This paper examines oil displacement as a function of polymer solution viscosity during laboratory studies in support of a polymer flood in the Cactus Lake reservoir in Canada. When displacing 1610-cp crude oil from field cores (at 27°C and 1 ft/d), oil recovery efficiency increased with polymer solution viscosity up to 25 cp (7.3 s-1). No significant benefit was noted from injecting polymer solutions more viscous than 25 cp. Much of the paper explores why this result occurred. That is, was it due to the core, the oil, the saturation history, the relative permeability characteristics, emulsification, or simply the nature of the test? Floods in field cores examined relative permeability for different saturation histories—including native state, cleaned/water-saturated first, and cleaned/oil-saturated first. In addition to the field cores and crude oil, studies were performed using hydrophobic (oil-wet) polyethylene cores and refined oils with viscosities ranging from 2.9 to 1000 cp. In nine field cores, relative permeability to water (
Spontaneous and forced imbibition are recognized as important recovery mechanisms in naturally fractured reservoirs as the capillary force controls the movement of the fluid between the matrix and the fracture. For unconventional reservoirs, imbibition is also important as the capillary pressure is more dominant in these tighter formations, and the theoretical understanding of the flow mechanism for the imbibition process will benefit the understanding of important multiphase flow phenomenons like water blocking. In this paper, a new semi-analytic method is presented to examine the interaction between spontaneous and forced imbibition and to quantitatively represent the transient imbibition process. The methodology solves the partial differential equation of unsteady state immiscible, incompressible flow with arbitrary saturation-dependent functions using the normalized water flux concept, which is very identical to the fractional flow terminology used in traditional Buckley-Leverett analysis. The result gives a universal inherent relationship between time, normalized water flux, saturation profile and the ratio between co-current and total flux. The current analysis also develops a novel stability envelope outside of which the flow becomes unstable due to strong capillary forces, and the characteristic dimensionless parameter shown in the envelope is derived from the intrinsic properties of the rock and fluid system and can describe the relative magnitude of capillary and viscous forces at the continuum scale. This dimensionless parameter is consistently applicable in both capillary dominated and viscous dominated flow conditions.
Recently, the miscible CO2-EOR tertiary process used in the main pay zone (MP) of suitable reservoirs has broadened to include exploitation of the underlying residual oil zone (ROZ) where a significant amount of oil may remain. The objective of this study is to identify the ROZ and to assess the remaining oil in a brownfield ROZ by using core data and conventional well logs with probabilistic and predictive methods.
Core and log data from three wells located in the East Seminole Field in Gaines County, Texas, were used to identify the MP and ROZ in the San Andres Limestone, and to predict oil saturations. The core measurements were used to calculate probabilistic in-situ oil saturations within the MP and the ROZ as a function of depth. Well logs, in combination with core data and calculated saturations, on the other hand, were used to develop two expert systems using artificial neural networks (ANN); one to identify the ROZ and MP, and the other to predict oil saturation. These systems were also supported by a classification and regression tree (CART) analysis to delineate the rules that lead to classifications of zones.
Results showed that expert systems developed and calibrated by combining core and well log data can identify MP and ROZ with a success score of more than 90%. Saturations within these zones can be predicted with a correlation coefficient of around 0.6 for testing and 0.8 for training data. The analyses showed that neutron porosity and density well log readings are the most influential ones to identify zones in this field and to predict oil saturations in the MP and ROZ. To explain the relationships of input data with the results, a rule-based system was also applied, which revealed the underlying petrophysical differences between MP and ROZ.
This new predictive approach using machine learning techniques, could potentially address the challenges that previous studies have come up against in defining the ROZ within the formation and quantifying remaining oil saturations. The method can potentially be applied to additional fields and help reliably identify the ROZ and estimate saturations for future resource evaluations.
Water alternating gas (WAG) injection is a common technique in enhanced oil recovery. However, gas injection often associates with fingering due to high gas mobility, which leaves a large portion of the reservoir unswept. This study addresses gas mobility control observations through novel X-ray microfocus visualization of core-flood experiments and interpretation aided by numerical simulation. We use foam as our primary mobility control agent for improving conformance.
