Knowledge of accurate rock strength is essential for in situ stress estimation, wellbore stability analysis, sand production prediction and other geomechanical applications. Reliable quantitative data on rock strength can only be obtained from cores. However, cores are limited, discontinuous and often biased. Consequently, rock strength evaluation is primarily based on log strength indicators, calibrated where possible against limited core measured values. There are a number of published log-core strength correlations that can be used for rock strength modelling. These empirical relationships are developed for specific rock type, age, depth range and field. Their general applications, therefore, need to be critically assessed on a case by case basis. This paper briefly: (i) outlines the best practice for obtaining quality rock strength data from core tests; (ii) presents common empirical rock strength equations for sedimentary rocks and (iii) discusses ways of improving rock strength estimates.While some equations such as porosity-based or sonic log-based rock strength models work reasonably well, rock strength variations within individual rock properties show considerable scatter, indicating that most of the empirical models are not sufficiently generic to fit all rocks in the database. Like any other physical rock properties, the variation in rock strength in a given sedimentary rock is controlled by mineralogy, sedimentology and micro-structure of the rock and simple log-derived rock strength models need further modification and classification incorporating these geological characteristics.This paper has shown that when sufficient core rock strength data exists, applications of computing techniques, such as fuzzy logic and cluster pattern recognition, coupled with sedimentary facies analysis and diagenetic classification can improve strength estimation. Semi-continuous impact energy logs using portable non-destructive testing tools can be correlated with petrophysical logs to generate mechanical facies and improved sampling for conventional rock testing.
The source of sand production is the presence of disintegrated sand grains due to rock failure at the wellbore and/or perforation walls. Decision for appropriate sand control strategy requires engineering analysis to evaluate timing and severity of sanding over the life of field conditions. Optimizing well parameters such as well trajectory, perforation orientation, and level of drawdown using geomechanical principles can minimize and delay sand production. This paper presents a geomechanical modeling approach that integrates production history with information from drilling data, well logs and rock mechanics tests. A gas field in South Asia with 11 wells and several years of production experience is used to demonstrate this approach. Core-calibrated rock strength log profiles are estimated throughout the reservoir depth for all existing wells. A rock failure criterion at the sand face is developed as a function of in-situ stresses, rock strength, well trajectory, perforation orientation, reservoir depletion and drawdown. Sanding evaluation results are calibrated and verified with production data and evidence of sanding in existing wells. Sand-free operating envelopes and sand evaluation logs are then generated for all existing wells and planned infill wells for life of field conditions. Sand prone zones and timing of sanding are established as a function of depletion and drawdown for each well using production forecasts for the rest of field life. For new infill wells, optimum well trajectories, selective perforation intervals and optimum perforation orientations are proposed to minimize and delay sand production. Re-completion and utilizing passive sand control methods including selective and orientated perforations are recommended for a number of existing wells. This paper is expected to provide well engineers with guidelines to understand the principles and overall workflow involved in sand production prediction and minimization of sand production risk by optimizing well trajectory, perforation orientation and selective perforation strategy. Introduction Mitigation of sand production is increasingly becoming an important and challenging issue in the petroleum industry as ever increasing demands for oil and gas resources are forcing the industry to expand its exploration and production operations in more challenging unconsolidated reservoir rocks and depleted sandstones with more complex well completion architecture. A sand production prediction study is now an integral part of an overall field development planning study to see whether and when sand production will be an issue over the life of the field and, depending on its timing and severity, what type of sand control measures and sand management strategy will be cost-effective for the field. The source for sand production is the presence of disintegrated sand grains around the wellbore or perforation walls. The source for disintegrated sand grains may be the unconsolidated reservoir sands or rock failure around the borehole or the perforation. While unconsolidated reservoir sands often call for sand control measures from the beginning of the production phase, the sand production prediction study provides much benefit for reservoirs having sandstones of weak to intermediate strengths. Rock failure in such reservoirs may be minimized by controlling the well trajectory, perforation orientation, perforation intervals and drawdown by knowing the in-situ stresses and rock strength in the field. While standard methods are available for in-situ stress and rock strength characterization, the solution over the field life becomes complex due to the change of reservoir pressure and its effect on rock failure.
