Modified G-Function and Double-Logarithmic Pressure Analysis for Complex Fractures in Volume-Fractured Tight Gas Reservoirs

ABSTRACT: The channelized tight sandstone gas reservoir in Jinqiu gas field, China, is mainly produced with hydraulic fractured horizontal wells. Currently, the fracturing parameters (e.g, cluster spacing and injection volume) are optimized with given sand body shape, which has strong limitations when applied to complex sand body geometries in practice. In this work, we try to construct a method to find the optimal parameters for arbitrarily shaped sand. First, a surrogate model for fracture geometry prediction based on numerical simulation results is built using a deep neural network (DNN). Then, the embedded discrete fracture model (EDFM) is used to characterize the fractures and evaluate the effectiveness of different fracturing designs. With the above models, we first find the optimal designs of fluid injection volume and fracture spacing for difference reservoir types and sand height/length. Optimization for horizontally and vertically curved sand bodies are then conducted to show the impact of sand geometries on fracturing parameter designs. The surrogate model proposed in this work helps to quickly predict the fracture geometries, which makes it possible to optimize fracturing parameters with optimization algorithms. 1. INTRODUCTION Tight gas, due to its advantages such as widespread distribution and abundant reserves, has occupied a key position in the development of unconventional natural gas in China (Zeng et al., 2024). Compared with conventional gas reservoirs, tight gas reservoirs usually have characteristics such as low porosity, high water saturation, and low permeability, making the optimization of fracturing parameters more complex (Zhang et al., 2022). The Shaximiao reservoir in the Jinqiu gas field is a typical tight gas reservoir, with porosity ranging from 8% to 16%, averaging 12.31%, and permeability ranging from 0.01 mD to 1 mD. The channel width is 200 – 4800 m and the sand thickness is 5 – 40 m (Fig. 1 and Fig. 2). The Jinqiu gas field is a typical narrow channelized sandstone gas reservoir, which is mainly produced with hydraulic fractured horizontal wells. To further increase the production, it is necessary to optimize the fracturing parameters considering the sand body geometries.

Many tight gas wells show transient linear flow that lasts for many years. Linear flow is normally associated with hydraulic fractures, but tight gas reservoirs may contain geometrical effects that lead to linear flow behaviour. In this study, long-term linear flow caused by the presence of natural parallel fractures is investigated and a systematic procedure to analyze linear flow in tight gas wells is described. Application of this methodology to production analysis of three tight gas wells, and validation of the results by using numerical simulation, is described. Introduction Linear flow is characterized by t behaviour during transient flow. This is sometimes associated with hydraulically fractured wells with linear flow perpendicular to the fracture. At the end of linear flow, the pressure response (for a constant rate solution) of these wells flatten as flow enters from outside the fracture tips(1,2). However, this paper refers to observed well behaviour in which the pressure response becomes steeper at the end of linear flow, indicating an outer boundary effect. For these wells, there appears to be only linear flow during transient and outer boundary dominated flow. Actual field data shows long-term linear flow for years in a large number of wells(3–12) because of the extremely low permeability. A "half slope" (slope = 0.5) on a log-log plot of [m(pi) [m(pwf)]/ Qg vs. t for either constant gas rate production, qg, or constant bottomhole flowing pressure, Pwf, indicates linear flow. Long-term linear behaviour has been reported in tight gas wells which have no or not particularly large fracture treatments(7, 9, 11). The reason for linear flow may not be known for a particular well. But several papers discuss physical scenarios which may cause linear flow(5, 7, 11, 13, 14), including the occurrence of natural fractures. Tectonic stresses determine the direction of natural fractures. These natural fractures may tend to be parallel to the hydraulic fracture plane and cause linear flow even if the hydraulic fracture length was limited. However, if the tectonic stresses have changed since the formation of the natural fracturing, the hydraulic fracture could have a different orientation from the natural fractures(15). In this paper, we discuss how parallel natural fractures lead to permeability anisotropy and cause long-term linear flow. We show several field examples and outline a stepwise procedure for analyzing wells with long-term linear flow. Linear Flow Due to Anisotropy Parallel Natural Fracturing Long-term linear flow in tight gas wells may develop because of large permeability anisotropy ratios. Anisotropic permeability in porous medium has been examined in several papers(15–25) and books(26–31). One of the most important reasons for anisotropic permeability is parallel natural fracturing. Figure 1 shows a sketch of a well in a closed square with a parallel natural fracture system. In order to calculate the effect of the natural fractures on permeability, we assume that the natural fractures are continuous in the x direction and there is a regular spacing between fractures, dA, in the y direction.

