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Collaborating Authors
fluid distribution
Pore-Scale Modeling of Immiscible Displacement In Porous Media: The Effects of Dual Wettability
Cha, Luming (China University of Petroleum (East China)) | Feng, Qihong (China University of Petroleum (East China) (Corresponding author)) | Wang, Sen (China University of Petroleum (East China)) | Xu, Shiqian (Southwest Petroleum University) | Xie, Chiyu (University of Science and Technology Beijing (Corresponding author))
Summary Many naturally occurring porous media contain different types of grains with different wettabilities, therefore, understanding the effect of wettability heterogeneity on multiphase flow in porous media is important. We investigate the immiscible displacement during imbibition in a dual-wettability porous medium by direct pore-scale modeling. We propose a heterogeneous index (HI) to quantify the wettability heterogeneity. Our simulations on the capillary rise in dual-wettability tubes are compared with theoretical predictions, which verifies the numerical method. Our simulation results on the displacement in the dual-wettability porous media show that the wettability heterogeneity has a great impact on the fluid distribution, the capillary pressure curve, and the relative permeability curve. With the increase of wettability heterogeneity (HI), more capillary fingers are found during the displacement, the recovery rate of nonwetting fluid decreases, and the capillary pressure and the relative permeability of the wetting fluid decrease.
- North America > United States > Texas > East Texas Salt Basin > East Texas Field > Woodbine Formation (0.98)
- North America > United States > Gulf of Mexico > Central GOM > West Gulf Coast Tertiary Basin > Garden Banks > Block 605 > Winter Field (0.93)
Summary Clays, with their charged surfaces, are characterized by strong interactions with dissolved ions in brines and injected water. While there is a considerable body of research devoted to clay swelling, little to no progress has been made on fluid distributions and their impact on transport through clay pores when exposed to fluids of varying salinity. In this work, we use a molecular dynamics (MD) approach to characterize fluid distributions when oil and brine with varying salinities are present in clay-hosted pores. This promises to provide a rationale for optimizing salinities in fracturing fluid salinity (or low-salinity waterflooding applications). Both of these phenomena impede the diffusion of oil molecules through the clay nanopores. At intermediate values of salinity, in the absence of either ionic aggregates or water bridges, we observe the highest mobility of the oil phase. This modeling-based work provides a first look into optimal salinity values that promote oil mobility for fracturing fluids (or low-salinity waterflooding applications) for formations where clays may be present. Introduction Clay minerals are layer-type aluminosilicates (Sposito et al. 1999), ubiquitous in geological deposits (Pevear 1999; Tombรกcz et al. 2004; Katti et al. 2017; Hao et al. 2019). The crystal structures of clay minerals are usually classified as 1:1 or T:O type, typified by kaolinite (T and O stand for one tetrahedral silicate sheet and one octahedral hydroxide sheet separately) and 2:1 or T:O:T type, typified by illite (Ferrell 2013).
- Europe (1.00)
- North America > United States > Oklahoma (0.46)
- North America > United States > California (0.46)
- (3 more...)
X-Ray Computed Tomography Assisted Investigation of Flow Behaviour of Miscible CO2 to Enhance Oil Recovery in Layered Sandstone Porous Media
Al-bayati, Duraid (Curtin University) | Saeedi, Ali (Curtin University) | Ktao, Ipek (Private researcher) | Myers, Matthew (CSIRO-Energy) | White, Cameron (CSIRO-Energy) | Mousavi, Ali (Faculty of Upstream Petroleum Industry) | Xie, Quan (Curtin University) | Lagat, Christopher (Curtin University)
Abstract Reservoir heterogeneity reflected by permeability variation in the vertical direction is expected to significantly impact on the subsurface multiphase flow behaviour. In this context, we have shown previously that during immiscible flooding the crossflow between low and high permeability zones plays a significant role in determining the reservoir performance in terms of the hydrocarbon yield. In this manuscript, the contribution of crossflow to oil recovery in layered sandstone porous media during miscible CO2 flooding is explored. We conducted core flooding experiments using a core sample constructed by attaching two axially split half sandstone plugs each with a different permeability (0.008 and 0.1 (ฮผm)). The crossflow between the two layers was controlled by placing either a lint-free tissue paper or an impermeable Teflon sheet to represent a layered heterogeneity with and without communication, respectively. Additionally, to better understand the underpinning mechanisms influencing the flood performance, we imaged the samples during flooding using a high-resolution medical X-Ray computed tomography (XCT) scanner. Our results show that core-scale heterogeneity would indeed play an important role in determining the spatial distribution of the injected CO2during miscible flooding, consequently the oil recovery factor. For instance, our results confirm that permeability heterogeneity in vertical direction would lead to CO2 establishing a prefrential flow path through the high permeability layer leading to its early breakthrough. The above-mentioned CO2 channeling is clearly evident from the X-ray images captured during flooding. However, a reasonble amount of CO2 would still enter the low permeability layer contributing positively to the ultimate oil recovery factor. In fact, the post-processing of the XCT data confirmed the above to take place when cross-layer communication was allowed. The diversion of CO2 from the high to low permeablity layer is believed to be due to the crossflow phenomenon (induced by the viscous and dispersion forces) resulting in a subtle increase (i.e. 1.7%) in the ultimate oil recovery. In a similar study we have done about immiscible flooding, the contribution of crossflow to the overall recovery was found to be about 5%. The less pronounced effect of crossflow under miscible conditions is believed to be due to the absence of capillarity as a more effective driving force behind crossflow. To the best of our knowledge, our core-flooding results as presented in this manuscript and backed by X-ray CT visualisation, are the first set of their kind. They are insightful and would be of interest to the scientific community in revealing how crossflow may control flow behaviour in heterogeneous sandstone reservoirs, with important implications for numerical modelling of CO2 injection.
