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Applying simpler and more powerful waterflood performance analytical modeling tools to history match and forecast fluid (oil and water) production rates is always a subject of interest. Increasing improvements of these no grid-based tools trigger their use as predictive and trustworthy precursors of grid-based modeling, providing significant insights and allowing a previous assessment of historical and future waterflood performance without a significant time-and investment-consuming modeling. Setting up a unified fractional-flow model (UFFM), that considers both the traditional Buckley-Leverettbased stable fractional-flow model (BLBFFM) and instabilities due to oil viscous-fingering effect, to accurately predict the oil recovery from traditional waterflood performance analytical modeling tools is the objective of this paper. The unification is based on using appropriate k ro/ k rw vs. water saturation expression that considers viscous-oil effect based on the effective finger model (EFM), allowing the substitution of a classic semilog linear relationship of k ro/ k rw vs. S w (constant coefficients A and B) by a unified nonlinear oilwater relative permeability ratio. This UFFM approach aims to boost the analysis from well-known waterflood performance analytical methods: water-oil ratio (WOR), X-plot, Y-function and the capacitance-resistance model (CRM).
Thomas, F. Brent (Resopstrategies) | Qanbari, Farhad (Seven Generations Energy) | Piwowar, Michael (Stratum Reservoir) | Noroozi, Mehdi (Stratum Reservoir) | Apil, Ronnel (Stratum Reservoir) | Marin, Juan (Stratum Reservoir) | Gibb, William (Stratum Reservoir) | Clarkson, Carter (Stratum Reservoir) | Zhang, Hongmei (Stratum Reservoir) | Swacha, Stan (Stratum Reservoir)
An experimental apparatus was developed that provides axial fracture flow and radial matrix flow in the context of differential pressure gradients at full reservoir conditions. Flow within the frac(s) and flow between frac(s) and matrix are operative in the system. The influence of cycling pressure, injection gas composition, soak time and level of primary depletion before initiation of GCEOR have been measured previously with volatile oil systems. To date no direct comparison has been made with rich gas condensate GCEOR performance in the same rock with similar GCEOR design parameters. Primary depletion of a volatile oil in a Montney porous media is compared to primary depletion in the same rock with a rich gas condensate. Pursuant to primary depletion, GCEOR was applied for both the oil and the gas condensate fluid.
A novel experimental design for core-flow testing has permitted the quantification of GCEOR using large lab-scale hydro-carbon pore volumes (HCPV). The unique experimental design allows nano-Darcy media to be tested using a time line comparable to conventional millidarcy media. The porous media tested herein exhibited a reservoir oil permeability of 110 nD at full reservoir conditions. Mechanisms for EOR have been described previously on the basis of this experimental protocol. Due to the large hydrocarbon pore volume of this procedure (130 to 480 ml) measurements of produced gas, liquid and recombined fluid compositions are obtained, as a function of Puff cycle number, as well as produced liquid densities and recovery factors cycle to cycle. These procedures were applied to a volatile oil and a retrograde condensate fluid.
A naturally-fractured porous media was saturated with a dew point fluid exhibiting a condensate-gas ratio of 200 BBL/MMscf. Primary depletion was conducted following a linear pressure depletion corresponding to field-real primary production times scaled to the laboratory experiment. Liquid recovery factor, produced fluid compositions and densities along with frac and matrix pressures were recorded. Pursuant to primary depletion GCEOR was conducted in order to quantify the increased liquid recovery after primary production. The system was then extracted to determine Sor. The porous media was then re-saturated and restored with volatile oil and primary depletion followed by GCEOR. It was observed that liquid recovery factor was better for the gas condensate in this low-permeability porous media. Primary depletion produced higher liquid recovery (C6+) with the gas condensate fluid than with the volatile oil. GCEOR after primary depletion performed similarly. Other insights were obtained and are discussed.
