Pore Pressure
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Pengda Cheng ◽  
Weijun Shen ◽  
Qingyan Xu ◽  
Xiaobing Lu ◽  
Chao Qian ◽  

AbstractUnderstanding the changes of the near-wellbore pore pressure associated with the reservoir depletion is greatly significant for the development of ultra-deep natural gas reservoirs. However, there is still a great challenge for the fluid flow and geomechanics in the reservoir depletion. In this study, a fully coupled model was developed to simulate the near-wellbore and reservoir physics caused by pore pressure in ultra-deep natural gas reservoirs. The stress-dependent porosity and permeability models as well as geomechanics deformation induced by pore pressure were considered in this model, and the COMSOL Multiphysics was used to implement and solve the problem. The numerical model was validated by the reservoir depletion from Dabei gas field in China, and the effects of reservoir properties and production parameters on gas production, near-wellbore pore pressure and permeability evolution were discussed. The results show that the gas production rate increases nonlinearly with the increase in porosity, permeability and Young’s modulus. The lower reservoir porosity will result in the greater near-wellbore pore pressure and the larger rock deformation. The permeability changes have little effect on geomechanics deformation while it affects greatly the gas production rate in the reservoir depletion. With the increase in the gas production rate, the near-wellbore pore pressure and permeability decrease rapidly and tend to balance with time. The reservoir rocks with higher deformation capacity will cause the greater near-wellbore pore pressure.

Nathan Lee Young ◽  
Jean-Michel Lemieux ◽  
Laura Mony ◽  
Alexandra Germain ◽  
Pascal Locat ◽  

Vibrating wire piezometers provide a number of advantages over the traditional hydraulic piezometer design. There are currently many methods and configurations for installing vibrating-wire piezometers, the most common being: single piezometers in sand packs (SP), multilevel piezometers in sand packs (MLSP), and fully-grouted multilevel piezometers using either bentonite (FGB) or cement-bentonite grout (FGCB). This study assesses the performance of these four different installation methods at a field site possessing complex stratigraphy, including glacial and marine sediments. To accomplish this objective, pore pressure data recorded between December 2017 and July 2019 were analyzed. Data indicate that SP, MLSP, and FGB piezometers performed most reliably, based on the fact that piezometers installed at the same depth with these methods recorded similar pressure variations that were coherent with the hydrogeological setting. Of the two fully-grouted installations using cement-bentonite grout, one installation failed completely due to a hydraulic short circuit, likely caused by preferential flow occurring along the wires of the embedded instruments. The lack of a standard method for mixing cement-bentonite grout at the time of construction likely contributed to the failure of the FGCB installations, as the grout mixture used in this study was likely too viscous to provide a suitable seal.

