Relative permeability of coal to gas and water is an important variable in coalbed methane (CBM) reservoir development as it is required for reserve estimation and field production planning. In this study, two coal samples (GP and GS) were used to determine the relative permeabilities using three gases (He, CH4 and CO2) at three different operating pressures (100, 300, 400 psi) and a constant overburden pressure of 800 psi. Both drainage and imbibition curves were obtained. Unsteady state displacements were used.
The petrophysical properties of these coal samples were also measured. The very low absolute permeability of the cores (0.07 mD) required special procedures to minimize errors. The experimental results presented here showed that the relative permeabilities were typically very low for all gases and high for water. The irreducible water saturation showed correlation with the type of gas (non-adsorbable He to strongly adsorbable CO2) and pressure.
It is concluded that coal relative permeability to gas and water depended on the nature of gas and the operational pressure. Relative permeability of coal changed also because of fluid-mineral interactions. It is concluded that the GP and GS samples tended to be more water-wet at higher pressures in the case of the adsorbable gases, viz. methane and carbon dioxide. However, in the case of non-adsorbing helium, higher pressure prevented the influx of water into the larger pores leading to smaller irreducible water saturation.
Coalbed methane is gaining increasing importance because of the growing emphasis on clean fuels on one hand and as a source of hydrogen on the other. Historically, natural gas price has been about one-half of the price of oil on the same energy basis primarily because of the difficulty of transporting gas. In Canada, natural gas is particularly important because of the production and upgrading of bitumen from oilsands. Gas consumption is about 3 Mscf/bbl of bitumen.
With the looming natural gas supply shortages, coalbed methane is becoming an important energy resource of Canada, U.S.A., Australia, and other developing countries. In the U.S.A., coalbed methane supplies about 8% of the total gas consumption of about 23 Tcf/year (1 Tcf = 1012 scf) and in Canada, about 1% of natural gas needs. It is believed that this resource would contribute significantly to future natural gas supply as the natural gas reserves dwindle and development of tight gas costs rise.
A major part of commercial coalbed methane exploitation is the ability to make reliable predictions of reservoir performance, which requires high quality reservoir data and petrophysical properties of coal, such as porosity, permeability, capillary pressure, and especially the two-phase gas-water relative permeability of coal. This would be required for all dynamic studies of the reservoir or individual wells as most coalbed methane reservoirs contain
water to varying saturations. Often such water is mobile and gas is produced along with large volumes of water. In this work, an experimental apparatus was designed, built, tested, and commissioned to determine the relative permeability of coal to gas and water using the unsteady state measurement method at a number of operating pressures. The gases used as the gas phase were helium, methane, and carbon dioxide in this order of adsorbing strength on coal and the water phase was 2% formation brine.
Shale gas reservoirs have become a significant source of gas supply in North America owing to the advancement of drilling and stimulation techniques to enable commercial development. The most popular method for exploiting shale gas reservoirs today is the use of long horizontal wells completed with multiple-fracturing stages (MFHW). The stimulation process may result in bi-wing fractures or a complex hydraulic fracture network. However, there is no way to differentiate between these two scenarios using production data analysis alone, making accurate forecasting difficult.
For simplicity, often hydraulic fractures are considered bi-wing when analyzing production data. A conceptual model that is often used for analyzing MFHWs is that of a homogeneous completion; in which all fractures have the same length. However, fracture lengths that are equal in length are rarely if ever seen (Ambrose et al., 2011).
In this paper, production data from heterogeneous MFHW (i.e., all fracture lengths are not the same) drilled in extremely low permeability reservoirs is studied. First, the simplified forecasting method of Nobakht et al. (2010) developed for homogeneous completions is extended to heterogeneous completions. For one specific case, the Arps decline exponent is correlated to the heterogeneity of the completion. It is found that Arps' decline exponent to be used after the end of linear flow increases with the heterogeneity of the completion. Finally, it is shown that ignoring the heterogeneity of the completion can have a great effect on the long-term forecast of these wells.
In the drive to improve the economics of shale gas plays, producers are drilling more wells per pad and continually developing new techniques to maximize efficiency, reduce setup costs and optimize completion process. Through careful project planning and logistics, simultaneous 24 hour operations can be achieved. As a result, equipment is often required to operate with minimal maintenance time. The typical mobile fracturing equipment used in these operations is being operated similarly to a process plant environment and is expected to operate in excess of 18 hours per day for consecutive months, contrary to its intended design.
These operations are primarily performed in shale formations employing stimulation treatments involving abrasive slick water pumped at high pressure and high flow rate.Also, the increased work cycles often lead to higher than normal erosion and fatigue frequency in the pumping equipment and flow lines, in comparison to conventional stimulation methods.
