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Thomas, F Brent (Resopstrategies) | Piwowar, Michael (Stratum Reservoir) | Noroozi, Mehdi (Stratum Reservoir) | Apil, Ronnel (Stratum Reservoir) | Marin, Juan (Stratum Reservoir) | Gibb, William (Stratum Reservoir) | Clarkson, Carter (Stratum Reservoir) | Zhang, Hongmei (Stratum Reservoir) | Swacha, Stan (Stratum Reservoir)
The role of cycling pressure, injection gas composition, soak time and level of primary depletion before initiation of GCEOR and the importance of geology have been measured. Gas-cycling Huff and Puff operations have been analyzed in porous media exhibiting in situ oil permeabilities ranging from 20 to 2000 nD, with fluid densities between 40 and 47 API and gas-oil ratios between 800 and 2750 scf/BBL. The importance of geological properties relative to oil properties in GCEOR design was quantified along with analysis of GCEOR performance in systems exhibiting Peclet numbers changing over two orders of magnitude.
High-permeability fracs and very low permeability matrix have been combined into a novel patent-pending laboratory equipment design whereby large hydrocarbon pore volumes with live reservoir fluids are used. Flow between matrix and fracture(s) is induced by scaling field operations to lab-size experiments and inducing differential pressure gradients between matrix and frac during Huff and Puff cycles. Produced gas, liquid and recombined fluid compositions, as a function of time, are measured along with produced liquid densities. Full reservoir conditions are reproduced and Primary Depletion followed by Huff and Puff GCEOR are evaluated, while changing the design parameters listed above. This work has been performed on diverse oil and rock properties. With this equipment various fluids can be tested in diverse porous media whereby the relative importance of rock properties on GCEOR performance is measured. Moreover, for porous media that exhibit broad pore size distributions, or micro-scale heterogeneity, the efficacy of conformance control agents can be evaluated.
With more than fifty primary depletion tests followed by cyclic Huff and Puff gas injection, insights into GCEOR have been obtained. First-contact miscible gases have been observed to respond very differently as a function of changes in rock properties and reservoir fluid volatility. Performing primary depletion followed by GCEOR with different reservoir fluids but in the same porous media elucidate the importance of rock properties. It was found that appropriate GCEOR design must consider rock quality. Mercury injection capillary pressure data have been measured and are shown to breathe insight into GCEOR performance. For geology that possesses micro-scale heterogeneity water injection was used as a conformance control agent. GCEOR performance is quantified with and without water as a means of conformance control. The effects of cycling pressure, injection gas composition, soak time, level of primary depletion, before GCEOR, and other parameters have been investigated. All GCEOR testing was done in order to quantify the relative benefit compared to primary depletion recovery. This experimental protocol represents a valuable adjunct to using simulation to scale-up from lab to field.
Martins, A. L. (Petrobras) | Santos, H. F .L. (Petrobras) | Castro, B. B. (Petrobras) | Gonçalves, A. S. (Interdisciplinary Center for Fluid Dynamics, NIDF/UFRJ.) | Maffra, D. A. (Interdisciplinary Center for Fluid Dynamics, NIDF/UFRJ.) | Loureiro, J. B. R. (Interdisciplinary Center for Fluid Dynamics, NIDF/UFRJ.)
Downhole carbonate scaling is a major concern in offshore scenarios, where workover operations are associated with very high costs. Intelligent completion concepts are also a requirement for reservoir management optimization. These systems however, introduce several elements in the production string which may constitute hotspots for scaling. The goal of this work is to present pilot scale test facilities and procedures designed to mimic real field situations. Results presented include pH, conductivity and particle size distributions from samples taken along the pipe length and along periodic time intervals. Severe, but representative of some of Brazilian pre-salt scenarios, scaling conditions (S between 3 and 3.4 and pH around 7.5) enable comparative results with a reasonable test volume. Pressure drop on the valve and along the pipe length is also discussed. The scale adherent to the pipe wall and on the valve have been dried and weighted after the experiment. X-ray diffraction and scanning electron microscopy have been used for further characterization of the scale structure. The role of flow rates, water composition and valve opening (creating different localized pressure drops) is experimentally investigated. A discussion on scaling mechanisms is presented. Additionally, the use of non-chemical strategies to delay pressure drop increase is also shown. Results show the present experimental set up is able to reproduce hydrodynamics and scaling conditions of downhole scenario. In this work reproducible large scale test procedures have been established. The flow loop allows the evaluation of chemical injection devices besides non chemical mitigation alternatives, including coatings and physical strategies.
