Carbon emitted on account of our continued use of fossil fuel can be offset using carbon capture and storage (CCS). The technology for this exists, however the economics of it is context dependent and CCS is shown not to be very cost effective in oilsands. Committing to the needed large scale sequestration projects without properly considering alternatives can prove costly at both economic and social levels. Charcoal sequestration, discussed earlier by Gupta carries with it a few advantages such as being less costly and lacking any post operation liabilities. Above all, it is reversible allowing flexibility of policy and operation and avoiding long term or large scale commitments.
The economics of the charcoal approach depends mainly on two factors: the cost of the feed biomass and the cost of processing. The first of these is addressed by using municipal waste as feedstock which can be available free of charge. Expectedly the cost of processing, the second factor, depends on the apparatus and the scale of operation.
In this paper, the authors discuss prominent traditional and modern apparatus used for conversion of biomass to charcoal with their benefits and drawbacks and describe a simple and pragmatic apparatus which could be assembled relatively easily, for a small scale operation such as processing industrial camp generated solid organic waste.
Offsetting carbon in this manner can obviously be a good way to initiate demo projects for the charcoal sequestration approach as it also helps with waste management. These demo projects in turn will help evaluate various aspects of this novel method of sequestration, and enhance public awareness on the subject which in turn will help the larger society make an informed choice to embark on a right course of action for atmospheric carbon abatement. Additionally, in light of the growing per capita waste worldwide, use of municipal waste as feedstock for charcoal sequestration can be a significant measure of carbon offset at global scale in its own right.
Starting in the 1970s, Union Oil Company of Canada (Unocal), in partnership with Canadian Superior and the Alberta Government, conducted a series of exploratory field tests in the bitumen-saturated carbonate rocks of the Grosmont Formation. These tests applied thermal recovery technologies, including steam drive and cyclic steam stimulation (CSS), that were in their early stages of development. Significant amounts of production and observational data were obtained. Although some results were encouraging, activities in Grosmont were eventually stalled in the mid 1980s as economic attention was shifted to Cold Lake and Athabasca Cretaceous siliclastic reservoirs. Since then, in situ bitumen recovery, 3D seismic, horizontal well and surface processing technologies have matured significantly. In light of the enormous resources (406 billion barrels) hosted within the Grosmont Formation, it is pertinent to ask whether those new technologies are applicable for carbonate reservoir development.
To answer this question, we studied data from the Unocal pilots conducted in the Grosmont C and augmented it with recent laboratory tests on newly acquired Grosmont C cores. The previous pilot CSS results were encouraging, with the cycle steam-to-oil ratio as low as 3.65 and a peak rate of 440 bbls/d from a single vertical well. With subsequent cycles the ratio of the produced fluid to the injected fluid increased, signifying the injected energy was retained and more effective in later cycles. The operation strategy of the Unocal pilots and its implementation were not optimal and we believe that this could be improved with modern techniques.
Based on our new understanding of the Grosmont Formation and specifically the Grosmont C, a numerical model was created and verified with production data. Model results indicate that the application of SAGD will be a commercially viable recovery process for Grosmont carbonate reservoirs and that low pressure injection (below 3500kPa) would be desirable. The laboratory tests not only support these conclusions but also suggest that performance of the applicable thermal processes can be enhanced with the addition of solvent. A SAGD/solvent pilot test is planned to start up in late 2010. This pilot will be critical to the development of exploitation strategies applicable to Grosmont carbonate bitumen resources.
Heavy crude oil reserves are steadily gaining attention as the world's energy demand increases. The fluid characterization of heavy oil and bitumen is critical in deciding best extraction, production, and processing methods of a heavy oil asset. High viscosity, low API, low saturation pressure, and low GOR impose challenges in measuring fluid properties of heavy oil. Such challenges include fluid sampling, sample handling, cleaning and de-emulsification of heavy samples and slow evolution of gas from oil phase during pressure-volume-temperature (PVT) testing— e.g., constant composition expansion (CCE) experiment. Due to these challenges, the accurate and reliable fluid characterization of heavy oil becomes more difficult. Currently, no industry standards exist for heavy oil property measurements. More often, heavy oil property measurements are performed in the same way as black oil fluid property measurements. This poses a big risk in obtaining erroneous fluid properties measurement for heavy oils.
This paper summarizes the heavy oil fluid characterization technique that includes fluid sample handling, PVT analysis, fluid viscosity, emulsion and rheology, slow kinetics of gas evolution during CCE experiment, solvent solubility study, steam stripping study, and high temperature vapor-liquid equilibrium of oil-solvent-steam systems. The experimental methodologies, including the merits and experimental limitations for these measurements are discussed in detail. Example results of heavy oil property measurements for each technique are presented. Finally, a systematic heavy oil characterization workflow is proposed for various types of production processes such as cold depletion, steam flood and heavy oil flow assurance characterization.
