As U.S. shipyards implement swaged bulkheads on a larger scale and classification society rules are developed regarding the design of swaged bulkheads, several subjects surrounding the technology require further investigation. Swaging refers to the formation of arc-shaped ridges in a light-gage plate, typically using a round die in a press brake. These ridges have specific dimensions that are designed with structural properties to replace traditional welded stiffeners. The aim of this study is to advance the technical maturity of swage structures in order to facilitate their implementation on American-built ships and realize their potential benefits of cost savings, reduced labor, and weight reduction. Swage technology is being advanced through the development of direct analysis methodologies that can reliably predict the behavior of swaged bulkheads under various load profiles. This will allow certain swage designs to be evaluated analytically without having to build and test physical specimens. Ultimately this understanding and capability will facilitate the widespread use of swage bulkheads for both non-load bearing and loaded applications in ship designs.
The ability to effectively transport sand without the use of guar-based fluids has led to the development of friction reducers that build viscosity. These new products, also known as high viscosity friction reducers (HVFR) generate viscosities comparable to or greater than linear gel fluids. The selection criteria have focused primarily on achieving greater than 10 cP at 300 RPM (511s-1). As the salinity of the base fluid changes, the HVFR dosages must be increased up to 4X to meet this target. However, there is limited data available on how this viscosity correlates to the fluid’s ability to transport sand. This study presents methodology used to screen HVFR’s in various fluids and results on product performance, which identifies need for alternative specifications to viscosity.
The sand transport capacity under dynamic conditions was evaluated for two commercially available HVFR’s in up to 120,000 TDS synthetic water. A slot flow apparatus was used to mimic fluid flow through a fracture under different shear and flow conditions. The viscosity and elasticity were also measured using an advanced rotational rheometer. For comparison, a linear gel fluid was also evaluated.
While viscosity targets can be achieved by many commercially available HVFR products in freshwater, when salinity is increased, these products fail to meet the same targets. A comparison of the viscosity versus the sand transport capacity of these fluids, suggests viscosity does not indicate sand carrying capacity. The author did not find a correlation between higher viscosity and better sand transport. The results provided insight into the effect of flow rate on sand transport. The effect of salinity on s and transport suggests good performance can be achieved even at low viscosity. Elasticity testing of those same products suggested that HVFR’s have a critical elasticity range at which they will provide optimal performance.
This paper provides insight into the HVFR properties which correlate to sand transport and highlights the need for development of standardized test criteria other than viscosity. Further testing and screening of HVFR’s will increase the understanding of key factors influencing sand transport.
Moreno Ortiz, Jaime Eduardo (Schlumberger) | Gossuin, Jean (Schlumberger) | Liu, Yunlong (Schlumberger) | Klemin, Denis (Schlumberger) | Gurpinar, Omer (Schlumberger) | Gheneim Herrera, Thaer (Schlumberger)
Challenges on EOR process upscaling have been discussed extensively in the industry and effects of diffusion, dispersion, heterogeneity, force balance and frontal velocity -among others, recognized and qualified, along with the importance of understanding the numerical model finite difference equations and modeling strategy. Augmenting the upscaling complexity is the often-limited understanding/data on the EOR displacement at different scales (from micro to full field), including the EOR agent/rock/fluid interactions that is often available at the early stages of the EOR process de-risking.
A common denominator for the EOR process characterization and upscaling (along with the discretization of the displacement) is the non-uniqueness nature of the problem. As the complexity of numerical representation of the EOR process increases (thus increasing data characterization requirements), so does the number of plausible solutions and challenges when dealing with an otherwise incomplete dataset. Digital rock has evolved as a strong alternative to complement laboratory corefloods, allowing for EOR agent optimization on a high-resolution digital representation of the pore structure, detailed digital fluid model of both reservoir fluids and EOR agents and physical rock-EOR agent-reservoir fluid interaction, thus providing several calibration points to ensure the finite-difference model calibration and upscaling preserve the process behavior.
This paper discusses the use of digital rock solutions on the EOR deployment, particularly on translating the results to numerical finite difference models, addressing the inherent laboratory measurement uncertainty and proposing a fit-for-purpose multi-scale upscaling strategy that addresses both effects of heterogeneity and EOR agent characterization during the upscale process.
