Chapter 6 - Fluid-rock interactions in tight gas reservoirs: Wettability, pore structural alteration, and associated multiphysics transport

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. Appraisal of deep tight gas reservoirs offers many challenges, including production rate predictions when wells are drilled overbalanced. Overbalance leads to near wellbore damage to the rock matrix and fractures. Damage to natural fractures intersecting the well can prevent their detection leading to missed productive intervals. In addition, the operating environment is very challenging and that affects the decisions for data acquisition. The use of salt-saturated mud systems creates a contrast and uncertainty in the data. Hence, the quality of data acquired is compromised. In the 80's hydraulic fracturing of deviated wells was the method of choice for developing tight gas reservoirs worldwide. Although sound in principle, in practice problems were experienced and caused either by poor cleanup due to fluid incompatibility, erosion of surface facilities or early water breakthrough due to fracturing into the water leg. In the 90's horizontal drilling became common practice as new drilling technologies developed and proved to be very successful in many tight gas fields. However, conventional drilling operations introduced foreign fluids and solids into the reservoir which lead to several different formations damage mechanisms that prevented the identification of the gas production potential from these wells. In the late 90's underbalanced drilling (UBD) was introduced, mainly to avoid the frequent drilling problems associated with total losses into these tight gas reservoirs. However, significant productivity gains were also observed and this became a key driver to apply the same UBD technology in tight gas fields. This paper provides a technical overview of the state-of-the-art UBD technology used to develop unconventional tight gas reservoirs. Two real case histories from eastern Jordan and South West Algeria will be presented and discussed. Introduction The increased demand for more sources of clean energy such as natural gas from unconventional (tight) reservoirs has forced the industry to explore for more challenging tight gas reservoirs. New production will probably come from more difficult to produce reservoirs. In general it was accepted that static evaluation tools (logging, coring and seismic), that have proven so important for conventional reservoirs, were inadequate to characterize tight gas reservoirs and that a shift to use of dynamic flow data was needed.

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^

Unconventional resources have been identified throughout the world and contain enormous in-place volumes but tight and unfamiliar reservoirs challenge the transformation of these resources to supplies. The key issue is whether industry can grow production from unconventional reservoirs at a rate that will offset declines from older conventional reservoirs. E&P companies are attracted to such resources because they have low exploration risk, material production volumes, long-lasting production and exist near mature, stable markets. In addition, with the exception of Canadian bitumen production, current recovery factors are low so these accumulations have the potential for a substantial "technology dividend". At some 7.5 trillion barrels, estimates of the in-place resource of bitumen, extra-heavy oil and shale oil are over three times greater than the 2.25 trillion barrels of recoverable conventional oil estimated to have been discovered to date. Unconventional liquids production from Canada and Venezuela currently comprises about 2% of world liquids production. Current projections indicate these giant resources will add no more than about 400,000 barrels of annual new production. This is les than desired to offset global declines of 5 to 6 MMb/yr. Excluding gas hydrates, remaining recoverable resources of the three principal gas resource play types are estimated at over 1,000 trillion cubic feet and there is significant potential for growth in unconventional gas resources outside North America. Even though U.S. unconventional gas well completions have tripled the growth of gas from unconventional reservoirs has not offset decliines in conventional gas production. Introduction Among the three pillars of future oil and gas supplies, the unconventional resource potential greatly exceeds that of the other two pillars - growth to known fields and yet to find fields. Estimated in-place resource of bitumen, extra-heavy oil and shale oil are about 7 times greater than the estimated recoverable conventional liquids from field growth and yet to find sources. Excluding gas hydrates, estimated in-place volumes of unconventional gas are estimated to be 4 to 5 times greater than estimated recoverable conventional gas from field growth and yet to find sources. In-place unconventional resources are huge but there are substantial challenges to transform these resources into supplies. Unconventional hydrocarbons are found in tight, low permeability, low porosity, low recovery "difficult to produce" rock formations, such as tight sands, shales, chalks and coal seams. These rocks require distinctive completion, stimulation, and / or production techniques to recover the hydrocarbons. Fractures often are critical to establish economic recoveries and unconventional reservoirs may be over or under pressured and typically are not affected by hydrodynamic influences. Unconventional reservoirs often are described as "resource plays". Many are pervasive throughout a wide area and also are referred to as "Continuous -type Deposits". Realistically, the boundaries between "conventional" and "unconventional" are gradational and change over time. For purposes of this report original definitions applied some 20 years ago to define U.S. tight gas reservoirs are used. Tight reservoirs were defined as having less than 0.1 millidarcy permeability and tight reservoirs typically have 13% or less porosity. Unconventional reservoirs also were characterized by low recovery factors - often less than 10% recovery on primary recovery. Conversion-sourced hydrocarbons such as gas to liquids and coal to liquids, fermentation of carbohydrates, non-fossil renewable resources and gas hydrates are not included in this report.

