bluuebunny/crossref_metadata_2025_split huggingface dataset:
Developments in Marine Seismic Acquisition: Wide-Tow and Beyond
Authors: Hager Ed 
Published: November 2016

Abstract
The future demands of exploration demand new techniques which increase the efficiency or quality, or even both of marine seismic data. This can be achieved by using the latest geophysical acquisition techniques and geometries in conjunction with developments in processing.
By using recently developed deflectors large wide-tow streamer spreads have become possible which allow for regional 3D surveys to replace 2D surveys, at a relatively low cost increase, but reducing the asset development time by basing initial target evaluation on 3D, albeit low quality, rather than 2D. To gain conventional quality 3D survey the lines can be interleaved to halve the cross-line bin size at a later date where needed based on the initial interpretation. We can also look to incorporating wide spreads with more than two sources –this maintains the spatial sampling and hence quality-but requires shorter shotpoint intervals so that inline fold is maintained. This implies that shots will overlap and that in processing shot interference removal is needed, but it is worth noting that the shot interference would typically start 5 seconds below the water-bottom, which is generally deeper than most targets and so a low-risk for interpretation, especially QI. We can even extend to five sources allowing for fine cross-line sampling for high-resolution surveys and by varying the streamer separations we can achieve an efficient acquisition. To achieve 5 sources with a reasonable volume the sub-arrays are used in more than one source definition and by spacing them equally the source separation can be maintained at 12.5m.
The removal of interfering shot energy is demonstrated on the Capreolus survey, North-West Shelf Australia where the survey covers data from very shallow water, ~100ms to very deep at several seconds showing the interference can be removed in a robust way in a variety of geological settings. Further the 5 source acquisition performed on the Baxter area, also NWS Australia, validates that fine cross-line sampling can be achieved in an efficient manner and is compared to a reference survey with a conventional geometry acquired at the same time. The conclusion from these two surveys is that the ability to remove interfering shot energy combined with multiple sources gives rise to a new range of options within marine seismic
The use of novel multi-source and/or wide-tow marine geometries finally opens up the possibilities in acquisition which then allows the operator to match better survey requirements to the development time-frames and costs.
Case Study: Forecast Performance of Potential Zone Using Artificial Intelligence AI in Deltaic Mature Field
Authors: Respati Pradhipta Seno , Ardan Cesti , Alfaqih Muchammad R. 
Published: November 2016

Abstract
Having characteristic deltaic sandstone with 72 multilayer reservoirs with 252 perforation history became more challenging when determining potential zone. It is challenging because most of all have already produced. Regarding low oil price, high success rate on evaluating potential zones are needed. Developing an artificial intelligent (AI) to evaluate performance of potential zone based on perforation history and log evaluation could increase its success rate.
Since log evaluation is used to determine potential zone, basic log evaluation parameter is used as input. There are also several zone characterizations to made AI more accurate such as; water zone, tight zone, and coal zone. Production history was used as an output and converted as 0–1. The output of this AI expected to predict cumulative production in one year in 0–1 index by iterated using Bournazel – Jeanson water breakthrough model to predict performance.
Artificial Intelligent has been implemented while determining workover program. There are eight workover programs that have been executed. All of them give an expected result based on artificial intelligent prediction. Three programs has been executed and produced more than a year. The production performance created by artificial intelligence are quite match within actual performance.
A Systematic Drilling Hydraulics Optimization Method for Improving Rate of Penetration and its Application in Ultra-Deep Wells
Authors: Meng X. , Zhou H. , Fan H. , Peng Q. , Deng S. 
Published: November 2016

