bluuebunny/crossref_metadata_2025_split huggingface dataset:
Modern Marine Transport of Compressed Natural Gas in 2010
Authors: Wang Xiuli , Economides Michael J. 
Published: February 2011

Abstract
Worldwide natural gas is transported with two well-established technologies: 70 percent by pipeline and 30 percent by liquefied natural gas (LNG). For offshore transportation, pipelines have a distance limit and terrain restrictions. LNG is applicable for long-haul sea distances and large gas volumes, because the facilities at both ends are expensive to construct and the entire process is complicated, costly, and energy wasteful.
We and others have proposed that compressed natural gas (CNG) transportation by boat is an alternative for shorter distances and smaller markets that are not connected to large pipelines or base load LNG accepting facilities. Although this approach has been proposed for years, it has not yet materialized into a sizeable project. The industrial emphasis on LNG has affected CNG projects and one of the reasons is that some proponents have attempted to take some market share from LNG. This is not a viable approach.
In this paper, results show that for shorter distances (e.g., 1,000 km) and especially for the far lower natural gas prices that have emerged since the 2008 economic crisis, LNG simply cannot compete with CNG. Even at longer distances (e.g., 2,000 km) CNG is still more attractive, assuming that offshore pipelines are not feasible. For smaller volumes, such as 1 to 2 billion cubic meters per year (Bcm/yr) or even less, CNG is the only solution to bring this energy source to many markets. In other words, smaller and smaller markets are ideal for CNG.
The preferred path for CNG transportation vessels may follow what we have called in earlier publications "hub -and-spoke" or cyclical "milk-run" patterns depending on market demands at the receiving sites.
These findings suggest that many parts of the world (many markets in the entire Mediterranean basin, near Sakhalin Island, places in South-East Asia and the Caribbean) would be better served by CNG even if LNG projects have already been approved and under construction near them.
Uncertainty Management: A Structured Approach Towards Recognizing, Quantifying and Managing Subsurface Unknowns
Authors: Alessio Laurent , Everts Arnout , Rahmat Faeez 
Published: February 2011

ABSTRACT
This paper illustrates, through field studies examples, why and how a structured approach towards managing uncertainties, and especially sampling biases, delivers valuable insights through the successive early asset life stages - exploration, appraisal and field development phases. In doing so, we respond to three fundamental questions.
Firstly, ‘What are the key uncertainties – those that matter?’ Field studies should begin with a comprehensive upfront assessment of uncertainties’ impact on historical and future well and field performance. However, often major factors are overlooked, leading to under-prediction of true outcome ranges and the inability to reconcile historical production. Our illustration is a large producing carbonate field, where after 15 years of production, large scale Karstification was finally evidenced to be the explanation for the field performance that couldn't be history matched with the measured matrix porosity and permeability ranges.
Secondly ‘What are realistic ranges for these uncertainties?’ Known Industry best practices include intensive expert-assist, integration of drilling, mud-logging and other traditional sources of data from the field, resorting to analogue benchmarking. Despite these, we often fail to understand and correct for sampling bias, which we show often leads to over-optimism. The paper will highlight why such biases are present and propose simple and practical methods to remove them. The case study is the volumetric assessment of a gas discoveries portfolio, where geophysical techniques were instrumental in exploration and appraisal drilling.
Finally ‘How these uncertainties will evolve with time?’ This is an important question for assessing value of Information: the impact that additional data may have on the uncertainty range of uncertainties and the base case. Unconventional fractured plays, often characterized by data abundance but extreme variability, provide surprising insights on how uncertainties ranges evolve. This paper presents methods to develop confidence curves for important parameters.
Multi-Circulation Steam Generator Concept
Authors: Corriger E. , Abry G. 
Published: February 2011