This paper addresses the challenges of chemical flooding upscaling, particularly polymer by using a real-life polymer injection case where digital rock, corefloods and more importantly pilot results are available to test and validate our observations. Using a polymer coreflood and digital rock results as input, numerical finite difference simulation models were built and calibrated to effectively reproduce the displacement physics observed on both digital rock and corefloods, digital flood results were used to bridge the laboratory-to-numerical model step by providing effective upscaled polymer properties as well as intrinsic rock properties such as relative permeability and capillary pressures, which are then taken through a series of multi-scale finite difference models to identify, validate and quantify upscaling requirements, addressing polymer deformation through pore throats and effective simulation viscosity. Digital rock is used to rank and resolve ambiguity on the finite difference model calibration by providing an otherwise rare opportunity to visualize the displacement in the 3D space. The analysis shed a new light on fluid-fluid and fluid-rock interaction at pore scale and enabled us to improve on the finite difference model generation and polymer properties.
Ba Geri, Mohammed (Missouri University of Science and Technology) | Ellafi, Abdulaziz (University of North Dakota) | Flori, Ralph (Missouri University of Science and Technology) | Noles, Jerry (Coil Chem LLC) | Kim, Sangjoon (Coil Chem LLC)
Viscoelastic property of high-viscosity friction reducers (HVFRs) was developed as an alternative fracturing fluid system because of advantages such as the ability to transport particles, higher fracture conductivity, and potential lower cost due to fewer chemicals and equipment on location. However, concerns remain about using HVFRs to transport proppant in DI water and harsh brine solution (e.g. 2wt% KCl and 10 lbs. brine). The primary objective of this study is to investigate the viscoelastic property that can help to understand the true proppant transporting capacity of fracturing fluids in high-TDS environment.
To address the evaluation performance of HVFRs, a comprehensive review of numerous papers associated to viscoelastic property of hydraulic fracturing fluids were investigated and summarized. This paper also provides a full comparison study of viscosity and elastic modulus between HVFRs and among fracturing fluids such as xanthan, polyacrylamide-based emulsion polymer, and guar. Moreover, viscosity profiles and elastic modulus were conducted at different temperatures. Better proppant transportation effect though higher viscosity through Stoke's law and the effect on proppant transportation from elastic modulus comparison were also investigated. Finally, HVFR Conductivity test and successful field test result were explained.
The results of the experimental work show that viscoelastic property HVFRs provides good behavior to transport proppant. Viscosity profile decreased slightly as the temperature increased from 75 to 150 when the DI water was used. While using 10 lbs. Brine the viscosity was reduced by 33%. The longer polymer chains of HVFR indicated better elastic modulus in DI water. The elastic modulus also indicated that the highest values at frequency 4.5 Hz from each amplitude, and lower values as amplitude was increased. Although high molecular weight HVFRs were utilized on the conductivity test, the results observed that the regained permeability was up to 110%. Finally, the promising results from the case study showed that using HVFRs could be performed economically and efficiently for the purpose of proppant transportation and pressure reduction in high TDS fluids.
An experimental study was conducted to measure the settling velocity of spherical particles in viscoplastic fluids. Using a mechanistic model based on the balance of the forces acting on the settling particle and detailed statistical analyses of the experimental results, a generalized model for predicting settling velocity of spherical particles in viscoplastic fluids was developed. The main objectives of the study were: i.) To measure the terminal settling velocity of particles in various viscoplastic fluids intending to expand the present database of experimental data ii.) To develop a new Drag coefficient-particle Reynolds number (CD-Rep) correlation that is applicable to both Newtonian and non-Newtonian viscoplastic fluids iii.) To present a general non-iterative approach for predicting settling velocities of particles in Newtonian and non-Newtonian viscoplastic fluids irrespective of their rheological models (Casson Model, Herschel Bulkley Model, and Bingham Model etc.).
