bluuebunny/crossref_metadata_2025_split huggingface dataset:
Comparison of Correlations for Viscosity of Sour Natural Gas
Authors: Jeje O. , Mattar L. 
Published: March 2010

Abstract
There are two commonly used correlations for determining the viscosity of natural gases. These are the Carr, Kobayashi, and Burrows (CKB) and the Lee, Gonzalez, and Eakin (LGE). The CKB applies to both sweet and sour gas, but the LGE was derived purely for sweet gas. The CKB is a graphical correlation, and consists of two sets of graphs with temperature as the correlating parameter (not easily adaptable for computer applications). On the other hand, the LGE is a set of simple equations, and therefore can be easily programmed for a computer. The LGE is used in numerous computer programs, with no regard to the fact that it was not derived for sour gas.
This study compares the LGE to the CKB graphs for both sweet and sour gases. A detailed comparison of the two methods using various gas mixture compositions, temperatures, and pressures was conducted. The results illustrate that for sweet gases, the comparison is acceptable, and the LGE equation can be used for most reservoir engineering purposes. However, for sour gases, the differences between the LGE and CKB correlations can be significant. This leads to the conclusion that the LGE correlation, which was derived for sweet gases only, should not be indiscriminately applied to sour gases.

Introduction
Gas viscosity is used in several calculations dealing with fluid flow and reservoir behaviour. Empirical correlations have been developed to estimate values for viscosity over a range of pressures. Most viscosity correlations are either equation based or in a graphical form derived from laboratory measurements. Typically the correlations are functions of temperature, pressure, gas gravity, and composition. Often they are paired with various corrections for non-hydrocarbon components. Applying a correlation without corrections to a sour gas case can lead to large errors in predicting viscosity.

Carr, Kobayashi, and Burrows Correlation
The Carr et al. correlation (henceforth referred to as CKB) was developed to predict the viscosity of gas hydrocarbon mixtures over a large pressure and temperature range. The limits of the correlation are temperatures between 32 and 400 °F and reduced pressures up to 20 (which can equate to pressures higher than 12,000 psia). It was designed to handle non-hydrocarbon components CO2, N2, H2 S) in concentrations of up to 15% each.
Calculation of viscosity with the CKB method is a three-step process based on graphical methods. The first step is to determine the viscosity at atmospheric pressure based on the gas gravity and temperature using Figure 1.
Next, corrections are added to the viscosity based on the H2S, CO2, and/or N2 content of the gas. Finally, the viscosity is multiplied by a ratio based on the reduced pressure from Figure 2.
The only disadvantage of the CKB method is that it is based on several charts, making it difficult to program into a computer. Two methods that have been used to simplify computation have been to generate a series of polynomial curve-fits or to use a table lookupinterpolation scheme(1)
Experimental Study of a Novel In Situ Gasification Technique for Improved Oil Recovery From Light Oil Reservoirs
Authors: Greaves M. , Xia T.X. , Rathbone R.R. , Bentaher A.H. 
Published: March 2010

Abstract
In situ gasification of crude oil using downhole gasification (DHG) is a new, improved oil recovery technique for application in light oil reservoirs. Inert gas is generated inside a DHG unit by gasifying part of the produced oil. A string of DHG units is positioned along a horizontal producer well, or on a vertical well. The gases, mainly hydrogen and CO2, are then directed into a gas cap formation. Incremental oil recovery is achieved via gravity stabilized gas injection (GSGI) or another suitable gas displacement drive method. There is essentially no net heat release into the reservoir if efficient heat recovery is practiced.
A series of high pressure, continuous flow experiments was performed in a small-scale gasifier unit, using n-pentane as feedstock, to represent the light naphtha fraction from a crude oil. The experiments were operated at pressures up to 100 bar, compared to the 20 to 30 bar normally used in a surface steam reforming plant. Catalytic steam reforming of the pseudo-light naphtha fraction, containing reservoir gas, achieved conversions of 70 to 80% at a gasifier exit temperature of 720 °C. The produced gas contained up to 50% hydrogen, with the remainder comprising carbon oxides.
The new IOR technique has wide potential application in depleted light oil reservoirs where the pressure is less than about 200 bar, although it may be possible to increase this limit. The economics of the DHG process appear to be attractive, if energy is recovered from the hot gas stream. The produced gases are stored-up in the reservoir and any emissions are therefore limited to those which are released from the crude oil when it is produced. If the reservoir pressure is low, then the amount of gas produced with the oil will be relatively small. The hydrogen product storedup in the reservoir is a valuable resource, which could be recovered later for use in the future "hydrogen economy."

