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Our services and products allow engineers to optimize the economic value of the field operations by maximizing their production, keeping their sand production to an acceptable minimum during cold production without severely compromising oil output. For horizontal wells, our product optimizes a perforation and completion design by considering perforation orientation and temperature change. For sand control, the package allows the engineer to forecast the maximum production or drawdown of the sand before actual massive sand production is initiated. Our products also allow engineers in evaluating the production in wells after sand production, and our unique numerical tool (based on a coupled reservoir-geomechanics erosion model) can effectively simulate the entire process of cold production so that the operating costs can be reduced substantially. Our completion software can be used to evaluate the profitability and suitability of various completion strategies, including the state-of-Art Cavity-like completion strategy.
Research interests 1) Sand control, management, and optimized production: current focus is on how deviated fracturing or perforation hole affect gravel, sand transport, and production. In-situ stresses determinations near a fault region: Developing an finite element algorithm for far-field stresses based on the in-situ stresses extracted from wells. Wellbore stability and hydraulic fracturing propagation in wells near a fault region: in-situ stresses differ in different locations of a faulting region. The wellbore failure risks, collapsing, and fracturing pressures must be determined based of the locations of the planned wells against fault center.Sanding prediction in Gas-Hydrate-bearing sediment: A constant wellbore temperature depressurization process is proposed for onset of sand production prediction. A fully coupled THMH model is developed and the hydrate decomposition zone and induced stresses near a wellbore are calculated. Both production and induced sand risk are analyzed. 2) Petrov-Galerkin finite element simulation of reduction change in Stress-sensitive formations: permeability change in the fractured media is dominating the permeability along the natural fractures. A dual-porosity model is applied to a field where productions decline are observed six months after production. A critical pressure is identified after this pressure no production increased may be expected by a drawdown increase. 3) Breakdown pressure determinations in staged fracturing horizontal well in shale gas formations: oriented perforation may pose different fracturing pressure due to the induced stress changes near a perforation hole. The induced stresses near a wellbore is superposed with those due to an oriented perforated hole. A critical fracturing pressure based the fracturing pressure from a perforated hole oriented from a location where the least induced compressive stresses can be found. A realistic fracturing pressure can be calculated by proposed model. 4) Injection strategy for EGS in HDR: a coupled system between low-permeability formation and wellbore is developed. Both hydraulic and thermal conservation equations along the wellbore and between the formation are established. Heat extraction and temperature change from the HDR formation to the surface can be calculated and an optimized strategy may be obtained. 5) As one of the evaluation factor, salt cavern volume is used as one key information for gas (hydrogen) storage. Depending on the depth, thermal gradient and the maximum injection and mininum production pressures, the real storge volume in a salt cavern may not reach their maximum capacity due to the limits on these pressure which are controlling the wellbore integrity and possible leakage through overburden confining layer. In addition, the gas density and other flow properties may vary significantly before and after the supercritical condition, and these properties change subject to different pressure and thermal gradients will alter the critical wellbore pressure and temperature. Another important issue is that the deformation or cavern caving in may show different time-dependent characteristics subject to these thermal and hydraulic characteristics due to salt creeping. All these factors must be considered for the economic cycle and evaluation. Thus one must address these questions before the feasibility of gas storage in salt cavern can be assured. Specifically a) we define the hydrogen TH characteristics under different pressure and temperatures； b) salt creeping under different temperature and stresses; c） critical wellbore pressures for wellbore integrity in different depths; d) fracturing and failure criteria under different temperatures; e) critical injection and production rates before possible failure; f) develop software for these aforementioned problems. The project requires input from the thermodynamics side (compression and de-compression of gas) as well as the geomechanics side. The maximum pressure of storage in salt caverns depends on the local stress state, and authorities generally state that the maximum pressure should not be more than 75 or 80 or 85% of the overburden stress, or perhaps 85 or 90% of minimun stress. The minimum pressure is strongly dependent on the depth l have to be maintained high because if it is too low, the high deviatoric stress will result in rapid creep and loss of storage capacity (Eminence Dome in the USA experienced 10-15% volume loss per year about 40 years ago). For a hot cavern 1500 m deep, p_max might be 30 MPa, but p_min might have to be as high as 25 MPa, allowing cycling only between these pressures. On the other hand, a cavern only 700 m deep with a low ground T, as in Ontario where we know that the horizontal stresses in the overburden are greater than the vertical stress and the rock mass is dense, the p_max might be 15 MPa and the p_min 4-5 MPa. 6）The current active project in the next five years is THM formulations and coupling for Evaluations and Analysis of Wellbore and Caprock Integrity during CO2/CH4/H2 Injection and production in naturally fractured reservoirs.and ground T because of creep. If the T is high and the cavern is deep, then the storage pressure wil
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