The settling velocities of the spherical particles (Specific gravity ranging from 2.5 - 7.7; Diameters: ranging from 1.09 - 4.00 mm) in various Carbopol solutions were measured using Particle Image Shadowgraphy (PIS). The experimental results were combined with experimental data published in the literature to broaden the range and applicability of empirical analysis. Advanced statistical analysis programs (OriginPro 9.0 and MATLAB r2018b) were utilized together with extensive experimental data to develop a new CD-Rep correlation. In this study, a new modified shear Reynolds number (
We have shown that presented new model predicts settling velocity better and yielded relatively more accurate results than existing models with the lowest approximate Mean Absolute Error (MAE) of 0.1 m/s for all data points. In addition to enhanced prediction accuracy, this new model occludes application constraints and offers prediction versatility that is lacking in current existing models by being valid for diverse rheological models of non-Newtonian viscoplastic fluids. The paper is concluded by presenting an illustrative and pragmatic example to calculate the terminal velocity of a spherical particle in a non-Newtonian viscoplastic fluid using the presented generalized model.
The knowledge of particle settling velocity in viscoplastic fluids is indispensable for the design, analysis, and optimization of a wide spectrum of industrial processes such as cuttings transport in oil and gas well drilling and proppant transport in hydraulic fracturing operations. By augmenting the current corpus of experimental data; we have provided much-needed particle settling velocity database that can be used for modeling of relevant transport processes (i.e. cuttings and/or proppants transport). Finally, by combining a mechanistic model describing the forces acting on the settling particles with the newly developed CD-Rep correlation, we have presented a new generalized predictive model of particle settling velocity in viscoplastic fluids that can be used for the optimization of particle transport in oil and gas well drilling and hydraulic fracturing operations.
Ghosh, Pinaki (The University of Texas at Austin) | Zepeda, Angel (The University of Texas at Austin) | Bernal, Gildardo (The University of Texas at Austin) | Mohanty, Kishore (The University of Texas at Austin)
Waterflood in low permeability carbonate reservoirs (<50 mD) leaves behind a substantial amount of oil due to capillary trapping and poor sweep. Addition of polymer to the injected water increases the viscosity of the aqueous phase and decreases the mobility ratio, thus, improving the sweep efficiency and oil production from the tight formations. Performance of current synthetic EOR polymers is limited by salinity, temperature and injectivity issues in low permeability formations. Mechanical shear degradation can be applied to high molecular weight synthetic polymers to improve the injectivitiy; but makes the process less economical due to significant viscosity loss and consequent increase in polymer dosage. Recently, a different class of polymer has been developed called "hydrophobically modified associative polymers (AP)". The primary goal of this work is to investigate the performance of associative polymers in low permeability carbonate reservoirs. We compare the performance of associative polymers with that of conventional HPAM polymers in low permeability formations. A low molecular weight associative polymer was investigated as part of this study. A detailed study of polymer rheology and the effect of salinity at the reservoir temperature (60 °C) was performed. Additional experiments were performed in bulk and porous media to investigate the synergy of associative polymers with hydrophilic surfactant blends at different brine salinities. Single phase polymer flow experiments were performed in outcrop Edwards Yellow and Indiana limestone cores of low permeability to determine the optimum polymer concentration to achieve the desired in-situ resistance factor (or apparent viscosity). Similar experiments were performed with HPAM polymer for a comparative study. Results showed successful transport of this associative polymer in low permeability formations after a small degree of shear degradation. The resistance factors for the associative polymer were higher than those for HPAM. Shear degraded polymers showed significant improvement in polymer transport in lower permeability cores with reduction in RRF.
