bluuebunny/crossref_metadata_2025_split huggingface dataset:
Consistently Integrating Static and Dynamic Data in the Facies Model Description Using an Ensemble Based Approach
Authors: Sætrom Jon , Phade Anish , Vinther Morten Loell , Munck Tore Felix 
Published: November 2016

AbstractBuilding reservoir models that consistently honors static and dynamic data is a difficult, if not impossible, task using traditional approaches resulting from limitations of existing tools and best practice workflows. The crux of this task has traditionally been to utilize dynamic data in the facies modelling process, which is often the cornerstone of the reservoir modelling workflow. Hence, failing to integrate the static and dynamic data measurements in the facies modelling process consistently can dramatically reduce the predictability of the generated reservoir models. In this paper, we efficiently solved this problem using an ensemble-based approach in combination with an adaptive pluri-Gaussian facies modelling scheme. We demonstrate the procedure on a medium size field with 15 years of production history. During the dynamic data conditioning, clear trends are established in the facies model throughout the reservoir, which provide a good indication of the expected facies distribution and associated connectivity. Having a thorough description and understanding of the subsurface uncertainties - especially when it comes to the facies model description - is key to improved reservoir management decisions when considering both optimal drainage strategies and well placement.
Reservoir Characterisation and Modelling of the Nang Nuan Oil Field Thailand
Authors: Lurprommas T. , Hamon Y. , Lerat O. , Nantawuttisak J. 
Published: November 2016

Abstract
The main objective of this study is to construct a geological and static reservoir model of the interpreted karst reservoir in Nang Nuan Oil Field (NNN) in order to obtain hydrocarbon accumulation zone of the field. The target intervals are Permian Ratburi carbonate and Tertiary polymitic conglomerate which are suspected to be potential reservoir. This study started with the review of previous literatures and all available subsurface information such as conventional core, electric logs, production data, 3D seismic etc. Hence, the geological model was reconstructed and proposed to use for static reservoir model. Electrofacies was identified during the data preparation phase in order to get the link of lihofacies and electric log including petrophysical properties. The numerical model was constructed following the basic static reservoir modelling workflow. Regarding integration of all information in hand, the geological model of this study is partly different from the previous model. The most significant difference is the reservoir facies. This study proposes Tertiary conglomerate facies from interpreted alluvial fan deposits as the reservoir instead of Permian carbonates meanwhile the dissolution is still the main key of porosity development. In term of numerical model, the sequencial indicator simulation is used for distribute facies and petrophysical properties in spatial. According to the result of this study, the reservoir geometry and porosity development were changed from the existing model. The geometry of carbonate karst tower is restricted in term of the area meanwhile Tertiary conglomerate from alluvial fan deposits is more extensive and the key that advocates the increasing of dissolution is stratigraphic break. The result of this study changes reservoir facies which impacts possitively to distribution of petrophysical properties. Thus, the new model may lead to re-think of the field value and make it becomes viable again.
From Single Wireline Formation Tester Station to Reservoir Characterization: A Workflow to Evaluate Reservoir Compartmentalization
Authors: Bertolini A. , Betancourt S. , Duangprasert T. 
Published: November 2016

Abstract
Even with the sophisticated reservoir characterization techniques available today, the oil and gas industry develops and manages reservoirs under considerable uncertainty about their true properties. Two examples of these uncertainties particularly critical in deepwater projects are reservoir compartmentalization (lack of lateral and/or vertical connectivity because of geologic features or organic barriers) and flow assurance, both of which have a significant impact on reservoir understanding, field development planning, and productivity forecasts. Reservoir compartmentalization has been proven to be a persistent problem that mandates new methods and tools for reservoir evaluation.
Some operators have aggressive targets to bring their deepwater fields to production within 7 years of discovery. This implies that important decisions on field development have to be made with very limited information. The increased complexity of new discoveries in deepwater settings and the associated high developments costs demand improvements on reservoir analysis. Reservoir pressure analysis and downhole fluid analysis (DFA) from wireline formation testing (WFT) tools have enabling cost-effective assessment and measurement of fluid composition required to assess reservoir connectivity and early diagnostic of flow assurance issues. Pressure and DFA data coupled with the conventional cubic equation of state for dissolved gas-liquid analysis and the new Flory-Huggins-Zuo equation of state (FHZ EOS) for dissolved solid (asphaltene)-liquid analysis provide the opportunity to model the heavy-end fluid distribution from heavy oils to condensate. New data interpretation workflows centered on pressure analysis and DFA provide information on connectivity and fluid behavior useful for reducing the uncertainty when generating a field development plan.
A generic deepwater field is used here to illustrate the process of integrating wireline formation tester data (DFA and pressure) acquired during field exploration and appraisal in the generation of a field development plan (FDP). WFT data is used to evaluate the variation of fluid properties and pressure gradients in the reservoir and delineate compartments. This data improves understanding of the reservoir structure and gives a model that is closer to reality that is used in an optimization workflow to generate a field development plan (FDP). Another (optimal) FDP is also generated using the reservoir model created when WFT information is not used. These two FDPs based on approximate reservoir models are implemented on the "real" reservoir structure, known in this exercise, to quantify the value of WFT information.
Dynamic Embedded Discrete Fracture Multi-Continuum Model for the Simulation of Fractured Shale Reservoirs
Authors: Chai Z. , Yan B. , Killough J. E. , Wang Y. 
Published: November 2016

