bluuebunny/crossref_metadata_2025_split huggingface dataset:
A Novel Mud Formulation for Drilling Operations in the Permafrost
Authors: Kamel Ahmed H. 
Published: April 2013

Abstract
Umiat field is located in the North Slope, Alaska where most oil reserves are within the permafrost. The formation temperature is around 20°F and thus frozen filtrate is a crucial issue in formation damage. Frozen filtrate can form an impermeable barrier to oil flow and maximize formation damage in the permafrost. Its impact is even more pronounced in horizontal wells. In addition to formation damage concerns, low formation pressure, sensitive arctic environment and ice disintegration when exposed to certain fluids are key factors to be considered when selecting the suitable drilling fluid. This paper is a comprehensive experimental investigation of various drilling fluids to eventually propose a non-damaging fluid system that is suitable for permafrost drilling operations. Specially formulated, free-solid mud systems including WBM, brine mud, native crude OBM, synthetic oil mud, emulsion and foam are evaluated. The evaluation includes their rheological properties, filtration properties, clay swelling properties and potential freezing of fluid filtrate.
The results show that WBM drastically damage the formation. Yet, clay swelling is not a major issue. Freezing of water filtrate is the key damaging mechanism. In spite of its large filtrate volume, brine mud shows a moderate impact on formation damage. Its depressed freezing point makes it suitable for the drilling operations. However, it may not be preferable due to its ice disintegration effects. OBM and synthetic oil mud yield the minimal damage and show excellent rheological and filtration properties. Their depressed freezing point favors their use. Foams and emulsions exhibit numerous advantages. The analysis and evaluation of the different fluid systems is discussed in more details in the present paper. Finally, a specific formulation of drilling fluid is recommended to alleviate the formation damage and production impairment problems and to effectively reduce the well completion cost and eventually, to increase well productivity from such shallow frozen oil field.
Interpreting Pressure and Flow Rate Data from Permanent Downhole Gauges Using Convolution-Kernel-Based Data Mining Approaches
Authors: Liu Yang , Horne Roland N. 
Published: April 2013

Abstract
The convolution kernel was initially invented and applied in the domain of nature language machine learning. In the original linguistic study, the convolution kernel decomposed words into parts, and evaluated the parts using a simple kernel function. This inspired us to apply the convolution kernel method to data from permanent downhole gauges (PDG) by decomposing the pressure transient into a series of pressure responses to the previous flow rate change events.
In this study, the data mining process was conducted in two stages, namely learning and prediction processes. In the learning process, the PDG data were used to train the convolution-kernel-based data mining algorithm until the algorithm converged. After convergence, the reservoir model is obtained implicitly in the form of polynomials in the high-dimensional Hilbert space defined by the convolution kernel function. In the prediction process, a pressure prediction was made by the data mining algorithm according to an arbitrary given flow rate history (usually a constant flow rate history for simplicity). This flow rate history and the corresponding pressure prediction revealed the reservoir model underlying the variable PDG data.
13 synthetic cases representing different well/reservoir models and three real field cases were used to test this approach. The method recovered the reservoir model successfully in all cases.
Optimal Voidage Replacement Ratio for Viscous and Heavy Oil Reservoirs
Authors: Delgado D. E. , Vittoratos E. , Kovscek A. R. 
Published: April 2013

