The petro-elastic model (PEM) represents an integral component in the closed-loop calibration of integrated four-dimensional (4D) solutions incorporating time-lapse seismic, elastic and petrophysical rock property modeling, and reservoir simulation. Calibration of the reservoir simulation model is needed so that it is not only consistent with production history but also with the contemporaneous subsurface description as characterized by time-lapse seismic. The PEM requires dry rock properties in its description, which are typically derived from mechanical rock tests. In the absence of those mechanical tests, a small data challenge is posed, whereby all necessary data is not available but the value of reconciling seismic attributes to simulated production remains. A seismic inversion-constrained n-dimensional metaheuristic optimization technique is employed directly on three-dimensional (3D) geocellular arrays to determine elastic and density properties for the PEM embedded in the commercial reservoir simulator.
Ill-posed dry elastic and density property models are considered in a field case where the seismic inversion and petrophysical property model constrained by seismic inversion exist. An n-dimensional design optimization technique is implemented to determine the optimal solution of a multidimensional pseudo-objective function comprised of multidimensional design variables. This study investigates the execution of a modified particle swarm optimization (PSO) method combined with an exterior penalty function (EPF) with varied constraints. The proposed technique involves using n-dimensional design optimization to solve the pseudo-objective function comprised of the PSO and EPF given limited availability of constraints. In this work, an examination of heavily and reduced-order penalized metaheuristic optimization processes, where the design variables and optimal solution are derived from 3D arrays, is conducted so that constraint applicability is quantified. While the process is examined specifically for PEM, it can be applied to other data-limited modeling techniques.
Guetni, Imane (IFP Energies nouvelles – Rueil-Malmaison Université de Lorraine, CNRS, LIEC - Nancy) | Marliere, Claire (IFP Energies nouvelles – Rueil-Malmaison) | Rousseau, David (IFP Energies nouvelles – Rueil-Malmaison) | Bihannic, Isabelle (Université de Lorraine, CNRS, LIEC - Nancy) | Pelletier, Manuel (Université de Lorraine, CNRS, LIEC - Nancy) | Villieras, Frédéric (Université de Lorraine, CNRS, LIEC - Nancy)
Chemical EOR is now considered as an attractive option for sandstone reservoirs with permeability below 100mD, in particular where lack of gas supply does not allow gas injection (
Beyond a few reference textbooks (
In the case of porous media with low permeability for chemical EOR (below 100mD), typically characterized by small pores throats and complex mineralogical composition, thoses issues are all the more important. Low permeability sandstones are usually rich in clay, responsible for high polymer retention (
The objective of this study is to visualize the drained rock volume (DRV) and pressure depletion in hydraulically and naturally fractured reservoirs, using a high-resolution simulator to plot streamlines and time-of-flight contours that outline the DRV, based on computationally efficient complex potentials. A recently developed expression based on fast, grid-less Complex Analysis Methods (CAM) is applied to model the flow through discrete natural fractures with variable hydraulic conductivity. The impact of natural fractures on the local development of DRV contours and streamline patterns is analyzed. A sensitivity analysis of various permeability contrasts between natural fractures and the matrix is included. The results show that the DRV near hydraulic fractures is significantly affected by the presence of nearby natural fractures. The DRV location shifts according to the orientations, permeability and the density of the natural fractures. Reservoirs with numerous natural fractures result in highly distorted DRV shapes as compared to reservoirs without any discernable natural fractures. Additionally, the DRV shift due to natural fractures may contribute to enhanced well-interference by flow channeling via the natural fractures, as well as the creation of undrained rock volumes between the natural fractures. Complementary pressure depletion plots for each case show how the local pressure field changes, in a heterogeneous reservoir, due to the presence of natural fractures. The results from this study offer insights on how natural fractures affect the DRV and pressure contour plots. This study uses a fast grid-less and meshless high-resolution flow simulation tool based on CAM to simulate the flow in heterogeneous naturally fractured porous media. The CAM tool provides a practical/efficient simulation platform, complementary to grid-based reservoir simulators.
