Lin, B. (China University of Petroleum) | Chen, S. (Xinjiang Oilfield Corporation) | Jin, Y. (China University of Petroleum) | Chen, M. (China University of Petroleum) | Hou, B. (China University of Petroleum) | Lu, Y. (China University of Petroleum)
Steam assisted gravity drainage (SAGD) adopts a stimulation process through water injection to a pair of horizontal wells. Two deformation mechanisms named shear dilation and tensile parting occur in this process. The linear Drucker-Prager (DP) model had been used to model the injection of the marine-facies Alberta oil sand in Canada, whose structure consists of densely packed, interpenetrative sand grains. However, for the land-facies Karamay oil sand, the grains were loosely packed and isolated by a mixed matrix of bitumen, sand and clay. Triaxial tests confirmed that the sand exhibited substantial volumetric expansion upon hydrostatic unloading that demonstrated apparent plastic behavior. In consequence, the modified DP model with cap plasticity was selected as the constitutive framework, whose yielding surface takes into account not only shear dilation (plastic softening) but also hydrostatic expansion (inelastic strain softening). Numerical analysis was carried out on a finite element platform to evaluate and compare the capacities of the isotropic elasticity, linear DP and modified DP model with cap plasticity. Surprisingly, the analysis disclosed that all of the three constitutive models gave rise to exactly identical results in terms of cumulative injection volume, pore pressure distribution and Mises stress distribution.
Steam assisted gravity drainage (SAGD) has become the mainstream technology to develop the heavy and ultra-heavy oil sand reservoirs in Karamay city of Xinjiang province, northwest China. The stimulation before preheating the reservoirs in terms of water injection has been frequently adopted to save both time and cost spent in preheating. The stimulation involves controlled water injection to a SAGD wellpair such that a dilative zone is created in the inter-well domain. Here water injection instead of hydraulic fracturing is a more appropriate term due to the absence of stress shadow effects in weak rocks (Lin et al. 2015). Two mechanical mechanisms named shear dilation and tensile parting-induced dilation control this process. The former originates from the rollover motion of sand grains relative to each other upon shearing, while the latter is in fact a hydrostatic unloading of the oil sand matrix (Dusseault 1977, Dusseault and Morgenstern 1978, Agar and Morgenstern 1983, Oldakowski 1994, Samieh 1995, Yuan et al. 2011a&b, Lin et al. 2015). Both mechanisms result in a generation of flow channels in terms of microcracks and expanded pore space at regions in close proximity to the wellbores (Yuan et al. 2011b). The injection process and mechanisms are depicted in Fig.1.
There is considerable research interest in the sorption/transport properties of shales to assist in the evaluation of shales as reservoirs for natural gas and oil. These properties can also be used to evaluate the potential of shales for storage of greenhouse gases (e.g. CO2) or enhanced recovery. However, shales have proven difficult to characterize, in part because of the challenges of obtaining viable reservoir samples from multi-fractured horizontal wells used to produce from them. Often the only reservoir samples available from horizontal wells are drill cuttings – the sample sizes obtained from cuttings are typically too small for quantitative analysis using conventional techniques. Therefore, new, high-precision methods are required to analyze the smaller cuttings sets. Further, the physics of gas storage and transport through the multi-model pore structure of shale is complex, requiring rigorous modeling approaches to extract parameters of interest such as permeability/diffusivity.
In this work, the use of a high-precision, low-pressure adsorption device is explored for extracting permeability/diffusivity parameters from small amounts (2 g) of synthetic (crushed core sample) drill cuttings of Duvernay shale. In order to extract the transport parameters, gas flow through the complex, heterogeneous matrix pore structure of the shale has been approximated using a general dual porosity numerical model which assumes that (1) gas flows through macropores by continuum viscous flow (2) gas flows through meso and micropores by Knudsen diffusion and molecular slippage on pore walls and (3) adsorption occurs in meso and micropores. The model can be simplified into two sub-models; macro/micropore system and meso/micropore system, depending on the measured pore size distribution of the samples of interest.
The new multi-pore (bidisperse) numerical model is applied to carbon dioxide low-pressure adsorption rate data obtained from the crushed Duvernay shale core samples, and apparent permeability for each gas/sample group is calculated at different pressure steps. The low-pressure adsorption device yields pressure-time data that is of much better quality than a commercial crushed rock permeability device that requires larger sample sizes. The new bidisperse pore structure numerical model, which allows permeability to vary (at each pressure step) due to gas slippage effects, properly describes the entire adsorption rate history of the samples studied. Mesopore apparent permeabilities range from 1E-2–1E-3 mD and micropore apparent diffusivities are in the 1E-7 mD range. The calculated apparent diffusivities obtained from modeling adsorption rate data change with pressure.
