A passive tracer that labels gas or water in a well-to-well tracer test must fulfill the following criteria. The tracers discussed in the following sections have properties that make them suitable for application in well-to-well test in which dilution volumes are large. For small fields in which the requirement with respect to dilution is less important, other tracers can be applied. Figure 1.1 – Production curve of S14CN compared with the production curve of HTO in a dynamic flooding laboratory test (carbonate rock) (after Bjørnstad and Maggio). There are no possibilities for thermal degradation, and it follows the water closely. The 36Cl- is a long-lived nuclide (3 105 years), and the detection method is atomic mass spectroscopy rather than radiation measurements.
To obtain high-quality tracer-response curves that are the basis for the further interpretation, a well-designed sampling program is needed. In general, more samples will give the potential for extraction of more information from field tests. Too often, interpretation is difficult because of limited tracer data. The final objective of a well-to-well study is the interpretation of the response curves. A good analysis of the information given by the tracers, in combination with other available data, gives a better understanding of the flow in the reservoir, not just verification of communication between injector and producer.
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. Injection water and gas were monitored with tracers, 18 and the resulting tracer measurements are discussed in this page. The same tracers used in the Snorre field have been injected in the Gullfaks field in the North Sea. The tracers identified unexpected communication paths between layers. The results contributed to methods for improving the WAG recovery performance.
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Islam, M. S. (Dhofar University in Oman and Fault Analysis Group, UCD School of Earth Sciences, University College Dublin in Ireland) | Manzocchi, T. (Fault Analysis Group and Irish Centre for Research in Applied Geosciences, UCD School of Earth Sciences, University College Dublin)
Most petroleum reservoirs contain faults, and a major technical challenge in full-field flow simulation is to represent the effects of 3D fault zone structure within the 2D fault surface represented in the industry standard commercial simulator. Geometrical upscaling (GU) is sometimes performed to include these fault zones implicitly in the upscaled model, and in this study, a comparison is made of the accuracy and flexibility of different geometrical upscaling methods. The existing template-based geometrical upscaling (TBGU) method is compared to a new flow-based geometrical upscaling (FBGU) method. In both methods, the faults are represented in the upscaled flow simulation model implicitly as neighbor and non-neighbor cell-to-cell connection transmissibilities, which are determined from 3D fault zone structures, but these transmissibilities are calculated in very different ways. Both approaches require a high-resolution flow simulation model (referred as truth model in this paper) containing complex 3D sub-seismic fault zone structure explicitly, which is then upscaled using the two methods to take into account the influences of the fault zone geometry as across-fault and along-fault flow. The accuracy of the upscaling methods is examined by comparing the flow behavior of the high-resolution flow simulation model with that of model versions upscaled in the two different ways. Individual well performance for the high-resolution truth and the upscaled models reveal significant differences between the two methods, and indicate that the flowbased geometrical upscaling technique is a more accurate means of including structurally complex fault zones into low-resolution upscaled flow simulation model.
The Bahrain Oil Field was the first oil discovery in the Gulf Region in 1932 and is now in a mature stage of development. Crestal gas injection in the oil bearing, under saturated, layered and heavily faulted carbonate Mauddud reservoir has continued to be the dominant drive mechanism since 1938. Thirty eight 40 acre 5-spot waterflood patterns were implemented from 2011 to 2012. These patterns were located in both the South East and North West part of the Mauddud reservoir with a maximum injection rate of 80,000 bbl/day. With less than 10% PV water injected as of December 2012, premature water breakthrough was observed in most of the producers. Rapid water breakthrough in Mauddud A (Ba) is attributed to presence of high permeability vugs and layers resulting in water cycling and poor sweep in the matrix leaving bypassed oil. Following recommendations from the 2013 partner Peer Assist, the South East and North West waterfloods have been converted from pattern to peripheral with downdip wells providing water injection. Peripheral re-alignment has arrested the production decline, reduced water cut and stabilized production.
Surveillance data such as bottomhole pressure data, production logs, reservoir saturation logs, temperature logs and tracer data form the basis of understanding waterflood performance. Additionally, an array of analytical tools were used for diagnosis and analysis. Amongst the diagnostic tools, the Y- function helped to understand water cycling and sweep; the modified-Hall plot assisted in understanding the high-permeability channel or lack thereof and the water-oil-ratio (WOR) provided the clue on fluid displacement. Additional plots such as the "X" plot, decline curve, Cobb plot, pore volume injected vs. recovery, Jordan plot, and Stagg's plot were generated to gain insight on the waterflood.
Based on the waterflood analysis, a field study was initiated in December 2016 by shutting more than 80% of water injection followed by complete shut-in in September 2017. The purpose was to reduce the water cut, improve production taking advantage of gravity drainage effect of gas injectors located up dip of waterflood areas. The implementation of water injection shut-in is still ongoing in the Bahrain Field and pressure/production performance is being closely monitored. Improved production performance is observed following water injection shut-in.
This study underscores the importance of modern analytical tools to diagnose and analyze waterflood performance. This understanding also paves the way for much improved learning to take appropriate actions and help devise long-term reservoir management strategy.