Prior to 2007, the U.S. Department of Energy (DOE) upstream oil and gas research program focused primarily on onshore applications. In 2000, the DOE published the
Discussion focuses on key research findings from the DOE ultra-deepwater research portfolio of 2007-2013. Then the paper describes the current offshore research portfolio 2014 – 2019. Finally, the paper describes the outcomes and insights from key discussions with industry, academia, research and non-government and government stakeholders that could become a frame for a technology research roadmap for the entire Outer Continental Shelf.
DOE research investments in public-private partnerships with industry, academia, research labs, and others have made an important contribution to the current state-of-the-art in offshore technology---contributions that most people may not realize are tied to previous research investments by DOE. Tracing these contributions, tracking them back to the
The information in this paper will both inform and inspire new frontiers of research for the OCS. As the USA moves forward with onshore development of unconventional resources, there are features of the DOE onshore research portfolio that may have merit in the OCS. For example, the DOE Field Laboratory program is focused on basin-specific research strategies where new technology can be applied to operating oilfields and evaluated via the scientific method. Then the data captured can potentially become part of further research by the DOE National Laboratories including geophysical, geomechanical, geochemical, and data analytics such as machine learning. This DOE program has been very successful onshore, and perhaps there is a place for a comparable multi-disciplinary, multi-partner approach in the OCS.
Al-Rudaini, Ali (Heriot-Watt University) | Geiger, Sebastian (Heriot-Watt University) | Mackay, Eric (Heriot-Watt University) | Maier, Christine (Heriot-Watt University) | Pola, Jackson (Heriot-Watt University)
Summary We propose a workflow to optimize the configuration of multiple-interacting-continua (MINC) models and overcome the limitations of the classical dual-porosity (DP) model when simulating chemical-component-transport processes during two-phase flow. Our workflow is intuitive and derived from the simple concept that fine-scale single-porosity (SP) models capture fracture/matrix interaction accurately; it can hence be easily applied in any reservoir simulator with MINC capabilities. Results from the fine-scale SP model are translated into an equivalent MINC model that yields more accurate results compared with a classical DP model for oil recovery by spontaneous imbibition; for example, in a water-wet (WW) case, the root-mean-square error (RMSE) improves from 0.123 to 0.034. In general, improved simulation results can be obtained when selecting five or fewer shells in the MINC model. However, the actual number of shells is case specific. The largest improvement in accuracy is observed for cases where the matrix permeability is low and fracture/matrix transfer remains in a transient state for a prolonged time. The novelty of our approach is the simplicity of defining shells for a MINC model such that the chemicalcomponent-transport process in naturally fractured reservoirs can be predicted more accurately, especially in cases where the matrix has low permeability. Hence, the improved MINC model is particularly suitable to model chemical-component transport, key to many CEOR processes, in (tight) fractured carbonates. Fractures are more common in carbonate reservoirs than in clastic reservoirs (Ahr 2008), and much oil can be left behind in the rock matrix, which is typically oil-wet (OW) and mixed-wet (MW) (Treiber and Owens 1972), causing low recovery factors. The scope of this paper is to investigate the applicability of different DP models for predicting the transport of chemical components from fractures into a matrix block by means of spontaneous imbibition (SI). The effects of matrix permeability and wettability conditions are also investigated. The motivation to study chemical-component transport comes from the fact that it occurs in all CEOR processes. If we simulate chemical-component transport in a fractured reservoir incorrectly using DP models, then any subsequent chemical reaction [e.g., wettability alteration or interfacial-tension (IFT) reduction] during CEOR will also be predicted incorrectly.
Pre-loading parent wells with surfactant-based treatment fluids for frac hit mitigation has been applied extensively in liquids-rich shale plays, where infill drilling and tighter well spacing are prerequisites for improved production and economic return. Pre-loads can provide a significant and temporary increase in fracture network pressure if done properly and are most effective with a surfactant and solvent package. However, it remains elusive why specific chemical packages help improve the parent well production, although the notion of capillary force resistance reduction for further treatment fluid leakoff into fractures and rock wettability alteration by surfactant has been proposed previously. Recent residual surfactant analysis in produced water from both parent and child wells indicates that there is indeed hydraulic communication after frac hits, and field trials in the Wolfcamp suggest that adding the same surfactant package in primary frac fluids in child wells can migrate to parent wells, thereby potentially activating various secondary oil recovery mechanisms.
Astrategy for properly selecting a surfactant solvent package is presented for parent wells. Most conventional surfactant tests do not provide much insight in the absence of formation rock. Instead, a rock-on-a-chip microfluidic device is used to illustrate the interactions between parent and child wells when frac hits occur. Spontaneous imbibitions of primary frac and secondary treatment fluids into formation rocks are performed along with computed tomography (CT) imaging to understand the surfactant efficacy for enhancing leakoff into secondary fractures.
