bluuebunny/crossref_metadata_2025_split huggingface dataset:
Phase Behavior of Gas Condensates in Shales Due to Pore Proximity Effects: Implications for Transport, Reserves and Well Productivity
Authors: Devegowda Deepak , Sapmanee Kanin , Civan Faruk , Sigal Richard 
Published: October 2012

Abstract
The present study investigates the alteration of the properties, transport, and production of gas-condensates in shale gas reservoirs and develops and demonstrates an effective and practical methodology to apply these modifications in existing numerical simulation software. Simple models that investigate the phenomena can be investigated without the need for any modifications to an existing simulation code, but realistic models will require significant modifications. Our modeling results indicate that when pore sizes are in the sub-10 nm range, typical of many gas shales, the influence of pore walls on the phase behavior and viscosity of typical gas-condensate fluids is dramatic, in both organic and inorganic pores, and creates favorable fluid and transport conditions leading to enhanced production. This is because the fluid mixture in such porous formations tends to exhibit behavior similar to that of a dry gas or a leaner gas-condensate system, thereby reducing the condensate banking effect considerably in the near-wellbore region and consequently, not impairing the productivity of the producing well. The results also underscore possible reasons for the significant production of condensate liquid from these nanoporous media in contrast to what is expected based on the industry's collective experience with conventional reservoirs. Consequently, the analysis and exercises carried out in this article provide valuable insights into the nature of fluid behavior and advances our understanding of the mechanisms of gas-condensate transport in extremely low permeability nanoporous media.
Inaccuracy in Pipeline Compressor Station Construction Cost Estimation
Authors: Rui Zhenhua , Metz Paul , Wang Xiaoqing , Chen Gang , Zhou Xiyu , Reynolds Douglas 
Published: October 2012

Abstract
The aim of this paper is to investigate pipeline compressor station project cost overruns. A total of 220 pipeline compressor station projects constructed between 1992 and 2008 have been collected, including material, labor, miscellaneous, land, and total costs, compressor station capacity, location, and year of completion. Statistical methods are applied to identify the distribution of cost overruns and overrun causes. Overall average overrun rates of pipeline compressor station material, labor, miscellaneous, land and total costs are 0.03, 0.60, 0.02, −0.14, and 0.11, respectively. Cost estimations of compressor station construction components are biased except for the material cost. In addition, the cost estimation errors of underestimated compressor station construction components are generally larger than those of overestimated components. Results of the analysis show that compressor station project size, capacity, location, and year of completion have different impacts on individual construction cost component cost overruns.
Autonomous ICD Single Phase Testing
Authors: Least Brandon , Greci Stephen , Burkey Russell , Ufford Adam , Wileman Angel 
Published: October 2012

Abstract
Reservoir flow control is important for maximizing hydrocarbon production. Traditional in-flow control devices (ICDs) attempt to balance the completion pressure differential with the reservoir pressure differential so that even flow across production zones is maintained. This maximizes oil production by delaying unwanted fluids from breaking through. Unfortunately, when lower viscosity fluids do break through, they take over the well, significantly reducing production of the desired hydrocarbon. This paper describes the design and function of a new self-adjusting in-flow control device (AICD). When hydrocarbons are producing from all zones, the AICD will behave as a traditional ICD, balancing flow. However, when low-viscosity fluids break through, the AICD chokes them, significantly slowing flow from the zone producing the undesirable fluids. This autonomous function enables the well to continue producing the desired hydrocarbons for a longer time, maximizing total production.
The paper describes the laboratory testing performed to evaluate the performance of the new AICD in field-like conditions. Results from single phase experimental flow testing with model fluids are presented and discussed.
The testing results proved that the AICD could restrict flow from zones producing undesirable fluids. The discussion further shows that if technology such as the new AICD is applied to new well completion designs, total hydrocarbon recovery will be enhanced, providing a significant benefit for production companies and those involved in design and modeling of new well completions.
Development of a Correlation for the Estimation of Condensate to Gas Ratio CGR and Other Key Gas Properties From Density/Molecular Weight
Authors: Dindoruk Birol 
Published: October 2012

