Selecting the appropriate tracer, and understanding the information gathered during a well to well tracer test requires consideration of how various tracers interact with, and therefore flow, through reservoir rock. When tracers are flowing in the reservoirs, it is normally a requirement that the compounds follow the phase they are going to trace. The best example of a passive water tracer is tritiated water (HTO). The HTO will, in all practical aspects, follow the water phase. For gas tracers, there are no known passive tracers.
Capillary desaturation experiments are combined with high-resolution microtomography imaging to understand the impact of wettability on the global and local distribution of fluids in the pore space of sandstone outcrops. Small cylindrical rock samples are cored, imaged in dry state then successively prepared at irreducible water saturation before steps of waterflood. Several samples also go through a wettability-alteration phase in order to expand the range of wettability conditions: namely, oil-wet to mixed-wet. Waterflooding is done at various capillary numbers and injected brine volumes, depending on the case. The entire rock is imaged at voxel resolutions of typically 2 or 4 µm, to ensure a high-quality segmentation.
Global oil saturation results show how the wettability impacts the shape of capillary desaturation curves, in particular, the existence of a critical capillary number. In the nonwater-wet experiments, oil saturation is controlled by a large, highly-connected oil cluster percolating from the inlet to the outlet of the sample. Such results are important for pore-scale flow modeling strategy and validation. We demonstrate that the wettability is not always uniformly distributed along the core despite of the use of classical wettability-alteration protocols, highlighting potential biases in traditional SCAL tests.
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)
Gas hydrates are considered a major flow-assurance challenge in subsea flowlines. They agglomerate rapidly and form hydrate blockages. 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 µm) during the shut-in, as compared to the CP tests (=40 µm) 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 = 94 µm), as compared with the test with no demulsifier (mean droplet size = 21 µm). 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.
Formation of scales in near-wellbore reservoir/downhole and production systems can lead to production loss, system integrity and reliability degradation, and fouling of device and equipment. The mitigation and remediation of oilfield depositions can be difficult and costly. Better understanding of the key factors impacting scale dissolution, such as temperature and pH will benefit scale mitigation practices. Most of the research and investigation of silicate dissolution for example are based on low temperature experiences (e.g., <100 °C). Strong acids such as concentrated HCl, HF and aqua regia may not be applicable for field application.
In this study, field depositions with various scale types such as silicates, carbonate, sulfides are characterized and used for studying effects of pH, temperature and solvent on their dissolution. Experiments with oilfield scale deposit samples including silicates were conducted with high temperature thermal aging cells at temperature range >100 °C and pH from 6 – 8. Dissolution test with field scale samples were also conducted under ambient conditions. Various solvents including xylene, HCl and acetic acid were used in the test.
To summarize the results, decreasing temperature has limited effect on dissolution of magnesium silicates, but improves dissolution of calcite and anhydrite which coexist with the field sample. Decreasing pH improves the dissolution of magnesium silicate and calcite. Total amount of dissolved silicates can increase significantly due to appropriate pH decrease. Solution pH is increased dramatically due to the formation of hydroxyl ions during the dissolution process. The reaction for dissolution of metal silicate scale is proposed based on observation and results in the study. More fine particles are produced after dissolution and suspended in solution for at least 15 minutes, which makes solid mitigation possible by applying proper agitation. Oilfield deposits can include a variety of components, and appropriate scale sample characterization should be utilized for selection of mitigation/remediation approaches.
This paper provides novel information of oilfield scale dissolution (including silicate scale) at high temperature by using field applicable treatment approaches. Results lead to better understanding of silicate dissolution at various pHs and temperatures, and required conditions for successful mitigation and remediation of oilfield scale deposits
Zou, Jiandong (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Liao, Xinwei (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Zhao, Xiaoliang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Chen, Zhiming (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Mu, Lingyu (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Chu, Hongyang (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Wu, Jiaqi (State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum) | Zhang, Zhen (North District Exploration Department of Oil and Gas Exploration Company, Shaanxi Yanchang Petroleum Group Co., Ltd.)
Carbonated water injection (CWI) is a modified CO2 flooding method for enhanced oil recovery, which takes the both advantages of CO2 flooding and water injection and have attracted much attention recently. The objective of this study is to mimic the dynamic mass transfer process of carbonated water to "live" crude oil through a series of well-designed multi-contact tests.
