Fedutenko, Eugene (Computer Modelling Group Ltd.) | Nghiem, Long (Computer Modelling Group Ltd.) | Yang, Chaodong (Computer Modelling Group Ltd.) | Chen, Tong (Computer Modelling Group Ltd.) | Seifi, Mojtaba (Computer Modelling Group Ltd.)
The incorporation of geomechanical effects into the flow simulation is crucial for accurate modeling of unconventional hydraulic fracture systems. Such an incorporation requires a proper construction of stress and pressure dependent permeability/porosity distribution for the whole reservoir domain. Usually this is accomplished by the generation of the correspondent multipliers for porosity and permeability under the assumption of exponential and power law correlations. This task can become complicated for sandstones that display non-linear and inelastic behavior such as hysteresis when subjected to cyclic loading, as it involves many parameters including different moduli for loading and unloading introduced as best fit for experimental values.
We propose a novel Machine Learning approach to this problem based on Multi-Layer Neural Network (MLNN) Modeling of hysteresis nonlinearity caused by Elastic, Dilation, and Compaction compressibility term. MLNN considers the experimentally obtained pressure dependency of permeability and/or porosity for Elastic, Dilation and Maximum Compaction as its training data. After the Network is trained it is used to predict the multiplier curve for any intermediate (i.e. low, middle, and high) compactions. This is accomplished by MLNN hysteresis function which considers the curve forecast as a pattern identification problem. Such an approach is often used for modeling of hysteresis in piezo-actuators and magnetic systems, however it has never been applied to geomechanical modeling before. This paper modifies the classical MLNN in the way that it exactly matches the training data, i.e. honors the boundary conditions for dilation-compaction hysteresis. A history match of a couple of field examples indicate that the proposed model provides a good match with production data.
Liang, Guangyue (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Shangqi (Research Institute of Petroleum Exploration and Development, CNPC) | Liu, Yang (Research Institute of Petroleum Exploration and Development, CNPC) | Zhou, Jiuning (Research Institute of Petroleum Exploration and Development, CNPC) | Han, Bin (Research Institute of Petroleum Exploration and Development, CNPC) | Bao, Yu (Research Institute of Petroleum Exploration and Development, CNPC) | Huang, Jixin (Research Institute of Petroleum Exploration and Development, CNPC)
The preheating start-up is indispensable before converting to super heavy oil and oil sands SAGD process. It is mainly achieved through steam circulation or stimulation. Either way, the preheating time and steam consumption are usually over 5 months and 30,000 tons, respectively, especially for well pairs in reservoir with bottom transition zone or widely distributed mudstone. Thus, a modified technology about dilation by polymer injection was proposed and demonstrated to improve oil sands SAGD performance.
Based on the data of mini-fracture test, tri-axial test and core test of polymer displacement, the feasibility study of dilation by polymer injection technology to improve SAGD process was conducted. On the basis, the pilot test and follow-up steam circulation process were well-designed and history matched by coupled geomechanical and thermal simulations, considering the mechanisms of polymer adsorption, degradation reaction, shear thinning and residual resistance, etc. Specially, the key to success of dilation by polymer injection technology was also analyzed.
The feasibility study indicates that the vertical dilated zone easily creates and fast start-up process can be achieved under high injection pressure. While the reservoir is first dilated to form a high-porosity and high-permeability conduit connecting the SAGD well pair, the polymer solution is then injected into these newly created pore spaces, yielding a greater range of dilated zone which is more uniform along the horizontal section. The history matching results demonstrate that inter-well porosity and permeability significantly enhance. Compared with adjacent well pairs, thermal and hydraulic connectivity obviously improve, both steam consumption and circulation time reduce nearly by half. Besides, the first year oil rate improves in follow-up SAGD process.
The field experience and findings can help to improve the SAGD performance and economy of super heavy oil and oil sands projects, especially for heterogeneous reservoir with bottom transition zone or widely distributed mudstone.
Refracturing is often required in shale and tight gas formations because of inadequate initial HF design or unexpectedly rapid production decline. Water blocking because of fracturing liquid incompatibility, unexpected proppant embedment and crushing, shorter or curved primary fracture length because of premature screen off, general pressure depletion, primary fracture mis-orientation from stress shadowing, unfavourable poroelastic effects limiting the performance of the stimulated volume, and, in general, formation permeability reduction from stress sensitivity may all contribute to unsatisfactory or rapidly declining production. We emphasize the role of geomechanics in candidate screening and review the major factors leading to production decline in unconventional reservoirs. Although the fracture geometry may be altered in a staged fracturing process, the primary focus should be given to the formation permeability enhancement either due to shear dilation or induced fractured network elongation.