The increased demand for more sources of clean energy such as natural gas from unconventional reservoirs has forced the industry to explore the more challenging tight gas reservoirs. Tight gas reservoirs constitute a significant proportion of the world's natural gas resource and offer great potential for future reserve growth and production. However, to meet future global energy demand, access to tight gas reservoirs requires innovative and cost effective technical solutions. Yet, tight gas reservoirs are often characterized by complex geological and petrophysical systems as well as heterogeneities at all scales. Exploring and developing tight gas accumulations are both technically and commercially challenging due to the large subsurface uncertainty and low expected ultimate recovery per well. In addition, formation damage is an undesirable operational and economic dilemma that may occur during any phase of gas recovery from tight gas reservoirs. Tight gas reservoirs normally show significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques. The main damage mechanisms and the factors that have significant influence on well productivity in tight gas reservoirs include mechanical damage to formation rock, plugging of natural fractures by mud solid particles invasion, relative permeability reduction around wellbore as a result of filtrate invasion, liquid leak-off into the formation during fracturing operations, water blocking, damage due to wellbore breakouts, compression damage and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occur through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures. Prevention, control and remediation of formation damage are among the most important issues to be resolved for efficient exploitation of tight gas reservoirs. Designing certain chemicals and/or treatment procedures for damage control and remediation is not an easy scientific and engineering task. Good understanding of the formation damage mechanisms would allow operators to make informed decision as to the best practices to drill, complete and produce tight gas wells. In this paper, a review of commonly practiced methods and tools available for prevention, control and remediation of formation damage will be discussed and presented.

Crossplots of porosity vs. permeability from various North American basins show that there is a continuum between conventional, tight and shale gas reservoirs. This is significant as some of the key issues, particularly in shale and tight gas reservoirs, are having good estimates of storage and flow capacity. The crossplots include data from the Fayettville, Barnett, Ohio and Marcellus shales in the United States; Horn River and soft shales in Canada, tight gas Nikanassin formation in Canada and several conventional North American gas reservoirs. The data used in the crossplots have been obtained from plugs, crushed samples and drill cuttings. The results permit integration of the storage and potential gas deliverability for determining flow units and other important characteristics such as brittleness and/or ductility, hydraulic fracturing alternatives, effect of water saturation and mud filtrate; and differentiation between viscous and diffusion dominated flow. Examples of simulation at the pore throat level, from which it is possible to estimate petrophysical, rock-fluid interaction and rock mechanics properties, are presented. The storage and flow capacity in the case of stacked layers, or lateral variations of conventional, tight and shale gas formations, are discussed in detail. The data suggest that permeability determinations from crushed shale samples might be pessimistic as they do not take into account the possible presence of microfractures and pores in organic matter within shale matrix. It is concluded that crossplots of porosity vs. permeability are very powerful for distinguishing and evaluating storage and flow capacities of conventional, tight and shale gas reservoirs. The concept of flow units in shales and tight gas, and its differentiation from conventional formations, should prove powerful in future simulation work.

The limitation of conventional hydraulic fracturing with two long wings of coplanar fractures is well recognized in the context of naturally fractured tight gas or Hot Dry Rock (HDR) geothermal reservoirs. This paper presents a 3D model for an alternative stimulation technology for such reservoirs. The model stochastically simulates actual reservoir representative natural fractures processing field data available from cores and logs. These simulated fractures are then analyzed for deformations with the combination of simple elastic structural mechanics and linear elastic fracture mechanics principles coupling with the injected fluid pressure and in-situ stresses. Finally, the hydraulic conductivity and the reservoir growth pattern are formulated as functions of fracture deformations.The applicability of the model has been verified using the data of actual fracture stimulation programs conducted in the Hijiori HDR site. It has been found that the model is capable of simulating actual natural fracture distribution in the reservoir. The model is finally applied to a series of numerical analysis with central Australian reservoir conditions to investigate the sensitivity of natural fracture parameters (e.g. size, density and orientation) and in-situ stresses to reservoir growth and conductivity. It is observed that the reservoir growth pattern is mainly influenced by fracture parameters and the relative magnitude and direction of in-situ stresses. Reservoirs with predominantly strike-slip and reverse faulting stress regimes and high deviatoric stresses are favorable for horizontally dominant reservoir growth - a pattern which is highly desirable for efficient HDR geothermal energy extraction. The information provided in the paper is directly applicable to HDR geothermal reservoir development with a high potential for new applications in tight gas reservoirs in which the abundance of natural fractures is so far posing significant complexity to conventional hydraulic fracturing, resulting in multiple fractures, high treatment pressure and premature screen-out.