Polymer flooding provides a better sweep compared with water flooding, but there is concern about maintaining sufficient injectivity. Longer fractures could provide injectivity, but pose a risk for early break-through and containment. In addition, shear dilation of unconsolidated sand is also expected to improve permeability and injectivity. Shear dilation causing absolute permeability enhancement was observed in tri-axial tests. The relationship between propagation pressure and confining pressure was determined in unconsolidated sands by a series of physical model tests. The accuracy of the minimum in-situ stress determination was also investigated in unconsolidated sands. The results demonstrated that there is a small enhancement of absolute permeability due to dilation of unconsolidated sand and they do have a difference in absolute permeability between stress states for increasing and decreasing effective stress. Besides, the geometry of fractures induced by viscous fluids in an unconsolidated formation is a dominantly planar fracture, although it is very tortuous. In view of isotropic stress in the horizontal plane, multiple fractures were induced in several directions.
Key words: Polymer injection; Shear dilation; Unconsolidated sand; Heavy oil; Hydraulic fracture;
Polymer flooding has been employed for many years during recovery of heavy oil from unconsolidated reservoirs. It provides a much better mobility ratio when using polymer flooding instead of water flooding. Fracture behaviour in unconsolidated rock may be quite different from behaviour in elastic rock. Unlike competent formations, unconsolidated sands beds have little or no tensile stress. Besides, when fracture initiation and propagation, shear failure of this formation plays critical role. At the same time, polymer, as a kind of viscous fluid, could lead to different behaviour of fracture and pressure when compared with water injection. Therefore it is a challenging to predict injectivity and monitor fracture evolution by pressure measurements when using polymer flooding strategy in unconsolidated reservoirs.
Some experimental and simulation work has been done to reveal mechanism of fracture initiation and propagation in unconsolidated sands formation. Y. Dong and C.J. de Pater  and B. Bohloli and C.J. de Pater performed a series of experiments into unconsolidated sand samples to reveal the impact of stress and fluids rheology on the geometry of fractures caused by cross-linked gel and viscous Newtonian fluids injection. The simulation of hydraulic fracturing in unconsolidated sands was done by Zhai and Sharma. They found that shear failure is the dominant mechanism when fluids are injected into unconsolidated sands, while tensile failure happens only at the near wellbore region under strike-slip stress conditions.
The colloidal gas aphron (CGA) based drilling fluids are designed to minimize formation damage by blocking the pores of the rock with microbubbles, which can later be removed easily when the well is open for production. Aphrons behave like a flexible bridging material and form an internal seal in a pore-structure.
Size and concentrations of the bridging materials are very critical to the fluid's ability to seal the high permeability zones. Proper sizing of the microbubbles with respect to pore size distribution is essential for developing an aphron drilling fluid with effective sealing ability. The physico-chemical properties (i.e., viscosity, density, fluid loss, etc.) of the CGA base drilling fluids also need to be understood in order to drill with these fluids more effectively.
Aqueous CGA based drilling fluids systems have been fairly well characterized and successfully implemented in high-angle and horizontal wells drilled in low permeability as well as highly depleted reservoirs. Effectiveness of pore blocking by colloidal gas aphrons is expected to be improved even more, if we can replace water with non-aqueous base fluid such as mineral oil.
An experimental study has been conducted to determine the effect of base fluid composition (i.e., surfactant and polymer concentration) on the microbubble size and stability. The surfactant and polymer concentrations required for optimum formulation of mineral oil base CGA drilling fluids were determined.
The physico-chemical properties of non-aqueous CGA drilling fluids are also investigated. The results of rheology, filtration loss and density measurement tests are also presented.