- Asia (1.00)
- North America > United States > Texas (0.46)
Abstract In this study, we established initial water saturation (Swi) using three techniques: (1) the dynamic displacement technique, (2) the porous plate technique, and (3) the vacuum saturation technique. A unique heterogeneous carbonate reservoir rock sample (1.5-inch diameter and 3-inches long) was used repeatedly to compare the techniques without an uncertainty of different cores. After establishing Swi by each initialization technique, the cross sections were scanned using a micro-CT scanner. The image data was processed to estimate the cross sectional fluid distribution in XY-direction. Furthermore, each areal average Swi was calculated to investigate Swi distribution in Z-direction (direction of injection). Based on the comparison of interpreted fluid distribution, pros/cons of each technique was discussed.
- North America > United States (0.68)
- Asia > Middle East > UAE (0.46)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Carbonate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Waterflooding (0.67)
Abstract In exploration areas formation water salinity is often unknown. Several log-based techniques can be used to estimate the water resistivity, which can be used to calculate the equivalent formation water salinity, such as the Pickett's plot technique or spontaneous potential (SP log) but remain subjected to some uncertainties. Although captured down hole samples can accurately determine salinity, it can take a long time to receive the laboratory analysis results, delaying the Field Development Plan (FDP) studies and affecting current logging operations decisions. In this paper, we tested two methodologies. First, we utilized a novel dry weight chlorine (DWCL) measurement from an advanced spectroscopy tool to estimate the formation salinity at the depth of investigation of the device. This newly introduced methodology can be used in areas where formation salinity is unknown. The second methodology uses a new downhole induction resistivity cell in the formation tester tool. This cell gives a calibrated direct measurement of the water resistivity in the flowline, which can be converted into an equivalent water salinity if temperature is provided, and cross-checked with the DWCL values from the spectroscopy tool. The new chlorine measurement, along with the flowline induction resistivity measurement, provides a robust workflow to estimate the formation water salinity, enhancing the quality of the saturation evaluation for quick decision-making during logging operations, and accelerating the evaluation studies rather than waiting on laboratory results.
- North America > United States (0.69)
- Asia > Middle East > Saudi Arabia (0.47)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Formation test analysis (e.g., wireline, LWD) (1.00)
- Well Drilling > Drilling Fluids and Materials > Drilling fluid selection and formulation (chemistry, properties) (0.98)
Abstract An Enhanced Geothermal System (EGS) uses flow through fractures in an effectively impermeable high-temperature rock formation to provide sustainable and affordable heat extraction that can be employed virtually anywhere with no need for a geothermal reservoir. The problem is that there is no commercial application of this technology. The three-well pattern introduced in this paper employs a multiple transverse fractured horizontal well (MTFHW) drilled and fractured in an effectively impermeable high-temperature formation. Two parallel horizontal wells drilled above and below or on opposing sides of the MTFHW have trajectories that intersect its created fractures. Fluid injected in the MTFHW flows through the fractures and horizontal wells, thus extracting heat from the surrounding high-temperature rock. This study aims to find the most cost-effective well and fracture spacing for this pattern to supply hot fluid to a 20-megawatt power plant. Analytical and numerical models compare heat transfer behavior for a single fracture unit in an MTFHW that is then replicated along with the horizontal well pattern(s). The Computer Modeling Group (CMG) STARS simulator is used to model the circulation of cold water injected into the center of a radial transverse hydraulic fracture and produced from two horizontal wells. Key factors to the design include formation temperature, the flow rate in fractures, the fractured radius, spacing, heat transfer, and pressure loss along the wells. The Aspen HYSYS software is used to model the geothermal power plant, and heat transfer and pressure loss in wells and fractures. The comparison between analytical and numerical models showed the simplified analytical model provides overly optimistic results and indicates the need for a numerical model. Sensitivity studies using the numerical model vary the key design factors and reveal how many fractures the plant requires. The economic performance of several scenarios was investigated to minimize well drilling and completion pattern costs. This study illustrates the viability of applying known and widely used well technologies in an enhanced geothermal system.