The experimental setup utilizes an automated fluid injection system monitored by an X-ray microfocus scanner to quantify displacement patterns and saturations during WAG core-flood experiments. The core-flood device – placed within an X-ray shielded cabinet – is wirelessly operated through a computer. The resolution of the images permits observation of not only core scale fingering but also pore-scale displacement. We use a metastable foam with surfactant dissolved in the liquid phase to stabilize the gas diffusion in the liquid and to decrease the permeability and/or lower the apparent gas viscosity.
Results show that saturation patterns and displacement front during WAG injection are highly influenced by bedding orientation and rock heterogeneity. Without gas mobility control during WAG injection, fingering and early breakthrough occur in those cases in which bedding orientation facilitates gas to flow through high permeability layers. In these cases, sweep efficiency is low during early time injection of nitrogen and only improves after injection is prolonged. With gas mobility control, the displacement efficiency is significantly improved. Also, dynamic processes like phase trapping, which could severely impair permeability and overall sweep efficiency, is more clearly visualized with the microfocus technique. Simulation work matches experimental data well and replicates saturation patterns measured experimentally in laminated Berea sandstone samples.
The novel visualization technique presented here provides new pore-scale experimental insight to quantifying WAG displacement in heterogeneous media, a resolution one order of magnitude higher than with medical X-ray CT or other core-scale visualization techniques. The findings are useful for understanding flow regimes in structurally complex and heterogeneous formations.
Liang, Tianbo (The University of Texas at Austin) | Achour, Sofiane H. (The University of Texas at Austin) | Longoria, Rafael A. (The University of Texas at Austin) | DiCarlo, David A. (The University of Texas at Austin) | Nguyen, Quoc P. (The University of Texas at Austin)
Significant amount of fracturing fluid is lost after hydraulic fracturing, and it is believed that the loss of fluid into the matrix can hinder the hydrocarbon production. One way to reduce this damage is to use the surfactants. Robust surfactant formulations have been developed for chemical enhanced oil recovery (CEOR); similar ideas are introduced in this study to reduce water blocks in low permeability reservoirs. Here we present an experimental investigation based on a coreflood sequence that simulates fluid invasion, flowback, and hydrocarbon production within the rock near the fracture face. Different levels of IFT reductions are tested and compared in order to explore the best condition that maximizes the permeability enhancement. The effect of in-situ microemulsion generation to mobilize the trapped water is also studied. From this work, we recognize the mechanism responsible for the permeability damage in matrix and we suggest criteria to optimize the performance of surfactant additives so as to enhance the hydrocarbon production from low permeability gas/oil reservoirs after hydraulic fracturing.
Hou, Binchi (Research Institute of Shaanxi Yanchang Petroleum (Group) CO., LTD.) | Liu, Hongliang (China Petroleum Logging TuHa Business Division) | Bian, Huiyuan (Xi'an University of Science and Technology) | Wang, Chengrong (China Petroleum Logging TuHa Business Division) | Xie, Ronghua (Daqing Oilfield CO.LTD., PetroChina) | Li, Kewen (China University of Geosciences(Beijing)/Stanford University)
Capillary pressure and resistivity in porous rocks are both functions of wetting phase saturation. Theoretically, there should be a relationship between the two parameters. However, few studies have been made regarding this issue. Capillary pressure may be neglected in high permeability reservoirs but not in low permeability reservoirs. It is more difficult to measure capillary pressure than resistivity. It would be useful to infer capillary pressure from resistivity well logging data if a reliable relationship between capillary pressure and resistivity can be found. To confirm the previous study of a power law correlation between capillary pressure and resistivity index and develop a mathematical model with a better accuracy, a series of experiments for simultaneously measuring gas-water capillary pressure and resistivity data at a room temperature in 16 core samples from 2 wells in an oil reservoir were conducted. The permeability of the core samples ranged from 9 to 974 md. The gas-water capillary pressure data were measured with confining pressures using a semi-porous plate technique. We developed the specific experimental apparatus to measure gas-water capillary pressure and resistivity simultaneously. The results demonstrated that the previous power law model correlating capillary pressure and resistivity works well in many cases studied. A more general relationship between the exponent of the power law model and the rock permeability was developed and verified using the experimental data.