To "push" water impurities toward the tail of your Steam Generator where exchanged heat flux is low, this is the main purpose of the Multi-Circulation concept.
This is done by design with Once Trough Steam Generator (OTSG) while for water tubes drum boilers (WTD) impurities concentration in boiler water remains constant from boiler entrance (furnace side, with high heat flux and high flue gases temperature) to boiler tail (exit side with low heat flux and low flue gases temperature). Refer also to Fig 1
Both of these boilers are water tubes type: water & steam side is tubes side.
One other main specificity of OTSG boiler is also that water volume ratio decreases from 100 % at tube entrance (furnace side typically) down to 2 or 3 % -typical for 100 bar pressure - at tube exit (boiler exit typically) (Refer also to Fig 2); so such boilers can be subject to inside tubes fouling when salinity is too high and / or blow down rate is too low. You have to make arbitration between maintenance costs and water & energy costs varying in opposite way by selecting the right boiler blow down rate. Boiler yearly availability is also a consequence of this decision.
For WTD boilers, water volume ratio is quite constant from entrance to exit as for this kind of boiler, natural circulation is controlled by design; operator has no impact on this parameter for a boiler operated within it normal design range. These boilers are then less subject to tubes fouling but water characteristics are more stringent. Of course boiler tubes fouling are mainly depending on feed water quality - so on water treatment system - and on boiler characteristics such as water volume ratio, heat flux and salinity level. When salinity concentration increases and when water volume ratio is low, fouling risks by deposits are then max. With some salts such as Silica having a low thermal conductivity, even very thin deposits have a great impact on tubes wall temperature leading quickly to tubes failures if they are in hot flue gases (furnace side).
Regarding these parameters each boiler type is different and then boiler shall be selected carefully considering advantages and inconvenient of each type.
Then, if you have to operate your boiler with low quality feed water and high availability rate we would recommend you prior to select one of two well know boiler type - OTSG or WTD - to consider a third type: the MultiCirculation Steam Generator (MCSG).
The Multicirculation, what is that? A kind of OTSG / WTD hybrid: a WTD design slightly modified to include one OTSG main characteristic: variable boiler water salinity from inlet to outlet. Then this MCSG boiler has advantages of both types: Low Feed water quality, low blow down rate, high water volume ratio and then and Low Fouling risks. (Refer also to table 1).
Heating surfaces of a MCSG boiler are then subject to or highest heating flux and lowest water salinity, or lowest heating flux and highest water salinity, but never to highest flux and highest water salinity.
Inducing Spherical Flow Conditions with Formation Testers
Authors: Betancourt Soraya S. , Dussan V. E. B. , Lake Larry W. 
Published: February 2011

Abstract
Permeability is one of the most important parameters for evaluating the production potential of a reservoir. Though there are several ways to determine permeability, the focus here is on formation tester pretests. The pretest is a routine measurement that provides in situ values of formation mobility (permeability/viscosity) at several depths along a wellbore. Because this measurement is easily accessible, it is of interest to maximize the value of the information obtained.
Two types of mobility can be determined from a pretest, one of them is the mobility obtained using the amplitude of the pressure signal, usually referred to as drawdown mobility. This measurement has a very shallow depth of investigation; therefore, it characterizes only the formation in the immediate vicinity of the probe, i.e., it is an indicator of the mobility at the wellbore wall, where formation damage is likely to occur. The uncertainty associated with this mobility measurement decreases when the drawdown is long enough to approximate steady state flow. Another way of inferring mobility is done by analyzing the pressure transient signal during the late stage of buildup, during the so-called spherical flow period, hence it is referred to as the spherical mobility. This method has the advantage of characterizing properties deeper in the formation. However, the spherical flow regime is usually difficult to identify in the recorded pressure signal, and in the few instances where it has been claimed to be identified, the inferred formation mobility is almost always smaller than the drawdown mobility. A major problem in analyzing pressure data during the spherical flow period is that it requires quantifying a small rate of change in the signal as equilibrium is approached.
In this study, we model the performance of three different tool configurations with six different formations having mobility ranging from 0.001md/cp to 100md/cp, to identify the pretest parameters that maximize the pressure signal during the spherical flow regime. The results may be used as a general guideline on the selection of pretest parameters when the objective is to evaluate formation properties away from the wellbore. When representative values of drawdown and spherical mobility are obtained, it is possible to infer the undamaged formation mobility as well as the magnitude of the formation skin.
Energy Gain Efficiency in Steam-Assisted Gravity Drainage (SAGD)
Authors: Alharthy Najeeb , Kazemi Hossein , Graves Ramona , Akinboyewa John 
Published: February 2011