The recent and rapid success of using high viscosity friction reducers (HVFRs) in hydraulic fracturing treatments is due to several advantages over other fracture fluids (e.g. linear gel), which include better proppant carrying capability, induce more complex fracture system network with higher fracture length, and overall lower costs due to fewer chemicals and less equipment on location. However, some concerns remain, like how HVFRs rheological properties can have impact on proppant transport into fractures. The objective of this study is to provide a comprehensive understanding of the influence the rheological characterization of HVFRs have on proppant static settling velocity within hydraulic fracturing process. To address these concerns, comprehensive rheological tests including viscosity profile, elasticity profile, and thermal stability were conducted for both HVFR and linear gel. In the steady shear-viscosity measurement, viscosity behavior versus a wide range of shear rates was studied. Moreover, the influence of elasticity was examined by performing oscillatory-shear tests over the range of frequencies. Normal stress was the other elasticity factor examined to evaluate elastic properties. Also, the Weissenberg number was calculated to determine the elastic to viscous forces. Lastly, quantitative and qualitative measurements were carried out to study proppant settling velocity in the fluids made from HVFRs and linear gel. The results of rheological measurement reveal that a lower concentration of HVFR-2 loading at 2gpt has approximately more than 8 times the viscosity of linear gel loading at 20ppt. Elastic measurement exposes that generally HVFRs have a much higher relaxation time compared to linear gel. Interestingly, the normal stress N1 of HVFR-2, 2gpt was over 3 times that of linear gel loading 20ppt. This could conclude that linear gel fracture fluids have weak elastic characterization compared to HVFR. The results also concluded that at 80 C° linear gel has a weak thermal stability while HVFR-2 loses its properties only slightly with increasing temperature. HVFR-2 showed better proppant settling velocity relative to guar-based fluids. The reduction on proppant settling velocity exceed 75% when HVFR-2 loading at 2gpt was used compared to 20ppt of linear gel. Even though much work was performed to understand the proppant settling velocity, not much experimental work has investigated the HVFR behavior on the static proppant settling velocity measurements. This paper will provide a better understanding of the distinct changes of the mechanical characterization on the HVFRs which could be used as guidance for fracture engineers to design and select better high viscous friction reducers.
Failures due to solid particles flowing with the production fluid is one of the main causes of interventions in wells with beam pumping systems. When this problem is accompanied with chemical deposition like scale, leads to a very common intervention during well operation. This paper proposes an analytical methodology that consists of evaluation of the particle size distribution, viability for the use of sand screens and centrifugal separation systems for sand control management in wells with short run time. These systems have proven effective for failure wells that requires a sand control management system when if not addressed increase the lifting costs leading many projects to be infeasible from an economic standpoint. All the technical considerations are explained focusing on the information required and the parameters analyzed to recommend the most accurate design for sand control; selected approaches and models that have been developed to improve the run time due to sand issues are shown in this paper. A case study is showed in a well with average run time of 27 days indicating that identification of particle size distribution was a key factor to provide the right solution for sand control management. These novel applications help operators to reduced OPEX (operating expense), by minimizing well Interventions, decreasing failures in the pump; stabilizing the production and reducing the unforeseen interruption.
Viscoelastic surfactants (VES) are essential components in self-diverting acid systems. Their low thermal stability limits their application at elevated temperatures. The industry introduced new VES chemistries with modified hydrophilic functional groups, which enhances their thermal stability. These new chemistries are still challenged by the lack of compatibility with corrosion inhibitors (CI). This work aims to study the nature and the mechanism of the interaction between the VES and the corrosion inhibitors, which affects both the rheological and corrosion inhibition characteristics of the self-diverting acid system.
