bluuebunny/crossref_metadata_2025_split huggingface dataset:
Development of Water-Dissolved Gas in Nishikambara Gas Field and Calculation of Land Subsidence Induced by Water Pumping
Authors: Higuma T.. , Fujii H.. , Horikawa K.. 
Published: January 2013

Abstract
Water-dissolved gas is a natural gas resource dissolved in groundwater. The gas mainly consists of methane gas and has been produced in many parts of Japan since the 1930’s. Although it is considered as an unconventional resource on a global standard, about 20 % of gas production in Japan comes from the water-dissolved gas fields. The resource is considered important in Japan since the R/P ratio of the water-dissolved gas is larger than one hundred years. In addition, iodine is commonly produced with the groundwater as a byproduct in a water-dissolved gas fields, which makes Japan as one of the largest iodine producers in the world.
Although water-dissolved gas is an attractive resource, its development often causes significant land subsidence due to the need of pumping large amount of groundwater. In Nishikambara water-dissolved gas field in Niigata, Japan, the target field of this research, a maximum 200 mm/year of land subsidence was observed at the early stage of the development in the 1950’s. As a countermeasure, all produced water has been re-injected into each reservoir since the early 1970’s, which enabled the gas production without any land subsidence for many decades. In this research, numerical models of water-dissolved gas reservoirs and the method to calculate the magnitude of the land subsidence were developed to investigate the mechanisms of gas production and land subsidence performance for the further development of the field. The numerical reservoir simulation models were developed using a black oil simulator, ECLIPSE100, on the basis of the field data. The land subsidence performance was calculated using a linear equation based on Hooke’s law. The reservoir pressure calculated by the numerical reservoir simulation models were used to calculate the magnitude of the land subsidence. Through the history matching, good agreement between the observed and calculated land subsidence was obtained.
Multidisciplinary Insights from Analysis of Borehole Microseismic Data from the Cotton Valley Tight Gas Formation in East Texas, U.S.A.
Authors: Gangopadhyay Abhijit , Rodrigues Victoria , Malayalam Atif , Liu Shujie , Plemons Patricia , Faz Ignacio 
Published: January 2013

Abstract
Microseismic data were acquired during the hydraulic fracture stimulation of a horizontal well in the Cotton Valley tight gas formation in east Texas, U.S.A., using a borehole observation array. The ~3700 feet horizontal well was successfully stimulated in six stages using slickwater cross-linked treatment at 80 – 88 barrels/minute. The resulting microseismic events were recorded in a vertical observation well using an array of seven sensors spaced at 100 feet intervals, spanning ~600 feet along the wellbore, and ~125 feet above the target reservoir. Based on 148 microseismic events, the inferred, dominant fracture orientations range between ~S59°W and ~S65°W, consistent with the regional orientations of SHmax. At least one ~N-S oriented fracture intersected the dominant orientations. Using all microseismic event locations, the derived fracture lengths are between ~2,257 feet and ~2,529 feet, independently confirmed by observed inter-well fracture hits in the area. Calculated fracture heights range between ~125 feet and ~387 feet indicating that the stimulations were contained within the ~400 feet target reservoir. The dominant linear fractures initiated in intervals within the tight sand where gamma ray log values are &lt; ~70 gAPI units, thereby indicating a potential diagnostic range of frac-ability, consistent with independent field-wide rock typing study within the Cotton Valley formation. While the number and size of microseismic events varied amongst stages, treatment pressures and proppant concentration &gt;~4,000 psi and ~1.3 ppg respectively, influenced stimulation of the reservoir, resulting in larger and more frequent microseismic events. Production characteristics of the treatment well, and tracer data collected from it, indicate that only part of the inferred fracture network volume from microseismic events, is effectively stimulated. These multidisciplinary insights guide improvements in future horizontal well stimulations in tight gas formations.
Practical Insights and Benefits of Integrating Technology into Exploration, Appraisal and Development of Unconventional Gas and Liquid Rich Shale Reservoirs
Authors: Oz Bora , Braun David , Vitthal Sanjay , Okouma Mangha Viannet , Molenaar Mathieu M , Peringod Chandran , Kazakoff Sergei , Li Yongyi , Asgar-Deen Michele , Langille David Lindsay 
Published: January 2013

