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In formations where the pore space is occupied by a stationary gas phase and a mobile water phase, such as in a watered-out gas reservoir, the residual gas saturation (Sgr) may need to be measured in situ. The Sgr also can be determined using a single-well injection/production test method. Sgr measurement involves injecting and immediately producing a suitable volume of water. The water used for injection typically is produced from the target well before the test and stored in tanks on the surface. During production, the amount of gas dissolved in the water (Rsw) that is produced from the formation is measured.
The single-well chemical tracer (SWCT) test is an in-situ method for measuring fluid saturations in reservoirs. Most often, residual oil saturation is measured; less frequently, connate water saturation (Swc) is the objective. Either saturation is measured where one phase effectively is stationary in the pore space (i.e., is at residual saturation) and the other phase can flow to the wellbore. Recently, the SWCT method has been extended to measure oil/water fractional flow at measured fluid saturations in situations in which both oil and water phases are mobile. The SWCT test is used primarily to quantify the target oil saturation before initiating improved oil recovery (IOR) operations, to measure the effectiveness of IOR agents in a single well pilot and to assess a field for bypassed oil targets.
Interwell tracer tests are widely used. This article reviews some of the studies reported in open literature. The selection introduces different problems that have been addressed, but the original papers should be studied to obtain a more detailed description of the programs. The Snorre field is a giant oil reservoir (sandstone) in the Norwegian sector of the North Sea. Injection water and gas were monitored with tracers, 18 and the resulting tracer measurements are discussed in this page.
The single-well chemical tracer (SWCT) test is an in-situ method for measuring fluid saturations in reservoirs. The most common use is the assessment of residual oil saturation (Sor) prior to improved oil recovery (IOR) operations (post-waterflooding). The SWCT test for Sor uses only one well and involves the injection and back production of water carrying chemical tracers. A typical target interval for SWCT testing is shown in Figure 1. The candidate well should be completed only to the watered-out zone of interest (zone at Sor).
Figure 1.1b – Reservoir evaluation by material balance with measured Sor. A reliable in-situ measurement of Sor simultaneously defines the target for enhanced oil recovery (EOR) and allows estimation of the potential bypassed (mobile) oil in the field. This moveable oil is the target for infill drilling and/or flood sweep efficiency improvements. Because Sor varies greatly with formation type, oil/water properties, and other variables that are not completely understood (e.g., wettability changes caused by water flood practices), Sor measurements range from 10% to 45%. There is no reliable way to predict Sor with acceptable accuracy for most reservoirs.
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.
The seven volume Petroleum Engineering Handbook (PEH) published by the Society of Petroleum Engineers (SPE). The Petroleum Engineering Handbook has long been recognized as a valuable, comprehensive reference book that offers practical day-to-day applications for students and experienced engineering professionals alike. This new edition, the first since 1987, has been greatly expanded and consists of seven volumes.
Summary Seawater injection is widely used to improve oil recovery in offshore oil reservoirs. However, injecting seawater into reservoirs can cause many flow-assurance issues, such as scaling and reservoir souring, which are strongly related to the percentage of seawater breakthrough. Thermodynamic models have been developed to evaluate the effects of barite deposition on oil production, but the reservoir stripping effect has not been fully considered. In this study, a new model that incorporates both chemical reaction (barium and sulfate reaction) and physical reactions (ion adsorption/desorption) is developed to investigate the in-situbarite-deposition process. To the best of our knowledge, for the first time, ion adsorption/desorption is integrated by coupling the adsorption/desorption isotherm to the reservoir simulator. The barium and sulfate chemical reaction is modeled by incorporating the solubility product constant into the model. The model accuracy is verified through convergence rate tests and comparison with the coreflood experimental results. The simulation results of both barium and sulfate concentration profiles are greatly improved by integrating the ion adsorption/desorption process. The new physicochemical model is further used to investigate barite deposition under various scenarios. Simulation results indicate that most barite deposits are in the deep reservoir for the areal model. Barite that deposits in the reservoir before seawater breakthrough accounts for 45% of total barite deposition and the barite deposited during the seawater-breakthrough period makes up 54%, while the deposition during the tailing period, where the seawater fraction is larger than 95%, is negligible. For a homogeneous reservoir, the barite-deposition period at the near-wellbore area of the producer is between 30% and 65% of the seawater-breakthrough percentage, and heterogeneity leads to a broader deposition period. For vertical heterogeneous reservoirs, a considerable amount of barite forms in the wellbore, which accounts for 17% of total barite deposition. Based on the accurate simulation of barium and sulfate transport in the reservoir, barium and sulfate concentration profiles can be used to determine the seawater-breakthrough percentage and help optimize production operations that aim to mitigate flow assuranceissues.
Abstract Monitoring and surveillance (M&S) is one of the key requisites for assessing the effectiveness and success of any Improved Oil Recovery (IOR) or Enhanced Oil Recovery (EOR) project. These projects can include waterflooding, gas flooding, chemical injection, or any other types. It will help understand, track, monitor and predict the injectant plume migration, flow paths, and breakthrough times. The M&S helps in quantifying the performance of the IOR/EOR project objectives. It provides a good understanding of the remaining oil saturation (ROS) and its distribution in the reservoir during and after the flood. A comprehensive and advanced monitoring and surveillance (M&S) program has to be developed for any given IOR/EOR project. The best practices of any such M&S program should include conventional, advanced and emerging novel technologies for wellbore and inter-well measurements. These include advanced time-lapse pulsed neutron, resistivity, diffusion logs, and bore-hole gravity measurements, cross-well geophysical measurements, water and gas tracers, geochemical, compositional and soil gas analyses, and 4D seismic and surface gravity measurements. The data obtained from the M&S program provide a better understanding of the reservoir dynamics and can be used to refine the reservoir simulation model and fine tune its parameters. This presentation reviews some proven best practices and draw examples from on-going projects and related novel technologies being deployed. We will then look at the new horizon for advanced M&S technologies.
The subject field is an offshore oil field located in the Arabian Gulf that has been on production since the 1960s. After the initial natural- depletion phase, during the 1970s, crestal dump-flood water injection was carried out to maintain the reservoir pressure. During the 1980s, peripheral water injection was introduced to serve as the principal source of energy to arrest reservoir-pressure decline. In 2006, a crestal gas-injection project was initiated to support production from the wells lying away from the periphery. Geologically, the field belongs to the Lower Cretaceous and is divided into six distinct anticline layers; for purposes of monitoring reservoir performance, each layer is further divided into six sectors, as shown in Figure 1 (above). The division of sectors arose out of operational convenience and was not defined by any special characteristics of the layers in the reservoir.