Liang, Xingyuan (China University of Petroleum at Beijing) | Zhou, Fujian (China University of Petroleum at Beijing) | Liang, Tianbo (China University of Petroleum at Beijing) | Wang, Rui (China University of Petroleum at Beijing) | Su, Hang (China University of Petroleum at Beijing) | Wang, Xinglin (Rice University)
Liquid nanofluid (LNF) is being gradually used in unconventional reservoirs. However, the application of LNF during hydraulic fracturing in tight reservoirs needs to be further investigated. In this study, a series of experiments were conducted to discuss the above problem. First, a new method to evaluate wettability in different pore-scale was provided. Then core flooding experiments were conducted to study invasion pressure for the LNF. Finally, the efficiency of drag reduction after adding the LNF was evaluated. The result showed that imbibition and nuclear magnetic resonance (NMR) can be combined to evaluate the average wettability for the unconventional rock. Core flooding experiments stated that the LNF could reduce the invasion pressure, which would enhance the effective volume. Drag reduction experiments demonstrate that LNF makes drag reduction more efficient. Field application proved the LNF could help enhance the production in tight oil reservoirs. Several advantages of using LNF in the process of hydraulic fracturing were also revealed.
The tight oil reservoir has been one crucial part of petroleum resources (Hu et al., 2019; Li and Misra, 2018; Liang et al., 2020a). The hydraulic fracturing and horizontal well have been two main technologies to explore the tight and other unconventional reservoirs(Liang et al., 2020b; Wang et al., 2019, 2015, 2020b). However, the production decreases rapidly on account of low permeability and complex pore structure(Liang et al., 2017; Wang et al., 2020a). Imbibition has been one of the important methods to enhance oil recovery in unconventional reservoirs(Liang et al., 2020c; Liu et al., 2019; Meng et al., 2016). Imbibition help replaces the oil into fractures and helps increase production. Wettability is one of the most important factors, which influence the imbibition oil recovery. As we all know, the aqueous phase can be spontaneously imbibed into the rock with water-wet; while the rock with oil-wet cannot imbibe aqueous fracturing fluid spontaneously. The rock has been turned into oil/mix wet after contacting with crude oil for hundreds of years, especially for carbonate minerals. Wettability testing is much important so that people can understand the potential imbibition ability for the reservoir. Besides, people could evaluate the wettability alteration after using chemical additive, like surfactant or micro emulsion.
Relative permeability is an important control on fluid (gas/liquid) mobility in the reservoir, and a key input for models used to evaluate primary and enhanced oil recovery in tight hydrocarbon reservoirs. However, this critical property is notoriously difficult and time-consuming to measure in the laboratory for lowpermeability sedimentary rocks with permeability values in the nanodarcy/microdarcy range. The primary objectives of this work are to 1) implement a series of rigorous-yet-simple methods for laboratory-based characterization of gas/liquid relative permeability in tight oil reservoirs with examples from western Canadian tight oil plays, 2) compare different laboratory-based techniques for determination of gas/liquid relative permeability in tight rocks and 3) examine the impact of a variety of operational controls (e.g. fluid saturation, pore/reservoir pressure, hysteresis path) on relative permeability of these unconventional reservoirs.
Using a customized liquid/relative permeameter designed and constructed in-house, gas/liquid relative permeability tests are conducted with formation oil using different hydrocarbon/non-hydrocarbon gases (CH4, N2) on intact core plug samples extracted from the Montney and Duvernay formations (Alberta, Canada). Two direct methods for measuring gas/liquid relative permeability data are investigated including a modified version of the Dacy method and the "gas breakthrough" (GBT) technique, tailored to high- (> 0.001 md) and low-permeability samples (< 0.001 md), respectively. The modified Dacy method is based on the stationary-liquid approach, resulting in relative permeability estimation as a function of fluid saturation. The GBT technique is based on "forced" drainage and spontaneous imbibition cycles, resulting in relative permeability estimation as a function of differential pressure. To the best of our knowledge, this is the first-time application of GBT method to tight oil systems for gas/oil relative permeability evaluation.
