Optimizing Hydraulic Fracturing Treatment Integrating Geomechanical Analysis and Reservoir Simulation for a Fractured Tight Gas Reservoir, Tarim Basin, China (original) (raw)
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International Journal of Petroleum Engineering, 2018
We investigated the impact of the friction reducer, nonionic surfactant and slugs of dilute HCl on the Eagle Ford and Marcellus shales permeability during hydraulic fracturing pad stage. Moreover, we examined injecting of a nonionic surfactant or slugs of 3% HCl when the slickwater was used in the pad stage. Lastly, we investigated the impact of pumping slugs of 3% HCl when a nonionic surfactant was added to the slickwater pad fluid. Throughout fracturing pad stage, the polymer adsorption reduces both of the fluid loss and fluid flowback. However, the nonionic surfactant and HCl acid increase the fluid loss. The results recommended injecting slugs of a nonionic surfactant for both of the Eagle Ford and Marcellus shales when the pad fluid was a slickwater. Moreover, pumping slugs of 3% HCl was only recommended for the Eagle Ford when the nonionic surfactant was added to the slickwater pad fluid.
SPE Annual Technical Conference and Exhibition, 2010
This paper presents an application of the wiremesh hydraulic fracturing model to analyze slickwater fracturing stimulation treatments of three Barnett Shale horizontal gas wells. For each treatment stage, the created hydraulic fracture network (HFN) was characterized on the basis of associated microseismic events distribution, treatment data, and geomechanical properties of involved formation layers. A systematic analysis of all stages, such as the potential effect of earlier treatment stages on a later one, the relationship between HFN properties such as the fracture surface area and treatment parameters, etc, was also presented. The information obtained was then applied to examine proppant placement in each of the HFNs. Potential ways of treatment improvement and optimization for future jobs are discussed based on these analyses.
Impact Of Fracturing And Drainage-Wide Production On Tight Gas Reservoirs
Hydraulic fracturing has been established as perhaps the most compelling and attractive production enhancement technique for both conventional and tight gas reservoirs. However a number of formation evaluation considerations must be accounted such as the location and distance of water and hydrocarbon contacts, layering and other barriers which could limit achievable production results.
Gas production from ultra-low permeable shale resources declines drastically at early times upon which organically rich undrained zones are still left at high gas content. In order to enhance nearly flat gas production rates, re-fracturing virgin zones using the newly emerged technologies has been widely implemented in the past few years. Therefore, numerical optimizing tools for re-fracturing must capture several production steps including the irreversible reservoir conditions; the depleted reservoir pressure and the associated fracturing fluid pore blockage close to hydraulic fractures. These have not been considered in the production models in the literature. In this paper, we introduce a multi-step production model including intermediate fracturing fluid injection and soaking time, followed by a detailed sensitivity analysis for the most influential parameters in gas production. A synthetic shale gas reservoir model is created with logarithmically spaced, locally refined grids (LS-LR) inside the stimulated reservoir volume to accurately capture the physics of flow in shale gas reservoirs. This model consists of the following sequential steps: 1) production from the first set of hydraulic fractures and well shut-in at the re-fracturing time; 2) activation of the second set of hydraulic fractures induced by re-fracturing, and fracturing fluid (water) injection into all fractures to simulate the fracturing fluid invasion into the matrix; 3) fracturing fluid soaking period; and 4) production from the renovated fracture network (the new and old hydraulic fractures). This model provides a mechanistic approach to include and simulate the following obstacles in gas production enhancement using re-fracturing: 1) reservoir pressure depletion in the initially stimulated reservoir volume as the depleted reservoir pressure cannot strongly repel the invaded fracturing fluid out of the matrix; 2) deep fracturing fluid invasion due to the pressure depletion and the alteration of single phase flow to two phase flow. The results showed that the pressure depletion and the resultant water retainment in the pore space reduced the production enhancement by 5% compared to the base case without these effects. This modification in gas production can influence the risk assessments for further investment on re-fracturing a field yet producing at low rates, and may revise the number of considered fields for re-fracturing.
Hydraulic fracturing in tight gas sandstone reservoirs increases the connectivity of the well to more reservoir layers and farther areal regions, thus boosting the production as well as the net-present-value of the project. When comparing different well performances, wells that far outperform other wells are usually connected to high permeability streaks or natural fractures. This paper demonstrates the analysis and performance evaluation of hydraulic fractures that are connected to high permeability streaks or natural fractures. In order for oil and gas operators to consider the development of tight gas sandstone reservoirs economically feasible, stimulation operations such as a large hydraulic fracture treatment of the wells are required. However, the induced fracture is not the main reason for the success of many of the field development in tight gas sandstone reservoirs. In the Southern North Sea, the more productive multiple hydraulically fractured horizontal wells (MHFHW) are ...
