|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Special Core Analysis, SCAL data has a direct impact on the way fluids are allocated and distributed in the reservoir simulation models, which would directly impact reservoirs’ STOIIP estimation and their distribution. Moreover, it directly affects the performance of secondary and EOR flooding processes, and in turn impacts the accuracy of the oil and gas reserve estimates, and the management of these reserves. Therefore, SCAL data could be considered as one of the most critical reservoir input data for reservoir simulation models. This course will shed light on the theoretical and experimental background of SCAL data. It will explain the concept of reservoir wettability and different factors that could induce changes in reservoir wettability.
Alyafei, Nayef (Texas A&M University at Qatar) | Bautista, Jerahmeel (Texas A&M University at Qatar) | Mari, Sahar (Texas A&M University at Qatar) | Khan, Talha (Texas A&M University at Qatar) | Seers, Thomas (Texas A&M University at Qatar)
We present a project-based learning prototype for visual analysis of petrophysical properties using 2D cross-sections and micro-models of porous media. Micro-computed Tomography (CT) scans are used to create the quasi-2D micro-models that are printed using Stereolithography (SLA) 3D printers to study petrophysical properties in porous media. The methodology involves obtaining 8 different cross-sections of rocks either from micro-CT scans or online libraries. 2D cross-sections are segmented into black and white binary images and then skeletonized to create quasi-2D models. The flow of oil and water in initially water saturated pores in the printed 2D models mimics the drainage and imbibition processes, respectively. High definition photography is used to capture still and dynamic photographs of flow processes. The binary images are used to analyze porosity and grain size distribution while the still and dynamic photographs are used to analyze fluid saturation and displacement efficiency. The images are analyzed using open source software where a systematic tutorial is provided. The primary outcome of this project is to improve the understanding of petrophysical concepts and 3D printing by the utilization of imagery to create porous media. This project has been tested in teaching and showed major improvements in students’ understanding of petrophysical concepts when compared to pre-project. The data and tutorials used in this project are made available for the community to use through a link in the paper.
Fauziah, Cut Aja (Curtin University) | Al-Khdheeawi, Emad A. (Curtin University) | Iglauer, Stefan (University of Technology-Petroleum Technology Department) | Barifcani, Ahmed (Edith Cowan University)
Wettability of CO2–water– reservoir rock system is a key factor to determine fluid dynamic and storage capacities in CO2 geo-storage process. Despite the past researches on this matter, the parameters that influence the CO2–water–rock wettability variation are still not fully understood. One of these parameters is rock-total organic content (TOC). Thus, here, we investigated the effect of TOC on the CO2–water–sandstone wettability and the implication for CO2 geo-storage at relevant reservoir conditions. The used sandstone samples were retrieved from the South West Hub CO2 capture and storage project (GSWA Harvey 1) in Western Australia. Here, we measured the contact angles for a range of sandstone TOC (i.e. 0.01 wt %, 0.015 wt %, 0.017 wt %, and 0.019 wt % TOC) at various pressures (5 MPa, 10 MPa, 15 MPa, and 20 MPa) and at an isothermal reservoir temperature (334 K). The results indicate that both of the advancing (
Water flooding has been applied either along with primary production to maintain reservoir pressure or later to displace the oil in conventional and heavy oil reservoirs. Although it is generally accepted that water flooding of light oil reservoirs in oil-wet systems delivers the least oil compared to either water-wet or intermediate-wet systems, there is a lack of systematic research to study water flooding of heavy oils in oil-wet reservoirs. This research gives some new insights on the effect of injection velocity and oil viscosity on water flooding of oil-wet reservoirs.
Seven different oils with a broad range of viscosity ranging from 1 to 15,000 mPa.s at 25 °C were used in fifteen core flooding experiments where injection velocity was varied from 0.7 to 24.3 ft/D (2.5 × 10−6 m/s to 86.0 × 10−6 m/s). Oil-wet sand (with contact angle of 159.31 ± 3.06°) was used in all the flooding experiments. Breakthrough time was precisely determined using an in-line densitometer installed downstream of the core.
Our observations suggest that drainage displacement does not occur unless non-wetting (water) phase pressure exceeds a critical breakthrough capillary pressure. At the same injection velocity, this non-wetting phase invading pressure is a function of the viscosity of the oil being displaced. For the same viscosity ratio, oil recovery monotonically increases with increasing injection velocity suggesting that the flow regime is viscous-dominant for all the viscosities studied. This is consistent with the classical literature on carbonates (
In this paper, it is demonstrated that in an oil-wet system increasing velocity improves forced drainage to the extent that it takes over viscous fingering. For the viscous oil system (15,000 mPa.s), it was found that wettability critically affects the pressure gradient across the core to the extent that one order of magnitude larger pressure gradient was observed in an oil-wet system compared to the completely same system but water-wet. This notable larger pressure gradient in oil-wet system accompanies with delayed water breakthrough leading to incremental (around 30 % OOIP) oil recovery compared to the water-wet case. This is completely opposite to the classical literature on light oils and needs to be further investigated due to the lack of literature on heavy oil domains. Observations reported in this study can provide some useful information about the sizes of the pores being invaded as a function of oil viscosity and wettability, which is a subject of our future microfluidic studies at the pore scale.