Abstract
Historically a voidage replacement ratio (VRR) of 1 is assumed to be optimal for oil recovery regardless of whether recovery occurs from an unconventional heavy oil reservoir or a conventional oil reservoir. That is, it is assumed that of all scenarios, the most oil recovery occurs when the amount of fluids injected into the subsurface equals the amount produced. Recent work publications have analyzed both field and core-scale data to conclude that a VRR of 1 is suboptimal for certain viscous and heavy-oil reservoirs. In this work, we use numerical simulation to seek an understanding of the conditions under which a VRR of 1 is suboptimal. Models are core-size to enable better interpretation of mechanisms. We tested the sensitivity of the optimal VRR to the curvature of our relative permeability relationships (i.e., Corey exponent), the critical gas saturation, the three-phase flow model, potential chemistry of the oil, the statistics of permeability values, the connectivity of low and high permeability regions, and the reference scale at which results are compared. Realistic relative permeability curves based off rock and fluid interactions observed in the literature were developed and used in the majority of our simulations. We find that gas mobility is an influential parameter in determining the optimal VRR at core scale. As the gas mobility decreases relative to oil and water and/or the reservoir heterogeneity increases, a VRR below 1 becomes more favorable. The heterogeneity and its connectivity also influenced the optimal VRR to a lesser extent.
Potential for Non-thermal Chemical Augmented Waterflood for Producing Viscous Oils
Authors: Xu Haomin , Kim Do Hoon , Delshad Mojdeh 
Published: April 2013

Abstract
Chemical Enhanced Oil Recovery (EOR) has regained its attention because of high oil price and the depletion of conventional oil reservoirs. This process is more complex than the primary and secondary recovery and requires detailed engineering design for a successful field-scale application.
An alkaline/co-solvent/polymer (ACP) formulation was developed and corefloods were performed for a cost efficient alternative to alkaline/surfactant/polymer floods. Alkali reacts with acidic components of heavy oil (i.e. 170 cp in-situ viscosities) to form natural soap and significantly reduce the interfacial tension, which allows producing residual oil not contacted by waterflood or polymer flood alone. Polymer provides mobility control to drive chemical slug and oil bank. Co-solvent helps to improve the compatibility between in-situ soap and polymer and to reduce microemulsion viscosity. An impressive recovery of 70% of the waterflood residual oil saturation was achieved from an outcrop core where the remaining oil saturation after the ACP flood was reduced to only 13.5%. The results were promising with very low chemical utilization. UTCHEM reservoir simulator was used to model the coreflood experiment to obtain parameters for pilot scale simulations. Geological model was based on unconsolidated reservoir sand with multiple seven spot well patterns.
However, facility capacity and field logistics, reservoir heterogeneity as well as mixing and dispersion effects might prevent the design followed in coreflood to be directly scaled for field implementation. Field-scale sensitivity simulations were conducted to optimize the design. The influence of chemical mass, slug size, polymer pre-flush, and injection rates on ultimate oil recovery was investigated. This research emphasizes the importance of small well spacing and good mobility control on recovery efficiency. The in-situ soap generated from alkali-naphthenic acid reaction not only mobilizes residual oil to increase oil recovery, but also enhances water relative permeability to increase injectivity.
The paper discusses a cost effective chemical flooding design with an impressive oil recovery by adding relatively small solvent and polymer quantities to injected water. The potential for producing residual oil of the viscous oil is demonstrated in both the coreflood and pilot-scale simulations.
Improved Oil Reservoir Characterization: Offshore Malaysia Field
Authors: Hassan Rozlin , Malaysia Lundin , Haddad Sammy , Wa Wee Wei , Johan Zailily , Lim Lee Chin 
Published: April 2013

