bluuebunny/crossref_metadata_2025_split huggingface dataset:
Estimation of Petrophysical Parameters of Heterogeneous Carbonate Rock Sample with Multi-Scale CT Images
Authors: Sun Huafeng , Vega Sandra , Tao Guo , Yong Hong , Li Bing 
Published: November 2016

Abstract
The understanding of petrophysical properties is essential for the assessment and exploitation of hydrocarbon reserves. Reservoir rock is one of the main sources used to derive petrophysical properties by laboratory measurements. However, probing complex pore structure and heterogeneity of carbonate rocks are difficult with conventional experimental methods. Digital rock physics (DRP) is able to compute the petrophyscial parameters (e.g. porosity, permeability, elastic modulus) from three dimensional (3D) computed tomography (CT) images, which can make up for some disadvantages of traditional experiments. It also provides an understanding on how the large variations in petrophysical properties are caused by wide variations in pore type, pore shape, and pore interconnectivity.
This paper is a case study on analysis of heterogeneity and estimation of petrophysical parameters in a heterogeneous rudstone sample using multi-scale CT images with three resolutions of 39.48 μm/voxel, 1.0357 μm/voxel and 65 nm/voxel. The Back-scattered Electron Image (BSEI) analysis that is used to locate subsamples in low-resolution image for high-resolution CT scan shows the range of pore-throat radius size of this sample is from 0.1μm to 10μm and most pores are under 1μm. The low-resolution images (here resolution of 39.48 μm/voxel and 1.0357 μm/voxel) show a poor pore connectivity. The high-resolution image (65 nm/voxel) provide a more detailed pore structure that contributes to estimation of petrophysical properties. The estimated porosity (21.92%) and absolute permeability (6.54mD) from the high-resolution images are close to the lab measurements (22.7% and 4.9mD), which shows the accuracy of DRP in this particular sample. The relative errors of elastic modulus between the simulation and the measurements are 77.23% and 87.68% for bulk moduli and shear moduli, respectively. The image registration locates the Nano-CT images in the low-resolution image (1.0357 μm/voxel), which better characterize the pore geometry in different 3D image and provide a new way to do the upscaling work. The multi-scale images, the visualization of fluid velocity distribution, the lab measurements, and the simulated values show the heterogeneity of this carbonate sample.
Seismically Derived Porosity Prediction for Field Development- An Onshore Abu Dhabi Jurassic Carbonate Reservoir Case Study
Authors: Chatterjee Shraddha , Burreson Matthew , Six Bertrand , Michel Jean-Marc 
Published: November 2016

Abstract
A high quality broadband impedance solution by inverting seismic amplitudes is one of the most common industrial standards to integrate geophysical inputs into geological models during field development studies and planning. The use of accurately quantified petrophysical volumes derived from seismic data during geological model building can help improve the understanding of the reservoir and in maximizing the value of seismic data.
During this case study for two sour gas carbonate reservoirs- reservoir units C & D, in an onshore Abu Dhabi field, the acoustic impedance volume from seismic inversion and the seismic data itself were further converted into a porosity volume by a probabilistic neural network (PNN) approach. This non-linear transform approach establishes the link between seismically-derived impedance and porosity through an optimized training correlation and error method approach at each well location. A combination of the following factors pertaining to training dataset, established a successful neural network based porosity prediction workflow for the reservoirs: Amplitude preservation of seismic data (target-reservoir specific re-processing)Many calibration wells with good quality calculated log porosityHigh quality inverted seismic impedance.
A high correlation of predicted porosity to measured well porosity was achieved at all the well locations. In addition, reservoir unit C porosity grades from a very high but thinner porosity at the top to medium-high thicker porosity at the base, which was well resolved within the available seismic bandwidth and the PNN method of porosity prediction matched this variation of the log porosity. High cross-validation scores achieved during PNN training for porosity prediction, in effect provided the confidence in prediction away from the wells. Furthermore, a close match of predicted and measured porosity at blind test wells drilled in the field extended the confidence in the porosity prediction results. The porosity prediction successfully delineated regionally known non-porous lineaments and faults (encountered while drilling wells) on mean porosity maps of the two reservoirs.
The main objective of reservoir-focused reprocessing was to minimize the amplitude damaging effects of the near-surface, mainly due to presence of large sand dunes, and adequately prepare the data for seismic inversion. Successfully estimating seismically derived porosity was an important tool for well planning, geosteering long reach horizontals and also a key input for reservoir characterization to improve our understanding and distribution of reservoir properties in our geologic model.
Styles of Salt Tectonics in the Sab'atayn Basin, Onshore Yemen
Authors: Tari Gabor , Zabalza Isabelle , Neff Pascale , Dellmour Rudolf , Rodgers Emma , Asmar Chloe , Hagedorn Peter , Salman Adel 
Published: November 2016