A general formulation for a coupled Thermal-Hydraulic-Mechanical with hydrate Dissociation (THMD) system is developed and applied to sand prediction for conventional gas and gas hydrate bearing sediments (GHBS). Two-phase fluid and conductive heat flow are coupled to an elastoplastic geomechanics model. Series of solutions for simplified models are presented. Fundamental geomechanics behaviors before and after plastic yielding, sanding, and gas hydrate dissociation are defined, discussed, and simulated differently and sanding onset for both conventional gas formations and GHBS are defined by an effective plastic strain (EPS) criterion. The accuracy and reliability of the proposed conventional model are verified by comparing the model prediction with the results of hollow cylinder tests on two different types of sandstone. The advantages of using the EPS over stress-based criteria as an indicator for onset of borehole collapse and sand production are discussed. Introducing a moving gas hydrate dissociation zone (front), the fundamental geomechanics behaviour and elastoplastic deformation of the skeleton formation are highlighted. The effects on sand prediction due to the characteristics of nonlinear plastic yielding criteria and gas flow in porous media are also emphasized.
Safety aspects of SAGD/CSS on cap rock integrity, the various geomechanics field data types, data gathering & analysis methods, surface heave, thermally induced stresses, failure criteria, dilation, etc. are some of the topics that will be covered. Numerical examples using Alberta specific data will be provided where applicable. Geomechanics Fundamentals Principles of equilibrium as they apply to oil sands and overlying formations What is ‘effective stress’ and why it is an important concept What is a fault and what is a tensile fracture Fracturing Fundamentals for oil sands What controls the orientation of a fracture What controls vertical growth of fractures Dilation and Heave Why do we induce dilation and heave with thermal operations How do we model dilation in the simulator and what impact does it have. How can steaming strategies be modified to manage caprock and casing integrity How do dilation effects impact fracture orientation Caprock Integrity Why is caprock integrity a concern for regulators and operators? What is required for a typical caprock integrity assessment?
In thermal heavy-oil production, steam is injected to reduce oil viscosity and promote the less viscous oil flowing to the production wells. Steam injectivity and its conformance in the reservoir greatly impacts oil production and project economics. It is found that hydraulic dilation stimulation of heavy-oil reservoirs before steam injection can create a large and targeted stimulated reservoir volume for the steam to contact the heavy-oil phase. As a result, steam injectivity increases and steam conformance improves. These eventually translate to increased oil production and reduced steam/oil ratio, which has been proven in hundreds of wells worldwide. This paper describes relevant fundamental mechanisms and field performance.
As a major novelty, the hydraulic stimulation avoids fracturing the reservoir, but seeks to cause dilation. If the reservoir is fractured, a linear conduit is created. Steam can easily break through to neighbouring wells and the steam conformance is poor. When dilation takes place, however, additional pore space is created in the rock matrix. This results in truly volumetric stimulation, which is helpful to increase the steam injectivity while ideal thermal conformance is also achieved. This paper illustrates these theoretical bases and their resultant positive field performance in assisting thermal heavy-oil production.
To consider the roughness effect on shear strength and deformation of rock joint, this research proposed a joint model for the discrete element method. The background theory of the proposed model is based on Barton’s shear strength criterion which is widely used to describe non-cohesive joint with roughness. To implement Barton’s criterion in DEM software, three calculation modifications were performed, including exceeded force recapture, contact area equalization, and stiffness adjustment. Through the modifications, the force of each joint contact could be calculated, which reasonably reflect the joint mechanical behavior under different normal stress. Afterward, the proposed model was verified by comparing to the theoretical model. The results indicated that the proposed model rationally describes the shear stiffness influenced by mobilized joint roughness coefficient during the shear process. The comparisons showed that the proposed model is versatile in simulating the shear displacement with loading-unloading-reloading cycles, normal closure, and shear dilation of joint.
The strength and deformability of rock mass are heavily influenced by the properties of joints. The joint exhibits highly non-linear behavior under applied stress and is influenced by surface roughness. To describe the joint behavior, Barton proposed a non-linear model for rock joint (Barton, 1973). It not only provided the description of the failure envelope but also considered the evaluation of shear-displacement and dilation relationships. Therefore, it is widely used in the analysis of rock mechanics.
On the other hand, the discrete element method (DEM) has been widely adopted to explore the behavior of rock mass and successfully applied to rock engineering. Lots of models were developed to simulate joint behavior in DEM, including the bond-eliminate method, the smooth-joint method, and so on (Chiu et al., 2013). However, these methods can not reflect the phenomenon in experiments, such as shear-displacement curve and nonlinear failure envelope. To overcome this problem, this study proposed a rock joint model “rough-joint model”. The theory of the proposed model is based on Barton’s model. To implement Barton’s criterion in DEM software, three calculation modifications were needed. After finishing the construction of the joint model, the direct shear test with reverse shearing has been simulated to show the performance. The failure envelope, shear-displacement curve, closure curve and dilation curve fit Barton’s model very well. The above results show that rough-joint model can provide a way to simulated joint behavior with roughness in DEM, which is helpful for researchers to perform numerical analysis for the joint sliding problem.