Abstract
With the oil and gas exploration and development in deep formation and the number of deep wells grow continually, the ROP decreases greatly and the cost of drilling operation increases rapidly. A comprehensive procedure of optimization hydraulic design for improving ROP was formulated. It can conduct the integrated hydraulics design to improve ROP not only during making the drilling design, but also can generate recommendations of hydraulic optimization for improving ROP in the process of drilling based on the real-time drilling situation.
First, this paper presents a mathematical analysis of the hydraulics (Bit pressure drop, bit specific hydraulic horsepower, et al.) influence on the ROP based on the drilling engineering data of several wells of Tarim basin in west China,. In order to eliminate the influence caused by the difference of the other drilling data, all of them were normalized in this process. Second, according to the problem that no single rheology model can describe exactly the rheological properties of all types drilling fluids, a systemic hydraulic optimization approach was established, which is applicable for all common rheological models. For improving the design precision, the flow channel both in pipe and annuli was divided into several sections and the flow regime change of each section was considered. Moreover, for maximizing the ROP, the size of drill pipe size was considered during the process of hydraulics optimization.
The technology has been applied in several wells in Tarim basin of China and the test formations are about 3535m-6935m depth. Based on the novel and systematic method, the optimal drill assembly, flow rate, pump pressure, nozzle combination and others drilling parameters were all obtained. The results show that the ROP of these wells were improved about 10.5%~80%.
Through the application of the proposed method, the results show that the ROP in deep and ultra-deep well has been improved obviously, and which have decreased the cost of drilling operation greatly. Therefore, this method can afford an effective approach to improve ROP in deep well.
Horizontal Wells with Multistage Transverse and Longitudinal Fractures - What is the Optimal Production Scenario? Examples from Carbonate Reservoirs
Authors: Rahim Zillur , Al-Kanaan Adnan A. , Soliman M. Y. , Pacheco Eduardo 
Published: November 2016

Abstract
Strong demand for energy during the last decade influenced the increase in horizontal wells with multiple fracture stimulations. The strategy helped in increasing oil and gas production to meet the demand of internal and external markets.
Wells with transverse fractures have been the first option in low-permeability shale, sandstone, and carbonate formations. This is to increase the number of independently growing fractures thereby increasing the contact area. The fractures propagate transverse to the wells as they are drilled and completed in the direction of maximum in-situ stress (σmax). Many authors, however, have reported that in sandstone reservoirs, the efficiency of transverse fractures is affected by proppant pack permeability reduction due to non-Darcy flow. The study focuses on the best completion option for gas wells in terms of production performance and logistics that will ensure optimal field development.
Deep-Spectrum Gaschromatography and Carbon Isotopes Analysis While Drilling Enhance Value of Real-Time Formation Evaluation, Reducing Interpretation Uncertainty
Authors: Ferroni Gionata 
Published: November 2016

Abstract
Mud gas data represent the "first breath" of a well being drilled. However, despite significant progress in technology, techniques and theoretical understanding of mud gas detection and analysis, such data are still largely under-utilized by formation and fluid evaluation specialists.
This paper addresses such issue; it presents how new mud gas data realistically expand the limits of surface logging and redefine interpretation uncertainties.
The modern analysis process of hydrocarbons detection while drilling rests on three legs: First, advances in mud gas detection enable to analyze a broader spectrum of hydrocarbons directly on site, detecting more than 30 hydrocarbon species from methane to n-octane. This is coupled with the analysis of the carbon isotopic fingerprint of light components at the wellsite.
The second leg is constituted by a robust procedure covering all aspects of data acquisition, quality control and interpretation, applied systematically to the analysis process.
Finally, the third leg is the integrated utilization of all formation data available, from surface and downhole sources.
The principles described above have been applied in several projects worldwide. One of the main results is a significant reduction in the uncertainty in fluid-type indication. In fact, the utilization of chromatographic and isotopic data, simultaneously collected by entirely independent instruments, leaves limited doubt in fluid typing.
Furthermore, early isotopic data have permitted understanding some of the reservoir characteristics without waiting for laboratory sample tests.
Another important result is that the utilization of early formation evaluation data has enabled to optimize downhole data acquisition programs, with significant cost savings.
In all the successful cases, data interpretation has been carried out taking into account the geological context and utilizing models validated with laboratory data. The application of specific analysis procedures has also resulted in identifying reducible and non-reducible limits of mud gas detection and analysis.
The overall result of this approach is a significant reduction in data uncertainty in mud gas data. In the same time, it provides a realistic review of how far the analysis of light hydrocarbons can be extended, given the recent technology advances. Ultimately, a critical approach to surface logging-based formation evaluation techniques leads to a better understanding of the significance of such under-utilized although cost-effective data, and indicates the way forward for further development in this discipline, based, it should not be forgotten, on the direct and early analysis of the formation fluids.
Use of Nickel Nanoparticles for Promoting Aquathermolysis Reaction During Cyclic Steam Stimulation
Authors: Yi Siyuan , Babadagli Tayfun , Li Huazhou Andy 
Published: November 2016

