Relative permeability plays a significant role in predicting oil rate and ultimate oil recovery factor. The literature reveals that same set of relative permeability is often used to predict the ES-SAGD performance regardless of not only the downhole operating temperature but also the injected solvent concentration. This can lead to significant errors when predicting the ES-SAGD performance and its economical feasibility. In paper SPE-180713-MS, SAGD relative permeability was presented as a function of temperature. In this paper, a series of realistic ES-SAGD relative permeability curves were developed based on experimental work combined with simulation studies.
A typical Athabasca oil and sand were used to obtain the experimental data and construct relative permeabilities using unsteady-state method. First residual oil saturations were determined in presence of hot water and steam flooding under SAGD condition at a given temperature. Following that, a typical n-alkane (n-heaxane) solvent was co-injected with steam at different concentrations varying from one to 25 weight percent of the injected steam while the operating temperature was kept constant. The produced oil and water volumes were collected and measured during the hot water, steam injection, and solvent co-injection experiments. The data were utilized to construct the relative permeability curves at a given operating temperature (200 °C) and various solvent concentrations. Finally, a series of reservoir simulations were performed to history match the lab experiments and examine the accuracy of inferred relative permeability curves.
This paper presents a preliminary experimental and numerical modeling study on stability of boreholes with preexisting breakouts. A set of borehole and breakout stability experiments were carried out using a polyaxial cell on weak sandstone samples. The tests were performed by increasing the outer boundary stresses at a given stress ratio until sufficient failure was induced. The samples were then unloaded and the failed material removed manually to form breakouts. The samples with the new hole geometry were then re-tested along the same stress path with further failure monitored. It was observed that the failure started from the breakout tips. The failure initiation stress was slightly less that on the circular borehole and significantly less than the applied maximum stress in the borehole stability experiments. The breakout did not widen until the external load was close to the applied maximum level. The experiments were simulated numerically using an elasto-plastic damage constitutive model. It has been observed that the numerical simulation was able to qualitatively re-produce some of the experimental observations.
Wellbore instability is a significant contributor to nonproductive time and a major cause of equipment lost in hole during drilling (Wu and Tan, 2011). Industry approach to overcome the problem is to select a compatible drilling fluid for the rock formations to be drilled (van Oort, 2003) and an optimal drilling fluid density that prevents significant wellbore instability and drilling fluid loss (Zoback, 2010). Well trajectory could also be optimized based on wellbore stability considerations if permitted by the local geological conditions and production requirement. Furthermore, drilling fluid temperature may be conditioned to effect the near wellbore stress condition to prevent wellbore failure or mud loss (Maury and Guenot, 1995).
Majority research on wellbore stability has focused on initial stability of a circular borehole by comparing borehole stress with formation rock strength, and once the former is greater than the latter for a certain portion of borehole circumference, borehole failure is assumed. Such an approach does not consider progressive borehole failure. It is well known that wellbore and/or reservoir stress condition can change during drilling and production. It is important to understand how the borehole that already suffered rock failure and breakouts would response to the changed wellbore and reservoir stress conditions, and whether the breakouts would remain stable or enlarged further resulting in large cavings and borehole collapse.
A geomechanical analysis of underground coal gasification (UCG) requires integrated modeling in complex multidisciplinary areas of coupled fluid flow, rock and cavity mechanics. In this study, the results from an existing thermal and multi-phase fluid flow simulator are imported into a geomechanical module to solve for the vertical displacement and the stress variation around a propagating cavity induced by a coal gasification process. A Controlled Retracting Injection Point (CRIP) well configuration is applied in the thermal reservoir simulator to model chemical reactions and geochemistry. The high temperature nature of the UCG process as well as creation of void space within the rock mass continuum require the use of efficient rock constitutive models. Three different constitutive models are investigated in this study: linear elastic, hyperbolic, and elasto-plastic. We have then applied these constitutive models on a case study to compare the results. The displacement of a coal layer and the surrounding blocks as well as stress arching in regions away from the cavity can efficiently be captured by the use of all the above constitutive models; however, a stress analysis around the induced cavity necessitates implementation of a constitutive model which can efficiently capture the shear softening after the rock failure.