The primary objective of hydraulic fracturing is to create a propped fracture with sufficient conductivity and length to maximize or at least optimize well performance. In permeable reservoirs where transient flow is short lived, a fracture with a Dimensionless Fracture Capacity, FCD, of 2 is required to meet the design objective. In low permeability formations where transient flow can be extensive and where fracture fluid cleanup requires additional conductivity, an FCD in excess of 10 is desired. As a result, reservoir permeability becomes/is a key fracture design and analysis parameter. In higher permeability applications, permeability is determined simply, inexpensively, and routinely through conventional well testing techniques. Conventional well testing in tight formation gas reservoirs has not been proven as effective, can be expensive (cost of lengthy tests and production deferment), and is quite simply not routinely utilized. These reservoirs are often non productive without fracture stimulation and post fracture stimulation testing requires extensive shut-in time as the time to pseudo radial flow is proportional to the square of the fracture half-length. As a result, the development and routine use of any technique to determine permeability in these tight formation gas reservoirs has great value. In addition, without adequate well testing techniques and capabilities in tight gas reservoirs, the engineer is left with the use of log derived values of permeability which can often overstate in-situ permeability by factors of five to ten. Determination of in-situ permeability not only aids the well completion and stimulation but can be used to calibrate the log and core derived estimates of permeability improving performance predictions and field development. Prior papers have developed the use of After Closure Analysis techniques in permeable reservoirs, this paper will show the application of this technique to several tight gas formations in North America. This paper will demonstrate the following: The effective application of this technique in tight gas formations in the U.S. and Canada,Develop a cost effective and operationally simple means of collecting and analyzing the data,Compare and contrast the technique to other methods of determining permeability in tight formation gas reservoirs, such as impulse, Perforation Inflow Diagnostic (PID), Closed Chamber Drill-Stem Tests (CCDST), post-frac build-up, production decline analysis, Modular Dynamic Formation Tester (MDT).Show the application and value of calibrating log and core-derived permeability with in-situ measurements for improved well performance predictions.

Model of cross-flow interference index and application for multi-layer commingled production in Sulige tight sandstone gas reservoir, Ordos Basin, China

It is clear that the characteristics of water production and effusion in horizontal wells of tight gas reservoirs can predict the water production trend and regularity of horizontal wells in advance, and reduce the damage of produced water to gas well productivity. According to the law of gas production in horizontal wells of tight gas reservoirs, the dynamic and static factors affecting the production of tight gas are analyzed, and the parameters related to the characteristics of effusion are optimized. Combined with the cluster analysis method, the horizontal wells of tight gas reservoirs are divided into different categories. The dynamic parameter variation characteristics of the liquid well are conducive to correctly identifying the effusion law of the gas well. The results show that the characteristics of water-bearing effusion in horizontal wells of tight sandstone gas reservoirs are not only related to horizontal well types, but also dynamically change with production time; the same horizontal wells have different production capacities at different times and have different effluent characteristics and trends. The study suggests that the effusion phenomenon of horizontal wells in tight sandstone gas reservoirs is a comprehensive reflection of reservoir physical properties, gas seepage and fluid flow capacity in horizontal wellbore. A large number of production dynamic data can reflect the effusion characteristics of horizontal wells in tight gas reservoirs; The big data clustering analysis method can identify the different characteristics of horizontal well effusion, and has guiding significance for the treatment of horizontal well effusion in tight gas reservoirs.

