bluuebunny/crossref_metadata_2025_split huggingface dataset:
Gas Production System From Methane Hydrate Layers by Hot Water Injection Using Dual Horizontal Wells
Authors: Sasaki K. , Ono S. , Sugai Y. , Ebinuma T. , Narita H. , Yamaguchi T. 
Published: June 2010

Abstract
In this study, we investigate a system of gas production from methane hydrate layers involving hot water injection using dual horizontal wells. Physical and numerical models simulating the gas production process from methane hydrate layers within a hot water chamber are proposed.
Experiments with scaled two-dimensional physical models using an imitated hydrate layer (NaHCO3 ice formation) were performed to investigate fluid flow characteristics and production performance. The thermal simulator was used to simulate experimental chamber growth and field production. Numerical simulations for the processes were successfully performed with a two-component (water and oil or methane hydrates), three-phase (water, methane hydrates and methane gas) and three-dimensional model, matching the physical model. Results of the history-matched numerical simulations were in good agreement with data on production and chamber shapes obtained using the Intermediate3-Stone1 wettability model. Simulations of field production using dual horizontal wells 500 m in length were performed to evaluate cumulative gas production over 3 years of injection with 500 × 103 kg/day of hot water, which varied from 5 × 106 to 9 × 106 std m3. The production process appears economical, in view of the expected convective heat transfer from the chamber boundary and buoyancy force on dissociated methane gas.

Introduction
Recent studies confirm that conserved methane hydrate deposits in sedimentation layers at a depth of more than 200 to 300 m from the bottom of the sea floor can be utilized as novel natural gas resources. In-situ hydrate decomposition into water and gas is required to produce methane gas economically from these layers, since methane hydrate is a type of non-mobile solid energy resource. To trigger methane hydrate decomposition, decompression or temperature increase out of the equilibrium zone is necessary, while heat should be supplied for continuous dissociation. Accordingly, new gas production systems that supply heat continuously into the methane hydrate layers have been reported. The conventional methods of gas production to date include depressurization, inhibitor injection and thermal recovery.
Effects of SO2 and pH Concentration on CO2 Adsorption Capacity in Coal Seams for CO2 Sequestration With Considerations for Flue Gas From Coal-Fired Power Plants
Authors: Huy P.Q. , Sasaki K. , Sugai Y. , Kiga T. , Fujioka M. , Adachi T. 
Published: June 2010

Abstract
Coal-fired power plants produce flue gas consisting mainly of nitrogen (around 79%), followed by CO2 (around 10 - 15%), and small amounts of other gases such as H2, NOx and SO2. One of the promising methods for reducing CO2 emission is CO2 sequestration into deep, unminable coal seams. At present, flue gases exhausted from coal-fired plant must be separated to extract pure CO2 before injecting it into coal seams.
In order to enhance the efficiency of carbon capture and storage (CCS) from a coal-fired power plant, oxy-fuel combustion technology has been employed. This technology uses pure oxygen to burn the coal, and consequently CO2 concentration in the flue gas is theoretically increased up to 95%.
This study aims to simulate the CH4 replacement mechanism in coal by using pure CO2 and a synthesized flue gas (99% CO2 and 1% SO2) that is similar to the emission gas from the coal-fired power plants. A measurement procedure for gas adsorption is employed which, after establishing methane adsorption equilibrium of the coal samples, injects pure CO2 or the synthesized flue gas into an adsorption cell in order to investigate CH4 replacement properties. Coal samples used for the present experiments were taken from the coal seams of Vietnam, Japan, Australia, China and Indonesia. The samples were crushed to particle sizes ranging from 250 µm to 5 mm. The concentration of gases was taken from the adsorption cell and analyzed by using a gas chromatograph. Adsorption isotherms of CH4, CO2 and SO2 were measured by using the volumetric method apparatus.
This paper discusses the characteristics of methane replacement by using pure CO2, the synthesized flue gas and the effect of SO2 on adsorption properties of coal.