Abstract
The wide implementation of hydraulic fracturing in shale reservoirs and the interactions among hydraulic fractures, natural fractures and the shale matrix have brought great challenge for reservoir studies using conventional finite-difference-based reservoir simulators. This work establishes a dynamic approach for the simulation of fractured shale reservoirs that incorporate the embedded discrete fracture model (EDFM) as well as the multiple porosity model, which is necessary for simulating the complex transportation process in shale reservoirs.
In this paper, we extend the EDFM approach for fractured shale reservoirs to a multi-continuum context, in which one fracture segment can have mass transfer with multiple parent grid blocks in favor of the complex porosity types of shale formations. The reservoir model can be updated dynamically during the simulation with our in-house simulator to consider the change of the fracture network due to fracking and refracking at different stages of field development. This is achieved by altering the effective non-neighbor connections with time that are associated with the fracture system. Therefore the reservoir with a changing fracture distribution can be modeled with a single simulation. The formulation is based on finite volume rather than finite difference to facilitate the unstructured nature of the reservoir model.
The result is compared with the explicit fracture model with PEBI grid blocks to evaluate its accuracy. For the test case of a horizontal well with multiple hydraulic fractures and large scale natural fractures, the simulation result can be matched with great accuracy. Sensitivity analysis to grid refinement is also conducted, which proves the model only need moderate grid refinement to obtain desirable accuracy.
This work established a more flexible and efficient yet more accurate approach for fractured shale reservoir modeling, with the emphasis on improving the ability to model the fluid transportation among different porosity types. The proposed model improves the simulation by reducing the complexity of the gridding process, cutting the total number of grid blocks, and significantly decreasing the CPU time. It provides a coherent method for characterizing the fluid transportation in fractured shale reservoirs, which is usually a difficult task with traditional reservoir models.
Development of Marine Seismic Vibrator towards Realization of Shear Wave Source with No Touch-Down to Seafloor
Authors: Ozasa Hiroaki , Sato Fumio , Asakawa Eiichi , Murakami Fumitoshi , Jamali Hondori Ehsan , Takekawa Junichi , Mikada Hitoshi 
Published: November 2016

Abstract
We developed a towed marine seismic vibrator (MSV) as a new type marine seismic source that employed the hydraulic servo system for the controllability both in phase and in amplitude of the signal being emitted. MSV could mitigate a risk of the impact to the marine environment while satisfying the necessary condition of seismic sources and could enable shear wave analysis in the marine environment to improve the situation of marine seismic data acquisition. We conducted a sea trial to acquire seismic reflection data using a downsized MSV and a streamer cable above the seafloor where a cabled seismic observatory has been deployed. A series of controlled chirp signals was generated by MSV. The sea trial showed that penetration of seismic signals generated by the downsized MSV was comparable to that by an airgun of 480 cu-inch with a slight inferior signal-to-noise ratio. We could observe the improvement in the penetration of seismic signals for the downsized MSV towed deeper that is preferable to generate shear waves. Finally, we could observe that the amplitude of shear waves, which are reflected back from the subseafloor structure, is acquired by the horizontal components of a seafloor installed seismometer.
Simulation Study of Foam Displacement at Pore and Reservoir Scale
Authors: Xia Jun , Li Xiangfang , Zang Jiali , Zhou Tong , Li Jing , Bai Jie , Jiang Mingjie , Zhang Zenghua , Chen Yu 
Published: November 2016

