Relative Permeability Behavior of Oil- Water Systems in Wolfcamp and Eagle Ford Fractures

Presently, two-phase flow behavior through propped and unpropped fractures is poorly understood, and due to this fact, reservoir modeling using numerical simulation for the domain that contains fractures typically assumes straight-line relative permeability curves and zero capillary pressure in the fractures. However, there have been several studies demonstrating that both viscous and capillary dominated flow can be expected in fractured reservoirs, where non-linear fracture relative permeabilities must be used to accurately model these reservoirs. The objective of this study is to develop an understanding of the relative permeability of oil-water systems in fractures through experimental study. The experimental measurements conducted in this study were done using downhole cores from the Wolfcamp and the Eagle Ford Shale formations. The cores were cut to 1.5-in diameter and 6-in length testing samples. The specimens are saw-cut to generate a fracture along each sample first, and then conditioned in the reservoir fluid at the reservoir temperature for a minimum of 30 days prior to any testing. Wolfcamp and Eagle Ford formation oil and reconstituted brine with and without surfactants are used as the test fluids. The measurements were recorded at effective fracture closure stress and reservoir temperature. Also, real-time measurements of density, pressure, and flow rate are recorded throughout the duration of each test. Fluid saturation within the fracture was calculated using the mass continuity equation. The oil-water relative permeability was measured using the steady-state method. All measurements were conducted at reservoir temperature and at representative effective fracture closure stress. The data from the experimental measurements was analyzed using Darcy's law, and a clear relationship between relative permeability and saturation was observed. The calculated relative permeability curves closely follow the generalized Brooks-Corey correlation for oil-water systems. Furthermore, there was a significant difference in the relative permeability curves between the oil-water only systems and the oil-water surfactant systems. The result of this study is useful for estimating the expected oil production more realistically. It also provides information about the effect of surfactants on oil-water relative permeability for optimal design of fracture fluids.

Wettability of Carbonate Reservoir Rocks: A Comparative Analysis

Various methods have been proposed for the evaluation of reservoir rock wettability. Among them, Amott–Harvey and USBM are the most commonly used approaches in industry. Some other methods, such as the Lak and modified Lak indices, the normalized water fractional flow curve, Craig’s triple rules of thumb, and the modified Craig’s second rule are based on relative permeability data. In this study, a set of capillary pressure curves and relative permeability experiments was conducted on 19 core plug samples from a carbonate reservoir to evaluate and compare different quantitative and qualitative wettability indicators. We found that the results of relative permeability-based approaches were consistent with those of Amott–Harvey and USBM methods. We also investigated the relationship between wettability indices and rock quality indicators RQI, FZI, and Winland R35. Results showed that as the rock quality indicators increased, the samples became more oil-wet.

Core Effective and Relative Permeability Measurements for Conventional and Unconventional Reservoirs by Saturation Monitoring in High Frequency 3d Gradient NMR

A big challenge in tight conventional and unconventional rock systems is the lack of representative reservoir deliverability models for movement of water, oil and gas through micro-pore and nano-pore networks. Relative permeability is a key input in modelling these rocks; but due to limitations in core analysis techniques, permeability has become a knob or tuning parameter in reservoir simulation. Current relative permeability measurements on conventional core samples rely on density contrast between oil/water or gas/water on CT (Computed Tomography) scans and recording of effluent volumes to determine relative fluid saturations during the core flooding process. However, tight rocks are characterized by low porosities (< 10 %) and ultra-low permeabilities (< 1 micro-Darcy), that make effective and relative permeability measurements very difficult, time-consuming, and prone to high errors associated with low pore volumes and flow rates. Nuclear Magnetic Resonance (NMR) measurements have been used extensively in the industry to measure fluid porosities, pore size characterization, wettability evaluation, etc. Core NMR scans can provide accurate quantification of pore fluids (oil, gas, water) even in very small quantities, using T2, T1T2 and D-T2 activation sequences. We have developed a novel process to perform experiments that measure effective and relative permeability values on both conventional and tight reservoirs at reservoir conditions while accurately monitoring fluid saturations and fluid fronts in a 12 MHz 3D gradient NMR spectrometer. The experimental process starts by acquiring Micro-CT scans of the cylindrical rock plugs to screen the samples for artifacts or microcracks that may affect permeability measurements. Once the samples are chosen, NMR T2 and T1T2 scans are performed to establish residual fluid saturations in the as-received state. If a liquid effective permeability test is required, the samples are then saturated with the given liquid through a combination of humidification, vacuum-assisted spontaneous imbibition, and saturation under pressure and temperature. After saturation, NMR scans are obtained to verify the volumes of the liquids and determine if the samples have achieved complete saturation. The sample is then loaded into a special core-flooding vessel that is invisible to the NMR spectrometer to minimize interference with the NMR signals from the fluids in the sample. The sample is brought up to reservoir stress and temperature, and the main flowing fluid is injected from one side of the sample while controlling the pressures on the other side of the sample with a back pressure regulator. The saturation front of the injected fluid is continuously monitored using 2D and 3D gradient NMR scans and the volumes of different fluids in the sample are measured using NMR T2 and T1T2 scans. The use of a 12 MHz NMR spectrometer provides very high SNR (signal-to-noise ratio); and clear distinction of water and hydrocarbon signals in the core plug during the entire process. The scanning times are also reduced by orders of magnitude, thereby allowing for more scans to properly capture the saturation front and changes in saturation. Simultaneously, the fluid flowrates and pressures are recorded in order to compute permeability values. The setup is rated to 10,000 psi confining pressures, 9000 psi of pore pressure and a working temperature of up to 100 C. Flowrates as low as 0.00001 cc/min can be recorded. These tests have been done with brine, dead and live crudes, and hydrocarbon gases. The measured relative permeability values have been used successfully in both simulation and production modelling studies in various reservoirs worldwide.

