bluuebunny/crossref_metadata_2025 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

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

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

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

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

Shale 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

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

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

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

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

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

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

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.
Gas Transportation: Present and Future
Authors: Rajnauth J. , Ayeni K. , Barrufet M.
Published: June 2008

Natural gas is a versatile form of non-polluting fuel. With just over a dozen nations accounting for 84% of the world-wide production, access to natural gas has become a significant factor in international economics and politics. The major difficulty in the use of natural gas is transportation and storage because of its low density. Despite this, natural gas production has seen tremendous growth over the years. This has been due to large amount of natural gas reserves, the wide variety of uses of natural gas and carbon dioxide emissions from natural gas energy generation are far less.

In the past, the natural gas recovered in the course of producing petroleum could not be profitably sold, and was simply flared. This wasteful practice is now illegal in many countries. The most common method for transporting natural gas was high pressure in underground pipelines. Additionally, countries now recognize that value for the gas may be achieved with LNG, CNG, or other transportation methods to end-users in the future. In many cases the gas is now re-injected back into the formation for later recovery. Transportation is now a very important and key role in the supply chain for natural gas and the big challenge is to transport gas to markets at the lowest cost without too much environmental risks. Now re-gasification at the market is important when selecting the mode of transportation of natural gas.

This paper reviews, analyzes and provide insight to present and future gas transportation methods. These options of transporting gas from oil and gas field to markets include pipelines, liquefied natural gas, compressed natural gas, gas to solids (hydrate), gas to liquids, gas to wire and other gas to commodity methods. The paper provides an overview of the challenges facing present transportation modes, and discussion on possibilities for improvement via new technology or new gas transport options. Another focus of the paper is to compare and highlight some critical factors affecting the different means of transportation of natural gas. These include economics, markets, gas concentrations, environmental risks and re-gasification issues.
New Semi-Analytical Solutions for Multilayer Reservoirs
Authors: Lolon E. P. , Archer R. A. , Ilk D. , Blasingame T. A.
Published: June 2008

This paper presents the development, validation, and application of new approximate (semi-analytical) solutions for the wellbore pressure and fractional flowrate responses of commingled layered reservoirs — without interlayer cross/low (crossflow is only permitted in the wellbore, not in the reservoir). These formulations use "basis" pressure drop relations for each layer as a mechanism to create multilayer solutions in the Laplace domain — and due to the choice of these basis relations; the formulation can be analytically inverted into the real domain. This process provides a direct (albeit approximate) solution for multilayer reservoir systems. The basis relations include a "constant" pressure case and "linear" pressure case. In addition to these methods, we also provide a "Total Pressure/Rate Averaging" (TPRA) formulation which is used to provide an average rate and pressure response for each layer.

These semi-analytical solutions can be used to construct well test or production profiles in a simple computational environment (e.g., a spreadsheet). These solutions can also be used to diagnose well test and production data in terms of layered reservoir behavior. The "linear" pressure case (non-zero intercept) gives the best performance — however, from a practical standpoint, the algebra involved limits this approach to 2-layer reservoir case. The TPRA formulation is very consistent, but not as accurate as the other solutions — however; the TPRA formulation is easily be extended to n-layers.
Simplifying Gas Production Modeling
Authors: Jordan Colin L. , Jackson Robert , Smith Cooper
Published: June 2008

This paper presents a simple, but reliable, method for predicting the performance of multiple gas wells in complex reservoir shapes. Using an approximation of the traditional "image well" method, pressure and production profiles can be generated for arbitrary shaped reservoirs, with internal boundaries and similar heterogeneity, as well as multiple well completions. The procedure will allow for modeling and analysis, as well as forecasting of complex operating conditions including varying rate and flowing pressure schedules (including shut-in) for conventional and unconventional gas systems without the need of advanced engineering mathematics or computational libraries.

The approach overcomes many limitations of conventional analytical methods (i.e. single well solutions or limited reservoir shapes) which are generally unsuitable for multi-well planning, in-fill drilling, or full field development. But, it also allows for petroleum engineers, without numerical simulation resources or skills, to perform field wide evaluations on reservoirs and wells with a variety of operating conditions. A number of computational and quality issues are addressed including Laplace space inversion methods; addition of wellbore storage and skin (at wellbore and observation points); incorporation of absorbed gas for unconventional gas systems; pressure dependant fluid properties; reservoir heterogeneity; and rate forecasting. The methodology is validated by comparison to both analytical solutions and commercial numerical tools.

