bluuebunny/crossref_metadata_2025_split huggingface dataset:
Source Rock Stimulation: Does This Require More Art Than Science?
Authors: Lehman L. V. , Andress G. R. , Minner W. A. , Mullen M. J. 
Published: September 2014

Abstract
This paper discusses many of the best practices that have evolved through the processes of developing unconventional resources around the globe. The previous phrase is simply a marketing term that describes the practice of completing a formation that was historically considered to be a hydrocarbon source for reservoirs above or sometimes below the actual horizon. Many operators believe that they can seek and eventually use analogous basin case studies to develop their assets when in fact basic data sources can be utilized to develop a completion plan. Total organic content, reservoir pressure, stress regime and brittleness versus ductility values are essential for effective stimulation and ultimately field development for source rock development.
Our case studies focus on the initial field development processes for Bakken, which allowed the development of a neural network model; Eagle Ford, which helped to determine best-reservoir diagnostics for staging and stimulation type; and the Bone Springs play in the Delaware Basin, which has become a target for liquids seekers. The case histories outline data sources useful for new emerging plays as well as examples of pitfalls to avoid.
Vibration Wave Communication-Realise Remote Control for Zonal Production
Authors: Lichen Zheng , Fuchao Sun , Xiaohan Pei , He Liu , Deli Jia 
Published: September 2014

Abstract
Downhole data transmission is a key technology for oil industry. Traditional methods to realize selective zone production were mainly based on cable or pressure pulse technology and the application scale is limited because of their deficiencies. Downhole vibration wave communication realizes digital signal transmission through tubing or casing, vibration wave is used as carrier wave which is modulated by digital signal before transmission, characterized by low cost, simple operation, it will be used widely in the future. In this paper, the transmission characteristics of tubing and the attenuation rule of tubing are studied by a series of experiment & analysis. According to the findings above, a new digital signal transmission strategy was proposed, that is, three or more carrier waves will be used in series during the vibration wave signal transmission in order to avoid the notch wave band of tubing, at the same time, Manchester coding of digital signals and OOK modulation method of vibration wave were developed. A new vibration signal generator was developed based on magnetostrictive material, a new actuator controlled by vibration sensor was developed based on three degree of freedom sensor together with the tubing or casing, which form a new generation of downhole communication system. A new selective zone production system remotely controlled by vibration wave has been developed based on the above system and is under testing now.
Probabilistic Reservoir Property Modelling Jointly Constrained by 3D Seismic Data and Hydraulic Unit Analysis
Authors: Emami Niri M. , Lumley D. E. 
Published: September 2014

Abstract
We present a new method for seismic reservoir characterization and reservoir property modeling based on an integrated analysis of 3D seismic data and hydraulic flow units, and apply it to an example of a producing reservoir offshore Western Australia. Our method combines hydraulic unit analysis with a set of techniques for seismic reservoir characterization including: rock physics analysis, Bayesian inference, pre-stack seismic inversion and geostatistical simulation of reservoir properties. Hydraulic units are geologic layers and zones characterized by similar properties of fluid flow in porous permeable media, and are defined at well locations based on logs, core measurements and production data. However, the number of wells available for hydraulic unit analysis is often extremely limited. In comparison, the lateral coverage and resolution of 3D seismic data is excellent, and can thus be used to extend hydraulic unit analysis away from well locations into the full 3D reservoir volume. We develop a probabilistic relationship between certain 3D seismic data attributes and the hydraulic units we determine at well locations. Since porosity and permeability distributions are estimated for each hydraulic flow unit as part of the process, we can use the 3D seismic probabilistic relationships to constraint geostatistical realizations of porosity and permeability in the reservoir, to be consistent with the flow unit analysis. Reservoir models jointly constrained by both 3D seismic data and hydraulic flow unit analysis can therefore help to improve the accuracy of dynamic reservoir flow simulation and production history matching.
Integrated Production Modelling of Gas Condensate Field
Authors: Bartolomeu Mayembe , Abdrakhmanov Adkar 
Published: September 2014