AbstractAlthough the microscopic mechanisms of foam generation, migration, coalescence and collapse are well studied in many laboratory experiments, it is still inappropriate to apply the experimental results to the field directly. At reservoir scale, the velocity and shape of foam displacement front should be emphasized rather than the foam behavior.Based on a heterogeneous low permeability oil reservoir with horizontal fractures which locates in western China, a numerical foam flooding simulation model is built. Sensitivity analysis is conducted through changing parameters in three aspects. For the first aspect, geological properties such as reservoir permeability, porosity, oil saturation as well as horizontal fracture aperture are discussed. The second aspect includes foam half-life and its adsorption amount on formation rocks. In the last aspect, injection parameters like gas-liquid ratio, injection circle, and injected pore volume of foam are discussed.Simulation results demonstrate that the foam displacement velocity are largely affected by the formation permeability and porosity. Large pore size means that bubbles population could be easily created with the result of great increase of foam resistance capacity. The foam flooding front moves faster with increasing porosity and permeability when they are both above the limited values. While oil saturation and horizontal fracture aperture have an important impact on the shape of foam displacement front, foam system tends to avoid the pay zone with high oil saturation and percolates preferably into the horizontal fractures. High oil saturation leads to the collapse of foam displacement front and transfers it into surfactant flooding. The comparison of simulation works shows that both foam displacement velocity and front shape are closely related with injection pressure and injection cycles. With longer alternating period, the foam flooding front could propagate over a larger distance. The larger the injection pressure is, the more uniform the displacement front is.This work is using simulation tool to analyze the impact of geological properties, foam system and injection parameters on the velocity and shape of foam displacement front. This is verified by field trials which provides some insight to the application of foam flooding at reservoir scale.
3D Close the Loop using Probabilistic Seismic Inversion for a Gas Field in Carnarvon Basin / Australia
Authors: Srivastava Shilpi , Goudswaard Jeroen , Busman Sito , Ugbo Justin 
Published: November 2016

Abstract
The study area is located in the Carnarvon Basin, offshore Western Australia. The paper discusses an approach for predicting the lateral variation of Net-to-Gross using 3D probabilistic seismic inversion. The goal is to define and understand the distribution of sands and shales on the basis of seismic reflection data. This modelling and inversion is supported by the good quality of seismic data. The seismic amplitude patterns indicate hydrocarbon presence and variation in properties like Net-to-Gross.
Qualitative 3D CtL ("Check the Loop") is used to highlight the mismatches between the forward modelled synthetic data generated from the model and the actual seismic. The possible causes of these mismatches are investigated and suggestions are made to improve the model in the key areas of mismatch. The Quantitative 3D CtL is used to further constrain the reservoir model by the seismic data. A 3D probabilistic seismic inversion for the main uncertain reservoir parameter using Shell's proprietary stochastic model-based elastic inversion algorithm is deployed.
After the 3D CtL with the static reservoir model, reserves in both North and South blocks of the field were reduced, whereas the probabilistic inversion highlighted the presence of a high Net-to-Gross (NtG) channelized feature which facilitated an additional volume booking for the central block. These insights immediately impacted development decisions.
This study underpins the benefits of seismically constrained reservoir modelling. The use of probabilistic inversion to map out geological features (like higher NtG channels) is a new insight in the applicability of this methodology.
Current State and Future Trends of Wireline Formation Testing Downhole Fluid Analysis for Improved Reservoir Fluid Evaluation
Authors: Ramaswami S. R. , Cornelisse P. W. , Mooijer M. , Kim I. , Elshahawi H. , Dong C. L. 
Published: November 2016

Abstract
The introduction of downhole fluid analysis (DFA) two decades ago was a major addition to the wireline formation testing suite of measurements previously available in the industry, both in real-time to optimize the sampling operations and to provide additional fluid measurements as an integral component of integrated fluid property interpretations. The progression from basic measurements such as fluid resistivity to advanced optical analysis has paved the way for much improved definition of reservoir fluids, including the variation of fluids within reservoirs.
Downhole Fluid Analysis is a continuously evolving field, so we will begin this paper by looking back at the evolution and application of various types of sensors for operational real-time decision making as well as post-operational fluid evaluation. We will then highlight current capability gaps, focusing on the need for improved real-time contamination monitoring in some environments of interest and our desire to measure additional fluid properties and specific species concentrations.
A Theoretical Model for Dynamic Performance Prediction of Air-Foam Flooding in Heterogeneous Reservoirs
Authors: Yang Jun , Wang Xiangzeng , Wang Shubao , Gao Ruimin , Zhang Yizhong , Yang Yongchao , Zeng Fanhua 
Published: November 2016

