Fractured Carbonate Gas Reservoir Research Articles

Plugging Efficiency in Fractured Carbonate Gas Reservoirs Using Fuzzy-Ball Fluids Combined with Solid Plugging Agents

Loss encountered during workover operation is a common challenge in the development of fractured carbonate gas reservoirs. Fuzzy-ball fluid, a non-solid phase plugging material developed based on Fuzzy Sealaplugging Theory, has been widely used in killing the well. However, in the plugging of fractured carbonate gas reservoirs, a substantial volume of Fuzzy-ball fluid is required and the pressurization process is time-consuming, which greatly impairs its application. In this study, solid plugging agents including calcium carbonate and fibers are introduced into Fuzzy-ball fluids to improve the plugging efficiency of large-scale macro-fractures. In particular, the plugging performance was evaluated by the indoor plugging of a synthetic core containing a 5 mm wide wedge-shaped fracture, as well as by field trials in two wells. The results show that the plugging ability of the new fluid increases as the concentration of calcium carbonate or fiber increases. Moreover, a more significant enhancement of plugging efficiency was achieved by fibers. In field applications, the use of Fuzzy-ball fluids with calcium carbonate or fibers reduced the volume of fluid consumed by 33~74% and decreased the pressurization time by 33~69%. Therefore, by combining solid plugging agents with Fuzzy-ball fluids, the dual demand for plugging efficiency and cost-effectiveness for fractured carbonate gas reservoirs is achieved simultaneously, which provides an alternative technique for addressing fluid loss in fractured carbonate gas reservoirs.

Numerical simulation study on the bottom-water invasion in the carbonate gas reservoir with high angle fractures and high permeability zones

Numerical simulation of carbonate gas reservoir with bottom-water is still a challenging issue, due to the presence of nature conductive fractures. When the water invades into the gas well, the permeability of gas phase decreases sharply. The high angle fractures and high permeability zones have a serious impact on the production performance of the gas wells. The characteristic of the water invasion was unpredictable in conventional dynamic analysis.In fractured carbonate reservoir, the geometric shapes of the angled fracture are difficult to be described using commercial numerical simulation software. The method that calculating the pseudo relative permeability of the grid block containing high angle fracture was utilized in this paper. Through this method, the rapid water advancement in the conductive fracture was accurately tracked without modifying the grid geometry, and the influence of the conductive fracture to the water breakthrough phenomenon was studied by using the IMEX module in CMG. The results show that the water invasion intensity depends on the conductivity of fracture, and the higher the conductivity is, the shorter the water breakthrough time is. The breakthrough time of water is affected by the angle of the fracture, the relative horizontal distance, the length of the fracture, the production rate and the type of water invasion. According to the characteristic curve, the type of water invasion can be quickly distinguished, which provides a basis for further study on the enhanced recovery of the fractured carbonate gas reservoir with water.

Experimental study on water invasion mechanism of fractured carbonate gas reservoirs in Longwangmiao Formation, Moxi block, Sichuan Basin

Fractured carbonate gas reservoirs feature high heterogeneity and difficulty in development, and the invasion of edge and bottom water intensifies the complexity of exploitation of such gas reservoirs. In this study, reservoir cores with a permeability of 0.001 mD, 0.1 mD, and 10 mD were selected by analyzing the fracture characteristics of the Longwangmiao gas reservoir, and water invasion in fractured carbonate gas reservoirs with edge and bottom water was simulated using an experimental system to investigate the effects of different parameters on gas reservoir exploitation. The results show that the larger the water volume ratio, the more serious the water invasion and the lower the recovery factor. But water aquifer did not strongly affect the recovery factor once the water aquifer exceeded a critical value. The higher the gas production rate, the faster the water invasion and the smaller the recovery factor. The recovery factor peaked when the gas production rate was equivalent to the gas supply capacity of the matrix to the fractures. For gas reservoirs with the overall permeability, the higher the matrix permeability, the higher the recovery factor. Although an appropriate fracturing scale was able to enhance the recovery factor when its matrix permeability was low, an excessive fracturing scale would cause water to flow along the fractures at a rapid rate, which further caused a sharp decline in the recovery factor. With the increase of matrix permeability, fractures exerted a decreasing effect on gas reservoirs. These results can provide insights into a better understanding of water invasion and the effects of reservoir properties so as to optimize gas production in fractured carbonate gas reservoirs.

A New Leakoff Analysis Approach for Acid Fracturing in Naturally Fractured Carbonate Gas Reservoirs

A New Leakoff Analysis Approach for Acid Fracturing in Naturally Fractured Carbonate Gas Reservoirs

Comprehensive study of fracture flow characteristic and feasibility of hybrid volume stimulation technique in tight fractured carbonate gas reservoir

Tight fractured carbonate reservoirs are difficult to obtain industrial oil and gas flow through conventional stimulation methods. The traditional stimulation techniques such as hydraulic fracturing and acid fracturing do not perform well in such reservoirs due to poor formation properties. Therefore, a novel stimulation technique named hybrid volume stimulation (HVS) is put forward. This technique consists of three stages, which are pad fluid fracturing, large-scale acid fracturing and proppant injection. The core idea of this technique is to create a complex fracture system with c conductivity to get further control of the reserves.In this study, laboratory tests were performed on reservoir rock samples to evaluate the stimulation effect and feasibility of HVS. Effects of pad fluid fracturing on carbonate rocks with pre-existing natural fractures were investigated. Then, features of acid dissolution on tight matrix and natural fractures in different cementing degrees were revealed. Moreover, fracture conductivity provided by different propping types was measured and the equivalent conductivity of the fracture system was calculated.The results showed that the natural fractures were extended and the induced fractures were created after pad fluid injection. Gelled acid could dissolve the cement in the partially cemented fractures and connect the fractures into one system. The propped fractures could provide enough conductivity under both high and low closure stress, while the un-propped conductivity was very limited. The acid-etched fractures might provide enough conductivity under low closure stress, however, as the closure stress increasing, it reduced to the same order of magnitude as un-propped ones. The equivalent conductivity of the fracture system was 3–4 times higher than that of the double-wing fracture, verified the feasibility and effect of HVS technique in tight fractured carbonate formations.

