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Kakitani, Celina (Federal University of Technology of Parana UTFPR) | Marques, Daniela C. (Federal University of Technology of Parana UTFPR) | Neto, Moisés A. Marcelino (Federal University of Technology of Parana UTFPR) | Teixeira, Adriana (Petrobras Research Center CENPES) | Valim, Leandro S. (Petrobras Research Center CENPES) | Morales, Rigoberto E. M. (Federal University of Technology of Parana UTFPR) | Sum, Amadeu K. (Colorado School of Mines)
The exploration fields under more severe conditions is accompanied by concerns about solid precipitation/deposition and hydrate formation. Transient operations, involving shut-in and restart is the most challenging scenario with risk for hydrate problem. The residence time of the production fluids associated to the rate of heat loss to the ambient seabed during the period of shut-in may increase the potential risk of hydrate blockage. This work is focused on understanding the hydrate formation, breakup, agglomeration and deposition, reproducing the shut-in and restart conditions in a lab-scale. Experiments were performed using a high pressure cell coupled to a rheometer using a custom-designed impeller and a rocking cell experiments with visual capabilities. A two-phase (water and gas) and three-phase (water, oil and gas) systems were used in the experiments. Also, the impact of the shear applied at restart on the hydrate morphology was evaluated. The viscoelastic behavior was observed in most shut-in and restart tests. Understanding the mechanism of hydrate formation and agglomeration during transient conditions may help to develop strategies to avoid hydrate plugging and allow the formation of a hydrate slurry yielding flowable conditions.
Qin, Hao (Colorado School of Mines) | Qu, Anqi (Colorado School of Mines) | Wang, Yan (Colorado School of Mines) | Zerpa, Luis (Colorado School of Mines) | Koh, Carolyn (Colorado School of Mines) | Bodnar, Scot (Multi-Chem Halliburton) | Daly, Sean (Multi-Chem Halliburton) | Palermo, Thierry (Total) | Mateen, Khalid (Total)
The formation of gas hydrates is considered a major flow assurance issue resulting from high pressure and low temperature conditions during petroleum production in deep water developments (
Traditionally, thermodynamic approaches are used to prevent the formation of hydrates in flowlines, including the injection of thermodynamic hydrate inhibitors (THIs), such as methanol or glycols. THIs work by shifting the hydrate phase equilibrium conditions to a lower temperature and higher pressure, which makes the condition unfavorable for hydrates to form (
Delgado-Linares, Jose G. (Colorado School of Mines) | Costa Salmin, Davi (Colorado School of Mines) | Stoner, Hannah (Colorado School of Mines) | Wu, David T. (Colorado School of Mines) | E. Zerpa, Luis (Colorado School of Mines) | A. Koh, Carolyn (Colorado School of Mines) | Mateen, Khalid (Total) | Bodnar, Scot (Multi-Chem, Halliburton) | Prince, Philippe (Multi-Chem, Halliburton) | Teixeira, Adriana (Petrobras)
Gas hydrate formation in oil and gas flowlines can represent a safety concern and a cause for hindered production, resulting in economic losses. Hydrate risk mitigation can be attained through hydrate avoidance or management strategies. Hydrate avoidance methods aim to keep the flowline outside of the hydrate stability region through, for example, the use of thermodynamic hydrate inhibitors. Thermodynamic hydrate inhibitors (THIs) increasingly shift the hydrate boundary towards higher pressures and lower temperatures as a function of THI concentration in solution. Hydrate management strategies allow the flowline to operate inside the hydrate stability zone, without the risk of forming a plug by using kinetic hydrate inhibitors or commercial hydrate anti-agglomerants. Some crude oils, denoted non-plugging crude oils, have naturally occurring surfactants (e.g., asphaltenes) that can behave as a hydrate anti-agglomerant and allow the formation of a transportable non-agglomerating hydrate slurry. Recent work has suggested that the asphaltene-aggregation state is a parameter that may dictate the natural hydrate anti-agglomeration behavior of non-plugging crude oils.