Introduction
Previous attempts to increase oil recovery from (mainly) heavy oil reservoirs by introducing a source of heat have focused on heating up part of the reservoir. Thus, Niles(1) proposed using an electrical heater to heat part of the oil formation so that the oil was partially vapourized in order to increase the reservoir pressure. It was also claimed that the oil viscosity was reduced, thereby increasing the flow of the oil. This was probably only a marginal effect because there is no permanent overall reduction in the crude oil viscosity. Nielsen(2) proposed a method of heating shale oil layers by pumping hot gases into the reservoir matrix to pyrolyse the oil or kerogen material. The vapourized fractions were then collected at the surface.
The new underground gasification, or DHG technique, first proposed by Davidson and Yule(3), differs from all other previous attempts in one major respect. Heat is provided electrically inside a DHG unit so that there is no direct contact with the reservoir matrix.
Rate Dependence of Transient Linear Flow in Tight Gas Wells
Authors: Ibrahim M. , Wattenbarger R.A. 
Published: March 2010

Abstract
Many tight gas wells (permeability less than 0.1 mD) exhibit transient linear flow; sometimes for several years. This behaviour differs from radial flow in many ways. This paper reports another import difference between linear flow and radial flow? rate sensitivity.
It has been shown and accepted for years that real gas pseudopressure can be used to apply analytical solutions to transient radial flow. However, it has been noticed that analytical solutions can be in serious error when applied to transient linear flow. Specifically, the slope of the √t plot departs from the analytical value as the flow rates or degree of drawdown becomes higher.
This paper demonstrates the rate/drawdown sensitivity of transient linear flow. Then a correction factor is presented which corrects the slope of the plot and improves the accuracy of √k Ac and OGIP, as calculated from production/pressure performance.

Introduction
Many wells in tight gas reservoirs have long-term performance which exhibit only linear flow, not radial flow, during the transient period. Wells have been observed which stay in the transient linear flow regime for several years. Some of these wells have hydraulic fractures and some do not. It is usually not practical to analyze tight gas wells with build-up tests, but long-term production and pressure data can be used for analysis. Previous papers have presented methods of analysis(1–5).
The analysis of these wells comes from plotting [m(pi) - m(pwf)]/ Qg vs. √t and observing the slope, mCPL, and the end of the straight line, tesr (end of the transient linear flow period). From these values, √k Ac and OGIP can be calculated.
It has long been accepted that radial flow transient solutions can be approximated by analytical solutions, in terms of m(p), regardless of flow rate. Constant rate solutions have been emphasized, but it can also be shown that constant pwf flow can also be approximated by analytical solutions, regardless of the level of drawdown(5).
The drawdown/rate dependency linear flow is different than analysis of radial flow. This difference was demonstrated with reservoir simulation in this work. A correction method was developed to improve the accuracy of analysis of transient linear flow for analyzing tight gas wells.
Effect of Drawdown on Transient Linear Flow (Constant pwf)
A number of transient linear flow cases were run with constant Pwf. It was found that these cases did not have the same slopes as the analytical solution, but varied according to the level of drawdown. In order to demonstrate this effect, a dimensionless drawdown parameter is defined as follows:
Equation (Available In Full Paper)
Some results are plotted in Figure 1. It can be seen that the slope of these plots is greatly affected by the level of drawdown, DD. As the drawdown value increases, the slope (mCPL) value decreases. Since the analysis equations(5) are based on analytical solutions, the calculations may be wrong when actual data is analyzed.
Optimization of Solvent Aided Process
Authors: Gupta S. , Gittins S. 
Published: March 2010

Abstract
The Solvent Aided Process (SAP), described previously by the authors, is an improvement to SAGD that promises to enhance the economics of bitumen/heavy oil recovery projects and reduce water usage.
In SAP, a small amount of hydrocarbon solvent (such as a low molecular weight alkane) is introduced as an additive to the injected steam during SAGD. The viscosity of the oil is reduced due to solvent dilution in addition to heating. SAP holds the promise of significantly improving the energy efficiency of SAGD, thus, reducing the heat requirement. Encana's field trials of SAP, discussed elsewhere, have shown the practical upside of this process. This paper discusses two conceptual optimizations of SAP.
SAP reduces the effective steam-oil ratio (SOR) of SAGD. However, this comes at a cost as a part of the injected solvent is retained in the reservoir and lost in terms of economics. The smaller this cost is, the better are the economics of SAP. In this paper, the merits and drawbacks of using two alternate substances, SO2 and olefinated light alkanes, as solvents are discussed.
Bottom-up SAP is a special geometrical configuration of SAP, discussed before. In this variant of the SAP process, bitumen recovery progresses from the bottom to the top of the reservoir, and employs injector and producer wells that are spaced horizontally apart rather than being in the same vertical plane. For large horizontal spacing between the injector and producer in a well pair, rates are low. On the other hand, for small spacing, the capital associated with the project is high. This paper explores the optimal horizontal spacing between the wells in a bottom-up SAP well pair.