- Energy > Renewable > Geothermal > Geothermal Resource (1.00)
- Energy > Oil & Gas > Upstream (1.00)
- Energy > Renewable > Geothermal > Geothermal Resource for Power Generation > Enhanced Geothermal System (0.81)
- North America > United States > Texas > Haynesville Shale Formation (0.99)
- North America > United States > Louisiana > Haynesville Shale Formation (0.99)
- North America > United States > Arkansas > Haynesville Shale Formation (0.99)
Experimental Study on the Saturation Model of Volcanic Rock Based on Fluid Distribution
Pan, Baozhi (College of Geo-exploration Science and Technology) | Zhou, Weiyi (College of Geo-exploration Science and Technology) | Guo, Yuhang (College of Geo-exploration Science and Technology) | Si, Zhaowei (Exploration and Development Research Institute of Jidong Oilfield Company) | Lin, Fawu (Exploration and Development Research Institute of Jidong Oilfield Company)
A saturation evaluation model suitable for Nanpu volcanic rock formation is established based on the experiment of acoustic velocity changing with saturation during the water drainage process of volcanic rock in the Nanpu area. The experimental data show that in the early stage of water drainage, the fluid distribution in the pores of rock samples satisfies the patchy formula. With the decrease of the sample saturation, the fluid distribution in the pores is more similar to the uniform fluid distribution model. In this paper, combined with the Gassmann-Brie and patchy formula, the calculation equation of Gassmann-Brie-Patchy (G-B-P) saturation is established, and the effect of contact softening is considered. The model can be used to calculate water saturation based on acoustic velocity, which provides a new idea for the quantitative evaluation of volcanic oil and gas reservoirs using seismic and acoustic logging data.
- Asia > China (0.28)
- North America > United States (0.28)
- Europe > Norway > Norwegian Sea (0.24)
- Research Report > New Finding (0.65)
- Research Report > Experimental Study (0.51)
- Geology > Rock Type (1.00)
- Geology > Geological Subdiscipline > Volcanology (1.00)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)
- Asia > China > Bohai Bay > Bohai Basin > Jidong Nanpu Field (0.99)
- North America > United States > Wyoming > Wood Field (0.89)
- North America > United States > Oklahoma > Anadarko Basin > Lindsay Field (0.89)
ABSTRACT: In-well fiber optics Distributed Acoustic Sensing (DAS) data are widely used to estimate cluster fluid contribution and monitor cross-stage fluid communication. One common way of visualizing fluid distribution is through waterfall plots of energy attribute derived from the DAS data. The energy attribute in combination with the treatment data is used to quantitatively calculate fluid contribution, which is usually visualized as histogram or dynamic flow-rate plots. Using the relationship between the energy attribute and the flow rate, we compute cumulative slurry per cluster and plot them with time (cumsum-time curves) on top of treatment curves. The slope of the cumulative slurry curves can be used to estimate the average flow rate through each perf cluster, where higher slopes represent higher flow rates and vice versa. The curves can also be used to visualize how the flow rate is changing with stimulation. We showed these curves for DAS data acquired in a treatment well in the Marcellus Shale. We observed a varying slope (infers varying flow rate) of cumulative slurry for inter and intra-stage perf clusters reacting to changes in proppant concentration. The cumsum-time curves provide new insights into flow-rate dynamics of individual clusters in relation to the treatment data. 1. Introduction Multiple diagnostic tools are available to understand the efficacy of hydraulic fracturing of a horizontal well. Common tools include radioactive tracers, microseismic monitoring, video-based perforation imaging, fiber optic distributed acoustic sensing (DAS), and distributed temperature sensing (DTS) data (Ugueto C et al., 2016; Cramer et al., 2019; Lorwongngam et al., 2020). Distributed fiber optic technology consists of a fiber cable with an intrinsic sensor that measures the spatial distribution of acoustic vibrations (DAS) or temperature (DTS) along the sensing fiber (Hartog, 2017). The low-frequency (< 0.05 Hz) component of DAS (LF-DAS) is a powerful tool to monitor small strain perturbations caused by hydraulic fracturing (Jin and Roy, 2017). The completion effectiveness of a hydraulically fractured well can be monitored with fiber installed in the treatment well (In-well monitoring) or with fiber installed in offset wells (Cross-well monitoring). In-well fiber monitoring is used to understand the perf cluster efficiency, fluid allocation, and cross-stage fluid communications. Offset-well fiber can be used to detect fracture-driven interactions, also called frac-hits.
