bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modeling Two-Phase Fluid and Heat Flows in Geothermal Wells
Authors: Hasan A. Rashid , Kabir C. Shah 
Published: March 2009

AbstractThis study presents a robust model for two-phase flow in geothermal wells using the drift-flux approach. For estimating the static head, we use a single expression for liquid holdup, with flow-pattern-dependent values for flow parameter and rise velocity that gradually changes near the transition boundaries to avoid discontinuity in the estimated gradients. Frictional and kinetic heads are estimated with the simple homogeneous modeling approach.As the geothermal fluids ascend up the well, loss of both momentum and heat occur. The consequent pressure loss often leads to flashing and increase in steam fraction (quality) despite heat loss. Accurate estimation of heat loss, which leads to significant changes in fluid properties influencing pressure-drop is, therefore, important in modeling flow in geothermal wells. Heat transfer from the wellbore fluid to the surrounding formation is rigorously modeled by treating the wellbore as a heat sink of finite radius in an infinite-acting medium (formation) and accounting for the resistances to heat transfer offered by various elements of the wellbore.We present a comparative study involving the new model and those that are often used for geothermal wells. These models include those of Ansari et al., Orkiszewski, Hagedorn and Brown, Beggs and Brill, and the homogeneous model. The main ingredient of this study entails the use of a small but reliable dataset. Statistical analyses suggest that all the models behave similarly, although the proposed model offers marginally greater accuracy and simplicity of use. Uncertainty of performance appears to depend upon the quality of data input, rather than the model characteristics.
Spontaneous Countercurrent Imbibition and Forced Displacement Characteristics of Low-Permeability, Siliceous Shale Rocks
Authors: Takahashi Satoru , Kovscek Anthony R. 
Published: March 2009

Abstract
Enhanced oil production from naturally-fractured low-permeability reservoirs is challenging. A large amount of oil is generally left behind because of heterogeneity and unfavorable rock wettability. Spontaneous countercurrent imbibition in naturally-fractured reservoirs is an important oil recovery mechanism and has been widely studied in the oil and gas industry. Nevertheless, complicated rock properties such as low permeability and other factors controlling flow mechanisms make it difficult to understand the flow characteristics and to generalize expected recovery.
Spontaneous countercurrent imbibition and forced displacement tests at reservoir temperature were completed using siliceous shale core plugs that have low permeability, relatively high porosity, and intermediate to oil-wet surfaces. Four brine formulations were examined: carbonated synthetic brine (pH of 3), acidic (pH of 3), neutral, and alkaline (pH of 12).
During spontaneous countercurrent imbibition, the oil recovery was about 10% of the oil in place (OIP) or less when the low to the neutral pH synthetic brine was used. On the other hand, with the high pH synthetic brine, the oil recovery increased to 30% of the OIP. In forced displacement after spontaneous imbibition, the final oil recovery was 65%, 70-80%, and 95% of the OIP in the neutral pH, low pH and carbonated water, and high pH brine, respectively.
The siliceous shale core used in this study is an intermediate to oil-wet rock as gauged from the oil recovery by spontaneous imbibition in the neutral pH brine. With pH-controlled synthetic brine, the final oil recovery increases; especially using high pH brine. This suggests that the wettability shifts to greater water-wet conditions and the residual oil saturation decreased by exposing high pH brine. In the simulation study, it is inferred that the oil recovery characteristics change by changing the capillary pressure characteristics and the interfacial tension.
Solutions for Better Production in Tight Gas Reservoirs Through Hydraulic Fracturing
Authors: Arukhe James , Aguilera Roberto , Harding Thomas G. 
Published: March 2009

