A New Approach for Building Composite Cores for Corefloods in Complex Carbonate Rocks

Carbonate reservoir rocks are composed of complex pore structures and networks, forming a wide range of sedimentary facies. Considering this complexity, we present a novel approach for a better selection of coreflood composites. In this approach, reservoir plugs undergo a thorough filtration process by completing several lab tests before they get classified into reservoir rock types. Those tests include conventional core analysis (CCA), liquid permeability, plug computed tomography (CT), nuclear magnetic resonance (NMR), end-trim mercury injection capillary pressure (MICP), X-ray diffraction (XRD), thin-section analysis (TS), scanning electron microscopy (SEM), and drainage capillary pressure (Pc). We recommend starting with a large pool of plugs and narrowing down the selection as they complete different stages of the screening process. The CT scans help to exclude plugs exhibiting composite-like behavior or containing vugs and fractures that potentially influence coreflood results. After that, the plugs are categorized into separate groups representing the available reservoir rock types. Then, we look into each rock type and determine whether the selected plugs share similar pore-structures, rock texture, and mineral content. The end-trim MICP is usually helpful in clustering plugs having similar pore-throat size distributions. Nevertheless, it also poses a challenge because it may not represent the whole plug, especially for heterogeneous carbonates. In such a case, we recommend harnessing the NMR capabilities to verify the pore-size distribution. After pore-size distribution verification, plugs are further screened for textural and mineral similarity using the petrographic data (XRD, TS, and SEM). Finally, we evaluate the similarity of brine permeability (Kb), irreducible water saturation (Swir) from Pc, and effective oil permeability data at Swir (Koe, after wettability restoration for unpreserved plugs) before finalizing the composite selection. The paper demonstrates significant aspects of applying the proposed approach to carbonate reservoir rock samples. It integrates geology, petrophysics, and reservoir engineering elements when deciding the best possible composite for coreflood experiments. By practicing this workflow, we also observe considerable differences in rock types depending on the data source, suggesting that careful use of end-trim data for carbonates is advisable compared to more representative full-plug MICP and NMR test results. In addition, we generally observe that Kb and Koe are usually lower than the Klinkenberg permeability with a varying degree that is plug-specific, highlighting the benefit of incorporating these measurements as additional criteria in coreflood composite selection for carbonate reservoirs.

Calculation Model of Relative Permeability in Tight Sandstone Gas Reservoir with Stress Sensitivity

During the development of tight gas reservoir, the irreducible water saturation, rock permeability, and relative permeability change with formation pressure, which has a significant impact on well production. Based on capillary bundle model and fractal theory, the irreducible water saturation model, permeability model, and relative permeability model are constructed considering the influence of water film and stress sensitivity at the same time. The accuracy of this model is verified by results of nuclear magnetic experiment and comparison with previous models. The effects of some factors on irreducible water saturation, permeability, and relative permeability curves are discussed. The results show that the stress sensitivity will obviously reduce the formation permeability and increase the irreducible water saturation, and the existence of water film will reduce the permeability of gas phase. The increase of elastic modulus weakens the stress sensitivity of reservoir. The irreducible water saturation increases, and the relative permeability curve changes little with the increase of effective stress. When the minimum pore radius is constant, the ratio of maximum pore radius to minimum pore radius increases, the permeability increases, the irreducible water saturation decreases obviously, and the two-phase flow interval of relative permeability curve increases. When the displacement pressure increases, the irreducible water saturation decreases, and the interval of two-phase flow increases. These models can calculate the irreducible water saturation, permeability and relative permeability curves under any pressure in the development of tight gas reservoir. The findings of this study can help for better understanding of the productivity evaluation and performance prediction of tight sandstone gas reservoirs.

An Integrated Petrophysical Characterization of a Siliciclastic Tight Gas Reservoir in Neuquén Basin, Western Argentina