Coal accounts for almost 30% of global primary energy consumption, which makes it the second largest primary energy source in the world after oil. Coal is also the largest provider of electricity. Over 40% of global power production derives from coal . Coal's significant position in the global energy mix is mainly because it is abundant, low-cost, and the most wide-spread fossil fuel in the world . Despite a decline in the coal demand growth in 2014, International Energy Agency's forecast shows the growth of almost 1% per year through 2020 . Moreover, based on the 2013 survey of World Energy Council, coal consumption is forecast to increase over 50% to 2030. This rise will be mainly due to the escalating electricity rates in the developing countries . Therefore, more coal extraction is necessary to meet the global future energy demand.
Noraei Danesh, N. (School of Mechanical and Mining Engineering, the University of Queensland) | Chen, Z. (School of Mechanical and Mining Engineering, the University of Queensland) | Pan, Z. (CSIRO Energy Flagship) | Connell, L. D. (CSIRO Energy Flagship) | Aminossadati, S. M. (School of Mechanical and Mining Engineering, the University of Queensland) | Bai, T. (School of Mechanical and Mining Engineering, the University of Queensland) | Kizil, M. S. (School of Mechanical and Mining Engineering, the University of Queensland)
Drainage of fluids (hydrocarbon or water) from coal seam via drainage boreholes brings about compaction creep and permanent loss of porosity and permeability over time. In this paper, the impact of creep (time-dependent deformation) on coal permeability has been experimentally studied using a triaxial rig. The bituminous coal sample used for the triaxial creep test was excavated from Bowen Basin, Australia. Methane gas was used in the triaxial test to investigate the effect of creep triggered by pore pressure depletion on permeability during desorption under constant hydrostatic and axial stresses. The results show that the creep induced to coal results in a significant drop in coal permeability when approximately zero creep rate is reached. Permeability measurements show that drop of pore pressure in a step manner from 2.5 MPa to 1.5 MPa, 1 MPa, and 0.5 MPa leads to decrease in permeability loss ratio of 16.8%, 6% and 5.4% for each step change. Permeability rebound was not obtained in our experiments for this range of pressures. The experimental results of this study can shed light on complexity of interaction of gas transport and timedependent deformation of coal during gas drainage.
Coal as a soft rock experiences compaction when pore pressure depletes and effective stress increases during Coal Seam Gas (CSG) drainage. The increase in effective stress during gas drainage causes the reservoir to undergo compaction (Schatz and Carroll, 1981). This mechanical induced compaction causes permanent deformation of coal microstructure and loss of porosity. As a result, a reduction in permeability and weaker response to gas drainage is predicted in the coal influenced by compaction creep. Also, deeper coal seams undergo less deformation owing to restriction on stress relaxation in and around the working face during mining. The impact of creep on permeability is more important for lower rank coals located at shallow depth as they are softer than higher rank coals and therefore they experience more creep. Creep compaction of rocks, as a long-term process, occurs very slowly at the equilibrium state that has been reached in millions of years. However, creep process and shrinkage of rocks are accelerated when subsurface fluids are drained from the rocks via drainage boreholes. Deformation in coal can occur much faster due to being much softer than adjacent rocks (roof and floor rocks) (Brantut et al., 2013; Kaiser and Morgenstein, 1981). Negligence of the impact of compaction creep on coal permeability may result in misestimating the level of drained gas. This may lead to a delay in mining operations due to the need for addressing residual hazards associated with methane gas such as coal and gas outburst and asphyxiation.
The uniaxial compressive strength of a brittle rock mass is scale-dependent. In this paper, we will employ a uniaxial compressive strength varying linearly with the aspect ratio of the high-stress zone to determine material failure around an evolving traction-free opening. Under the conditions of given external loads, the stresses around the opening are calculated based on an elastic boundary element method, and they are checked against the uniaxial compressive strength with regard to the occurrence of extensional spalling. Provided that the material failure occurs at test points arranged in multiple layers surrounding the borehole, the breakout front will propagate to these points. The updated opening shape is then remeshed until a stable shape without further material failure is reached. Numerical results demonstrate that the cross-sectional shapes of stable breakouts are obtained for a larger slope of the linear relation between the uniaxial compressive strength and the aspect ratio, but the slot-shaped breakouts are found to continue propagating for smaller slopes. A more complex size-dependent rock strength relationship appears to be in need to capture different stable breakout shapes.
