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Formation damage caused by drilling-fluid invasion, production, or injection can lead to positive skin factors and affect fluid flow by reducing permeability. When mud filtrate invades the formation surrounding a borehole, it will generally remain in the formation even after the well is cased and perforated. This mud filtrate in the formation reduces the effective permeability to hydrocarbons near the wellbore. It may also cause clays in the formation to swell, reducing the absolute permeability of the formation. In addition, solid particles from the mud may enter the formation and reduce permeability at the formation face.
A challenge in many permeable, water-sensitive, subhydrostatic reservoirs is avoiding the loss of completion fluid when completing or working over wells. To overcome the limitation of conventional fluid-loss-control pills, a low-viscosity system was developed. The system is composed of a viscous disproportionate permeability modifier (VDPM) with sized synthetic polymer particles and fibers, which degrade into organic acids. The VDPM reduces the effective permeability to water-based fluids, and the sized particles create an impermeable filter cake. When the particles degrade, the organic acid acts to break any remaining polymer. The limitations of many conventional fluid-loss-control pills have resulted in the development of a number of solids-free fluid-loss-control pills.
Most multiple-transverse-fracture horizontal wells in shale-gas formations remain in transient bilinear or linear flow for very long periods. However, there are often reported cases of shale wells that exhibit boundary-dominated flow in a very short period, which implies a stimulated rock volume (SRV) much smaller than would be expected. This paper offers an alternative explanation for the early boundary-dominated flow related to dissolution of salt-sealed natural fractures in the shale. Operators producing gas from the Haynesville, Marcellus, and Horn River shale formations have observed that produced water is more saline than the injected fracturing fluid. Additionally, the fraction of injected water that flows back when the well is put on production--termed load recovery--is low.
Abstract The objective of this work is to analyze the pressure transient behavior in long or extended testing times to detect reservoir limits and to guarantee an optimal reservoir dynamic characterization that allows to understand, the real behavior of the producing formation since the beginning of its productive life, as well as ensuring timely decision-making. For this analysis, we considered some Extended Limit Tests (ELT) in exploratory or wildcat wells and currently producing wells in developed fields, from which we found the main well productivity associated parameters, an approximation of the optimum number of wells, drainage radii, estimated reserves to recover and the detection of reservoir limits and heterogeneities. The responses obtained were compared then, the associated problems and the causes that originated them from the design, execution and finally, during the interpretation of the Pressure Transient Analysis (PTA) were identified. Additionally, the present paper also attempts to propose a practical approximation for well drainage and investigation radii considering the nature of fractures in carbonates. The importance of this work lies in improving the initial characterization of reservoirs through the analysis of Extended Limit Tests (ELT) for reaching a greater radius of investigation; correspondingly, it is intended to implement an appropriate exploitation scheme (fit for purpose) for each field according to their characteristics and behavior shown for a good reservoir management and Optimal Number of Wells (ONW) to increase the recovery factor, risk mitigation and future investments assurance.
We present a workflow to estimate recovery in unconventional reservoirs that uses flow simulation models constrained by seismic data, geomechanical parameters, and hydraulic stages properties. The goal of the workflow is the rapid testing of different hydraulic stage scenarios in the presence of natural fractures and other hypotheses that can be compared to select the one that yields optimal recovery. All the parameters of interest are generated directly into a flow simulation grid centered on the horizontal well. Thickness of hydraulic stages equals that of one cell of the simulation grid and therefore, details of individual hydraulic fractures are not explicitly considered allowing modeling of larger reservoir scale effects on recovery. The first step is the estimation of natural fracture orientations using seismic data calibrated with independent fracture information. Then, the flow grid is also populated with geomechanical parameters such as stress field and stress orientations, pore pressure, and friction coefficient. After defining locations and geometry of hydraulic stages along the well path and assuming fluid pressure decay functions away from the hydraulic stages, we use Mohr-Coulomb faulting theory to estimate which natural fractures are more prone to reactivation after hydraulic stimulation. This volume of reactivated natural factures is then upscaled to effective fracture permeability that serves as input to an ultra-fast dual-permeability flow simulator. Finally, once the model is in the flow simulator, we use fluid properties and other dynamic parameters for calibrating with production information, changing the simulation model if needed, and performing long term forecast. We illustrate the application of the workflow in the Eagle Ford formation (South Texas) using a data set that consists of 3D seismic, outcrop descriptions, geomechanics measurements, and production information.
