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Roostaei, Morteza (RGL Reservoir Management Inc.) | Hosseini, Seyed Abolhassan (University of Alberta and RGL Reservoir Management Inc.) | Soroush, Mohammad (University of Alberta and RGL Reservoir Management Inc.) | Velayati, Arian (University of Alberta) | Alkouh, Ahmad (College of Technical Studies) | Mahmoudi, Mahdi (RGL Reservoir Management Inc.) | Ghalambor, Ali (Oil Center Research International) | Fattahpour, Vahidoddin (RGL Reservoir Management Inc.)
Summary Sieve analysis, sedimentation, and laser diffraction (LD) have been the methods of choice in determining particle-size distribution (PSD) for sand control design. However, these methods do not provide any information regarding the particle shape. In this study, we introduce the application of dynamic image analysis (DIA) to characterize particle sizes and shape descriptors of sandbearing formations. Different methods were compared in the estimation of PSD and fines content, which are the primary factors important in sand-control design. Through minimizing the sampling and measurement errors, the deviation between different PSD measurement techniques was attributed solely to the shape of the particles and the amount of fine fraction. For fines-content measurement, the values obtained through Feret min parameter values (the minimum size of a particle along all directions) calculated by DIA and sieving measurement are comparable within a 5% confidence band. The deviation between the results of different methods becomes more significant by increasing fines content. The fines and clay content show higher values when measured by any wet analysis. LD also tends to overestimate the fines fraction and underestimate silt/sand fraction compared with other dry techniques. By comparing the deviation of the DIA and sieving at standard mesh sizes, an algorithm has been developed that chooses the equivalent sphere sizes of DIA with minimum deviation from sieving. This study performs several measurements on formation sands to illustrate the real advantage of the new methods over traditional measurement techniques. Furthermore, particle-shape descriptors were used to explain the deviation between the results of different PSD measurement methods. Introduction One of the main factors in classifying the components of soil is the investigation of the size distribution of the particles. PSD is generally being used for soil classification and some hydraulic properties including soil's permeability, porosity, consolidation, and shearand volume-change behavior (Campbell and Shiozawa 1992). Furthermore, depositional history of transported soil and development of in-situ soils are also being evaluated by PSD. Thus, PSD provides valuable information in engineering and other fields such as environmental geoscience, sedimentology, and pedology. Studies confirmed that there are major problems associated with sedimentation methods including their time-consuming procedure, need for a fairly large number of samples (20 g), and dependency of the results on laboratory equipment, specific technique, or operation (Percival and Lindsay 1996).
Seright, Randall S. (New Mexico Institute of Mining and Technology) | Wavrik, Kathryn E. (New Mexico Institute of Mining and Technology) | Zhang, Guoyin (New Mexico Institute of Mining and Technology) | AlSofi, Abdulkareem M. (Saudi Aramco)
The goal of this work was to identify viable polymers for use in the polymer flooding of high-temperature carbonate reservoirs with hard, saline brines. This study extensively examined recent enhanced-oil-recovery (EOR) polymers for stability, including new 2-acrylamido-tertbutylsulfonic acid (ATBS) polymers with a high degree of polymerization, scleroglucan, n-vinylpyrrolidone (NVP) -based polymers, and hydrophobic associative polymers. For each polymer, stability experiments were performed over a 2-year period under oxygen-free conditions (less than 1 ppb) at various temperatures up to 180°C in brines with total dissolved solids (TDS) ranging from 0.69 to 24.4%, including divalent cations from 0.034 to 2.16%. Use of the Arrhenius analysis was a novel feature of this work. This rarely used method allows a relatively rapid assessment of the long-term stability of EOR polymers. Rather than wait years or decades for results from conventional stability studies at the reservoir temperature, reliable estimates of the time-temperature stability relations were obtained within 2 years. Arrhenius analysis was used to project polymer-viscosity half-lives at the target reservoir temperature of 99°C. The analysis suggests that a set of ATBS polymers will exhibit a viscosity half-life over 5 years at 120°C and over 50 years at 99°C, representing a novel finding of this work and a major advance for extending polymer flooding to higher temperatures.