Several direct shear tests were commissioned by the author to research the shear strength of bedding partings in fresh shale materials of the Pilbara basin in Western Australia. These samples were selected from one rock unit, i.e. McRae Shale Formation, which is characterized by having an intact strength within the range 20-80 MPa. Only samples of clean natural partings were prepared at the laboratory and then tested by single-stage and multi-stage procedures using a servo-controlled shear box, to ensure the application of constant normal stress throughout each test. This paper presents the comparison between the observed laboratory dilation and the predicted dilation of the Barton-Bandis empirical model. The findings show that the Barton-Bandis model tends to predict a larger dilation than observed. The magnitude of the dilation angle is slightly higher in single-stage than in multi-stage test procedures, and in consequence the dilation corrected friction angle for single stage is normally lower than that determined from multi-stage tests. This means that the Barton-Bandis consistently overestimated the shear strength of the bedding when applying the laboratory determined JRC, JCS and Øb. These findings are part of the author’s research work at the University of Western Australia (UWA).
The Pilbara basin is located in the State of Western Australia, and it is well-known for the occurrence of the enriched Banded Iron Ore Formations (BIF) and form the host rocks within which a large number of open pit iron ore mines have been established. The geology includes a stratigraphical column known as the Hamersley group, with rock units of Archean and Proterozoic age, typically divided by geologists into the Brockman and Marra Mamba Formations (Fig. 1.). The Hamersley rock formations of the Pilbara have generally been well studied due to their significance within the Western Australian iron ore industry. These rock masses are characterized by pervasive bedding which have formed from Archean sedimentary formation processes. These anisotropic rock masses typically include inter-bedded shale, sandstones and banded iron formations.
These shale units of the Hamersley group are highly anisotropic with respect to shear strength and therefore the slope stability of most of the mining excavations developed within these formations is controlled by the relatively low bedding shear strength of the shale groups and shale bands, which are the weakest rock types. Shale formations range from fresh to highly weathered and are generally highly fissile when fresh and clayey when weathered. An accurate understanding of the shear strength of these materials is therefore of key importance for assessing the slope stability of these mines.
Coupled THM Modeling of Hydroshearing Stimulation in Tight Fractured Volcanic Rock.
Bao, Yu (Research Institute of Petroleum Exploration & Development, CNPC) | He, Liangchen (Liaohe Oilfield Company Ltd, Petrochina) | Lv, Xue (Sino-Pipeline International Company Ltd.) | Shen, Yang (Research Institute of Petroleum Exploration & Development, CNPC) | Li, Xingmin (Research Institute of Petroleum Exploration & Development, CNPC) | Liu, Zhangcong (Research Institute of Petroleum Exploration & Development, CNPC) | Yang, Zhaopeng (Research Institute of Petroleum Exploration & Development, CNPC)
The Orinoco heavy oil belt in Venezuela is one of the largest extra-heavy oil resources in the world. It has become a major goal for the unconventional oil exploitation in these years. Now, the most common production method is to use the horizontal well cold production without sand. It is an economic and commercial process, and with the reservoir of this area have high initial gas to oil ratio (GOR), porosity and permeability with unconsolidated sand. However, after several years' production, the oil rate draws down quickly caused by the reservoir pressure drops; the key challenge of cold production is that the recovery factor (RF) tends to be only between 8% and 12%, implying that the majority of the oil remains in the oil formation. It is necessary to develop viable recovery processes as a follow-up process for cold production. Generally, steam based recovery method was widely used as a follow-up process for cold production. In this paper, steam fracturing (dilation) Cyclic Steam Stimulation (CSS) operation and Non steam fracturing (No dilation) CSS operation by using reservoir simulator is examined for a post cold production in extra heavy oil reservoir, in order to analyze the performance of the oil rate, cumulative steam-to-oil ratio (cSOR), steam depletion zone, greenhouse gas emission and some necessary parameters.
The key component of the steam fracturing (dilation) is the ability to inject high temperature and pressure steam into the formation to fracture the reservoir rock which in turn raises the rock permeability and mobilized the oil by lowering the visocisity. To compare the results of the dilation and no dilation CSS operation, this study reveal that due to the steam is injected into the reservoir by using the same cumulative cold water equivalent (CWE), the steam condensate; pressurized by steam vapour, fracture the formation. Dilation operation achieves higher oil rate, lower cSOR. The result also show that fraturing (dilation) of the reservoir during steam injection relieves the pressure which in turn lowers the steam injection pressure below the case where No dilation operation ouccurs.