Disproportionate permeability reduction (DPR) may provide field solutions to address high volumes of water production and efficiency of oil recovery in non-communicating layered reservoirs. This work evaluates the lab-scale DPR effectiveness at different formation wettability conditions using an environmentally friendly, water-soluble, silicate gelant. A robust, time/temperature stable and easy-to-design water-soluble silicate gelant system is utilized to conduct DPR treatments in oil- and water-wet cores using a newly established steady-state, two-phase chemical system placement. The experimental procedure is applied to ensure the presence of moveable oil saturation at which the injected DPR fluid (gelant) gels in the treated zone and to quantitatively control the placement saturation conditions in the formation. DPR treatments are conducted using a steady-state, two-phase (oil/gelant) placement to better control the water/oil saturation at which the silicate gel sets. The performance of water-soluble, silicate-based DPR treatments are evaluated using pre- and post-treatment two-phase (brine/oil) steady-state and unsteady state permeability measurements.
Strongly water-wet Berea cores are chemically treated to alter their wettability to oil wet and measured phase effective permeability curves are used to characterize the newly established core wettability. Treatment design should include filterability/injectivity and rheological studies of the DPR fluid to evaluate gelant interaction with the formation as well as gelation time and kinetics. Single-phase DPR fluid injectivity through Berea cores is excellent. At relatively high watercuts in water-wet cores, two-phase DPR-fluid/oil injectivity is good and even better in oil-wet cores regardless the watrecut. At relatively low watercuts in water-wet cores, the injectivity is not as good as in higher watercuts and the mobility reduction keeps increasing with the co-injection of the DPR-fluid/oil.
DPR-fluid/oil placement experiments conducted at the same saturation conditions and water/oil ratio (WOR) showed that the ultimate oil residual resistance factor in oil-wet cores is significantly lower than the one in water-wet cores. This is mainly due to more favorable oil-phase continuity and distribution in oil-wet media compared to the corresponding ones in water-wet formations. In water-wet cores, encapsulation of oil by gel may cause oil-phase discontinuities and porous medium conductivity reduction. Wettability tests have shown that silicate gel is strongly water-wet. Therefore, in oil-wet DPR treatments, formed gel in porous media yields a mixed-wet formation and a lower trapped oil saturation compared to the water-wet formation.
In either wetting state, relative permeability hysteresis was insignificant during the post-DPR treatment imbibition/drainage cycles. This also reflects stable gels during post-DPR treatment floods. DPR treatments conducted at high WOR in oil-wet cores have shown a minor gel "erosion" during the post-treatment two- and single-phase (water) injection; gel "erosion" ceased during oil injection. DPR treatments conducted at high WOR caused an increase in residual resistance factor (
Jones, S. A. (Delft University of Technology) | Laskaris, G. (Delft University of Technology) | Vincent-Bonnieu, S. (Delft University of Technology and Shell Global Solutions International) | Farajzadeh, R. (Delft University of Technology and Shell Global Solutions International) | Rossen, W. R. (Delft University of Technology)
Aqueous foams play an important role in many industrial processes, from ore separation by froth flotation to enhanced oil recovery (EOR), where the foam is used as a means of increasing sweep efficiency through oil-bearing rock. The complex, structure-dependent, flow behavior of the foam gives improved penetration of lower-permeability regions. Foam is stabilized by surfactant molecules, and the foam strength is influenced by the surfactant concentration in the water phase. It is therefore of great importance to understand the effect of surfactant concentration on foam processes.
Implicit Texture (IT) foam models eg STARS account for the surfactant effect with functions that depend on surfactant concentration in the water and a few other parameters. However, there is no evidence that these functions are able to capture adequately the effect of surfactant concentration effect. We present a comparative study of foam core-flood experiments with various surfactant concentrations. Core-flood tests were conducted in rock cores with a diameter of 1 cm and length of 17cm, significantly smaller than typical cores. Plots of apparent viscosity vs. injected gas fraction were obtained for surfactant concentrations at the critical micellar concentration (CMC) and above. Bulk foam stability and surface tension were measured for all concentrations, in order to define the CMC and to compare with coreflood results. The experimental results have been matched with the STARS IT foam model and the dependency of model parameters on the surfactant concentration is discussed.
This work found that the IT model is not able to predict the decrease of the foam strength with decreasing surfactant concentration. Instead, the study shows that the effect of surfactant concentration can be correlated with the dry-out function of the IT model, and specifically to the limiting capillary pressure