Equilibrium Pc-RI measurements on low permeability core plugs present the SCAL laboratory with some difficult challenges regarding the duration of measurements and the attainment of truly equilibrated resistance readings. A new empirical method is described that allows estimation of fully equilibrated resistance by application of a simple transient data linearizing transform and plot slope analysis. A small set of plugs from a conventional tight gas field in the Sultanate of Oman is used to demonstrate the method. The method may also be used by the lab to monitor and shorten the Pc-RI measurement duration without compromising the interpretation of saturation exponents or capillary curves. Transform plot transients and macro capillary number are examined to estimate a boundary where the plugs transition from shock front rapid desaturation to slow percolation desaturation behavior.
Hadidi, Shahab (Petroleum Development Oman) | Boya Ferrero, Maria (Shell Global Solutions International) | Van Den Nouland, Casper (Petroleum Development Oman) | Nicholls, Christopher (Petroleum Development Oman)
The benchmark primary drainage Saturation Height Function (SHF) is a standardized dimensionless function that describes the expected saturation-depth profile for a specific rock type resulting from primary drainage. The paper's ambitious goal is to introduce the concept of creating an inventory of benchmark functions for every reservoir rock type. The benchmark function is the reference point to validate the fluid fill history and identify areas of primary drainage for a specific field. Furthermore, it can be used as a diagnostic tool to analyse changes in the reservoir rock type and pinpoint fluid fill variations. The benchmark function is a complementary model to constrain the SHF when there are insufficient data, especially in the transition zone. A key diagnostic criterion for a reservoir rock type is that it contains a consistent combination of pore types and hence has consistent (or predictable) capillary properties. Case studies on carbonate fields are presented from the Sultanate of Oman. The same concept is also applicable to clastic reservoirs.
The benchmark primary drainage function can be derived from the capillary pressure data. Conversion of this data into a normalized capillary pressure system is required. In this paper, we will introduce a workflow to utilize the saturation log data from different fields to build a benchmark function that is not influenced by reservoir fluids densities' and interfacial tension.
Benchmark primary drainage functions were created in different scenarios and rock types to aid saturation modelling in several fields. In one carbonate field, the saturation log data from an analogue field were used to constrain the transition zone due to data limitations. The benchmark function was also used to identify fluid fill variations and unlock a potential development.
The benchmark function of micro-porous rock, derived from several analogue fields, was the baseline for the saturation modelling workflow of a complex carbonate reservoir with a tilted contact and significant imbibition and it was a vital enabler in simplifying the saturation model.
Relative-permeabilities are a first-order parameter to consider when describing multiphase-flows in porous media. Among many other parameters, the core wettability controls the fluids repartition in the porous media at pore-scale, strongly affecting how the fluids can be displaced (i.e. their relative-permeabilities). As the initial core wettability of reservoir sampled cores is rarely preserved, classical SCAL measurements (such as relative permeabilities) may not reflect the rock properties at reservoir conditions. This originate core wettability may be restored in a process referred as ‘core aging’. It is generally done by injecting the reservoir fluids (brine and crude-oil) in the core to equilibrate the rock surface with respect to the oil and brine components. Here, we investigated the effect of two aging protocols (static and dynamic) on wettability restoration, and characterize the aging using oil/water relative permeabilities measured on the core after aging. The two aging protocols were applied on a set of initially strongly water-wet outcrop sandstone samples (Bentheimer). The relative permeabilities were measured using the steady-state method and a state of the art experimental setup (CAL-X) based on X-ray radiographies. The setup is equipped with an X-Ray radiography facility, enabling monitoring of 2D local saturations in real-time and thus giving access to fluid flow paths during the flooding. Aged samples relative permeability curves show clear differences when compared to water-wet relative permeabilities, hence suggesting that the wettability has been effectively altered. However, the two aging protocols were unable to produce the same results. The dynamic aging has led to an inversion of the original relative permeability curves asymmetry, suggesting a strongly oil-wet system, whereas the static aging protocol has altered the wettability to a lesser extent. The differences can be explained by analyzing a 2D saturation maps. In the case of dynamic aging we observed a homogeneous distribution of fluid saturation during fractional flow. On the opposite, the static protocol results in heterogeneous flow paths, confirming that this protocol did not alter uniformly the wettability of the sample and generates a patchier mixed-wettability system.
