bluuebunny/crossref_metadata_2025_split huggingface dataset:
Advanced Reservoir and Tar Mat Evaluation Using Downhole Fluid Analysis and Asphaltene Flory-Huggins-Zuo EoS
Authors: Zuo Julian Y. , Mullins Oliver C. , Mishra Vinay , Garcia German , Zhang Dan , Dong Chengli 
Published: May 2016

Abstract
Advances in asphaltene science and a new generation of downhole fluid analysis (DFA) technology have been integrated to yield powerful new insights to reservoir dynamics. The Yen-Mullins model of asphaltene nanoscience has enabled development of the industry's first predictive equation of state (EOS) for asphaltene concentration gradients - the Flory-Huggins-Zuo (FHZ) EOS in oil reservoirs. The FHZ EOS along with DFA measurements has successfully addressed a variety of reservoir concerns including reservoir connectivity, viscosity gradients, and fluid disequilibrium. The model shows that asphaltene concentration gradients can be large owing to both the gravity term and gas/oil ratio (GOR) gradients. The FHZ EOS is reduced to a very simple form for low GOR black oils and heavy oils, and heavy oils are shown to exhibit enormous asphaltene concentration gradients compared to conventional black oil. In this paper, the FHZ EOS has been applied not only to calculate asphaltene concentration gradients but also to predict asphaltene phase instability in oil reservoirs and potential flow assurance issues. Two categories of tar mats are addressed, one with a large discontinuous increase in asphaltene concentration versus depth typically at the base of an oil column (corresponding to asphaltene phase transition); the second with a continuous increase in asphaltene content at the base of a mobile heavy oil column due to an exponential increase in viscosity with asphaltene content. The discontinuous type of tar mat is show to occur in two distinct setting, one more common tar mat at the base of the column and a second unusual tar mat that occurs upstructure and is permeable. The predictions are in good agreement with the laboratory and field data and the mechanisms of forming these two kinds of tar mats are also discussed. This methodology establishes a powerful new approach for conducting the analyses of asphaltene concentration grading, flow assurance and tar mat formation in oil reservoirs by integrating the Yen-Mullins model, and the FHZ EOS with DFA technology.
Harnessing Multiple Learning Styles for Training Diverse Field Personnel in Conventional Coring Operations
Authors: Lee Roger K. , Strike Patrick M. , Sutton David B. , Rengel Carlos D. 
Published: May 2016

Abstract
Coring is a critical operation for geologists and petrophysicists to accurately determine the amounts of hydrocarbons in a reservoir. Conventional coring is the acquisition and recovery to surface of a continuous column of reservoir formation material. This important information assists in determining the amount of oil and gas in a rock and the difficulty involved in retrieving the hydrocarbons. Coring requires use of special drillstring with inner and outer barrels. Additionally, the performance metrics for coring are vastly different from drilling. Due to its specialty nature, it is difficult to educate new and inexperienced individuals in coring operational procedures in a classroom environment.
To address the challenge, this oilfield service organization utilized a holistic approach to develop a training course for conventional coring. Content required for the course included product functionality, rig operations procedures, and troubleshooting application challenges. The key deliverable was to meet the growing learning demands from younger generations of employees. The solution was to develop a course which encompassed multi-sensory resources including auditory, visual, and kinesthetic learning. This methodology was necessary to effectively teach a wide range of topics to a diverse population of field personnel. This paper will provide details of the innovative/new learning activities that engaged the learners and facilitated their training.