Abstract
The acquisition of high quality reservoir information in exploration campaigns is a continuous challenge in today's operations. The operational risks, time, cost, environmental concerns and reservoirs complexities are several important factors to be considered in reservoir characterization planning. Key reservoir information includes fluid types and composition, horizontal permeability, vertical permeability, damage skin, radius of investigation and reservoir pressure.
This work presents the reservoir evaluation done in the basement with the mobility range of 0.01 to 0.09 mD/cP in an offshore Malaysia oil field. An early and quick identification of hydrocarbon prospect was required for appraisal wells planning. The expected low mobility in basement complicates the exploration data acquisition. Conventional reservoir fluid characterization through bottom hole sampling and PVT lab analysis is proven to be ineffective due to the long waiting time before the results are available. Full scale DST on the other hands offers higher operational complexity and cost for reservoir parameters determination.
As an alternative, the wireline formation tester dual packer module was deployed to perform a DST like testing known as interval pressure transient test (IPTT). At the interval of interests with the presence of hydrocarbon, the dual packer module offers selectively straddling reservoir sections to provide the capability to conduct controlled local production and interference for reservoir parameters estimation through pressure transient analysis. Downhole fluid analysis was performed to provide the reservoir fluid properties input. By providing larger flow area also, dual packer module enables the reservoir characterization in the low mobility intervals through downhole fluid analysis and IPTT techniques. The examples of IPTT applications in oil reservoirs and the analysis methodology will be presented in this paper.
Effect of Bitumen Viscosity and Bitumen-Water Interfacial Tension on the Efficiency of Steam Assisted Bitumen Recovery Processes
Authors: Romaniuk N. , Little L. , Arguelles F. A. , Babadagli T. , Ozum B. 
Published: April 2013

Abstract
In Alberta, Canada bitumen is commercially produced by in-situ processes at about 830,000 bbl/d capacity, production capacity is projected to exceed 5,000,000 bbl/d in the next two decades. Steam assisted gravity drainage (SAGD) process is one of the in-situ bitumen recovery processes; the economics and efficiency of which would be improved by reducing the steam to bitumen ratio. For this purpose, the addition of light hydrocarbon solvents into steam as a solvent to reduce bitumen viscosity has been studied; however, several decades of research efforts has resulted in only limited commercial success. More recently, as an alternative to solvent addition, the use of biodiesel (fatty acid methyl esters) with steam as a surfactant additive reducing bitumen-water interfacial tension was proposed and studied experimentally (Babadagli et al, 2009; Babadagli and Ozum, 2010).
In the present study, experiments were performed at typical reservoir pressure conditions to evaluate the performance of solvent (pentane) addition with steam to reduce viscosity and biodiesel addition with steam to reduce bitumen-water interfacial tension to improve bitumen recovery efficiency. The results showed that bitumen recovery efficiency may decrease with the addition of hydrocarbon solvent if the solvent is added after a certain period of steam injection. Solvent addition to the steam was tested at 5% and 15% of bitumen mass dosages. Steam assisted bitumen recovery tests with biodiesel addition under 2-g/kg-bitumen dosage showed an increase in bitumen recovery efficiency. To further investigate the reasons behind the lowered recovery with solvent addition, an analytical model was developed to predict heat transfer and pressure fields in the reservoir causing Darcy flow, and therefore, bitumen mobility. The distribution of the aqueous and solvent phases injected in time and space considering the phase change (steam and solvent condensation) effect with respect to steam chamber were clarified for different injection conditions and scenarios.
The results and observation will be useful in defining the appropriate application conditions for both solvent as a viscosity reducer and biodiesel as an interfacial tension reducer additive in SAGD operations.
Clastic and Carbonate Formation Evaluation Case Study: East Asia
Authors: Bt Zulkipli Siti Najmi , Kyi Ko Ko , Haddad Sammy , Johan Zailily , Wa Wee Wei , Tan Willy , Sinnappu Suresh 
Published: April 2013