How to Address Subsidence Evaluation for a Fractured Carbonate Gas Reservoir Through a Multi-disciplinary Approach

This paper presents and discusses the outcome of a multi-disciplinary study aimed at evaluating ground surface movements which could be potentially induced by the future gas production of a carbonate reservoir located in central Italy. Thanks to both good quality and quantity of data (i.e. seismic surveys, well logs, petrophysical data, PVT-PressureVolumeTemperature-fluid data, geotechnical lab data) the issue was addressed via the set-up of a coupled 3D fluid flow and mechanical model based on the preliminary definition of a 3D structural and geological model. Because it is a forecast study, no model calibration was possible, consequently a set of sensitivity analyses were performed so as to assess the effect of the most critical parameters on subsidence evolution. The 3D FEM (Finite Element Method) mechanical model was set up by adopting an elasto-plastic constitutive law. The model was populated via the integration of data from different sources at different scales (i.e. lab tests, in situ acquisition, literature) and data interpretation adopting a traditional rock mechanics approach, in other words Bieniawski classification and the Barton classification. The obtained strength and deformation parameters depend on the Hoek and Brown criterion and the GSI classification application.

Developing a new NMR-based permeability model for fractured carbonate gas reservoirs

Fractured gas-bearing carbonates are dual porosity media characterized by their complex pore structure and heterogeneity. In reservoir evaluation, the pore fluids could accurately be characterized by nuclear magnetic resonance (NMR) well logging. However, the NMR-based permeability models of fractured carbonates are limited due to lack of understanding of how fractures affect NMR T2 spectrum. Based on the inevitable influence of fractures on reservoir permeability conditions, the current research investigates the effects of different fracture parameters on the resultant T2 spectrums and permeability values of the fractured gas-bearing carbonates. Firstly, a carbonate core sample having no fractures was scanned by CT imaging and its digital model was reconstructed by digital core algorithms. Secondly, fracture having various parameters dip angle, length, aperture and density were inserted into that digital core model to represent different fractured carbonate rock. In the next step, random walk simulation and lattice Boltzmann method were respectively used to simulate corresponding T2 spectrums and permeabilities of these models. We introduced a new kind of spectrum called ‘T2 spectrum of fractures’ or ‘T2f spectrum’ and used it to study effects of different fracture parameters on the NMR T2 spectrum. Finally, based on the quantitative analysis, a novel permeability model was presented for the fractured carbonates. Combined with nuclear magnetic resonance well logging data, this novel approach was used in the interpretation process of well logs. Compared to the existing models of permeability, this new model better matched the real-field permeabilities and greatly improved the accuracy of permeability interpretation in the studied fractured carbonate gas reservoir.

Numerical study of the gas-fluid displacement invasion behavior in a fractured carbonate reservoir

Gas-fluid displacement (GFD) invasion occurs frequently when drilling in fractured carbonate gas reservoirs. GFD invasion is a type of gas cut that is difficult to discover and is not widely known. In this study, the GFD invasion behavior was simulated based on the volume of fluid (VOF) method using a multidimensional two-phase flow model under different conditions and Fluent 6.3 software. The causes and process of GFD invasion were also explored. The effects of fracture width, drilling fluid viscosity and pressure difference were studied. The results show that the gas pressure increases because drilling fluid invades the fracture. Finally, GFD invasion occurs when the gas pressure is greater than the downhole pressure. A fracture width between 0.2 mm and 0.5 mm causes GFD invasion to obviously occur, and as the width increases, GFD invasion occurs more easily. Increasing the drilling fluid viscosity can postpone the GFD invasion to some degree. A small positive pressure difference between the wellbore and the fracture causes a more obvious GFD invasion. These results are also helpful for preventing and correcting GFD invasion.

Acid Leakoff Mechanism in Acid Fracturing of Naturally Fractured Carbonate Gas Reservoirs

In acid fracturing, excessive acid leakoff is thought to be the main reason that limits fracture propagation and live acid penetration distance, so its very important to do research about acid leak-off on naturally fractured carbonates. we developed a new model in this paper to simulate acid leakoff into a naturally fractured carbonates gas reservoir during acid fracturing. Our model incorporates the acid-rock reaction on the fractured surfaces. Given the information of the Puguang gas reservoir, the model predicts acid filtration and leakoff rate over time. In this study, we found that acid leak-off mechanism in naturally fractured carbonates is much different from that in reservoirs without natural fractures. The leakoff volume is several times of nonreactive acid. Since the acid widened natural fractures, leakoff velocity increase with time firstly , then decrease. While the leakoff velocity of the nonreactive fluid decrease sustained. We also analyze other sensitivity parameters of the acid leakoff. In this model, we explain the acid leakoff mechanism in naturally fractured carbonates, and provide a more accurate calculating of fluid loss.

ABSTRACT: Predictive Modelling of Water Breakthrough in a Fractured Carbonate Gas Reservoir

ABSTRACT: Predictive Modelling of Water Breakthrough in a Fractured Carbonate Gas Reservoir