Abstract
The challenge to make best producers for the least investment in tight gas reservoirs has always been with the oil and gas industry since production in many tight gas reservoirs is oftentimes marginal, at best. This paper presents solutions for better production in tight gas reservoirs through hydraulic fracturing.
Properly engineered hydraulic fracture treatments are enablers to achieve overall economies of scale with development of tight gas reservoirs. These treatments are conducted to bypass completion damage and stimulate production from low permeability reservoirs. They are designed using simulators with a range of capabilities in an effort to maximize the economic benefit of the treatment, effective fracture length, and number of zones producing, fracture conductivity, acceleration of recovery, addition of reserves, and minimize job failures and treatment costs. To accomplish these goals, substantial amount of information is required to describe reservoir flow capacity and provide the data needed to predict treatment pressure response as well as fracture geometry and conductivity. These data will determine the optimum size of the treatment, the maximum proppant concentration that can be pumped, and the expected production response to the stimulation. When sufficient input data are available to characterize the reservoir, the fracture geometry can be accurately modeled with a capable simulator, the treatment goals listed above can be realized and an optimum design can be reached.
The design process, including selection of proppants and fluids, pumping schedule, injected proppant concentrations, total job size, pump rate, and other parameters requires an idea of the desired outcome of the job: required fracture length, possible pack concentration and clean-up time. Critical measurements from testing of actual cores has allowed to sift through the chaff to find those "gems" in hydraulic fracturing that materially improve the completion efficiency in tight gas reservoirs.
Numerical Reservoir-Wellbore-Pipeline Simulation Model of The Geysers Geothermal Field, California, USA
Authors: Butler Steven J. , Enedy Steven L. 
Published: March 2009

Abstract
The Geysers geothermal field, located in Lake, Sonoma, and Mendocino Counties, California is the largest developed geothermal system in the world. Electric power generation started at The Geysers in 1960 with a 12 MW (gross) plant. The total installed capacity in the field peaked in 1989 at 2,043 MW. As more and more power plants were built during the 1980s and net mass withdrawals increased, reservoir pressures at The Geysers declined, eventually resulting in steam shortfalls and declining generation levels. This net withdraw is due to the fact that geothermal power plants at The Geysers typically lose about 70 to 80% of produced mass to evaporation in cooling towers, with the balance of mass being returned to the reservoir through injection of steam condensate.
In response to this decline, field operators made modifications to the pipelines and turbines to be able to operate more efficiently at lower system pressures. Based on studies funded by the California Energy Commission that showed that injection of water from outside sources was the most effective method of managing the long-term decline in the resource, a program of augmented injection, using large volumes of treated sewage effluent, was started in the late 1990s.
This program of augmented injection has brought mass injected, more or less, into parity with mass produced, and the rate of reservoir pressure decline has been significantly reduced. Still, optimizing the distribution of augmented injection throughout the field and making corresponding adjustments to plant and pipeline facilities is a complicated process, with many interdependencies.
To aid in ongoing optimization of the field, an integrated model has been developed for the Northern California Power Agency (NCPA) that combines reservoir simulation with mathematical modeling of the wellbores, the pipelines, and the power plants. This integrated model, funded in part by the California Energy Commission, has proven very useful for evaluating the most cost-effective improvements to the combination of wells and surface facilities, and to study the benefit of increasing the volume of augmented injection.
A New Method for Continual Forecasting of Interwell Connectivity in Waterfloods Using an Extended Kalman Filter
Authors: Zhai Daoyuan , Mendel Jerry M. , Liu Feilong 
Published: March 2009

Abstract
This paper is based on a relatively simple parametric model that characterizes the system function between a specific producer and each of its contributing injectors. The model has only two parameters for each producer-injector pair; so, if N injectors are assumed to contribute to a producer, there will be 2N unknown parameters. An adaptive strategy, using an Extended Kalman Filter (EKF), is used to estimate the 2N parameters, which are then used to generate N numeric Injector-Producer-Relationship (IPR) values for the N producer-injector pairs. The IPR values allow one to assess how well an injector influences the producer.
This same model and an EKF were first used in Liu, et al [5]. The modified EKF used in this paper avoids problems that can arise when processing real data and provides additional information that is useful for future research. Our modified EKF is applied to real data from a section of an oil field. A validation strategy for the estimated IPR values is developed in terms of "prediction errors." A strategy is also presented for choosing an optimal set of injectors that affect a producer. Finally, a simple method is presented for converting producer-centric IPR values to injector-centric IPR values so that reservoir engineers can easily see which producers are being affected by a specific injector.
A Mutual Information-Based Metric for Identification of Nonlinear Injector Producer Relationships in Waterfloods
Authors: Khodaei A. , Lee Hyokyeong , Banaei-Kashani F. , Shahabi C. , Ershaghi I. 
Published: March 2009