Background on Coring
Conventional coring is the acquisition and recovery of a continuous column of reservoir material from depths of down to 10,000 meters to the surface with the use of purpose built coring bits and barrels. The continuous column of reservoir material, or conventional core, is captured during the creation of the wellbore when drilling through a target formation. The drilling parameters such as weight on bit, revolutions per minute, and mud flow rates, used during conventional coring typically differ compared to standard drilling. This is principally due to the primary objective of obtaining a quality intact sample of the reservoir while coring. Conventional coring has been a principle component of formation evaluation and has been around since the 1920's. As more challenging reservoirs are explored, the ability to understand and produce them has also become more difficult. However, the techniques, equipment, and personnel for coring projects have kept pace and produced increasingly more complex and diverse tools.
Best Practices and Application of Integrated Fit for Purpose Technologies to Revitalise High Water Cut Mature Fields A Case History from Offshore South China
Authors: Xiaoping Zou , Guoda Yu , Yanping Li , Yingshi Huang , Tran Thanh , Castellan Francisco , Yanping Li , Xiang Tian , Jianjun Tong , Halomoan Parlindungan Monris , Lanhua Ge , Bisain Amarjit Singh , Yang Liu 
Published: May 2016

Abstract
Huizhou oil field, located offshore south China, has been in production for over 20 years. Most of the primary oil was produced from 1991 to 1996 by vertical wells and commingled production. Horizontal geometric drilling was first introduced in 1997. However, as the field became more mature, the rate of success could not be sustained, and a rapid production decline began in 2000. By 2006, the field average water cut reached 90%.
A reservoir surveillance program was conducted to evaluate remaining reserves, delineate current oil water contacts, and update geologic and reservoir models. This work revealed that remaining reserves in the high-permeability reservoir accumulated in attic locations, while the reserves of low-permeability reservoirs remained unproduced despite years of commingled production with the high-permeability reservoirs.
A new horizontal drilling program was initiated in 2007 to target the 3 m to 5 m thin attic oil column of high-permeability reservoirs overlying strong aquifers. The 1 m to 3 m thin and low-permeability interbedded shale reservoirs were also targeted. Because the reservoir targets are much thinner compared to original conditions, the standoff between lateral and oil water contact is very sensitive to well performance and reserve recovery. Precise landing and lateral placement of horizontal wells and the use of inflow control devices for completion, have become critical to the success of this campaign. The results have shown 39% higher production compared to the set targets, up to 15% improvement in reserves recovery, and 14% reduction in annual field production decline rate.
Based on project results, best practices in finding and revitalizing remaining oil in mature fields and complex reservoirs were developed. Project success was also aided by applications of fit-for-purpose technologies, including advance multifunction formation evaluation and azimuthal logging-while-drilling, well placement, and inflow control devices, as an integrated solution.
Case Study: Productivity Evaluation of Ultralow-Permeability Clastic Oil Reservoir Drilled at High Overbalance with Water Based Mud
Authors: HeShen Shi , ChengGang Xian 
Published: May 2016

Abstract
Ultralow-permeability (1.0- to 10- md) oil reservoirs are becoming primary targets offshore China. Reliable productivity evaluation is needed for such reservoirs, which have significant technical challenges and a narrow economical margin. Evaluation of wells drilled at high overbalance with water-based mud (WBM) presents several key challenges: severe near-wellbore formation damage, lack of porosity-permeability relationships because of the complex pore structures, large-scale permeability effects from pronounced heterogeneities, and big discrepancies among the permeability sources for which analysis is complicated by different measurement environments and interpretation methods. Parameter discrepancy creates significant bias for determining cut-offs and optimizing completion and stimulation strategies. More significantly, defining producible pay and consequently how it will produce are greatly complicated by capillary pressure and relative permeability conditions. Very different pictures may be drawn if these challenges are not addressed systematically.
A comprehensive case study provided lessons learned for the productivity evaluation of an ultralow-permeability clastic oil reservoir drilled at high overbalance with WBM. An integrated approach was conducted to overcome challenges by using all available data through extensive data acquisition. Flow-based rock typing (FBRT) with a neural network used pore structure, capillary pressure, and relative permeability as key inputs or control parameters in addition to the routine parameters in conventional rock-typing methods. Different permeability sources with different scales were systematically integrated and up-scaled into a numerical model based on classified FBRTs and validated by history matching of dynamical tests. Pore structure delineation is identified as the key input for reliable productivity evaluation. FBRT presents an attractive solution if measurements of pore structure, capillary pressure, and relative permeability and dynamical data are carefully used. Optimizing productivity must start with minimizing formation damage and progress through optimizing completion and stimulation.
The Spectrum of Fine-Grained Reservoirs From
Authors: Bohacs K.M. , Passey Q.R. , Rudnicki M. , Esch W.L. , Lazar O.R. 
Published: May 2016