Abstract
Steam Assisted Gravity Drainage (SAGD) is a highly popular method for extracting bitumen in situ, and has gained wide acceptance for unlocking Canada's bitumen reserves. Although SAGD is very attractive, it is energy and labor intensive, produces significant quantity of emissions, and requires large water resource and treatment facility. This study addresses these issues by proposing a method to sequester steam boiler exhaust CO2, but focuses specifically on improving the energy gain ratio by reducing the energy input. The proposed method is to augment steam injection with less energy intensive, less expensive, non-condensable gases (CO2 and flue). To quantify the benefits of the method and assess the effectiveness of the process we use energy gain ratio as the main yardstick of the assessment. Five cases of SAGD were simulated with a thermal simulator using a bitumen field data. The study conclusively shows that the process is viable. Specifically the study results in four main conclusions: First, energy gain ratio can be improved by augmenting steam injection with non-condensable gases, for example, if we augment CO2 with steam in a cyclic fashion, energy gain increases by a factor of 1.5 to almost 2. Second, CO2 and flue gas produce the same energy gain ratios and the same recovery factors. Third, intermittent cyclic steam injection performs better than the continuous steam injection in terms of energy gain ratio and recovery factor. Fourth, the injection sequence and the length of the steam and non-condensable gas cycles are important to optimize water and gas breakthrough times. It can also be inferred that reducing steam injection produces economic gains by reducing water usage, fuel requirements for steam generation, and water softening volumes. Also augmenting steam with non-condensable gases reduces green house gas emissions.
Novel Method of Time Controllable Chemistry Water Shutoff Technology
Authors: He Liu , Dan-feng Xiao 
Published: February 2011

Abstract
In late stage of high water cut development period, difficulty in plugging high aquifers increases because the initial pore structure near well bore area has been damaged. Therefore, polymer single fluid plugging technique was developed. Single fluid plugging agent is polymerization initiated by free radical. Reaction time, which is 4-6 hours under normal hole temperature from 40°C to 60°C, is controlled by the half life and the inducement period of initiator. Whereas, in actual application, some wells, such as high temperature deep wells or channeling plugging wells, require longer or shorter gel forming period. Therefore, reaction time control analysis of plugging agent was carried out in order to increase safety and maneuverability of field operation and to expand application field. This paper describes the application of single-fluid water plugging technique in late stage of high water cut development period. Based on the actual condition in oilfield development, the recipe and operation process have to adjust correspondingly to make this technique more serialized and popular. The analysis result on field operation and typical well showed that this water plugging technique could increase oil production and decrease water cut, and satisfied the complicated geological condition of late stage in high water cut development period.
DFA Profiling of Oil Columns With Asphaltene Gradients
Authors: Zuo Julian Y. , Freed Denise , Mullins Oliver C. , Zhang Dan 
Published: February 2011

Abstract
Downhole fluid analysis (DFA) has successfully been used to delineate reservoir attributes such as vertical and lateral connectivity and properties of the produced fluids. The new-generation DFA tools measure GOR, density, light-end compositions of CO2, C1, C2, C3–C5, and C6+, and color that is linearly related to the heavy ends in real time at formation conditions. Color grading analysis in oil columns becomes vital to discern reservoir complexities by means of integrating advanced asphaltene science with DFA Fluid Profiling.
Modeling of asphaltenes and heavy ends of reservoir crude oils is only now becoming possible because of recent advances in the understanding of the molecular and colloidal structure of asphaltenes in crude oils. The Flory-Huggins polymer model has been widely used in modeling of asphaltene precipitation in the oil and gas industry. However, it has been excluded to describe asphaltene gradients in oil columns because the gravitational term requires knowledge of the sizes of asphaltenes which have been unclear until now. On the other hand, typical cubic equations of state (EOS) cannot represent asphaltenes well because of inaccurate asphaltene characterization and the lack of critical points for asphaltenes. Here, we treat the gas-liquid components of crude oil with the Peng-Robinson EOS. Heavy end gradients are treated with the Flory-Huggins formalism explicitly incorporating the size of asphaltene molecules and aggregates. All parameters in the model were related to DFA measurements such as compositions, GOR, density, etc. The variations of gas and oil properties with depth were calculated by the Peng-Robinson EOS based on DFA compositions using specifically developed delumping, characterizing, and OBM correcting techniques. In particular, oil solubility parameters are linearly related to DFA density. Filed case studies prove the value and simplicity of our heavy end treatment. A volatile oil case study shows that colored resins (heavy asphaltene-like resins) are molecularly dissolved in crude oils. Several case studies show asphaltenes are dispersed as nanoaggregates in stable crude. These case studies are in accord with the observations in the recent advances in asphaltene science. Heuristics can be developed form results herein corresponding to prediction of asphaltene gradients. For example, heavy ends (resins, asphaltenes) preferentially reside at the bottom of the oil column both because of gravity and the possible GOR gradients, thus variable solvation strengths. This methodology establishes a powerful new approach for conducting DFA color grading analysis by coupling advanced asphaltene science, the Flory-Huggins grading model, the new workflow and other information with DFA Fluid Profiling to address reservoir connectivity.
Comparison of Permeabilities and Skin Damages Results from Flow Build-up and Injection Falloff Tests in CBM Reservoirs
Authors: Taco Gelber , Kamenar Alberto , Edgoose Jeff 
Published: February 2011