The ability of naturally occurring anti-agglomerants to prevent hydrate plugs is limited by the intrinsic amount found in the non-plugging oils and thus depends on the amount of hydrates formed in the flowline. Therefore, there is an opportunity to use thermodynamic hydrate under-inhibition (i.e., partial thermodynamic inhibition) in non-plugging crude oil systems that can no longer safely avoid a hydrate plug while relying on natural surfactants alone. If THI under-inhibition is used to partially reduce the amount of hydrates formed, the natural anti-agglomerants can prevent hydrate agglomeration of the remaining hydrates formed. The THI volume required for under-inhibition would be lower than that of complete THI inhibition, thereby reducing operational costs.
In this work, alcohols with different hydrocarbon chains and mono-ethylene glycol were shown to have a key impact on the asphaltene-aggregation state, inferred through size measurements of solvent-extracted asphaltene particles, correlating with changes in emulsion stability, and the non-plugging potential of a crude oil as assessed by rocking cell tests. The effect of alcohols on the asphaltene-particle size was also shown to be highly sensitive to the presence of a free-water phase, likely due to observed alcohol partitioning into the water phase. Alcohols with intermediate-hydrocarbon chains prevented asphaltene aggregation more effectively and reduced their emulsification tendency compared to alcohols with shorter carbon chain lengths. Furthermore, short-chain alcohols or MEG showed no antagonism when used with the non-plugging oil tested, resulting in a partially inhibited system able to avoid hydrate agglomeration at a higher water cut compared to a non-inhibited system. On the other hand, alcohols with intermediate-chain length were found to be detrimental to the non-plugging potential of the specific crude oil tested, potentially due to its effect of reducing the asphaltene-particle size in solution. More experimental work is required to better understand these phenomena and determine if other non-plugging crude oils show a similar behavior.
Zhu, Ziming (Colorado School of Mines) | Fang, Chao (Virginia Polytechnic Institute and State University) | Qiao, Rui (Virginia Polytechnic Institute and State University) | Yin, Xiaolong (Colorado School of Mines) | Ozkan, Erdal (Colorado School of Mines)
In nanoporous rocks, potential size/mobility exclusion and fluid–rock interactions in nanosized pores and pore throats can turn the rock into a semipermeable membrane, blocking or hindering the passage of certain molecules while allowing other molecules to pass freely. In this work, we conducted several experiments to investigate whether CO2 can mitigate the sieving effect on the hydrocarbon molecules flowing through Niobrara samples. Molecular dynamics (MD) simulations of adsorption equilibrium with and without CO2 were performed to help understand the trends observed in the experiments. The experimental procedure includes pumping liquid binary hydrocarbon mixtures (C10 and C17) of known compositions into Niobrara samples, collecting the effluents from the samples, and analyzing the compositions of the effluents. A specialized experimental setup that uses an in-line filter as a minicore holder was built for this investigation. Niobrara samples were cored and machined into 0.5-in. diameter and 0.7-in. length minicores. Hydrocarbon mixtures were injected into the minicores, and effluents were collected periodically and analyzed using gas chromatography (GC). After observing the sieving effect of the minicores, CO2 huff ‘n’ puff was performed at 600 psi, a pressure much lower than the miscibility pressure. CO2 was injected from the production side to soak the sample for a period, then the flow of the mixture was resumed, and effluents were analyzed using GC. Experimental results show that CO2 huff ‘n’ puff in several experiments noticeably mitigated the sieving of heavier components (C17). The observed increase in the fraction of C17 in the produced fluid can be either temporary or lasting. In most experiments, temporary increases in flow rates were also observed. MD simulation results suggest that for a calcite surface in equilibrium with a binary mixture of C10 and C17, more C17 molecules adsorb on the carbonate surface than the C10 molecules. Once CO2 molecules are added to the system, CO2 displaces C10 and C17 from calcite. Thus, the experimentally observed increase in the fraction of C17 can be attributed to the release of adsorbed C17. This study suggests that surface effects play a significant role in affecting flows and compositions of fluids in tight formations. In unconventional oil reservoirs, observed enhanced recovery from CO2 huff ‘n’ puff could be partly attributed to surface effects in addition to the recognized thermodynamic interaction mechanisms.