Tight Gas Reservoirs (TGR) are one of the primary types of unconventional reservoirs to be exploited in the search for longlasting resources.TGR's are difficult to produce for a number of reasons. Due to their low productivity a thorough understanding is needed regarding the factors that affect gas production rate over the life of these reservoirs. This paper is focused on analyzing the effects of drainage area, gas rate, fracture conductivity, porosity, and reservoir permeability on production performance. In particular, the impact of permeability, from ultra tight (0.0004 md) to tight (0.1 md) reservoirs, on drainage area and reserves is analyzed in detail. A semi-analytical simulator is used in this study. A conceptual case study was performed comparing a hydraulically fractured vertical well with a multiple-fracture horizontal well in same reservoir. Fracture conductivity is estimated by using StimLAB proppant consortium correlations for different flow rates, which takes into account non-Darcy pressure drops and other factors. The results of this work conclude that in ultra tight reservoirs, the drainage area is significantly reduced. Only the near fracture rock is drained, and a high density of wells and fractures is needed. This behavior changes with increase in reservoir permeability. In ultra-tight reservoirs, horizontal wells with multiple fracs may be the only viable option for commercial production. A general workflow is also described as to how forecasting in such reservoirs can be made more accurate. Introduction With the increasing demand for oil and gas, and declining production from existing fields, conventional hydrocarbons cannot meet the current and future energy demands of the world. The oil and gas industry is investing in the development of methods and technologies needed to exploit unconventional resources. Fig-1 shows the resource triangle (Holditch 2006; Hein 2009) and describes how unconventional reservoirs are different from conventional reservoirs in regards to technology required for commercial exploitation and reservoir volumes. Compared to conventional reservoirs, unconventional reservoirs are larger in volume but difficult to exploit. In the resource triangle as we move towards unconventional resources, better technology in drilling and development are key factors to success. Unconventional resources include tight gas reservoirs, gas hydrates, Coal bed methane, and oil shales. This paper is focused on tight gas reservoirs (TGR). The term Tight Gas is commonly used for referring to low permeability reservoirs producing dry natural gas (Holditch 2006). Though the definition of Tight Gas Reservoirs is different in different parts of the world, there is general agreement that permeability below 0.1 mD characterizes tight gas reservoir. In some countries, for purposes of gas sale pricing, TGR can have permeability upto 1 and even 2 md. In this paper we look at permeabilities below 0.1 mD.

To understand the reservoir flow behavior and estimate its parameters (e.g., permeability, skin), either transient pressure or rate data are usually used. However, in tight reservoirs, due to the economic and technical difficulties of transient pressure well test operations and data analysis, working with transient rate data, i.e., decline curve analysis, sometimes, is considered to be more attractive. This study focuses on the application of the widely accepted Fetkovich type curves for tight gas and gas condensate reservoirs. Initially, a synthetic reservoir model was constructed to replicate one of the case histories of a tight oil reservoir studied by Fetkovich et al. (1987). Various sensitivities on permeability, skin, reservoir radius, and fluid type were performed to ensure the validity and generality of the model. The application of Fetkovich type curves was then investigated for three gas condensate fluids with various richness levels. Here, implications and limitations of this extension are highlighted when various reservoir parameters (i.e., skin and reservoir radius) are varied. Our results demonstrate that Fetkovich type curves can be used to derive reservoir parameters for tight reservoirs, but caution needs to be taken for different fluid types and production constraints. For dry gas, the Fetkovich method can directly be applied. In gas condensate systems, this method together with the gas equivalent concept gives reliable results if bottomhole pressure is above the dewpoint. Extension of this approach when bottomhole pressure is below the dewpoint, leads to erroneous results. If the preferred two-phase pseudo-pressure approach is considered in the interpretation; the results are more accurate but still not fully acceptable. The findings of this study allow better evaluation of production potentials and improved management of unconventional gas reservoirs. Introduction Holditch and Madani (2010) highlighted that worldwide gas resources from conventional reservoirs are diminishing with unconventional reservoirs playing more important roles in sustaining production to satisfy energy consumption demand. They classified unconventional gas resources into the three most common types: tight sands, coalbed methane, and shale gas. It was discussed in their work that tight gas is expected to be the greatest contributor in terms of fulfilling the production capacity in the near future. Generally, there is no specific definition for a tight gas reservoir. Naik (2013) gave examples of authors that referred to tight gas with different cutoffs. Holditch (2006) proposed a definition as a reservoir that cannot deliver natural gas at economic rate nor reach the ultimate economic recovery efficiency unless the productivity is enhanced by the use of reservoir stimulation or adapting the concept of horizontal or multilateral wellbores. It was discussed in his work that higher investment cost and more complicated technology are required to develop tight gas reservoirs. Hence, to optimize the development, a proper knowledge of the reservoir parameters (permeability, skin, etc.) is one of the keys for success. This knowledge could be acquired from either conventional well testing, which is based on the analysis of transient pressure data, or decline curve analysis, which is focused on the transient rate data.