For five polymers that showed potential for application at higher temperatures, corefloods were performed under anaerobic conditions. Another novel feature of this work was that anaerobic floods were performed without using chemical oxygen scavengers, chemical stabilizing packages, or chelating agents (that are feared to alter rock properties). Using carbonate cores and representative conditions, corefloods were performed to evaluate polymer retention, rheology in porous media, susceptibility to mechanical degradation, and the residual resistance factor for each of the polymers at 99°C.
Summary Rock typing into flow units (FUs) plays a pivotal role in constructing static and dynamic models of petroleum reservoirs. Decisions made by asset teams mostly depend on predictions of how fluids will percolate through the subsurface during the reservoir life cycle. In carbonate settings, dealing with rock typing is complex and can generate a large quantity of units because of diagenetic processes such as dissolution, cementation, and silicification. Seismic data can be used to detect large-scale FUs and assist the interpolation of small-scale FUs in 3D reservoir volume, thus producing more-realistic static and dynamic models. We propose a modification of the classical rock-typing methods that use permeability (k) vs. porosity (/) plots and electrical properties, with a data set from the Mero Field, part of the giant Libra Field of presalt carbonate reservoirs in offshore Brazil. From the permeability cumulative S-curve analysis, we established major large-scale FUs that maintain part of the carbonate flow heterogeneity and correlate them with the elastic attributes: P-impedance (PI) and S-impedance (SI). In addition, we established a priori PI and SI correlations with the formation-factor (FF) (F) parameter to categorize large-scale FUs using the F vs. k methodology. With the large-scale FUs mapped in seismic data sets, core-plug-scale FUs can be populated into the 3D static and dynamic models using geostatistics tools, thus creating more-realistic reservoir models and assisting asset teams in the decision-making process. Introduction Hydrocarbon reservoirs are heterogeneous and not uniform, and can be divided into multiple homogeneous groups called FUs. Each unit presents similarities in terms of grain size, texture, cementation, pore distribution, porosity, and other physical characteristics controlled by the sediment depositional environment and diagenesis (Altunbay et al. 1994). FUs for reservoir characterization are an effective way to simulate fluid movement and oil-production behavior. According to Ebanks (1987), "a flow unit (FU) is a representative elementary volume of the total reservoir rock, within which geological and petrophysical properties that affect fluid flow rate are internally consistent and predictably different from properties of other rock volumes." Rock typing for FUs in reservoirs has been a source of debate for geoscientists.
Production from previously uneconomic tight/shale formations has become feasible by constructing multifractured horizontal wells. Rate-transient analysis of these wells is commonly performed with the assumption of homogeneous-reservoir models, which might not be valid in reality. During hydraulic fracturing, secondary fractures might be formed in the reservoir. Because of the limited energy of hydraulic fracturing, the quality of secondary fractures decreases with the distance from the main fracture. This would negate the assumption of a homogeneous reservoir.
In this paper, we present practical solutions that include reservoir heterogeneity in rate-transient analysis of multifractured wells. The solutions are developed for transient linear flow, which is a dominant-flow regime in many tight/shale reservoirs. In addition to forward solutions, inverse solutions are also developed that would ease the analysis procedure and reduce the uncertainty of estimation. The solutions are presented in simple formats and can be easily applied. We first developed the solutions such that they can be applied for any arbitrary permeability profile. We further considered special formats for the permeability/distance relationship and developed the relevant models. For a homogeneous system, the well-known square-root-of-time (time to the power of 0.5) plot is used. For the case of heterogeneity, however, the power of time should be greater than 0.5 and less than unity to produce a straight-line plot. We mathematically demonstrate this for a recognized format of the permeability/distance relationship.
The presented solutions are verified with the numerical simulation of synthetic examples. Comparison of the results reveals the accuracy of the analytical solutions. Two field examples are also analyzed to indicate the practical applicability of the analytical solutions. The permeability/distance profiles for these field examples are derived using the inverse solutions.