Petroleum Science and Technology, 2010
Worldwide there are vast reserves of natural gas trapped in tight sandstone formation and due to the low viscosity of natural gas it can be easily recovered. To produce this huge amount of reserve from low permeability formation economically, hydraulic fracturing can be applied. Therefore, the objective of hydraulic fracturing for well stimulation is to increase well productivity by creating a highly conductive path (compared to reservoir permeability) a distance away from the wellbore into the formation. The post treatment performance provides a good indication of stimulation success, whereas, pressure transient (PTA) and production data analysis for hydraulically fractured vertical well remains the most applied method to determine the reservoir and fracture parameters. Therefore, this analysis is a key element for optimization of hydraulic fracturing process and forecasting well performance. This paper discus the analysis of pressure and production data from hydraulically fractured vertical well in low permeability sandstone reservoir. Whereas, Pressure transient analysis is used to evaluate the effective fracture parameters such as fracture half-length, fracture conductivity and reservoir properties. Field example of application of production data analysis for vertical fractured well are presented. The aim of this study is to evaluate the gas well productivity as a result of hydraulic fracturing treatments compared to the pre fracturing productivity and to estimate the petrophysical properties of the gas well from MIT testing data. Moreover, a discussion of how significant the increment in gas productivity was achieved with a very high propped fracture treatment success rate, is also presented. Furthermore, a view of how the correct design of fracture treatments can enhance reservoir performance and the recovery rate is discussed in details.
A Practical and Economical Fracturing Solution For Low Permeability Shallow Reservoirs
Journal of Canadian Petroleum Technology, 2003
Fluid cost saving is critical for fracturing operations in low permeability reservoirs where the production revenues are low but the job size is relatively large and the fluid cost is high. Cross-linked fluids (CLF) are usually the first option. However, they may cause significant damage to both propped fractures and formations, and are not the cheapest option. Polymer-free fluids, on the other hand, cause much less damage but they are expensive and fluid costs may impair the economic results of fracturing. Waterfrac would be a compromise solution for low permeability reservoirs since its fluids are cheap and fluid damage is low. The success of waterfrac with low slurry concentrations is, however, difficult to predict. This paper presents a new fluid system that was formulated to maximize the economic return of fracturing wells in low permeability shallow oil reservoirs. It is a solid-free, linear, synthetic polymer-based system with a very low formation damage characteristic. The new fluid system can meet a variety of fracturing requirements, including slurry concentrations of conventional field levels. Moreover, it is much cheaper than cross-linked guar gel (CLGG). The method for designing fluid components and the procedure for preparing the fluid to achieve minimum formation damage and minimize the cost are described. A comparison of the production performances from the same well or adjacent reference wells fractured with the new fluids and CLGG is made. The reservoir geology, fluid type, and operation data of fracturing, and well performances from more than 300 successful wells in three different low permeability shallow oil reservoirs (800 1 ,500 m depth) are also presented in detail.
Geomechanical Principles of Hydraulic Fracturing Method in Unconventional Gas Reservoirs
International Journal of Engineering, 2018
Unconventional gas production from shale formation is not new to oil and gas experts worldwide. But our research work was built around hydraulic fracturing technique with focus on the Perkins Kern-Nordgren (PKN) 1972 hydraulic fracturing model(s). It is a very robust and flexible model that can be used on two major shale reservoirs (with the assumption of a fixed height and fracture fluid pressure). The essence was to compare detailed geo-mechanical parameters extracted from wire-line logs with Perkin-C model to select the right well as candidate for simulation. It aided in the prediction production of shale gas from tight shale formations. These also helped in reviewing safe and economical ways of obtaining clean energy sources. Based on similarities in well and formation properties our research team subjected IDJE-2 well (located in the Agbada shale Formation of Niger Delta, Nigeria) to various conditions, equations and assumptions proposed by the study model while also validating our results with the PENOBSCOT L-30 well, located in Canada (with existing profound results from stimulations). The PENOBSCOT L-30 well (Case 1) and IDJE-2 well (Case 2) were both subjected to same conditions, equations and assumptions as applicable to the study model to enable us compare and evaluate stimulation performances. But both cases tend to react differently. However the fluid behavior at constant injection time increases at about 99.64%. Whereas, the maximum width at wellbore shows that a constant increase of fracture width will yield an increase in propant permeability, tensile strength and Poisson's ratio for Case 1 & 2. Our research results show how rock properties can affect fracture geometry and expected production rates from stimulated shale reservoir formations.