New Effective-Stress Law for Predicting Perforation Depth at Downhole Conditions (original) (raw)
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Stress-Dependent Perforation in Carbonate Rocks: An Experimental Study
SPE drilling & completion, 2018
Perforation with shaped charges as a conventional well-completion technique is widely used in the oil industry. Different phenomena influence perforation performance and depth of penetration (DOP). The authors examined the effect of in-situ stresses and shot density on DOP and created fracture patterns in concrete and limestone samples with surface and polyaxial/triaxial-stress-loading conditions. To achieve this aim, we designed and developed a polyaxial-perforation test machine. We optimized the number of experimental tests using the Taguchi-design test method. The Taguchi orthogonal scheme is well-known and is a highly recommended method to optimize the number of required experiments (Taguchi 1990; Ross 1996; Jeyapaul et al. 2005; Gupta et al. 2014). Our experimental setup resembles vertical wells in the strike/slip-faulting regions and horizontal wells in the reverse-faulting regions. The results show that DOP is more controlled by stresses normal to the shooting direction in polyaxial tests than by the stress in the direction of penetration. DOP and the maximum hole diameter from the second charge had a direct relation with shot density. The DOP observed in polyaxial-loading conditions was a little lower than in the triaxial-loading mode, where the mean value of stresses normal to the shooting direction in the polyaxial tests was the same as the horizontal stresses in the triaxial tests. In both surface and triaxial-loading conditions, the patterns of perforation fractures were radial and regular, whereas the cracks created were oriented along the direction of maximum horizontal stress in the polyaxial tests. Polyaxial-Compressive-Test Machine The authors designed and constructed the blocky-scale polyaxial-compressive-perforation apparatus and conducted perforation tests on different rock types with shaped charges and spacing. Fig. 1 shows a schematic of the polyaxial-perforation machine. The main
A new correlation to evaluate the fracture permeability changes as reservoir is depleted
Journal of Petroleum Science and Engineering
The increasing development of unconventional resources plays an important role in filling the gap between demand and conventional oil and gas supply. Due to the nature of low permeability, tight gas and shale reservoirs need fractures, natural and artificial, to produce hydrocarbon at commercial rates. Fracture permeability is a key factor affecting the development of these unconventional reservoirs. It is observed that fracture permeabilities decline as reservoirs are depleted because pore pressure declines lead to the closures of fractures and the permeability reductions. Therefore a correlation to quantify the variations of the fracture permeability with pore pressure is highly needed. In this study we investigate the effects of pore pressures on fracture permeabilities assuming constant in-situ stresses exert on the formations. Starting from the force balance, we derived equations to calculate fracture permeability based on fracture geometry. Our new correlations can also be used to evaluate the changing fracture permeability during the recovery of hydrocarbon. The proposed correlations provide a way to estimate the fracture permeability at initial pressure and the depleted pressure at any production stage. Although some experiments had been conducted to build relationships between fracture permeability and pressure for some types of rocks. It is noted that experiments are time
Energies
Permeability prediction in hydrocarbon production is an important task. The decrease in permeability due to depletion leads to an increase in the time of oil or gas production. Permeability models usually are obtained by various methods, including coreflooding and the field testing of wells. The results of previous studies have shown that permeability has a power-law or exponential dependence on effective pressure; however, the difficulty in predicting permeability is associated with hysteresis, the causes of which remain not fully understood. To model permeability, as well as explain the causes of hysteresis, some authors have used mechanical reservoir models. Studies have shown that these models cannot be applied with small fluctuations in effective pressures in the initial period of hydrocarbon production. In this work, based on the analysis of well test data, we came to the conclusion that in the initial period of production under constant thermobaric conditions, the permeabilit...
SPE Reservoir Evaluation & Engineering, 2005
A comprehensive semi-analytical model is built to investigate the effects of drilling/perforating damage and high-velocity flow on the performance of perforated horizontal wells. In our previous papers 1, 2 , we presented a semi-analytical model for completed horizontal wells by coupling the 3D reservoir flow model and the wellbore-hydraulics model and discussed the pseudo-skin approach for clean perforated completion. In this paper, the additional pressure drop due to formation damage and high-velocity flow are addressed and incorporated into the previous semi-analytical model. The reservoir model considers the 3D convergent flow into individual perforations, flow through the damaged zone around the wellbore and the crushed zone around the perforation tunnels as well as the additional pressure drop due to non-Darcy flow in near wellbore region. Both oil and gas wells are discussed. The expressions for additional pressure losses due to perforating damage, drilling damage and high-velocity flow can be used to optimize perforating parameters and to decompose the total skin into its components (perforation pseudoskin, damage skin, and non-Darcy skin).