Abstract
Condensate to Gas Ratio (CGR) is a measure of liquid content of a naturally occurring hydrocarbon mixture that is classified as gas condensate at reservoir conditions. It is also one of the most important parameters that impacts the economics of gas projects. In many cases, especially in the case of stranded gas, significant project value will be drawn from the liquid content of the gas. There are number of difficulties in measuring the CGR of a gas stream in the laboratory, or sometimes simply the value may not be known. Some of the difficulties in lab processes (but not limited to) originate from:
Non-equilibrium flash and carry-over Amount of the fluid used (volume constraints and errors)
In this paper, we have developed a simple easy to use semi-empirical correlation that accurately estimates the CGR of a gas condensate system using fluid densities (or molecular weights). Fluid densities can be obtained either from gradient measurements or directly from the laboratory measurements. To our knowledge, there is no equivalent correlation published in literature. The proposed correlation can be used for:
Exploration support to estimate the CGR ranges (valid up to CGR = 350 STB/MMSCF). Form a yard-stick to quality-check laboratory experiments. Generate necessary input parameters for other key gas properties: such as Z-factor, gas formation volume factor, Molecular weight, gas viscosity and even compositions. Reconciliation of contaminated samples against the measured or estimated fluid densities.
Uncovering the Potential of Thin, Tight Gas Reservoirs in Sichuan Basin, China - New Development Campaign Using New LWD Imaging Technology and Innovative Interpretation Workflows
Authors: Gang Lv Zong , Run Peng Hai , Qin Xia , Rong Li Qi , Parlindungan H. M. , Zhao Jing Kai , Denichou Jean-Michel , Yuk Ha Stephanie Chow , Ju Song 
Published: October 2012

ABSTRACT
Located in central China, the Sichuan basin holds the biggest gas reserve in the country. Tight gas reservoir (limestone, dolomite, and tight sand) development has been taking place since early 1992.
Since then, relatively thicker gas reservoirs have been commonly developed, and more challenging, very thin reservoirs are now being targeted. Long horizontal drilling combined with multistage hydraulic fracturing is planned. However, the management of the subsurface uncertainties appears as the biggest challenge.
Located in a major compressional tectonic area, the geological province presents reverse/thrust faults and high structural dip uncertainty. Lateral property changes in the dolomite target reservoir and a stratigraphic thickness of the reservoir that varies from 1 m to 2 m add to the difficulty.
To overcome these challenges and to enhance reservoir understanding, advanced logging-while-drilling acquisition and real-time transmission of high-resolution electrical borehole images, azimuthal gamma ray, and multidepth measurement of formation resistivity were deployed in a recently completed gas well.
Based on these data and advanced techniques, structural features including dips, faults, and fractures could be clearly identified in real time while drilling and helped the team to: 1) accurately geosteer the well and significantly reduce the probability of erroneous lateral placement and 2) optimize the completion design and planning of the hydraulic fracturing staging and segmentations.
Completed in 2011, the well represents the first successful completion in the thin, tight gas reservoir; a 1095-m horizontal section was drilled with 91% net-to-gross and the gas production was recorded at 123 700 m3/d, exceeding the set production goal of the well by 33%.
This particular success is proving that a thin, tight gas reservoir can be profitably developed. Several subsequent wells have been planned to be drilled in different target zones in the Sichuan basin.
Wettability in CO2/Brine/Quartz Systems: An Experimental Study at Reservoir Conditions
Authors: Saraji Soheil , Goual Lamia , Piri Mohammad 
Published: October 2012