Unconventional reservoirs are characterized by extremely low permeabilities that hinder fluid communication between the reservoir and the borehole. These permeabilities are enhanced by the generation of hydraulic fractures after high-pressure fluid is injected into the formations of interest. Even though hydraulic fractures are the main source of permeability enhancement near the wellbore, reactivation of existing natural fractures in the vicinity of the hydraulic fractures is also an important mechanism of self-propped permeability enhancement in the stimulated reservoir volume (SRV) (Gutierrez et al., 2000; Zhang and Li, 2016; Rutledge and Phillips, 2003) and the hydraulic fractures regions (Jeffrey, 2010; Maxwell, 2011).
Reactivation of existing natural fractures depends on the current state of stress, orientation and intensity of existing natural fractures relative to the stress field, injected fluid pressures, rock properties, and geometry of hydraulic stages. In this paper, we consider all these parameters in an integrated fashion that uses Mohr-Coulomb faulting theory to estimate the likelihood of slip of existing natural fractures. Then, we use simple aperture versus fluid pressure assumptions to generate effective permeability volumes of reactivated fractures.
Understanding gas condensate reservoirs require comprehensive data acquisition efforts to collect representative PVT samples, measure the effective reservoir permeability and characterize reservoir behavior through well test. Right well test design is key in tight gas reservoirs to reveal all flow regimes and characterize reservoir to have valid FDP formulation including well trajectory design, well completion design and well locations and proper facility sizing.
Well test design was done and updated in appraisal to reflect condensate banking in tight reservoir with moderate condensate gas ratio (CGR). The main objective was to measure the well deliverability and reservoir characterization to get condensate banking fingerprint (signature) on pressure derivative in Modified Isochronal Test (MIT) section. This design allows to measure the permeability and radius of impaired region due to condensate banking, while extending test enough allows to measure gas zone permeability as well.
A single well radial model (SWRM) was constructed to reflect the condensate banking in simulation model as well. The log data been up-scaled to well test data in free gas zone to analyze the flow behavior of condensate banking in near-wellbore.
The condensate bank radius was estimated for different test rates in MIT test. The estimated permeability of condensate bank at different flow rates (and draw-down) are different as per expectation. This is due different saturation at different draw-down based on liquid drop-out. The permeability of single-phase gas zone (far from near-wellbore) is constant in all flow periods of MIT consistently. The results from well test is in perfect agreement with up-scaled single well model. The wellbore hydro-dynamic is modeled using transient well models (OLGA application) and showing liquid loading in long term which suggest to couple the model with transient model to consider the impact of liquid hold-up in the wellbore for proper completion design, well trajectory design and production profile forecast.
The liquid drop-out from PVT analysis was used to estimate the saturation near wellbore at each pressure and then from different draw-down periods the effective permeability of each test period correlated to this saturation. This resulted to estimate relative permeability from well test and PVT data (CVD test) which is more reliable due to extra-large scale compare to core analysis tests.
Tabatabaei, Maryam (Pennsylvania State University) | Dahi Taleghani, Arash (Pennsylvania State University) | Cai, Yuzhe (Pennsylvania State University) | Santos, Livio (Pennsylvania State University) | Alem, Nasim (Pennsylvania State University)
Proppant bed can play a critical role in enhancing oil and gas production in stimulated wells. In the last 2 decades, there have been consistent efforts to improve shape characteristics and mechanical strength properties to guarantee high permeability in the resultant propped fracture. However, engineering the surface properties of proppants, such as tuning their wettability, has not received considerable attention. Considering that water-wet proppants can not only limit production because of reduced hydrocarbon relative permeability but also facilitate fines migration through the proppant bed, a methodology is presented here to alter the wettability of proppants using graphite nanoplatelets (GNPs). The idea benefits from the intrinsic hydrophobicity of graphitic surfaces, their relatively low cost, and their planar geometry for coating proppants. Conductivity tests are conducted according to ISO 13503-5:2006 (2006) and API RP 19D (2008) to examine how the coating process changes the relative permeability to water and oil. According to the simulation results, the newly developed graphite-coated proppants speed up the water cleanup and increase long-term oil production in an oil-wet reservoir.