2019
We investigate pore pressure conditions and reservoir compaction associated with oil and gas production using 3 different permeability models, which are all based on one-dimensional radial flow diffusion model, but differ in considering permeability evolution during production. Model 1 assumes the most simplistic constant and invariable permeability regardless of production; Model 2 considers permeability reduction associated with reservoir compaction only due to pore pressure drawdown during production; Model 3 also considers permeability reduction but due to the effects of both pore pressure drawdown and coupled pore pressure-stress process. We first derive a unified stresspermeability relation that can be used for various sandstones. We then apply this equation to calculate pore pressure and permeability changes in the reservoir due to fluid extraction using the three permeability models. All the three models yield pore pressure profiles in the form of pressure funnel with differ...
Permeability and Effective Pore Pressure of Shales
Laboratory-derived permeability and pore-pressure data obtained for Wellington and Pierre shales are used to describe swelling pressure, and spalling types of wellbore instability. Tests showed that increased pore pressures can lead to wellbore failure. The laboratory pore-pressure information developed displays a time-dependent swelling process followed by a Darcy type of flow. A "total aqueous chemical potential" concept is presented that describes the driving potentials that operate during both phases of flow. Experimental methods are presented to determine the "storage" of water shale during the swelling phase and the permeabilities with steady-state-flow and transient-flow techniques. Permeability values measured under effective stresses up to 8,000 psi show the Wellington shale to have values as low as 0.30 x 10 -6 md.
Journal of Natural Gas Science and Engineering, 2019
Accurate and routinely applicable methods to determine porosities and permeability coefficients are needed in order to ensure effective hydrocarbon recovery in shale and tight sandstone plays. In this study 129 gas uptake measurements ("GRI method", "inflow" experiments) were performed on core plugs from three unconventional reservoir lithotypes (oil shales, gas shales and tight gas sandstones) under elevated effective stress conditions. The results were compared to those from "flow-through" tests (standard pulse decay) under similar experimental conditions, e.g. the same gas type and pore pressure range. The samples covered a porosity range from 1.3% to 12%. Equilibration times ranged from 10 2 s to 10 4 s and permeability coefficients from 10-18 to 10-21 m 2. In order to successfully determine apparent gas permeability coefficients and porosities and to reliably interpret fluid dynamic effects from gas uptake data it is necessary to ensure a sufficiently high excess pressure drop during the uptake tests. This can be controlled by adjustment of the reservoir to pore volume ratio and initial differential pressure. Permeability coefficients derived from uptake tests on all six samples do not show any systematic deviations from those obtained from flow-through measurements. Best results were achieved for a core plug from the Lower Palaeozoic Alum Shale (Djupvik, Öland, Sweden), where Klinkenberg regressions of inflow and flow-through differ only by 4% (slope) and 10% (y-axis intercept). Here, the gas storage capacity ratio was
Worldwide increase demand for oil and gas led to an evolution in drilling techniques that maximize oil and gas production such as inclined, multilateral, and long horizontal drilling. The interaction of the drilling fluid and mud filtration with the penetrated formation is very critical and very important to be evaluated especially in the case of horizontal drilling where the drilling operation may take more than 20 days. This study aims to assess the effect of exposure time on the changes of the unconfined compressive strength (UCS) while drilling horizontal sandstone formation using water-based drilling fluid. Modified high-pressure high-temperature (HPHT) filter press cell was used to soak Buff Berea sandstone cores with barite-weighted mud under 300 psi differential pressure and 200 � F temperature for different periods. Nuclear magnetic resonance (NMR) was used to assess the change of the porosity while the scratch test was conducted to evaluate the changes in the UCS. The obtained results showed that UCS decreased significantly with increasing exposure time. For instance, the UCS was reduced by 18% after 5 days. NMR results confirmed that there was a corresponding increase in formation damage as shown by a progressive decrease in the rock porosity and permeability with time. The exposure time was found to be a controlling factor for both reducing the rock UCS and porosity. The statistical analysis showed that there is an inverse linear relationship (with 0.92 coefficient of determination R 2) between the UCS values vs the extended exposure time. Meanwhile, an approximate logarithmic relationship (with R 2 of 0.98) for estimating the reduction in rock porosity with the exposure time was investigated.