Abstract
In this paper we introduce a new analytical approach for management of waterfloods in heterogeneous reservoirs. The main contribution is the development of a process and metric to evaluate the pair-wise injector-producer (IP) relationships, i.e., to quantify the impact of any injection well on the neighboring producing wells. The proposed metric is particularly designed to consider the non-linearity of the IP relationship between the injection and production rates by using the Mutual Information (MI) data mining tool. Non-linearity of the IP relationship is the main challenge in quantifying this relationship and, to the best of our knowledge, this is the first time that MI is used in the petroleum literature for IP relationship identification. In addition to MI that captures the non-linear correlation in the IP relationship, our metric considers other parameters such as the distance between the IP pair as well as their relative injection and production rates, respectively. Leveraging our proposed metric, we propose a system, for optimal waterflooding with which a field engineer can automatically: Identify the under-performing producers based on their performance characteristics such as wateroil ratio, gas oil ratio, and oil production rate;Rank all injectors based on their impact on the under-performing producers using our proposed IP relationship identification metric;Decide on optimal injection volumes for individual injectors that have the most impact on the under-performing producers and maximize the recovery factor.
The proposed technique can significantly reduce the decision-making time for the effective management of complex waterflood.
Combining Step-Rate Well Test with Transient-Pressure Test: Is it Possible?
Authors: Silin Dmitriy , Robin George 
Published: March 2009

Abstract
The step rate well test (SRT) is a well-established tool for estimating formation parting pressure. The procedure consists of a sequence of injection intervals, on each of which the injection rate is constant. The rate increments between the intervals are usually the same, and the time durations of these intervals are equal to each other. A conventional transient pressure test requires the well to be shut-in for a substantial period of time in order to estimate hydraulic formation properties in the vicinity of the wellbore. Combining these two tests in one offers great benefits, since each test requires interruption of regular operations and providing storage capacities for storing the injectate until operations can be resumed.
Step-rate test evaluation is based on a single data point for each interval. However, if one saves the data points covering transition from one rate to another, this information can be used for transient analysis. Moreover, transient analysis of SRT data can provide an estimate of the parting pressure with a higher accuracy. We will present a theoretical justification of this statement, and show examples of transient analysis of SRT data using the ODA (Operations Data Analysis) code.
Cost-Effective Production-Enhancement Solution for Heavy Oil
Authors: Gorham Tim , Rodriguez Samuel E. , Wise John , Ripley Michael , Dyer Richard J. 
Published: March 2009

Abstract
Heavy oil, oil &lt; 17o API, accounts for a growing percentage of the production and reserve portfolios of North American Oil Producing Companies. A key challenge in the production of heavy oil is that its properties provide a greater likelihood of common damage mechanisms and result in a drop in production rates.
Historically, operators of heavy oil reservoirs have used several options to address the common damage mechanisms of asphaltene, paraffin and inorganic scale depositions, as well as wettability changes in order to increase the production of their existing wells. However these options are generally limited to costly and resource consuming methods such as cyclic steam injection and workover rig based liner or perforation washes.
A cost effective alternative production enhancement process to these types of well interventions has been implemented in the Midway Sunset heavy oil field (Kern County, California). This alternative production enhancement process is based on a combination of candidate selection practices and a unique blend of solvents, surfactants, and acid. To date 2,500+ individual well treatments have been performed in a field wide application of this technology. A 27% average increase in oil production rates was observed for the wells that were treated. On a well by well basis a 73% economic success rate was achieved with an overall project economic return of greater than 500% ROI. This process significantly reduces the reliance solely upon workover rigs and steam for stimulation purposes. Additionally production downtime is limited to twenty four to forty eight hours and repeat applications to maintain increased production are only required every 90-120 days.
As with many tools and techniques in the oilfield, proper well selection and application directly affects the effectiveness of the tool or technology. The modifiable, multifunctional treatment fluid allows for the remediation of depositional damage mechanisms such as asphaltenes, paraffin, and inorganic scales and allows for wettability modification to restore the near-wellbore region to a water wet state.
Continued Development of Mature Heavy-Oil Field With Strong Waterdrive Using Mechanistic Reservoir Simulation
Authors: Han Mei , Tajer Ehsan S. , Fox Carrie M. , Behm Ed J. 
Published: March 2009