In recent years successful stimulation and extraction of hydrocarbons from unconventional reservoirs has led to various approaches to the stimulation process. Slickwater stimulations pumped at very high flow rates have become the staple in formations such as the Barnett Shale. High treatment rates are made possible by the implementation of low dosages of polyacrylamide, which lower the effective pipe friction. This type of treatment process is common among other shale and tight gas plays throughout North America. Other types of treatments include conventional crosslinked or linear gelled fluids. Some treatments combine the conventional crosslinked fluids and the slickwater approach. Experimentation with multiple stimulation programs is a response to the changes in formation properties that vary from one formation to the next and within areas of the same formation. Over the last few years there have been several successful treatments implementing a high-quality foam stimulation in some shale formations. These treatments have usually included a gas phase in excess of 90 quality and often as high as 99 quality. This type of treatment is especially fitting for low-pressure reservoirs and in depleted zones. One advantage of a high-quality foam is its reduced environmental impact by using very small quantities of water as compared to high-rate slickwater stimulations. In these particular high-quality foams, a viscoelastic surfactant gel is used in the liquid phase as the gelling and foaming agent. With the combination of high-quality foam and non-damaging viscoelastic gel, the total fluid is completely non-damaging to the formation. Successful treatments in formations in the northeastern United States have led to a demand for use in other formations, necessitating a better understanding of fluid properties in order to design treatments. Very little published data is available for high-quality foam fluid properties. A study has been conducted to examine the fluid characteristics of high-quality foams as compared to typical 50 - 70 quality foams. This study will show trends of viscosity, foam stability and temperature sensitivity of high-quality foams using xanthan, guar-based gelling agents and viscoelastic base fluids.
When an appropriate treatment fluid is considered for fracturing applications, foamed fluids offer several attractive features. Foamed fracturing fluids are particularly attractive in formations sensitive to water. Foamed fracturing fluids effectively reduce the amount of water introduced to the formation as compared to slickwater fracturing treatments. In the case of a 70 quality (70% by volume) foamed fluid, the effective liquid introduced to the formation would be 30 percent of the total fluid volume. As the gas fraction or quality of the fluid is increased, the percentage of the liquid phase decreases proportionally, introducing less liquid into the formation. It is easy to see why some operators find a fracturing treatment that introduces only 1-10% aqueous phase to the formation very attractive. Another attractive feature of these high-quality foams is their effectiveness in depleted zones. Since these foams are predominantly gas (90 - 99%), recovery of the liquid phase is enhanced greatly by the amount of gas available to aid in fluid recovery. Since there is very little liquid placed into the formation, there is less fluid to recover and dispose. The environmental impact of large ponds or tanks for fracturing purposes is greatly reduced when only about 5-10% of the fluid requirement is liquid. Smaller tanks and ponds mean smaller locations with less environment disturbed.
Heavy oil and bitumen are expected to become increasingly important sources of fuel in the coming decades. There are extensive deposits in Alberta that could be a principal source of fuel in the coming century. The Athabasca Oil Sands, the largest petroleum accumulation in the world, the Cold Lake oil deposit, and the Lloydminster reservoir are all major Canadian oil sands deposits. SAGD, which has shown considerable promise in all three of these major deposits, remains an expensive technique and requires large energy input. Energy intensity of SAGD and the environmental concerns make it imperative to find new oil extraction technologies.
Co-injecting hydrocarbon additives with steam offers the potential of lower energy and water consumption and reduced greenhouse gas emission by improving the oil rates and recoveries. In a previous paper by the same authors(Hosseininejad Mohebati, Maini et al. 2009), it was shown that the selection of a suitable hydrocarbon additive and the effectiveness of this hybrid process are strongly dependent on the operating conditions, reservoir fluid composition, the heavy oil viscosity, and the petrophysical properties of the reservoir. Among these factors, the heavy oil viscosity which is the most prominent difference between these three reservoirs could be a very important parameter in the performance of this hybrid process. Therefore, it is important to evaluate the effect of oil viscosity on solvent assisted SAGD.
Extensive numerical studies in a 3D model by means of a fully implicit thermal simulator were conducted to evaluate the efficiency of each hydrocarbon additive in Athabasca, Cold Lake and Lloydminster reservoirs. Varying mole percents of hexane, butane and methane were co-injected with steam in with different values of heavy oil viscosity. The effect of oil viscosity on the performance of each solvent was compared in terms of oil production rate and cumulative steam oil ratio.
Coalbed methane (CBM) production in the San Juan Basin of northwestern New Mexico and southwestern Colorado has spanned over 30 years. Some parts of the field, such as the high-permeability Fairway, are now in a mature stage of reservoir pressure depletion. Optimization of well production operations in the Fairway presents many challenges because of its extremely low reservoir pressure (less than 100 psi in some areas), heavy coal fines production, difficult artificial lift challenges, increasing CO2%, and the presence of paraffin, inorganic scale and corrosion.
We use history matching by reservoir simulation to help diagnose the causes of well production inefficiencies and then plan how to mitigate them. Simulation of Fairway wells typically requires the use of an increasing reservoir permeability trend caused by coal matrix shrinkage with the desorption of methane and CO2. However, we have observed in some Fairway wells that below a reservoir pressure of around 300 psi, there is a flattening or even a decrease in the permeability trend. This shift in the permeability trend is likely caused by coal failure (i.e. a change in mechanical properties of coal) that is evidenced in the wells by an increased amount of coal fines production.