The Río Neuquén Field is located between Neuquén and Río Negro provinces, Argentina. Historically, it has been a conventional oil producer, but it was converted to a tight gas producer from deeper reservoirs. The targeted geological formations are Lajas, which is already a known tight gas producer, and the less-known overlaying Punta Rosada Formation, which is the main objective of the current work. Punta Rosada presents a diverse lithology, including shaly intervals separating multiple stacked reservoirs that grade from fine-grained sandstones to conglomerates. The reservoir pressure can change from the normal hydrostatic gradient to up to 50% of overpressure. There is little evidence of movable water. The key well in this study has a comprehensive set of openhole logs, including pulsed-neutron spectroscopy data, and is supported by a full core study over 597 ft. Additionally, data from several offset wells were used, containing sidewall cores and complete sets of electrical logs. This allowed the development of rock-calibrated mineral models, adjusting the clay volume with X-ray diffraction data, porosity, and permeability with core measurements, and linking the log interpretation to dominant pore-throat radius models from MICP Purcell tests. Several water saturation models were tested, attempting to adjust the irreducible water saturation with NMR and Purcell tests at reservoir conditions. As a result, three hydraulic units were defined and characterized, identifying a strong correlation with lithofacies observed in cores and image logs. A cluster analysis model allowed the propagation of the facies to the rest of the wells (50). Finally, lithofacies were distributed in a full-field 3D model, guided by an elastic seismic inversion. In the main key well, in addition to the openhole logs and core data, a casedhole pulsed-neutron log (PNL) was also acquired, which was used to develop algorithms to generate synthetic pseudo-openhole logs such as bulk density and resistivity, integrated with the spectroscopy mineralogical information and other PNL data, to perform the petrophysical evaluation. This enables the option to evaluate wells in contingency situations where openhole logs are not possible or too risky, and also in planned situations to replace the openhole data in infill wells, saving considerable drilling rig time during this field development phase. Additionally, the calibrated casedhole model can be used in old wells. This paper explores the integration of different core and log measurements and explains the development of rock-calibrated petrophysical and rock type models addressing the characterization challenges found in tight gas sand reservoirs. The results of this study will be crucial to optimize the field development.

Effect of temperature on the pH of water flood effluents and irreducible water saturation: A study with reference to the Barail sandstone outcrop of the upper Assam Basin

Low salinity water flooding (LSWF) is a promising strategy for improving oil recovery in sandstone reservoirs, and recent studies have shown that the recovery with low salinity water injection is a function of not only the salinity and ionic composition but also of the pH of injected brine, temperature, and the combined effect of both on the wetting properties of the clay mineral surfaces. Following brine flooding, the initial wettability of sandstone rock surfaces existed when crude oil, formation water (FW), and rock surface interaction were in chemical equilibrium at reservoir condition changes based on brine pH, salinity, temperature, and clay mineralogy. This study proposes pH, core flood temperature, and irreducible water saturation as key parameters in inducing wettability changes in the sandstone porous media. In the present work, the sandstone cores were subjected to flooding at temperatures of 70 °C, 85 °C, and 105 °C and measured the pH of the discharge effluents and initial or irreducible water saturation with respect to varying temperatures. This paper investigates the rise of the pH gradient and irreducible water saturation, Swir with respect to LS flooding, at increasing temperatures using a Barail sandstone core. The key results include the following: The pH of the flood effluents increases with increasing core flood temperature, which indicates a shifting of the existing wetting state of the rock. The combined effects of increasing pH and initial or irreducible water saturation pertaining to low salinity flooding at progressively increasing temperatures result in increasing water wettability of the sandstone rock. Increasing flooding temperatures cause an increase in Swir, which follows a linear relationship. The findings of the paper highlight the link of increasing pH and irreducible water saturation with the water wetting properties of the sandstone reservoir rock and hence the fluid flow or the oil–water relative permeability behaviour. This paper proposes that increased irreducible water saturation and pH of water flood effluents are connected to increasing water wetness in a sandstone rock as a function of elevated temperatures. As adequate work and consensus on the potential effects of temperature on wettability alteration under low salinity water flooding is still lacking, the current work in relation to the Barail sandstone of the upper Assam basin could be a novel reference for understanding of the importance of temperature dependent wettability alteration behaviour in sandstone cores. The findings of this study can assist in the formation of a novel approach towards considering the increasing irreducible water saturation and pH of the brine effluent as an effect of alternatively injection of low salinity water at elevated temperatures on sandstone porous rock.

Experimental studies on influence of temperature on relative permeability curves in sandstone reservoirs

It is crucial to obtain the representative relative permeability curves for related numerical simulation and oilfield development. The influence of temperature on the relative permeability curve remains unclear. An unsteady method was adopted to investigate the influence of temperature (range from 25–130 °C) on the oil–water relative permeability curve of sandstone reservoirs in different blocks. Then, the experimental data was analyzed by using an improved Johnson–Bossler–Naumann method. Results reveal that with the increase in temperature within a certain temperature range: (1) the relative permeability of the oil and water phases increases; (2) the irreducible water saturation increases linearly, whereas the residual oil saturation decreases nonlinearly, and the oil recovery factor increases; and (3) the saturation of two equal permeability points moves to the right, and hydrophilicity becomes stronger. The findings will aid future numerical simulation studies, thus leading to the improvement of oil displacement efficiency.