Integration of conventional logs, core and 3-D seismic with borehole images provide a reliable and decent approach to geological modeling in tight clastics deep gas reservoirs in Oman. The Studied field is of Cambrian-Ordovician age. The field structure is North-South elongated domal anticline associated with a salt pillow.The main hydrocarbon bearing and producing reservoirs are predominantly of continental to marine environments in the deepest part: aeolian dominated formation (A) to sabkha dominated formation (B) in middle intervals and non-marine (coastal plain) to shallow marine (intertidal-subtidal) (C) sandstone members at the shallowest levels.The seismic image quality at the reservoir levels are poor, mainly due to the weak acoustic impedance contrast between deep reservoirs and the overlaying shale, besides the presence of multiple noises further obscured the event, in addition to limited number of core intervals all over the field.In order to refine the structural, depositional model and facies distribution for clastic tight gas deep reservoirs, a detailed integrated borehole resistivity images log interpretation with the available data was performed. Structural dip, structural features like faults locations and their strike and dip angles, sub seismic faults for field transmissibility, and compartments, natural fractures, sedimentological and facies analysis where core - logs comparison was done to improve the rock typing which later correlated to the petrophysical properties, are the major achievements from this study. The study has also analyzed the major accumulations and the paleo-current and paleo wind directions over the reservoirs units by predicting their paleo-drainage and sediments entry points. These results formed valuable input to the field geological modeling.The exercise of tying the above results with seismic data was carried out with a very effective methodology for the generation and significant improvement of a new geological model to support further development and added new reserves in tight gas reservoirs.

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 131786, ’Integration of Microseismic and Other Post-Fracture Surveillance With Production Analysis: A Tight Gas Study,’ by C.R. Clarkson, SPE, University of Calgary, and J.J. Beierle, SPE, Talisman Energy, prepared for the 2010 SPE Unconventional Gas Conference, Pittsburgh, Pennsylvania, 23-25 February. The paper has not been peer reviewed. Quantitative production analysis of tight gas reservoirs is a challenge because of complex reservoir characteristics, induced-hydraulic-fracture properties in vertical wells, operational complexities, and data quality. These challenges make extracting reservoir and hydraulic-fracture properties (i.e., fracture half-length, xf, and fracture conductivity) solely from production and flowing-pressure data difficult, often resulting in nonunique answers. Many tight gas reservoirs are exploited with horizontal wells, often stimulated with multiple hydraulic fractures, imparting greater complexity to the analysis. Flow-regime identification, which is critical to correct analysis, becomes more complicated because of the variety of flow regimes that could be encountered in such wells. Introduction Development of tight gas, shale gas, and coalbed methane (collectively referred to as unconventional gas reservoirs) benefits from advances in drilling, completions, and stimulation technology; formation evaluation; and during-/post-stimulation-surveillance technology. Formation-evaluation techniques enable determining critical parameters such as matrix permeability in ultratight rock from cores, and adsorbed- and free-gas content in shale and coalbed methane from cores and cuttings. During-/post-fracture-stimulation-surveillance technology (such as microseismic monitoring) aids identifying the hydraulic-fracture geometry created in unconventional reservoirs (hydraulic-fracture growth), particularly in coals and shales. Predicting hydraulic-fracture geometries is complicated by heterogeneities, such as natural fractures (healed or open) and layering (with associated contrasts in mechanical properties), and in some cases, by nonlinear elastic behavior. Advanced production-analysis techniques, such as production type curves, supplement reservoir and stimulation information obtained from pressure-transient analysis (well testing) in conventional oil and gas reservoirs and even some unconventional reservoirs such as coalbed methane and tight gas. However, applying these methods to tight gas and shale reservoirs that are produced through multifractured horizontal wells has been difficult because of the complexity of the system, poor quality of flowing-pressure and rate data, and the lack of sufficient data to characterize the system fully. Even if the production and flowing-pressure data were of sufficient quality to identify flow regimes, as in pressure-transient analysis, without additional surveillance information, it is difficult to ascertain how the flow regimes relate to the reservoir and hydraulic-fracture system. If the flow regimes are misinterpreted, then the extracted information will be incorrect. A workflow is proposed to improve the quality of information extracted from production-data analysis (PDA) of hydraulically fractured horizontal wells completed in tight gas reservoirs.