Abstract
Proving a hydrocarbon bearing zone has a significant impact on appraising a well. Pressure gradient and fluid sampling are typically used to identify fluid type in exploration phase. In addition, to confirm if the field is viable for oil & gas production, there is a need to ascertain volume of hydrocarbon from petrophysical evaluation. Aside from this evaluation, reference to adjacent development wells occasionally become common for the operator to aid in reservoir study and plan for development.
This work is based on a case study on a Sarawak Basin field, drilled with Water Base Mud, which has three reservoirs of interests stretching across Clastics and Central Luconia Carbonate on the bottom zone. The poor quality sand and tight upper zone are challenging for reservoir evaluation. This has called for the application of multi-frequency dielectric tool for fluid saturation and advanced downhole fluid analyzer to obtain PVT equivalent fluid analysis in real time.
With the dielectric tool showing the presence of hydrocarbon in both clastic and carbonate formations, downhole fluid analysis was planned to verify the mobile formation fluid and successfully guided the identification of oil and water in clastic formation and gas in the carbonate reservoir. The presence of water in clastic formation was not expected since the water producing interval is located at about 100 m down dip from a nearby development well that is producing gas. Dispute in results, in addition to tight nature of the reservoir has triggered the need for larger scale testing. A DST was initially planned by the operator after the well has been cased. With cost and time consideration, the decision was changed to run the formation tester dual packer module to perform interval pressure transient testing (IPTT). This paper will present the results of IPTT, fluid analysis and dielectric tool to demonstrate the methodology used in this case study field evaluation.
Liquid Lift Dual Gradient Drilling in Deep Water: Early Kick Detection and Control
Authors: Dhameliya J. D. , Jain S. , Gupta V. 
Published: April 2013

Abstract
As the demand for energy is increasing, the search for oil and gas extends into hostile and challenging environment. Among these problematical environments are the deepwater regions of the world. One of the many challenges faced when drilling deepwater offshore wells is the decreasing window between pore pressure and formation fracture pressure, which is one of the major reliability issues affecting the use of conventional drilling in deepwater. Also, for successful oil and gas exploration, increased accessibility to reserves, improved wellbore integrity, reduced overhead costs and most importantly, providing a safe working environment to take place in this area, new drilling methods must be developed to carry out drilling operations in deepwater.
Applying a dual gradient drilling (DGD) technology to offshore drilling isn't a new concept, but one that is being addressed with new fervor and can help meet all of these industry goals. DGD is a rapidly growing technology that has been used in deepwater for various applications nowadays such as, fewer required casing strings, larger production tubing, improved well control and reduction of lost-circulation setbacks etc.
In conventional drilling, after detecting a kick, the well is immediately shut in. But, in DGD due to the pressure imbalance the well cannot be shut-in until equilibrium is reached. Otherwise it may lead to formation fracture and lost circulation.
This paper focuses upon some of technology related to early kick detection in liquid lift DGD and once a kick is detected, how to stop the further influx and circulate the kick fluid out of the wellbore. To achieve this objective we have analyzed economic and institutional factor by the use of appropriate model predictive control variants. We have concluded our paper with some relevant recommendation on some operational and design strategies as well as future direction for integration of additional variable.
Coupling Programming of an Adaptive Genetic Algorithm with Reservoir Flow Simulation for Infill Oil Well Locations Optimization
Authors: Al-Mudhafer Wathiq J. 
Published: April 2013

Abstract
Planning of an optimal field development scenario in a mature oil field is a crucial decision since it requires an efficient design of integrated reservoir modeling. One of the most imperative field development scenario is determining the locations of infill wells. The reservoir under study is the main pay in the South Rumaila oil field. This is a mature oil field located in the South of Iraq with around 58 years of production. It has 40 producing wells and 20 injection wells. An efficient reservoir simulation model has been coupled in sequence with a stable and well-conditioned genetic algorithm to optimize the infill well locations. A Genetic Algorithm offers an efficient search method that can be used as a powerful optimization tool by randomly generating potential solutions in order to achieve increasingly better results by applying a set of operators: Selection, Crossover (Recombination), and Mutation.
In this study, a black oil reservoir model has been used to evaluate the reservoir and predict its future performance. After attaining a considerable history matching, the simulator has been coupled with an Adaptive Genetic Algorithm (AGA). This algorithm is coupled with the simulator in order to re-evaluate the optimized wells at each iteration. Net Present Value (NPV) has been adopted here as an objective function. The initial population consists of a random number of chromosomes that have eight genes that represent the number of possible new proposed wells that have the highest values of permeability and oil saturation at the last time step. The genetic algorithm takes two parents randomly from the population and produces two children (offspring) by applying the operators such as crossover, mutation, and replacement on the two parents. Subsequently, the program sorts the population' chromosomes from best to worst. The resulting chromosome represents the optimal wells at this iteration. Then the AGA program re-inputs the optimized wells in the input file of the simulator to repeat the processes for many iterations until the optimal solution with the highest NPV is obtained. The entire procedure has led to optimize three infill wells that have the highest NPV among the other solutions.
Yield Potential of Hulless Versus Hulled Full‐Sib Genotypes in Four Winter Barley Populations
Authors: Berger G. , Green A. , Brooks W. , Vaughn M. , Pitman R. , Thomason W. , Griffey C. 
Published: April 2013