Bashtani, Farzad (Joint Venture, Ashaw Energy and Baker Hughes, University of Calgary, Department of Chemical and Petroleum Engineering) | Kantzas, Apostolos (University of Calgary, Department of Chemical and Petroleum Engineering, PERM Inc.)
Abstract Multiphase relative permeability is a key parameter in reservoir simulation. Typically, end-point based correlations are employed in order to obtain such curves for reservoir simulation purposes. However, those correlations are not capable of capturing micro-scale physical phenomenon which can significantly affect flow pattern at larger scales. Consequently, it is necessary to obtain a scale-up methodology in order to transfer the micro-scale physics to reservoir-scale. The objective of this research is developing a scale up procedure which can be applied to multi-phase flow properties obtained by micro-scale flow simulation to compute the equivalent macro-scale and core-scale flow properties having the micro-scale flow properties. Two different sets of media are employed: media representing unconsolidated oil sands and media based on experimental data obtained from the Mesaverde formation located in the Poweder River Basin. The former is used for validating the scale up methodology since not all the required information is available in the experimental data set. Pore scale network modelling is used for calculating micro-scale multi-phase flow properties such as porosity, and absolute and relative permeability. Then the generated subsegments are populated in space to reconstruct the macro scale medium. Flow properties of such medium are then obtained by network modelling and the proposed scale-up methodology and the results are compared. Furthermore, macro-scale media are distributed in space in layers and stacks of increasing and decreasing permeability to form a core-level medium. Single and multi-phase flow properties are then calculated by applying a pressure drop across the core. Permeability and relative permeability curves are calculated using the combination of mass balance, equation of state, and Darcy equation assuming steady-state flow while capillary pressure curve is obtained using the modified Leverett-J function procedure used in micro-to-macro scale up section. Results show good agreement between the expected and calculated properties for both unconsolidated and consolidated media. Finally, physical behavior observed at micro and macro scale is transferred to the core scale.
The objective of the study was to estimate which was the effective mobility of a polymer solution injected in an extra heavy oil reservoir, also try to stablish if there was a reduction on effective permeability as injection progressed, and finally estimate the mobility ratio between the reservoir fluid and the injected fluid.
Laboratory analyses were used to evaluate the behavior at surface conditions of the polymer solution before injection, and also the quality of the polymer solution prior injection. Tests were performed to estimate the effect of water reservoir salinity over the polymer solution viscosity, and the effect of Iron and Oxygen ion content present in the solvent used for preparation. After project start up, five fall off tests (pressure transient tests) at different stages of the injection process were performed in order to evaluate the mobility evolution over an extended period of time. The tests were executed every three months after the beginning of the injection of the polymer solution. Other diagnostics techniques were also studied, in order to gain insight of what other variables could affect the injection process, among them: Hall plot diagnostics, and fiber optic data.
The evolution mobility of the polymer solution at reservoir conditions was determined, and as injection progressed, the solution mobility decreased over time for the same concentration, according to results obtained from interpretation of well tests analysis, the mobility decreased from 342 mD/cP to 145 mD/cP. Given that the mobility of the oil was very low (between 0,8 mD/cP and 1 mD/cP), the mobility ratio evolution over time showed that a reduction in polymer effective permeability occurred as injection progressed, favoring the flooding process, also depending of the effective permeability, the mobility compared to water, was almost seven times lower. Laboratory analyses showed and important dependency between shear rate and polymer viscosity in the case of polymer solution prior injection, and also a possible risk of solution viscosity reduction due the high salinity of the reservoir water.
The injection data, fall off analysis, and Hall plot analysis, combined with the results of the laboratory analyses are of great importance for the topic of enhanced oil recovery process in the case of extra heavy oil reservoirs. The results obtained show also that it is necessary to evaluate the actual performance, besides of the core test and simulation results. Finally the knowledge accomplished in this work was used to obtain important information necessary to asset feasibility, in the case of a larger scale implementation of the process.