Abstract
A spectrum of combinations of rock and hydrocarbon properties in fine-grained rocks can result in significant production, effectively spanning 'conventional' tight oil to fractured 'shale' gas reservoirs, in four main families based on dominant porosity-permeability system and stratal relations (i.e., 'Conventional' tight, Hybrid/Interbedded, Porous 'shale', Fractured 'shale'). Fine-grained reservoir types comprise 'shale-oil' reservoirs at lower thermal maturities and pressure-temperature (P-T) conditions to 'shale-gas' reservoirs at higher maturities and P-T conditions. These fine-grained reservoirs can contain a variety of pore types: inter-granular, intra-granular, fracture, intra-kerogen, and intra-pyrobitumen/char -- the last two 'organic-hosted' types are more obvious at higher maturities.
'Shale-oil' reservoirs share many attributes with 'shale-gas' reservoirs, but have some distinct differences. The key additional dimension is the properties of the hydrocarbon fluids: Over geological time, fluid density and phase influence fluid saturation in the matrix, and in the short term, viscosity and phase affect flow and production rates. Hence, two main classes of attributes affect ultimate 'shale' reservoir performance: rock properties (mainly permeability) and fluid properties (mainly viscosity) that are influenced by the full geological history of the reservoir. Overall reservoir permeability includes both matrix and fracture characteristics: Matrix permeability is a function of original depositional composition, texture, bedding, and stratal stacking plus burial history (thermal stress, diagenesis). Fracture permeability is a function of the same controls as matrix permeability along with structural history (mechanical stress). Fluid properties (viscosity, density) are also controlled by original depositional properties (which determine kerogen type) and burial/uplift history, along with present-day reservoir pressure and temperature.
The higher thermal maturities of 'shale-gas' reservoirs result in contrasts with 'shale-oil' reservoirs: they tend to have less smectite due to illitization, but more obvious porosity associated with kerogen and bitumen. These factors modify the porosity-permeability system and well-log responses. Appreciation of the similarities and differences between 'shale-gas' and 'shale-oil' enables more efficient and effective exploitation of the full range of resource types.
The Adaptability Research of Steam Flooding Assisted by Nitrogen Foam in Henan Oilfield
Authors: Lu C. , Liu H.Q. , Lu K.Q. , Liu Y.G. , Dong X.H. 
Published: May 2016

Abstract
With the further study on foaming agent performance, steam flooding assisted by nitrogen foam has been applied more widely. But the flexibility of this technology in heterogeneous shallow layer heavy oil reservoir has not been fully researched.
Through introducing a new dimensionless parameter—foam comprehensive evaluation index (FCEI), we use physical simulation to evaluate foaming agents. Then we make five sand filling tubes modeling permeability contrast in the light of Henan heterogeneous shallow layer heavy oil reservoir. Based on two kinds of foam-injected methods (steam following or not) impact analyses, the applicability of foam to multi-permeability contrast is further discussed. Furthermore, we use numerical simulation to optimize parameters including foam slug size, nitrogen steam ratio, foam injection interval and production-injection ratio, which applied to this type of reservoir.
The obtained results show that through foaming coefficient and decay coefficient, FCEI can unify the criteria of foam screening by taking foam volume and half-life into consideration. On even ground, compared with cold foam flooding, the oil production of unit foaming agent of hot foam flooding stays 1.24 % higher. There exists none negative correlation between foam's contributions to each layer's flooding efficiency and permeability. Two methods both indicate that the middle permeability layer, of which the producing degree is similar with lower ones, has great exploitation potential. When injected with cold foam, the start-up pressure of heterogeneous formations increases linearly along with the increase of permeability grade, but for hot foam, this value increases in function of power. And to higher permeability contrast layers, hot foam is better. Finally, under hot foam slug injection condition, the optimum foam slug size is 0.02PV, the optimum nitrogen steam ratio is 20:1, the optimum foam injection interval is 90 days and the best production injection ratio is 1.32:1.
Based on the study, this technology has been applied for selected field sites in 2011, and preliminary results have been achieved. The results demonstrate that this research can play an important guiding role in applying steam flooding assisted by nitrogen foam to heterogeneous shallow layer heavy oil reservoir.
Successful Multistage Hydraulic Fracturing in V-Shape Well as a Method for the Development of Coal Bed Methane in China
Authors: Qu H. , Jiang T. , Liu Y. , Wu Z. , Xie X. , Chi S. 
Published: May 2016