This study is based on rheology and corrosion inhibition tests, where combinations of VES and corrosion inhibitors are tested and complemented with chemical and microscopic analysis. Negatively charged thiourea and positively charged quaternary ammonium corrosion inhibitors were selected to study their impact on both cationic and zwitterionic VES systems. Each mixture of the corrosion inhibitor and the VES was blended in a 15 and 20 wt% HCl acid mixture, then assessed for its viscosity at different shear rates, CI concentrations, and temperatures up to 280°F in live and spent acid conditions. Each acid solution was assessed using Fourier-Transform-Infra-Red (FTIR) before and after each rheology and corrosion test to track the changes of the mixture functional groups. Each mixture was examined under a polarizing microscope to assess its colloidal nature. The corrosion inhibition effectiveness of selected acid mixtures was evaluated. N-80 steel coupons were immersed statically in the acid mixture for 6 hours at 150°F and 1,000 psi. The corrosion rate was evaluated by using metal coupon weight loss analysis followed by optical microscope examination for the metal surface.
The interaction between the CI and the VES surface charges and molecular geometries dictates both the rheological and the inhibitive properties of the acid mixtures. The use of a small molecular structure anionic CI with a cationic VES, results in a fine monodispersed CI particles in the VES-acid system. The opposite charges between the CI and the VES results in electrostatic attraction forces. Both the fine dispersion and the electrostatic attraction enhances the rheological performance of the mixture and packs the corrosion-inhibiting layer. The addition of a bulk and similarly charged CI with the VES results in a coarse polydispersed CI particles with repulsive nature with the VES. These properties increase the shear-induced structures and lower the packing of the inhibition layer deposited on the metal coupons, which decrease the rheological performance of the acid mixture and increase its corrosion rate. The FTIR analysis shows that there is no chemical reaction between the CIs and the VESs tested.
This work investigates the interactions between the corrosion inhibitors and the viscoelastic surfactants. It explains the impact of the surface charge of both corrosion inhibitors and VES on their rheological and corrosion inhibition characteristics. It adds a selection criterion for compatible VES and corrosion inhibitors.
Baghban Salehi, Mahsa (Chemistry & Chemical Engineering Research Center of Iran) | Mousavi Moghadam, Asefe (Chemistry & Chemical Engineering Research Center of Iran) | Jarrahian, Khosro (Heriot-Watt University)
Preformed Particle Gel (PPG) is an appropriate solution for conformance control and managing water production in low permeable reservoirs. Rheological behavior evaluation of these deformable particles is a key factor in designing composition to achieve the best conformance control treatment due to the viscoelastic behavior of these particles along with their swelling. The purpose of this paper is to evaluate the network parameters of PPGs through swelling tests, rheology and determining its role in maintaining their structural strength. Several PPG hydrogels were prepared by varying the concentrations of polyacrylamide and Cr(OAc)3 as copolymer and crosslinker, respectively. The characterization of these hydrogels was performed using Scanning Electron Micrographs (SEM), Electron Dispersion X-ray analysis (EDX), Environmental Scanning Electron Microscopy (ESEM), ThermoGravimetric Analysis (TGA), and Differential ThermoGravimetry (DTG). The correlation between reaction conditions and network parameters of polymer networks such as, molecular weight of the polymer chain between two neighboring crosslinks, crosslink density, and size fraction have been determined. The swelling of the hydrogels was found through the Fickian diffusion mechanism. In this case, the diffusion rate of water in the 3D structure of the hydrogel is less than the relaxation of the polymeric chain, resulting in a significant increase in the PPG particles volume. As PPG was invaded such as in the reservoir by formation water or oil, repeatedly, the sensitivity factor was measured to ensure the swelling in the electrolyte solution. Based on rheological tests, the dynamic modulus of the swelled PPG was strongly dependent on the concentration and consequently network parameters. Also, through the optimization of the network parameters, the appropriate composition from the point of view of strength (complex modulus of 4×104 Pa) and salt sensitivity of 0.5 was presented. In addition, the results of the TGA/DTG test demonstrated the thermal stability of the sample was in temperature range 245 to 340°C. The determination and analysis of the network parameter is the novel technique for predicting the hydrogel performance in porous media and investigating its strength under harsh reservoir conditions. In other words, determination of the network parameter can be a shortcut to ensure the success of the gel performance in porous media.