Introduction
Global warming and climate change due to the greenhouse effect continue to be a serious problem. In particular, CO2 emission into the atmosphere from coal-fired power plants needs to be reduced. One of the most promising methods of reducing CO2 emissions is CO2 sequestration in deep, unminable coal seams. The CO2 adsorption capacities of coals were investigated by Huy et al.(1). The results showed that CO2 adsorption was double that of CH4.
Practical Considerations in Estimating Test Duration for Perforation Inflow Tests
Authors: Theys S. , Brunner F. , Mattar L. , Rahman N.M.A. 
Published: June 2010

Abstract
Perforation inflow tests are short, cost-effective and environmentally- friendly solutions to estimate the initial reservoir pressure, permeability and skin, immediately after perforating the well. The reservoir-dominated (radial) flow regime must be reached before terminating the test in order to obtain reasonable estimates of these parameters. These reservoir parameters and chamber (or wellbore) volume directly influence the rate of build-up of pressure and the test duration. In the field, it is not easy to ascertain whether or not sufficient data has been obtained so that the test can be terminated, especially when the data is not analyzed in real time. If the rate of build-up is closely monitored, it is possible to predict whether (i) the minimum required data will be obtained within the stipulated test time, (ii) the test has to be run longer, or (iii) a downhole shut-in is required.
In this paper, analytical simulation is used to run a sensitivity study on reservoir and well parameters and see how these affect the onset of the reservoir-dominated flow regime. The impulse derivative is used to identify the presence of reservoir-dominated flow. The rate of pressure build-up at I hour is used to determine if sufficient data will be collected within the test duration.
The outcome is a practical field guide to help the operator decide whether the test should be continued, modified or stopped.

Introduction
Perforation inflow tests are short and therefore increasingly popular in the industry. They can deliver valuable reservoir information, such as the initial reservoir pressure, the reservoir permeability and the skin effect. The data obtained from perforation inflow tests can be divided into two parts:the early-time data is wellbore storage dominated, andthe late-time data is reservoir- dominated.
Perforation inflow tests are not likely to exceed approximately 24 hours, and should be designed so that reservoir-dominated flow occurs during that period. For cases where wellbore storage does not excessively affect the early time data and when reservoir permeability is high enough, the duration of the perforation inflow test is likely sufficient to reach radial flow. However, for large wellbore storage and low reservoir permeability, the time to reach reservoir- dominated flow will be prohibitively long. In such cases, one option is to reduce wellbore storage by running a bridge plug, thus reducing the effects that initially masked the true reservoir performance.
Prediction of Carbon Dioxide Production in SAGD Operations
Authors: Thimm H.F. 
Published: June 2010

Abstract
In 2007, work was published on the predictability of hydrogen sulphide production in Athabasca SAGD projects. It was possible to predict the hydrogen sulphide production per unit volume of bitumen produced against steam zone temperature, by assuming pseudo-zero order kinetics, using the Arrhenius energy published by Strausz and his co-workers at the University of Alberta.
An examination of field results for carbon dioxide production in Athabasca projects shows that the predictability of carbon dioxide is less simple. The carbon dioxide production is not erratic but goes through a distinct temperature minimum, an important result in view of the dependence of silica production in SAGD and scaling behaviour in facilities on carbon dioxide. Again, as for hydrogen sulphide production, it is possible to estimate carbon dioxide production by a simple graphical technique, which is shown.
Partial explanations for the observed temperature minimum are offered.