Abstract
There is a rich coal bed methane reserve in the southeast margin of ordos basin. Hydraulic fracturing stimulation is the primary completion method to coal bed methane wellbores for many years in this area. Recently, V-Shape wells, which are complex architecture wells composed of a vertical well and two horizontal wells, are in order to improve recovery of CBM. Two horizontal wells intersect with vertical well in same depth, and the included angle between two well tracks of the plan projection is about 44 degree. Multistage hydraulic fracturing technology was treated two horizontal wells to create fracture network and induce nature fractures. Then, the vertical well was used to drainage to decrease bottom pressure.
Based on the geologic parameters, a total of eight stages were placed on two horizontal sections. One had three fractures, the other had five fractures. According to wellbore condition, pump bridge plug technology was used to execute multistage fracturing treatments. During field operation, 7200 m3 active water was mixed with quartz sand (492m3) and pumped down two wells together. The averaged proppant concentration was 14%. Because of included angle, the number of sand changed with stage increasing to avoid interference among fractures within two wells. And in the final stage, the treatment deployed 100m3 sand, and proppant loading reached to about 41750 Kg/m of net coal. This created a new Chinese record of proppant loading in coal bed methane.
Consequently, the first V-Shap well group was successfully treated in china. This work can research the application of special technology well in CBM, evaluate the effect of multi stimulation treatments, and confirm the gas content. It also provides the reliable guidance for the reasonable development of CBM reserve in the future.
Improved Oil Recovery by Hydrophilic Silica Nanoparticles Suspension: 2-Phase Flow Experimental Studies
Authors: Li Shidong , Hendraningrat Luky , Torsaeter Ole 
Published: May 2016

Abstract
In last decade, a number of papers about nanoparticles studies have been published related to its benefit for oil and gas industries. Some of them discussed about the potential of nanoparticles for enhanced oil recovery (EOR) in the laboratory scale. One of possible EOR mechanisms of nanofluids has been described as disjoining pressure gradient (Chengara, 2004, and Wasan, 2011). The benefit of using silica nanoparticles was explained by Miranda (2012). Hence, the present study objective is to investigate the potential of hydrophilic silica nanoparticles suspension as enhanced oil recovery agent and find out the main mechanisms of nanofluids for EOR.
In this study, hydrophilic nanoparticles with average particle size of 7 nm were used in both visualization glass micromodel flooding experiments and core flooding experiments. A water-wet transparent glass micromodel and Berea sandstone cores with 300–400 mD permeability were used as porous medium. Synthetic brine was used as disperse fluid for nanoparticles. In order to investigate the recovery mechanisms of nanofluids, interfacial tension (IFT) and contact angle between different concentration nanofluids and crude oil have been measured by using spinning drop and pendent drop methods.
The experimental results indicate that the nanofluids can reduce the IFT between water phase and oil phase and make the solid surface more water wet. In the visualization glass micromodel flooding experiments, it was observed that nanofluids can release oil drops trapped by capillary pressure, while the high concentration nanofluids stabilized oil-water emulsion. For the core flooding experiments, nanofluids can increase recovery about 4–5% compared to brine flooding. These results indicate that these nanoparticles are potential EOR agents. The future expectation is that nanoparticles could mobilize more oil in the pore network at field scale to improve oil recovery.
Combining Asphaltene Science and Downhole Fluid Analysis for Improved Reservoir Characterisation
Authors: Elshahawi Hani , Dong Chengli , Latifzai Ahmad , Zuo Julian , Mullins Oliver C. 
Published: May 2016