Part of the hydrocarbons generated in the mature kitchens migrate into the conventional traps while the other portions remain in the kitchens as unconventional resources. However, significant part of the generated hydrocarbons could be available in the migration pathways. Hydrocarbons in the migration pathways are either retained in the rocks in migration routes or accumulated in subtle traps due to the presence of heterogeneities along the migration pathways. The migration pathways traps are envisaged to be developed in response to the presence of an equilibrium state between the buoyancy forces that are trying to move the hydrocarbon through the rocks and the capillary pressures in the low permeable layers that are resisting these movements (figure 1). The only requirement to develop such traps is for the capillary pressure to be greater than the migration buoyancy force.
Formation pressure and sampling measurements in low mobility formations under dynamic filtration can lead to measurements influenced by continuous mud circulation. Generally, active mud circulation inhibits mud cake growth, promoting filtration and invasion of mud filtrate into the reservoir. The resulting invasion adds its own pressure to the actual formation pressure. This is more pronounced in low mobility formations where pressure or sampling measurements made with mud circulation show higher than expected reservoir pressures and/or extended clean up times as a result of dynamic filtration and invasion.
We focus on formation pressure acquisition and present data sets where pressure acquisition was done with active mud circulation. The data is then compared with measurements acquired in a pseudo-static and static mud column.
The measured near wellbore formation pressures acquired with active mud filtration are significantly higher (in some cases, > 400psi) compared to those obtained with a static mud column (assumed to be reading closer to the true formation pressure). The additional pressure is often referred to as supercharging, i.e., the excess pressure superimposed on the original formation pressure by the viscous flow of mud filtrate. The difference depends amongst other factors primarily on the formation mobility and surface pump flow rate during the pressure acquisition. For higher mobilities, there is generally little appreciable difference between active mud circulation and zero mud circulation. Secondary factors like pipe movement, pipe diameter, mud composition and reservoir wettability also influence the degree of the extra pressure measured.
Best practices for formation testing while drilling in low mobility carbonates are discussed. Lessons are drawn from experience where ignoring such best practices result in questionable data.
Al-Hammadi, Mariam Khalil (ADNOC OFFSHORE) | Sinha, Amit Kumar (ADNOC OFFSHORE) | Zakaria, Hasan Mohammed (ADNOC OFFSHORE) | Agrawal, Pawan (ADNOC OFFSHORE) | Al-Badi, Bader Saif (ADNOC OFFSHORE) | Al-Hassani, Sultan Dahi (ADNOC OFFSHORE) | Ahmed, Shafiq (ADNOC OFFSHORE) | Mohammed Khan, Owais (ADNOC OFFSHORE)
Field presented here is giant heterogeneous carbonate field consist of multi-stacked reservoirs, located in offshore Abu Dhabi. This paper presents development plan for one of reservoir. It consists of a very large rich gas cap with oil rim. Current development plan is oil production from oil rim with peripheral water injection with no gas injection and production. Significant amount of data (Core, Seismic, Logs, DST, production test & PTA) during the early production period have been collected. All the data have been integrated to prepare robust Co-development of oil-rim and gas cap to maximize oil and condensate value from the reservoir.
Reservoir consists of three main porous units: Upper, Middle and Lower Units inter-bedded with dense intervals. Generally the best porosity development is seen in the norther part of the field. Sedimentology study was mainly focused in the upper section of the reservoir. Five facies associations were made based on a low inclination ramp depositional model and diagenetic impact honoring the paragenetic sequence. Facies controlled diagenesis was noticed where abundance of echinoderms controlled the different degree of cementation degrading the reservoir quality. Identifying these dominant echinoderm facies zones allows us better well placement by avoiding them. The output of this study was four facies maps with five facies association distribution representing the four cycles seen in the upper part of the reservoir which is the best reservoir section. These facies maps were incorporated for property distribution in the static model.
The reservoir model is constructed using latest acquired seismic and more than 100s of well control for the top of the Reservoir, used as reference structure. Proportional layering was used for different reservoir layers which have been mapped using Isochore. The facies association was distributed using trend map and Vertical proportion curve observed on the Well. Reservoir properties like Porosity and Permeability were distributed using constrained of facies distribution. A newly drilled well also used as for blind test showing the predictability of the model. Dynamic data such PTA and time-lapse MDT has been integrated in the updated model to guide areal and vertical connectivity. Good history matching has been obtained with minimal changes in the static model.
With the updated model different sensitivities of gas cap and oil rim development has carried out in terms of co-development timing, lean gas recycling volume, and inner ring water injection in order to maximize oil and condensate value from the reservoir and avoid oil migration in the gas cap.