Abstract
A new experimental setup is developed that is capable of performing accurate IFT and contact angle measurements under extreme conditions, i.e., high pressure (up to 15,000 psi), high temperature (up to 200°C), and with highly corrosive fluids. The apparatus is equipped with an advanced and accurate temperature control system and a pulse-free Quizix pump to provide precise and stable experimental pressures and temperatures. Pre-equilibration of phases is achieved before each test, outside the measurement cell, to avoid non-equilibrium effects. Using an advanced drop shape analysis technique (ADSA-NA) and an automated polynomial fit, advancing and reseeding contact angles were measured with a protruded needle. The results cover a range of temperatures and pressures including subcritical and supercritical CO2 phases allowing characterization of wettability under both conditions. This preliminary study shows that wettability of quartz surface alters towards less water-wet condition when CO2 phase changes from subcritical to supercritical conditions. In addition, changes in wettability of quartz may not be monotonous function of temperature.
Artificial Lift Optimization with Foamer Technology in the Alliance Shale Gas Field
Authors: Farina Lisa , Passucci Claudio , Di Lullo Alberto , Negri Emanuele , Anderson Shawn , Page Stan 
Published: October 2012

Abstract
In the last years, the shale gas business has gained increasing emphasis within the major oil & gas companies. In particular, Quicksilver Resources and eni e&p, through its subsidiary eni US Operating Co., and are jointly involved in the development of the Alliance shale gas field in the prolific Barnett shale play located in Texas. Recently, both companies started a common effort to optimize production and lift costs. Such efforts included a deeper analysis of the artificial lift performance and exploitation of additional deliquification technologies.
In fact, typical shale gas wells are adversely affected by the continuous flow-back of the huge volumes of water used for the frac jobs. In the Alliance field, the most common way to support deliquification was by injecting lift-gas through the casing. Foaming agents were only occasionally deployed and a comprehensive activity to assess their technical and economic performance has been conducted.
In the last six months, extensive foamer injection tests have been performed on several wells, considering the effect of a factors such as production/injection mode (tubing or casing), foamer type and rate, lift-gas rate, gas and water rates and wellhead pressures. The uncommon synergy of continuous foamer and lift-gas injection has also been extensively exploited in horizontal wells.
At the end of the test phase, more than one third of the producing wells had been treated with a foamer and relevant technoeconomic improvements had been achieved. The paper describes in detail the methodology, the field experience and the results obtained.
Development of a Vogel type Inflow Performance Relationship (IPR) for Horizontal wells
Authors: Ogunleye Ayowole Onoopemipo 
Published: October 2012

Abstract
Vogel1's Inflow performance relationship (IPR) is the most frequently used method for evaluating productivity of vertical wells and it has also been proven to be reliable and accurate. Due to this and the increase in the use of horizontal wells, a Vogel type inflow performance relationship for horizontal wells is developed in this paper and skin is included into the equation generated in terms of flow efficiency.
The model is developed by inputting Vogel1, base case parameters into a Reservoir Simulator (Eclipse) and configuring the model as a vertical well. The results of the simulation are then validated with the Vogel1 Reference curve and after validation the configuration of the model is changed from that of a vertical well to a horizontal well. From this horizontal well model, a Vogel type IPR for horizontal wells is developed and skin which is a major factor affecting the productivity of wells is included into the equation generated.
This developed Vogel type IPR for horizontal wells accounts for the flaws of previously used correlations for predicting the performance of horizontal wells. This is achieved by accounting for the heterogeneity of the reservoir as other correlations for predicting the productivity of horizontal wells have assumed a homogenous reservoir which is not the case in real reservoir situations. Skin is also included in thus Developed Vogel type IPR as other correlations have assumed a Zero skin, which is also not the case in real situations.
Finally, the developed Vogel type IPR is tested for accuracy and consistency by comparing it frequently used correlations and the results obtained shows this Developed IPR is consistent and accurate and can therefore be used for evaluating the productivity of horizontal wells.
Modeling and Investigation of the Influence of Capillary Heterogeneity on Relative Permeability
Authors: Krause M. H. 
Published: October 2012