2022 ◽  
Ruqaiya Al Zadjali ◽  
Sandeep Mahaja ◽  
Mathieu M. Molenaar

Abstract Hydraulic Fracturing (HF) is widely used in PDO in low permeability tight gas formations to enhance production. The application of HF has been expanded to the Oil South as conventional practice in enhancing the recovery and production at lower cost. HF stimulation is used in a number of prospects in the south Oman, targeting sandstone formations such as Gharif, Al Khlata, Karim and Khaleel, most of which have undergone depletion. Fracture dimension are influenced by a combination of operational, well design and subsurface parameters such as injected fluid properties, injection rate, well inclination and azimuth, rock mechanical properties, formation stresses (i.e. fracture pressures) etc. Accurate fracture pressure estimate in HF design and modeling improves reliability of HF placement, which is the key for improved production performance of HF. HF treatments in the studied fields provide large volumes of valuable data. Developing standardized tables and charts can streamline the process to generate input parameters for HF modeling and design in an efficient and consistent manner. Results of the study can assist with developing guidelines and workflow and for HF operations. Field HF data from more than 100 wells in south Oman fields were analyzed to derive the magnitude of breakdown pressure (BP), Fracture Breakdown Pressure (FBP), Instantaneous Shut-In Pressure (ISIP) pressure, and Fracture Closure Pressure (FCP) and develop input correlations for HF design. Estimated initial FCP (in-situ pore pressure conditions) is in the range of 15.6 - 16 kPa/mTVD at reservoir formation pressure gradient of about 10.8 kPa/m TVD bdf. However, most of the fields have undergone variable degree of depletion prior to the HF operation. Horizontal stresses in the reservoir decrease with depletion, it is therefore important to assess the reduction of FCP with reduction in pore pressure (stress depletion). Depletion stress path coefficient (i.e. change on FCP as a fraction of change in pore pressure) was derived based on historic field data and used to predict reduction of FCP as a function of future depletion. Data from this field indicates that the magnitude of decrease in fracture pressure is about 50% of the pore pressure change. Based on the data analysis of available HF data, standardized charts and tables were developed to estimate FCP, FBP, and ISIP values. Ratios of FBP and ISIP to FCP were computed to establish trend with depth to provide inputs to HF planning and design. Results indicate FBP/FCP ratio ranges between 1.24-1.35 and ISIP/FCP ratio ranges between 1.1 to 1.2. Developed workflow and standardized tables, charts and trends provide reliable predictions inputs for HF modeling and design. Incorporating these data can be leveraged to optimize parameters for HF design and modeling for future wells.

2022 ◽  
Mark Mcclure ◽  
Garrett Fowler ◽  
Matteo Picone

Abstract In URTeC-123-2019, a group of operators and service companies presented a step-by-step procedure for interpretation of diagnostic fracture injection tests (DFITs). The procedure has now been applied on a wide variety of data across North and South America. This paper statistically summarizes results from 62 of these DFITs, contributed by ten operators spanning nine different shale plays. URTeC-123-2019 made several novel claims, which are tested and validated in this paper. We find that: (1) a ‘compliance method’ closure signature is apparent in the significant majority of DFITs; (2) in horizontal wells, early time pressure drop due to near-wellbore/midfield tortuosity is substantial and varies greatly, from 500 to 6000+ psi; (3) in vertical wells, early-time pressure drop is far weaker; this supports the interpretation that early- time pressure drop in horizontal wells is caused by near-wellbore/midfield tortuosity from transverse fracture propagation; (4) the (not recommended) tangent method of estimating closure yields Shmin estimates that are 100-1000+ psi lower than the estimate from the (recommended) compliance method; the implied net pressure values are 2.5x higher on average and up to 5-6x higher; (5) as predicted by theory, the difference between the tangent and compliance stress and net pressure estimates increases in formations with greater difference between Shmin and pore pressure; (6) the h-function and G-function methods allow permeability to be estimated from truncated data that never reaches late-time impulse flow; comparison shows that they give results that are close to the permeability estimates from impulse linear flow; (7) false radial flow signatures occur in the significant majority of gas shale DFITs, and are rare in oil shale DFITs; (8) if false radial signatures are used to estimate permeability, they tend to overestimate permeability, often by 100x or more; (9) the holistic-method permeability correlation overestimates permeability by 10-1000x; (10) in tests that do not reach late-time impulse transients, it is reasonable to make an approximate pore pressure estimate by extrapolating the pressure from the peak in t*dP/dt using a scaling of t^(-1/2) in oil shales and t^(3/4) in gas shales. The findings have direct practical implications for operators. Accurate permeability estimates are needed for calculating effective fracture length and for optimizing well spacing and frac design. Accurate stress estimation is fundamental to hydraulic fracture design and other geomechanics applications.