In short, a new mathematical approach for production modeling and forecasting has been introduced. Mathematical adaptations for reservoir heterogeneity, complex reservoir shapes, multiple completions and rate forecasting are discussed. Adaptations and applications for both conventional and unconventional gas (including coal and shale gas) are demonstrated. Finally, a simple solution process is presented for quick and easy implementation in MS Excel or other common tools.
Volumes and Areas of Pendular Rings With Non-Zero Contact Angle in Tight Gas Sands Dominated by Contractional Fractures and Slot Porosity
Authors: Aguilera Roberto
Published: June 2008

Contractional natural fractures and slot porosity play and will continue to play an important role in commercial gas production from tight sands. The process that leads to these types of porosities starts with deposition of sand grains. As the grains get progressively buried inelastically the net stress increases continuously. Eventually the sand grains reach their maximum depth of burial and at this stage the vast majority of the porosity and permeability has been destroyed. Uplift leads to a cooling effect and thermo-elastic stresses that create contractional fractures and slot porosity.

Throughout these processes the sand grains get deformed and as a result there are continuous variations in volumes and areas of pendular rings, which lead to variations in porosities, permeabilities and water saturations.

This paper discusses models that can be used for estimating these variations for zero and non-zero contact angles in tight gas sands.

The subject is significant because historically oil and gas companies have gone, rightly, after tectonic fractures associated with folding and faulting in tight gas sands. The present work discusses a different possibility as the contractional fractures discussed above are not restricted to areas dominated by major tectonic events.
One-Trip Multistage Completion Technology for Unconventional Gas Formations
Authors: Watson Don R. , Durst Doug G. , Harris Travis , Contreras Jesus D.
Published: June 2008

Cost-effective development of unconventional gas resources depends upon strategic application of advancing technologies. By employing efficient fracturing techniques with an appropriate multi-stage fracturing completion, operators can achieve higher initial gas rates, increased recovery rates and reduced completion costs. The completion process employs a single-trip multi-stage completion system which is driving the cost-effective exploitation of difficult reservoirs. Discussion will center on planning and execution strategies followed by some case history results and lessons learned. The introduction of a new feature to improve operational efficiency and future system improvements will be addressed.

The planning stage considers key factors associated with reserve estimates, selection of number of fractures, production behavior analysis, production forecast analysis, risk analysis, fracture design, and economic evaluation. The installation stage considers equipment and operational issues such as quantity and spacing of packers and sleeves. The completion stage involves techniques and procedures of the fracturing process. These planning and execution strategies achieve mechanical, volumetric and economic success, established by the efficiency of each fracture and total gas production rate when compared to initial evaluations.

The one-trip multi-stage fracturing completion process reduces rig time and cost for hydraulic fracturing services, accelerates production and improves reservoir drainage. When coupled with effective fracturing strategies and best practice procedures, the system provides improved production from unconventional gas formations.
Maximizing Energy at Coalface for Coalbed Methane Fracturing Operations
Authors: Mahdi Abbas W.A. , Yu Micheal , Pipchuk Douglas A. , Wasson Craig , Nguy Jim , Kathol Nathan Lawrence
Published: June 2008

Nitrogen coiled tubing fracturing is the predominant method for completing and stimulating dry coalbed methane (CBM) formations, such as the Horseshoe Canyon in the Western Canadian Sedimentary basin. A typical well has an average of 20 pay zones that are stimulated individually.

The coal cleats are fractured by pumping nitrogen at high rates through coiled tubing (CT) into perforations isolated by straddle assembly. Currently energy that can be delivered to the coalface of these dry CBM wells has been limited by the friction pressure through (CT). Efforts to increase the energy have involved increasing CT size and increasing surface horsepower. Economics and logistics practically limit the pipe size to 2 7/8 in. for deeper wells and 3¼ in. for shallow wells using CT fracturing technique.