Introduction
The production of acid gases in SAGD projects is a matter of some importance. A number of operational characteristics depend on the presence of carbon dioxide as produced through dissolution in produced water. It has been shown previously(1) that silica production is strongly dependent on dissolved carbon dioxide. There is likewise evidence that aggressive degassing of produced water has caused unwanted scales of silicate minerals, such as talc, chrysotile and tremolite, to be deposited in various parts of the facilities(2).
A simple production diagram for hydrogen sulphide in SAGD was recently reported by Thimm(3). The hydrogen sulphide produced per unit bitumen could be described as a simple Arrheniustype relationship with steam zone temperature, using an activation energy of 56,220 - 65,920 J/mole (13,450 - 15,770 cal/mole). The assumption of pseudo-zero order kinetics yielded a smooth curve which fitted the field data for most SAGD projects in Athabasca satisfactorily.
The behaviour for carbon dioxide was previously expected to be similar, with an Arrhenius activation energy of 17,520 J/mole (4,192 cal/mole)(4).
Application of Temperature Observation Wells During SAGD Operations in a Medium Deep Bitumen Reservoir
Authors: Wang H.Y. 
Published: June 2010

Abstract
The steam assisted gravity drainage (SAGD) pilot test in the LiaoHe oilfield of China is the first SAGD project conducted in China in the deeper bitumen reservoir (650 - 800 m), using a combination of vertical injectors and horizontal producers. Temperature observation wells play an important role in the understanding of the pilot performance and optimization of the operation process. This paper will present the objectives, principles, interpretation and application of the temperature observation wells in the pilot area. A number of production problems were identified and solutions were sought to improve the SAGD performance through the use of temperature and other data obtained from the observation wells.

Introduction
This paper is a continuation of CIPC paper 2006-146. That paper introduced the successful test of the SAGD pilot in a deep biutmen reservoir in China(1). The pilot has been expanded to include 12 horizontal wells since the presentation of the original paper. The earlier two wells have reached a daily oil rate of over 100 m3/day per well. The current recovery factor is approximately 27% and the anticipated ultimate recovery is over 60%.
Compared with most current Canadian SAGD projects, the reservoirs in the LiaoHe oil field operated by PetroChina presented two challenges to the use of SAGD technologies. First, the reservoir depth exceeded 500 m (530 - 810 m) compared to the typical 200 - 500 m present in most Canadian SAGD projects(2), which increased the heat loss from the injection wellbores to the overburden Second, the reservoir had been subjected to primary production by Cyclic Steam Stimulation (CSS) prior to the implementation of the SAGD process while for the majority of the Canadian SAGD projects the technique is applied directly to a virgin reservoir. The current recovery factor by CSS in the LiaoHe reservoir is approximately 20% of the OOIP. This prior depletion by CSS complicated the conversion to SAGD applications and determination of operating parameters caused by the alteration in the distribution of the remaining oil saturation present in the formation (Figure 1).
Protocols for Slotted Liner Design for Optimum SAGD Operation
Authors: Bennion D.B. , Gupta S. , Gittins S. , Hollies D. 
Published: June 2010

Abstract
Slotted liners are used extensively in the majority of steam assisted gravity drainage (SAGD) operations conducted in Western Canada due to their superior mechanical strength and integrity in contrast to other mechanical sand-control devices. These liners are required because of the generally poorly or unconsolidated nature of the majority of formations in which SAGD applications are conducted. These liners can have a variety of configurations with varying slot density, slotting patterns, slot apertures and slot internal geometries. The overall objective of a successful slotted liner design is to ensure that the liner allows the maximum production of bitumen and other fluids with a minimum pressure drop, while retaining the majority of the formation sand and preventing infill of the horizontal section of the well with solids and erosion and failure of downhole pumps and surface equipment. This paper describes a detailed lab test protocol which was successfully developed over a number years for the design and evaluation of slot geometry for SAGD applications, describes test procedures used and quantifies some of the major mechanisms discovered that lead to the plugging of slots. It has been found that in addition to grain size of the sand under consideration and slot geometry, that clay content of the formation, flow velocity, wetting phase type and pH play crucial roles in the plugging mechanism of slotted liners. Clay plugging at the top portion of the slots has been found to be the dominant damage mechanism.

