Development Of Tight Gas Reservoirs Research Articles

Comprehensive evaluation of formation damage induced by working fluid loss in fractured tight gas reservoir

Western Sichuan tight gas reservoir is characteristic of developed natural fractures and ultra low matrix permeability. Developed fracture is beneficial for the economic and efficient development of tight gas reservoir. But it will lead to lost circulation of working fluid and induce formation damage. Lost circulation has frequently occurred during drill-in, completion and test process. Formation damage degree and damage range are the key indexes for the formation damage evaluation. To our best knowledge, few papers have been published on the comprehensive consideration of the above two indexes. In this paper, we conduct laboratory experiments and develop a mathematical model to evaluate the formation damage degree and determine the formation damage range. Based on the study results a formation damage pattern is established to analyze the mechanism and process of the formation damage induced by working fluid loss. The study results show that the average formation damage degree induced by drill-in fluid loss is 68.51% and increases to 78.70% when the kill fluid loss damage is taken into consideration. The radius of formation damage zone induced by working fluid loss is 15.8 m. The formation damage pattern is as follows: First the loss of drill-in fluid induces serious formation damage including sensitive damage, particle plugging and water phase trapping. Then the subsequent loss of kill fluid in the process of completion and test further aggravates the formation damage degree. Finally in the acidizing treatment the acidizing radius cannot exceed the damage zone radius so that the formation damage cannot be completely removed. The comprehensive evaluation and pattern of formation damage are necessary for designing reasonable reservoir protection and damage removal measures for the fractured tight gas reservoir.

Prediction of Stimulated Reservoir Volume and Optimization of Fracturing in Tight Gas and Shale With a Fully Elasto-Plastic Coupled Geomechanical Model

Summary Hydraulic fracturing is essential for the economic development of tight gas reservoirs and shale-gas reservoirs. Current techniques are unable to predict the stimulated-reservoir-volume (SRV) dependence on fracturing-job and rock-mechanics parameters, which precludes any meaningful optimization. In the authors' previous work on the SRV-propagation prediction, the combined tensile/shear fracturing model applied to the fracturing of tight gas formations has shown the creation of a relatively narrow, focused SRV that resembled behavior dominated by a single fracture. In this work, the model has been significantly improved by the implementation of a rigorous full Newton elasto-plastic solution of the geomechanics of rock containing induced fractures. The results reveal interesting features of complex-fracture propagation in tight formations, which are in broad agreement with the shapes of SRVs obtained from microseismic imaging. The developed code is flexible enough to allow either tensile or shear fracturing or the occurrence of both to be examined on the basis of initial reservoir conditions. Different cases of 2D and 3D simulations will be presented that demonstrate some important features of the process. First, it is found that a wide SRV can result in cases in which initial reservoir conditions are close to the shear-fracturing point, such as in formations with microfractures, partially cemented natural fractures, and abnormally high initial pore pressure. Second, the SRV width is found to depend on the horizontal stress contrast, as expected. Third, wide SRV growth is associated with constant or increasing pumping pressure necessary for further failed-zone growth as a result of the loss of elastic coupling by off-planar failure propagation. Further, under high injection pressure, an efficient fracture elasto-plastic constitutive model developed can drive both maximal and minimal effective stresses to zero or tensile, and, therefore, the creation of tensile fracturing can be predicted simultaneously with shear fracturing. This will then provide a means of modeling proppant transport. The new model is a significant step toward the development of an integrated predictive tool for the optimization of shale-gas development.

Integrated application of 3D seismic and microseismic data in the development of tight gas reservoirs

The development of unconventional resources, such as shale gas and tight sand gas, requires the integration of multi-disciplinary knowledge to resolve many engineering problems in order to achieve economic production levels. The reservoir heterogeneity revealed by different data sets, such as 3D seismic and microseismic data, can more fully reflect the reservoir properties and is helpful to optimize the drilling and completion programs. First, we predict the local stress direction and open or close status of the natural fractures in tight sand reservoirs based on seismic curvature, an attribute that reveals reservoir heterogeneity and geomechanical properties. Meanwhile, the reservoir fracture network is predicted using an ant-tracking cube and the potential fracture barriers which can affect hydraulic fracture propagation are predicted by integrating the seismic curvature attribute and ant-tracking cube. Second, we use this information, derived from 3D seismic data, to assist in designing the fracture program and adjusting stimulation parameters. Finally, we interpret the reason why sand plugs will occur during the stimulation process by the integration of 3D seismic interpretation and microseismic imaging results, which further explain the hydraulic fracture propagation controlling factors and open or closed state of natural fractures in tight sand reservoirs.

