In the s, the United States government decided that the definition of a tight gas reservoir is one in which the expected value of permeability to gas flow would be less than 0. Rock permeability is usually increased by hydraulic fracturing. Unconventionals have been defined based on rock permeability k.
Conventional Play — Lifecycle Stages. During Exploration-Appraisal: The focus is on the search and discovery of a commercial hydrocarbon accumulation, evaluating the size of the accumulation, type of fluids oil vs gas as well as fluid properties, which define quality and price of the fluids, and are used in the economic evaluation at appraisal. Petroleum system analysis has a very important role and incorporates a continuous interaction between building the geologic model, basin model and using exploration geochemistry to evaluate main components of the petroleum system such as source rock, charge, migration, accumulation.
Drilling an exploration well, which results in a hydrocarbon discovery, usually marks a transition to appraisal stage. The appraisal stage involves drilling of additional appraisal wells to evaluate the discovery. During the appraisal stage, reservoir geochemistry may be utilized to evaluate presence of additional reservoir accumulations, fluid properties, in-reservoir processes e.
During Development-Production : Additional wells are drilled to define the best way to produce the field and maximize the recovery of petroleum from the accumulation.
Petroleum system analysis still plays a role as the geological and basin models are updated with newly acquired well data but the role of building static and dynamic reservoir models becomes much more important. The geochemistry applications, referred as reservoir and production geochemistry, become more important and could address issues such as reservoir compartmentalization, compositional graded fluid columns, prediction of water break-through, wax and asphaltene problems and remediation, operational issues.
Un-Conventional Play — Lifecycle Stages.
Conventional Oil and Ga s — Oil and Gas Pools in which wells can be drilled so that oil and natural gas flows naturally or can be pumped to the surface at economic flow rates. Uconventional Oil and Gas — unconventional oil and natural gas CANNOT flow naturally through the rock at economic flow rates , and requires special techniques to stimulate production e.
Types of Unconventional Resources. An estimate for the acceptable ranges of a and b for different rocks are provided below. This range differs from unconventional formations on the lower bound to a conventional rock on the upper bound. Due to the complex nature of hydraulic fractures and its network with pre-existing natural fractures and also very low permeability of shale reservoirs that is combined with horizontal completion, as always, reservoirs simulation is the cheapest and commonly preferred approach to evaluate and predict the performance of such complicated reservoirs. Numerical simulation techniques are widely accepted and sued in the oil and gas industry; however, some semi-analytical tools are also developed and is available in the literature   , the specific characteristics of such tools are considered being simple and fast which is valuable and helpful in the decision making processes although ignore most physics of shale compared to conventional wells.
The most important problem when using analytical or semi-analytical models are that they lack to capture the linear transient behavior of production in shale. This kind of behavior is due to the very low permeability of shale rock matrix. One way to improve these methods accuracy is combing them by the numerical simulations to capture the entire window of production.
In simulation of shale formation compared to simulating conventional assets, the computational cost and run time of simulation of discretized grids of entire reservoir including network of hydraulic and natural fractures, and unstimulated area is extremely high that requires some techniques implemented such as predictive modeling.
On another note, more specifically, it should be noted that Darcy flow and capillary equilibrium state already implemented in commercial simulators for conventional reservoirs are inaccurate for reliable simulation and production evaluation from shale gas reservoirs  . As of today, many developed capabilities of commercial reservoir simulators are not accurately implemented as they are not directly affecting any portion of production behavior of shale reservoirs and this put a big black dot in the result and how they are representing the actual trends observed in the real fields .
Andrade  recognized the branches where commercial simulators reaches unrealistic estimates unacceptable for shale gas reservoirs, these are outlined as a the assumption of instantaneous capillary equilibrium; b that Darcy flow gives a complete description of the flow regime; c that relative permeability is not rate dependent. Generally, two-phase fluid flow of water and gas in a model is considered in constructing the geologic model of shale gas reservoirs. For instance, the dual-permeability model considers the intercommunication between the inter-granular void spaces in contrast to the dual-porosity model.
Also, this model considers flow in two domains including the matrix and fractures. This model also allows the transfer of both gas and water between the matrix and fracture domains gas velocity in the matrix and fracture domain is calculated with Equations 7 and 8 :. Subscripts m and f represent matrix and fracture domain. Velocity of the water flowing in matrix and fracture are determined with Equations 9 and 10 , respectively:. Subscript mf represents the exchange between matrix and fracture.
For the water phase, the same equation is shown in Equation 12 :.
Evaluating Shale Oil and Gas Reservoirs
After some manipulation and simplifications, the gas flow governing equation in fracture becomes as the following, Equation 13 :. There are many factors that affect gas production from shale; in this section the most significant parameter has been described.
