bluuebunny/crossref_metadata_2025_split huggingface dataset:
Laboratory Measurements of Gas-Water Interfacial Tension at HP/HT Reservoir Conditions
Authors: Rushing J. A. , Newsham K. E. , Van Fraassen K. C. , Mehta S. A. , Moore G. R. 
Published: June 2008

Abstract
This paper presents preliminary results from a laboratory study designed to measure gas-water interfacial tension (IFT) at high-pressure/high-temperature (HP/HT) reservoir conditions. We used a pendant drop method with computer-aided image processing and analysis to measure gas-water IFT for several dry gas mixtures at pressures from 1,000 psia to 20,000 psia and temperatures of 300°F and 400°F. For our study, we define a dry gas as one that remains in the single hydrocarbon (gas) phase during the entire isothermal pressure depletion path from the reservoir through surface conditions. We also evaluated the effects of two common nonhydrocarbon contaminants (i.e., carbon dioxide and nitrogen) on the gas-water IFT behavior. Gas mixtures contained up to 20 mol% of either CO2 or N2 each. Finally, we evaluated the effects of total dissolved solids content in the connate water. All IFT measurements were made with either distilled water or synthetic brine with total dissolved solids concentrations of 100,000 ppm NaCl.
Study results demonstrate the complex interactions between pressure and temperature as well as gas and water compositions on gas-water IFT. Specifically, we observed the following behavior in the measured IFT:
temperature has a significant impact on gas-water IFT. Increasing the temperature from 300°F to 400°F tended to decrease the IFT for all pressures and gas compositions; the effects of CO2 varied depending on pressure, temperature, and concentration. For a given temperature, the presence of CO2 in the gas decreased the IFT at higher pressures; however, the pressure at which this trend was observed varied. Generally, higher concentrations of CO2 resulted in lower IFTs over a much greater pressure range than for the gases with lower CO2 concentrations; the effects of N2 also varied depending on pressure, temperature, and concentration. For lower N2 concentrations, we observed higher IFTs over the entire pressure range than for the gas with no N2. However, the gases with higher N2 concentrations had higher IFTs for the low pressure range only; the presence of total dissolved solids in the water caused the gas-water IFT to be higher than the values measured with distilled water. Higher concentrations of NaCl dissolved in the water caused greater increases in IFT for all pressures, temperatures and gas compositions evaluated in the study.
The Catalytic Effects of Nonhydrocarbon Contaminants on Equilibrium Water Vapor Content for a Dry Gas at HP/HT Reservoir Conditions
Authors: Rushing J. A. , Newsham K. E. , Van Fraassen K. C. , Mehta S. A. , Moore G. R. 
Published: June 2008

Abstract
This paper presents new laboratory data quantifying the catalytic effects of two common nonhydrocarbon contaminants (i.e., CO2 and N2) on the liquid water vaporization process as well as the water vapor content for natural gases at high-pressure, high-temperature (HP/HT) reservoir conditions. We conducted laboratory studies to measure the isothermal, equilibrium water vapor content for seven dry gas mixtures at pressures from 500 to 20,000 psia and temperatures of 300°F and 400°F. Gas mixtures evaluated in our study contained up to 20 mol% of either CO2 or N2 each. Principle results of our laboratory study demonstrate the following phase behavior:
temperature has a significant impact on the water vaporization process and the quantity of water vapor dissolved in a natural gas with no nonhydrocarbon contaminants. Increasing the temperature from 300°F to 400°F increases the equilibrium water vapor content by more than 70% above that for the gas at 300°F; the presence of CO2 in the gas phase also enhances the solubility of water vapor in a natural gas. Increasing the CO2 content from 5 mol% to 20 mol% increases the maximum water vapor content by 20% to 40%, respectively, above that measured for the same gas with no CO2 These increases were observed at both 300°F and 400°F; the presence of CO2 in the gas phase combined with higher temperatures further augments water vapor solubility in a natural gas. For example, the equilibrium water vapor content for the gas with 20 mol% CO2 at 400°F increased by 80% above that measured for the same gas at 300°F; the presence of N2 in the gas phase suppresses the water vaporization process and reduces the quantity of water vapor dissolved in the gas. At 300°F, 5 mol% N2 reduces the water vapor content from 10% to 20% of that for the same gas with no N2. Further increases in N2 content reduce the water vapor content below that for the same gas with no N2; the enhanced water vapor solubility at higher temperatures counters the suppressive effects of N2 in the gas phase. Increasing the N2 content at 400°F increases the maximum water vapor content from 5% (20 mol% N2) to 10% (5 mol% N2) above that measured for the same gas with no N2.
Natural Gas z-factors at HP/HT Reservoir Conditions: Comparing Laboratory Measurements with Industry-Standard Correlations for a Dry Gas
Authors: Rushing J. A. , Newsham K. E. , Van Fraassen K. C. , Mehta S. A. , Moore G. R. 
Published: June 2008

