bluuebunny/crossref_metadata_2025_split huggingface dataset:
Application of a Deconvolution Technique in PTA for Enhanced Reservoir Characterization
Authors: Ahmad S. B. , BinAkresh S. A. , Anisur Rahman N. M. 
Published: July 2016

Abstract
Current trends toward permanent downhole instrumentation allow the acquisition of large sets of well test data, ranging over much longer periods of time than was possible in the past. Such data sets can contain information about the reservoir at a substantially larger radius of investigation than the one accessible to conventional well test analysis methods, which is limited to the interpretation of single flow periods at constant rates. By contrast, deconvolution methods do not suffer from such a constraint as these are designed to perform analyses at variable flow rates. Deconvolution is a technique, which can be used to convert measured transient pressures from variable rate changes into the transient pressure response as a result of an equivalent constant flowing rate.
In this study, we will discuss a field case from an intelligent field, where deconvolution techniques have been successfully implemented in pressure transient analyses. The subject intelligent field has generated large data sets that span months to years. The case study showed that the additional reservoir characterization has been achieved through revealing responses in deeper regions of investigation, which would have been impossible without applying a deconvolution technique. The technique has proven the communication between reservoir layers and identifies the presence of aquifer. Methods independent of the deconvolution methods have suggested aquifer volumes that are very close to the one determined from the transient model. The upper completed layer is isolated from high porosity, high permeability zone below it, which has not been obvious from the conventional analysis of data within the normal test duration. Deconvolution method used managed to address the issue and allow the utilization of the complete data set for enhanced reservoir characterization.
Surfactant Derived from Natural Renewable Product for SP Flooding in High Temperature, Low Salinity Reservoir
Authors: Hongyan Cai , Qiang Wang , Jian Fan , Wanlu Liu , Wenli Luo , Ming Gao , Zhengbo Wang 
Published: July 2016

Abstract
Surfactant/Polymer binary flooding technique has become one of the most important research fields in CEOR due to the prevention of side-effects of alkali. Nevertheless, the lack of efficient surfactant greatly restricts the in-lab evaluation and field application of this promising technique. Without the help of alkali, surfactants with higher interfacial activity are needed in SP flooding compared with their counterparts in ASP. It is even harder to find an ideal surfactant for SP flooding in high temperature, low salinity reservoir because the requirements on stability and interfacial tension decreasing capability of surfactant become more challenging.
A betaine surfactant derived from oleic acid, which is a product hydrolyzed from renewable conventional vegetable oil, was prepared through four step reactions. Related SP formulation utilizing this betaine was developed for a high temperature, low salinity sandstone reservoir with formation temperature at 85°C and brine salinity at 1270 mg/L. Comprehensive evaluations, including interfacial activity with crude oil, phase behavior, static adsorption, and long term thermal stability were preformed for this surfactant.
The results showed for the solutions of prepared oleic acid derived betaine surfactant with concentrations ranging from 0.03%wt to 0.20%wt, ultralow interfacial tensions were reached with crude oil, demonstrating higher interfacial activity compared with conventional surfactants used in high temperature, high salinity reservoirs. Phase behavior test showed lower phase microemulsion was formed. Static adsorption and long term thermal stability tests also showed qualified results. Nature core flooding tests demonstrated for the selected SP formulation, the enhanced oil recovery of chemical flooding reached 15.2%.
The Developed betaine surfactant showed good performance for SP flooding in high temperature, low salinity reservoir. It bridges natural renewable product and enhanced oil recovery of fossil fuel, which is in accordance with sustainable development concept and displays a promising direction for the R&D of green and efficient alkali-free surfactant.
Transforming Oil Tracer Studies
Authors: Ellis Erika S , Kosynkin Dmitry , Askar Mohammad N 
Published: July 2016

Abstract
Chemical and radioactive tracers have been used for decades in the oil industry to track injected fluids to map inter-well permeable paths (as passive tracers) and as active tracers to identify reservoirs that are specifically suited for EOR operations by detecting residual oil saturation. The down side of using these types of tracers is the high cost of materials, time consuming collection, costly lab analysis and high safety hazards of the materials themselves. Saudi Aramco's Reservoir Engineering Team has made significant progress towards using nanoparticles as active and passive reservoir tracers that are inexpensive, easy to produce and pose very low safety hazards personally or environmentally. Additionally, Aramco has been developing a portable stand-alone system that can detect these advanced nanoparticle tracers in real-time, directly from the well head with no need for sample collection or lab analysis and can run without operator intervention for at least three months. This paper presents the prototype stand-alone sensing system for advanced nanoparticle tracers which has the potential to transform the efficiency of current nanoparticle oil tracing practices by nearly 99% by reducing collection and processing time from around 10 hours to &lt;5 minutes in real time. Recent results show the system's ability to separate, purify and detect fluorescent nanotracers from produced water to 0.1ppm levels in a portable inline process.
Effects of Multiple Transport Mechanisms on Shale Gas Production Behavior
Authors: Negara Ardiansyah , Sun Shuyu 
Published: July 2016