ABSTRACTDetermining what factors contribute to the yield difference that exists between hulled and hulless winter barley (Hordeum vulgare L.) is necessary for continued yield improvement in the hulless barley germplasm pool. This yield difference is a major factor limiting the acceptance and production of hulless barley as an alternative to traditional hulled barley. Experiments were conducted in Warsaw, VA, during 2010/2011 and 2011/2012 and in Blacksburg, VA, during 2011/2012. Seedling emergence, plants per square meter, normalized difference vegetative index, heading date, spikes per square meter, plant height, lodging, yield, grain volume weight, 1000 kernel weight, spikelets per spike, seeds per spike, seed weight per spike, ash, crude fiber, fat, protein, and starch were measured. Grain volume weight and protein concentration were significantly (p ≤ 0.05) higher for hulless genotypes while seedling emergence and grain ash concentration were significantly (p ≤ 0.05) higher for hulled genotypes. Other traits measured in the study varied by population and environment. On the basis of linear regression analysis, none of the traits explained yield variation in all populations and environments. Before adjustment for hull weight, hulless genotypes yielded significantly (p ≤ 0.05) less than hulled genotypes on average in all populations at Warsaw and for population 1 at Blacksburg during the 2011/2012 growing season. After adjustment for hull weight, yield potential of select hulless genotypes was statistically similar to that of hulled genotypes. Therefore, it is possible to identify hulless genotypes having yield potentials equal to those of their hulled sibs.
Effect of Gypsum Application on Mineral Composition in Peanut Pod Walls and Seeds
Authors: Pathak Bhuvan P. , Jain Mukesh , Tillman Barry L. , Grusak Michael A. , Gallo Maria 
Published: April 2013

ABSTRACTAlleviation of soil‐Ca deficiency through gypsum amendment increases the yield potential and ensures high seed quality in peanut (Arachis hypogaea L.). The effects of gypsum treatment, plant life cycle, and the fruit development stages on the accrual of several essential minerals (Ca, S, Mg, P, K, Cu, Ni, Mn, Zn, and Fe) and Na were studied in the pod walls and seeds of two runner cultivars, C‐99R and Georgia Green. Calcium concentration was nearly twofold higher in pod walls than in seeds, irrespective of gypsum treatment and cultivar differences. Significant increases in Ca and S, a decrease in P concentration in pod walls and seeds, and a marginal decline in seed‐Mg concentration were discernible following gypsum treatment. Sodium concentration decreased in the pod walls and Zn concentration increased in the seeds due to gypsum treatment. Progression in the plant life cycle stage was positively correlated with Ca accrual in both pod walls and seeds. The small‐seeded cultivar Georgia Green showed tissue‐specific increases in the acquisition of Ca, Mg, and Zn in pod walls and seeds, and a decrease in P concentration in the seeds compared with the large‐seeded cv. C‐99R. Compared with the respective seed maturation stages, the pod walls had lower S, Mg, P, K, and Zn, and higher Ca, Cu, Ni, Mn, Fe, and Na concentrations. While Ca, S, Mg, P, K, Zn, Fe, and Na concentrations declined, Mn concentration increased in both pod walls and seeds during fruit development.