Abstract" comprehensive geomechanical study was carried out to optimize stimulation for a fractured tight gas reservoir in the northwest Tarim "asin. Conventional gel fracturing and acidizing operations carried out in the field previously failed to yield the expected productivity. The objective of this study was to assess the effectiveness of slickwater or low-viscosity stimulation of natural fractures by shear slippage, creating a conductive, complex fracture network. This type of stimulation is proven to successfully exploit shale gas resources in many fields in the United States." field-scale geomechanical model was built using core, well log, drilling data and experiences characterizing the in-situ stress, pore pressure and rock mechanical properties in both overburden and reservoir sections. "orehole image data collected in three offset wells were used to characterize the in-situ natural fracture system in the reservoir. The pressure required to stimulate the natural fracture systems by shear slippage in the current stress field was predicted. The injection of low-viscosity slickwater was simulated and the resulting shape of the stimulated reservoir volume was predicted using a dual-porosity, dual-permeability finite-difference flow simulator with anisotropic, pressure-sensitive reservoir properties. " hydraulic fracturing design and evaluation simulator was used to model the geometry and conductivity of the principal hydraulic fracture filled with proppant. Fracture growth in the presence of the lithology-based stress contrast and rock properties was computed, taking into account leakage of the injected fluid into the stimulated reservoir volume
Hydraulic fracturing is a widely used technology in the petroleum industry to increase production rates from low-permeability reservoirs. It has also been successfully applied to coalbed methane gas development in many occasions. This paper presents an Australian field case of coalbed methane gas development where expensive fracture treatments did not yield the expected benefits. A comprehensive integrated geomechanical analysis was performed to understand the underlying causes for the failure. The geomechanical model consists of the magnitude and orientation of the three principal stresses, the pore pressure, and the rock strength. Fracture treatment data were used to estimate the least principal stress, vertical stress was determined from density logs, pore pressure was derived from direct field measurements, and rock strength values were determined from well logs and core measurements. The maximum horizontal stress (SHmax) magnitude was constrained by modeling the stress and pressure conditions consistent with the observation of wellbore breakouts in image logs. The relative magnitude of principal stresses corresponds to a transition between Strike-Slip and Reverse Faulting stress regimes (SV< Shmin < SHmax) with an overall SHmax orientation of NE-SW. Fracture propagation simulations using boundary element modeling showed that a complex fracture growth under the influence of the current in-situ stresses could be the main reason for the fracture treatment failure. The study recommended a number of alternative configurations for well orientations and fracture treatments in the field considering the existing in situ stress and the complex fracture network. Also the interactions between the coal seam and different fracturing fluids have been studied to evaluate the formation damage aspects to recommend the formation compatible fracturing fluid. Presentation of these results in this paper is expected to give a general framework for successful hydraulic fracture treatments and example of specific implementation issues with respect to an Australian coalbed methane gas field. Introduction Hydraulic fracturing is a process whereby proppant-laden fluid is injected into a well under high pressure to initiate a fracture from the wellbore wall and extend the fracture deep into the reservoir. Once the injection is ceased, the propped fracture becomes the principal conduit for flow of the hydrocarbon from the reservoir to the well, and thus achieving increased production rates. The petroleum industry has long been applying hydraulic fracturing treatment as a principal technique to improve oil and gas production. Of the production wells drilled in North America since 1950s, about 70% of gas wells and 50% of oil wells have been hydraulically fractured1. The technology has also been applied to many Coal Bed Methane (CBM) reservoirs. Improved design and execution of hydraulic fracturing treatments is, therefore, an important task in the petroleum industry. In fact, high demands for fracturing treatments in the industry have led to the wide commercialisation of this technology. Despite many success cases, the operational performance and cost-benefit accounts of hydraulic fracture treatments have not been positive in some occasions, particularly onshore Australia2. Major difficulties encountered during treatments include the requirement of high injection pressure, high frictional pressure drop, inability to inject proppant at required concentrations within the pump capacity, inability to extend the initiated fracture, and consequently, poor post-stimulation productivity. These experiences in usual sandstone reservoirs have also been recently encountered in a (CBM) gas field in Australia (name withheld due to confidentiality agreement). Further improved understanding is, therefore, necessary to design and execute treatments that would be effective for such unconventional field conditions. Without field-appropriate design and execution of treatments, there is very little chance that fracturing programs will be successful to realise its potential benefits commensurate to its investments and expectations. This paper presents the Australian CBM field case where fracture treatments were unsuccessful. The objective of this paper is to investigate the causes for failures of the treatments carried out through an integrated geomechanics analysis and to suggest measures that could be taken to increase the likelihood of success.
Summary The source of sand production is the presence of disintegrated sand grains caused by rock failure at the wellbore and/or perforation walls. Decision for appropriate sand-control strategy requires engineering analysis to evaluate timing and severity of sanding over the life of field conditions. Optimizing well parameters such as well trajectory, perforation orientation, and level of drawdown using geomechanical principles can minimize and delay sand production. This paper presents a geomechanical modeling approach that integrates production history with information from drilling data, well logs, and rock-mechanics tests. A gas field in south Asia with 11 wells and several years of production experience is used to demonstrate this approach. Core-calibrated rock-strength-log profiles are estimated throughout the reservoir depth for all existing wells. A rock-failure criterion at the sandface is developed as a function of in-situ stresses, rock strength, well trajectory, perforation orientation, reservoir depletion, and drawdown. Sanding-evaluation results are calibrated and verified with production data and evidence of sanding in existing wells. Sand-free operating envelopes and sand evaluation logs are then generated for all existing wells and planned infill wells for the life of field conditions. Sand-prone zones and timing of sanding are established as a function of depletion and drawdown for each well, using production forecasts for the rest of field life. For new infill wells, optimum well trajectories, selective perforation intervals, and optimum perforation orientations are proposed to minimize and delay sand production. Recompletion and using passive sand-control methods including selective and orientated perforations are recommended for a number of existing wells. This paper is expected to provide well engineers with guidelines to understand the principles and overall workflow involved in sand-production prediction and minimization of sand production risk by optimizing well trajectory, perforation orientation, and selective-perforation strategy.
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