Fracture Porosity

Key Takeaways

• Dual-porosity reservoir behavior resulting from the contrast between fracture and matrix properties creates distinctive production signatures that distinguish fractured reservoirs from homogeneous matrix reservoirs in well test analysis, production decline analysis, and reservoir simulation: at early time after a well is opened to production, the flowing fluid is primarily from the high-permeability fracture network (the fractures are at reservoir pressure initially and dewater rapidly), producing a high initial production rate that declines quickly as the fracture pressure decreases; at intermediate to late time, the lower-permeability matrix begins to transfer fluid into the depleted fractures by the pressure gradient between the matrix blocks (still at near-reservoir pressure) and the fractures (at the lower pressure established by production), producing a characteristic secondary plateau or slower decline rate in the production decline curve that represents the steady-state matrix-to-fracture transfer at the production-maintained drawdown; the Warren-Root dual-porosity model (the classical analytical model for fractured reservoir behavior) describes this behavior in terms of the omega parameter (the ratio of fracture storage capacity to total storage capacity, approximately equal to the fracture porosity divided by the sum of fracture and matrix porosity) and the lambda parameter (the fracture-matrix interporosity flow coefficient, proportional to the fracture-matrix transmissivity), which can be determined from the derivative signature of a pressure buildup test in a dual-porosity reservoir.
• Fracture characterization from well logs uses a combination of resistivity imaging tools (FMI, STAR, OBMI), acoustic imaging tools (UBI, CAST), caliper measurements, and conventional log responses to identify and characterize fractures in the near-wellbore zone: resistivity image logs (microresistivity tools that measure the formation resistivity at very shallow investigation depths with high vertical resolution, typically 1-5 mm) produce color-coded images of the borehole wall that show fractures as sinusoidal dark features (conductive fractures filled with drilling fluid) or sinusoidal bright features (resistive fractures cemented with calcite, anhydrite, or other minerals); the dip and azimuth of fractures identified on resistivity image logs are determined by fitting a sinusoid to the fracture trace as it wraps around the borehole, with the sinusoid amplitude giving the fracture dip and the phase giving the fracture azimuth; acoustic image logs (ultrasonic caliper tools that measure the two-way travel time and amplitude of ultrasonic pulses reflected from the borehole wall) detect fractures as amplitude lows (acoustic energy is scattered or absorbed by the open fracture) and provide complementary information to resistivity images, particularly in non-conductive oil-based muds where resistivity images have poor contrast; the distinction between natural fractures (formed by tectonic or diagenetic processes before drilling) and induced fractures (formed by drilling-related stress concentration or hydraulic pressure near the wellbore) is made from the fracture geometry (natural fractures are typically oblique to the wellbore axis and consistent in dip and azimuth with the regional stress field, while induced fractures are typically sub-vertical, vertical, or horizontal and align with the current principal stress directions).
• Fracture permeability calculation from the fracture aperture, spacing, and orientation provides the reservoir permeability input for dual-porosity reservoir models that govern fluid flow simulation and production forecasting: for a single set of parallel fractures with uniform aperture b, the fracture permeability k_f = b^3 / (12 x S) where S is the fracture spacing (the cubic law of fracture flow), with permeability in m^2 if b and S are in meters; a fracture aperture of 100 micrometers (0.1 mm) at a spacing of 1 meter gives a fracture permeability of approximately 830 millidarcies (extremely permeable by reservoir standards), while a fracture aperture of 10 micrometers at the same spacing gives a fracture permeability of 0.83 millidarcies; the challenge of applying the cubic law to real fractured reservoirs is that fracture apertures are extremely difficult to measure directly (the fracture is compressed by the in-situ effective stress, which may reduce the open aperture to a fraction of the nominal fracture width measured on core or outcrop), fracture apertures are heterogeneous within and between fractures, and many fractures are partially or fully cemented by diagenetic minerals (calcite, quartz, pyrite, barite) that block permeability without completely filling the fracture void space visible in core or image logs; the effective fracture permeability measured by well testing (the permeability that controls fluid flow into the wellbore over a larger volume than the wellbore vicinity sampled by image logs) integrates the contribution of all connected fractures in the tested volume and is typically the most reliable measure of fracture permeability for reservoir simulation purposes.
• Fracture porosity measurement techniques face the fundamental challenge that fracture apertures are typically in the range of 10-500 micrometers, below the resolution limit of most conventional logging tools and below the scale of routine core plug measurements: wireline neutron and density logs have measurement volumes of tens of liters (the volume of formation the tool samples), which contain many matrix pores but very few fracture voids, making them insensitive to fracture porosity changes below approximately 0.5-1% of bulk volume; nuclear magnetic resonance (NMR) logging tools can detect fracture porosity from the relatively long T2 relaxation times of fracture fluids (because the large fracture aperture relative to the surface area means the fluid-surface relaxation mechanism is less effective than in small matrix pores, resulting in a long T2 relaxation time typically above 100-300 ms that is distinct from the short T2 times of fluid in tight matrix pores), but the NMR measurement is limited to the near-wellbore region and may not be representative of the bulk fracture porosity further from the well; the most direct measurement of total fracture porosity from a well test uses the dual-porosity storage model to determine the omega parameter from the pressure transient response, from which the fracture porosity can be estimated if the matrix porosity is known from conventional logs; outcrop analogue studies and well-by-well fracture intensity mapping from image logs across the reservoir remain the primary tools for characterizing the spatial distribution of fracture porosity throughout the reservoir volume between wells.
• Cement filling and diagenetic occlusion of fractures reduces or eliminates the open fracture porosity and permeability that makes fractured reservoirs productive, creating sealed fractures that appear in core and image logs but no longer contribute to fluid flow: the precipitation of calcite, quartz, anhydrite, pyrite, or chlorite cement in fracture voids is a post-fracturing diagenetic process driven by the flow of supersaturated formation fluids through the fracture network (which is the same high-permeability pathway that makes fractures valuable for production); the fraction of fractures that are fully cemented versus partially cemented versus open (uncemented) varies spatially within a fractured reservoir and is controlled by the fluid flow history, the diagenetic history, and the tectonic stress history that may have reopened previously cemented fractures under later deformation events; the distinction between open, partial, and cemented fractures is made on resistivity image logs from the contrast between the conductive (dark) fracture fill (open or water-filled fractures) and the resistive (light) fill (cemented fractures in resistive cement such as calcite or anhydrite); only the open fractures contribute to fracture porosity and permeability, and the proportion of open to total fractures (the "open fraction") is one of the most important uncertain parameters in fractured reservoir characterization because the cemented fractures are geologically conspicuous (visible in core and image logs) but effectively invisible to production flow.