Stress-induced breakout, referred to as the cross-section elongation of a circular hole in the direction perpendicular to the maximum principal stress, has been observed in a variety of rocks and stress conditions (Bell & Gough 1979, Dresen et al. 2010, Haimson 2007, Ewy et al. 1990b, Santarelli et al. 1992, Schmitt et al. 2012, Gay 1973, 1976, Guenot 1989, Martini et al. 1997). Depending on rock types, breakout failure micro-mechanisms can be very different, from dilatant microcracking to non-dilatant grain debonding and repacking (Haimson 2007). In brittle solids, breakouts of a tunnel and a borehole drilled can be produced by progressive spalling controlled by the development of a process zone adjacent to the walls of tunnels and boreholes drilled into a rock subject to remote stresses (Zheng et al. 1989). The mean breakout direction of the pointed dog ear shape, which is aligned along the minimum horizontal stress direction determined by hydraulic fracturing, and the breakout depth have been used in estimating regional maximum principal stresses (Zoback et al. 1985). Although many efforts have been made to explore the breakout extension, the understanding is still elusive for stable development of breakout configurations in the presence of very high compressive stress concentration.
Zhan, J. (University of Calgary) | Seetahal, S. (The University of Trinidad and Tobago) | Cao, J. (University of Calgary) | Hejazi, H. (University of Calgary) | Alexander, D. (The University of Trinidad and Tobago) | He, R. (University of Calgary) | Zhang, K. (University of Calgary) | Chen, Z. (University of Calgary)
The application of horizontal well drilling coupled with the multistage fracturing technology enables commercial development of shale gas formations. However, due to the complexity of fracture network propagation, simulation of such reservoirs is challenging and associated with uncertainties. In order to minimize the uncertainty of modeling, we correlate first-hand pumping schedule data with the reservoir performance directly through coupling a fracking process with a reservoir simulator. This provides us an integrated way to characterize a well trajectory, hydraulic fracture configurations and shale gas reservoir performance. In addition, a geomechanical effect on the reservoir performance under certain fracture configurations is studied using a geomechanics module developed by CMG Ltd.
GOHFER is widely used in a hydraulic fracking analysis. In this work, we couple GOHFER simulation output with the CMG module to determine the hydraulic fracture configuration. Thus, a method to correlate the first-hand pumping data (a slurry rate, slurry concentration and pumping pressure) with the reservoir simulator is given. Because of the stress sensitivity of a shale formation, we employ a linear-elastic constitutive law to depict the rock behavior with Young's modulus of 5,000,000 psi and Poisson's ratio of 0.2. Moreover, a Barton-Bandis model is used to describe the tensile opening of natural fractures for the dual-permeability reservoir model.
From a series of numerical simulation studies, we find that the effective normal stress will increase with the development of a shale gas reservoir which will lead to a decrease in porosity and permeability. For the base case without a geomechanics effect, it will produce higher cumulative gas production than the case with the geomechanics effect. When producing for six months, the difference of the cumulative gas production between the two cases is 14.3%. The integrated process provides insights about shale gas reservoir performance with available data and handy tools.
Zhan, J. (University of Calgary) | Seetahal, S. (The University of Trinidad and Tobago) | Alexander, D. (The University of Trinidad and Tobago) | Hejazi, H. (University of Calgary) | Paul Cao, J. (University of Calgary) | He, R. (University of Calgary) | Zhang, K. (University of Calgary) | Chen, Z. (University of Calgary)
The application of coupled horizontal wells and the multistage fracturing technology to shale formations makes it viable to develop such hydrocarbon resources. In this paper, we focus on the water saturation distribution within hydraulic fractures and the uncertainty of water saturation distribution of the matrix around the hydraulic fractures resulted from fluid injection during a fracking process.
Arp's decline curve is introduced to depict initial water saturation distribution within the hydraulic fractures. Through modifying the decline index, it is easy to obtain a range of initial water saturation decline patterns which will lead to different water production profiles. Typical decline patterns such as linear, exponential, harmonic, and hyperbolic declines are used. As for the initial water saturation distribution of the matrix around the hydraulic fractures, the Stimulated Reservoir Volume (SRV) concept is implemented to identify the matrix region.
Through reservoir simulations, we find that the initial water saturation within the hydraulic fractures mainly contributes to the early water production. Various saturation distribution models result in about 25% differences in the total water production. On the other hand, a leak-off effect, which increases the initial water saturation of the matrix around the hydraulic fractures, contributes to the long term water production. This study provides insights about the uncertainty of water production during the development of shale gas reservoirs and guidelines for the history matching of water production rates.