Pressure Transient Modeling of Fractured Horizontal Wells in the Closed Tight Gas Reservoir

Fractured horizontal well is the important means for the development of tight gas reservoirs. Based on the geologic characteristics of the tight gas reservoir, a pressure transient model for fractured horizontal wells is established by the Green functions and Newman product principle. The model considers the seepage resistances and the inferences from fractures each other. Practical application presents the pressure changes and flow rate distribution of fractures at non-steady state and quasi-steady state, and the suggestions for field operation are given as well.

The Modeling and Simulation of Tight Gas Reservoirs Incorporating Desorption Phenomena

Tight gas reservoirs are categorized as unconventional gas reservoirs. One of the main characteristics of a tight gas reservoir is the adsorption of gas on the rock surface due to high specific surface area. Desorption is the process of adsorbing gas by the reservoir rock on its surface that is dependent on factors, such as reservoir pressure, reservoir rock type, and temperature. Therefore, analysis of production data using conventional methods is expected to be problematic. In this study, there was an endeavor to model and simulate the desorption phenomena in tight formations to investigate its effect on different properties and to study related reservoirs. The purpose of this work is to model the single-phase radial gas flow in tight gas reservoirs including equilibrium desorption phenomena on the rock surface and Darcy flow in a reservoir. Considering a control volume, the gas desorption rate as a function of time and space is incorporated into the radial continuity equation as a source term. Using a Langmuir-type sorption isotherm, the gas desorption rate is determined at any radius of the reservoir. The resulting governing equation is solved numerically using a finite difference approach. The simulator is used to model a tight reservoir to identify how important parameters affect the performance of a tight gas reservoir. The results suggest that the development of tight gas reservoirs with significant gas desorption can lead to higher production rates and improve the productivity of the gas reservoir. The model developed here can be used as an engineering tool for evaluating the role of adsorbed gases in improving the productivity and extending the life of tight gas reservoirs.

Induced and natural fracture interaction in tight-gas reservoirs

This paper investigates the interaction of an induced hydraulic fracture in the presence of a natural fracture and the subsequent propagation of this induced fracture. The developed, fully coupled finite element model integrates a wellbore, an induced hydraulic fracture, a natural fracture, and a reservoir that simulates interaction between the induced and natural fracture. The results of this study have shown that natural fractures can have a profound effect on induced fracture propagation. In most cases, the induced fracture crosses the natural fracture at high angles of approach and high differential stress. At low angles of approach and low differential stress, the induced fracture is more likely to be arrested and/or break out from the far-end side of the natural fracture. It has also been observed that the propagation of the induced fracture is stopped by a large natural fracture at a high angle of approach, when the injection rate remains low. At a low angle of approach, the induced fracture deviates and propagates along the natural fracture. Crossing of the natural fracture and/or arrest by the natural fracture is controlled by the shear strength of the natural fracture, natural fracture orientation, and the in situ stress state of the reservoir. In tight-gas reservoir development, the optimum well spacing and induced hydraulic fracture length are correlated. Therefore, fracturing design should be performed during the initial reservoir development planning phase along with the well spacing design to obtain an optimal depletion strategy. This model has a potential application in the design and optimisation of fracturing design in unconventional reservoirs including tight-gas reservoirs and enhanced geothermal systems.

Damage Mechanisms in Unconventional-Gas-Well Stimulation - New Look at an Old Problem

