterised by long inclines which could also contribute to water separation from the oil-water emulsion. Further consideration was given to sections of the pipeline where solid accumulation was possible, as this may aggravate internal corrosion. As the pipeline is practically straight in the horizontal plane (from bottom of riser) to the tee connection with a 20″ export pipeline, there are no additional pipeline fittings (dead legs) with the exception of a 10″ tap assembly to allow product into the 20″ pipeline.

Auto-UT provides highly accurate wall thickness measurement and a defect resolution from 1mm x 1mm. All measurements are recorded in millimetres and repeated inspections at the same location provide most accurate corrosion growth rates. The main concern with auto-UT is that it does not provide information on the condition of the whole pipeline, only for the area of pipeline covered by the auto-UT. This limitation has to be overcome with a correct choice of the locations to be inspected.

Novel/Additive Information

This paper describes the thought processes that must be undertaken when considering the short term integrity of an unpiggable pipeline: the likelihood and expected types of corrosion existing within,the likely locations, most susceptible for corrosion to occur andthe benefits of using various inspection technologies to determine both the short and long term integrity of the pipeline.
Non-contact Approach in Milling Operations for Well Intervention Operations
Authors: Gajdos Matus , Kocis Igor , Mostenicky Ivan , Kristofic Tomas , Taha Islam , Plichta Michal
Published: November 2015

The main objective of the paper is to present the possibility of non-contact approach based on electrical plasma in downhole milling or cutting operations. The features of this approach can be beneficial for a variety of Well Intervention applications characteristic for Middle East region. These applications include slot recovery, side-tracking, pipe recovery and several others.

The presented approach utilizes thermal electrical plasma capable to disintegrate a variety of materials (steel, cement, rock) with the same tool. Milling or cutting using this approach is based on a hybridized plasmachemical and thermochemical processes resulting fast metal degradation and removal in water steam environment. The main processes responsible for the rate and effectivity of steel/cement removal are oxidative processes as well as melting and evaporation. This non-contact approach utilizing coiled tubing (CT) technology brings also improved reliability by minimization of wear and tear of the tool itself.

Based on its features, the technology can bring the following benefits into Slot recovery application area: Multicasing milling in fewer trips100% rigless operation – Light Well Intervention Vessel offering flexible use and satisfying immediate needsGeneration of small swarf (no mechanical stuck, less viscous and cheaper fluids)Reduction of HSE-related risks due to reduced tripping and automated CT systemReduction of issues with fluid management due to simplified handling with milled materialShortening of the whole process due to its structural simplification

Similarly, the mentioned features can be used also for other potential applications including: Multi-lateral side-trackingPipe recovery of stuck BHARepair/replacement of damaged casingWellhead retrieval

Moreover, after development and modifications of the tool geometry, it can provide an efficient substitution of conventional junk/fish milling tools.