Abstract
Recent success with horizontal infill wells is evaluated using mechanistic modeling to aid in the understanding of observed performance and then assesses potential for unswept regions and additional drilling opportunties.
A mechanistic simulation approach is used to model the reservoir because few modern logs and only key production rates are available. Historical reservoir pressure, oil rates and water cuts of vertical and recent horizontal wells were modeled successfully. The model shows that edge-water drive has limited effect on oil displacement in the upper-section of reservoir with proximity to the aquifer. Early vertical wells drilled in this area had low oil recovery because of the bottom water. Recent horizontal well production performance has bolstered confidence to drill near the edges of the field to provide additional incremental production. Recent drilling results support these findings.
Mechanistic simulation approach was successfully used as a fast and efficient technique to understand recovery mechanisms and exploit potential.
Reserves in Unconventional Reservoirs: Effect of New SEC Rules
Authors: Lee W. John 
Published: March 2009

Abstract
The United States Securities and Exchange Commission, on December 29 2008, adopted new rules for disclosing oil and gas reserves. The definitions contained within these rules are broadly consistent with the SPE Petroleum Resources Management System (PRMS); the definitions in the previous rules differed from PRMS in a number of specific instances. A notable difference in the new rules is inclusion of more unconventional resources as potential oil and gas reserves rather than as mining reserves. These new rules offer enhanced opportunities for investors to understand the potential values of oil and gas companies and for companies to access the capital markets in the United States more efficiently.

Disclaimer
The opinions expressed in this paper are mine alone, and represent neither the opinions of the United States Securities and Exchange Commission nor of its staff members.
New Cu(II), Co(II), and Ni(II) complexes with thieno[2,3-b]pyridine and 2-methylthieno[2,3-b]pyridine as ligands: Synthesis and crystal structures
Authors: Halgaš Ján , Kolenová Viera , Števíková Zuzana , Perašínová Lucia , Kožíšek Jozef 
Published: March 2009

AbstractAlthough thienopyridines attract attention because of their biological activities, they have not been used as ligands in coordination compounds. Thieno[2,3-b]pyridine was prepared by known procedures; by reduction of 2-nitrothiophene, and reaction of the resulting 2-thienyl ammonium salt with malondialdehyde tetramethylacetal in the presence of zinc chloride. The same procedure was used for the preparation of a new derivative, 2-methylthieno[2,3-b]pyridine, starting from 2-methyl-5-nitrothiophene. The thienopyridines were used in the synthesis of coordination compounds. Chlorides, isothiocyanates, acetates, and chloroacetates of copper(II), nickel(II), or cobalt(II) were used as starting salts. The prepared complexes were characterized by elemental analysis and FT IR. Structures of the four complexes were determined by single-crystal X-ray diffraction analysis.
Global optimization for parameter estimation of differential-algebraic systems
Authors: Čižniar Michal , Podmajerský Marián , Hirmajer Tomáš , Fikar Miroslav , Latifi Abderrazak 
Published: March 2009