Experimental observations indicate that relative permeability values are affected by fluid saturation, pore/reservoir pressure, differential pressure, and hysteresis path. Using the GBT method, the maximum relative permeability values measured after gas breakthrough on fully/partially oil-saturated core plug samples vary between 0.02 and 0.32, depending on pore pressure (1.3 – 6.4 MPa; 190 – 930 psi), effective stress (3.4 – 19.4 MPa; 480 – 2810 psi), differential pressure (0.5 – 3.1 MPa; 65 – 445 psi) and hysteresis path. Using the GBT technique, the gas relative permeability values 1) first increase, and then decrease after gas breakthrough for
Accurate determination of relative permeability – a critical control on multi-phase flow in tight oil reservoirs – is essential for reliable production forecast and optimizing field-scale models. For tight oil systems, however, only a few experimental datasets are available in the literature primarily for rock samples with permeability values in the microdarcy/millidarcy range. The systematic two-phase (gas/liquid) flow experiments conducted herein extend the available experimental dataset and are of significant importance for constraining 1) rate-transient analysis (RTA) models used to evaluate reservoir and hydraulic fracture properties and 2) numerical simulation of primary and enhanced oil recovery, particularly cyclic solvent injection (huff-n-puff) processes in tight oil systems.
Ali, Safdar (W.D. Von Gonten Laboratories) | Barnes, Colton (W.D. Von Gonten Laboratories) | Mathur, Ashish (W.D. Von Gonten Laboratories) | Chin, Brian (W.D. Von Gonten Laboratories) | Belanger, Chad (W.D. Von Gonten Laboratories)
Techniques such as horizontal drilling and hydraulic fracturing have helped in exploitation of unconventional shale reservoirs. However, a drawback of hydraulic fracturing is that it results in forced imbibition of frac-water into the pore system of the organic shale matrix. This can potentially result in lower productivity emanating from water blockage of oil-wet and oil-bearing nano-pore networks. This paper introduces a laboratory setup to investigate and quantify the damage to oil permeability caused by invasion of fracturing fluids in shales. The proposed process also allows for testing the impact of altering completions fluids chemistry (fresh versus produced water, surfactants, friction reducers, etc) on oil productivity.
The technique starts with carrying out micro-CT and NMR scans on as-received shale plug samples to evaluate sample condition and fluid saturations. These samples are then humidified and then saturated with either produced crude, after which a subsequent NMR scan is done to track oil and water saturation. For the permeability measurement, the samples are then loaded in an overburden cell, some of which are made of non-ferrous material and can be loaded in the NMR spectrometer. The sample is brought to reservoir stress conditions by increasing overburden stress and pore pressure gradually. The initial steady state permeability measurement is measured by injecting produced crude or hydrocarbon gases at a constant flow rate using a pump and monitoring pore pressures for stability. The downstream pressure is controlled by a back-pressure regulator.
Once steady state flow is established and the baseline effective hydrocarbon permeability is measured, a brine or a fracturing fluid solution is injected into the sample from the downstream side (frac face) for a specified time period. The completion fluid injection pressure is typically about 1000 psi to 2000 psi higher than the upstream oil pressure to simulate hydraulic fracturing induced imbibition of water. Then, to mimic shut-in that follows hydraulic fracturing of a stage, the upstream and downstream valves are closed for about 12 to 24 hours. Finally, hydrocarbon permeability is measured again as was done initially, to quantify degradation of deliverability due to water imbibition. Saturations of hydrocarbon fluid and brine in the sample are calculated using NMR T2 and T1T2 scans either during the test or right after the test is complete. In some instances, the saturation front of the hydrocarbon fluid or injected brine is examined using 2D and 3D gradient NMR scans.