Economical production from unconventional reservoirs including tight dolomite require some forms of stimulation techniques to increase the effective contact areas between wellbore and formation. However, productivity improvement of these formations with conventional techniques (e.g. acid stimulation) is very limited and mostly unfeasible. In this paper, an efficient chemical treatment is proposed to stimulate tight dolomite formation through wormholing mechanism and scale-based damage removal. The formation damage in tight reservoirs are much more severe due to the smaller pore/throat size. Among them, the scale-based permeability impairment or phase trapping can cause significant production lost. In this study, the proposed treatment fluid is used to remove the scale-based formation damage, mostly caused by drilling mud. To this aim, the damage removal efficiencies of dolomite cores, artificially damaged by scale precipitation, were investigated after HPHT coreflood treatment. In addition, the performance of the treatment fluid was evaluated as a mean to bypass the damaged zones around hydraulic fractures (caused by liquid phase trapping or significant net stress). To evaluate this, a series of coreflooding experiments were also performed on untreated tight dolomite cores and the feasibility of the wormholing mechanism was studied. The permeabilities of tight dolomite rocks were measured before and after the treatment. To visualize the wormhole propagation inside the cores, computed CT scanning were performed. The rock-fluid interaction was also investigated by analyzing the effluent samples by ICP. The main mechanism of this treatment technique is pore body/pore throat enlargement by slow rock dissolution. From the pore scale analysis, it is found that even at lower concentrations, the active ingredient reacts with rock minerals. A damaged dolomite core was also treated, and the results showed that the removal of Barite-based scale can be achieved even in the presence of native calcite or dolomite minerals. Also, it is found that wormholing can be only achieved at certain concentrations (>10 w%). It also depends on the injection rate and other field conditions such as temperature. Even at low concentration, the rock permeability of the damaged dolomite core can be increased by a factor of 35 (Kf/Ki=35). Finally, dolomite reservoir cores (25-30 μD) were treated at low injection rates (0.08-0.1 ml/min) imposed from the well injectivity condition. It was shown that despite an order of magnitude lower injection rate (compared to those in conventional acidizing) still an optimum injection rate is needed to extend the wormhole across the core. It is also verified that the active ingredient can be used in alcohol-based solutions for special applications such as tight gas and gas condensate reservoirs. The corrosion rate is far below the accepted corrosion level of 0.05 lb/ft2 and it is fully compatible with other additives and high salinity brines. The proposed treatment method is cost effective and experimentally proven to be efficient and long-lasting. Such treatment is recommended to tackle the low productivity of unconventional tight reservoirs. This treatment can be even applied to remove the additional formation damages usually caused during conventional stimulations such as hydraulic fracturing to boost the production.