Sand Mass Production in Anisotropic Stresses from Lab to Field Predictions

Sand onset and sand rate predictions are important in hydrocarbon production to optimize production, increase recovery, and reduce costs and the environmental footprint. Recent laboratory results on Castlegate sandstone from sand production tests in a True Triaxial test system have revealed that stress anisotropy plays an important role not only on sand onset but also in sand rate. The results confirmed our hypothesis that stress anisotropy means earlier sand produced but less sand. The laboratory results also revealed the effect of fluid saturation, i.e., oil, brine or irreducible water saturation on sand onset and sand rate. They allow the calibration of SandPredictor, a field sand prediction model, for stress anisotropy and production before and after water breakthrough. A field case analysis demonstrated the effects and showed the importance of in situ stress anisotropy and watercut on sand mass and rate.

Influence of Pore Size Distribution on the Electrokinetic Coupling Coefficient in Two-Phase Flow Conditions

Streaming potential is a promising method for a variety of hydrogeophysical applications, including the characterisation of the critical zone, contaminant transport or saline intrusion. A simple bundle of capillary tubes model that accounts for realistic pore and pore throat size distribution of porous rocks is presented in this paper to simulate the electrokinetic coupling coefficient and compared with previously published models. In contrast to previous studies, the non-monotonic pore size distribution function used in our model relies on experimental data for Berea sandstone samples. In our approach, we combined this explicit capillary size distribution with the alternating radius of each capillary tube to mimic pores and pore throats of real rocks. The simulation results obtained with our model predicts water saturation dependence of the relative electrokinetic coupling coefficient more accurately compared with previous studies. Compared with previous studies, our simulation results demonstrate that the relative coupling coefficient remains stable at higher water saturations but vanishes to zero more rapidly as water saturation approaches the irreducible value. This prediction is consistent with the published experimental data. Moreover, our model was more accurate compared with previously published studies in computing the true irreducible water saturation relative to the value reported in an experimental study on a Berea sandstone sample saturated with tap water and liquid CO2. Further modifications, including explicit modelling of the capillary trapping of the non-wetting phase, are required to improve the accuracy of the model.

An Approach for Exploring the Application of the Flow Zone Index Concept in Describing Petrophysical Properties Using Available SCAL Data Relative Permeability

This paper describes a unique approach for exploring the Flow Zone Index (FZI) concept using available relative permeability data. It proposes an innovative routine for relating the FZI parameter to saturation end-points of relative permeability data and produces a better model for relative permeability curves. In addition, this paper shows distinct wettabilities for various core samples and validated functions between FZI and residual oil saturation (Sor), irreducible water saturation (Swi), maximum oil allowed to flow (Kro, max), maximum water allowed to flow (Krw, max),and mobile/recoverable oil (100-Swi-Sor). The wettability of the core samples were defined using cross-plots of relative permeability of oil (Kro), relative permeability of water (Krw), and water saturation (Sw). After classifying the data sets into their respective wettabilities based on these criteria, a stepwise non-linear regression analysis was undertaken to develop realistic correlations between the FZI parameter, initial water saturation and end-point relative permeability parameters. In addition, a correlation using Corey's type generalised model was developed using relative permeability data, with new power law constants and well defined curves. Other parameters, including Sor, Swi, Kro, max, Krw,max and mobile oil, were plotted against FZI and correlations developed for them showed unique well behaved plots with the exception of the Sor plot. A possible theory to explain this unexpected behaviour of the FZI Vs Sor cross plot was noted and discussed. These derived functions and established relationships between the FZI term and other petrophysical parameters such as permeability, porosity, water saturation, relative permeability and residual oil saturation can be applied to other wells or reservoir models where these key parameters are already known or unknown. These distinctive established correlations could be employed in the proper characterization of a reservoir as well as predicting and ground truthing petrophysical properties.