Abstract
Because permeability and skin are important parameters to assess the potential success or failure of a coal seam gas or mining project, it is necessary to implement their measurement at an early stage. For this reason, a suite of Flow Build-up (FBU), Injection Falloff Test (IFT) and Step Rate Test (SRT) tests should be run early in the project but their correct design, execution and interpretation should also be carefully planned.
It is expected that permeability and skin damage outcomes from FBU and IFT tests conducted in the same layer be equal since both employ the same fluids and the same equipment; however, these outcomes are not always the same.
In a Coal field a total 91 tests were run including: 39 FBU, 33 IFT and 19 SRT. Furthermore, in 33 zones the operator conducted sequentially both the FBU and IFT tests. The results indicate that in 42% of these tests, the permeability result from FBU tests differed from the permeability derived from IFT between 0% and 10%, and furthermore, in 28% of these cases, this difference was more than 30%. It was also observed that in 85% of these tests, the skin damage recorded from IFT was higher than from FBU. These outcomes are illustrated with statistics and real examples.
It is the author's view that coal sensitivity to stress is the major contributor to the difference in the permeability results derived from the two procedures since the stress around the borehole is different during the FBU than in IFT. These differences are more frequently seen in low pressure, low permeability seams.
It is also the authors contention that, the higher skin in the IFT test is the result of damaged material (mud cake, drilling fluids and possibly coal fines) being pushed into the formation by the pumping action during the injection period of the IFT test. This effect is noticed more frequently when the well is killed post FBU test to retrieve the testing tool from the well and re-run for the corresponding IFT test.
In summary, with knowledge of the true coal permeability, stress and skin at an early stage by measurement, the project risk of failure could be reduced. The combined effort of the operator who carries out the testing and the analyst who interprets it will help to achieve this aim.
Customized Insulating Packer Fluid Improves Steam Injection Well Integrity
Authors: Turner Jay , Ezell Ryan , MacMillan Brian , Ezzat Dodie 
Published: February 2011

Abstract
Excessive unsupported casing growth at the surface is a problem which could dramatically affect the integrity of the steam injection wells. This problem was recently encountered in a Middle East oil field where severe cement fallback on numerous wells caused excessive casing growth upon injecting steam. Surface steam supply lines could accommodate up to 4 ft (1.2 meters) of casing growth, but the wells with poor cement bond experienced up to 8 ft of wellhead movement. Remedial cement placement was not an acceptable option for injection wells that require perforated casing. An alternative economical method to control casing growth was therefore needed.
Fresh water was normally placed in the annulus, which evaporated and released to the atmosphere due to the very high steam temperature (ca. 575°F/300°C). Heat transfer to the casing was very high, causing the excessive casing expansion. Controlling this heat transfer will limit wellhead movement while retaining the energy in the steam for more efficient reservoir heating and oil recovery.
A high temperature insulating fluid was custom-designed for these subject wells. The solids-free water-based fluid had low inherent heat transfer and was gelled with a unique stable inorganic viscosifier to prevent convection at the target temperature. Preventing convection is a key factor in reducing heat transfer. After four days of steam injection, the operator reported that wellhead movement was half of that in offset wells completed with fresh water as the packer fluid. This paper will present and discuss the lab and field data for the new insulating fluid which offers several advantages in reliability and performance for extreme temperature applications such as the geothermal and steam injection wells.
Logging-While-Drilling in Unconventional Shales
Authors: Market Jennifer , Quirein John , Pitcher Jason , Hinz David , Buller Dan , Al-Dammad Chaled , Spain David , Odumosu Tobi 
Published: February 2011

Abstract
Unconventional shale environments have traditionally been evaluated with wireline logging tools. Recently, it has become more common to evaluate these wells with logging-while-drilling tools because of challenges such as wellbore stability problems that make it risky to leave the hole uncased long enough to run wireline. This paper discusses when it may be appropriate to log unconventional shale environments with LWD tools, the services that are available, and the possible advantages of real-time data while drilling. It also describes the possible differences in the LWD and wireline measurements, including such factors as openhole vs. cased hole data acquisition, time-lapse effects, and anisotropy responses of sonic, resistivity, and nuclear tools.
The paper presents examples from the Bakken and Haynesville shales, including azimuthal resistivity, density, caliper, and sonic data. Special considerations for interpreting logs in these environments are discussed, particularly regarding log interpretation in high angle wellbores. Finally, details about the optimization of the logging program and tool configurations are provided for ideal data acquisition in unconventional shale environments.