The results of this study have important implications for shale matrix transport characterization. The resulting data can be used for making completions decisions and in reservoir models which capture reservoir property changes along a horizontal lateral.
Zhang, K. (University of Calgary) | Li, Y. (EOR Center of China University of Petroleum) | Hong, A. (University of Stavanger) | Wu, K. (University of Calgary) | Jing, G. (University of Calgary) | Torsæter, O. (Norwegian University of Science and Technology) | Chen, S. (University of Calgary) | Chen, Z. (University of Calgary)
Over past decades, technology innovation in exploiting unconventional resources has become increasingly important. Associated with technologies applied in shale gas development, exploiting tight oil resources comes into a new stage. Primary recovery in tight oil reservoirs remains low even produced with massively hydraulically fractured horizontal wells.
Waterflooding is applicable over a wide range of reservoir conditions but its recovery is not high enough. In addition, gas flooding suffers from channeling problems with existence of highly permeable channels. A water alternating gas (WAG) process seems a good method to recovery tight oil.
Recent breakthrough in nanotechnology provides a promising technique in the oil and gas industry. Nanoparticles have a very high surface-volume ratio, easily moving into tight formation without external forces. Nanoparticles additive does not raise weight of an injection fluid, associated with wettability alteration and interfacial tension reduction, and can be an excellent solution in improving recovery in tight oil reservoirs.
This paper demonstrates the merits of nanofluids; concentration of 0.05wt% nanofluid gives the best performance in a core flooding test. Simulations of nanoparticles additive in a WAG process are run by Eclipse and CMG in various cases. As the degree of wettability alteration and permeability reduction highly depends on concentration of nanoparticles underground, a tracer is applied in the simulations to confirm the locations of nanoparticels underground and its concentration, and it shows that nanoparticles mainly stay around injection wells and high permeable zones. Simulation results show that a nanofluid alternating gas (NAG) process has a great potential in improving WAG performance, and it performs better with existence of natural fractures.
Zhang, K. (University of Calgary) | Qin, T. (University of Calgary) | Wu, K. (University of Calgary) | Jing, G. (University of Calgary) | Han, J. (University of Calgary) | Hong, A. (University of Stavanger) | Zhang, J. (China Univeristy of Petroleum) | Chen, S. (University of Calgary) | Chen, Z. (University of Calgary)
As a result of poor fluid delivery in tight oil reservoirs, oil production drops rapidly at early stages of depletion development. While water flooding only boosts production to a limited extent, CO2 miscible flooding seems a promising technique in improving tight oil recovery. Generally, CO2 flooding is performed only after water flooding gives better results than natural depletion. Since cumulative CO2 injection versus oil production goes up as formation permeability goes down, it is crucial to select suitable reservoir candidates to conduct CO2 flooding to be economically successful. There are several methods of ranking candidate reservoirs for the CO2 enahnced oil recovery (EOR) process based on criteria on reservoir parameters. Nevertheless, few of them take account of an oil recovery increment and risk analysis. In this paper, an integrated method for CO2 flooding reservoir screening criteria is presented, considering asphaltene precipitation and an oil recovery factor increment. This method is based on the least squares method, reservoir simulation, and fuzzy analytical hierarchy process, associated with equation of state (EOS) compositional calculations and compositional modelling. It is applicable in high diversity and can be used as guidance to screen tight oil reservoirs for CO2 flooding.
Zhang, K. (University of Calgary) | Wang, M. (University of Calgary) | Liu, Q. (University of Calgary) | Wu, K. (University of Calgary) | Yu, L. (China University of Petroleum) | Zhang, J. (China University of Petroleum) | Chen, S. (University of Calgary)
Shale gas becomes an important natural gas supplier in recent years. The technologies including horizontal wells and hydraulic fracturing drive the booming of shale gas industry. Gas in shale reservoirs is stored as free gas in both mineral pores and natural fractures, as well as absorbed gas on pores surface. The effect of gas adsorption is generally ignored in conventional reservoirs. However, the absorbed gas has to be taken into consideration for shale gas production because of its huge amount in nanoscale porous media. The smaller the pore throat radius, the more significant is the effect of confinement. Therefore, production behavior can be altered by the effects of adsorption and confinement in shale gas reservoirs. On the basis of Montney shale gas reservoir modeling, effects of adsorption and confinement on shale gas production behavior are investigated in this paper. Results show that total gas production increases with the consideration of adsorption and confinement effects. As gas density and viscosity decreases prior to condensation occur with the effect of confinement caused by nanoscale pore throat, incremental of density difference between free gas and absorbed gas will delay the production of absorbed gas. Moreover, the difference between the amount of free gas produced and absorbed gas produced become larger with the effect of confinement during reservoir depletion.