Abstract
This paper presents preliminary laboratory measurements of the natural gas compressibility or z-factor at high-pressure, high-temperature (HP/HT) reservoir conditions. We conducted laboratory studies to measure gas density and z-factor for several dry gas mixtures at pressures up to 20,000 psia and temperatures of 300°F and 400°F. For our study, we define a dry gas as one that remains in the single hydrocarbon (gas) phase during the entire isothermal pressure depletion path from the reservoir through surface conditions. We also measured the effects of CO2 in the gas phase on gas density and z-factor at HP/HT conditions. Several gas mixtures contained CO2 concentrations up to 20 mol% each.
We then compared the new laboratory data with two equation-of-state (EOS) models used by the petroleum industry to compute z-factor. In combination with our evaluation of the EOS models, we also assessed several mixing rules and empirical correlations for estimating pseudocritical properties of gas mixtures. Results of our comparisons indicate the following:
For gases with no CO2, the Hall & Yarborough EOS [1973] combined with the Sutton [2005, 2007] pseudocritical property correlations were the most accurate, especially in the higher pressure range and for both temperatures evaluated. The Dranchuk & Abou-Kassem EOS [1975] was the least accurate regardless of the mixing rule or empirical correlation used to estimate pseudocritical properties; Although the Hall & Yarborough EOS combined with the Sutton pseudocritical property correlations were the most accurate for gases with no CO2 at 400°F, the errors were still more than 300% higher than those for the same gas mixtures at 300°F. These differences suggest neither EOS has been properly "tuned" to data at higher temperatures and validates our concerns about extending the Standing-Katz correlations numerically to higher pressures and temperatures; When combined with the Hall & Yarborough EOS, both the Kay [1936] and the Stewart-Burkhardt-Voo [1956] mixing rules were surprisingly quite often the second most accurate models for estimating z-factors at HP/HT conditions; and For gas mixtures with CO2, the Hall & Yarborough EOS was again the most accurate when combined with the Wichert & Aziz [1971] correlations for CO2 and the Sutton pseudocritical property correlations. Conversely, the Dranchuk & Abou-Kassem EOS was the least accurate for all mixing rules or empirical correlations.
Behavior of the Mercury Removal Absorbents at Egyptian Gas Plant
Authors: Abu El Ela M. , Nabawi M. H. , Azim M. Abdel 
Published: June 2008

Abstract
Khalda Petroleum Company has mercury removal unit at its Salam gas processing plant in Egypt's Western Desert, which are intended to protect the downstream aluminum heat exchangers from mercury corrosion.
Last year, the mercury removal adsorbent was exposed to liquid entrainment due to liquid condensation upstream the mercury removal unit. The liquid entrainment caused (1) physical damage to the absorbent pellets which became one solid, cement-like block inside the vessel, and (2) higher levels of mercury in the treated gas. Therefore, the absorbent had to be offloaded and replaced to improve the unit performance.
This article will present the reasons of the liquid condensation upstream the mercury unit and show how (1) the problem was solved, (2) the absorbents were replaced, and (3) the liquid condensation was avoided.
Rate Transient Analysis in Naturally Fractured Shale Gas Reservoirs
Authors: Bello Rasheed O. , Wattenbarger Robert A. 
Published: June 2008