In each test, carbonated water (CW) was brought into contact with live crude oil in a high-temperature and high-pressure PVT cell. Pressure changes during the test were observed and recorded. After equilibrium, all of the transferred carbonated water was taken out of the cell and the swelled oil was proceed to the next contact. The volume of water and liberated gas were measured. The oil swelling factor was also measured, which would verify the existence of moving interface between carbonated water and live crude oil. A total of 12 contact tests were performed.
It was observed that the pressure rapidly builds up immediately after the contact of carbonated water and live crude oil in the closed system. For the first contact, equilibrium pressure increased by 6.46MPa and for the last contact equilibrium pressure increased by 2.16Mpa. This result indicates a strong mutual interaction of carbonated water with live crude oil and be beneficial to maintain reservoir pressure. Due to large amount of CO2 transferred from carbonated water to the live crude oil, the swelling effect was quite obvious and a total swelling factor of 1.26 was obtained at the end of the experiments. The volume changes of carbonated water and live crude oil could be good evidence of the existence of moving interfaces during the dynamic mass transfer process. The other enhanced oil recovery mechanism by CWI such as viscosity reduction was also found in the tests.
The experimental results clearly indicate that the pressure buildup during the diffusion process originated from the CO2 dissolution from carbonated water and swelling of the oil phase. The partition coefficient is relevant to CO2 solubility in water and live crude oil. The tests vividly replicated the dynamic interactions between live crude oil in a closed system and the flowing carbonated water, in which the oil would be contacted by fresh carbonated water.
In this study, we use a custom-designed visual cell to investigate nonequilibrium carbon dioxide (CO2)/oil interactions under high-pressure/high-temperature conditions. We visualize the CO2/oil interface and measure the visual-cell pressure over time. We perform five sets of visualization tests. The first three tests aim at investigating interactions of gaseous (g), liquid (l), and supercritical (sc) CO2 with a Montney (MTN) oil sample. In the fourth test, to visualize the interactions in the bulk oil phase, we replace the opaque MTN oil with a translucent Duvernay (DUV) light oil (LO). Finally, we conduct an N2(sc)/oil test to compare the results with those of CO2(sc)/oil test. We also compare the results of nonequilibrium CO2/oil interactions with those obtained from conventional pressure/volume/temperature (PVT) tests.
Results of the first three tests show that oil immediately expands upon injection of CO2 into the visual cell. CO2(sc) leads to the maximum oil expansion followed by CO2(l) and CO2(g). Furthermore, the rate of oil expansion in the CO2(sc)/oil test is higher than that in CO2(l)/oil and CO2(g)/oil tests. We also observe extracting and condensing flows at the CO2(l)/oil and CO2(sc)/oil interfaces. Moreover, we observe density-driven fingers inside the LO phase because of the local increase in the density of LO. The results of PVT tests show that the density of the CO2/oil mixture is higher than that of the CO2-free oil, explaining the density-driven natural convection during CO2(sc) injection into the visual cell. We do not observe either extracting/condensing flows or density-driven mixing for the N2(sc)/oil test, explaining the low expansion of oil in this test. The results suggest that the combination of density-driven natural convection and extracting/condensing flows enhances CO2(sc) dissolution into the oil phase, leading to fast oil expansion after CO2(sc) injection into the visual cell.