These factors are divided into three sections, geological, economic issues and technological aspects. The geology of shale gas formation and the productivity of the well drilled as well as availability of water are considered very important and apart from economic issues such as additional cost of horizontal drilling, completions and fracturing parameters and also more importantly fluctuating gas prices, cost of leasing the land and etc.
Some of the most influencing parameters are as below:. The potential of hydrocarbon available in an economical level is determined by other parameters such as Total Organic Carbon TOC , kerogen type, thermal maturity and gas content of specific shale formations that varies widely from place to place. Above also affect the quality of the gas produced that ultimately affects the eco- nomic viability of the project. From a petro-physical point of view, it is very important to notice that two parameters, porosity and permeability, of the formation should be accurately measured as it directly affect the original gas in place calculation along with the desorption characteristics of the shale rock.old.zppdon.ru/images
Unconventional Gas Reservoirs 1E
In , Freeman noticed that based on the acceptance of continuum flow, the Darcy law is applicable is shale but however, Javadpour  has suggested the continuum law is not appropriate and fails when applied to shale formations as it is in nano-scale and mean free path of the gas molecules are very small. A very accurate determination of permeability is a key in reservoir characterization of shale resources.
Especially in shale, using traditional methods applied to conventional will not produce an accurate result for shale due to its very complex nature, therefore, the process f measuring shale permeability is very challenging.
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Moreover, permeability measurements of shale rock in different laboratories with entirely different methods have given different according to . As a result, some advances in technologies for reliable measurements of shale formation permeability are developed such as pulse decay method and some even with steady state methods.
In , Aguilera suggested that flow in shale occurs through mega-pores, macro pores, meso-pores and micro pores. On another note, diffusion flow in shale nano pores are deviating from Darcy law as a consequence of Klinkenberg slippage effect and inertial flow . It is concluded that by ignoring the non-Darcy flow, results obtained from laboratory measurements will lead to significant errors when determining permeability.
There are also some advances in steady state methods that have minimized these effects but again they are not completely eliminative. As it is mentioned previously, to achieve an economic viable natural gas production form shale formations, hydraulic fracturing is become a standard practice. A complete and accurate hydraulic fracturing is achieved by pumping slick water, proppant that is injecting very high pressurized flow into the shale formation to create network of fractures.
Due to higher pressure exerted on the formation, a fracture is created that in most simulations studies are considered perpendicular to the horizontal wells. Also, the length of the fractures are assumed equal in both sides of the horizontal wells that should be carefully used in each formation due to different issues such as rock compaction around wellbore. The length of the fracture on one side of the wellbore is referred to as the fracture half-length, Figure 3 depicts schematic of a hydraulic fracture.
On a different note, due to brittleness of shale formations, a very huge fluid pressure is required for creating a very efficient hydraulic fracturing network as it is considered the heart of production form shale. This ratio is an indicator of these parameters that govern the propagation of hydraulic fractures  .
At the end, successful application of hydraulic fracturing is proven to be valid method to unlock production from these previously known un-pro- ducible formations due to their nano-Darcy permeability. The more proppant is injected the larger hydraulic fractures is achieved. However, it should be noted that an optimized injection rate is necessary since a very large hydraulic fracture may breaks into the water zone and causes further problems such as two phase flow and relative permeability issues for gas flow.
Evaluating Shale Oil and Gas Reservoirs: Training Course by Rose & Assoc
This fact will be detrimental to the production from shale and must be given a careful attention. This fact aside other factors, a large number of well-sized hydraulic fractures are very desirable compared to very large hydraulic fractures but in less density. The last but not least unique characteristics of shale reservoirs are encountering a very high capillary pressure that causes fluid imbibition that retains fracturing fluid. Water blockage is directly depends on the previous phenomena that is the existence of a region with very high water saturation that reduces the mobility of natural gas in the rock and prevents its movements  .
Fast cleanup of the horizontal wellbore and shale formation is very critical in order to improve the natural gas production  . The sensitivity of production from shale wells to the size and the conductivity assigned to the Stimulated Reservoir Volume explains the uncertainties associated with the forecasts that are made using this technique. Furthermore, SRV techniques are incapable of making serious contribution to designing an optimum frac-job specific to a given well. According to the available production data form unconventional shale reservoirs, a well by well basis use of decline curve analysis is very common where in conventional assets it is possible to use on both well scale and field scale sizes .
Production from unconventional gas reservoirs are shown in Figure 4 , Three dominant flow regimes are defined for the flow of natural gas from the shale matrix and through the hydraulic fractures toward the horizontal wells and ultimately to the well production.