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Even with a properly designed single well chemical tracer (SWCT) test, interpreting the data requires judgment calls, and typically, simulation, to arrive at a final estimation of residual oil. Tomich et al. report one of the earliest SWCT tests, which was performed on a Frio Sandstone reservoir on the Texas Gulf Coast. The results of this test are used here to demonstrate the details of SWCT test interpretation for an ideal situation. The test well in the Tomich et al. report was in a fault block that had been depleted for several years. Because of the natural water drive and high permeability of the sand, the formation was believed to be near true Sor.
Summary Seawater injection is widely used to maintain offshore-oil-reservoir pressure and improve oil recovery. However, injecting seawater into reservoirs can cause many issues, such as reservoir souring and scaling, which are strongly related to the seawater-breakthrough percentage. Accurately calculating the seawater-breakthrough percentage is important for estimating the severity of those problems and further developing effective strategies to mitigate those issues. The validation of using natural-ion boron as a tracer to calculate seawater-breakthrough percentage was investigated. Boron can interact with clays, which can influence the accuracy in seawater-breakthrough calculation. Therefore, the interaction between boron and different clays at various conditions was first studied, and the Freundlich adsorption equation was used to describe the boron-adsorption isotherms. Then, the boron-adsorption isotherms were coupled into the reservoir simulator to investigate the boron transport in porous media, and the results in turn were further analyzed to calculate the accurate seawater-breakthrough percentage. Results indicated that boron adsorption by different clays varied. pH value of solution can significantly influence the amount of boron adsorbed. As a result, the boron-concentration profile was delayed in coreflood tests. The accuracy of the new model was verified by convergence rate tests and comparison with analytical results. Furthermore, model results fit well with experimental data. On the basis of the reservoir-simulation results, the boron-concentration profile in produced water can be used to calculate the seawater-breakthrough percentage by considering the clay-content distribution. However, the seawater-breakthrough point cannot be determined by boron because the boron concentration is still at the formation level after seawater breakthrough due to boron desorption.
Gopani, Paras Himmat (University of Calgary) | Singh, Navpreet (University of Calgary) | Sarma, Hemanta Kumar (University of Calgary) | Negi, Digambar S. (Oil and Natural Gas Corporation Limited) | Mattey, Padmaja S. (Oil and Natural Gas Corporation Limited)
Abstract As carbonate reservoirs are mostly oil-wet, the potential for the success of a waterflooding is lower. Therefore, a primary focus during waterflooding such reservoirs is on the ionic composition and salinity of injected brine which are able to impact the alteration of the rock wettability favorably by altering the surface charge towards a higher negative value or close to zero. The objective of this study is to employ zeta potentiometric studies comprising streaming potential and streaming current techniques to quantify the surface interactions and charges between the carbonate rock and fluid type as a function of the variations in its ionic state and rock saturation. Zeta potentiometric studies were conducted on carbonate rock samples to understand the behavior of different aqueous solutions by variation in the brine's salinity and ionic composition and the results were integrated with wettability studies. The concentrations of potential-determining ions (PDIs) such as SO4, Mg and Ca in the injected brines are deemed responsible for altering the wettability state of the carbonate rocks. Several diluted brines (25%, 10% and 1% diluted seawater) and smart brines have been investigated. Smart brines were prepared by spiking the concentration of major PDIs. All zeta potential measurements were conducted using a specially designed zeta potentiometer sample-holding clamp capable of using the whole core plugs rather than pulverized rock samples. A major advantage of using the whole core sample is that the same core can be used in subsequent coreflooding tests, thus making zeta potentiometric results more relevant and representative for a particular rock-fluid system used in the study. The classical streaming potential and streaming current techniques were used for zeta potential measurement. The Fairbrother-Mastin approach was used where the streaming potential is measured against different pressure differentials. Measurements were also carried out for brines with rock samples of different states: oil-saturated, water-saturated and rock samples cleaned with organic solvents to determine any likely variations in surface charge interactions. The results of our experiments imply that the value of zeta potential either increases or becomes more negative with increasing percentage of dilution (25%, 10%, and 1%). This can be attributed to electrical double-layer expansion which is primarily caused by reduced ionic strength. Furthermore, with measurements done on smart brines, zeta potential value was also found to be increased when different diluted brines are spiked with ionic concentration of PDIs such as sulfate. This could have been caused by surface ion alteration mechanism where PDIs get adsorbed on rock surface causing possible detachment of oil droplets. Both the phenomena are known mechanisms for altering wettability towards more water wetness in carbonate rocks and are discussed in detail.
Abstract Foams are the divergent fluids that are employed in the upstream oil and gas industry to reduce fluid channeling and fingering in the high permeability region. Foams are usually generated in the high permeability reservoirs (e.g. glass beads) by the alternative injection of surfactant and gas. Conventional foaming systems exhibit stability issues at the high temperature and high salinity reservoir conditions. In this investigation, we study the stability and efficiency (in terms of both enhanced inflow performance and added oil recovery) of foams formed using surfactant solution with and without carbon Nanodots (CND). The study involved using different brine salinities, CND concentrations, temperature and pressure conditions, and types of surfactants. A multifaceted interrelationship of the various influencing mechanisms is demonstrated. Foams are examined using foam analyzer, HP/HT coreflood and microfluidic setup. In trace amounts (5-10 ppm), CND contributed to 60-70% improvement in foam stability in high salinity brine. The improvement is attributed by the reduction of the drainage rate of the lamellae and a delay of the bubble rupturing point. Both microfluidic and core-flood experiments showed noticeable improvement in mobility control with the addition of the CND. This is contributed to an improved foamability, morphology, strength, and stability of the foam.