The quest for smart and cost-effective demulsification materials to separate water-in-crude oil (W/O) emulsions is highly desired in the petroleum industry. In this paper, an assessment study was conducted on the potency of coal fly ash (CFA) as a demulsifier for W/O emulsions. To our knowledge, this is the first study reporting CFA as a demulsifier for highly stable W/O emulsions. W/O emulsion samples were prepared without using any conventional emulsifier. Asphaltenes in the crude oil acted as an emulsifier and stable emulsions were produced. Six W/O emulsion samples of the same crude oil to water volume ratio (4:6) were formulated. A reference sample was selected for comparison during demulsification. Demulsification tests were performed at room temperature (25 °C). Demulsification results obtained via the bottle tests showed that the reference sample (blank) without CFA remained stable without water separation after 48 hrs while the addition of various CFA quantities (1 % to 7 %) brought about separation of water from the oil phase. Separation of water was observed to have increased with increasing CFA addition in the emulsion. Water separation continued for each sample until around 24 hrs when equilibrium was attained, and water separation remained constant. The W/O emulsion containing 7 % CFA displayed the highest performance with demulsification efficiency (DE) of 96.67%. Demulsification comparison test results between CFA and a commercial demulsifier (poloxamer – 407) using same concentration and under room temperature showed that CFA was capable of separating water better than this commercial demulsifier. This observation indicates that CFA can compete favorably with many commercial demulsifiers available in the market. Additionally, the outcome of demulsification efficiency of 7% CFA at elevated temperatures (i.e., 60 °C and 80 °C) was around 98%. More importantly, the separated water at these elevated temperatures was clearer and contained lesser oil floccules than the separated water phase observed during demulsification tests conducted at room temperature (25 °C) condition. Shear rheology measurement reveals that CFA addition altered the viscoelastic characteristics at the crude oil/water interface at an aging time of 10 hrs and 55 mins. Viscous modulus remained stagnant while elastic modulus dropped significantly. Optical morphology revealed the phase transformation in the as-prepared W/O emulsion before and after the addition of CFA particles. The possible mechanism governing the demulsification of W/O emulsion driven by CFA particles was proposed. It is believed that this work will be relevant to petroleum exploration and refining operations.
Favorable interactions between injection gas and crude oil are crucial for successful carbon dioxide (CO2) recovery processes. The miscibility behavior and thereby the flooding scheme changes with the pressure applied. Although first contact miscibility (FCM) flooding schemes result in most efficient recovery processes, in many cases multiple contact miscibility (MCM) provides economically viable recovery rates already at lower injection pressure. Thus, the determination of the miscibility pressure is a key step in the lab evaluation for CO2 EOR. Miscibility enhancing additives are able to improve the interactions between CO2 and crude oil leading to reduced miscibility pressure.
This paper illustrates an easily applicable procedure to identify the pressure required for full miscibility. Using a pressure resistant sapphire cell the phase behavior of mixtures of different crude oils and CO2 with and without additives was investigated at common reservoir conditions. The effect of the additives on the physical phase behavior of CO2/crude oil mixtures and the benefit that can be achieved by their application will be discussed.
The miscibility gaps are determined by measuring the phase behavior of CO2/additive/crude oil mixtures as a function of pressure and temperature. The pressure required for full miscibility (physical minimum miscibility pressure (MMPP)), coming along with an FCM scheme, can easily be detected as the pressure above which the miscibility gap closes and a homogeneous mixture is obtained. Another important point, which was determined in this study, was the critical point of the miscibility gap. Its corresponding pressure is the maximum value of the minimum miscibility pressure (MMP) from a thermodynamical viewpoint, above which MCM schemes take place. Hence, knowledge of the critical point of the mixture is an easy to use method to estimate the maximum value of the MMP for a specific reservoir. Adding proper additives to the CO2 improves the miscibility of injection gas and crude oil. By this the miscibility gap shrinks and both the MMP and the MMPP will be reduced significantly compared to the pure CO2/crude oil system.
The method presented is a proper, quick, and low-cost alternative to the time-consuming and expensive slim tube experiments commonly used in the oil industry to measure the MMP. Since at pressures above the MMP an MCM procedure is ensured by physics it is the lowest injection pressure that needs to be applied to ensure miscible CO2 EOR. Reducing the MMP and the MMPP using proper additives can lead to a more economical CO2 flood or can even make reservoirs accessible for this technology, which are naturally not.
High nanogel concentrations were injected for a couple of hours because there were several injection downtimes in the injection. The well never recovered the initial injectivity, even after the acid job, which may indicate that the damage was not easily removed. The investigators suspected that the product did not meet specifications. Even though the nanogel was designed to be compatible with the water salinity of Barrancas field, the water quality was not properly defined as the TSS (total suspended solids) and the total oil content.
To form a certain degree of injection resistance in the existing high-permeability water channels, to create a more-homogeneous reservoir To displace the oil in the relatively low-permeability (oil-containing) regions by enlarging sweep area To increase oil production and decrease water cut for the long term.