These tests can be conducted at high pressure and temperature, while the setup that involves continuous NMR scanning of the plug during the core flooding process is rated to 10,000 psi for overburden pressure, 9000 psi for reservoir pressure and 100 C for reservoir temperature [Mathur et al. 2020]. Permeabilities as lows as 5 nano-Darcies can be measured. Varying completions fluids chemistries (salinity alteration, KCl, surfactants, FRs, etc) can also be used in the setup to evaluate the benefit or lack thereof in minimizing permeability damage.
On average, a decrease of 70% in hydrocarbon productivity is observed on comparing initial permeability and final permeability after water damage. As a validation of the water block phenomenon, samples have also been injected with decane and diesel from the bottom and little to no damage in hydrocarbon productivity is observed. Some scenarios of adding surfactant mixtures to the frac water, as well as cyclic gas injection have shown initial positive results; and are active areas of study.
Thomas, F Brent (Resopstrategies) | Piwowar, Michael (Stratum Reservoir) | Noroozi, Mehdi (Stratum Reservoir) | Apil, Ronnel (Stratum Reservoir) | Marin, Juan (Stratum Reservoir) | Gibb, William (Stratum Reservoir) | Clarkson, Carter (Stratum Reservoir) | Zhang, Hongmei (Stratum Reservoir) | Swacha, Stan (Stratum Reservoir)
The role of cycling pressure, injection gas composition, soak time and level of primary depletion before initiation of GCEOR and the importance of geology have been measured. Gas-cycling Huff and Puff operations have been analyzed in porous media exhibiting in situ oil permeabilities ranging from 20 to 2000 nD, with fluid densities between 40 and 47 API and gas-oil ratios between 800 and 2750 scf/BBL. The importance of geological properties relative to oil properties in GCEOR design was quantified along with analysis of GCEOR performance in systems exhibiting Peclet numbers changing over two orders of magnitude.
High-permeability fracs and very low permeability matrix have been combined into a novel patent-pending laboratory equipment design whereby large hydrocarbon pore volumes with live reservoir fluids are used. Flow between matrix and fracture(s) is induced by scaling field operations to lab-size experiments and inducing differential pressure gradients between matrix and frac during Huff and Puff cycles. Produced gas, liquid and recombined fluid compositions, as a function of time, are measured along with produced liquid densities. Full reservoir conditions are reproduced and Primary Depletion followed by Huff and Puff GCEOR are evaluated, while changing the design parameters listed above. This work has been performed on diverse oil and rock properties. With this equipment various fluids can be tested in diverse porous media whereby the relative importance of rock properties on GCEOR performance is measured. Moreover, for porous media that exhibit broad pore size distributions, or micro-scale heterogeneity, the efficacy of conformance control agents can be evaluated.
With more than fifty primary depletion tests followed by cyclic Huff and Puff gas injection, insights into GCEOR have been obtained. First-contact miscible gases have been observed to respond very differently as a function of changes in rock properties and reservoir fluid volatility. Performing primary depletion followed by GCEOR with different reservoir fluids but in the same porous media elucidate the importance of rock properties. It was found that appropriate GCEOR design must consider rock quality. Mercury injection capillary pressure data have been measured and are shown to breathe insight into GCEOR performance. For geology that possesses micro-scale heterogeneity water injection was used as a conformance control agent. GCEOR performance is quantified with and without water as a means of conformance control. The effects of cycling pressure, injection gas composition, soak time, level of primary depletion, before GCEOR, and other parameters have been investigated. All GCEOR testing was done in order to quantify the relative benefit compared to primary depletion recovery. This experimental protocol represents a valuable adjunct to using simulation to scale-up from lab to field.
The conceptual aspects of the displacement of oil by gas in reservoir rocks are discussed in this article. There are three aspects to this displacement: gas and oil viscosities, gas/oil capillary pressure (Pc) and relative permeability (kr) data, and the compositional interaction, or component mass transfer, between the oil and gas phases. One must first understand the viscosity and density differences between gas and oil to appreciate why the gas/oil displacement process can be very inefficient. Gases at reservoir conditions have viscosities of 0.02 cp, whereas oil viscosities generally range from 0.5 cp to tens of centipoises. Gases at reservoir conditions have densities generally one-third or less than that of oil.