Quantifying wettability of organic-rich mudrocks is important for reliable formation evaluation, optimizing production, predicting water/hydrocarbon production, and selection of appropriate fracture fluids. Recent publications suggest that kerogen wettability can vary as a function of thermal maturity, ranging from water- to hydrocarbon-wet at low to high thermal maturities, respectively. However, clay minerals tend to preferentially be water-wet. It is therefore important to determine which of these constituents have a dominant contribution to overall wettability of the rock. To answer this question, we introduce methods to quantify the relative water-adsorption capacities of clay minerals, kerogen, and organic-rich mudrocks at different thermal-maturity levels. We started with isolating kerogen from organic-rich mudrock samples using chemical and physical separation methods and synthetically matured them to different thermal-maturity levels. We then prepared synthetic organic-rich mudrock samples by mixing known quantities of clay minerals, nonclay inorganic minerals, and kerogen. We then performed water-vapor adsorption measurements on pure clay minerals, pure kerogen samples, and synthetic organic-rich mudrock samples under controlled humidity conditions. Nuclear magnetic resonance (NMR) measurements were then used to quantify the volume of water adsorbed on clay minerals and organic-rich mudrock samples. We used the flotation test to qualitatively assess the wettability of the synthetic organic-rich mudrocks.
Water-vapor adsorption experiments showed that the volume of water adsorbed on the surface of nonheated kerogen samples at low thermal maturities is 5.31 mL/100 g, which decreases significantly to 0.09 mL/100 g when the kerogen sample is heat-treated to 450°C. The results can be attributed to strong attraction between the oxygen content in kerogen and water at low thermal maturities. We quantified the water-adsorption capacity of kerogen samples heat-treated at 450°C and found that volume of water adsorbed decreases with an increase in thermal maturity both in the presence and absence of bitumen. In the case of synthetic organic-rich mudrock samples, we found that the volume of water adsorbed in samples at higher thermal maturity decreases by 16% compared with organic-rich mudrocks at low thermal maturity at the same concentration of nonswelling clay minerals. Results from the flotation test showed that the oil-wettability of the synthetic organic-rich mudrock samples increases as its thermal maturity decreases, with a hydrogen index (HI) of 328 to 54 mg hydrocarbon/g organic carbon (mg-HC/g-OC). Results confirmed that kerogen and its geochemistry can have a significant influence on the overall wettability of organic-rich mudrocks even at low concentrations of 4 wt%. The outcomes of this paper can contribute to a better understanding of the parameters affecting wettability of organic-rich mudrocks and are promising for in-situ assessment of their wettability. This can potentially contribute to improved understanding of flow mechanisms in organic-rich mudrocks, which control hydrocarbon/water production.
Unconventional reservoirs such as Wolfcamp and Eagle Ford formations have played an important role in boosting the oil and gas production in the United States, but unfortunately, primary recovery from these reservoirs seldom exceeds 10%. Thus, operators are exploring enhanced oil recovery (EOR) techniques such as miscible gas injection (huff ‘n’ puff) and surfactants to increase the production from shales. This study evaluates several commercial surfactants and the commonly used solvent limonene for their ability to increase hydrocarbon recovery. The results show that the various surfactants at 2 gallons per ton (gal/t) or 0.8 wt% concentration recover up to 29, 33, and 34% hydrocarbons from Lyons sandstone, Wolfcamp, and Eagle Ford rock samples, respectively. This is significantly more than the base case (no surfactants), which recovers only 16, 19, and 14%, respectively. The increased recovery by surfactants can be partially explained by the reduction in interfacial tension (IFT) between crude oil and brine (up to 90%) caused by the surfactant solutions. Another important reason governing the hydrocarbon recovery is the ability of the surfactants to prevent asphaltene precipitation. This study focused on the interaction of the surfactants with the asphaltenes and found some surfactants can cause a linear decrease in asphaltene precipitation with increasing surfactant concentration. Finally, the contact angle measurements were used to study the change in wettability of the rock surface caused by surfactant solutions that can preferentially change the oil-wet and mixed-wet pores to more water-wet pores, thereby further aiding the hydrocarbon recovery. This study shows that an integrated approach including a broad spectrum of measurements such as aqueous stability, IFT, contact angle, phase behavior, spontaneous imbibition hydrocarbon recovery, and asphaltene precipitation is required to adequately characterize any surfactant and its ability to increase the hydrocarbon recovery.