The paradigm shift in these fracturing operations has led to the re-evaluation of current equipment design. With data taken from a successful fracturing campaign in the Horn River Basin of Northeastern BC, this paper will discuss the challenges encountered in this project, the design limitation of conventional fracturing equipment and considerations for new equipment design which includes fuel delivery, flow line management, and equipment logistics.
Woo, Ving (Bellatrix Exploration Ltd.) | Pope, Timothy Lawrence (Schlumberger) | Abou-khalil, Emile (Schlumberger) | Davidson, John (Schlumberger Canada Ltd.) | Bonnell, Andrew (Schlumberger) | Zhang, Jenny (Schlumberger Canada Ltd.)
The Cretaceous Cardium formation has been produced since the early 1950's. The Cardium is a sandstone that can exhibit a wide range in permeability. This is due to the diversity of the depositional environment creating deposits that can vary from siltstone, fine grained sandstone to conglomerate. The formation is laterally extensive across western Alberta. Secondary recovery in the form of water flooding has been ongoing in the core area since the 1960's allowing production into the twenty first century. However, it wasn't until the application of horizontal drilling and multi-stage completion techniques that the vast reserves in the poorer quality areas could be economically produced.
This paper discusses the initial phase of an optimization process used to increase production and net present value in Cardium completions through the application of reservoir modeling, optimized fracture spacing and the application of a solids-free viscoelastic fracturing fluid. The new approach provides higher production rates and accelerated flowback compared to the gelled oil system previously employed. In addition to the previous two points, the economics are further enhanced by the elimination of the substantial cost of oil used in gelled oil stimulations.
Examples of an integrated approach for quantifying oil and gas production potential in different hydrocarbon windows of the Eagle Ford Shale are presented. The Eagle Ford basin is unique in that reservoir fluids range from black oil to dry gas depending on the geology, burial depth, and temperature. The main goal of this paper is to guide operators to an understanding of potential reserves and their distribution in the Eagle Ford through the use of our specialized analysis and methodology to estimate ultimate recoveries.
Data from the Eagle Ford Shale was compiled and analyzed to gain knowledge about the basin. The geology aided in indentifying "sweet spots?? based on the various thermal maturation windows. Also, recent drilling and completion activities were examined in addition to the observed production from public databases.
The intent was to determine curent completion practices in different parts of the Eagle Ford and also provide insight on the relationship between geologic features and production trends. A rapid asset evaluation case study is presented to demonstrate technique and workflow that uses vintage vertical well data to provide an estimate of asset value and reserves for a typical horizontal well in the Eagle Ford.
The results of the study identifies "sweet spots?? of oil and gas production and indicates that 1) Eagle Ford production is related to the maturation windows, as well as structure; 2) the best wells in the Eagle Ford are in the thicker areas; 3) Austin Chalk production relates to the underlying Eagle Ford production; 4) different completions for different areas and types of hydrocarbons should be considered, and 5) data and knowledge integration is the key for rapid evaluation of asset value in the Eagle Ford Shale.
Operators can use this information and technique to help 1) better understand the uniqueness of the Eagle Ford Shale, 2) optimize their completion design and field development plan, and 3) calibrate expectations on oil and gas reserves potential under their acreage.
Microseismic (MS) monitoring of hydraulic fractures using either the downhole or surface geophones has become a common practice. The same setup may be used for the multi-stage fractures. The main limitations in using these data to understand hydraulic fracturing results are: the sensor location which is far away from the source, limited azimuthal coverage and inadequate velocity models. Analysis becomes more complex when we start dealing with anisotropic reservoirs. Typically the service companies produce the spatial and temporal plots of hypocenters without estimates of uncertainty leading the engineer to believe the hypocenter locations are exact. The hypocenter location problem becomes more complex in anisotropic shale reservoirs. Hypocenter locations are often determined from the arrival times of P-wave and S-waves and a known velocity model. The difference in the velocity structure and the complex fracture network make accurate fracture mapping difficult. In this paper, we report on a series of laboratory hydraulic fracturing studies performed on sandstone and a strongly foliated metamorphic rock, pyrophyllite. Microseismic events associated with the hydraulic fracturing are dominated by shear failure; fracture orientation is controlled as predicted by applied stresses in isotropic materials. However, in anisotropic materials the hydraulic fracture direction is influenced by the magnitude of anisotropy but is predictable when the anisotropic elastic constants are known. Visual evidence supports the hypocenter locations and focal mechanism determinations. Scanning Electron Microscope (SEM) observations reveal the nonlinear and nonplanar nature of the induced fractures. The fracture trace confirms the wider aperture at the injection point and the frequent occurrence of the terminations and bifurcations farther along the fracture front.