AbstractShale gas reservoirs have been observed to exhibit a half slope on a log-log plot of rate against time. This indicates transient linear behavior and is believed to be caused by drainage from matrix surfaces into the adjoining fractures.A standard test case for the slab matrix transient dual porosity model is presented in this paper. It is shown in this paper that various shape factor formulations can be used in the transient dual porosity model provided that corresponding appropriate changes are made in the solution parameters and the interporosity flow parameter. It is also shown in this paper that different matrix geometry exhibit the same transient linear response when the area-volume ratios are similar.This paper also presents a procedure incorporating a rectangular geometry dual porosity model to analyze the transient linear flow regime obtained in naturally fractured shale gas reservoirs. This procedure allows the use of different matrix geometries.
Successful Multistage Horizontal Well Fracturing in the Deep Gas Reservoirs of Saudi Arabia: Field Testing of a Promising Innovative New Completion Technology
Authors: Solares J. R. , Franco C. A. , Al-Marri H. M. , Al-Jubran H. A. , Ramanathan Venkateshwaran , Kelkar Shri , Johnston Bryan 
Published: June 2008

Abstract
One of the key strategies in Saudi Aramco's optimum gas development project is drilling single and multilateral wells to achieve maximum reservoir contact to maximize well productivity. This strategy has proven very successful over the past few years as the majority of the horizontal gas producers have yielded excellent results, with open-hole completions in particular. Consequently, most of the planned future wells will be drilled as open-hole horizontal completions.
Nonetheless, due to the highly complex nature of the Khuff carbonate reservoir some wells have experienced complications during the drilling phase and encountered unexpected reservoir challenges which has kept them from achieving their production targets. These wells require stimulation to regain their productivity, but the available choices to achieve effective stimulation in horizontal open hole completions have traditionally been limited at best. Previous stimulation attempts with coiled tubing have yielded modest improvements mainly due to difficulty in accessing the long, deep and high pressure/temperature zones requiring treatment. Bullhead treatments at high injection rates have also yielded similar modest well productivity enhancements, because of the inability to achieve effective diversion. Consequently, Saudi Aramco field tested an innovative new completion technology that provided the ability to selectively fracture stimulate multiple zones along the horizontal section. Field trials have yielded excellent and highly promising results, which compared favorably with the performance of non-stimulated offset wells.
It is well-known in the industry that fracture stimulating horizontal open-hole completions with conventional methods is a challenging endeavor, and that often times results are disappointing. Nevertheless, the completion technology tested by Saudi Aramco proved capable of overcoming most of the challenges associated with horizontal fracturing, and effective stimulation of the long horizontal section was achieved. Through this technology multiple mechanical isolation points are created in the wellbore using specially designed multiple open-hole packers, and then selected zones of varying lengths can be individually treated in accordance with reservoir characteristics and production targets.
This paper details the planning and design processes leading to the implementation of the first field trial, experience and lessons learned during deployment of the completion and implementation of the stimulation treatment, and the post stimulation results. Suggested optimization steps from this successful experience are discussed as a way to further enhance the benefits from the technology in future applications.
Advanced Drilling Simulation Proves Managed-Pressure Drilling (MPD) Economical in Gasfield Developments in Western Canada
Authors: Hareland Geir , Olea Uribe Ivan Vinicio , Shirkavand Farid , Teichrob Robert Raymond , kustamsi Andang 
Published: June 2008

Abstract
The application of managed pressure drilling (MPD) is becoming more widely spread throughout the world. It is well known that MPD has less hydrostatic head during drilling therefore the rate of penetration (ROP) is increased. This is due to the reduced rock confinement and chip hold down effects. By simulating the conventional drilling and MPD of a well in advance the benefits of MPD can be quantified in terms of increase in ROP and therefore the economical benefits. Applying a commercially available drilling simulator (1)meter by meter drilling performance is analyzed, first simulating and optimizing a conventional drilling operation and then performing the same procedure for a MPD operation in Western Canada. The additional costs of the MPD operation are integrated into the economical analysis. The analysis shows that the ROP during MPD in the higher mud weight regime of the well is improved from 60 to 80 percent. In addition to the faster drilling during MPD the drill bits last longer due to the lesser hardness of the rock being less confined and therefore also reducing the amount of bit wear and the number of bits required and tripping time. Overall the results indicate that the MPD operation reduce the drilling cost of gas wells in Central Alberta more then 20 percent and due to the reduced time at the location less environmental impact is seen.