Oil recovery and associated water saturation in the microfluidic-based device with or without surfactant are quantified and reveal that the oil recovery is enhanced with surfactant, and water saturation in the parent well could be reduced thereby mitigating water blocks from primary frac fluid invasion from child wells. Spontaneous imbibition results provide insight into a surfactant's effectiveness to leakoff into secondary fractures within a matter of several days, which coincides with a typical short time window for the offset frac to begin to achieve maximum pressure support.
Scaling groups for hybrid steam-solvent recovery processes are presented in this paper. A brief discussion of the derivation of the scaling groups is given first. Then an examination of the comparative behavior of these scaling groups at different scales is provided using reservoir simulation for the example of a high solvent load steam-butane gravity drainage process (i.e., steam-butane hybrid (SBH)).
Scaling groups were derived for hybrid steam-solvent recovery processes by inspectional analysis using governing equations for multi-phase flow in porous media. The effects of key mechanisms in these processes (diffusion, dispersion, advection and capillary pressure) were examined within the context of the derived scaling groups using reservoir simulation of SBH at three different geometric scales, ranging from the laboratory scale through a semi-field scale to the field scale, for one specific set of operating conditions. The scaling groups were used to analyse and interpret the numerical results.
The scaling groups were characterized according to the physical mechanisms from which they were derived. The intent of this analysis was to determine which of the mechanisms tend to be most important to the SBH process at different geometric scales. It is clear from a cursory examination of the scaling groups that all of the scaling groups representing the behavior of the SBH process cannot be satisfied when the geometric scale is changed from the laboratory scale to the field scale. The results of the study also indicate that the Pujol and Boberg scaling criteria for thermal processes seem to provide a reasonable approach for scaling SBH, when they are adapted to include the effects of dispersion. The influence of capillary pressure was secondary to other mechanisms involved in the process. It was evident from the simulations that the influence of dispersion was much more pronounced than diffusion for the solvent loading that was considered. Further, it was found that mechanical dispersity must be scaled with length to scale this mechanism appropriately in the reservoir simulator that was used in this study (CMG STARS™). As a final observation, the influence of capillary pressure was secondary to other mechanisms involved in the process.
Few studies on scaling high solvent loading hybrid steam-solvent processes have been undertaken. Using reservoir simulation to study scaling groups for these processes is a novel approach to this subject. Understanding the scalability of hybrid steam-solvent processes from the laboratory scale to the field scale would improve the capability of laboratory experiments to represent the performance of these recovery processes at the field scale.
Summary Spontaneous imbibition is a capillary-dominated displacement process in which a nonwetting fluid is displaced from a porous medium by the inflow of a more-wetting fluid. Decades of core-scale experiments have concluded that spontaneous imbibition occurs by a uniformly shaped saturation front with a rate that scales with the square root of time. The imbibition rate during early stages of spontaneous imbibition (the onset period) has been reported to deviate from the square-root-of-time behavior, although its effect on the imbibition process is not well-understood. Controlled-imbibition tests, presented in this paper, demonstrate that restricted wetting-phase flow during the onset period gives irregular saturation fronts and deviation from the square-root-of-time behavior. The deviation was caused by local variation in porosity and permeability or by a nonuniform wettability distribution, and was directly visualized or imaged by positron-emission tomography (PET). Without knowledge of local flow patterns, the development of irregular saturation fronts cannot be observed; hence, the effect cannot be accounted for, and the development of spontaneous imbibition might be erroneously interpreted as a core-scale wettability effect. Restricted wetting-phase flow at the inlet affects Darcy-scale wettability measurements, scaling, and modeling; our observations underline the need for a homogeneous wettability preference through the porous medium when performing laboratory spontaneous-imbibition measurements. Introduction Spontaneous imbibition is a process in which a nonwetting fluid is displaced from a porous material by the inflow of a more-wetting fluid, as a result of the pressure difference across the interface between two immiscible fluids (Morrow and Mason 2001). Spontaneous imbibition strongly affects waterflood oil recovery in fractured reservoirs and is widely studied. Correlation of laboratory core-scale production data to recovery on the reservoir scale has been investigated for several decades.
Scaling of imbibition data is of essential importance in predicting oil recovery from fractured reservoirs. In this work, oil recovery by countercurrent spontaneous imbibition from 2D matrix blocks with different boundary conditions was studied using numerical calculations. The numerical results show that the shape of imbibition-recovery curves changes with different boundary conditions. Therefore, the imbibition curves could not be closely correlated with a constant parameter. A modified characteristic length was proposed by a combination of Ma et al. (1997) and theoretical characteristic length. The modified characteristic length is a function of imbibition time, and the shape of imbibition curves could be changed using the modified characteristic length. The overall imbibition curves were closely correlated using the modified characteristic length. Finally, the modified characteristic length was verified by experimental data for imbibition with different boundary conditions.