Abstract
In the current high oil / low gas price North American environment, and considering the new options available for well completions technology in unconventional reservoirs, recent industry activities have turned their focus to the areas of Liquid Rich Shales (LRS) and Light Tight Oil (LTO) along with unconventional tight and shale gas (UG).
Integrated workflows are important to the successful execution of this portfolio, i.e. systematic methodologies to screen and appraise opportunities, and cutting edge integrated technologies must be viewed as key enablers. It is also important to maintain a life-cycle mindset and leverage economies of scale to execute projects faster and more efficiently.
This paper will discuss some of the advances and best practices that Shell has in each of the following disciplines, the value of R&D and applied technologies as well as integrated workflows used for exploration, appraisal and development of UG, LRS, and LTO plays: • Geological screening and sweet-spotting • Geomechanics evaluation and modeling • Reservoir engineering, including PVT sampling and characterization • Completions, stimulations and diagnostics • Artificial lift and operational considerations
Case History of Using Integrated Reservoir Modeling Workflow for Tight Gas Reservoirs
Authors: Abacioglu Yafes , Sebastian Herbert M. , Bonney Kyle E. 
Published: January 2013

Abstract
As the demand for energy increases, more and more low-permeability reservoirs are being developed with the help of advancements in hydraulic fracturing and horizontal drilling technologies. Integrated reservoir modeling studies become increasingly important to understand and improve reservoir management of such reservoirs for optimum depletion planning.
This paper presents the approach used for applying an integrated reservoir modeling workflow to the tight gas sands of the Cotton Valley reservoir. The main objective of the study is to understand well performance for horizontal infill wells with multiple hydraulic fractures.
In order to accurately simulate gas flow in hydraulically fractured wells (HFW) in full-field or regional models of unconventional gas reservoirs with many HFW, it is critical to appropriately represent these wells in the simulation models. Various methods have been used in the industry to numerically simulate hydraulic fractures in large reservoir models. In this paper, we will also review these methods and show that almost all the methods require calibration with fine grid models in which the hydraulic fracture is explicitly gridded. For homogeneous models calibration is relatively easy, but it is almost impossible for heterogeneous models. Therefore, we used local grid refinement (LGR) as the solution for modeling hydraulically fractured wells in coarse grid simulation. Our approach is different than other LGR approaches presented in the literature in that we only refine the coarse gridblocks that contain the fractures and wells.
Finally, since it is very time consuming to generate LGRs manually for models with many wells a software tool was developed to generate LGR gridding automatically for HFW for commercial simulators.
On Simulation of Flow in Tight and Shale Gas Reservoirs
Authors: Darishchev A.. , de Nancy E. N. , Lemouzy P.. , Rouvroy P.. 
Published: January 2013

AbstractApplicability of existing numerical simulation methodologies to unconventional reservoirs is questionable and requires investigation and research.We have focused on gas flow simulation of a highly heterogeneous fractured reservoir with extremely low matrix permeability. First of all we have considered the key roadmap components, natural gas composition, rock properties, critical elements and the main features inherent in tight and shale gas reservoir engineering. Using field reference data and a reservoir simulator, different scenarios of gas production have been modelled. This paper presents results from a sensitivity study of the dimension of hydraulic fracturing stimulated reservoir volume (SRV), matrix and propped fracture permeability which is spatially varied as one of the most realistic approaches, and of the bottom hole pressure. The approaches "dual porosity -single permeability", "dual porosity -dual permeability" and key reservoir properties have been reconsidered for specific geological and technological conditions in order to support decision making in unconventional reservoir management. Assuming pseudo-steady state gas flow, the simulation time step and gridblock size have been adjusted with a sector model represented by a logarithmically refined grid. In comparison with previous studies, it has been stated that the proposed approach of discrete fracture network modeling can be used in cases where the dual medium approach is questionable or inappropriate. The simulations of flow that have been performed, showed that the contribution of unstimulated reservoir volume (in the vicinity of the SRV) to gas production is non-negligible and can be a significant part of gas production to be taken into account in some field cases.The results of this study can be used in unconventional reservoir modeling and flow simulation to identify development, stimulation, and completion strategies aimed at optimization of gas production, reservoir performance and gas recovery. The proposed approach also supports risk and uncertainty analysis, revenue estimation and economic performance evaluation.
Unconventional Gas Stimulation by Creating Synthetic Sweetspot
Authors: Al-Nakhli Ayman R. , Abass Hazim , Al-Ajwad Hassan A. , KwaK Hyung T. , Al-Harith Abdullah , Al-Otaibi Ahmad 
Published: January 2013