The goal was to search for a replacement of CaCl2 which presents the most widely used accelerator for oil well cement used in cold and arctic environments and sometimes in deepwater drilling. For this purpose, novel calcium silicate hydrate (C-S-H) nanoparticles were synthesized and tested. The C-S-H was synthesized by the precipitation method in an aqueous solution of polycarboxylate (PCE) comb polymer which is widely used as concrete superplasticizer. The resulting C-S-H-PCE suspension was tested in the UCA instrument as seeding material to initiate the crystallization of cement and thus accelerate cement hydration as well as shorten the thickening time at low temperature. It was found that in PCE solution, C-S-H precipitates first as nano-sized droplets (Ø ~20 - 50 nm) exhibiting a PCE shell. Following a rare, non-classical nucleation mechanism, the globules convert slowly to nanofoils (HR TEM images: l ~ 50 nm, d ~ 5 nm) which present excellent seeding materials for the formation of C-S-H from the silicate phases C3S/C2S present in cement. Thickening time tests performed at + 4 °C in an atmospheric consistometer revealed stronger acceleration than from CaCl2 while very low slurry viscosity was maintained, as was evidenced from rheological measurements. Accelerated strength development was checked on UCA cured at + 4 °C and under pressure, especially the wait on cement time was significantly reduced. Furthermore, combinations of C-S-H-PCE and HEC as well as an ATBS-based sulfonated fluid loss polymer were tested. It was found that this C-S-H- based nanocomposite is fully compatible with these additives. The novel accelerator based on a C-S-H-PCE nanocomposite solves the problems generally associated with CaCl2, namely undesired viscosity increase, poor compatibility with other additives and corrosiveness against steel pipes and casing.
Asphaltene deposition and plugging of pipelines during oil production and transportation is considered a challenging flow assurance issue. Instead of adding dispersants, the concept proposes to remove asphaltenes from the flow stream by means of electro–deposition prior to transportation to prevent later deposition. This study mainly examined the effect of molecular composition on the efficiency of electro-deposition. Two sources of asphaltene, namely asphaltenes from coal tar ("AS-C") and asphaltenes from bitumen ("AS-B") with different molecular composition were collected in this study. Elemental analysis revealed that both AS-B and AS-C possessed transition metals (V and Ni) and heteroatoms (O, N and S). The effect of oil components on the stability of two asphaltenes was studied. After conducting the electro–deposition of both asphaltenes with various oil components and electric field strength, the deposition charge and recover rate was recorded and compared. During stability test, the amount of precipitated AS-B decreased with increasing aromaticity of solvent, while that of AS-C was constant. For electro–deposition, the electro–kinetic behavior of AS-C reveals strong sensitivity to the oil components. Interestingly, both asphaltenes exhibited a change in the net charge, which occurred under 6000 V/cm and 12000 V/cm for AS-B and AS-C respectively, as evidenced by a change in the electrode upon which deposition ocurred. Based on the results, the efficiency of electro–deposition is confirmed to depend upon the metal and heteroatoms of asphaltenes; in addition, and by interaction with these elements, the oil composition and electric field affected the stability, net charge, and electro–kinetic behavior of apshaltene. However, our study is the first to show that the current density plays a role in the net charge of the asphaltene molecule and offers an explanation to the controversy over the polarity or the charge sign of asphaltenes, which gives a clue to understanding the microstructure of asphaltenes. In addition, this is the first study to include the effect of oil components and electric field strength on the performance of deposition, which makes further optimization of the proposed process possible.
Paul, Ferm (Nouryon) | Jeff, Germer (Nouryon) | Kurt, Heidemann (Nouryon) | Stuart, Holt (Nouryon) | Andrew, Robertson (Nouryon) | Jannifer, Sanders (Nouryon) | Klin, Rodrigues (Nouryon) | John, Thomaides (Nouryon) | Nick, Wolf (Nouryon) | Lei, Zhang (Nouryon)
The controlled release of scale inhibitors (SI) and other treatment chemicals in the near-wellbore region is a key strategy to improving water management and extended well production. In addition, during some completion and stimulation operations, it is desired that robust particles providing controlled release be placed in gravel and sand packs. A novel controlled release scale inhibitor particle is presented which provides beneficial properties due to its unique chemistry and polymer processing methods. This technology provides extended feedback of scale inhibitor with tunable release rates.