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 142479, ’Damage Mechanisms in Unconventional-Gas- Well Stimulation - A New Look at an Old Problem,’ by Josef Shaoul, SPE, StrataGen Delft; Lars van Zelm, SPE, Delft University of Technology; and Hans J. de Pater, SPE, StrataGen Delft, prepared for the 2011 SPE Middle East Unconventional Gas Conference and Exhibition, Muscat, Oman, 31 January- 2 February. The paper has not been peer reviewed. After fracture stimulation, production often increases slowly instead of showing an early transient. This condition indicates either a severe reduction in fracture conductivity or reservoir damage. Little agreement exists about the most likely damage mechanism. New ideas were proposed that may better explain the behavior commonly observed in actual production data. These ideas include “permeability jail” in which relative permeability indicates that water and gas are both immobile at a given saturation, small-scale reservoir heterogeneity, and stress-sensitive matrix permeability at high drawdown. These effects on post-fracture production from an unconventional (0.001-md) gas well were studied by reservoir simulation. Realistic assumptions about proppant-pack cleanup showed a relation of poor cleanup and short effective fracture length to a reduction in contacted permeability-thickness (kh) and to connected reservoir volume. Simulation results showed 50% reduction of production in the first year(s) caused by these effects in unconventional reservoirs. Introduction Worldwide rising gas demand is creating opportunities to exploit low-permeability gas reservoirs outside North America, where a long history of tight-gas-reservoir development exists. In the absence of open natural fractures, economic development of tight gas reservoirs is possible only through the use of hydraulic fracturing, in either vertical or horizontal wells. Production enhancement for any well, whether oil or gas, can be simulated by use of combined reservoir and fracture simulators. Generally, the well-productivity increase can be calculated to a certain degree. For tight gas wells, improved well productivity often is overestimated by simulation programs that use fracture characteristics estimated from fracture-simulation software. Several factors may result in unrealistic production forecasting. In tight reservoirs, it is very difficult to measure kh and reservoir pressure, which are needed for basic flow calculations and are crucial for evaluating stimulation success. The problem arises because of the long time required to measure these parameters in post-fracture well tests. Prefracture-treatment well tests also are time consuming, but have the further problem that it is difficult to know the height of the flowing zone, and it is not desirable to perforate the entire interval in a well that is going to be fracture stimulated. An additional problem in tight gas reservoirs is evaluating the performance of the propped fracture to optimize the stimulation design. Estimating productivity after stimulation requires use of estimated values for fracture dimensions (length, width, and height) and fracture conductivity, all of which are difficult to quantify from well-test or production data without an accurate estimate of the kh. Fracture diagnostics can provide an indication of the created height and length, but reveals nothing about the effective producing-fracture length or height. Estimating kh from diagnostic injection tests is possible, but this method suffers from not knowing the height of the formation being investigated.

Technology Focus: Well Construction (May 2011)

Technology Focus This year, most of the well-construction papers focused on long-term durability in high-pressure/high-temperature (HP/HT), tight gas/-shale, steamflood, and carbon-capture and -storage (CCS) environments, a shift toward nonconventional wells. Previously, we discussed the growing awareness of the value of measuring cement mechanical properties and modeling mechanical stresses imposed upon the cemented annulus in HP/HT, deepwater, and steamflood applications. Recognition of the technology’s value has now expanded into CCS and tight gas applications. Paper SPE 139668 discusses the many aspects and value of modeling cement-placement mechanics, cement mechanical properties, and imposed stresses. It also provides excellent tutorial insight into the complexity of modeling cement behavior in fluid and solid states. As discussed last year, lost circulation and narrow pore-/fracture-pressure windows remain key challenges in achieving casing points and targeted cement coverage. Paper SPE 130319 details field results for drilling a liner to setting depth and cementing it with a new automated managed-pressure-drilling system while providing a nearly constant bottomhole pressure, a very promising technology. Traditionally, casing- and tubing-design engineers have used a deterministic stress-limits approach that uses the API Bulletin 5C3 and the von Mises criterion. However, depending upon which of the different empirical equations and safety factors are used, the resulting tubular design may be significantly over- or underdesigned. Paper SPE 134550 details a new design methodology that uses a 3D finite-element model, variation in tubular dimensions, sensitivity modeling, and stochastic study to develop a better design specification. Manny Gonzalez, SPE, Alliance Manager for Chevron ETC, noted that when applying new metallurgies, such as titanium and high-end corrosion-resistant alloys, this statistical approach becomes critical because there is no single guide for use of the current API formulas. Well Construction additional reading available at OnePetro: www.onepetro.org SPE 142150 • “Ongoing Development of Cementing Practices and Technologies for Kuwait Oil Company’s Deep HP/HT Exploration and Gas Wells—Case History” by M.J. Al-Saeedi, SPE, Kuwait Oil Company, et al. SPE 132541 • “Determining Production-Casing and -Tubing Size by Satisfying Completion, Stimulation, and Production Requirements for Tight-Gas-Sand Reservoirs” by Y. Wei, SPE, C&C Reservoirs, et al. SPE 131489 • “Solid-Expandable Tubular Combined With Swellable Elastomers Facilitates Multizonal Isolation and Fracturing, With Nothing Left in the Wellbore To Drill, for Efficient Development of Tight Gas Reservoirs in Cost-Effective Way” by M. Ghufran Anjum, University of Engineering & Technology, Lahore, Pakistan, et al.