The expanding solvent-steam-assisted gravity drainage (ES-SAGD) is a newly proposed thermal recovery technique showing promising efficiency in terms of a smaller steam-to-oil ratio and greater production rate to recover heavy oils and bitumen from oil-bearing formations, where a solvent is coinjected with the steam in the SAGD process. Numerical simulation of the ES-SAGD process requires reliable relative permeability data. The number of reported measurements of relative permeability involving bitumen systems is limited in the literature, mostly because of the experimental difficulties involved in such measurements. The relative permeability data sets for Canadian bitumen, in the presence of solvents, are simply not available in the open literature. The fluid-flow behavior of bitumen/water systems in the presence of solvent is an important matter that must be assessed before the implementation of any ES-SAGD process; therefore, the objective of the current study is to evaluate the impact of a light hydrocarbon solvent (n-hexane) on bitumen/water relative permeability under SAGD conditions. For this purpose, two-phase bitumen/water relative-permeability measurements were conducted in sandpacks over a wide range of temperatures from 70°C to 220°C using Athabasca bitumen, deionized water, and a light hydrocarbon solvent. A well-instrumented experimental setup was developed to perform the relative permeability measurements with the capability of applying confining pressure on the sand and measuring the pore-pressure profile with several intermediate pressure taps. Isothermal oil-displacement tests were carried out with solvent premixed with bitumen. The history-matching approach and Johnson-Bossler-Naumann (JBN) method were used to translate the oil displacement data into the relative-permeability curves. The results obtained with a solvent from this study and without any solvent reported in our previous study are compared to assess the solvent’s impact on relative permeability. In addition, the steady-state relative permeability was measured to assess the reliability of unsteady-state relative permeability. The interfacial tension (IFT) and contact-angle measurements using the same fluids were carried out to determine the fluid/fluid interaction and wettability state of the system under high-pressure/high-temperature (HP/HT) conditions.
The results of the present study confirmed that the two-phase diluted bitumen/water relative permeability is sensitive to temperature, especially in terms of the endpoint relative permeability to bitumen and water. Furthermore, adding normal hexane (below the asphaltene precipitation threshold) not only improves the displacement efficiency of water flooding because of the significant decrease in oil viscosity but also modifies the wettability and IFT of this system. At the same temperature, the two-phase oil/water relative permeability for bitumen/water systems is significantly different when the oil is diluted with the solvent. Also, the impact of solvent is more pronounced at lower temperatures. Furthermore, the consistency between the steady-state and unsteady-state relative permeability data proved that the effect of viscous fingering was small enough.
In this paper, we investigate the change in oil effective permeability (keffo) caused by fracturing-fluid (FF) leakoff after hydraulic fracturing (HF) of tight carbonate reservoirs. We perform a series of flooding tests on core plugs with a range of porosity and permeability collected from the Midale tight carbonate formation onshore Canada to simulate FF-leakoff/flowback processes. First, we clean and saturate the plugs with reservoir brine and oil, and age the plugs in the oil for 14 days under reservoir conditions (P = 172 bar and T = 60°C). Then, we measure keffo before (baseline) and after the leakoff process to evaluate the effects of FF properties, shut-in duration, and plug properties on regained permeability values.
