Production from unconventional reservoirs such as shales has increased significantly in the recent years due to the technological advancement such as horizontal drilling and hydraulic fracturing. EIA (Energy Information Administration, USA) has reported that 49% of oil and 54% of natural gas in the USA are produced from fractured reservoirs as of February 2015. Current industrial practice of production of liquid hydrocarbons (oil and condensate) and natural gas leads to low recovery and high environmental impact. Only 5-10 % of liquid is recovered from ultra-low permeability (50 – 1000 nD) reservoirs such as shales leaving vast amount of liquids in the subsurface. Hydraulic fracturing is the key technology that has made the enhanced production possible. However, there are potential significant environmental issues related to impact on groundwater, fate of injected water, fugitive emissions and induced seismicity. The challenges to minimize the environmental impacts and to maximize production require understanding the fundamentals of fluid flow in ultra-low permeability porous media in the context of complex geologic and operational controls. In this research, methods to maximize recovery while minimizing some of the environmental considerations are presented.
Reservoir numerical simulation of multiphase fluid flows in tight and ultra-tight reservoirs has become the standard tool to predict production performance from these unconventional resources. Numerical simulation requires accurate modeling of fluid flow, reservoir geometry and spatial distribution of properties. However, the simulations need to be structured in a logical fashion to ascertain accurate results. Even though applicability of Darcy’s law for ultra-low permeability porous media is questionable, it is widely used in commercial simulators for flow modeling. More complex fluids and lower permeability reservoirs require better grid resolution. Grid refinement must be applied even more carefully when dealing with the production of condensates. Situations involving multiple, complex parameters need to be handled using specific methods that prioritize the parameter list. Formation permeability is one of the most significant parameters in the production of liquids from shales. Production increases with increase in reservoir permeability but produced gas oil ratio also increases. The oil production is higher with more compressible rock. Produced gas oil ratio is also reduced for higher compressibility rock. Reduced spacing, generally speaking, results in higher recovery. Spacing has the greatest influence up to 500 nD permeability. It is observed that recovery factor is higher in hydraulically fractured reservoirs in primary production than the recovery from the higher permeability conventional reservoirs, assuming fracture spacing of 100 feet or lower. However, production data from unconventional reservoirs do not reflect this fact.
Surrogate reservoir model considering complex interaction of parameters using multivariate regression of simulated results for black oil and condensate from ultra-low permeability reservoirs is an efficient tool. Surrogate models are also utilized to determine the hierarchy of the important factors and to analyze the uncertainty in the production outcomes for given distributions of input factors.
Operating the well at higher flowing bottom hole pressure (FBHP) is preferable for low permeability (100 nD) reservoir and low FBHP for higher permeability (1000 nD) reservoir to recover more liquid such as condensate and volatile oil.
It is known that only about 30% of the water injected during hydraulic fracturing is recovered. It is quite likely that the injected water may be retained in the matrix and is trapped as immovable water saturation. As the wettability of the matrix changes from being water wet to oil wet, the recovery increases by about 15%. Surface equipment and conditions affect subsurface operations and vice-versa. Rapid deployment of resources for liquid shale developments may not always result in optimal choices. It is shown that both from a liquids quality and gas venting perspective, a two-separator arrangement is best when producing moderately volatile oil or a condensate. However, the current practice in most locations is to use single-stage separation.
Measurement of reservoir permeability, thermodynamic properties such as bubble and dew points, gas-oil ratios, etc., are very important. It is thus critically important to understand the impact of the nanoporous structure on the basic properties of shales and fluids in these shales. The current method of measuring permeability in shales consists of crushing the rock, exposing this to pressure and measuring pressure decay. New methods of measurement of rock properties and rock fluid properties such as permeability, relative permeability and porosity should be developed. The fluid sampling technique and re-combination of separator fluids to represent reservoir fluid should be revisited. Determining the suitable location of fracturing in the reservoir is one of the key factors for effective fracturing which will reduce the environmental impact in many ways such as reducing the water requirement for proppant transport. Designing proppant ensuring proper mechanical properties to keep fracture open during production is another key factor. Geomechanical properties such as stress change in the reservoir during fracturing and then production should be studied. The change stress in the field affects many geological properties such as permeability and it also controls the morphology of hydraulic fractures. Injection of gas or water into reservoir is one possibility to exploit more hydrocarbons from unconventional reservoirs. In-fill drilling and refracturing in existing reservoir considering economic constraint are also promising ways to extract more hydrocarbons.
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