Levels of the two most important anthropogenic greenhouse gases, carbon dioxide and methane, continued their unrelenting rise in 2020 despite the economic slowdown caused by the coronavirus pandemic response, NOAA announced. The global surface average for carbon dioxide (CO2), calculated from measurements collected at NOAA's remote sampling locations, was 412.5 parts per million (ppm) in 2020, rising by 2.6 ppm during the year. The global rate of increase was the fifth highest in NOAA's 63-year record, following 1987, 1998, 2015, and 2016. The annual mean at NOAA's Mauna Loa Observatory in Hawaii was 414.4 ppm during 2020. The atmospheric burden of CO2 is now comparable to where it was during the Mid-Pliocene Warm Period around 3.6 million years ago, when concentrations of carbon dioxide ranged from about 380 to 450 parts per million.
A property of water that causes formation of an insoluble residue when the water is used with soap and a scale in vessels which water has been allowed to evaporate. It is primarily due to the presence of ions of calcium and magnesium, but also to ions of other alkali metals, other metals (such as iron), and even hydrogen. Hardness of water is generally expressed as ppm of CaC03 (40 ppm Ca produces a hardness of 100 ppm as CaC03), also as mg/L, and as the combination of carbonate hardness and noncarbonate hardness.
Gupta, M K (Oil and Natural Gas Corporation India Limited) | Singh, V K (Oil and Natural Gas Corporation India Limited) | Sharma, MSK (Oil and Natural Gas Corporation India Limited) | Katre, N V (Oil and Natural Gas Corporation India Limited) | Boddu, V (Oil and Natural Gas Corporation India Limited) | Nath, Siddharth Priya (Oil and Natural Gas Corporation India Limited) | Reddy, Rajesh (Oil and Natural Gas Corporation India Limited) | Raman, Ravi (Oil and Natural Gas Corporation India Limited)
Abstract In a producing field of western offshore, H2S content in oil was found to be in the range of 3000-5000 ppm against the desired level of 200ppm. High H2S concentration posed a serious threat to pipelines integrity and downstream equipment. Mitigation by conventional means such as chemical injection is generally avoided at offshore due to constraint like continuous pumping, storage of chemicals, frequent monitoring, logistical impediments and disposing off by-products in compliance with statutory requirements. Considering many limitations at offshore, an approach was adopted for reduction of H2S utilizing Henry's principle which states that the amount of dissolved gas in a liquid is proportional to its partial pressure. Reducing the partial pressure by utilizing sweet natural gas or some other inert gas, H2S can be removed. Same principle was applied to conceptualize a processing system wherein sour crude can be sweetened to the desired level utilizing sweet gas as stripping gas. Processing System was designed considering many downstream and upstream constraints in the existing system and without any rotating and heating requirement. Unlike conventional way of sweetening such as chemical injection which requires continuous dosing of chemical and disposing off by-products in compliance with statutory requirements and hence, found not feasible at offshore to sweet enormous amount of crude. The designed processing system, a first in Indian offshore environment, is commissioned at one of the offshore complex and has proved it efficacy wherein H2S content of around 3000 ppm in around 6000 barrel/day of crude is being reduced to less than 10 ppm level without use of any hazardous chemicals and without any need of rotating and heating equipment's and with minimum maintenance and manual intervention requirement. The system has lowest operating cost, low maintenance and without use of any rotating and heating equipment's and hence can be emerged as an ideal solution for crude oil sweetening at offshore environment or in an environment where bare manual intervention is required.
Al Kalbani, Mandhr (Heriot–Watt University) | Al Shabibi, Hatem (Heriot–Watt University) | Ishkov, Oleg (Heriot–Watt University) | Silva, Duarte (Heriot–Watt University) | Mackay, Eric (Heriot–Watt University) | Baraka-Lokmane, Salima (Total) | Pedenaud, Pierre (Total)
Summary Injection of low-sulfate seawater (LSSW) instead of untreated full-sulfate seawater (FSSW) is widely used to mitigate barium sulfate scaling risk at the production wells. LSSW injection may no longer be required when the barium concentrations in the produced water drop below a certain threshold. Such a trigger value could be estimated from the barium sulfate precipitation tendency. Relaxation of requirements for the sulfate reduction plant (SRP) can significantly reduce operational costs. This study investigates the impact of several parameters on the timing and degree of relaxation of the output sulfate concentration by the SRP. Finally, the optimal switching strategy is proposed for a field case. The strategy for switching from LSSW to FSSW (e.g., time and method; direct or gradual increase in the sulfate concentration) was initially investigated using generic 2D areal and vertical models. The sensitivity study included the impact of reservoir heterogeneity and the initial barium and sulfate ion concentrations. Findings were later applied on a full-field reservoir simulation model followed by a mineral scale prediction software to investigate the specific switching strategy for a field that has multiple wells and significantly more complex heterogeneity. The results show that barium concentrations in the formation brine affect the choice of switching time more than the output sulfate concentration produced by the SRP. The degree of heterogeneity around the producers also has a significant impact on the switching time. Another parameter is the contrast in the permeability between layers; higher contrast allows a longer period of coproduction of the scaling ions and thus delays the switching time. In the field case, switching to FSSW at early times allows higher consumption of barium ions because of its in-situ precipitation. Barium is no longer a limiting ion, and so a higher degree of deep reservoir precipitation reduces the requirement for prolonged LSSW injection. Another strategy is a gradual relaxation of LSSW output, which allows even earlier buildup of the injected sulfate concentration compared with the direct FSSW switch. The study investigates the reservoir parameters that affect sulfate relaxation of LSSW injection for a field. After the proposed workflow, the optimal relaxation strategy can be designed for other field cases.