Introduction
The first objective of this exercise was to develop a "base case" drilling simulation from which subsequent optimization simulations could be run. An apparent rock strength log (ARSL) was developed based on actual drilling data and formed the backbone of all subsequent calculations. The second objective of the exercise was to compare the non-optimized base case (as above) with an optimized base case. Based on previous experience, drilling economics should improve by approximately 25%. The third and primary objective of this exercise was to compare the optimized base case with an optimized Managed Pressure drilling (MPD) case and, if possible, to justify the additional cost of implementing MPD technology.
Increased Drilling Efficiency of Gas-Storage Wells Proven Using Drilling Simulator
Authors: Hareland G. , Motahhari H. R. , Hayes J. P. , Qureshi A. 
Published: June 2008

Abstract
Gas storage wells are being drilled in Nova Scotia, Canada for natural gas storage in underground rock and salt caverns. A study was performed to evaluate the efficiency of the drilling of these wells. Utilizing a drilling simulator where drilling operational or log data is required to generate a drillability log or apparent rock strength log (ARSL) offset gas storage wells in the area were analyzed. The sonic log data from the offset wells were utilized to calculate the ARSL and the formation information was obtained from strip logs. The actual drilling of the next gas storage well was then simulated and optimized using the commercially available drilling simulator. The optimization process proved that the potential for reducing drilling cost is more the 30 percent. This is a typical cost reduction that can be obtained utilizing drilling simulation on conventional wells in other areas of Canada were only a few offset wells have been drilled. The analysis proves that even with unconventional drilling like for gas storage well with larger hole sizes and the utilization of hole openers the cost reduction potential is the same as with conventional drilling. This paper presents the field data utilized and the results from the simulation study including the economical analysis.
Filtering Elevation Profile Data To Improve Performance of Multiphase Pipeline Simulations
Authors: Jackson Donald F. B. 
Published: June 2008

Abstract
This paper outlines a technique for filtering elevation profile data for multiphase pipeline calculations. When gas and liquids flow together in a pipeline, slip between the phases results in the accumulation of liquid in uphill sections of the pipeline. This liquid holdup causes the pressure losses due to hydrostatic head in the uphill sections of the line to be greater than the pressure recovery in downhill sections of the line. Consequently, it is necessary to use detailed elevation profiles when using software to simulate flow in a multiphase pipeline. Extremely detailed elevation profiles (e.g. the result of electronic processing of aerial photography) are becoming more commonly available, but can result in pipeline models with long calculation times, large memory usage, and large output files. This paper presents a filtering technique that removes redundant points, reducing the computing requirements of a model without significant impact on the integrity of the results.
The procedure outlined in this paper was evaluated using measured data from existing pipeline systems. In one such system, the number of points in the elevation profile was reduced by 83% with a corresponding 91% reduction in the time taken to perform the calculations and less than a 0.25% change in the calculated pressure losses and only a 0.2% change in the calculated liquid holdup. Results for other systems that were evaluated were comparable. Trials conducted with as few as 3.2% of the original number of points showed no more than a 2.2% change in the calculated pressure losses and no more than an 8.4% change in the calculated liquid holdup. The size of the resulting output data files was reduced by 64–96%. Filtering elevation data profiles using the procedure outlined in this paper should be worthwhile in almost any multiphase pipeline modelling where extremely detailed elevation profiles are available.
Multiphase pipeline modelling with detailed elevation profile data is often assumed to be a time-consuming process, taxing for even today's powerful desktop computers. The procedure outlined in this paper can dramatically improve the efficiency of the modelling process.
Fracture Detection in Unconventional Gas Plays Using 3D-Seismic Data
Authors: Gray F. David 
Published: June 2008