Srivastava, Vishal (Colorado School of Mines) | Majid, Ahmad A. A. (Colorado School of Mines) | Warrier, Pramod (Colorado School of Mines) | Grasso, Giovanny (Colorado School of Mines) | Koh, Carolyn A. (Colorado School of Mines) | Zerpa, Luis E. (Colorado School of Mines)
Summary Gas hydrates are considered a major flow-assurance challenge in subsea flowlines. During transient operations [shut-in and restart (RS)], risk of blockage formation owing to hydrates can be greater compared to that during the continuous operations. In particular, hydrate formation during an unplanned shut-in and subsequent restart could lead to increased operational hazards. In this work, flow-loop tests were conducted under both continuous-pumping (CP) and RS conditions, using Conroe crude oil with three different water fractions (30, 50, 90 vol%) at 5 wt% salinity, over a range of mixture velocities (from 2.4 to 9.4 ft/sec). It was determined that RS operations resulted in an earlier onset of hydrate particle bedding--twice as fast as those in CP tests--from the interpretation of pressure-drop and mass-flow-rate (MFR) measurements. Droplet imaging using a particle vision and measurement (PVM) probe suggested larger water droplets (100-300 mm) during the shut-in, as compared to the CP tests (40 mm) at 50 and 90 vol% water cuts (WCs). For the tests performed using a demulsifier at 200 ppm, PVM images suggested larger water droplets (mean droplet size ¼ 94 mm), as compared with the test with no demulsifier (mean droplet size ¼ 21 mm). The test using a demulsifier resulted in higher pressure drops and lower MFRs compared with the test with no demulsifier, indicating poor hydrate transportability when water was partially dispersed in the oil phase. The current study indicated that partially dispersed systems present greater risks of hydrate plugging as compared with the fully dispersed systems in the range of water volume fractions from 50 to 95 vol% WC, which was the phase inversion point of the water-in-crude-oil (Conroe14 crude) system. The flow-loop-test analyses presented in this work can potentially aid in an improved mechanistic understanding of RS operations, involving unplanned shut-ins and restarts.
Joshi, Deep (Colorado School of Mines) | Eustes, Alfred (Colorado School of Mines) | Rostami, Jamal (Colorado School of Mines) | Hanson, Jenna (Colorado School of Mines) | Dreyer, Christopher (Colorado School of Mines)
This paper discusses the evolution of a pattern recognition algorithm that utilizes the high-frequency drilling data to characterize the water-ice on the Moon. The algorithm developed here can estimate the moisture content of a grout sample by analyzing the trend of drilling data. Such an algorithm can be used by NASA and private organizations in near-future to identify and produce water from Lunar Poles.
An auger based rotary drilling rig with a drilling data acquisition system was designed and fabricated. The data acquisition system records drilling parameters like RPM, drilling depth, torque, and weight on bit at 1000Hz. The data is then filtered to remove electromagnetic interference. The drilling tests were conducted on meticulously designed grout block samples which contained the lunar soil simulant with specific geotechnical properties, replicating lunar subsurface at a specific pressure, temperature condition, and moisture contents. Simultaneously, the UCS of the grout block was tested in a lab to correlate the drilling data to specific grout strength.
The drilling data recorded in the homogenous samples and the data collected during UCS tests were used to develop and validate a pattern recognition algorithm. The algorithm was tested on layered grout samples containing layers with varying strength. The UCS estimated by this algorithm was then correlated to the moisture content using the lab observations and published literature. The algorithm could distinctly detect the boundaries between different layers, estimate the UCS, and moisture content in real-time. The high-frequency drilling data was also used to identify different dysfunctions and optimize drilling operations. Trends of MSE, RPM, and torque were analyzed to detect auger choking, inefficient cuttings transport, and drilling vibrations.