Abstract
In the Sab'atayn Basin of Yemen hydrocarbons were generated from pre-salt Upper Jurassic source rocks during the Cenozoic and the salt provides the ultimate seal for the pre-salt and intra-salt traps. Therefore the proper understanding of salt tectonics is critical for ongoing hydrocarbon exploration efforts in the Sab'atayn Basin.
A variety of distinct salt tectonic features are present in the Sab'atayn Basin. Based on the regional interpretation of 2D seismic and locally available 3D seismic reflection data calibrated by exploration wells in the central part of the basin, an Upper Jurassic evaporite formation ("salt" from this point on) produced numerous salt rollers, pillows, reactive, flip-flop, active and falling diapirs.
Due to regional extension, halokinetics began by formation of salt rollers, as soon as the early Cretaceous, within just a few million years after the deposition of the Tithonian Sab'atayn Formation. The salt locally formed salt pillows which evolved to salt diapirs and diapiric salt walls as the result of renewed extension in the basin. As the result of a prominent extensional episode at the end of the Cretaceous most of the diapiric walls in the basin are controlled by large normal faults on their updip flanks. Some of the diapiric walls even evolved into falling diapirs due to ongoing extension. As the post-Cretaceous sedimentary cover is largely missing in the study area, the assumed reactivation of salt structures during the Cenozoic remains poorly constrained.
As the Sab'atayn Formation has typically several massive salt intervals in it, it defines post-, intra- and pre-salt play types in the basin. However, other than just providing traps and seals in the basin, salt tectonics is also very important for source rock maturation in the basin. As there are many salt diapirs in the study area, their cooling effect on the the pre-salt hydrocarbon kitchens appears to be quite significant, based on our preliminary basin modelling efforts.
Linking The Subsurface To The Surface Integrated Asset Modelling For A Super-Giant Oil Field To Optimize And Manage Production
Authors: Al-Jumah Ali , Doush Mohamad , Alharthy Said , Lalji Farhad 
Published: November 2016

Abstract
With limited and scarce subsurface and surface data, it becomes quite challenging to monitor a rather large field, having more than 50 wells actively producing, and actively optimize the production, achieving the desired production rates and maximizing the benefit for the operator and partners. The field in question was inherited from the previous operator, with 27 legacy wells, and a surface facility capable of processing ca. 100kbb/d of crude. Additional processing facility was installed to double the legacy capacity and 30 wells drilled by the time of preparing this paper for supplying the crude. The field had a shut-in period of 14 months in 2011-12 for various upgrades and surface works. It was then necessary to introduce an integrated modelling tool, to allow for a more efficient control and monitoring of the producing asset, combining all the components together and testing the interactions between the different system parts.
The Integrated Production System Model (IPSM) was built based on the principle of following the oil molecule from the pore throat to the export. As such, it comprises of three main components, linking the subsurface to the surface, those are: –Reservoir Models (built with Petex® MBAL©)–Well Models (built with Petex® PROSPER©)–Trunklines/Flowlines and Separators (built with Petex® GAP©)
Petroleum Experts® (Petex) develop the Integrated Production modelling software suite that comprises the tools mentioned above and are the company's proprietary. The current version of the IPSM is used in variety of situations; these include mainly but not limited to: ▪Medium Term Production Forecasting (MTPF)▪Production System Optimization (PSO)▪Opportunities assessment▪Identification of bottlenecks▪Further well scoping
The IPSM has facilitated the application of many processes, allowing for a faster and more informed decision making, these include: ▪Optimization: as required and identified in PSO Meetings, optimization activities are carried out as part of increasing the total system production output, which adds more value to this process▪MTPF: generated on a monthly basis, the MTPF clearly highlights the production pitfalls, and the expected targets with a given set of assumption, and honouring the constraints that exist in the system, allowing for proper future planning, and the need for well scoping studies and highlight of the requirements to meet the desirable targets▪Maturing opportunities and assessing their system gains and impact on system
This paper presents the process of building and maintaining an IPSM model throughout the different phases of a super giant field's life, from early production days with limited wells and data to the point of having real time data transferred to the office, fully utilizing the available data help make decisions that maximizes and eliminates waste.
High Temperature Cementing: Fluid Loss Control Polymers Performance and Limitations
Authors: Cadix A. , Wilson J. , Bzducha W. , Gomez J.-R. , Feuillette A. , Guichon H. , Thant K. , Nelson T. 
Published: November 2016