The design of solvent-based and solvent assisted heavy oil recovery processes requires accurate predictions of phase behavior as straightforward as saturation pressures and as potentially complex as vapour-liquid-liquid equilibria and asphaltene precipitation. In this case study, saturation pressures of dead and live bitumen were measured in a Jefri PVT cell at different concentrations of a multi-component solvent at temperatures from 20 to 180°C. Saturation pressures and the onset of asphaltene precipitation were also measured for the bitumen diluted with n-pentane. The onset of precipitation was determined by titrating the bitumen with pentane and periodically circulating the mixture past a high pressure microscope.
The data were modeled with the Advanced Peng-Robinson equation of state (APR EoS). The maltene fraction of the bitumen was characterized into pseudo-components based on extrapolated distillation data. The asphaltenes were characterized based on a Gamma distribution of the molecular weights of self-associated asphaltenes. The APR EoS was tuned to match the saturation pressures by adjusting the binary interaction parameter between the solvent and the pseudo-components via a correlation based on critical temperatures. Rather than adjusting the interaction parameters for each pair of components, only the exponent in the correlation was adjusted. The role of mixing rules in correctly predicting the onset and amount of asphaltene precipitation is discussed.
Previous works have presented the results of successful simulations of fluid injection into naturally fractured shale using a Discrete Element Model (DEM). The simulations included coupled fluid flow-deformation analysis, failure type and extent calculations, as well as a series of parametric analyses. The parameters investigated included: 1) injection rate and its effect on the overall fracturing results, and 2) fluid viscosity, which had a significant influence on the ratio of tensile (mode 1) failure versus shear failure.
With the huge growth in the stimulation of naturally fractured formations such as fractured shales, it is clear that the industry needs new hydraulic fracturing simulation tools beyond the limits imposed by pseudo3D fracturing models. DEMs, in which both matrix block behavior and fracture behavior are explicitly modeled, offer one option for the specific modeling of hydraulic fracture creation and growth in a naturally fractured formation without, for example, the assumption of bi-planar fracture growth.
In this paper, we extend the previous works to quantify, for fractured shale gas plays, the effect of stress orientation, fluid viscosity, and rock mechanical properties in terms of changes in fracture aperture and transmissivity. Changes in fracture transmissivity directly correlate with improvements in well productivity - the primary goal of the stimulation.
The results of the study provide a means to improve shale completions by understanding the effects of the DFN orientation relative to the stress field, fluid viscosity, and rock mechanical properties on changes in fracture aperture, fracture transmissivity, and formation effective permeability, which directly relate to well productivity.
During the life of producing wells, there comes a time when the well approaches its economic viability as a producing well. If the reservoir potential is sufficient to support the expenditure, many wells are candidates for recompletion, reperforation, or restimulation. This type of focus on the Barnett shale began in the late 1990s. Drilling activity dramatically increased during the ensuing years and now there are more than 14,000 wells that have been drilled, most of which are producing wells. A lot of these wells are potential candidates for restimulation (refrac) because their production rates have declined but still have significant reservoir potential. The completion techniques deployed in the Barnett evolved over time to where many wells have dozensof perforation clusters and hundreds of individual perforations. Generally, refracsare ineffectual unless the perforations can be temporarily isolated so that the energy of the subsequent fracturing treatment can be focused on individual portions of the reservoir. Additionally,refrac candidate wells often contain challenging wellbore environments that further complicate the ability to successfully refrac the wells. The use of biodegradable particulates to facilitate the temporary diversion and concentration of frac energy has increased the success of restimulation.
This paper discusses the recent development of techniques and materials being used in refracturing operations. Included are discussions of laboratory results of new and novel materials, along with case histories of refrac wells demonstrating application of such materials and techniques.
A method is presented that integrates a triple porosity model with sonic, density and resistivity logs for evaluation of tight gas formations. The interpretation takes into account results from petrographic work in the Western Canada Sedimentary Basin (WCSB), which indicates that tight rocks are comprised of different types of pores including (i) intergranular, (ii) slot + microfractures, and (iii) isolated non-effective porosities.
Seismic data are powerful in the exploration and production domains but a method that integrates seismic velocities and the observed triple porosity petrographic characteristics of tight gas formations is not available. This paper provides the theoretical foundation and development of equations for this integration along with examples using real data from tight gas formations in the WCSB.
The proposed method provides estimates of inter-well formation resistivity, porosity and water saturation to obtain estimates of original gas in place. The comparison between resistivity from seismic velocities and resistivity from well logs is good with a strong statistical effectiveness. Under favorable conditions, the partition between effective and non-effective porosity might be estimated.
The proposed methodology has significant potential for application in tight gas formations of the WCSB. The method can probably be extended to other regions around the world, which possess tight gas formations with similar characteristics to the ones described in this work.