NMR Fluid Substitution–A New Method of Reconstructing T2 Distributions Under Primary Drainage and Imbibition Conditions

Most nuclear magnetic resonance (NMR)-based petrophysics models, such as pore structure characterization and permeability prediction, were developed using T2 distributions measured at fully water-saturated conditions (i.e., Sw = 1). The downhole implementation of those models across the hydrocarbon zones is disputable due to partial saturation (Sw < 1) conditions; hence, a correction to such effects on T2 distributions is required. This paper provides a critical review of the fluid substitution methods currently available in the industry and presents an improved method for enhanced formation evaluation. In the new method presented, an effective irreducible water saturation model is used to account for the pore structure and capillary pressure effects, which were barely considered by the currently available NMR fluid substitution methods. For water-wet reservoir rocks, the typical NMR T2 distribution at the partial saturation condition displays a clear separation between the wetting and nonwetting phases. The water phase can be classified as irreducible and movable fluid volumes. Then, using a T2 mapping relationship and a total porosity constraint, the T2 distribution of movable water at Sw < 1 is shifted and amplified to determine the T2 distribution of movable water at Sw = 1. To validate the new method, NMR measurements were conducted on sandstone samples at Sw = 1 as well as Sw < 1. The reconstructed T2 distribution at Sw = 1 was compared with the measured T2 distribution at Sw = 1. Results showed that the reconstructed T2 distribution matched very well with the T2 distribution measured at Sw = 1, confirming the robustness of the new technique. Parameters used in the reconstruction methodology are observed to be a good indicator of pore connectivity. During desaturation, the water T2 in large pores shifts to a shorter T2 because of the enhanced surface relaxation as the water volume decreases while the surface area remains constant. Therefore, the amplitude at the short T2 increases. The increased amplitude was remapped to large pores in reconstructing T2 spectra of full saturation.

Technique Proves Effective in Remediation of Phase-Trapping Damage in Tight Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 202996, “An Efficient Treatment Technique for Remediation of Phase-Trapping Damage in Tight Carbonate Gas Reservoirs,” by Rasoul Nazari Moghaddam, SPE, Marcel Van Doorn, and Auribel Dos Santos, SPE, Nouryon, prepared for the 2020 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, held virtually 9–12 November. The paper has not been peer reviewed. Aqueous- and hydrocarbon-phase trapping are among the few formation-damage mechanisms capable of significant reduction in effective permeability (sometimes near 100%). In this study, a new chemical treatment is proposed for efficient remediation of water- or hydrocarbon-phase-trapping damage in low-permeability porous media. The method proposed here is cost-effective and experimentally proved to be efficient and long-lasting. Such a chemical treatment is recommended to alleviate gas flow in tight gas with aqueous-trapping-damaged zones or in gas condensate reservoirs with condensate-banking challenges. Introduction Remediation techniques for existing aqueous- or hydrocarbon-phase-trapping damage can be categorized into two approaches: bypassing the damaged region by direct penetration techniques and trapping-phase removal. In the former category, the damaged zone is bypassed by creation of high-conductance flow paths through hydraulic fracturing or acidizing. However, for tight and ultratight formations, conventional acidizing may not be feasible (mostly because of injectivity difficulties). In the second category, direct removal and indirect removal have been used, but usually are seen as short-term solutions. The fluid used in the proposed treatment is comprised of a nonacidic chelating agent. The treatment fluid can be injected safely into the damaged region, while a slow reaction rate allows it to penetrate deep into the formation. In the proposed treatment, the mechanism is the permanent enlargement of pore throats where the nonwetting phase has the most restriction (to overcome the capillary forces) to pass through. In fact, phase trapping or capillary trapping occurs inside the pore structure when viscous forces are not strong enough to overcome the capillary pressure. The experimental setup and method are detailed in the complete paper. Results and Discussion Treatment of Outcrop Samples: Lueder Carbonate. The performance of the proposed treatment fluid initially was investigated on two outcrop core samples from the Lueder carbonate formation. The first treatment was conducted on the Le1 core sample with an absolute permeability of 1.46 md. To establish trapped water in the core, 10 pore volumes (PV) of 5 wt% potassium chloride brine were injected followed by nitrogen (N2) gas displacement. Then, to achieve irreducible water saturation, N2 was injected at a rate of 2 cm3/min for at least 100 PVs until no further water was produced. Next, the effective gas permeability was measured while N2 was injected at approximately 0.2 cm3/min. The effective gas permeability was obtained as 0.042 md. The trapped water saturation was also calculated (from the core weight) as 77.7%. After all pretreatment measurements, the core was loaded into the core holder for the treatment. The treatment injections with preflush and post-flush were performed at 130°C. In this test, 0.5 PV of treatment fluid was injected.