We found that adding appropriate surfactants in FF not only significantly reduces keffo impairment caused by leakoff, but also improves keffo compared with the original baseline for a low-permeability carbonate plug. For a plug with relatively high permeability (kair > 0.13 md), freshwater leakoff reduced keffo by 55% (from 1.57 to 0.7 md) while FF (with surfactants) reduced keffo by only 10%. The observed improvement in regained keffo is primarily because of the reduction of interfacial tension (IFT) by the surfactants (from 26.07 to 5.79 mN/m). The contact-angle (CA) measurements before and after the flowback process do not show any significant wettability alteration. The results show that for plugs with kair > 0.13 md, FF leakoff reduces keffo by 5 to 10%, and this range only increases slightly by increasing the shut-in time from 3 to 14 days. However, for the plug with kair < 0.09 md, the regained permeability is even higher than the original keffo before the leakoff process. We observed 28.52 and 64.61% increase in keffo after 3- and 14-day shut-in periods, respectively. This observation is explained by an effective reduction of IFT between the oil and brine in the pore network of the tight plug, which significantly reduces irreducible water saturation (Swirr) and consequently increases keffo. Under such conditions, extending the shut-in time enhances the mixing between invaded FF and oil/brine initially in the plug, leading to more effective reductions in IFT and consequently Swirr. Finally, the results show that the regained permeability strongly depends on the permeability, pore structure, and Swirr of the plugs.
Sugar, Antonia (King Abdullah University of Science & Technology) | Serag, Maged F. (King Abdullah University of Science & Technology) | Torrealba, Victor A. (King Abdullah University of Science & Technology, now at Chevron Corp.) | Buttner, Ulrich (Nanofabrication Core Lab, King Abdullah University of Science & Technology) | Habuchi, Satoshi (King Abdullah University of Science & Technology) | Hoteit, Hussein (King Abdullah University of Science & Technology)
Understanding polymer transport through porous media is key to successful field implementations, including well conformance control and EOR processes. Polymer retention is typically assessed indirectly through its effect on pressure drops and effluent concentrations. Microfluidic techniques represent convenient tools to observe and quantify polymer retention in porous media. In this paper, we demonstrate how a soft-lithography microfluidics protocol can be used to gain insights into polymer transport mechanisms through rocks.
The design of the microfluidic chips honors typical pore-size distributions of oil-bearing conventional reservoir rocks, with pore-throats ranging from 2 to 10 μm. The fabrication technology enables the design transfer on a silicon wafer substrate using photolithography. The etched wafer holding the negative pattern of the pore-network served as a mold for building the microfluidics chip body out of polydimethylsiloxane (PDMS). The oxygen plasma bonding of the PDMS to a thin glass slide resulted in a sealed microfluidic chip, conceptually referred to as "Reservoir-on-a-Chip". We conduct single-phase polymer flooding experiments on the designed chips to understand how polymer-rock interactions impact polymer transport behavior in rocks. These experiments allow for polymer transport visualization at the molecule-scale owing to the use of polymer tagging and single-molecule tracking techniques.
This study presents, for the first time, a direct visualization of polymer retention mechanisms in porous media. We identified three mechanisms leading to polymer retention: adsorption, mechanical entrapment, and hydrodynamic retention. Polymer adsorption on the chip surfaces resulted in flow conductivity reduction in specific pathways and complete blockage in others, inducing alterations in the flowpaths. This mechanism occurred almost instantaneously during the first minutes of flow then, dramatically diminished as adsorption was satisfied. In addition to static adsorption, flow-induced adsorption (entrapment) was also distinguished from the binding of flowing polymer molecules to the already adsorbed polymer layer. Evidence of polymer desorption was observed, which consents with the presumed reversibility character of polymer retention mechanisms. The narrowest channels along with the reduced area due to adsorption, created favorable conditions for polymer entrapment. Both mechanical and hydrodynamic trapped polymers were successfully imaged. These phenomena led to polymer clogging of the porous network, which is one of the major concerns for operational aspects of polymer flooding processes.
Better understanding and quantification of polymer retention in porous media can help to make better decisions related to field-scale implementations of polymer-based processes in the subsurface. In this study, we used a soft-lithography fabrication technique and single-molecule imaging, to show, for the first time, polymer transport insights at the molecule- and pore-scales. This approach opens a new avenue to improve our understanding of the first principals of polymer retention while flowing through porous media.