This paper discusses the development of a technique which initially eliminates the CT friction limits on transferring energy to coalface. A large-volume pressure pulse is released downhole during the fracturing process to create an order of magnitude change in available energy at the fracture face, compared to current dynamic fracturing processes. The additional energy is dissipated by increasing the surface cleat area exposed. The development of the technique and field tests results will be discussed.

Introduction

The Horseshoe canyon dry coal formations have been commercially exploited since late 2000. From the beginning it was clear the Horseshoe Canyon CBM play was a unique CBM play, it is set apart by consisting of a dry under pressured coal. The coal therefore does not require dewatering before production. The coal consists of multiple thin seams, ranging from 10 - 30 seams per well. The coal seam thickness ranges lies between 0.1 and 2.5 meters. (Fig 1 - Horseshoe Canyon CBM log)

The production rates from these CBM wells dictates that a efficient drilling and completion model be adopted in order to be economic. The current model that is utilized is the wells are drilled with coiled tubing drilling rigs, cased and cemented. Wireline perforating crews are then dispatched to perforate the zones of interest in a rig less operation. The individual coal seams are then stimulated via the injection of dry nitrogen at high rates through a coiled tubing reel that is equipped with a fracturing isolation tool. The dry coal has not responded well to any other form of stimulation. The lack of success of more traditional stimulation methods is deemed to be damage to the dry under pressured coal seams.
Use of Bandra Formation Lean Gas as Fuel Gas at Heera Processing Complex (Offshore)
Authors: Gupta Anil Kumar , Asija Narendra
Published: June 2008

HEERA, one of the most promising hydrocarbon producing fields in Mumbai offshore; produces oil and gas from multilayered pay zones ranging from depth of 700 meters to 1500 meters. Bandra Formation, the uppermost strata of reservoir is a Miocene structure. This is the youngest pay zone in the Cenozoic carbonates of Mumbai Offshore basin comprising of limestone with shale bands at a depth of about 700 meters sub-sea bearing lean gas with 96+ percent of C1. Heera Offshore Processing Complex presently uses 2, 50,000 SCMD of rich gas for internal consumption mainly in turbine generators and Process Gas Compressor drivers. Process complex delivers gas to three users i.e. Gas Lift Wells at 80 kg/cm2, End Consumer at 56 kg/cm2 and Internal Consumption at 27 kg/cm2. Presently, fuel gas is tapped from Process Gas Compressor discharge at 80 kg/cm2. This gas has about 28% of C2+ component and good source for Value Added Products like C2/C3, LPG, Naphtha, etc. Study reveals that Bandra gas shall be ideally suited as fuel gas. Rich gas when replaced by lean Bandra gas as fuel gas will in turn add in to the Value Added Products (VAP) extraction. Around 1.0 MMSCMD gas production is expected thru upcoming three gas producers on HG platform in Bandra formation lasting for a period of 15 years.

The study suggests maximum utilization of Bandra gas as fuel gas in phased manner depending on the available formation pressure. Study also infers a) Optimization of the compressor utilization depending on the end pressure requirement by way of dedicating one compressor exclusively for compressing lean Bandra Gas at 56 kg/cm2, b) Split the two trains of Gas Dehydration Unit and operate them at 80 kg/cm2 and 56 kg/cm2 pressures respectively. Thus saving in compression energy of 960 KW per compressor, c) Sourcing fuel gas from Bandra formation shall reduce collective emissions of Green House Gases (GHG), mainly CO2, by an average of 7.28 percent compared to the present emission using rich gas, d) Rich gas thus added in the gas to consumers will add quantities of VAP (C2/C3: 50 TPD, LPG: 50 TPD and Naphtha: 8 TPD) extracted at downstream end.

The above study has optimized compression, dehydration facilities in terms of energy conservation, reduction of GHG emission and generation of VAP. Recommendations of the study are currently in the process of implementation.
Tight Gas Production Performance Using Decline Curves
Authors: Kupchenko C. L. , Gault B. W. , Mattar L.
Published: June 2008

Traditional ("Arps") decline analysis is the most common reservoir engineering tool used for production performance forecasting. It has several advantages over other techniques in that it is simple to use, requires minimal data and is well understood by the industry. Currently, however, these methods are being misused in unconventional applications, such as tight gas.