2022 ◽  
Dharmendra Kumar ◽  
Ahmad Ghassemi

Abstract The communication among the horizontal wells or "frac-hits" issue have been reported in several field observations. These observations show that the "infill" well fractures could have a tendency to propagate towards the "parent" well depending on reservoir in-situ conditions and operational parameters. Drilling the horizontal wells in a "staggered" layout with both horizontal and vertical offset could be a mitigation strategy to prevent the "frac-hits" issue. In this study, we present a detailed geomechanical modeling and analysis of the proposed solution. For numerical modeling, we used our state-of-the-art fully coupled poroelastic model "GeoFrac-3D" which is based on the boundary element method for the rock matrix deformation/fracture propagation and the finite element method for the fracture fluid flow. The "GeoFrac-3D" simulator fully couples pore pressure to stresses and allows for dynamic modeling of production/injection and fracture propagation. The simulation results demonstrate that production from a "parent’ well causes a non-uniform reduction of the reservoir pore pressure around the production fractures, resulting in an anisotropic decrease of the reservoir total stresses, which could affect fracture propagation from the "infill" wells. We examine the optimal orientation and position of the "infill" well based on the numerical analysis to reduce the "frac-hits" issue in the horizontal well refracturing. The posibility of "frac-hits" can be reduced by optimizing the direction and locations of the "infill" wells, as well as re-pressurizing the "parent" well. The results suggest that arranging the horizontal wells in a "staggered" or "wine rack" arrangement decreases direct well interference and could increase the drainage volume.

2022 ◽  
Javier Alejandro Franquet ◽  
Viraj Nitin Telang ◽  
Hayat Abdi Ibrahim Jibar ◽  
Karem Alejandra Khan

Abstract The scope of this work is to measure downhole fracture-initiation pressures in multiple carbonate reservoirs located onshore about 50 km from Abu Dhabi city. The objective of characterizing formation breakdown across several reservoirs is to quantify the maximum gas and CO2 injection capacity on each reservoir layer for pressure maintenance and enhance oil recovery operations. This study also acquires pore pressure and fracture closure pressure measurements for calibrating the geomechanical in-situ stress model and far-field lateral strain boundary conditions. Several single-probe pressure drawdown and straddle packer microfrac injection tests provide accurate downhole measurements of reservoir pore pressure, fracture initiation, reopening and fracture closure pressures. These tests are achieved using a wireline or pipe-conveyed straddle packer logging tool capable to isolate 3 feet of openhole formation in a vertical pilot hole across five Lower Cretaceous carbonate reservoirs zones. The fracture closure pressures are obtained from three decline methods during the pressure fall-off after fracture propagation injection cycle. The three methods are: (1) square-root of the shut-in time, (2) G-Function pressure derivative, and (3) Log-Log pressure derivative. The far-field strain values are estimated by multi-variable regression from the microfrac test data and the core-calibrated static elastic properties of the formations where the stress tests are done. The reservoir pressure across these carbonate formations are between 0.48 to 0.5 psi/ft with a value repeatability of 0.05 psi among build-up tests and 0.05 psi/min of pressure stability. The formation breakdown pressures are obtained between 0.97 and 1.12 psi/ft over 5,500 psi above hydrostatic pressure. The in-situ fracture closure measurements provide the magnitude of the minimum horizontal stress 0.74 - 0.83 psi/ft which is used to back-calculate the lateral strain values (0.15 and 0.72 mStrain) as far-field boundary condition for subsequent geomechanical modeling. These measurements provide critical subsurface information to accurately predict wellbore stability, hydraulic fracture containment and CO2 injection capacity for effective enhance oil recovery within these reservoirs. This in-situ stress wellbore data represents the first of its kind in the field allowing petroleum and reservoir engineers to optimize the subsurface injection plans for efficient field developing.

Geofluids ◽  
2022 ◽  
Vol 2022 ◽  
pp. 1-7
Rui Shen ◽  
Zhiming Hu ◽  
Xianggang Duan ◽  
Wei Sun ◽  
Wei Xiong ◽  