Abstract
A recently developed technique to accurately characterize sub-core scale heterogeneity by Krause et al. (2011, 2012) is applied to investigate the flow rate dependency of relative permeability on heterogeneity. Leverett (1939) first reported the dependency of laboratory measured relative permeability on flow rate, these results have since been both supported (Rapoport and Leas 1953) and challenged (Richardson 1957) by a number of investigators. Studies have shown that this apparent flow rate dependency is a result of both sub-core scale heterogeneity (Corey and Rathjens 1956) and outlet boundary effects (Richardson et al. 1952), however this has only been demonstrated numerically for highly simplified models of porous media. In this paper, flow rate dependency of effective relative permeability is demonstrated using two sandstone rock cores, one a Berea Sandstone having a low degree of heterogeneity, the other a heterogeneous sandstone from the Otway Basin Pilot Project in Australia. Steady-state coreflooding simulations are conducted at a number of injection rates using a single set of input characteristic relative permeability curves, and flow rate dependent effective relative permeability is calculated from the simulation data using Darcy's law. An optimization procedure is then used to derive the input characteristic relative permeability from the flow rate affected effective relative permeability. Results show that even in a Berea Sandstone, which has a relatively low degree of heterogeneity, the impact of fine-scale heterogeneities on measured relative permeability can be significant. Results also show that the apparent flow rate dependency of effective relative permeability is a stronger function of fine-scale heterogeneities than of capillary pressure gradients caused by the end effect. In addition to these observations, this work supports two important conclusions: the first is that using a one-dimensional homogeneous grid to simulate what is really a three-dimensional heterogeneous core can lead to significant errors in the derived relative permeability, even for cores of low heterogeneity. Second, the characteristic relative permeability curves can be accurately determined using flow rate affected effective relative permeability data using numerical simulation, provided the sub-core scale permeability distribution is accurately characterized.
The Study of Mass Transfer between Phases in Gas and Organic Drilling Fluid Mixtures
Authors: Policarpo N. A. 
Published: October 2012

Abstract
The study of mass transfer between phases is a very important issue during drilling operations with organic based drilling fluids. The research in the area is necessary to understand the interaction between the formation fluid (oil and/or gas) and the synthetic drilling fluid filtrate inside the invaded zone and also during a kick situation. A comprehensive literature search was conducted in order to identify the state of the art in the subject and to choose the appropriate experimental procedure and physical/mathematical modeling technique.
The present experimental work comprises the measurement and modeling of the diffusivity and interface mass transfer coefficients for those gas-liquid systems. The experimental data were obtained with accurate PVT measurements, under high pressure and high temperature conditions. The tests were carried out in the 70°C through 120°C temperature range for n- paraffin liquids with the following mole fraction of gas: i) 15% to 91% mol of CH4 and ii) 27% to 75% mol of CO2. The pressure decay method, which is based on the gas phase pressure decline with time as a consequence of the diffusion process, was applied to data modeling. A transient state diffusion model, with short and long term analytical solution, was applied to determine the mass transfer parameters for the two mixtures: CH4/n-paraffin and CO2/n-paraffin. The results of this ongoing research have two important contributions: i) to increase the safety during well control operations, mitigating the risk of blowouts, and ii) to understand the interaction of formation gas and organic based drilling fluids, especially in reservoir with high CO2 content, as those encountered in the recently found Brazilian sub-salt reservoirs.
Development of a Coupled Wellbore/Reservoir Simulator for Damage Prediction and Remediation
Authors: Shirdel Mahdy 
Published: October 2012

Abstract
Particle deposition is a complex problem in oil fields which affects all aspects of petroleum production, processing, and transportation. Asphaltene deposition has been repeatedly reported in various oil fields with interest on how it impacts the development of a reservoir. In many of the reported cases, it has been indicated that asphaltene deposition damages the wellbore and production facilities more severely than the formation.
A great deal of research has been conducted to study the phase behavior and dynamic aspect of asphaltene deposition. However, there is a lack of comprehensive integrated modeling of asphaltene deposition in the wellbore during the multiphase fluid flow. In this paper, we present an implementation of asphaltene precipitation and deposition models into a thermal, multiphase, multi-component wellbore simulator that can be coupled with a compositional reservoir simulator.
A key contribution of this work is the development of a simulator for predicting the detrimental effects of asphaltene in a well. Simulation results can show where and when the presence of asphaltene particles severely damages the efficiency and the productivity of the wells. This prediction is highly crucial if it is aimed to control the well performance and to optimize productivity.
Analysis and Potential of CO2 Huff-n-Puff for Near Wellbore Condensate Removal and Enhanced Gas Recovery
Authors: Odi Uchenna 
Published: October 2012