Abstract
Understanding reservoir complexities such as compartmentalisation and compositional gradients early in the life of a field is crucial for its optimal development. That's especially true for deepwater reservoirs. Deepwater exploration and development has become a key area for most E&P companies because of the increased global demand for oil and gas and the limited accessibility of other potential unexploited resources. Modern wireline formation testers can provide a wide range of downhole rock and fluid properties at in-situ reservoir conditions and can help diagnose deepwater reservoir issues such as compartmentalisation and compositional grading early on. Advanced downhole fluid analysis (DFA) performed by wireline formation testing tools provides real time quantitative measurement of variation in asphaltene content as manifested though fluorescence and fluid coloration. Gas-oil ratio (GOR), another key determinant in asphaltene stability and gradients, is also measured downhole with the DFA technique. Building on recent advances in asphaltene molecular and colloidal physics, a new asphaltene equation of state (EoS) can be used to model asphaltene gradients in crude oils in the same way that a traditional cubic EoS is used for modeling GOR gradients.
In this paper, we analyze a deepwater case study showing increases in asphaltenes content with depth due to destabilisation resulting from secondary gas charging at the top of the column and with solid hydrocarbon/tar depositing at the base. These seemingly contradictory observations are shown to follow from a new nanoscience model of asphaltenes. A simple model is proposed for this tar mat formation and consisting of disequilibrium gas charging, large disequilibrium gradients of asphaltene and GOR, asphaltene instability in the oil, and tar in the core. Likely compartmentalisation will also be identified using DFA analysis and verified using lab data analysis, allowing integration into the reservoir modeling process.
How to Get the Most Out of Your Oil Rim Reservoirs?
Authors: Masoudi Rahim , Karkooti Hooman , Othman Mohamad B. 
Published: May 2016

Abstract
Oil production from oil rim reservoirs has always been a challenge due to their thinly spread oil resources and complicated production mechanisms. Movement of oil/water and gas/oil contacts could be very sensitive to conventional production operation and cause detrimental early water/gas breakthrough. The low oil production volume and hence low recovery (typically less than 18%) make the oil rim field development economically less attractive. However, integration of state-of-the-art engineering approaches, innovative technical initiatives and new technologies can make a significant change in the oil rim reservoir development.
This paper, which is a brief of the author's recent SPE distinguished lecture on the same topic, disseminates the applied fundamentals, critical elements and proven practices to maximize the hydrocarbon recovery in successful and integrated oil rim developments. The paper covers the reliable volumetric assessment and development concept (i.e., sequential, concurrent, etc.), robust and proactive reservoir management/monitoring policy to advice on depletion strategies and production to control the conning and cusping of water and gas. In addition, utilizing new technologies, appropriate production technology advice to assist timely development decision making, best simulation and modeling approach for the applied technologies (e.g., Horizontal/Multilateral wells, smart wells/completion, ICD/ICV, tracer, etc.) and complicated mechanism and dynamics involved in oil rim development are explained and discussed.
The recommended workflow, guideline and technical initiatives will be elaborated throughout the paper and the success and value creation of the recommended methodology will be demonstrated in various real case studies. The paper demonstrates progressive and step-by-step recovery factor improvement up to additional 20% in the studied real cases.