Introduction
SAGD is being used extensively in Western Canada and other areas in the world as an effective and economic means for the recovery of heavy oil and bitumen reserves and represents the current primary technology for the exploitation of this large hydrocarbon resource(1-5).
Experimental and Economic Analysis of the Thermal Solvent and Hybrid Solvent Processes
Authors: Frauenfeld T.W. , Jossy C. , Bleile J. , Krispin D. , Ivory J. 
Published: June 2010

Abstract
Several partially scaled laboratory model experiments were conducted to evaluate a hybrid solvent-steam process for recovery of heavy oil or bitumen. All experiments used Athabasca UTF bitumen, and modelled a 30-metre-thick formation. The experiments were compared using a common set of economic assumptions. The experiments showed that a hybrid solvent-steam process could recover bitumen at steam-oil ratios much lower than those observed for steam assisted gravity drainage (SAGD), and achieve reasonable ultimate oil recovery (60% IOIP). The economic analysis based on experiments indicated that a hybrid solvent-steam process could be more cost-effective than SAGD for a 30-m Athabasca formation.

Introduction
Some heavy oil reservoirs are difficult to produce by cold production. The oil may be immobile at reservoir temperature, or there may be some initial oil mobility and some reservoir drive energy, but the sand strength precludes the production of wormholes. These reservoirs may contain dead oil, as in the case of Athabasca bitumen, or they may have some dissolved gas, as in the case of Cold Lake or Burnt Lake reservoirs.
SAGD is the main commercial technology used for in-situ recovery of these oils. Because of the increasing costs for energy (natural gas) and the increasing restrictions on fresh water usage, solvent-based processes (VAPEX, Thermal Solvent, Hybrid Solvent, N-Solv, Savex) have been proposed as alternative technologies for heavy oil and bitumen production. Most of these technologies utilize a pair of horizontal wells, similar to those used in SAGD, but use a gaseous solvent, typically propane, alone or in conjunction with steam, to recover the oil.
The VAPEX process may be augmented by adding heat. Heating of a horizontal wellbore will reduce bitumen viscosity sufficiently to produce a large increase in oil production rate. The heat also serves to initiate communication between the injector and the producer. The heat also serves to speed the diffusion of solvent into the oil. The combination of heated wellbores and VAPEX is known as the thermal solvent process.
Simultaneous Estimation of Relative Permeability and Porosity/Permeability Fields by History Matching Production Data
Authors: Eydinov D. , Gao G. , Li G. , Reynolds A.C. 
Published: June 2010

Abstract
This paper presents a procedure to estimate relative permeability curves together with gridblock porosities and permeabilities by automatic history matching three-phase flow production data using the LBFGS algorithm for optimization and the adjoint method for generating sensitivity coefficients. Both power law and B-splines are considered for the representation of relative permeability curves. Power law functions provide a simple representation; however, B-splines have the advantage of being able to accurately represent any set of relative permeability curves. In the B-spline representation, we provide a simple procedure based on a transformation of parameters (control points) defining the B-splines to ensure that monotonic curves are obtained. Without this transformation, the automatic history-matching process fails. If endpoint saturations are included as parameters, we show how to modify the adjoint procedure to account for the fact that initial conditions are sensitive to endpoint saturations. While the history-matching process is inherently non-unique, we show that reasonable estimates of relative permeability curves and porosity/ permeability fields can be obtained for a synthetic reservoir example. We also provide a quantification of the uncertainty in model parameters and reservoir performance prediction using the randomized maximum likelihood (RML) method.