The solvent thermal resource innovation process (STRIP), a downhole steam-generation technology, has the capacity to show improved recovery factors with a significantly reduced environmental footprint compared with traditional thermal-enhanced-oil-recovery (TEOR) methods, most notably by delivering all the combustion heat to the pay zone. In this effort, a quarter-symmetry inverse-five-spot model and a multiphase, multicomponent reservoir-simulation framework were used to simulate the STRIP technology. Commercial simulators such as STARS - Thermal and Advanced Processes Reservoir Simulator [Computer Modelling Group Ltd. (CMG), Calgary, Alberta, Canada; CMG 2015b] often use the K-value approach to simulate TEOR. However, the method cannot simulate STRIP’s carbon dioxide (CO2) and steam coinjection because the K-value method does not consider miscible gas injection. On the other hand, CMG’s GEM - Compositional and Unconventional Simulator (CMG 2015a) includes the effects of miscible gases but does not provide comprehensive support for steam-injection processes, which are better handled by STARS. The novel simulation framework developed here leverages and combines the individual strengths of STARS (thermal features) and GEM (compositional features). In this framework, STARS simulated steam injection (but cannot directly simulate the effects of CO2) and was the governing model that synchronized temperature, pressure, and phase saturations for two parallel iterations of the GEM models (GEM-1 and GEM-2) at each timestep. Immiscible methane (CH4) was added to GEM models to maintain gas saturations equivalent to the STARS model. GEM-1 simulated hot-water and CH4 injection, but at increased rates to yield a pressure field and gas saturations equivalent to STARS. A final run of GEM-1 injected both CO2 and hot water and demonstrated the expected increase in oil production. Calibrated injection rates from GEM-1 were specified in GEM-2 to ensure equivalence of the pressure field. Next, the GEM-2 model also simulated hot-water and CH4 injection, but matched both water and oil productions along with oil saturations from the final GEM-1 run by altering relative permeabilities. Finally, the updated relative permeabilities were fed back to STARS, and iteration proceeded. Results from this framework were verified against a STARS steam-injection simulation. Finally, when considering coinjection of CO2, STRIP’s superior performance was demonstrated through increased oil recovery and a lower steam/oil ratio (SOR).
Summary A higher-order numerical model for compositional two-phase flow in fractured media is presented in this paper. The simulation of horizontal and deviated wells is incorporated in the formation using unstructured grids. All commonly used types of finite elements are accounted for in the algorithm: quadrangular and triangular elements in 2D, and hexahedra, prisms and tetrahedra elements in 3D. The fracture crossflow equilibrium (FCFE) approach is applied to model the flow exchange between the fractures and the matrix. FCFE is combined with the hybridized form of the mass conservative mixed finite element (MHFE) and the higher-order discontinuous Galerkin (DG) method. A computer-aided design (CAD) interface is developed that connects the mesh generator to the CAD software. The interface allows to design, mesh, and incorporate horizontal and deviated wells into the higher-order simulator. The algorithm allows flow simulation in fractures in all ranges of permeability values as opposed to the embedded discrete fracture matrix (EDFM) approach where low permeable fractures affect the accuracy of the results. The efficiency, accuracy, and strengths of the model are demonstrated in comparison to alternatives including the embedded discrete fracture approach in different examples. Detailed incorporation of complex wells is presented in this work. Introduction A substantial amount of the hydrocarbon reserves is in the naturally fractured reservoirs. Efficient exploitation of these reservoirs is facilitated using compositional reservoir simulators that have accuracy and computational efficiency. Modeling of fractured reservoirs is challenging because fractures impose a large range of spatial properties.
Quantifying wettability of organic-rich mudrocks is important for reliable formation evaluation, optimizing production, predicting water/hydrocarbon production, and selection of appropriate fracture fluids. Recent publications suggest that kerogen wettability can vary as a function of thermal maturity, ranging from water- to hydrocarbon-wet at low to high thermal maturities, respectively. However, clay minerals tend to preferentially be water-wet. It is therefore important to determine which of these constituents have a dominant contribution to overall wettability of the rock. To answer this question, we introduce methods to quantify the relative water-adsorption capacities of clay minerals, kerogen, and organic-rich mudrocks at different thermal-maturity levels. We started with isolating kerogen from organic-rich mudrock samples using chemical and physical separation methods and synthetically matured them to different thermal-maturity levels. We then prepared synthetic organic-rich mudrock samples by mixing known quantities of clay minerals, nonclay inorganic minerals, and kerogen. We then performed water-vapor adsorption measurements on pure clay minerals, pure kerogen samples, and synthetic organic-rich mudrock samples under controlled humidity conditions. Nuclear magnetic resonance (NMR) measurements were then used to quantify the volume of water adsorbed on clay minerals and organic-rich mudrock samples. We used the flotation test to qualitatively assess the wettability of the synthetic organic-rich mudrocks.