Abstract
Oil well cementing is a technically critical job and requires a well controlled placement along the wellbore and an even fill of the annular volume. As a consequence fluid loss control additives, preventing water from filtering into the formation are key ingredients of cement designs. These additives are often based on synthetic high molecular weight sulfonated copolymers.
The mechanism of action of these polymers has been studied recently and it was demonstrated that adsorption onto the cement surface is key to the achieve product performance. Unfortunately this adsorption yield is generally limited and typically performance decreases significantly as temperature increases. In order to overcome that loss, formulators typically increase loading to regain acceptable performance. Due to the high molecular weight nature of these AMPS copolymers, the subsequent drawback of increased loading is also an increase in cement slurry viscosity. In addition, as higher density slurries are typically used when downhole temperature increases, the problem is exacerbated and these limitations highlight the need for alternative technologies.
In this study we investigated the use of block copolymers comprising first a strong adsorbing block, then a long second hydrophilic block providing filtration control. This technology has already demonstrated to be very effective in preventing performance losses in presence of competitive formulation additives such as dispersant or retarders (see SPE173758). In this work, the behavior of such fluid loss additive is investigated in several cement grades and at elevated temperature.
Thanks to systematic methodology combining adsorption quantification with a standard HP/HT filtration, it is possible to quantify fluid loss polymer adsorption. This methodology using steric exclusion chromatography applies even in the case of complex formulations comprising retarders.
This work focuses on the analysis of the adsorption of fluid loss polymers on several cement grades and at elevated temperature.
Comparison of conventional copolymers and diblock copolymers show that conventional systems are very sensitive to cement grades even at moderate temperatures and gets very difficult to use above 100°C. On the other hand diblock copolymers are consistently performing at moderate temperature. Some potential performance limitation of this additive may occur at very high temperature if sulfate/aluminate balance of cement is such that ettringite thermal degradation can take place.
Fiber Optic Leak Detection FOLD Project
Authors: Baqué Marc 
Published: November 2016

Abstract

Fibre Optic Leak Detection (FOLD) Project
Recent news headline came to remind the dangers associated with gas transportation. Due to its asset size, pipelines are often the facilities the more difficult to protect in cases of an explosive gas leakage.
The objectives of the Fibre Optic Leak Detection (FOLD) project were to assess the capability of fibre optic sensing to detect a small gaseous leakage on a buried pipe, to give guidelines regarding the best deployment positions of the fibre along the pipe, to compare the performance of several methodologies and to assess the impact of the fibre optic length on the detection performance.
The strength of this project is to propose a representative test bench to help the industry to mature the detection methodologies: Gaseous leakages were performed from the external surface of a steel pipe with an internal diameter of 390 mm and a length of 30 m. These leakages were of methane, hydrogen or nitrogen and took place through different orifices (from 1 to 7 mm) and at varying released pressure (between 20 and 100 bar). This pipe and the optical cable were buried in a granular type soil compacted to a known level. Several types of interrogator (DTS - Distributed Temperature Sensor) from different suppliers were tested during the FOLD project.
The paper will present the experimental bench and the main results. Based on these results, it will be possible to conclude on the overall performance of the DTS technologies to detect a small gaseous leakage on a buried pipe, to give guidelines to optimise several parameters for improved detection performances: fibre optic position or deployment architecture along the pipe (directly buried or into a polyethylene tube), detection range assessment, equipment choice... Five different instrument suppliers took part in the initiative and delivered comprehensive data.
To make sure that detection will occur whatever the gaseous leakage flow rate on a buried pipe, it could be interesting to use both internal detection means (pressure or flowrate transducers placed at both ends) and external ones. Among the technologies available for external sensing, the optical fibre seems to be a promising candidate. This paper will present brand new data, collected in very controlled conditions, to assess the performance of such technology.
We will present the proportion of instruments capable of detecting leaks and the possible configurations presently recommended to pipeline designs in project phase.
Estimation of Relative Permeability from Laboratory Displacement Experiments Application of the Analytic Solution with Capillary Corrections
Authors: Deng Lichi , King Michael J. 
Published: November 2016