Multistage hydraulic fracturing technique now applied with horizontal wells and over large areas has enabled commercial production of oil and gas from low-permeability rock formations, changing the energy landscape in North America. In these reservoirs, tons of fracturing fluid and proppants are pumped into the reservoir matrix to create hydraulic fractures and it is important to understand the propagation mechanism of hydraulic fractures and further optimize their properties. In addition, natural fractures are often present in the shale and tight formations, which might be activated during the fracturing process and contribute to the after-stimulation well production rates.
In this paper, reservoir simulation is coupled with rock mechanics to predict the well after-stimulation production performance. Firstly, a dual-permeability geological model is built based on field data collected from a well pad in Montney formation, Canada. Fracturing fluid flow in the formation coupled rock mechanics is employed to simulate dynamic hydraulic fracturing process. More specifically, as the continuous injection of fracturing flurry, the effective stress will decrease accordingly. When the effective stress reaches the rock failure criteria, hydraulic fractures will be generated, allowing the fracturing liquid to flow along the fractures. Based on the fracturing operational schedule, dynamic hydraulic fracturing simulation is conducted and results show that hydraulic fractures tend to propagate upward first until it connects the entire formation in the vertical direction. Early production history of the stimulated well is then matched to valid the simulated fracture geometries. Finally, the effects of natural fractures and well bottom-hole pressure on well production are studied. Results show that if natural fracture can be propped or partially propped by the proppants, the production will be increased significantly for shale liquid rich gas plays. This paper provides a significant insights on the fracture propagation and can be a reference for fracturing treatments in unconventional shale reservoirs.
Pang, H. (China University of Petroleum Beijing) | Lin, B. (China University of Petroleum Beijing) | Chen, M. (China University of Petroleum Beijing) | Jin, Y. (China University of Petroleum Beijing) | Chen, S. (Xinjiang Oilfield Corporation, PetroChina) | You, H. (Xinjiang Oilfield Corporation, PetroChina)
Successful application of steam assisted gravity drainage (SAGD) on the recovery of land facies ultra-heavy oil in Xinjiang oilfield depends largely on shortening the preheating period with the aid of the micro-fracturing technology, which is conducted through controlled water injection to a pair of horizontal wells to create homogenously distributed microcracks in the zone between the two wells. The numerical simulation of this mechanical process is yet to be investigated. Up to date, there has been research work on rock mechanics during the SAGD production period of marine deposited ultra-heavy oilsands, but the counterpart research on land facies ultra-heavy oilsands of Xinjiang oilfield is left undone. In this regard, this study is attempted to perform numerical simulation of the fracturing process on land facies unconsolidated oilsands. With this objective, the study first investigates geological and physical identification of the field collected cores, then carries out mechanical analysis on laboratory triaixal test results, based on which numerical simulation of the fractured zone is performed. The simulation is applied through a finite element platform adopting extended Drucker-Prager constitutive model, with the parameters determined by experimental work. It is verified that hydraulic fracturing of unconsolidated oilsands generates a microcrack feature in terms of a dilative zone instead of linear apertures. The extent to which the fractured zone propagates is visually demonstrated based on the magnitude distribution of equivalent plastic strain or volumetric dilation. Evaluation of the connection of injection and production wells can possibly be determined by the expansion of the saturated region around each well. Finally, the implications on the efficiency of hydraulic fracturing in stimulation of the pay zone are investigated.
Ultra-heavy oilsands resources have been discovered and explored in several countries like Canada, Venezuela and China. To recover this type of oil endowed with extremely high viscosity (over 100, 000 mPa·s at a temperature of 50°C) reservoir stimulation in terms of steam injection is needed to raise pressure and temperature so that the oil can turn to flowing fluid state. A robust and efficient thermal process (or technique) named steam assisted gravity drainage (SAGD) has been applied in large scale in Alberta, Canada and Xinjiang, China, in the recovery of ultra-heavy oilsands. The concept and implementation of SAGD were first conceived by Butler and Stephens (1981) and later developed by their colleagues (e.g., Chalaturnyk 1997, Edmunds 1999&2000, Nasr and Issacs 2001, etc.), which in general involves introducing steam into reservoir and producing heated oil through two horizontal wells (Albahlani et al. 2008). The SAGD process composes two stages–preheating and production, with the former aimed at transferring heat from condensated steam to the surrounding of the wellbores, and therefore generating a thermal zone where the oil is able to be drained by gravity drive and produced in the latter stage.