Rapid combustion of fossil fuels in huge quantities resulted in the enormous release of CO2 in the atmosphere. Subsequently, leading to the greenhouse gas effect and climate change and contemporarily, quest and usage of fossil fuels has increased dramatically in recent times. The only solution to resolve the problem of CO2 emissions to the atmosphere is geological/subsurface storage of carbon dioxide or carbon capture and storage (CCS). Additionally, CO2 can be employed in the oil and gas fields for enhanced oil recovery operations and this cyclic form of the carbon dioxide injection into reservoirs for recovering oil and gas is known as CO2 Enhanced Oil and Gas Recovery (EOGR). Hence, this paper presents the CO2 retention dominance in tight oil and gas reservoirs in the Western Canadian Sedimentary Basin (WCSB) of the Alberta Province, Canada. Actually, hysteresis modeling was applied in the oil and gas reservoirs of WCSB for sequestering or trapping CO2 and EOR as well. Totally, four cases were taken for the investigation, such as WCSB Alberta tight oil and gas reservoirs with CO2 huff-n-puff and flooding processes. Actually, Canada has complex geology and therefore, implicate that it can serve as a promising candidate that is suitable and safer place for CO2 storage. Furthermore, injection pressure, time, rate (mass), number of cycles, soaking time, fracture half-length, conductivity, porosity, permeability, and initial reservoir pressure were taken as input parameters and cumulative oil production and oil recovery factor are the output parameters, this is mainly for tight oil reservoirs. In the tight gas reservoirs, only the output parameters differ from the oil reservoir, such as cumulative gas production and gas recovery factor. Reservoirs were modelled to operate for 30 years of oil and gas production and the factor year was designated as decision-making unit (DMU). CO2 retention was estimated in all four models and overall the gas retention in four cases showed a near sinusoidal behavior and the variations are sporadic. More than 80% CO2 retention in these tight formations were achieved and the major influencing factors that govern the CO2 storage in these tight reservoirs are injection pressure, time, mass, number of cycles, and soaking time. In general, the subsurface geology of the Canada is very complex consisting with many structural and stratigraphic layers and thus, it offers safe location for CO2 storage through retention mechanism and increasing the efficiency and reliability of oil and gas extraction from these complicated subsurface formations.

Exploring ways to enhance the liquid-phase seepage ability and increase the flow-back rate of external fluids in the production process is an important way to solve the problem of water blocking in tight reservoirs. Based on the analysis of the characteristics of water phase retention damage caused by foreign fluid invasion during the development of tight sandstone gas reservoirs, a set of ether nano-displacement agent system was optimized. The mechanism of wetting modification is revealed from the perspective of the physical composition of nano-displacement agent, and the mechanism of action between nano-displacement agent and rock and different clay minerals is clarified. Laboratory experiments show that :(1) 0.5 wt% CNDAD1# nano-displacement agent fluid can change the wettability of sandstone to gas-phase wetting, "air-salt water-rock" three-phase static contact angle increased from 38.5° to 126°. (2) SEM and EDX results prove that the nano-displacement agent has good macroscopic static and dynamic adsorption performance on the sandstone surface. This paper provides a reference method for exploring the use of environmentally friendly chemical agents to remove water blocking damage in tight sandstone gas reservoirs. INTRODUCTION Tight sandstone gas reservoirs refer to sandstone gas reservoirs with overburden matrix permeability less than or equal to 0.1 mD. Single wells generally have no natural productivity or natural productivity is lower than the lower limit of industrial gas flow. Industrial natural gas production needs to be obtained through fracturing, horizontal wells, multi-branch wells, etc. (Wei G, Zhang F, Li J, et al., 2016; Jia C, Zheng M and Zhang Y, 2012; Zou N, Zhu R, Wu S, et al., 2012). According to the data, China contains a wealth of tight sandstone gas reservoirs, tight sandstone gas resources account for about 27.5 % of China ‘s natural gas resources, mainly distributed in different basins in China, such as Sichuan, Tarim Basin and other regions, and most of the reserves have not been effectively developed (Wang J, Hu Y, Liu Y, et al., 2019; Fuhai J, Tang D, Xu H, et al., 2012; Bybee K, 2007). Therefore, the development of tight sandstone gas reservoirs will become one of the key sources of future energy security in China, and it is also the focus of unconventional oil and gas development. However, most of the tight sandstone gas reservoirs have low natural productivity of single wells. The combination of horizontal well drilling and fracturing is one of the main ways to realize the commercial exploitation of tight sandstone gas reservoirs. However, during the fracturing process, the fracturing fluid flowback is not timely or the edge and bottom water invades the reservoir during the production process. The reservoir will produce a large amount of external water phase retention or edge and bottom water invasion water, forming a ‘ liquid phase trap ‘ and further tight sandstone gas well productivity (Dutta R, Lee C H, Odumabo S, et al., 2012; You Q, Wang H, Zhang Y, et al., 2018; Zhang L, Zhou F, Mou J Y, et al., 2018).