Wang, Zhihua (Northeast Petroleum University) | Zhu, Chaoliang (Northeast Petroleum University) | Lou, Yuhua (PetroChina Daqing Oilfield Engineering Company Limited) | Cheng, Qinglin (Northeast Petroleum University) | Liu, Yang (Northeast Petroleum University) | Wang, Xinyu (PetroChina Daqing Oilfield Company Limited)
Wax crystals can aggregate and precipitate when the oil temperature decreases to below the wax appearance temperature (WAT) of waxy crude oil, which has undesirable effects on the transportation of crude oil in pipelines. Thermodynamic models considering the molecular diffusion, shearing dispersion, and shear stripping as well as hydrodynamic models have been developed for predicting the wax deposition in crude oil pipelines. However, the aggregation behavior of wax crystals during crude oil production and transportation is not well understood. The microscopic rheological parameters have not been related to the bulk flow parameters in the shearing field, and the prediction of the wax deposition behavior under complex conditions is restricted by the vector characteristics of the shearing stress and flow rate. A set of microscopic experiments was performed in this study to obtain the basic information from images of wax crystals in shearing fields. A novel method of fractal dimensional analysis was introduced to elucidate the aggregation behavior of wax crystals in different shear flow fields. The fractal methodology for characterizing wax crystal aggregation was then developed, and a blanket algorithm was introduced to compute the fractal dimension of the aggregated wax crystals. The flow characteristics of waxy crude oil in a pipeline were correlated with the shearing stress work, and a wax deposition model focusing on shearing energy analysis was established. The results indicate that a quantitative interpretation of the wax crystal aggregation behavior can be realized using the fractal methodology. The aggregation behavior of the wax crystals is closely related to the temperature and shearing experienced by the waxy crude oil. The aggregation behavior will be intensified with decreasing temperature and shearing effect, and a wider fractal dimension distribution appears at lower temperatures when the same shear rate range is employed. The lower the fractal dimensions obtained at high temperature and strong shear action, the weaker will be the nonlinear characteristics of the wax crystal aggregation structure, and thus, the potential wax deposition will be inhibited during waxy crude oil production and transportation. Furthermore, the improved model provides a method for discussing the effects of the operating conditions on wax deposition. The average relative deviation between the improved model prediction results and experimental results from the literature is 3.01%–5.32%. The fractal methodology developed in this study and the improvement in wax deposition modeling are beneficial for understanding and optimizing flow assurance operations in the pipeline transportation of waxy crude oils, and the results are expected to facilitate a better understanding of the wax crystallization and deposition mechanism.
Within the last decade, technical advancements in horizontal drilling have created an environment in the hydraulic fracturing industry resulting in a paradigm shift for the completion of unconventional wells. This shift away from conventional, vertical, bi-wing fractures with large diameter proppant, to the current unconventional design of multi-zone laterals, requires a new generation of proppants and carrying fluids. This proposes a challenge to the industry to successfully place proppant into the far field regions of potentially multiple fracture networks. To meet this challenge the industry has dedicated numerous resources to study proppant transport behavior and carrying agent behavior to better understand and apply materials that will economically optimize well completions.
This paper focuses on how proppant is transported with different fracturing fluids using a combination of pipe flow and patent-pending slot flow tests to study their behavior in various sections of a simulated fracture, including near-wellbore and far-field (low shear) fracture environments.
The objectives for the project are defined as: Identify proppant transport characteristics (40/70 and 100 mesh frac sand) through an open channel of high shear, low shear, leak off and low-to-zero shear environments with various fluids (slickwater, HVFR, linear gel and crosslinked gel). Determine how changes in geometry (incline, decline, dead-end, drop-off, and banking) impact proppant placement. Determine the carrying capabilities of various fluids with 40/70 and 100 mesh proppants.
Identify proppant transport characteristics (40/70 and 100 mesh frac sand) through an open channel of high shear, low shear, leak off and low-to-zero shear environments with various fluids (slickwater, HVFR, linear gel and crosslinked gel).
Determine how changes in geometry (incline, decline, dead-end, drop-off, and banking) impact proppant placement.
Determine the carrying capabilities of various fluids with 40/70 and 100 mesh proppants.
Comprehensive testing was performed on three separate test designs: pipe flow, standard 4′x8′ slot flow and patent-pending 4′×8′ slot flow with obstructions inside the structure. Test procedures are designed to simulate a typical West Texas unconventional well with 100 bbl/min, 5 ½″ casing, 15,000′ of casing. Fluids are conditioned to well specifications prior to entering the test design. Fluid and proppant are trapped, and the equipment is disassembled for further analysis after each test. The collected data includes shear rates, fluid viscosities, mean particle diameter, proppant distribution, proppant concentration, pictures and videos.
Observations and conclusions include, but are not limited to, the changes/lack of changes of mean particle diameter of the proppant within the structure, comparative analysis of the carrying capabilities of slickwater, high viscosity friction reducers (HVFR), linear gel and crosslinked gel. Noteworthy differences between 40/70 and 100 mesh behavior are evaluated. An in-depth study on the carrying capabilities of high concentrations of HVFR (4 gpt and 6 gpt) is also included.