Abstract
Wet gas fields often experience reduction in productivity due to condensate banking in the near wellbore region. This occurs when the pressure in the near wellbore region falls below the dew point pressure and also when gas flow in tighter matrixes results in production of lighter components and the liquid dropout of heavier components. Carbon dioxide (CO2) in a process termed CO2 Huff-n-Puff can be used to lower the dew point of the condensate blocking the wellbore, thus removing the condensate blockage. To use CO2 Huff-n-Puff requires analysis of the potential of the interaction between CO2 and condensate. This analysis includes investigation of the impact that CO2 has on dew point pressure, effusion, diffusion coefficients into condensate, and productivity index. The overall objective of this work is to illustrate the potential of using CO2 to remove near wellbore condensate and for CO2 EGR.
To maintain field gas production targets, operators routinely set the bottom hole pressure below the dew point pressure which results in condensate blockage. Injecting CO2 can delay the onset of condensate blockage by reducing the dew point pressure of the condensate blockage zone. The approach illustrated, utilizes CO2 to delay the onset of condensate blockage. Factors such as improved effusion, diffusion, condensate skin factor, and productivity were analyzed to justify the use of CO2 for wellbore condensate removal and EGR.
Results show increases in productivity index after CO2 injection. Increases in productivity index were caused by CO2 evaporating the condensate blockage. Condensate vaporization was caused by CO2 reducing the dew point pressure of the condensate while repressurizing the reservoir above the reduced dew point pressure. Improvements in relative permeability profiles were used to quantify the success of the Huff-n-Puff process while improvements in NPV were used to illustrate the economic impact of using CO2.
Condensate blockage in wet gas reservoirs can be very detrimental in obtaining economic gas recoveries. This work is applicable to quantifying the potential CO2 Huff-n-Puff for near wellbore condensate removal and designing optimal EGR schedules. Results of this work provide a basis for justifying the use of CO2 as a treatment fluid and EGR solvent.
Audit Reporting for Going-Concern Uncertainty: A Research Synthesis
Authors: Carson Elizabeth , Fargher Neil L. , Geiger Marshall A. , Lennox Clive S. , Raghunandan K. , Willekens Marleen 
Published: October 2012

SUMMARY
In this synthesis we review research on going-concern modified audit opinions (GCOs) and develop a framework to categorize this research. We identify three major areas of research: (1) determinants of GCOs that include client factors, auditor factors, auditor-client relationships, and other environmental factors; (2) accuracy of GCOs; and (3) consequences arising from GCOs. We identify method-related considerations for researchers working in the area and identify future research opportunities.
Measuring Top Management's IT Governance Knowledge Absorptive Capacity
Authors: Ali Syaiful , Green Peter , Robb Alastair 
Published: October 2012

ABSTRACT
Top management's involvement in IT governance appears to positively influence the establishment and implementation of effective IT governance within organizations. Considering the lack of advancement in the area in practice, this study offers a deeper understanding of dimensions that help to explain top management's knowledge of IT governance. Using absorptive capacity as its theoretical underpinning, and based on Australian empirical data, this study shows that for top management to achieve higher levels of absorptive capacity of IT governance knowledge (ACAP-ITG), they need to focus on four dimensions: prior relevant knowledge, effective communication network, appropriate communication climate, and effective knowledge scanning. To further support the usefulness of the ACAP-ITG construct, this study empirically tested the relationship between the construct and corporate performance. This study presents top management in organizations with useful measures that can help them assess their organization's strengths and weaknesses related to ACAP-ITG.