The wettability of organic-rich mudrocks has a significant effect on multiphase-fluid flow and hydrocarbon recovery. This important rock property has still not been well-quantified in organic-rich mudrocks. Kerogen constitutes a significant fraction of mudrocks and can considerably affect their wettability. Recent publications suggested that kerogen wettability is affected by the thermal maturity of rocks and can influence the wettability of mudrocks. In this paper, we experimentally quantify the influence of geochemistry and thermal maturity of kerogen on the wettability of organic-rich mudrocks, and the influence of thermal maturity and chemical bonding on the wettability of kerogen. The wettability of organic-rich-mudrock samples at different experimental thermal-maturity levels was measured using the sessile-drop method, and also qualitatively estimated using a Flotation test and spontaneous-imbibition experiments on crushed-organic-rich-mudrock samples. The concentration of minerals in the mudrock samples was quantified using X-ray diffraction (XRD) at different experimental maturity levels. We then isolated kerogen samples from an organic-rich-mudrock formation and experimentally matured them. The variation in the chemical-bonding state of carbon present in kerogen at different levels of natural and experimental thermal maturity was determined using X-ray-photoelectron-spectroscopy (XPS) measurements. Finally, the wettability of pure-kerogen samples at different thermal-maturity levels was quantified using the sessile-drop method and the effect of aromatic carbon content on the wettability of the kerogen samples was determined.
The sessile-drop test performed on the organic-rich-mudrock-rock samples showed a 5° increase in contact angle with a 96% decrease in the hydrogen index (HI). The Flotation test showed that the oil-wet fraction of the mudrock samples increases by 81% as the heat-treatment temperature increases from nonheated to 650°C. The water-imbibition measurements in crushed-mudrock samples suggest that the volume of water imbibed was higher by 22 cm3 at lower thermal maturity [i.e., HI of 328 mg hydrocarbon/g organic carbon (mg HC/g OC)] compared with mudrock samples at higher thermal maturity (i.e., HI of 10 mg HC/g OC). Results indicate that the thermal maturity of kerogen could potentially affect the wettability of mudrocks and that the mudrock has higher water wettability at lower thermal maturity of kerogen. The experimental results also demonstrated that the wettability of kerogen changes from waterwet to hydrocarbon-wet with an increase in the aromatic carbon content. The contact angle of the water droplet on the kerogen samples from Formation A increased by 78° when the aromatic carbon concentration increased by 19%. The results contribute to a better understanding of the effects of kerogen wettability and thermal maturity on the wettability of organic-rich mudrocks. The outcomes can also have potential future contributions in understanding flow mechanisms in organic-rich mudrocks as well as in developing reliable rockphysics models for the interpretation of borehole geophysical measurements [e.g., electromagnetic and nuclear-magnetic-resonance (NMR) measurements] in organic-rich mudrocks.
Wang, Lin (Chengdu University of Technology / Guangdong University of Petrochemical Technology) | He, Yong Ming (Chengdu University of Technology) | Xiao, Yi Hang (Chengdu University of Technology) | Wang, Hong Hui (Chengdu University of Technology) | Ma, Fei Ying (Guangdong University of Petrochemical Technology)
The classic Lucas-Washburn imbibition equation is applicable only to homogeneous hydrophilic pores, not to hydrophobic and mixed-wet pores. Shale and coalbed rocks contain water-wet pores, oil-wet pores and mixed-wet pores. To describe water imbibition into these pores, functional relations between flow velocity of gas-water interface, interfacial tension, size of pore, contact angle, viscosity and area fraction of wall have been derived by the Lucas-Washburn equation method of mixed-wet cylindrical capillary. The result of research shows that contact angles and the surface-area fraction of wall combine to determine direction of flow during spontaneous gas-water imbibition in mixed-wet pore. The level-set numerical simulation method was used to verify the result of the Lucas-Washburn equation method, and results of the both methods are roughly consistent. The imbibition equation of mixed-wet pores can be used to determine whether fracturing-fluid imbibition occurs in rocks, and it can also provide a basis for adding wettability alteration additive in fracturing fluid.
The chemistry of injection water affects oil recovery from carbonate reservoirs by smartwater flooding. It is widely believed that the ions present in the smartwater alter the wettability of carbonate rocks, depending on their type and the amounts present. Although some effort has been made to understand the effects of salinity and water-ion compositions on wettability in carbonates, the prior research studies were mostly limited to contact angle, spontaneous imbibition, and coreflooding.