AbstractAir-foam flooding has already been pilot-tested and approved as a feasible and promising EOR method in tight oil reservoir. This study is to develop a simple but effective model to predict dynamic performance of air-foam flooding by considering main physical and chemical mechanisms in this process, such as gas channeling caused by mobility difference, flue gas driving and instability of foam.According to the instability of foam, a new model is proposed to estimate recovery factor, which separates foam flooding status into three areas, including gas, water and foam area. Prediction of breakthrough time is critical for this model, which is estimated according to relation between area being swept and area to be swept by cycle of injected slug. Once the breakthrough time of gas and surfactant solution are estimated, dynamic performance of every stage during air-foam flooding is predictable. Relation between recovery factor and production time or PV can be predicted, if essential reservoir, fluid and operational parameters are provided.Relative numerical simulation studies on homogeneous case and heterogeneous case are both introduced to validate proposed model. Results of comparison suggest this model is highly consistent with the numerical simulation results. The most extreme difference in recovery factor after ten years between proposed method and simulation is less than 6.2%, which is less than 2.5% in most case. Meanwhile, this model requires much less input data than numerical simulation for dynamic performance prediction, which makes it a really convenient tool to evaluate potential of an air-foam flooding project. Sensitivity analysis is introduced to study effects of variation in parameters on the performance of air-foam flooding project, including fluid injection rate, slug size, slug proportion and reservoir heterogeneity. The higher liquid ratio is injected in each slug, the better recovery factor is obtained. However, there isn't much difference once liquid ratio is higher than 50%. Recovery factor increases with higher fluid injection rate. Meanwhile, the increasing rate of recovery factor drops as fluid injection rate increases. Also, optimum slug size exists which means any slug size being higher or lower this value would result in lower recovery factor. These conclusions can help get optimized operational parameters once economic data are settled.This proposed model considered major mechanisms in air-foam flooding and related reservoir, fluid and operational parameters, and provided a fast approach to predict dynamic performance of air-foam flooding and can be used as a tool to optimize the operational parameters. The core idea of this method, such as the estimation of breakthrough time, also provides a new approach to estimate the performance of other immiscible flooding method.
Production Diagnostic Analysis and Optimisation in Complex High GOR Horizontal Oil Producer
Authors: Kyi Ko Ko , Amin M Farid B M , Alam Bambang Noor , Salleh N Hajjar , Yaakob A Afiq , Wa Wee Wei , Haddad Sammy , Johan Zailily , Wijoseno Danny Aryo , Devan Thesigan 
Published: November 2016

AbstractHorizontal wells have been an important development option for oil production due to the increased exposure to the hydrocarbon bearing interval in the long open section. Nevertheless, there are several typical complications associated with the horizontal well production. Firstly, the barefoot completion often collapses after certain period of production and to prevent that, a slotted liner is installed across the open-hole section to provide required mechanical support and improve the wellbore stability. Next, the permeability distribution can be in great contrast from heel to toe and this necessitates the installation of an inflow control device (ICD) to avoid premature gas or water breakthrough that can easily kill the oil production. All the aforementioned completions, while helping to optimise the oil production, can complicate further the flow regime in the horizontal section and make production monitoring very difficult. The questions like phase stratification, flow behind slotted liner and production source for fluid entering ICD need to be answered for accurate production diagnostics in such horizontal completions.This paper presents successful production diagnostic work performed in a problematic and complex long horizontal oil well, completed with both slotted liner and ICD. The well has been suffering from increasing GOR three weeks into production in year 2012 and was produced with the lowest choke size since then and eventually shut off to avoid excessive gas production. The source of the gas needed to be identified to perform gas shut-off. The production diagnostic work started with thorough clean-out of the long horizontal slotted liner and ICD sections via active coil tubing. The clean-out was proven to be efficient and the well was successfully beaned up to high oil production rate for subsequent flow profile diagnostics. The complex flow regime in this complicated horizontal completion was well identified by the multi-spinner, multi probe production logging (PL) tool deployed using the active coil tubing.The production log interpretation, the historical production plot and the surface well test results were integrated and provided the required information to determine the forward production strategy in this horizontal oil producer. The planning and the implementation of active coil tubing cleaning and multi-spinner, multi probe PL, as well as lessons learned and best practices throughout this production diagnostic work, will be discussed.
Quantifying Carbonate Heterogeneities that Impact Flow in Reservoirs: Lessons Learned from the Central Luconia Gas Fields, Malaysia
Authors: Warrlich G. M. , Ryba A. , Adams E. , Tam T. , Chiew E. C. , Angelatos M. , Soo D. K. , Lojikim Chrissie 
Published: November 2016

Extended Abstract
Carbonate fields in Central Luconia have been delivering gas for about 30 years and petroleum engineers have been collecting large amounts of static and dynamic data by exploring, appraising and producing these Miocene platforms hosting the gas. The knowledge acquired is presently used to optimize existing field recovery, develop new fields without production data and reduce geohazards for drilling operations. It also provides an outstanding data set that can be extrapolated to understand the role of reservoir heterogeneities and hydrocarbon properties on production behavior and recovery in similar fields with less data outside Luconia.