Summary The Rocky Mountain region contains major gas resources in tight (low-permeability) reservoirs of Cretaceous and Ternary age. These reservoirs usually have an in-situ permeability to gas of 0.1 md or less and can be classified into four general geologic and engineering categories:marginal marine blanket,lenticular,chalk, andmarine blanket shallow. Microscopic study of pore/permeability relationships indicates the existence of two varieties of tight reservoirs. One variety is tightly because of the fine grain size of the rock. The second variety is tight because the rock is relatively tightly cemented and the pores are poorly connected by small pore throats and capillaries. Other characteristics of tight gas reservoirs are:discrete gas/water contacts are absent in lenticular and marginal marine blanket reservoirs,most of the gas occurs in stratigraphic traps,well log analysis is difficult in tight reservoirs.many Rocky Mountain tight gas basins are either overpressured or underpressured, andformation damage may occur when wells are drilled and completed. Introduction Gas-bearing, tight (low-permeability) reservoirs are present in sandstone, siltstone, silty shale, and chalk in the Rocky Mountain region. Most of the gas occurs in rocks of Cretaceous and Tertiary ages. Organic-rich dark shales and coals are the source of the gas. A combined engineering and geologic effort is needed to identify, to map, and to recover gas from tight gas reservoirs. It is particularly important that geologists working on tight gas reservoir analyses be aware of problems being encountered in well log interpretation and reservoir stimulation. It is equally important for the engineer to understand the geologic differences between tight (unconventional) and conventional gas reservoirs. Tight gas reservoirs exhibit several unique characteristics compared with conventional reservoirs. One of the most significant differences is that conventional reservoirs have a reasonably consistent relationship between porosity and permeability, whereas tight reservoirs may or may not exhibit a consistent relationship between porosity and laboratory-measured permeability except that the in-situ permeability to gas is generally less than 0.1 md. The following discussion will describe some geologic characteristics of tight gas reservoirs in the Rocky Mountain region. Types of Tight Gas Reservoirs Fig. 1 shows basins and areas within and adjacent to the Rocky Mountains that contain tight gas reservoirs. Most of these localities also contain conventional reservoirs. Many sandstone stratigraphic intervals that are tight in the deep parts of basins have conventional reservoir characteristics at shallow burial depth. Tight gas reservoirs in the Rocky Mountains are predominantly Cretaceous and early Tertiary age. They can be grouped into four general reservoir types:marginal marine blanket,lenticular,chalk, andmarine blanket shallow. Marginal Marine Blanket Reservoirs Marginal marine blanket reservoirs are strata deposited on or near a shoreline that occur within a relatively predictable stratigraphic interval. These reservoirs commonly are overlain by marine shales and may be underlain by marine shale or continental deposits. They are called "blanket" for engineering reasons and normally would not be considered blanket sandstones by geologists. Tight blanket reservoirs are strata that have relatively better horizontal continuity than lenticular reservoirs. Blanket reservoirs usually respond to hydraulic fracturing in a somewhat predictable (blanket-like) manner. When the volume of fracture proppant is increased, there is a general increase in well productivity up to certain limits. Some examples of marginal marine blanket reservoirs are the Lower Cretaceous "J" sandstone in the Denver basin, the Upper Cretaceous Upper Almond formation and the Frontier formation in the Greater Green River basin, and the Upper Cretaceous Corcoran and Cozzette sandstones in the Piceance Creek basin. The locations of these basins are shown in Fig. 1. Lenticular Reservoirs Lenticular reservoirs are reservoirs that were deposited predominantly by rivers. These fluvial sandstones are very discontinuous and exhibit many internal permeability variations. The geometry and dimensions of these reservoirs are difficult to predict. The response of lenticular sandstones to hydraulic fracturing is very erratic, and generally the stimulation results are poorer than usually possible in marginal marine blanket sandstones. Some examples of lenticular reservoirs are fluvial sandstones in the Upper Cretaceous Mesaverde group and Tertiary in the San Juan, Uinta, Piceance Creek, and Greater Green River basins. JPT P. 1308^

Faced with difficulties stemming from the complex interactions between tight gas sand bodies and fractures, when describing and identifying reservoirs, a composite reservoir model was established. By setting the supply boundary to characterize the superposition characteristics of sand bodies, a mathematical model of unstable seepage in fractured vertical wells in tight sandstone gas reservoirs was developed, considering factors such as stress sensitivity, fracture density and fracture symmetry. The seepage law and pressure response characteristics of gas wells in tight sandstone discontinuous reservoirs with stress sensitivity, semi-permeable supply boundary and complex fracture topology were determined, and the reliability of the model was verified. The research results more accurately display the pressure characteristic of a vertical well in the superimposed sand body with complex fractures and provide a more comprehensive model for tight gas production dynamic analysis and well test data analysis, which can more accurately guide the dynamic inversion of reservoir and fracture parameters.