In the current study, adhesion forces between a carbonate substrate and a crude-oil droplet in the brines of varying ionic compositions were measured directly by using a custom-designed integrated-thin-film drainage apparatus (ITFDA) equipped with a bimorph force sensor. In addition, the liberation kinetics of crude oil from carbonate rocks were determined using an optical microscope-based liberation cell at both ambient and elevated temperatures. These measurements were complemented with thermogravimetric analysis (TGA) and standard macroscopic data such as water-contact angles and zeta-potentials. The effect of individual cations [calcium (Ca2+); magnesium (Mg2+)] and anions [sulfate (SO2–4)] on wettability, adhesion, and oil liberation in carbonates was studied by using reservoir rock surfaces, reservoir crude oil, and different brines composed of a single type of salt at a fixed low salinity. Both deionized (DI) water and low-salinity brine composed of sufficient amounts of the three key ions (SO2–4, Ca2+, and Mg2+) were also used as the baseline for these experiments. The results showed a significant increase in water wettability (or decrease in contact angles) with low-salinity brines compared with DI water, depending on the types of ions present in these brines. The presence of SO2–4 increased the water wettability the most, followed by the Ca2+ and Mg2+ ions. The zeta-potential data of carbonate rock minerals in DI water/brines showed similar trends on surface charges to correlate well with contact angles. Increasing the water wettability of brines on carbonate surfaces decreased the adhesion force between the oil and the rock in the corresponding brines. The adhesion forces on the carbonate surface were found to be in the following order: DI water > Mg2+ brine > Ca2+ low-salinity brine with SO2–4, Ca2+, and Mg2+ ions > SO2–4 brine. Such favorable changes in adhesion forces in turn led to more efficient crude-oil liberation from carbonates at a microscopic scale when exposed to different low-salinity brines than in DI water. The dynamic oil-liberation data from carbonates at both ambient and elevated temperatures demonstrated the significant advantage of low-salinity brine containing SO2–4 ions compared with DI water, but showed only its slight effectiveness over the low-salinity brine composed of three key ions. The TGA further confirmed the efficiency of both the low-salinity brines, composed of SO2–4 and the three key ions, to liberate more crude oil from carbonates.
The findings from different microscopic- to macroscopic-scale measurements reported in this work clearly indicate the importance of both lower salinity and the major role of certain ions in the smartwater to effectively release crude oil from carbonates. It can also be concluded that low-salinity water containing sufficient amounts of three key ions can become a practical smartwater for waterflooding operations, considering the adverse effect of SO2–4 ions on the interactions at the crude-oil/water interface as well as the reservoir damage resulting from scaling and souring issues.
Nuclear magnetic resonance (NMR) measurements have been attractive options for wettability characterization of reservoir rocks as they are sensitive to the type of fluid in contact with the grain surface. Several NMR-based wettability indices are documented in previous publications. Most of these methods require extensive calibration or involve complex inversion algorithms, which makes them computationally expensive and complicates their applicability in mixed-wet multimodal rocks. In this paper, we introduce a new NMR-based wettability index and verify its reliability in pore-scale and core-scale domains using numerical simulations and experimental measurements, respectively. This new index requires calibration at fully water-saturated water-wet and fully hydrocarbon-saturated hydrocarbon-wet states and can be applied to mixed-wet rocks at any fluid saturation level.
This new NMR-based wettability index is a function of the transverse magnetization (T2) of mixed-wet rocks, the bulk relaxivity and saturation of each fluid, and the T2 distributions for fully water-wet and hydrocarbon-wet samples of the same rock type. The reliability of the new index was first tested in the pore-scale domain. For this part, we selected several pore-scale microcomputed tomography (CT) images of carbonate and sandstone rocks. We used a previously developed finite volume simulator to model the T2 responses in these images at fully water-wet and fully hydrocarbon-wet wettability states. Then we generated synthetic partially saturated mixed-wet samples and simulated T2 responses in these synthetic images. We used the simulated T2 results for determining their NMR-based wettability index and verified its applicability in the pore-scale domain.
Next, we tested the reliability of the new NMR-based wettability index in the core-scale domain using NMR measurements in four Texas Cream (TC) rock samples, obtained from the Edwards formation. We altered the wettability of the cores to be water-, hydrocarbon-, and mixed-wet by injecting brine, a naphthenic acid in decane solution, or an anionic surfactant solution. We quantified the wettability of these samples using the Amott-Harvey (AH) index and contact angle measurements. Next, we measured the T2 distribution of these samples at different fluid saturation levels. Finally, we quantified the wettability values of these core samples using the new NMR-based index and compared them to those obtained from the AH index and contact angle measurements. We documented successful verification of the proposed method on samples with wettability ranging from –0.90 to 0.98 and from –0.6 to 0.5 (independently quantified using the AH method) in the pore- and core-scale domains, respectively. Results demonstrated that the new NMR-based wettability index reliably estimates the wettability of mixed-wet rocks in a wide range of wettability states. The new wettability index can potentially improve the speed and reliability of NMR-based wettability characterization and is promising for log-scale wettability assessment in mixed-wet rocks.