The goal of this project is to add further knowledge and insight into the design of unconventional completion techniques and to evaluate new and/or novel proppant and fracturing fluids. With the rapid shift to fine mesh proppants and a lack of comparative production data (ranging from 12-24 months), the industry is relying heavily on research and development to identify effective products for unconventional well completions. These learnings should allow for further development of materials and technologies targeted expressly for unconventional completions.
Long-term integrity and practical storage of CO2 is contingent upon its seal performance and the dynamic sealing capacity of faults for the CO2 storage site. Faults are prone to reactivation with reservoir pressurization caused by CO2 injection. The goal of this study is to create and verify a reservoir elasto-plastic model capable of capturing short-term evolution of fault reactivation and the resulting change of permeability. This model is then used to explore the effects of coupling geomechanics with reservoir fluid flow on the reactivation of faults.
In this paper, we introduce a workflow for modeling of fault reactivation with fault elements as gridblocks instead of surfaces. Reservoir simulation, with coupled fluid flow and geomechanics, was used for this purpose. The simulation models utilize a geomechanical module to capture elasto-plasticity and a compositional numerical scheme based on an equation of state (EOS) to calculate CO2-brine interaction. The geomechanical module used in this study is based on Hierarchical Single Surface (HISS) model that captures strain softening and hardening, and therefore post-yield plastic deformations related to fault reactivation. The compositional numerical scheme based on EOS calculates the amount of CO2 solubilization in brine as well as the density and viscosity of the CO2- and aqueous-rich phase. In this approach, the flow properties, i.e. permeability and porosity, dynamically change in response to geomechanical effects. The dynamic change was captured through a volumetric strain-permeability law.
Our simulation results show that the model is capable of capturing short-term evolution of fault reactivation and the resulting change of permeability along the fault. The dynamic changes of fault properties control the extent of fault reactivation, the pressure relief during injection, and the fault sealing capacity.
A well was drilled into a prospective new unconventional mudstone play offshore Norway. Two of five coring runs were successful while the rest yielded little to no core recovery. Investigations attributed the poor recovery to sub-optimal coring practices, equipment failure and operational errors. Recently, the accompanying petrophysical logs and seismic data were revisited, and upon detailed investigation several unusual responses were observed to correspond with intervals of poor core recovery. Subsequent investigation of the core itself substantiated that the coring issues largely had natural causes. This understanding is being applied to two imminent coring operations and has driven selection of drilling, coring and wireline technology and procedures, in addition to informing casing design.
Wireline nuclear magnetic resonance (NMR) and cross dipole acoustic data, logging whilst drilling (LWD) density (including azimuthal images), neutron porosity and resistivity was acquired over the interval of interest for standard formation evaluation purposes. This interpretation was conducted immediately after the initial drilling and showed the formation to be a series of highly porous oil bearing mudstones. However, no in depth advanced interpretation was conducted at the time. Recently, advanced analysis including high resolution log enhancement, NMR 2D porosity and saturation analysis, acoustic azimuthal anisotropy, near wellbore imaging, fracture interpretation, and borehole image interpretation were performed on the log data, and new and improved 3D seismic data was interpreted. When interpreted in detail it could be observed that unusual responses in the logs showed a close correspondence to the intervals of poor core recovery. In particular, high azimuthal anisotropy was observed, and when this was compared to the near wellbore reflection image a significant planar reflecting feature was identified which is determined to be a fault. Indications of this feature was subsequently found in seismic data. When then compared to the azimuthal density image after resolution enhancement was applied, although the image is still of too low resolution to directly image the fault, disturbed bedding was observed which is commonly associated with faulted intervals. Several core fragments proved to have extensive small-scale fracturing not noticed previously, and slickenlines were found along several larger fractures previously presumed to be drilling induced.
The investigations of the log data revealed that a previously unknown sub-seismic fault was present right below the depth where coring problems were encountered. The detailed interpretation was able to determine the precise location of the fault and its extent in the formation. Knowledge of this subsequently explained the coring problems encountered and helps to optimise imminent coring in the same formation. Lessons learned and the methodology likely also applies to similar formations.
In this paper we discuss coring issues encountered in a new and unconventional play offshore, present new data and interpretation that sheds light on them and describe the methodology of the detailed integrated interpretation that uncovered the previously unknown root cause. We then discuss how these findings can be (and are) used to optimise both drilling, coring, and logging operations in future wells.