Abstract
Liquid hydrocarbon production from a gas condensate field has been maximized by integrating the different parts into a single platform. The models integrated are, reservoir, wells, pipelines and surface processing model. With all models integrated, system bottlenecks have been identified and the whole production chain has been maximized on liquid hydrocarbon production.
Different production strategies and recovery mechanism such as Vaporizing Gas Drive (VGD) and Condensing Vaporizing mechanism (C/V) have been applied by gas cycling to enhance condensate recovery. For different production strategies an optimum condensate production has been found.
During pure depletion, most of the condensate has been trapped. Gas cycling has increased condensate recovery.
The best development strategy that maximized condensate production included pure depletion for the first 600 days, partial gas cycling from 600-2750days, full gas cycling from 2750-4250days followed by blowdown from 4250-5480days. For this strategy condensate recovery was 61%.
The process simulator includes the wells, pipeline and surface processing. In this case a production network application has been avoided by including the wells and pipelines in the process simulator.
Detailed steady state surface processing has been modelled for sales gas, lean gas injection, and Liquefied Natural Gas (LNG) plant and condensate production. For each reservoir time step, output process products have been obtained.
This single platform has given more realistic predictions than standalone models. It assists with decisions making, cost saving and long term forecasting.
Wellbore Stability Modelling for Horizontal and Multibranch Lateral Wells in CBM: Practical Solution to Better Understand the Uncertainty in Rock Strength and Coal Heterogeneity
Authors: Puspitasari Ratih , Gan Thomas , Pallikathekathil Zachariah John , Luft Joao 
Published: September 2014

Abstract
Arrow Energy has engaged in drilling production Coal Bed Methane (CBM) wells in the Bowen Basin. As part of its field development strategy, varied styles of horizontal wells have been planned and executed along the coal targets of Moranbah Coal Measures (MCM). Some of the recently drilled multi-branch lateral and horizontal wells experienced different drilling challenges and production performance. Potential geomechanical issues such as borehole conditions and fines/solid production are directly related to wellbore stability during and post drilling.
As part of Arrow subsurface modeling strategy, the project has embarked a detailed Geomechanics study in Moranbah Gas field. The main objectives were aiming to: (i) optimize the mud weight that is required to stabilize the borehole, (ii) understand how specific coal targets respond to the induced stress concentration around the wellbore during drilling and, (iii) capture the vertical and lateral mechanical heterogeneity within specific coal seams. This paper focuses on practical solutions to model the borehole stability, in particular of the uncertainties in the rock strength modeling and coal heterogeneity.
This innovative workflow coupled with geostatistical approach of rock strength and insitu stress with depth-of-damage is first of its kind in CBM environment. Borehole collapse depth-of-damage (DoD) concept is then used to assess risk associated to the volume of yielded rock as a percent of borehole size. The higher the percentage of DoD, the higher the risk of producing excessive cavings. It provides more confidence in optimizing drilling mud weight for CBM horizontal wells by allowing a more scientifically-sound and practical solution to address rock failure mechanisms associated with borehole instability.
The US Shale Gas "Revolution": A Review of the Production Performance and Geology to Establish Potential Economic Benchmarks for Australia
Authors: Starkey A. P. , Katelis Z. G. , McGhee P. 
Published: September 2014

Abstract
Shale plays have created the current natural gas boom in the United States (US) and according to the national Energy Information Administration (EIA, 2013)49 produced 47% of total daily production by the end of 2013 (approximately 31.8 Bscf/d). Extensive production data from thousands of wells are now available for analysis to provide potential benchmark information for the Australian shale gas industry, which is still in its infancy.
This paper focusses on analysis of publicly available US production data from horizontal wells in five depositional basins reported for the Barnett, Eagle Ford, Fayetteville, and Haynesville shale plays. Type-wells are evaluated which allow estimation of a range of representative initial gas production rate and technical Estimated Ultimate Recovery (EUR) characteristics. The analysis also results in generic recommendations for the minimum sample size and duration required for statistically significant well appraisal programs in shale plays. Such activity phases' primary objective should be to efficiently obtain reasonably reliable type-well performance indicators. The US shale plays' experiences to date provide insight concerning this aspect.
Variability in geological factors including, but not limited to: stress regime, total organic content, thermal maturity, porosity, brittleness, natural fractures, and reservoir pressure can result in production performance that differs substantially both within and between shale plays. Also affecting performance is how the wells are completed. The geology of shale formations is discussed along with recent Australian operational activity, geomechanical considerations, and example economics. Analyses of the US data provide potential technical and economic benchmarks for preliminary comparisons to be made with Australian information, and may help to demonstrate the economic resilience required for exploitation of prospective shale gas resources.
However, it must be recognised that the likely performance characteristics of the prospective Australian shale plays' type-wells are not currently well understood due to lack of data. Significant exploration and appraisal activity is needed to augment the extremely limited shale gas well performance data available in Australia to date.
Achieving Operation Efficiency and Enhancing Production in a Brownfield with Multizone Gravel-Packed Intelligent Completions: Two Case Studies from Malaysia
Authors: Atkinson W. R. , Ceccarelli T. U. , Zabala J. J. , Khalis A. , Razak F. , Yildiz R. , Gil J. , Raw I. 
Published: September 2014