Shale gas reservoirs have a high total organic content (TOC) and are composed of a lot of microspores, which result in a high content of adsorbed gas. Laboratory and theoretical calculations show that the adsorption potential of CO2 in shale is higher than that of CH4. In other words, the shales prefer adsorbing CO2 to CH4. Therefore, during CO2 injection, the adsorbed CH4 is released by CO2 adsorption, even in a high reservoir pressure. Several models have been studied to describe the pure and multicomponent adsorption on shale. The Langmuir and extended Langmuir models are usually applied in reservoir simulators, because other models are more complex and not applicable to be coupled into a simulator. In this work, a simulation study is carried out to investigate the effects of gas adsorption on primary recovery and CO2 enhanced recovery processes.
Dual permeability, logarithmically spaced, locally refined grids are implemented to model natural and hydraulic fractures and to capture the sensitive changes of multicomponent adsorption. Reservoir pressure variation is coupled with a geomechanical module that updates porosity, permeability and fracture conductivity simultaneously at each time step. A multicomponent mixture on the basis of lab measured adsorption properties of the Eagle Ford shale are implemented into a reservoir simulator. Both primary recovery and CO2 huff-n-puff processes are investigated.
The simulation results show multicomponent adsorption behaviors of extended Langmuir model can slightly increase the well performance in the primary recovery. However, the adsorption behavior is more complex during CO2 injection processes. This study highlights the effect of multicomponent adsorption on gas production during CO2 cycling, and provides an optimal enhanced recovery strategy for shale gas reservoir.
With the production of a gas condensate tight reservoir, condensate in fracture can significantly decrease the productivity of gas condensate wells. Previous work shows that the negative effect of condensate bank on gas production is more seriously in tighter reservoir. The implement of hydraulic fracture and multi-stages fracturing can mitigate the negative effects on the formation of condensate bank, but the effects cannot be completely removed. A huff-n-puff methane injection has been proven to be an effective method to reduce the effect of condensate by maintaining the reservoir pressure above the dew-point pressure and revaporizing the formed condensate. However, the previous work neglects the effect of hydraulic fractures on the treatment of condensate by gas injection.
Non-aqueous components are lumped into fourteen pseudo components. Dual permeability, logarithmically spaced, locally refined grids are implemented to model natural and hydraulic fractures in a simulation model. The laboratory measured relative permeability taking account of condensate bank is used to accurately represent two-phase flow in a shale reservoir. Furthermore, two different settings of cyclic schedule are implemented to test their advantages and disadvantages.
The results show that the huff-n-puff dry gas injection can effectively improve gas and condensate recovery. A fracture conductivity has significant influences on well production during the injection, while during the primary recovery its impact is not that obvious. In addition, the huff-n-puff schedules also plays a crucial role in both gas and condensate recovery. Our study highlights gas injection mitigates the effect of condensate bank on gas production in a shale reservoir, and provides an extensive insight on optimal design of Huff-n-Puff gas injection.
Chen, Z. (China University of Petroleum-Beijing) | Liao, X. (China University of Petroleum-Beijing) | Zhao, X. (China University of Petroleum-Beijing) | Chen, C. (China University of Petroleum-Beijing) | Zhu, L. (China University of Petroleum-Beijing) | Zhang, F. (China University of Petroleum-Beijing) | Mu, L. (China University of Petroleum-Beijing) | Zhou, X. (China University of Petroleum-Beijing)
To meet with the energy strategy, some natural gas reservoirs in Ordos Basin are planned to use as gas storages. However, most of the gas reservoirs have high content of H2S. If they were operated without parameters optimization, it would put reservoir engineers as well as the environment at rick. Thus, optimization of injection and production parameters of these sour gas storages is urgently needed.
In the paper, using numerical method, the movement mechanism of H2S is studied. With the sensitivity analysis, the effects of some critical factors on H2S mole fraction in produced gas are investigated including ultimate recovery factor, injection rate, production rate, and injection-production rate ratio. Based on the results of the sensitivity analysis, optimal injection-production parameters are selected for a gas storage S24 in Ordos Basin.
The results show that the H2S mole fraction in produced gas decreases as the injection-production cycle number increases. When the cycle number reaches 5, the H2S mole fraction is relatively stable. Additionally, the H2S mole fraction in produced gas hinges heavily on ultimate recovery factor, injection rate, production rate, and the injection-production rate ratio. The decrease amplitude of H2S mole fraction increases as ultimate recovery factor, injection rate, and injection-production rate ratio increase; it decreases as the production rate increases. Numerical results show that after 4 cycles of the operation with the optimal parameters, the produced natural gas from S24 gas storage can reach the quality standard II of commercial natural gas, which is safe for humans and environment.
This study provides us with key technical references for operation of the sour gas storages to ease the contradiction between energy supply and demand.