The complex fracture network or stimulated reservoir volume (SRV) can be induced by hydraulic fracturing of the unconventional reservoirs. The SRV dimension is one of the main drivers in a horizontal well performance after the hydraulic fracturing operation. It is of great importance to simulate the SRV dimensions to identify the optimum hydraulic fracturing treatment parameters. In this research, a new analytical model is proposed to accurately simulate the SRV dimension created from hydraulically fractured horizontal wells in unconventional reservoirs. More specifically, a SRV dimensional model is developed to simulate SRV dimensions using effective stresses, injected slurry volume and other reservoir and pumping data during the generation of the hydraulic fracture network. The SRV dimensional model is calibrated using microseismic data from 6 stages of a hydraulic fracturing job in a horizontal well penetrating the Glauconite formation in Hoadley field, Alberta, Canada. The calibrated SRV dimensional model can serve as an optimal fracture spacing estimator for future hydraulic fracture job designs. The average simulated SRV width is smaller than the average fracture port spacing and therefore for this study it is suggested to have the fracture port spacing tighter and equal with the simulated SRV width for optimum production.
At present, multistage hydraulic fracturing of horizontal wells has become a widely used technology in stimulating tight oil reservoirs. However, the treatment of hydraulic fractures in numerical simulation of multi-fractured horizontal wells in tight oil is excessively ideal. Effects of some fracture properties on numerical simulation of tight oil are usually not taken into consideration. Actually, fracture geometry in the reservoir is complex and fracture permeability is not a constant value. Numerical model without these factors may lead to a significant error in forecasting the reservoir response. In this paper, to make the result more reasonable and credible, based on an actual block of Imperial Oil Ltd in Cardium pool that is a tight oil reservoir of Pembina field, AB, Canada, geo-model is constructed at first with accurate description of the reservoir according to geology, physical properties and so on. In numerical reservoir model, in terms of micro-seismic data and relationship between fracture permeability and effective stress from experiment data, dynamic fracture permeability and fracture geometry are taken in considerations. And the history-matched reservoir model is then used to understand the development of multi-fractured horizontal wells in tight oil. Using field reference data and history-matched reservoir model, different scenarios including waterflooding and depleting development have been simulated. We also simulate similar scenarios without these factors. Results indicate that the effect of geometry and property of hydraulic fractures may be significant and cannot be neglected. The results in the model including these factors are different significantly from that without these factors. Especially, the difference is more evident in waterflooding development. And the results in the model with fracture geometry and dynamic fracture permeability are more suitable to the actual production of multi-fractured horizontal wells. The results proposed in this paper can act as a reference to optimize development of tight oil.
Organic-rich shale gas reservoirs have various complexities related to the physics of gas storage and transport. Traditionally, the OGIP in shales is calculated by the sum of the adsorbed-gas and the free-gas, as an analog of the CBM reservoirs. However, as noted by a few authors, the free-gas volume must be corrected for presence of adsorbed-gas, assuming all gas storage occurs in kerogen. Even with such correction, shales are still complex reservoirs in terms of flow characteristics. The contribution of viscous, diffusive, and slip forces in nano-scale conduits cause the permeability to be higher than its value expected by Darcy’s law.
A new model is developed to address the effect of the adsorbed-gas volume on the micropore storage capacity. The relative fraction of adsorbed-gas volume is treated as sorbed-phase saturation. The initial free-gas volume is then calculated by subtracting any non-free-gas saturation from the effective void volume. We have extended this concept to a gas material balance equation through which the free-gas volume is dynamically adjusted during depletion. The SLD adsorption model is used to evaluate sorbed-phase density and volume. To address the complexity in gas flow, permeability of the reservoir model is a function of pressure to determine the impact of advection, slippage and diffusion mechanisms. The permeability is calculated via a multi-mechanism flow model. Finally, we utilized the dynamically-corrected permeability in parallel with dynamically-corrected porosity to simulate the primary recovery of a shale gas reservoir.
The new models successfully describe the unique characteristics of shale reservoirs and correct the conventional methods for overestimation of reserves and underestimation of permeability. The format of the final material balance equation and the flow model used here keep the conventional reservoir engineering framework, which are familiar to the
engineers, but with some modifications.