Introduction
Steam-Assisted Gravity Drainage (SAGD) relies primarily on heat supplied to the reservoir by steam to reduce the viscosity of the oil(1). In SAP(2–5), solvent dilution is also taken advantage of to aid in this viscosity reduction. The result is an enhanced rate of oil production and recovery leading to superior economics with lower energy intensity and a reduction in water usage. To further improve the economics and energy efficiency of the process, in this paper, two optimizations of SAP are discussed; namely, employment of inexpensive solvents and optimal configuration of bottom-up SAP.
SAP economics depend on the extent of the residual solvent in the reservoir(3) such that, the higher the inventory and cost of the unrecovered solvent, the less advantageous it is to carry out SAP. In principle, any of the commercially-available light alkanes (e.g. propane, butane or natural gas condensate) can be employed for SAP. However, these liquids tend to be expensive due to their multiple uses in the industry and their price generally varies in sync with light sweet crude. This fact naturally offers an opportunity to further improve the economics of SAP by looking for other solvents, and the discussion below describes two such alternative, inexpensive solvents.
Advances in Magnetic Resonance Relaxometry for Heavy Oil and Bitumen Characterization
Authors: Kantzas A. 
Published: March 2010

Abstract
This paper offers a summary of the advances in heavy oil and bitumen reservoir characterization and fluid stream monitoring using low field magnetic resonance tools. Both laboratory and field advances are presented. Although the bulk of the work discussed was performed in our laboratory, a selection of other pertinent technologies is also presented. This overview aims at offering the reader a quick reference of what has been achieved in the past ten years and it is hoped that it will be used as a guide for future development in this area.

Introduction
Low field nuclear magnetic resonance (NMR) relaxometry is a technology that offers significant benefits in reservoir characterization through the magnetic resonance logging tools that are offered by oil and gas service companies(1). These tools can offer measurements of porosity, permeability, mobile and bound fluids and, potentially saturations, if they are properly calibrated. This technology has been active in its latest reincarnation since the middle of the 1980s. It was originally developed with conventional oil and gas reservoirs in Texas and the North Sea. There are currently several excellent reviews and two recommended books for those interested in studying the topic in detail(1–4).
Through low field NMR we measure the amount of and the mobility of hydrogen-bearing molecules. For reservoir characterization applications, such molecules translate into gas, water or oil present within a formation. Although the physics of the process are not the focus of this overview, a brief introductory summary is included. For details, the reader is directed to the references above.
The measured parameters in NMR are amplitudes of hydrogenbearing signal and relaxation times of hydrogen-bearing molecules. The amplitude is directly proportional to the amount of protons present and it can be correlated to the volume or mass of fluids within the region of measurement. The relaxation time is affected by the relative mobility of the hydrogen-bearing molecules. Thus, as visocsity increases, or the surroundings of the relaxing hydrogen are restricted, then relaxation occurs faster. There are two relaxation times that can be measured: longitudinal (T1) and transverse (T2). The focus of our work deals with transverse relaxation phenomena.
Figure 1 is used as the typical figure to explain different types of relaxation spectra obtained when exposing different systems in the standard pulse sequence that is used in logging and laboratory tools alike. The spectrum of bulk water (i.e. water in a beaker) is a simple narrow peak that shows relaxation at T2 of ~2,500 ms. Compared to water, bulk bitumen (viscosity of ~1,000,000 mPas at room temperature) typically relaxes with a broader peak at less than 2 ms. Thus, in principle, a beaker that is half-full of water and half-full of bitumen would show two peaks, as shown in Figure 2.
Figure 1,2,3,4 (available in full paper)
In this case, the oil is somewhat lighter than that of Figure 1 (viscosity of ~100,000 mPas at room temperature).
Conformance Control of CSS and Steam Drive Process With a Carbamide Surfactant
Authors: Zhang X. , Zhang Y. , Yue Q. , Gao Y. , Shen D. 
Published: March 2010

Abstract
Based on physical modelling, this paper discusses the feasibility of injecting additives to control the conformance of the cyclic steam stimulation (CSS) and steam drive processes in the Biquan 10 Block of the Henan Oil Field. The lab test results show that waterflooding with the addition of a carbamide surfactant can decrease residual oil saturation by 4.7% and that steam drive with the addition of this same surfactant can improve the sweep volume and increase the oil recovery factor by 17.5%. Also, field application results confirmed that injecting this surfactant in the CSS and steam drive processes can increase oil production, lower steam-oil ratio (SOR) and improve the economic benefitssignificantly.