Abstract
Gas transport in extremely low-permeability shale formations is a multi-mechanisms-coupling process that includes gas adsorption-desorption, Knudsen diffusion, and slip flow. Incorporating these mechanisms into a unified mathematical model is crucial to obtain a more accurate shale gas production behavior. The objective of this paper is to investigate the effect of each mechanism on shale gas production behavior. We establish shale gas dual-porosity dual-permeability model that incorporates gas adsorption-desorption, Knudsen diffusion, and slip flow as well as the thermodynamics calculations. Peng-Robinson equation of state (PR-EOS) was used to calculate the gas density and compressibility factor by solving the cubic equation. In our model, gas adsorption-desorption obeys the Langmuir's isotherm as a function of reservoir pressure. Furthermore, gas viscosity changes with Knudsen number during the pressure depletion; and pore radius will increase when the adsorption gas desorbs from the pore wall. In the numerical method implementation, we combine the finite volume method with the experimenting pressure field approach to obtain the pressure distribution in the matrix and fracture systems. In this study, we investigate the effects of adsorption, Knudsen diffusion, and gas-slippage (Klinkenberg effect) on shale production behavior. We switch each mechanism on and off in the model to observe its effect on the production performance. It is observed from the results that among these mechanisms, adsorption has a great influence on gas production. Ignoring adsorbed gas would lead to a lower cumulative production. Meanwhile, the effects of Knudsen diffusion and slip flow are not as significant as adsorption. In particular for the example presented in this paper, neglecting adsorption will decrease the production nearly 80% compared to 15%-18% when Knudsen diffusion and slip flow are ignored. Knudsen diffusion and slip flow have less impact on the production because both mechanisms occurs in the matrix and contribute only to the apparent permeability, while the production is mainly determined by the fracture permeability, which is critical in determining fluid flow from the fracture system to the wellbore.
A Novel Approach to Compare Pressure Regimes for Compartment Identification in Low Mobility Environment
Authors: Sharma Shivam , Batshas Siddhanta , Joshi Sameer , Tewari Shagun , Shukla Sourabh , Agarwal Ankit 
Published: July 2016

Abstract
Formation pressures recorded by Wireline Formation Testers are widely used for identification of compartments based on the pressure regimes. If two virgin zones are at the same pressure regime, it is not a sufficient condition to conclude that they will be in communication during the production life of the field. This is because pressure equilibrium has been attained over geological timescale and the zones may or may not be in communication in the production timespan. But on the other hand, if two virgin zones are found to be at different pressure regime, it can be safely concluded that the zones will not be in communication and thus, belong to separate compartments. While such analysis can be easily carried out for high mobility/ permeability zones, interpretation in case of low mobility zones is often challenging. In low mobility environment the pressures are not very reliable due to incomplete stabilization of buildup and supercharging effects. It is a big challenge to find whether 2 zones have same pressure regimes or not in low mobility scenario. This limitation hinders effective usage of pressure data when formation mobility is low.
In the current study, a novel approach has been adopted to analyse the pressures measured by formation testers across multiple zones. For diagnosis of the pressure regimes, a cross plot of excess pressure (Alton Brown et al. AAPG, 2003) versus mobility has been used. This cross plot resembles an exponential decline trend for all the points lying in the same pressure regime. The empirical relationship is supported by analytical models available in the prior literature. Under virgin conditions, the zone whose excess pressure points do not lie on the postulated curve is in all likelihood at a different pressure regime.
The workflow has been tested on multiple data sets from various exploratory wells in India. Using this technique, it became possible to identify separate compartments in low mobility environment. For validation, this technique was applied on the data sets where one or two high mobility points were also available. The compartment identification from excess pressure mobility cross plot corroborated with the interpretation based on the high mobility pressure points.
A Systematic Technique of Production Forecast for Fractured Vuggy Carbonate Gas Condensate Reservoirs
Authors: Li Yong , Zhang Jing , Liu Zhiliang , Li Baozhu , Deng Xingliang 
Published: July 2016