Production perfomance from tight gas reservoirs is characterized by steep initial decline rates and long periods of transient flow. If decline analysis is performed using this transient production data, the main assumption of boundary dominated flow (BDF) is violated and inaccurate forecasts may result. The goal of this work is to understand the behaviour of tight gas reservoirs during transient flow so that the familiar Arps method may be applied. The effects of different tight gas production responses (bilinear, linear, pseudo-radial, boundary dominated) are investigated. Finally, a methodology for applying traditional decline curve analysis to tight gas, with reference to long term transient flow, is presented.
Measurement of Relative Permeability of Coal: Approaches and Limitations
Authors: Ham Y. , Kantzas A.
Published: June 2008

A number of laboratory studies on coalbed methane (CBM) have provided data for the relative permeability of coal to gas and water, which are needed to analyze CBM reservoirs, particularly in numerical simulation.

The relative permeability curves of coal to gas and water are determined using the two methods used in the petroleum reservoir engineering, namely, the steady or unsteady state displacement methods. In most cases, the unsteady state displacement method is used because this method is relatively fast to carry out. In this method, the non-wetting fluid is displaced by the wetting fluid, and the effluent production and pressure history are used to back out the relative permeability of coal to gas and water.

One of the problems encountered in the displacement methods is the question of coal wettability. Many researchers studying this area have considered that coal is water-wet. However, it is a well-known fact that a large amount as much as 95% of methane is adsorbed on the internal surface of coal matrix. Therefore, coal could be regarded at least as initially gas-wet. The wettability of coal will depend on the flow characteristics of coal, that is, whether methane flows in the matrix. This paper investigates a number of wettability of coal scenarios and discusses the approaches used by various investigators, for instance, pre-heating the coal sample before any testing, and using a non-adsorbable gas, pointing out their limitations from the viewpoint of CBM reservoir simulation. The likely dependence of relative permeability of coal on flow pressure is also addressed.
Modified Flow After Flow Test To Predict Deliverability of Gas Wells With Turbulence
Authors: Kisko Sarah , Liao Shu Ping (Sandy) , Mattar Louis
Published: June 2008

This paper consists of two parts. The first part establishes the presence of turbulence in low pressure gas reservoirs even at relatively low rates. It is shown that it would be beneficial for these low pressure reservoirs to be tested using multiple rates to establish the level of turbulence. The second part describes a new type of flow test, which is a modified version of the traditional flow after flow test. The method of analysis of this proposed test requires the use of commonly available well testing software, and has been verified using synthetic data.
Pressure-Transient Test Design in Dual-Porosity Tight Gas Formations
Authors: Shahamat Mohammad Sadeq , Aguilera Roberto
Published: June 2008

The existence of natural fractures and their effects on the wellbore storage vanishing time and the onset of the outer boundary in a tight gas reservoir are examined. The so called pre- and post-fracture test design is used for both linear and radial flow type to investigate the effect of different values of ω and λf on the time needed for the wellbore storage to disappear and for the outer boundary to be reached.

It was found that for a constant hydraulic fracture conductivity, decreasing the ω value causes the wellbore storage to vanish earlier. Conversely, increasing the value of λf, with omega constant, causes the wellbore storage to vanish earlier. These changes have no effect on the time to reach outer boundary, which can be sealed or at constant pressure.

Commercial production from a tight gas reservoir seems to be a function of effectiveness of the natural fractures, and the hydraulic fractures. Applying the concept of dual porosity behaviour to a tight gas reservoir, as opposed to the single porosity behaviour that is considered by several other researchers, seems to be a promising idea for better understanding of these reservoirs.
Low-Volume Pumping Systems: Moving Gallons to Produce Thousands
Authors: Poythress Mike , Rowlan Lynn
Published: June 2008

In recent times, a continuous fiberglass rod pumping system has been designed for producing low volumes of fluid from gas wells that are loaded up with water. This system utilizes an efficient, low horsepower pumping unit, which operates on a ½ horsepower, solar powered DC electric motor. A conventional insert type rod pump is utilized so that pump changes do not require a work over rig, only the use of a spool trailer.