Abstract
Waterflood, or other forms of immiscible displacement, have been the most widely used mechanism for secondary recovery and the determination of individual phase's relative permeability has been crucial for many reservoir engineering applications. Traditionally there are two ways of determining the relative permeability from laboratory experiments: the steady state experiment and the unsteady state experiment. The steady state experiment has the disadvantages of being time-consuming, obtaining few points on the relative permeability curves, as well as not being identical to the true reservoir displcacement process. On the other hand, the Johnson-Bossler-Naumann (JBN) method, based on Buckley-Leverett (B-L) immiscible displacement theory, is the standard procedure used to determine relative permeability from unsteady state experiments. However, the neglect of capillary pressure effect in the Buckley-Leverett theory has placed limitations on the method, such as requiring high flow rates. In order to remove the limitations of the displacement experiments and give more flexibility to the experiment configuration, an analytic model with capillary corrections is presented in the context of viscous dominated flow to study the impact caused by capillarity. The solution shows a fixed water-oil saturation bank at the outlet whose magnitude depends upon the wettability of the system. The analytic model is able to predict the saturation profile, considering capillarity, under various rock and fluid properties and experimental configurations. Therefore, the model could be used to calculate accurate relative permeability by matching experimental pressure drop and production reponses, correcting for capillarity. Also, through this method, a dimensionless parameter could be provided to quantify the effect caused by capillary end effect based on the length scale affected. It reflects the influence from a variety of aspects, not only from the experimental settings.
Optimizing Seismic Survey Geometry with Blending Methods in a Transition Area
Authors: Ishiyama Tomohide , Ali Mohammed , Blacquiere Gerrit 
Published: November 2016

Abstract
Survey design should provide an efficient and practical survey geometry that meets the required survey parameters. Therefore, we have to seek an optimal geometry, taking survey productivity and constraints into consideration. In a transition area, the types of sources and receivers are various and mixed depending on the environment. They are independently deployed, allowing high flexibility in geometries with various roll and shooting patterns such as blending methods. In this paper, we tried to optimize the geometry with several shooting methods, maintaining the required parameters whilst enhancing the survey productivity. We will review and discuss the results of this case study.
An Evaluation Method of Snubbing Units in China
Authors: Liu He , Ming Eryang , Han Weiye , Li Tao , Li Yiliang , Pei Xiaohan , Sun Qiang , Huang Shouzhi 
Published: November 2016

Abstract
Since the popularizing of snubbing technique in China, a number of new types of snubbing units appeared in oil fields. Without new industrial standards, it was difficult for users to choose the exactly suitable units to fit into their conditions. Consequently, most units were inefficient and accompanied high maintenance cost. It is urgent to draft a rational selection reference for solving above problems.
This paper introduces an evaluation method on varied versatile snubbing units except those special units, including classification, rationales, characteristics, advantages & disadvantages, and costs. Based on investigation, by comparing rationales and analyzing structure characteristics, the snubbing units can be classified into several types. Advantages & disadvantages provide the comparisons of mobility, integration, theoretical efficiency and well site requirements. The cost evaluation which is composed of acquisition cost, operation cost and maintenance cost provides an economic effectiveness ranking among different types. According to these five aspects' comparisons, the rated ranges of use are provided.
According to this evaluation method, snubbing units in China are divided into 2 types, separated type and independent type, and subdivided into 5 subtypes. Normal rig-assistant type and single hydraulic power rig-assistant type belong to separated type. Rig-less type, vehicle-mounted integration type and hydraulic energy-storing service rig type belong to independent type. Each subtype associates with specific rationale and structure characteristics, and it is easy to identify by users. Furthermore, each subtype has unique level of mobility, integration, theoretical efficiency and well site requirements, which means that users have more accurate specifications to choose ideal snubbing units for their certain conditions. What is more, there is a cost evaluation to balance their budgets or anticipations before purchasing. For example, in the northeast of China, the well depth is average and it is a plain area. According to this method, mobility should be the main consideration in all matters. Therefore, vehicle-mounted integration type is highly recommended to the users from that area. However, in the southwest of China, because of the mountains, separated type is better. This selection reference is very convenient and effective for Chinese users.
The research result in this paper helps users, mainly, producers and managers to acquaint snubbing units' situations in China and to take advantage of that for better work performance. It promotes standardization of snubbing industry and has formed a new industrial standard. In addition, this result potentially improves the rate of capacity utilization which is particularly beneficial to petroleum industry.