- North America > United States > West Virginia (0.36)
- North America > United States > Virginia (0.36)
- North America > United States > Texas > Harris County > Houston (0.28)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Pennsylvania > Appalachian Basin > Marcellus Shale Formation (0.99)
- (3 more...)
Abstract In previous frac designs, proppant tracer logs revealed poor proppant distribution between clusters. In this study, various technologies were utilized to improve cluster efficiency, primarily focusing on selecting perforations in like-rock, adjusting perforation designs and the use of diverters. Effectiveness of the changes were analyzed using proppant tracer. This study consisted of a group of four wells completed sequentially. Sections of each well were divided into completion design groups characterized by different perforating methodologies. Perforation placement was primarily driven by RockMSE (Mechanical Specific Energy), a calculation derived from drilling data that relates to a rock's compressive strength. Additionally, the RockMSE values were compared alongside three different datasets: gamma ray collected while drilling, a calculation of stresses from accelerometer data placed at the bit, and Pulsed Neutron Cross Dipole Sonic log data. The results of this study showed strong indications that fluid flow is greatly affected by rock strength as mapped with the RockMSE, with fluid preferentially entering areas with low RockMSE. It was found that placing clusters in similar rock types yielded an improved fluid distribution. Additional improved fluid distribution was observed by adjusting hole diameter, number of perforations and pump rate.
- Geology > Geological Subdiscipline > Geomechanics (0.88)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.41)
- Geology > Petroleum Play Type > Unconventional Play > Shale Play > Shale Gas Play (0.41)
- North America > United States > Texas > Fort Worth Basin > Barnett Shale Formation (0.99)
- North America > Canada > Alberta > Johnson Field > Cardinal Hz Johnson 2-15-16-14 Well (0.97)
Modeling Wellbore Proppant Transport and Distribution Across a Single Hydraulic Fracturing Stage Under Field Conditions Using Computational Fluid Dynamics
Kebert, Brent (Colorado School of Mines) | Almulhim, Abdulraof (Colorado School of Mines) | Miskimins, Jennifer (Colorado School of Mines) | Hunter, William (Ovintiv Inc) | Soehner, Gage (Ovintiv Inc)
Abstract Successfully treating each cluster within a hydraulic fracturing stage is a key objective for "plug-n-perf" well completions. Most operating companies would agree that the main underlying desire for a successful completion is related to future production capability. In unconventional reservoirs, propped and conductive hydraulic fractures are the primary completion result that drives production and reserve recovery. When designing a treatment, the spacing of clusters is critical to optimizing production and reserve recovery parameters, and therefore, even proppant distribution across a single stage delivers a well the greatest potential for optimized production performance. Diverting the fracturing fluid and proppant evenly across the clusters in a stage allows the greatest opportunity for each cluster to produce equally and drain the associated reservoir volume. Generating equal, producing fractures across a horizontal wellbore is a difficult problem that operators are still trying to solve. This work models the fluid and proppant distribution across a field-scale, 250-ft long, horizontal hydraulic fracturing stage, replicating realistic field conditions. By utilizing computational fluid dynamics (CFD), this paper investigates the effected proppant distribution results from a fracturing stage mimicking the presence of both a leaking plug and the impacts of stress shadowing. The proppant concentration throughout the wellbore, along with internal wellbore pressure and velocity, are also reviewed to gain an understanding of the effect of the field conditions. Additionally, this paper illustrates the effect of different proppant "ramping" conditions during the fracturing stage. Proppant ramping schedules can be smooth or sharp when increasing proppant concentration, which alters the proppant concentrations throughout the wellbore and associated perforation clusters. Unanticipated alterations of the proppant concentration within the wellbore can lead to early screenouts. Gaining a better understanding of the proppant distribution and concentration inside the wellbore can lead to improved designs of hydraulic fracturing completions.