Fluid PVT is crucial to production of a petroleum reservoir. A complete PVT study requires high quality experimental measurement combined with subsequent efforts in PVT modelling. In contrast with the relatively matured PVT study for conventional reservoirs, PVT study for shale has a number of challenges. It is difficult to get representative fluid samples; and there are various speculations on how porous media can influence fluid PVT. For modeling shale PVT, it is necessary to consider the wall effects of the rock, mainly in terms of capillary pressure and adsorption. This requires robust algorithms as well as adequate procedures to integrate available experimental information into PVT modeling. Previously, we developed equilibrium calculation algorithms with capillary pressure and adsorption and modelled adsorption equilibrium in shale. Here we further integrate them into a PVT tool for PVT simulation, analysis of shale production, and gas injection in shale. The core module in the PVT calculation is flash with capillary pressure and adsorption. A robust flash module forms the basis of PVT simulation. The capillary pressure is described through the Young-Laplace equation. For adsorption, it requires a proper workflow to bridge the limited experimental measurement and the final modeling covering a wider range of hydrocarbons. It is recommended to model the available adsorption data for light gases using a theoretical adsorption model, and then extrapolate the model parameters to heavier hydrocarbons. The generated data from the theoretical model is then fitted to the simplified and more computationally convenient Langmuir model. The flash module can also be integrated into a slimtube simulator to study the porous media effects on gas injection applications. Capillary pressure alone lowers the bubble point pressure and the extent is system dependent. Nevertheless, even for systems with a moderate decrease, the change in the PVT properties in the two-phase region cannot be overlooked. Selective adsorption alters the bulk fluid composition and lowers the heavy components concentration in general. Adsorption is generally more pronounced in the gas region whereas capillary pressure is usually more obvious in the liquid region. Regarding the influence of capillary pressure on gas injection, it can be shown that the recoveries at pressures below the minimum miscibility pressure (MMP) are changed; however, the MMP does not seem to be affected due to the vanishing of capillarity effects. For the gas injection including adsorption, the results show that the recovery decreases if adsorption is considered. This is mainly due to adsorption of heavy components, and desorption of lighter components during the process. The heavy components stay in the adsorbed phase, and will not likely be recovered even at high injection pressures. The present study integrates our previous results on algorithms and modeling into a PVT tool for analyzing shale production. It can be used to infer what the initial fluid composition is in the shale reservoir, and to analyze how capillary pressure and adsorption influence shale production during a depletion procedure. Furthermore, the tool also allows a more advanced analysis for gas injection in shale.
Shah, Swej Y. (Delft University of Technology) | As Syukri, Herru (Delft University of Technology) | Wolf, Karl-Heinz (Delft University of Technology) | Pilus, Rashidah M. (Universiti Teknologi Petronas) | Rossen, William R. (Delft University of Technology)
Foam reduces gas mobility and can help improve sweep efficiency in an enhanced-oil-recovery (EOR) process. For the latter, long-distance foam propagation is crucial. In porous media, strong foam generation requires that the local pressure gradient exceed a critical value (∇Pmin). Normally, this happens only in the near-well region. Away from wells, these requirements might not be met, and foam propagation is uncertain. It has been shown theoretically that foam can be generated, independent of pressure gradient, during flow across an abrupt increase in permeability (Rossen 1999). The objective of this study is to validate theoretical explanations through experimental evidence and to quantify the effect of fractional flow on this process.
This article is an extension of a recent study (Shah et al. 2018) investigating the effect of permeability contrast on this process. In this study, the effects of fractional flow and total superficial velocity are described. Coreflood experiments were performed in a cylindrical sintered-glass porous medium with two homogeneous layers and a sharp permeability jump in between, representing a lamination or cross lamination. Unlike previous studies of this foam-generation mechanism, in this study, gas and surfactant solution were coinjected at field-like velocities into a medium that was first flooded to steady state with gas/brine coinjection. The pressure gradient is measured across several sections of the core. X-ray computed tomography (CT) is used to generate dynamic phase-saturation maps as foam generates and propagates through the core. We investigate the effects of velocity and injected-gas fractional flow on foam generation and mobilization by systematically changing these variables through multiple experiments. The core is thoroughly cleaned after each experiment to remove any trapped gas and to ensure no hysteresis.