Abstract
The aims of every oil & gas operator to optimize production, increase oil recovery, and minimize operating cost are driving the industry to look for innovative completion and production solutions. This is true for brownfields where operators are looking to rejuvenate reservoirs that still have reserves in place as original completion efficiencies deteriorated over time.
A workover and new well offshore Malaysia was conducted in a field to recover oil from a multilayered, high water/oil contact reservoir. The objective was to increase production and recovery volumes in a cost-effective way and reduce rig time. The original completion designs in the field lacked the ability to control and choke the flow from each zone independently, and thus could not optimize comingled production and water cut, resulting in limited oil recovery from the reservoir.
For this reason, an intelligent completion with downhole variable flow control valves and real-time pressure and temperature gauges was considered. The objective was to design an intelligent completion that is both cost effective in a marginal field and that can fit inside a cased-hole wellbore that requires sand control. Because of the many challenges faced in combining the multizone gravel-pack system and the intelligent completion components, both had to be re-engineered to allow for a perfect interface. This resulted in the first intelligent completion installation inside a shunt-tube gravel pack with multizone packers and subsequently future wells with same design.
An Innovative Solution to Accurately Address Water Detection in Subsea Wet Gas Conditions and Provide Accurate Condensate Gas Ratio (CGR)
Authors: Pinguet B. , Gosset P. 
Published: September 2014

Abstract
In wet gas business, the subsea oil & gas industry are struggling with the fundamental challenges to detect either condensed water or first formation water entry. This need is related to the flow assurance concerns, mitigation process with chemical injection, and detection of water breakthrough but beyond that, there are also challenges of custody transfer, fiscal allocation, and associated biases introduced to measurement devices by the change of fluid properties.
In recent years, operators have requested multiphase and wet gas meter manufacturers to solve these challenges by additional measurement and specifically the ‘salinity’ measurement (i.e. conductivity). Most of the manufacturers have responded by incorporating additional sensors into their conventional meter, which address the fundamental problems that their technology faced to correct the bias, but unfortunately, it is also increasing the entire equipment cost.
This paper is describing the development of the most innovative standalone solution to obtain this measurement without necessary the need for a subsea multiphase or wet gas meter. This versatility in the installation of the sensor is becoming an enabler for some oil and gas operators that can obtain a very cost effective solution in some development where a meter is not a requirement.
The paper is explaining the fundamental principle, and the entire process of qualification encountered over 4 years for obtaining a commercial solution including for high pressure and temperature conditions. The performance of the conductivity measurement will be check against the best flow loop references around the world.
The paper demonstrates that even in control conditions with only few tenth to hundredth ppm of liquid (0.001%), it is possible to discriminate the different phases, even the condensate formation inside the pipe (crossing the dew line). This innovative solution is a breakthrough for any wet gas development where flow assurance is critical.
Fleet-Wide Compressor Optimization
Authors: Cowan Adrian 
Published: September 2014

Abstract
In natural gas gathering applications, maintaining the lowest possible suction pressure can provide a significant production advantage. As fields fluctuate and, over time, decline, compressor optimization must be done on a regular basis in order to minimize suction pressure, while maximizing throughput and maintain high levels of overall fleet utilization. This paper gives an insight into the key tools and reports used by natural gas producers in order to manage and optimize fleets of compressors ranging in size from 5 to more than 1000 compressors.
Background into the key principles of compressor optimization and limitations are covered, while detailed compressor performance curves and pressure/temperature set-point start-up packages are used to explain optimizing for maximum throughput in order to: Increase running speedReduce added cylinder clearanceOptimize suction pressureDecrease recycle set point
To fully optimize a natural gas compressor fleet, tools and reports must be used in order to holistically consider the capacity and throughput requirements of each compressor, plant, field and area within an organization. To accomplish this, natural gas producers are implementing tools that provide statistics for easy identification of production and maintenance opportunities across an entire compressor fleet. Explained in this paper are the benefits of using Fleet Mapping Tools, Fleet Management Reports and Plant Potential Capacity Curves.
In a case study with Australian gas producer Santos Ltd, long-term tracking and analysis of detailed performance data was critical to achieving improved fleet utilization. Specific detailed cases illustrate how, over a period of more than four years, Santos Ltd. demonstrated a fleet-wide performance improvement of more than 7.5% in utilization across a fleet of more than 100 units.
Low Salinity Fines-Assisted Water-flood: Analytical Modelling and Reservoir Simulation
Authors: Zeinijahromi A.. , Borazjani S.. , Bedrikovetsky P.. , Rodrigues T.. 
Published: September 2014