Abstract
Unconventional resources are considered to be the game changer of near-by future energy. The huge resources of unconventional gas worldwide along with the increasing oil demand make the contribution of unconventional gas to be critical to the world economy. However, major challenges that operators face to produce from unconventional resources are due to the need for identifying a sweetspot, commercial stimulation technique that creates sufficient stimulated reservoir volume, very low permeability and different damage mechanisms such as water blocking, filtrate invasion during drilling, completion, stimulation or production.
This paper describes a new stimulation technique that creates synthetic sweetspot by thermal and mechanical energies. An energized fluid was used to generate localized heat and pressure in tight core samples and therefore create microfracturing. Created microfractures significantly increased permeability, porosity, and stimulated reservoir volume. A synthetic sweetspot nearby a wellbore or fracture area can be created by the new treatment mechanism. Permeability of tested cores was measured by Coreflood system and showed significant increase with new treatment technique. Communication between micro and macro pores was also found as a result of the treatment.
The treatment doesn't utilize any hydrocarbons and have no lift overs or potential damage. The generated high temperature and pressure can remove any damaging material or condensate banking near wellbore or fracture area. The new treatment technique was evaluated using Coreflood system with actual tight core samples collected from tight reservoirs in Saudi Arabia. NMR and CT-Scan analysis were used to show creation of microfracturing and permeability porosity changes.
Microseismic Leads to Improved Understanding of Hydraulic Fracturing in a Sultanate of Oman Tight Gas Well
Authors: MacKenzie Alasdair , Clark Robert Alfred , Al Anboori Abdullah 
Published: January 2013

Abstract
This paper details the successful downhole microseismic monitoring of a number of hydraulic fracture treatments in a horizontal well drilled in the Barik reservoir, integrating the results with treatment data. The treatment well was drilled in a direction of 312°, at 90° to the assumed maximum stress direction, with a horizontal section of 1000m.
The well was placed such that it passed within 300m of the well to be used as the observation well. The observation well was plugged immediately above the topmost reservoir perforations to minimize disturbance in micro-seismic data. The maximum geophone array length from the top of the plug to the production string was therefore 60m.
A number of fracture treatments were monitored, with the results giving understanding of fracture placement, direction, length, and height. The early results impacted immediate decision making on perforation strategy. Orientation of the maximum principal horizontal stress was confirmed. Overall frac height appears to demonstrate effective coverage of the Barik reservoir interval. This key data will strongly influence future completion design and the overall development plan of the field.
Optimal Design of Nonuniform Multiple Transverse Fractures for Horizontal Wells in Tight Gas Reservoirs
Authors: Gao Sunhua , Yao Jun , Sun Zhixue , Lu Ranran , Li Longlong , Wang Yuhang 
Published: January 2013

Abstract
A new comprehensive approach for designing the optimal nonuniform multiple stage/cluster transverse fractures intercepting horizontal wellbores is proposed. The proposed approach relies on the Genetic Algorithm (GA) method. Its aim is to optimize nonuniform transverse fracture spacing, number of fracture stages and clusters, nonuniform half length of fracture and fracture conductivity in order to achieve maximum net present value (NPV). The advantages of this method include: 1) The automated and comprehensive process makes it easier and more precise to find the optimum design than most previous works. 2) The design is based on a new configuration of nonuniform transverse fractures in a horizontal well. 3) The optimization of cluster spacing considers the effect of stress shadowing (Nicolas P. Roussel 2011) e.g. the opening of a fracture causes a reorientation of stresses in its neighborhood affecting negatively the efficiency of treatment. 4) It is based on NPV maximization, not just the initial production rate and cumulative production. 5) The procedure concerning well productivity also considers the effect of non-Darcy flow.
A field example in Sulige gas field is presented to demonstrate the application of our method for optimal design of multiple patterned transverse vertical hydraulic fractures intercepting horizontal wellbores. It is showed that this approach enable operators to achieve maximum reservoir productivity and NPV.
The multi-stage and multi-cluster per stage fracture treatments in horizontal wells have proven successful in tight gas recovery, by creating a large stimulated reservoir volume (SRV). In order to avoid sub-optimum fracture design relying on historical databases of hydraulic fracturing and personal experience, this new systematic method considers various factors affecting the optimal fracture spacing and length, and thus helps to get close to the optimal fracture pattern.
Transverse Fracturing of Horizontal Well - A Unified Fracture Design to Stimulate Tight Gas Sands
Authors: Rahman M. M. , Yu H.. , Sarma H. K. 
Published: January 2013