In order to predict the nature and distribution of natural fracturing, Advanced Resources Inc. (ARI) incorporated concepts of rock mechanics, geologic history, and local geology into a geomechanical approach for natural fracture prediction within mildly deformed, tight (low-permeability) gas reservoirs. Under the auspices of this project, ARI utilized and refined this approach in tight gas reservoir characterization and exploratory activities in three basins: the Piceance, Wind River and the Anadarko. The primary focus of this report is the knowledge gained on natural fractural prediction along with practical applications for enhancing gas recovery and commerciality. Of importance to tight formation gas production are two broad categories of natural fractures: (1) shear related natural fractures and (2) extensional (opening mode) natural fractures. While arising from different origins this natural fracture type differentiation based on morphology is sometimes inter related. Predicting fracture distribution successfully is largely a function of collecting and understanding the available relevant data in conjunction with a methodology appropriate to the fracture origin. Initially ARI envisioned the geomechanical approach to natural fracture prediction as the use of elastic rock mechanics methods to project the nature and distribution of natural fracturing within mildly deformed, tight (low permeability) gas reservoirs. Technical issuesmore » and inconsistencies during the project prompted re-evaluation of these initial assumptions. ARI's philosophy for the geomechanical tools was one of heuristic development through field site testing and iterative enhancements to make it a better tool. The technology and underlying concepts were refined considerably during the course of the project. As with any new tool, there was a substantial learning curve. Through a heuristic approach, addressing these discoveries with additional software and concepts resulted in a stronger set of geomechanical tools. Thus, the outcome of this project is a set of predictive tools with broad applicability across low permeability gas basins where natural fractures play an important role in reservoir permeability. Potential uses for these learnings and tools range from rank exploration to field-development portfolio management. Early incorporation of the permeability development concepts presented here can improve basin assessment and direct focus to the high potential areas within basins. Insight into production variability inherent in tight naturally fractured reservoirs leads to improved wellbore evaluation and reduces the incidence of premature exits from high potential plays. A significant conclusion of this project is that natural fractures, while often an important, overlooked aspect of reservoir geology, represent only one aspect of the overall reservoir fabric. A balanced perspective encompassing all aspects of reservoir geology will have the greatest impact on exploration and development in the low permeability gas setting.« less

This paper investigates interaction of induced and pre-existing fracture by coupling wellbore, induced fracture and natural fracture in a poroelastic reservoir. Possibilities of fracture crossing, bending, arrest and shear dilation for various angles of approach are investigated under different scenarios: in-situ stress state, reservoir rock and fluid properties and characteristics of natural fracture. The fully coupled poroelastic model and results of this study in particular have a beneficial application in the design and optimization of hydraulic fracture treatments in naturally fractured reservoirs, therefore tight gas reservoirs and enhanced geothermal systems. The model can be extended to design stimulation of naturally fractured reservoirs based on shear dilation (high pressure low injection rate). In this paper we have demonstrated that natural fractures, faults and other discontinuities severely restrict propagation of an induced fracture. In-situ stress state, orientation and shear strength of pre-existing fracture prove to be most significant factors that influence the fracture propagation trajectory: – Because of the poro-elastic formulation it was possible to investigate the change in stress state ahead of the fracture tip and evaluate whether the fracture is going to be attracted or rejected by the interface. It was observed that high leak off influences dilation of natural fracture ahead of the arrival of the induced fracture tip. – Possibilities of fracture arrest increases with increase in high differential stress state and shear strength of pre existing fractures. – Fracture crossing is another dominating behaviour for natural fracture with small aperture while fracture dilating for natural fracture with larger aperture. Fully coupled poroelastic modelling allowed us to gain new knowledge on interaction between induced and pre-existing fractures. This methodology and knowledge base will significantly improve our current approach to design and implement hydraulic fracture treatment in naturally fractured reservoirs.

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques. The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include: mechanical damage to formation rock; plugging of natural fractures by mud solid particle invasion; relative permeability reduction around wellbore as a result of filtrate invasion; liquid leak-off into the formation during fracturing operations; water blocking; skin due to wellbore breakouts; and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occurs through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures. This study represents an evaluation of different damage mechanisms in tight gas formations, and examines the factors that can have significant influence on total skin factor and well productivity. Reservoir simulation was carried out based on a typical West Australian tight gas reservoir to understand how well productivity is affected by each of the damage mechanisms, such as natural fracture plugging, mud filtrate invasion, water blocking and perforation. Furthermore, some damage prevention and productivity improvement techniques are proposed, which can help improve well productivity in tight gas reservoirs.