Abstract
Naturally fractured-vuggy carbonate gas condensate reservoirs in China have some distinctive characteristics: deep buried depth, multi-scale fractures, vugs and caves developed, poor reservoir connectivity and high production decline rate. It is hard to build effective geological models and run reservoir simulation for production forecasting. So how to properly forecast the performance of this kind of reservoirs is a major challenge. This paper presents a systematic technique of production forecast to solve this problem.
The systematic technique mainly involves analytical and numerical production analysis (PA), analytical and numerical pressure transient analysis (PTA) and material balance analysis in combination with the geological analysis results. Firstly, using the analytical PA and PTA can quickly and correctly evaluate reservoir properties. Take Tazhong No.1 carbonate gas condensate reservoir in China for example to elaborate the details of this method. The results show that the systematic method can not only properly calculate the reservoir properties, but also can quickly and properly forecast reservoir performance of fractured vuggy carbonate gas condensate reservoirs. And the calibrated dynamic numerical model can both match well production history data and well pressure data. Examples are presented to show how these material balance analysis, analytical and numerical PA and PTA methods fully integrated and constrained with each other, and how the reliable results can be generated finally. Because of the poor connectivity characteristic of Tazhong No. 1 field, dynamic models for each fractured-caved unit should be built and applied for performance prediction.
Optimizing Water Flood Performance to Improve Injector Efficiency in Fractured low-Permeability Reservoirs Using Streamline Simulation
Authors: Li Junchao , Lei Zhengdong , Li Shujun , Zhang Ran , Wang Fang , Yu Tao , Su Yantao , Tang Zichun 
Published: July 2016

Abstract

Objectives/Scope
Waterflooding has been the main development method for maintaining the formation energy in low-permeability reservoirs. Often these reservoirs are characterized by poor sweep and high water cut of oil wells due to natural fractures. Streamline technology is an ideal tool for optimization of waterflooding operations. One of the main advantages of streamline simulation is to display paths of fluid flow and to calculate rate allocation factors. However, describing fluid transport in fractured low-permeability reservoirs entails additional challenge because of the complicated physics arising from matrix-fracture interactions.

Methods, Procedures, Process
In this paper we demonstrate a straightforward workflow for optimizing injection rate based on a comprehensive analysis of injector efficiency (IE). First, the streamline model including improved transfer function and non-Darcy flow of matrix is generalized to describe fluid transport. In particular, the streamline time of flight concept is utilized to develop a general dual porosity dual permeability system of equations for water injection in naturally fractured reservoirs. The streamlines can be derived from the flux field of this model that represent a snapshot of the flow pattern within the reservoir, well drainage region information and fluid allocation changes with the flood progression. Second, using an analytical calculation to compute weighting factors for injection/production rate targets from a derived ranking of the wells (IE). Finally, reallocation of injected fluid volumes from low-efficiency to high-efficiency injectors improves volumetric displacement and sweep efficiency in the less swept areas of the reservoir. The application of this workflow is demonstrated with a real-field example of an fractured low-permeability sandstone reservoir in Chang Qing oilfield in China where the pattern balancing has led to incremental production over the 5 years forecast in which the IE average of the field is the benchmark while obeying facility constraints.

Results, Observations, Conclusions
The results indicate that water cycling was quantified by streamline simulation and water injection with a decrease of 30-40% on the maximum principal stress direction causes in a reduction in the produced water volumes. A new water injection strategy was implemented, and a decrease in water cut on this challenge sector was achieved in the targeted producers.

Novel/Additive Information
This work provides a comprehensive case study and useful method for better understanding the fractures on waterflooding performance and optimizing production plan of maximizing oil recovery on the fractured low-permeability reservoir.
Evaluation of a New Elemental Spectroscopy Device for Carbonates in Saudi Arabia
Authors: Saldungaray Pablo , Al-Tajar Firas , MacDonald Robin , Musharfi Nedhal 
Published: July 2016

Abstract
Elemental Spectroscopy measurements have become a standard component of the logging program in Exploration, Delineation and special Evaluation wells for Saudi Aramco. Elemental Spectroscopy data has proved critical when evaluating complex lithology formations in both siliciclastic and carbonate rocks to produce an accurate mineralogy analysis, resulting in good understanding of the subsurface lithology in a cost effective way.
A rigorous qualification protocol is applied to novel services when they are introduced to Saudi Aramco. New measurements are compared to existing equivalent services if available and to core data if applicable. For the specific case of the new Elemental Spectroscopy device, the elemental outputs were compared to a previous generation tool and to elemental concentrations from core measurements in a wide variety of formations and lithologies in clastic and carbonate reservoirs. Clastic reservoirs were covered in previous publications; in this work we show the results for carbonate rocks.
Initial comparisons between the previous and new generation tools showed good agreement for most of the elements except for Mg (Magnesium) at low concentrations. Several samples were selected from Jurassic carbonate reservoirs to understand better differences at low Mg concentrations. All samples were taken as 1 foot side trims from a full core slab. The samples were crushed and homogenized to minimize the effects of heterogeneity. The prepared samples were analyzed using X-ray fluorescence (XRF) for elemental concentrations and Dual Range Fourier Transform Infrared Spectroscopy mineralogy (DT-FTIR) for mineralogy. The elemental results from both tools and the core samples were then plotted and compared.
While existing measurements work in many areas, there are specific cases where the new technology can generate improved formation evaluation in carbonate formations or increase efficiency by logging faster.
Fractured Shale Gas Reservoir Development Evaluation Based on Discrete Fracture Model
Authors: Mi Lidong , Zhang Yanqing , Jiang Hanqiao , Wang Zhifa , Li Junjian , Liu Chuanbin , Liang Bin , An Cheng 
Published: July 2016