Relative Permeability Modifiers as a Chemical Means to Control Water Production in Oil and Gas Reservoirs

It is challenging to control water production in horizontal wells or in vertical wells having oil and water produced from the same zone using conventional methods such as through-tubing bridge plugs or other mechanical means. Relative permeability modifiers (RPMs), known to selectively reduce the relative permeability to water with minimum impact on the relative permeability to oil or gas, are considered a promising technology for solving this problem. The current generation of RPMs, unlike the old ones, can tolerate high hardness and so have higher success rates. An extensive experimental work was carried out to evaluate three RPMs for water control in gas and oil wells. Test conditions included gas flow in sandstone cores with temperatures of up to 300°F, and oil flow in carbonate cores with temperatures as high as 220°F. The effect of initial core permeability to brine, RPM concentration, flow rate, and water-wetting surfactants on the effectiveness of RPM to reduce water production was investigated using sandstone and carbonate cores. Coreflood experiments were undertaken at downhole conditions. The end-point relative permeabilities to various phases were measured. A back pressure of 500 psi, an overburden pressure of 3,500 to 5,000 psi and flow rates of 0.1 to 5 cm3/min were used. The concentration of RPM polymers was monitored in the core effluent using total organic carbon (TOC) analyzer to determine polymer retention in the core. The results revealed that temperature adversely affected the effectiveness of all RPMs evaluated. A better reduction in permeability to water was obtained at 220°F compared to that obtained at 300°F. The use of RPM at the right concentrations was found to significantly reduce permeability to water. A better water reduction was obtained at higher polymer injection rates, which was attributed to flow-induced polymer retention. Adsorption of RPM polymer tended to alter wettability of a carbonate rock to more water-wet. This paper discusses the effects of the above parameters on the performance of RPM in sandstone and carbonate reservoirs, and it gives some recommendations for improving the success rate of these chemical applications in the field.

The Effects of Interfacial Tension Dependent Relative Permeability on Sweep Efficiency and Oil Recovery Under Different Gas Injection Composition

The objective of this paper is to investigate the effects of interfacial tension dependent relative permeability (Kr_IFT) on oil displacement and recovery under different gas injection compositions utilizing a compositional simulation model. Oil production under miscible gas injection will result in variations of interfacial tension (IFT) due to changes in oil and gas compositions and other reservoir properties, such as pressure and temperature. Laboratory experiments show that changes in IFT will affect the two-phase relative permeability curve (Kr), especially for oil-gas system. Using a single relative permeability curve during the process from immiscible to miscible conditions will result in inaccurate gas mobility against water, which may lead to poor estimation of sweep efficiency and oil recovery. A synthetic sector compositional model was built to evaluate the effects of this phenomenon. Several simulation cases were investigated over different gas injection compositions (lean, rich and CO2), fluid properties and reservoir characterizations to demonstrate the impact of these parameters. Simulation model results show that the application of Kr_IFT on gas injection simulation modelling has captured different displacement behavior to provide better estimation of oil recovery and identify any upside potential.