Water-vapor adsorption experiments showed that the volume of water adsorbed on the surface of nonheated kerogen samples at low thermal maturities is 5.31 mL/100 g, which decreases significantly to 0.09 mL/100 g when the kerogen sample is heat-treated to 450°C. The results can be attributed to strong attraction between the oxygen content in kerogen and water at low thermal maturities. We quantified the water-adsorption capacity of kerogen samples heat-treated at 450°C and found that volume of water adsorbed decreases with an increase in thermal maturity both in the presence and absence of bitumen. In the case of synthetic organic-rich mudrock samples, we found that the volume of water adsorbed in samples at higher thermal maturity decreases by 16% compared with organic-rich mudrocks at low thermal maturity at the same concentration of nonswelling clay minerals. Results from the flotation test showed that the oil-wettability of the synthetic organic-rich mudrock samples increases as its thermal maturity decreases, with a hydrogen index (HI) of 328 to 54 mg hydrocarbon/g organic carbon (mg-HC/g-OC). Results confirmed that kerogen and its geochemistry can have a significant influence on the overall wettability of organic-rich mudrocks even at low concentrations of 4 wt%. The outcomes of this paper can contribute to a better understanding of the parameters affecting wettability of organic-rich mudrocks and are promising for in-situ assessment of their wettability. This can potentially contribute to improved understanding of flow mechanisms in organic-rich mudrocks, which control hydrocarbon/water production.
Complex flow mechanisms, such as Knudsen diffusion, are encountered in the shale matrix because of the presence of nanopores. Numerous apparent-permeability models have been proposed to capture the ensuing non-Darcy flow behavior. However, these models are not readily available in most commercial reservoir simulators, and ignoring these mechanisms can potentially underestimate the overall matrix conductivity. This work implements an explicit coupling strategy for integrating a pressure-dependent apparent-permeability model in reservoir simulation. The numerical models are subsequently used to study the effects of apparent-permeability modeling and natural-fracture distribution on gas production and water loss during flowback. The effects of multiphase-flow functions on fluid retention are also assessed.
A set of 3D reservoir models are constructed using field data obtained from the Horn River shale-gas reservoir. First, stochastic 3D discrete-fracture-network (DFN) models are scaled up into equivalent continuum dual-porosity/dual-permeability models. An apparent-permeability (Kapp) model accounting for contributions of slip flow, Knudsen diffusion, and surface pore roughness is applied at each gridblock. A novel coupling scheme is formulated to facilitate the updating of Kapp after a certain specified time interval, capturing the pressure dependency of the Kapp. The sensitivity of the updating frequency is analyzed.
The results reveal that incorporating these additional flow mechanisms by means of the apparent-permeability formulation could potentially increase the overall gas-production prediction by up to 11%, depending on the average pore radius, reservoir pressure, and several other matrix or fluid properties. The implications of Kapp modeling in water-loss mechanisms are further examined through a set of sensitivity analyses, where the effects of multiphase-flow functions and DFN distributions are systematically investigated. The following interesting findings are observed:
This work offers a novel, yet practical, scheme for representing the pressure-dependent matrix apparent permeability in the flow simulation of shale reservoirs. The proposed method captures the non-Darcy flow behavior caused by the complex transport mechanisms occurring in nanosized pores. Most importantly, this coupling procedure can be implemented in existing commercial reservoir-simulation packages. The results have revealed a few interesting insights regarding the potential implications in fracturing design and estimation of stimulated reservoir volume.