AbstractThe estimation of parameters in semi-empirical models is essential in numerous areas of engineering and applied science. In many cases, these models are described by a set of ordinary-differential equations or by a set of differential-algebraic equations. Due to the presence of non-convexities of functions participating in these equations, current gradient-based optimization methods can guarantee only locally optimal solutions. This deficiency can have a marked impact on the operation of chemical processes from the economical, environmental and safety points of view and it thus motivates the development of global optimization algorithms. This paper presents a global optimization method which guarantees ɛ-convergence to the global solution. The approach consists in the transformation of the dynamic optimization problem into a nonlinear programming problem (NLP) using the method of orthogonal collocation on finite elements. Rigorous convex underestimators of the nonconvex NLP problem are employed within the spatial branch-and-bound method and solved to global optimality. The proposed method was applied to two example problems dealing with parameter estimation from time series data.
Determination of alkaloids in Corydalis yanhusuo using hollow-fibre liquid phase microextraction and high performance liquid chromatography
Authors: Lu Huawei , Sun Huanquan , Liu Xia , Jiang Shengxiang 
Published: March 2009

AbstractHollow fibre based liquid phase microextraction (HF-LPME) with high performance liquid chromatography (HPLC) was developed for the determination of alkaloids in Corydalis yanhusuo. Three alkaloids (protopine, tetrahydropalmatine, tetrahydroberberine) were extracted from a 10 mL alkaline sample (donor phase) to an organic phase impregnated in the pores of the hollow fibre, and then, they were extracted to an acidic solution (acceptor phase) in the lumen of the fibre. The extract was determined directly by HPLC. Parameters affecting the HF-LPME include the organic solvent, pH of the donor and the acceptor phase, the extraction time and the stirring speed were investigated systematically. To minimize the error of the injection, palmatine was added as an internal standard (I.S.). Under optimal conditions, calibration curves were obtained in the range of 0.1–1.0 mg L−1 with a reasonable linearity (r 2 > 0.993) and the limits of detection (LODs) ranged between 10.0 × 10−3 mg L−1 and 13.7 × 10−3 mg L−1. Additionally, enrichment factors with 100 to 184-fold were obtained. The method was then applied to the crude extract of Corydalis yanhusuo successfully.
A rapid in vitro assay of cobalamin in human urine and medical tablets using ICP-MS
Authors: Zhang Gai , Liu Jianbo , Meng Zuchao , Wang Xin 
Published: March 2009

AbstractA rapid and simple as well as sensitive inductively coupled plasma mass spectrometry (ICP-MS) method for the determination of cobalamin is described. Cobalamin in human urine and medicine tablet solutions was converted on-line into free cobalt ions in acid medium, the cobalt ions were then detected by ICP-MS. Cobalamin was determined by measuring the increase of integral counts per second intensity, which was linear over the cobalamin concentration range of 1.0 × 10−10 g mL−1 to 8.0 × 10−5 g mL−1, and the limit of detection was 0.05 ng mL−1 (3σ). At the pump rate of 30 rotations per minute, one analysis cycle of cobalamin, including sampling and washing, could be accomplished in 0.5 min with the relative standard deviations of less than 5 %. The proposed procedure was applied successfully in monitoring cobalamin in human urine without any pretreatment process and in rapid determination of cobalamin in multivitamin tablets.
A simple flow injection spectrophotometric determination method for iron(III) based on O-acetylsalicylhydroxamic acid complexation
Authors: Andac Muberra , Asan Adem , Isildak Ibrahim 
Published: March 2009

AbstractA simple and rapid flow-injection spectrophotometric method for the determination of iron(III) and total iron is proposed. The method is based on the reaction between iron(III) and O-acetylsalicylhydroxamic acid (AcSHA) in a 2 % methanol solution resulting in an intense violet complex with strong absorption at 475 nm. Optimum conditions for the determination of iron(III) and the interfering ions were tested. The relative standard deviation for the determination of 5 μg L−1 iron(III) was 0.85 % (n = 10), and the limit of detection (blank signal plus three times the standard deviation of the blank) was 0.5 μg L−1, both based on the injection volumes of 20 μL. The method was successfully applied in the determination of iron(III) and total iron in water and ore samples. The method was verified by analysing a certified reference material Zn/Al/Cu 43XZ3F and also by the AAS method.