Abstract
All unconventional gas plays rely on the presence of natural fractures to enhance or create permeability in the reservoir. Fractures cause significant, measureable changes in 3D seismic data. These changes appear as variations in seismic amplitudes and velocities with shot-receiver azimuth and are known as seismic azimuthal anisotropy.
Examples of the seismic identification of fractures are shown for a Mannville Coal and gas shale from Alberta, and the tight gas sands of the Pinedale Field in Wyoming, which is an analog to Alberta's Deep Basin. In the latter example, seismic fracture estimates are shown to be the best predictors of well EUR (Estimated Ultimate Recoverable) and therefore they are used to predict EUR in 3D.
The technology to measure seismic azimuthal anisotropy is now well developed and ready to be used to pinpoint higher producing areas of natural fractures in fractured unconventional gas reservoirs such as tight gas, gas shales and coalbed methane.
Seismic azimuthal anisotropy measurements have achieved a technical success rate for identifying fractures upwards of 80% in unconventional gas plays. This can significantly impact drilling success in areas where success rates are low. These measurements also indicate the probable fracture strike and so, by identifying where the gas is coming from, they can be used to avoid drilling into depleted pools.
Integrated Petrophysical Evaluation of Shale Gas Reservoirs
Authors: Jacobi D. , Gladkikh M. , LeCompte B. , Hursan G. , Mendez F. , Longo J. , Ong S. , Bratovich M. , Patton G. , Shoemaker P. 
Published: June 2008

Abstract
Gas shales are economically viable hydrocarbon prospects that have proven to be successful in North America. Unlike conventional hydrocarbon prospects, gas shales serve as the source, seal, and the reservoir rock. Generating commercial production from these unique lithofacies requires stimulation through extensive hydraulic fracturing. The absence of an accurate petrophysical model for these unconventional plays makes the prediction of economic productivity and fracturing success risky.
This paper presents an integrated approach to petrophysical evaluation of shale gas reservoirs, specifically, the Barnett Shale from the Fort Worth basin is used as an example. The approach makes use of different formation evaluation data, including density, neutron, acoustic, nuclear magnetic resonance, and geochemical logging data. This combination of logging measurements is used to provide lithology, stratigraphy and mineralogy. It also differentiates source rock intervals, classifies depositional facies by their petrophysical and geomechanical properties, and quantifies total organic carbon. The analysis is also employed to locate optimal completion intervals, zones preferable for horizontal sections, and intervals of possible fracture propagation attenuation. Resistivity image analysis complements the approach with the identification of natural and drilling induced fractures. We compare results from three different wells to show the effectiveness of the method for shale gas characterization.
The methodology presented provides a means to understand the geomechanical and petrophysical properties of the Barnett Shale. This knowledge can be used to design a selective completion strategy that has the potential to reduce fracturing expenses and optimize well productivity. Though developed specifically for the Barnett Shale, the underlying ideas are applicable to other thermogenic shale gas plays in North America.
Novel Low Heat-of-Hydration Cement Compositions for Cementing Gas Hydrate Zones
Authors: Reddy B. R. 
Published: June 2008

Abstract
Cementing wellbores drilled in low-temperature formations such as permafrost and gas-hydrate zones requires cement compositions that set at low temperatures and yet have low heat-of-hydration. This is particularly the case for gas-hydrate zones because of the potential for gas liberation from gas hydrates and formation of gas flow channels if the temperature rise caused by heat-of-hydration exceeds the temperature at which gas hydrates decompose.
This paper presents novel cement compositions that contain heat-sink additives capable of absorbing heat released from cement hydration without a significant rise in the slurry temperature. The organic heat-sink materials are added to cement slurries as aqueous suspensions or emulsions and undergo phase changes when heated. The slurry temperature rise caused by cement hydration in the presence of these materials was measured under adiabatic conditions and the results are presented.