Introduction
Usually, the relative permeability curves are obtained from labs through coreflood tests. However, they can also be incorporated into the history matching procedure as model parameters. Archer and Wong(1) and Yang and Watson(2) were among the early researchers to consider the estimation of relative permeability curves by history matching laboratory coreflood data. A detailed literature review is given in Reynolds et al.(3). Reynolds et al.(3) also discussed the estimation of three-phase relative permeabilities by history matching production data.
The current work is a natural extension of Reynolds et al.(3). In this paper, we provide an alternative method for relative permeability estimation based on B-spline approximation. Compared to power law representation, B-splines have the advantage of being able to accurately represent any set of relative permeability curves.
Nine-Lumped Kinetic Models ofLiquefied Petroleum Gas Under Aromatization Reaction Conditions
Authors: You H. 
Published: June 2010

Abstract
The aromatization reaction of liquefied petroleum gas has been studied by using three liquefied petroleum gases as the raw material and LBO-A as the catalyst. Nine-lump kinetics model networks have been put forward on the basis of lumped theory and the aromatization reaction mechanism. In the network, the aromatization reaction species are firstly lumped into C4=, C40, n-paraffin, i-paraffin, olefins, aromatics, C2-3=, H2 + C1-30, and coke. A mathematical method is first introduced to study the product distribution of the liquefied petroleum gas aromatization reaction. The results from experimental data are in accordance with the quantitative analytical conclusions drawn from the calculated data.

Introduction
In 1994, 1.27 hundred million tons of petroleum were processed, more than 2.2 million tons of ethylene were produced, and the resources of liquefied petroleum gas (C4 fraction and C5 fraction) reached approximately 3.7 million tons in China(1,2). The resources of liquefied petroleum gas have become more and more abundant in China; the output of liquefied petroleum gas is more than 300 thousand tons per year(3,4). The resources of liquefied petroleum gas are mainly from three resources in China: oil and gas fields, refineries and from gas cracking(5).
The resources of liquefied petroleum gas are not completely used to create higher value products, whereas most resources are burned as fuel(6). Recently, research work has focused mainly on how to use liquefied petroleum gas effectively(7,8). The various quantitatively analytical methods have been studied, but the lumped-kinetics models are seldom done.
In this paper, nine-lumped kinetics models, which can predict aromatization reaction product distribution under various operating conditions and calculate the maximum deviations of the product yield between calculated results and practical values, are established for a confined fluidized bed reactor.
Drill-String Torsional Vibration Suppression Using GA Optimized Controllers
Authors: Karkoub M. , Abdel-Magid Y.L. , Balachandran B. 
Published: June 2010

Abstract
Failure of drill-strings is very costly in terms of money and time and occurs more frequently than oil companies would like to see. There are many reasons for drill-string failure, such as vibration, fatigue, and buckling. This paper addresses the problem of suppression of stick-slip oscillations in oil well drill-strings using proportional integral derivative (PID) and lead-lag controllers in conjunction with genetic algorithms. Simulation results are presented to validate the proposed control schemes.

Introduction
The drilling process is affected by the dynamically induced vibrations caused by design imperfections as well as material elasticity. Because of these vibrations, premature wear and damage of drilling equipment may occur. Vibrations can decrease the rate of penetration (ROP), and thereby increase the cost of the well(1,2,3). Moreover, vibrations can interfere with measurement-while-drilling (MWD) tools or even cause their damage. Another major problem caused by vibrations is the induced wellbore instabilities which can worsen the condition of the well(4,5).
The literature on drill-strings can be classified in three groups: drill-string modelling, drill-string control, and drill-string technology. In this paper, we will focus on drill-string dynamics and control. There have been a significant number of research publications on drill-string dynamics and a representative few are considered here. Many different models for drill-strings are available in the literature, which may include one or more of the following phenomena: bit-bounce, stick-slip, forward and backward whirl, axial, lateral, and torsional vibrations; see, for example, Christoforou et al.(6), Jansen and van den Steen(7,8), and Leine et al.(9). Stick-slip is a major cause of torsional vibrations and many researchers have tried to minimize its effect on the behaviour of the drill-strings using active damping techniques(10,11,12). These techniques reduce the torque fluctuations and torsional drill-string vibrations affecting in this manner the stick-slip conditions. The underlying concept is to reduce the amplitude of the downhole rotational vibrations using torque feedback. The feedback is used by the rotational drive, which slows down the rotary rate when the torque increases and speeds it up when the torque decreases(8,13,14).