Local pressure measurements and CT-based saturation maps confirm that foam is generated at the permeability transition, and it then propagates downstream to the outlet of the core. A significant reduction in gas mobility is observed, even at low superficial velocities. Foam was generated in all cases, at all the injected conditions tested; however, at the lowest velocity tested, strong foam did not propagate all the way to the outlet of the core. Although foam generation was triggered across the permeability boundary at this velocity, it appeared that, for our system, the limit of foam propagation, in terms of a minimum-driving-force requirement, was reached at this low rate. CT images were used to quantify the accumulation of liquid near the permeability jump, causing local capillary pressure to fall below the critical capillary pressure required for snap-off. This leads to foam generation by snap-off. At the tested fractional flows, no clear trend was observed between foam strength and fg. For a given permeability contrast, foam generation was observed at higher gas fractions than predicted by previous work (Rossen 1999). Significant fluctuations in pressure gradient accompanied the process of foam generation, indicating a degree of intermittency in the generation rate—probably reflecting cycles of foam generation, dryout, imbibition, and then generation. The intermittency of foam generation was found to increase with decreasing injection velocities and increasing fractional flow. Within the range of conditions tested, the onset of foam generation (identified by the rise in ∇P and Sg) occurs after roughly the same amount of surfactant injection, independent of fractional flow or injection rate.
Modelling fracture systems where fracture mechanics and fluid flow are consistent, constitutes an essential part for predicting the performance of shale oil and gas operations. One of the challenges in these complex systems is the reconciliation of volumes of injected water during fracturing, hydraulic fracture volume and the water flowback after the well is open to production. Achieving consistency becomes even more challenging given the interdependence of multiple sources of uncertainty.
We propose a workflow that uses multiple sources of observed operational data, such as volume of water injected and produced, static pressure, soaking time and saturation logs, to calibrate a static model representing the fracture volume and rates of water imbibed into the matrix. The soaking period is modeled using Embedded Discrete Fracture Model (EDFM) that honors the fracture geometry generated by a commercial software based on unconventional fracture model (UFM). The allocation of water imbibed into the matrix during the soaking period uses imbibition capillary pressure from 3D numerical models.
After applying the proposed methodology to calibrate stimulated shale oil reservoir in a multi well pad, we can assess the relative impact of fracture complexity compared to capillary dominated flow. Additionally, we can perform sensitivities on impact of the water retained in the fracture volume and matrix, respectively. Finally, the methodology showed that we can use the imbibition capillarity to explain and reconcile water losses during the soaking period. This information is of key importance while deciding the value of the flowback rates as input during calibration of hydraulic fracture area and quality of the stimulation procedure. Extended applications of this workflow include performance assessment of gas entrapment and evaluation of EOR operations in unconventional systems.
We propose a methodology based on the hypothesis of capillary imbibition mechanism to explain and capture the volume of injected water that does not return during hydrocarbon production. This workflow, well suited for realistic complex Hydraulic Fracture Networks (HFNs) consisting of millions of fractures planes, enables calibration of fracturing fluids and water flowback while assessing the effect of the spontaneous imbibition.
Kaiyi, Zhang (Virginia Polytechnic Institute and State University) | Fengshuang, Du (Virginia Polytechnic Institute and State University) | Bahareh, Nojabaei (Virginia Polytechnic Institute and State University)
In this paper, we investigate the effect of pore size heterogeneity on multicomponent multiphase hydrocarbon fluid composition distribution and its subsequent influence on mass transfer through shale nano-pores. We use a compositional simulation model with modified flash calculation, which considers the effect of large gas-oil capillary pressure on phase behavior. We consider different average pore sizes for different segments of the computational domain and investigate the effect of the resulting heterogeneity on phase and composition distributions, and production. A two dimensional formulation is considered here for the application of matrix-fracture cross mass transfer. Note that the rock matrix can also consist of different regions with different average pore sizes. Both convection and molecular diffusion terms are included in the mass balance equations, while different reservoir fluids such as Bakken and Marcellus are considered. The simulation results show that since oil and gas phase compositions depend on the pore size, there is a concentration gradient between the two adjacent pores with different sizes. Considering that shale permeability is small, we expect the mass transfer between two sections of the reservoir/core with two distinct average pore sizes to be diffusion-dominated. This observation implies that there can be a selective matrix-fracture component mass transfer during both primary production and gas injection EOR as a result of confinement-dependent phase behavior. Therefore, molecular diffusion term should be always included in the mass transfer equations, for both primary and gas injection EOR simulation of heterogeneous shale reservoirs.