On the Moon, this algorithm can be invaluable in optimizing the drilling operations, estimating the spatial distribution of various subsurface layers improving our understanding of the subsurface lunar stratigraphy. It can also be used to estimate the quantity of water available on the lunar poles, which will be essential in planning the manned and robotic lunar missions in the coming years.
Hydrochloric acid (HCl) is the acid of choice for acidizing operations in most carbonate formations and is the base acid commonly paired with others such as hydrofluoric (HF) in most sandstone applications. However, high dissolving power, high corrosion rate, lack of penetration, and sludging tendency coupled with high temperature can make HCl a poor choice. Alternatively, weaker and less corrosive chemicals such as organic acids can be used instead of HCl to avoid these issues. The objective of this paper is to provide an intensive review on recent advancements, technology, and problems associated with organic acids. The paper focuses on formic, acetic, citric, and lactic acids.
This review includes various laboratory evaluation tests and field cases which outline the usage of organic acids for formation damage removal and dissolution. Rotating disk apparatus results were reviewed to determine the kinetics for acid dissolution of different minerals. Additional results were collected from solubility, corrosion, core-flooding, Inductively Coupled Plasma (ICP), X-Ray Diffraction (XRD), and Scanning Electron Microscope Diffraction (SEM) tests.
Due to their retardation performance, organic acids have been used along with mineral acids or as a stand-alone solution for high-temperature applications. However, the main drawback of these acids is the solubility of reaction product salts. In terms of conducting dominant wormhole tests and low corrosion rating, organic acids with low concentrations show good results. Organic acids have also been utilized in other applications. For instance, formic acid is used as an intensifier to reduce the corrosion rate due to HCl in high-temperature operations. Acetic and lactic acids can be used to dissolve drilling mud filter cakes. Citric acid is commonly used as an iron sequestering agent.
This paper shows organic acid advances, limitations, and applications in oil and gas operations, specifically, in acidizing jobs. The paper differentiates and closes the gap between various organic acid applications along with providing researchers an intensive guide for present and future research.
Organic acids are commonly used to replace hydrochloric acid (HCl) in high reservoir temperature applications, as they are less corrosive and weaker than HCl. However, organic acids have shown some problems due to acid reaction product solubility. One such organic acid, lactic acid, produces calcium lactate when it reacts with calcite, which has a low solubility in water. However, reaction product solubility can be improved by up to five times when gluconate ions coexist with lactate and calcium ions. The objective of this research is to evaluate lactic and gluconic acid mixtures in term of dissolving calcite, reaction product, corrosion, wettability and generating dominant wormhole.
Lactic and gluconic acids were mixed together using deionized water and seawater to conduct calcite solubility tests. Corrosion tests, between 4 and 8 hours, were also run under reservoir conditions. Zeta potential measurements were performed to determine alterations in rock wettability. A formation response test (FRT) apparatus was used to run different coreflood tests using different combinations of injection rates and temperatures. These tests were accompanied with analytical results from ICP and IC to measure calcium, iron and sulfate ions in solution.
The results showed that mixing lactic and gluconic acids at a 1:1 molar ratio provided the optimal results as no precipitation occurred at total acids strengths of 10 wt% and up to 27 wt%. Seawater usage caused calcium sulfate precipitation; therefore, three scale inhibitors were evaluated to determine mitigation rates. Acid calcite-dissolving results were satisfactory when limestone was exposed to a 1:1 and 2:1 molar ratio of crushed core-to-acid ratios as at least 50% of the crushed core was dissolved. However, the two-acid mixture showed a corrosion rate that was higher than the acceptable rates and a trace of iron lactate precipitation occurred at 200 and 300°F. Five gpt from a sulfur-based corrosion inhibitor was enough to mitigate the corrosion rate to allow for eight hours of testing. Wettability alteration was noticeable due to the spent acid interaction with limestone rock and was the highest when high salinity seawater was used. Yet, the addition of corrosion inhibitor showed a reduction in the magnitude of zeta potential change. Coreflood tests showed that the mixture penetrated the tested core with minimal acid pore volume without any face dissolution or salt precipitation on the core faces.