Abstract
We discuss the fines-assisted case of low salinity water flooding, where the incremental recovery is achieved by induced fines migration, the straining decelerates the injected water with the consequent increase of sweep efficiency on micro and macro scales. The two layers cake reservoir with contrast permeability is discussed. The main idea is displacing of oil by slug of low salinity water with high salinity drive. The displacement occurs first from the highly permeable layer with it's plugging by released fines with the following displacement from low permeable layer by water drive. In this case, no formation damage is induced in low permeable homogenous layer, avoiding the oil production decrease due to induced permeability damage in the low permeable layer. The sensitivity study of with respect to the slug size is performed. We show the competitive effects of fines migration on sweep enhancement and on oil production deceleration. The minimum slug size for low salinity water providing higher recovery if compared with normal water-flood has been found.
Identification of Strike-Slip Faults Provides Insights into the Further Development of Mature Cooper Basin Fields
Authors: Grant-Woolley L. , Kong A. , Schoemaker B. , Nasreddin H. , Montague E. 
Published: September 2014

Abstract
Newly acquired full azimuth 3D seismic in conjunction with modern azimuthal acquisition and processing, and a fresh review of the regional structural model, has enabled the identification of strike-slip faults with greater certainty. Strike-slip faults are often difficult to identify in traditionally processed seismic due to the lack of vertical displacement. The resulting improvement in structural detail in the geological models has provided a better match with well production, performance and reservoir connectivity in mature Cooper Basin fields. The structural interpretation is independently supported by Pressure Transient Analysis (PTA) and image log data in one of the fields.
Field examples are used to demonstrate the observed relationship between strike-slip faulting and hydrodynamic connection. Pressure data supports that fields previously thought to be separate are demonstrated to be connected via strike-slip corridors. Therefore, hydrodynamic disconnect occurs across strike-slip faults. An observed relationship between underperforming wells and proximity to interpreted strike-slip faults is also discussed.
The integrated approach combining new full azimuth 3D seismic data with regional structural concepts, well performance and dynamic behaviour has led to the identification of new development and appraisal opportunities in several mature fields. Application of this multidisciplinary approach, including the structural model, seismic interpretation and analysis of dynamic data is recommended for all fields throughout the Cooper Basin with suitable full azimuth seismic data. This process should be embedded in future field development plans.
Combining Managed Pressure Drilling and Advanced Surface Gas Detection Systems Enables Early Formation Evaluation and Enhances the Drilling Efficiency in a Deep Gas Exploratory Well in Saudi Arabia
Authors: Garrido Cruz Raul A. , Muqeem Muhammad A. , Alghuryafi Ahmed M. , Duran Roberto C. , Hadj-Moussa Ayoub , Mazouz Cherif M. , D'Souza Steve Austin , Aloudat Rami 
Published: September 2014

Abstract
Saudi Aramco recently drilled a gas well using Managed Pressure Drilling (MPD) as part of its exploration program. This well was the third exploratory well drilled with the objective to test the hydrocarbon potential of the sandstone reservoirs of Lower Permian era. Since a narrow drilling window between the reservoir gradient and the fracture gradient was expected, Constant Bottom-hole Pressure (CBHP) variant of MPD was planned to be utilized in this well.
There was no Nonproductive Time (NPT) during the MPD phase, hydrocarbon gas from the target formation was measured by the Gas Chromatograph (GC) and properly circulated out via the Automated MPD Control System without the need of conventional well control procedures. Average Rate of Penetration (ROP) increased by three-folds compared to the nearest offset well. Based on the real-time GC analysis, four zones within the target hole section show the most potential for hydrocarbons and further delineations are being planned for these intervals.
This paper summarizes Saudi Aramco's experience gained during the drilling of this well. It further highlights the operational complexity and the challenges faced during the implementation of this technology while drilling the exploratory well with very little offset information.
The paper also elaborates on the lessons learned and how they were implemented continuously with regards to Health, Safety and Environment (HSE) during the MPD operations. It is concluded that the use of an Automated MPD control system integrated with GC in Saudi Aramco's deep gas drilling project represents a technological improvement that will enable the company in achieving its goals in a safer and a more efficient manner.