Abstract
Late cycles of cyclic steam stimulation (CSS) are characterized with a decreasing heavy-oil recovery and an increasing water cut. Nickel nanoparticles can be used to promote aquathermolysis reactions between water and heavy oil in steam injection processes, thereby increasing the recovery factor. In this paper, detailed investigations were performed to determine the optimum operational parameters and answers to the following questions: (1) What is the optimum concentration of nickel nanoparticles for promoting aquathermolysis under high steam temperature?; (2) Can we improve oil recovery at lower steam temperatures with the presence of nickel nanoparticles?; (3) What effect does the penetration depth of nickel nanoparticles have on the final oil recovery?
CSS experiments were conducted between temperatures 150°C and 220°C. Steam generated under these temperatures was injected into sand packs saturated with Mexican heavy oil. Powder-form nickel nanoparticle was introduced into this process to boost the oil production. In an attempt to obtain the optimum concentration, different concentrations were tested. Next, oil sands without any nanoparticle additives were first added into the cylinder. Then, only one third of the sand pack was mixed with nickel nanoparticle near the injection port. Experiments were executed to study the effects of temperature, nickel concentrations, and nanoparticle penetration depth on the ultimate oil recovery and produced oil-water ratios after each cycle. Produced oil quality and emulsion formation were evaluated with gas-chromatography (GC) analysis, viscosity measurements, saturates-asphaltenes-resins-aromatics (SARA) test, and microscopic analysis of the effluents.
Experimental results show that the best concentration of nickel nanoparticles, which gives the highest ultimate oil recovery factor, is 0.20 wt% of initial oil in place (IOIP) under 220°C, while the nickel concentration of 0.05 wt% provides the highest recovery factors at the early stages. A lower temperature of 150°C provides a much lower recovery factor than 220°C, which is mainly due to a lower level of aquathermolysis reactions at 150°C. By analyzing the compositions of produced oil and gas samples with GC and SARA, we confirm that (1) the major reaction mechanism during the aquathermolysis reaction is the breakage of C-S bond, (2) the nickel nanoparticles can act as catalyst for the aquathermolysis reaction, and (3) the catalytic effect becomes less remarkable from cycle to cycle. One run of experiment to test the effect of particle penetration depth revealed that nickel nanoparticle distributed near the injection port greatly contributed to the ultimate recovery factor.
Simplified Local Density Theory for Modeling Adsorbed Gas and Estimation of Gas-In-Place of Unconventional Gas Condensate Reservoirs
Authors: Ma Yixin , Li Baoyan , Mezzatesta Alberto , Jamili Ahmad 
Published: November 2016

AbstractIn shale formations, a large amount of hydrocarbon fluid is stored inside the organic matters where the pore sizes are in the order of nanometer scales. Inside these nanopores, the interactions between the fluid molecules and porous walls play such an important role that can change the fluid properties of the stored hydrocarbons, causing adsorption. For unconventional gas condensate reservoirs, the adsorption of gas could be multi-layers adsorption, because of the small pore size and heavy hydrocarbon components in the kerogen source rocks. A Langmuir isotherm is not valid for modeling the adsorbed gas content and estimation of gas in place (GIP) for shale gas condensate reservoirs, because it is based on the assumption that the adsorption is a single molecule layer adsorption.To accurately determine the film thickness and density of adsorbed gas, we introduced the Simplified Local-Density (SLD) theory coupled and combined it with modified Peng-Robinson Equation of State (EOS) to model the thermodynamic behavior of the adsorbed gas and free gas of multi-component hydrocarbons, considering the pore confinement of the source rocks. The proposed method is applied to compute the Gas-In-Place (GIP) at initial condition of shale gas condensate systems. A GIP model considering the effects of adsorption was developed based on results from the SLD model.We first validated the model by comparing the results with available literature data. We also performed the sensitivity analysis and found that fluid density distributions in nanopores were temperature, pressure, pore size and fluid composition dependent. In general, the adsorbed amount increased by increasing pressure and decreased by increasing temperature. Heavier components tended to accumulate near the wall (adsorbed phase) while lighter component would like to stay in the center region of the pore (bulk phase). Then we performed a case study of real reservoir fluids in condensate window of Eagle Ford shale and calculate the adsorbed gas content and the total GIP using the introduced model. The preliminary computation results showed that the adsorbed gas could take more than 30% of gas in place in Eagle Ford shale.By using the introduced method, the adsorbed gas content and the total GIP in unconventional reservoirs can be calculated with good accuracy under short computational time. This makes the model useful when implemented into reservoir simulators.
A Novel Approach to Develop and Characterise Reservoir Properties in Multi-Layer Completions
Authors: Aguilar C. L. , Berzou M. , Al-Mannai A. , Nada H. , Al-Kharaz H. A. , Al-Buainain M. , Al-Mohannadi M. I. , Morshidi L. 
Published: November 2016