Introduction
The CSS process has been applied in developing the heavy oil reservoirs in the Henan Oil Field since the late 1980s. It has been clearly demonstrated that with increasing the cycles of steam stimulation, the oil production rate decreases and SOR can rapidly reach the economic limit. For improving the oil production rate and recovery factor, the steam drive process needs to be applied as a subsequent technology. However, the reservoir in the Henan Oil Field is thin and interbedded so it is a challenge to operate the conventional steam drive process. To reduce the steam channeling effect, a number of high temperature resistant plugging surfactants have been tested, but they could not achieve ideal and persistent results(1). This paper discusses the development of a new kind of conformance control agent ? carbamide surfactant. The lab testing results and field applications of the steam drive process with the addition of a carbamide surfactant in Well Group 577, Biqian 10 Block, Henan Oil Field, are described in detail below.

Mechanism and Physical Modelling
When the carbamide surfactant is injected into the reservoir with steam, carbamide decomposes into CO2 and NH3 under high temperatures. The decomposition can be expressed as follows:
Equation (available in full paper)
The physical modelling shows that, with increasing temperature and pressure, the carbamide decomposes even faster but its concentration does not affect the decomposition speed. The produced CO2 dissolves in heavy oil and NH3 can react with some acid in the oil. As a result, the heavy oil volume expands and viscosity decreases. At 50 °C, when the oil-carbamide solution (30 wt% carbamide) ratio is 4 to 1, the oil viscosity can be reduced by 73% to 80%. The single tube displacement efficiency test shows that adding carbamide solution (30 wt% carbamide) into hot water will increase the displacing efficiency by 6.5%.

Field Application and Discussion
Reservoir Geology and Production History
Well pattern 577 in the east of Biqian 10 block was selected for the field test. The well pattern is an inverted 9-spot with injector-producer spacing of 70 m and 100 m. The pay zone is the IV-9 layer of the H-3 interval in the Hetaoyuan Formation. The basic reservoir parameters are as follows:
Considerations in Bank Financing of Producing Oil Properties
Authors: Humphries R.G. 
Published: March 2010

Abstract
The chartered banks in Canada play an important part in the oil and gasindustry by providing a large source of funds through oil and gas productionloans, and these loans permit a number of advantages to producers in borrowingagainst production.
Production loans are self-liquidating in that repayment of the loan isobtained from the proceeds of the sale of production from the same propertythat provides security for the loan.
The development of engineering reservoir techniques and the practice ofproration has permitted forecasts of production and income under relativelystable marketing conditions which provide a sound basis for the loan.
Three principal elements considered in a production loan are:
1. The factors which determine whether the borrower can be described as a"good borrower."
2. The engineering report and economic and loan evaluation of theproperties.
3. The legal documentation and registration of security.
A number of criteria are used by the banks in determining the amount of aloan which can be advanced against a given property. These criteria relate tothe projected net income, reserves, and fair market value of the property.
When all of the requirements have been satisfied and the amount of the loanagreed upon, security is taken by a very simple document which is provided forby Section 82 of the Bank Act.
Oil payment loans are widely used in the United States for oil propertyfinancing. Canadian tax laws differ from those in the United States and thesedifferences, particularly the absence of a provision for cost depletion, haveprevented the application of oil payment transactions in Canada.
Although the chartered banks in Canada provide loans to all phases of theoil and gas industry, from exploration through marketing and distribution, thepurpose of this paper is to discuss only those loans which are made to theproducing segment of the industry against the security of oil and gas in theground and retired from the sale of production of the same oil and gas -the socalled production loans. It is intended to describe the criteria generally usedby the bank to determine the amount which it can safely lend against thesecurity of an oil or gas property, in order to provide a guide for theevaluation engineer. He should be able to make a reasonable estimate of theamount which can be borrowed so that he can advise his management properly ofthe economic and engineering feasibility of any project. This is especiallyimportant where a decision between alternative investments must be made and allof the economic factors must be considered.