AbstractUnconventional tight gas reservoirs offer an enormous opportunity towards fulfilling our energy demand, and hence, they have been subject to significant R&D activities these days. Although the tight gas sands may not be a major focus today in UAE, their potential, however, must be recognized; for, UAE has several deep tight reservoirs that need to be fully exploited for their gas reserves. For such reservoirs the conventional approach of simply fracturing the formation to stimulate the horizontal well is inadequate. This is because most currently available commercial software may lack proper optimization tools in them with several key parameters and realistic constraints. Even the systematic design methods for fracture treatment parameters with constraints are not well presented in the literature.There are optimal number of transverse fractures and optimum treatment parameters when real field constraints and economic aspects are considered. An integrated model to optimize multistage transverse fractures has been developed to maximize gas production and net present value (NPV) with minimum treatment cost. Model couples both the industry experience and unified fracturing design parameters based on hydraulic fracture mechanics. Unified fracturing design defines the optimal compromise between the fracture width and fracture length for a given mass of proppant. Model integrates unified fracture geometry, reservoir in-situ parameters, treatment parameters at every stage, realistic design constraints, and production and economic modules. The integrated model has been successfully applied to a hypothetical deeper and tight gas sands to demonstrate its merits. A simple analytical approach has been used for evaluating and optimizing the productivity. The design indicates a significant incremental production. Effect of mass of proppant on production rate and NPV is also presented. Authors are working further to couple this integrated model with an optimization algorithm (genetic and polytope) to optimize the treatment parameters globally. This model could also be used to study the potential of the deep UAE offshore tight gas sands.
Rod-shaped Proppant Provides Superior Proppant Flowback Control in the Egyptian Eastern Desert
Authors: Edelman Jeff , Maghrabia Karim , Semary Mahmoud , Mathur Anil , Zaki Ahmed Samir , Bernechea Jose Maria 
Published: January 2013

Abstract
The Arta field in the Egyptian eastern desert produces mainly from the Nukhul formation that is characterized as a complex, thin-bedded sequence with heterogeneous laminated siltstone. Typical reservoirs show low-to-average permeability, low temperatures and moderately heavy oil in the 17-24 degree API range. Hydraulic fracturing is the technique traditionally employed to produce hydrocarbons from these marginal reservoirs. However, proppant flowback following the fracturing treatment is a major concern because of the relatively low formation stresses and high viscosity fluids, that results in damaged completions and impaired proppant pack permeability. Proppant flowback control therefore, became an essential requirement to maintain economical production rates from the field.
The rod-shaped proppant product was introduced in the Egyptian western desert in 2009. Published results illustrated excellent proppant flowback control as demonstrated by zero proppant flowback.1 Prior to this, several conventional proppant flowback techniques and products had been tested but they had limited application due to low reservoir temperatures. The rod-shaped proppants are inert and have no limitations on application from the reservoir or pumping equipment standpoint. Since introduction, more than 100 wells have been hydraulically fractured using this rod-shaped proppant product.
This paper describes the application of the rod-shaped proppant in the Arta field to control proppant flowback and enhance near-wellbore conductivity. The details of the evolution of rod-shaped proppant applications are presented for more than 20 wells in the Arta field, including the effects on the fractured well performance and production, as well as proppant flowback control. Results continue to demonstrate excellent proppant flowback control. In addition, cost savings result from reduced workovers, rig time savings and reduced damage to completion equipment and surface facilities.
An Integrated Approach to Rock Typing & its Impact on Well and Reservoir Performance in a Middle East Tight Gas Field
Authors: Southworth Adrian , El Hadidi Kareem , Miller Jessica 
Published: January 2013

Abstract
The Risha field is located in the North East region of the Hashemite Kingdom of Jordan approximately 370 km from Amman and is bordered by Iraq to the East, Syria to the North and Saudi Arabia to the South. Risha was discovered in 1987 and production started in 1989. The field consists of a predominantly tight gas reservoir but seismic and core data indicate the presence of faults and fractures. The Risha reservoir is late Ordovician, and is interpreted as a marine proglacial outwash fan setting. 45 wells have been drilled to date with mixed success and only 15 wells demonstrated some degree of production capacity. Historic well performance trends indicate a range of well types with some illustrating high initial rates, recoverable volume, and slow decline without need for stimulation. Others suffered from very low rates and sharp declines even after undergoing hydraulic fracturing. To date, high rate and recovery wells have been associated with fracture presence making fracture the key reservoir drive mechanism.
This paper attempts to analyze other potential reasons and factors causing well deliverability variation to date. It discusses the integrated approach followed to categorize the Risha rock types and determine whether they could be linked to historic reservoir performance. In this paper the reservoir units were loosely grouped according to petrophysical cutoffs, based on gamma ray, and compared with core data. The defined rock types along with well control were used to create a 3D simulation to model the rock quality variability and match the production and pressure history, with the ultimate aim of trying to understand if history performance is a reliable indicator of future behaviour.