Abstract
Monitoring individual layer performance (in commingled completions) and integrating the results into an overall understanding of field performance has always been a challenge. Overcoming this challenge allows for a better, layer-by-layer, understanding of the reservoir, and therefore will have a significant impact on well and reservoir management. This paper presents a success case for the integration of a novel approach, and specific applications are highlighted.
The Khuff Formation of the North Field is a multi-layered carbonate reservoir formed from four main reservoirs; K1, K2, K3 and K4. As most of the RasGas wells are completed commingled through the main Khuff reservoirs, a hybrid approach for integrating multi-layer pressure transient analysis (PTA) with production logging tools (PLT) analysis of flow and pressure profiles was developed. The process also accounts for the physics of carbonate matrix acidisation. The outcome of this technique has helped RasGas better assess the stimulation effectiveness in commingled wells, and establish baseline performance for individual layers. This work was used to build improved inputs for reservoir simulation models, thus providing more accurate predictions of reservoir performance. Additional benefits of this technique have been: 1) identification of wells with impaired productivity (candidates wells for re-stimulation), 2) a better understanding of the stim jobs (areas for improvement for future jobs), and 3) an improved understanding of log kh vs test kh variation (to understand specific questions on well performance).
This paper discusses the outcomes, applications, and the added value of this integrated methodology. The paper will also demonstrate examples where the technology was applied and the value that was added to the ongoing surveillance and future development activities.
Comparison Study of Two Different Methods on the Localised Enkf on SAGD Processes
Authors: Huang Yingchao , Zhou Xiang , Zeng Fanhua 
Published: November 2016

Abstract
The localization on the automatic history matching of SAGD processes has not been studied. Also the distance-based localization is not applicable to SAGD processes. That is because in SAGD processes oil is produced mainly from the transition zone instead of regions centered producer. Distance cannot be used as the localization scale for SAGD processes. As the transition zone could be defined by temperature distribution, a new localization function with temperature as localization scale was developed.
The temperature-based localization function was obtained through modifying distance-based localization function. The localization regions were determined through covariance analysis by using a large ensemble. Based on the covariance analysis, the temperature range of the transition zone is determined. The localization function is 1.0 for the regions within this temperature range. Beyond or below this range, the localization function reduces from 1.0 and at the critical or steam temperature the localization function reduces to zero. The localization is applied to covariance of data with permeability, saturation and temperature, as well as the covariance of data with data.
The general localization function was developed by sensitivity analysis with synthetic cases. It could be applied to any SAGD cases with different steam temperatures and reservoir parameters. In the numerical simulation process, the history matching results showed that without localization, the variability in the ensemble collapsed very quickly and lost the ability to assimilate later data with a small ensemble (50 ensemble members) while the prediction was far from the reference with data mismatch remaining at a high level. The temperature-based localization is able to avoid the collapse of the ensemble variability with a smaller ensemble (10 ensemble members) which saves computation time and gives better history-match and prediction results. The computation time was analyzed in the work. With the temperature-based localization the computation time is greatly decreased by 75%. And another approach (localised EnKF with oil saturation) is also applied in this study to compare the calculation rate and accuracy. For this two methods, the localization regions should be the regions that have true correlations with production data. Dynamic data-temperature and oil saturation is used as localization scale in the localization function. And the temperature range and oil-saturation range is defined at which oil is flowing. And critical temperature is defined at which oil begins to get mobile. The localization function is 1 for regions in the temperature and oil saturation range, and decreases to 0 when the temperature reaches the steam temperature or critical temperature, or oil saturation reached initial oil saturation or residual oil saturation. To get the best history matching and prediction results, the localization function is applied to the Kalman gain and covariance matrices separately.
An Integrated Approach for Overpressure Prediction in a Wild Cat High Pressure, High Temperature Exploration Well in Offshore Sarawak, Malaysia
Authors: Chatterjee Avirup , Ghosh Amitava , Bordoloi Sanjeev , Mustapha Anifadora Bt. 
Published: November 2016

Abstract
Pore pressure prediction plays a very important role in well planning as exploration targets is shifting to deeper overpressured reservoirs. Pressure related problems in such zones are mainly associated with narrow operating window resulting in severe well control incidents, sometimes even leading to early abandonment. Uncertainties in prediction models arise from input data, assumptions used in the workflow and the complexity of the geological/structural conditions. It is important to analyse these uncertainties and develop an understanding of the same, prior to drilling so that, various plans and mitigation systems can be put in place.