Shale gas reservoirs have pores of various sizes, in which gas flows in different patterns. The coexistence of multiple gas flow patterns is common. In order to quantitatively characterize the flow pattern in the process of shale gas depletion development, a physical simulation experiment of shale gas depletion development was designed, and a high-pressure on-line NMR analysis method of gas flow pattern in this process was proposed. The signal amplitudes of methane in pores of various sizes at different pressure levels were calculated according to the conversion relationship between the NMR T 2 relaxation time and pore radius, and then, the flow patterns of methane in pores of various sizes under different pore pressure conditions were analyzed as per the flow pattern determination criteria. It is found that there are three flow patterns in the process of shale gas depletion development, i.e., continuous medium flow, slip flow, and transitional flow, which account for 73.5%, 25.8%, and 0.7% of total gas flow, respectively. When the pore pressure is high, the continuous medium flow is dominant. With the gas production in shale reservoir, the pore pressure decreases, the Knudsen number increases, and the pore size range of slip flow zone and transitional flow zone expands. When the reservoir pressure is higher than the critical desorption pressure, the adsorbed gas is not desorbed intensively, and the produced gas is mainly free gas. When the reservoir pressure is lower than the critical desorption pressure, the adsorbed gas is gradually desorbed, and the proportion of desorbed gas in the produced gas gradually increases.

Géotechnique ◽  
2022 ◽  
pp. 1-35
S. L. Chen ◽  
Y. N. Abousleiman

A novel graphical analysis-based method is proposed for analysing the responses of a cylindrical cavity expanding under undrained conditions in modified Cam Clay soil. The essence of developing such an approach is to decompose and represent the strain increment/rate of a material point graphically into the elastic and plastic components in the deviatoric strain plane. It allows the effective stress path in the deviatoric plane to be readily determined by solving a first-order differential equation with the Lode angle being the single variable. The desired limiting cavity pressure and pore pressure can be equally conveniently evaluated, through basic numerical integrations with respect to the mean effective stress. Some ambiguity is clarified between the generalized (work conjugacy-based) shear strain increments and the corresponding deviatoric invariants of incremental strains. The present graph-based approach is also applicable for the determination of the stress and pore pressure distributions around the cavity. When used for predicting the ultimate cavity/pore pressures, it is computationally advantageous over the existing semi-analytical solutions that involve solving a system of coupled governing differential equations for the effective stress components. It thus may serve potentially as a useful and accurate interpretation of the results of in-situ pressuremeter tests on clay soils.

2022 ◽  
Vol 9 ◽  
Wei Guo ◽  
Xiaowei Zhang ◽  
Rongze Yu ◽  
Lixia Kang ◽  
Jinliang Gao ◽  

The flow of shale gas in nano scale pores is affected by multiple physical phenomena. At present, the influence of multiple physical phenomena on the transport mechanism of gas in nano-pores is not clear, and a unified mathematical model to describe these multiple physical phenomena is still not available. In this paper, an apparent permeability model was established, after comprehensively considering three gas flow mechanisms in shale matrix organic pores, including viscous slippage Flow, Knudsen diffusion and surface diffusion of adsorbed gas, and real gas effect and confinement effect, and at the same time considering the effects of matrix shrinkage, stress sensitivity, adsorption layer thinning, confinement effect and real gas effect on pore radius. The contribution of three flow mechanisms to apparent permeability under different pore pressure and pore size is analyzed. The effects of adsorption layer thinning, stress sensitivity, matrix shrinkage effect, real gas effect and confinement effect on apparent permeability were also systematically analyzed. The results show that the apparent permeability first decreases and then increases with the decrease of pore pressure. With the decrease of pore pressure, matrix shrinkage, Knudsen diffusion, slippage effect and surface diffusion effect increase gradually. These four effects will not only make up for the permeability loss caused by stress sensitivity and adsorption layer, but also significantly increase the permeability. With the decrease of pore radius, the contribution of slippage flow decreases, and the contributions of Knudsen diffusion and surface diffusion increase gradually. With the decrease of pore radius and the increase of pore pressure, the influence of real gas effect and confinement effect on permeability increases significantly. Considering real gas and confinement effect, the apparent permeability of pores with radius of 5 nm is increased by 13.2%, and the apparent permeability of pores with radius of 1 nm is increased by 61.3%. The apparent permeability model obtained in this paper can provide a theoretical basis for more accurate measurement of permeability of shale matrix and accurate evaluation of productivity of shale gas horizontal wells.

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