With the increase in demand and rapidly diminishing resources in conventional reservoirs, economically producing gas from unconventional reservoirs e.g. tight gas reservoir is a great challenge today. The character and distribution of tight gas reservoirs are not yet well understood. Low quality reservoirs are often seen as involving higher costs and risk than high-medium quality reservoirs. There is no formal definition for "Tight Gas". Law and Curtis (2002) defined low-permeability (tight) reservoirs as those with permeabilities less than 0.1 mD. The best definition of tight gas reservoir is "reservoirs that cannot be produced at economic flow rates or economic volumes of natural gas are unrecoverable, unless the well is stimulated by a large hydraulic fracture treatment or produced by use of a horizontal wellbore or multilateral wellbores." Unlike conventional reservoirs, which are small in volume but easy to develop, unconventional reservoirs are large in volume but difficult to develop. Improved technology and adequate gas price is the key to their development. Gas production from a tight-gas well will be low on a per-well basis compared with gas production from conventional reservoirs. A lot of wells have to be drilled to get most of the gas out of the ground in tight gas reservoirs. Testing a tight gas reservoir is a big challenge today but in coming future more and more numbers of wells are expected in tight gas reservoirs. If we want to grab a piece of this upcoming opportunity, we will have to accept the challenge today. More data and more engineering manpower are required to understand and design a well test in tight gas reservoir than a well test in good permeability conventional reservoirs. In this paper, a possible way to test a tight gas reservoir using hydraulic fracturing will be discussed. Since hydraulic fracturing is one of the most successful ways of producing a tight gas reservoir economically so far, an idea of integrating hydraulic fracturing job with well testing job as a complete package for testing tight gas reservoirs, especially in the exploratory phase, will be discussed.

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.

Relationship between tight sandstone reservoir formation and hydrocarbon charging: A case study of a Jurassic reservoir in the eastern Kuqa Depression, Tarim Basin, NW China

Summary Unconventional resources are important for exploration and production in Mexico. The Formation Chicontepec is considered unconventional tight oil & gas reservoirs. The tight reservoirs (TR) are called like that for their low permeability and porosity by petroleum and petrophysical field. This paper provide a research about concepts, classification, physical properties and petrophysical characteristics of TR, Identification of TR with cores and well logs, geological occurrence and sedimentary characteristics of unconventional tight reservoir in Mexico. Tight oil must not be confused with shale oil & gas, because they varied through API gravity, viscosity of fluids, extraction method and other aspects. Reservoirs connectivity is a modifying attribute, usually limited and discontinuous; for these reason, the stratigraphic correlation is discontinuous, because its heterogeneity. The Production cost is closed to economic limit and sometimes is overtaked. Well electrical logs are limited by their vertical resolution in these reservoirs; the only exception is the micro-resistivity image log. In future studies, is appropriated use equations and inversion models of well logs focus on TR.

Gas reservoirs with low permeability (k<0.1 mD) are among the unconventional reservoirs and are commonly termed as Tight Gas Reservoirs. In conventional gas reservoirs that have high permeability, the flow of gas is basically controlled by the reservoir permeability and it is calculated using the Darcy equation. In these reservoirs, gas flow due to gas diffusion is ignored compared to Darcy flow. However, diffusion phenomenon has a significant impact on the gas flow in tight gas reservoirs and the mechanism of gas diffusion can no longer be ignored in comparison to Darcy flow. In this study, a dual mechanism based on Darcy flow as well as diffusion is used for the gas flow modeling in tight gas reservoirs. The diffusivity equation is obtained using this method that it indicates the gas flow in a porous media. The conventional dry gas pseudo pressure function is not able to linearize the diffusivity equation including diffusion effect. Subsequently, a new real gas pseudo pressure function is used and a novel real gas pseudo time function is introduced. These pseudo functions consider changes in gas properties with pressure and linearize the diffusivity equation. The linear diffusivity equation is solved analytically for constant gas flow boundary condition under Pseudo Steady State (PSS) situation. Then, pseudo steady state analytical solution, based on new functions of pseudo pressure and pseudo time, is obtained. The calculation of reservoir parameters such as permeability, effective diffusion coefficient and original gas in place (OGIP) using reservoir data is the first application of analytical solution. Reservoir data is required to analysis the results of application of introduced model in low permeability gas reservoir.

This paper gives methods to characterize tight gas reservoirs in sufficient detail to allow an engineer to make accurate long-range production forecasts. These forecasts are the bases for sound engineering and business decisions. Because of the complexity and variability of tight gas reservoirs, the authors can present only general procedures for developing reservoir descriptions. Accordingly, the authors illustrate a reservoir characterization method with three examples of successful tight gas reservoir studies. The procedures in these examples can be modified as needed for other specific formations or areas.

Accumulation conditions and exploration and development of tight gas in the Upper Paleozoic of the Ordos Basin