Abstract
The present paper evaluates the development effectiveness of fractured shale gas reservoirs by fractured horizontal wells based on discrete fracture model. In this model, the flow in matrix meets "non-Darcy law" because of the ultralow permeability when using "Cubic law" to describe the flow in fracture that is high flow conductivity and the simulation is carried out by solving the nonlinear partial differential equations using finite element method. The method of fracture treatment in this model is more suitable to characterize the function of individual fracture than the traditional method. Establishing several conceptual models with different fracture parameters to investigate the exploitation characteristic by multistage fracturing horizontal well. The preliminary simulation results show that: (1) Horizontal well is superior to vertical well when developing the fractured shale gas reservoir. (2) Multistage fracturing horizontal well is an effective method to amplify drainage area and raise well production. (3) Improving the natural fracture properties, such as fracture aperture that connect to hydraulic fracture, is important to improve development effect. (4) Well type, horizontal well length, hydraulic fracture number, spacing, length and natural fracture aperture are the main factors that determining the development effect of fractured shale gas reservoir. Therefore, Horizontal well development, multistage fracturing horizontal well, extending horizontal well length, enhancing the natural fracture aperture that connect to hydraulic fractures, increasing hydraulic fracture number and shorting hydraulic fracture spacing is helpful to improve the development effect of shale gas reservoir.
Cost Effective Chelating Agent EOR Fluid System for Carbonate Reservoirs
Authors: M. Hassan Amjed , S. Al-Hashim Hasan 
Published: July 2016

Abstract
This paper presents a new approach for flooding carbonate reservoirs using chelating agent fluid system prepared using seawater without dilution. Sequential coreflooding tests using limestone core samples following seawater flooding with an increasing concentration of the chelating agent EOR fluids revealed significant incremental oil recovery ranging from 16 to 26%OOIP without any significant increase in the pressure drops. The sequential flooding starts with small concentrations of the chelating agent EOR fluid to alter the wettability of the limestone surface to a more water wet condition through gradual surface rock dissolution.
Zeta potential measurements as a function of chelating agent EOR fluid concentrations showed that increasing the concentration of the chelating agent resulted in altering the limestone surface charges to more negative values. Interfacial tension, IFT, was measured as a function of chelating agent the concentrations and found to decrease as the chelating agent concentration increases.
This new approach minimizes the use of large quantities of chelating agent chemicals and consequently reduces the cost.
Designing and Implementation of the First Steam Flooding Pilot Test in Sudanese Oil Field and Africa
Authors: Elbaloula Husham , Pengxiang Hao , Elammas Talal , Alwad Fahmi , Rdwan Mosab , Musa Tagwa 
Published: July 2016

Abstract
Steam flooding is to heat the oil to higher temperatures in order to decrease its viscosity so that it will be more easily flows through the formation from injector toward the producing wells, as the steam moves out into the reservoir away from the injection well, its temperature drops from heat losses and it begins to condense as hot water in the steam zone, the residual saturation is lowered, and the relative permeability increased. These represent the most important parameters that affect the oil recovery.
The objective of this paper is to select the optimum pilot area and propose the steam flooding injection parameter, the suitable well spacing as well as the required steam flooding facility for FNE oil field.
FNE reservoirs are highly porous (~30%), permeable (1000-2000 mD) and unconsolidated in nature. the fluid properties include viscous crude with 15 to 17.7 API. Corresponding viscosities are in the range of 250 cp and 500 cp at reservoir conditions.
In this paper the model was designed to simulate steam flooding of heavy oil reservoir in FNE oil field in which the reservoir is shallow and thin, six different cases at different well spacing were investigated and compared with the base case, the numerical thermal simulator was used to simulate the data from the present steam flooding experiments.
Steam injection temperature of 270°C, with 5~7 MPa injection pressure, steam injection quality of 0.6, and steam injection rate of 1.6 m3/d/ha/m; were used as Steam Flooding parameters for all simulation cases while the recovery ratio of 1.2 is also considered.
The result showed that converting of Cyclic Steam Stimulation (CSS) to steam flooding after the third cycle could improve the recovery factor of the field up to 43 ~ 50.1%, while CSS only can increase the recovery percent of the suggested well groups by 32.5 - 34.2% of the studied sector model which makes it more attractive method as development scenario for FNE oil field.