This paper is written in two parts. The first part presents the challenges we face in operating Fairway wells and the solutions we have developed to overcome them. Field observations and operating guidelines will be shared along with well intervention histories where we have seen success. The second part discusses our use of reservoir simulation to diagnose the causes of reduced well production efficiency.
Cui, Xiaojun Albert (CBM Solutions, a Division of Trican Well Service) | Bustin, R. Marc (U. of British Columbia) | Brezovski, Ron (CBM Solutions, a Division of Trican Well Service) | Nassichuk, Brent (CBM Solutions, a Division of Trican Well Service) | Glover, Ken (CBM Solutions, a Division of Trican Well Service) | Pathi, V. (CBM Solutions, a Division of Trican Well Service)
Accurate estimation of gas-in-place is crucial for successful evaluation and exploitation of unconventional gas reservoirs, such as shale gas, coalbed methane, and tight gas. However, gas effective porosity, one of the most important parameter in estimating gas in-place, is commonly measured on crushed samples of cores or cuttings at ambient pressure although many studies have shown that the porosity and permeability of reservoirs rocks decrease with increasing effective stress, and thus the pore volume/porosity measured on crushed samples at ambient (zero stress) conditions will be larger than porosity measured under in-situ reservoir stress conditions. Normally the stress-dependence of porosity is simply accounted for by a correction factor based on the linear poro-elastic deformation, which is likely an over-simplification.
In present study, we developed a new protocol for simultaneously measuring stress-dependent In-Situ Permeability and Porosity (ISPP) that provides a method for routine characterization of effective porosity and permeability under simulated reservoir conditions. Our new method can significantly reduce the uncertainties of porosity introduced by testing crushed samples under ambient conditions, testing time, and the need for good quality core samples that are usually unavailable.
Preliminary test results indicate that the stress dependence of porosity (or pore compressibility) of fine grained reservoir rocks follows a unique trend of each tested sample, which cannot be simply adjusted from ambient porosity by a universal factor. Physical and numerical sample tests suggest that our ISPP method can obtain permeability similar to the normal pressure Pulse-Decay Permeability (PDP) technique if samples are homogeneous or transversely layered along their axes. Otherwise, our ISPP method likely tests the geometrical average permeability of longitudinally layered samples instead of the weighted arithmetical average permeability tested by the PDP method.
Overall, our approach of simultaneously measuring effective porosity and permeability under reservoir conditions offers intrinsically consistent porosity-permeability data to characterize unconventional reservoirs. Our study also reveals that utilization of different methods to test samples in different orientations and different sizes is necessary to rigorously characterize the hierarchical permeability and porosity of heterogeneous and microporous unconventional reservoir rocks.
Torres, David Enrique (U. of Texas at Austin) | Sharma, Mukul Mani (U. of Texas at Austin) | Pope, Gary Arnold (U. of Texas at Austin) | Ahmadi, Mohabbat (U. of Texas at Austin) | McCulley, Corey Alan (U. of Texas at Austin) | Linnemeyer, Harry (University of Texas at Austin) | Gilani, Syed Furqan
In volatile oil reservoirs, the presence of two fluid phases (gas and oil) near the wellbore is a common problem that affects well deliverability. As the pressure falls below the bubble point the presence of two immiscible phases reduces the oil relative permeability and leads to lower oil production rates. In this paper, we show that the application of fluorinated chemicals can mitigate this impairment associated with gas blocking of volatile oils. We show through laboratory experiments that the treatment not only removes the water from the treated zone, but also modifies the wettability of the rock surface to neutral wet, minimizes capillary trapping and enhances the mobility of oil and gas. The chemical treatment is effective in the presence of connate or flowing water over a range of temperatures. This technique may be used as a curative or preventive treatment in volatile oil reservoirs, potentially increasing oil production rates and recoverable reserves. High-pressure high-temperature (HPHT) coreflood tests were conducted that show that the treatment improved the relative permeability, by a factor of about 1.3 to 2.6 at a GOR of 6000 to 7000 scf/STB in sandstone and limestone cores at low capillary numbers (Nc). Wettability alteration was measured using contact angle and imbibition tests. These tests together with x-ray photoelectron spectroscopy (XPS) analysis were used to screen the selected surfactants. Since this durable enhancement is achieved by treating a small area around the wellbore, it may be applicable in a wide variety of wells.