Other than using solar power this system is installed in two other configurations: 1) Hybrid – using available electricity and 2) Just the continuous fiberglass rod under a conventional beam pumping unit. In any configuration the goal is to minimize friction losses, so a small motor can power the system. Small diameter plunger limits both the fluid load lifted by the rods and limits the amount of fluid volume that can be produced to the surface, but only a few barrels per day of water can lead to liquid loading and killing flow from a gas well. Dynamometer and fluid level measurements will be presented to show the performance of several of the existing systems – Solar and Hybrid. Depth limitations for the ½″ diameter fiberglass rod will be discussed. Small diameter pump, small pumping unit size and light weight continuous rods allow the operator to use less than 1 hp motor to power the system.
Soybean Growth and Seed Yield Response to Tillage and Compost
Authors: Singer Jeremy W. , Logsdon Sally D. , Meek David W.
Published: June 2008

Plant response to organic amendment often varies and may interact with tillage. The objectives of this research were to determine if soybean [Glycine max (L.) Merr.] growth, nutrient uptake, and soil water use could explain whole‐plant and seed yield responses to tillage and compost amendment. A corn (Zea mays L.)‐soybean‐wheat (Triticum aestivum L.)/clover (Trifolium spp.) rotation, with or without fall compost application was initiated in 1998 in plots that had been managed with moldboard plow (MP), chisel plow (CT), or no‐tillage (NT) since 1988. No tillage by amendment interaction for yield was detected. Yield was similar in MP and CT. In 2003, yield was similar among tillage systems, but NT yielded 15% greater than MP and CT in 2004 and 8% lower in 2005. Mean yield across the 3 yr was similar. Compost amendment increased yield (9%) compared with nonamended soil only in 2004. Mean yield was 2% higher with compost than without. Water depth from the 0 to 90 cm soil depth was not affected by tillage or amendment. Seed P and K uptake were 18 and 16% greater in NT compared with MP and CT and 16 and 13% greater with compost than without in 2004. Soybean growing on compost‐amended soil had less seed protein compared with nonamended soil. Alternatively, seed oil content was 2 and 1% lower in nonamended than amended soil in 2003 and 2004. The mechanisms responsible for compost‐enhanced plant growth are difficult to quantify in the field under natural conditions because effects are short‐lived or too extreme.
Prevalence of and risk factors for hip dysplasia and cranial cruciate ligament deficiency in dogs
Authors: Witsberger Tige H. , Villamil J. Armando , Schultz Loren G. , Hahn Allen W. , Cook James L.
Published: June 2008

Objective—To evaluate prevalence of and risk factors for hip dysplasia (HD) and cranial cruciate ligament deficiency (CCLD) in dogs and determine change in prevalence over time.

Design—Cross-sectional study.

Animals—1,243,681 dogs for which information was reported to the Veterinary Medical Database between 1964 and 2003.

Procedures—Information on breed, sex, and age was collected, and prevalences and odds ratios were calculated.

Results—Castrated male dogs were significantly more likely than other dogs to have HD (odds ratio [OR], 1.21), and castrated male (OR, 1.68) and spayed female (OR, 2.35) dogs were significantly more likely to have CCLD. Dogs up to 4 years old were significantly more likely to have HD (OR for dogs 2 months to 1 year old, 1.22; OR for dogs > 1 to 4 years old, 1.48), whereas dogs > 4 years old were significantly more likely to have CCLD (OR for dogs > 4 to 7 years old, 1.82; OR for dogs > 7 years old, 1.48). In general, large- and giant-breed dogs were more likely than other dogs to have HD, CCLD, or both. Prevalences of HD and CCLD increased significantly over the 4 decades for which data were examined.

Conclusions and Clinical Relevance—Results suggested that sex, age, and breed were risk factors for HD, CCLD, or both in dogs and that prevalences of HD and CCLD have increased over time.
Asymmetry: The Foundation of Information. By Scott Muller. Springer: Berlin. 2007. VIII, 165 p. 33 illus., Hardcover. CHF 139.50. ISBN: 978-3-540-69883-8
Authors: Lin Shu-Kun
Published: June 2008

Normally a religious book should be read at least 100 times; a philosophy book 10 times and a science monograph should be read carefully at least once before you can claim that you have read the book and understand something.[...]