Surfactants induce spontaneous imbibition of water into oil-wet porous media by wettability alteration and interfacial-tension (IFT) reduction. Although the dependence of imbibition on wettability alteration is well-understood, the role of IFT is not as clear. This is partly because, at low IFT values, most water/oil/amphiphile(s) mixtures form emulsions and/or microemulsions, suggesting that the imbibition is accompanied by a phase change, which has been neglected or incorrectly accounted for in previous studies. In this paper, spontaneous displacement of oil from oil-wet porous media by microemulsion-forming surfactants is investigated through simulations and the results are compared with existing experimental data for low-permeability cores with different aspect ratios and permeabilities. Microemulsion viscosity and oil contact angles, with and without surfactant, were measured to better initialize and constrain the simulation model. Results show that with such processes, the imbibition rate and the oil recovery scale differently with core dimensions. Specifically, the rate of imbibition is faster in cores with larger diameter and height, but the recovery factor is smaller when the core aspect ratio deviates considerably from unity. With regard to the mechanism of water uptake, our results suggest, for the first time, that (i) microemulsion formation (i.e., fluid/fluid interface phenomenon) is fast and favored over the wettability alteration (i.e., rock-surface phenomenon) in short times; (ii) a complete wettability transition from an oil-wet to a mixed microemulsion-wet and surfactant-wet state always occurs at ultralow IFT; (iii) wettability alteration causes a more uniform imbibition profile along the core but creates a more diffused imbibition front; and (iv) total emulsification is a strong assumption and fails to describe the dynamics and the scaling of imbibition. Wettability alteration affects the imbibition dynamics locally by changing the composition path, and at a distance by changing the flow behavior. Simulations predict that even though water is not initially present, it forms inside the core. The implications of these results for optimizing the design of low-IFT imbibition are discussed.
Hydraulic fracturing has been widely used for unconventional reservoirs, including organic-rich carbonate formations, for oil and gas production. During hydraulic fracturing, massive amounts of fracturing fluids are pumped to crack open the formation, and only a small percentage of the fluids are recovered during the flowback process. The negative effects of the remaining fluid on the formation, such as clay swelling and reduction of rock mechanical properties, have been reported in the literature. However, the effects of the fluids on source-rock properties—especially on microstructures, porosity, and permeability—are scarcely documented. In this study, microstructure and mineralogy changes induced in tight carbonate rocks by imbibed fluids and the corresponding changes in permeability and porosity are reported.
Two sets of tight organic-rich carbonate-source-rock samples were examined. One sample set was sourced from a Middle East field, and the other was an outcrop from Eagle Ford Shale that is considered to be similar to the one from the Middle East field in terms of mineralogy and organic content. Three fracturing fluids—2% potassium chloride (KCl), 0.5 gal/1,000 gal (gpt) slickwater, and synthetic seawater—were used to treat the thin section of the source-rock and core samples. Modern analytical techniques, such as scanning electron microscopy (SEM) and energy-dispersive spectroscopy (EDS), were used to investigate the source-rock morphology and mineralogy changes before and after the fluid treatment, at the micrometer scale. Permeability as a function of effective stress was quantified on core samples to investigate changes in flow properties caused by the fracturing-fluid treatments.
The SEM and EDS results before and after fracturing-fluid treatments on the source-rock samples showed the microstructural changes for all three fluids. For 2% KCl and slickwater fluid, reopening of some mineral-filled natural fractures was observed. The enlargement of the aperture for pre-existing microfractures was slightly more noticeable for samples treated with 2% KCl compared with slickwater at the micrometer scale. In one sample, dissolution of organic matter was captured in the slickwater-fluid-treated rock sample. Mineral precipitation of sodium chloride (NaCl) and generation of new microfractures were observed for samples treated with synthetic seawater. The formation of new microfractures and the dissolution of minerals could result in increases in both porosity and permeability, whereas the mineral deposition would result in permeability decrease. The overall increase in absolute gas permeability was quantified by the experimental measurements under different effective stress for the core-plug samples. This effect on absolute-gas-permeability increase might have an important implication for hydrocarbon recovery from unconventional reservoirs.
This study provides experimental evidence at different scales that aqueous-based fracturing fluid might potentially have a positive effect on gas production from organic-rich carbonate source rock by increasing absolute gas permeability through mineral dissolution and generation of new fractures or reopening of existing microfractures. This observation will be beneficial to the future use of freshwater-and seawater-based fluids in stimulating gas production from organic-rich carbonate formations.