This research presents a set of diverse experimental data to confirm lactic acid accompanied by gluconic acid can penetrate carbonate formation without any by-product precipitation. The two organic acids are less corrosive and less hazardous which can provide a safe operation environment and can decrease replacement and maintenance costs.
Petroleum wells producing water are likely to develop deposits of inorganic scales that may form near the wellbore and may plug perforations, coat casing, production tubulars, valves, deteriorate pump performance, and affect downhole completion equipment. Scales form and precipitate because the solution equilibrium of water is disturbed by pressure and temperature changes, dissolved gases or incompatibility between mixing waters. If scale formation and precipitation are allowed to proceed, scaling will limit production, eventually requiring abandonment of the well. In order to remove the effects of scale on production after a well undergoes sharp or early decline in production, it is essential to first determine which scales are forming and where they are forming. Some of this information can be reliably inferred from computer simulation procedures or by running calipers down the wellbore and measure decreases in the tubing inner diameter so that the scale can be physically detected. Gamma ray log interpretation may also be used to detect barium sulfate scale because naturally radioactive radium precipitates as an insoluble sulfate with this scale. Scale remediation techniques must be quick and nondamaging to the wellbore, tubing, and the reservoir. If the scale is in the wellbore, it can be removed mechanically or dissolved chemically. Selecting the best scale-removal technique for a particular well depends on knowing the type and quantity of scale, its physical composition, and its texture. Mechanical methods such as Dynamic Underbalance Pressure (DUP) technique are among the promising methods of scale removal in tubulars and across perforations. The purpose of this work is to present a case study of removing barium sulfate (BaSO4) scales from perforation tunnels utilizing dynamic underbalance technique. Wells from a North African oil field were selected for designed and optimized dynamic underbalance treatments to remove barium sulfate scales that precipitated in the perforation tunnels, preventing hydrocarbons flow from the formation to the production tubing. Gamma ray log and production logging tool were used before the treatment to detect and evaluate the type of scale and the intervals affected. Then the same tools were used after the treatment to assess stimulation taking place in the wells. Data obtained from the treatment was used to develop a model for predicting productivity index/inflow performance relationships. The dynamic underbalance technique successfully removed scale from all targeted wells, leading to an increase in oil production, without killing them (i.e. while still in production). Some wells achieved increase in oil production after the treatment of up to 65%. A predictive model was developed in order to estimate the performance of an underbalance scale removal treatment.
Liu, Lijun (China University of Petroleum (East China)) | Huang, Zhaoqin (China University of Petroleum (East China)) | Yao, Jun (China University of Petroleum (East China)) | Di, Yuan (Peking University) | Wu, Yu-Shu (Colorado School of Mines)
Fractured vuggy reservoir is a typical type of carbonate reservoir. The 3D complex fracture networks and Stokes flow inside vugs make fractured vuggy reservoir simulation remain a challenging problem. Most of the proposed models in previous studies are computation consuming, which cannot meet with the demand of field application. In this paper, a novel and efficient hybrid model, consisting of a modified embedded discrete fracture model (EDFM) and a vug model, is proposed to simulate multiphase flow in 3D complex fractured vuggy reservoirs. The modified EDFM improves the fracture-discretization process by using two sets of independent grids for matrix and fracture systems, which promotes the modeling of 3D complex fractures in real geological structures. Meanwhile, the vug model simplifies the coupled porous-free flow with the assumption of multiphase instantaneous gravity differentiation. The accuracy of the modified EDFM and the vug model is demonstrated by comparing the results with those of the conventional EDFM and volume of fluid (VOF) method. After that, a series of case studies, including three conceptual fracture-vug unit models and a real field model, have been conducted to test the proposed hybrid model. The results of the three fracture-vug unit models indicate the significant effect of a local fracture-vug structure on the flow characteristics and production performance. Finally, the application with a real field model with 3D complex fracture and vug geometries further verifies the practicability of our proposed model in real fractured vuggy reservoirs.