Huang, Hai (Xi’an Shiyou University and Shaanxi Key Laboratory of Advanced Stimulation Technology for Oil & Gas Reservoirs) | Babadagli, Tayfun (University of Alberta and Xi’an Shiyou University) | Chen, Xin (University of Alberta) | Li, Huazhou (University of Alberta and Xi’an Shiyou University) | Zhang, Yanming (Oil & Gas Technology Research Institude of Changqing Oilfield Company)
Water blocking can be a serious problem, causing a low gas production rate after hydraulic fracturing, a result of the strong capillarity in the tight sandstone reservoir aggravating the spontaneous imbibition. Fortunately, chemicals added to the fracturing fluids can alter the surface properties and thus prevent or reduce the water-blocking issue. We designed a spontaneous imbibition experiment to explore the possibility of using novel chemicals to both mitigate the spontaneous imbibition of water into the tight gas cores and measure the surface tensions (STs) between the air and chemical solutions. A diverse group of chemical species has been experimentally examined in this study, including two anionic surfactants (O242 and O342), a cationic surfactant (C12TAB), an alkaline solution of sodium metaborate (NaBO2), an ionic liquid (BMMIM BF4), two nanofluids with aluminum oxide and silicon oxide (Al2O3 and SiO2, respectively), and a series of deep eutectic solvents (DES3-7, 9, 11, and 14). Experimental results indicate that the anionic surfactants (O242 and O342) contribute to low STs but cannot ease the water-blocking issue because they yield a more water-wet surface. The high pH solution (NaBO2), ionic liquid (BMMIM BF-4), and sodium chloride brine (NaCl) significantly decrease the volume of water imbibed to the tight sandstone core through wettability alteration, and C12TAB leads to both ST reduction and an air-wet rock surface, helping to prevent water blocking. The different types of DESs and nanofluids exhibit distinctly different effects on expelling gas from the tight sandstone cores through water imbibition. This preliminary research will be useful in both selecting and using proper chemicals in fracturing fluids to mitigate water-blocking problems in tight gas sandstones.
Injecting water with chemicals to generate emulsions in the reservoir is a promising method in the enhancement of heavy-oil recovery because the formation of oil-in-water (O/W) emulsions significantly reduces oil viscosity. Nanoparticles (NPs) (Pickering emulsions) can be used for this purpose as a cost-effective alternative to expensive surfactants; however, such Pickering emulsions need to be stable for successful applications. The objective of this study is to screen the effective emulsifier for O/W emulsions from a broad range of solid NPs and identify suitable Pickering emulsifying agents (e.g., adjusting pH or salt concentration) that can render emulsions stable at relevant conditions, and to investigate how a range of physical parameters, such as particle concentration, water/oil ratio (WOR), and temperature affect emulsion stability.
Five NPs—including cellulose nanocrystals (CNCs), silica, alumina, magnetite, and zirconia—were tested on their capabilities of stabilizing O/W emulsions through glass vial screening tests under various pH and salinity conditions. The screening results showed that the CNC could become an effective emulsifier by either adjusting pH or salinity. In addition, zeta potential measurements were conducted to explain the observations. The stabilization mechanisms of CNCs were studied through an epifluorescent transmitted microscope showing that the formation of a dense particle layer around the oil droplets, as well as a network in the continuous phase, were the two main mechanisms accounting for the high stability of the emulsions stabilized by CNCs. The effects of particle concentrations on the emulsion stability were studied quantitatively by analyzing the droplet-size distributions calculated by the open-source ImageJ software, with the results showing a sharp decrease in droplet size, followed by a smooth change as the particle concentration increased. For the WOR effect, phase inversion from O/W to water-in-oil (W/O) emulsions was observed when the oil content was more than 0.6. The thermal stability of emulsions was studied both macroscopically by glass bottle tests and microscopically through a microscope, both of which show that the CNC-stabilized emulsions remained thermally stable up to 100°C. The rheological properties of both aqueous dispersions of CNCs and the corresponding O/W emulsions were also measured under various salinity conditions. The results showed that the salinity had a great impact on the viscosity of the CNC suspension and the typical shear-thinning behavior of Pickering emulsions.
This study provides an option to enhance emulsion stability without surfactants, which will reduce the costs and facilitate field applications of emulsion flooding in heavy-oil recovery.