Beunat, Virginie (IFP Energies nouvelles) | Pannacci, Nicolas (IFP Energies nouvelles) | Batot, Guillaume (IFP Energies nouvelles) | Gland, Nicolas (IFP Energies nouvelles) | Chevallier, Eloïse (SOLVAY) | Cuenca, Amandine (SOLVAY)
Foam processes aim to improve the efficiency of gas-based injection methods through gases mobility control. They have been successfully applied in various EOR contexts: CCUS through CO2-EOR, steam injection for heavy oil reservoirs, and also in fractured reservoirs. The success of such processes depends on multiple factors, among which the interactions between the surfactants, the oil and the rock, play a key role. The purpose of this study is to provide initial answers by focusing on the influence of wettability and oil saturation on the behavior of CO2-foam flows.
A new coreflooding set-up is designed for ‘mesoscopic’ cores (2.5 cm diameter) in order to conduct foam formulation screening and perform faster foam injection tests at reservoir conditions (up to 200 bar and 60 °C). This set-up was first validated by repeating experiments performed previously on classical corefloods with 4 cm diameter cores. Similar results in terms of mobility reduction were obtained for the same operating conditions with a considerable reduction of test duration.
All experiments were performed with Clashach sandstones cores having approximatively 16 % porosity and 600 mD permeability. Two gas compositions have been studied: (1) a dense supercritical CO2 (density of 638 kg/m3 at P = 160 bar, T = 60°C) and (2) a non-dense gas mixture of CO2 and CH4. For each gas composition, four foam injection tests were carried out: two on water-wet rock samples, two others on crude-aged core samples, and for both in the absence and in presence of oil. Anionic surfactant formulations and gas were co-injected with a gas fraction of 0.7. Foam rheology was assessed by measuring foam apparent viscosity through a scan of interstitial velocities.
All the tests performed in dense conditions have highlighted the generation of strong foams, which present shear-thinning rheological behavior; the apparent viscosity decreases as a power law of the interstitial velocity. An influence of the wettability is observed on the foam apparent viscosity, which drops off by 30 % in altered wettability rock samples. When samples were originally saturated with oil at Swi, the level of apparent viscosity remains globally unchanged but the kinetics of the initial formation of the foam is slower with oil than without.
Foam flooding experiments are sometimes carried out simply in the presence of oil without taking into account the influence of wettability, which appears to be as important, if not more, than the oil saturation itself. These results will hopely provide some guidance for future foam studies and raise awareness on the importance of these parameters.
AlAbbad, Mohammed A. (Saudi Aramco) | Sanni, Modiu L. (Saudi Aramco) | Kokal, Sunil (Saudi Aramco) | Krivokapic, Alexander (Institutt for Energiteknikk) | Dye, Christian (Institutt for Energiteknikk) | Dugstad, Øyvind (Restrack) | Hartvig, Sven K. (Restrack) | Huseby, Olaf K. (Restrack)
The single-well chemical-tracer test (SWCTT) is an in-situ test to measure oil saturation, and has been used extensively to assess the potential for enhanced oil recovery (EOR) or to qualify particular EOR chemicals and methods. An SWCTT requires that a primary tracer be injected and that a secondary tracer be generated from the primary tracer in situ. Typically, a few hundred liters of ester is injected as primary tracer, and the secondary tracer is formed through hydrolysis in the formations. The ester is an oil/water-partitioning tracer, whereas the in-situ-generated alcohol is a water tracer. During production, these tracers separate and the time lag of the ester vs. the alcohol is used to estimate oil saturation in the near-well region.
In this paper, we report a field test of a class of new reacting tracers for SWCTTs. In the test, approximately 100 cm3 of each of the new tracers was injected and used to assess oil saturation. In the test, ethyl acetate (EtAc) was used as a benchmark to verify the new tracers. This paper reviews the design and implementation of the test, highlights operational issues, provides a summary of the analyzed tracer curves, and gives a summary of the interpretation methodology used to find oil saturations from the tracer curves. Briefly summarized, we find the Sor measured by each of the novel tracers to compare with that from a conventional SWCTT. To validate stability and detectability of the tracers, a mass-balance assessment for the new tracers is compared with that of the conventional tracers.
A benefit of the new tracers is the small amount needed. Methodological advantages resulting from using small amounts include the possibility to inject a mix of several tracers. Using several tracers with different partitioning coefficients enables probing of different depths of the reservoir. In addition, the robustness of SWCTTs can be increased by using several tracers, with different reaction rates and temperature sensitivity. The field trial also demonstrated that the new tracers have operational advantages. One benefit is the possibility to inject the new tracers as a short pulse of 10 minutes. Other benefits are that the small amounts needed reduce operational hazards and ease logistical handling.
Foam flow in porous media without oil shows two regimes depending on foam quality (gas fractional flow). Complexity and limited data on foam/oil interactions in porous media greatly restrict understanding of foam in contact with oil. Distinguishing which regimes are affected by oil is key to modeling the effect of oil on foam. We report steady-state corefloods to investigate the effect of oil on foam through its effect on the two flow regimes. We fit the parameters of a widely used local-equilibrium (LE) foam model to data for concurrent foam/oil flow. This research provides a practical approach and initial data for simulating foam enhanced oil recovery (EOR) in the presence of oil.
To ensure steady state, oil is coinjected with foam at a fixed ratio of oil (Uo) to water (Uw) superficial velocities in a Bentheimer Sandstone core. Model oils used here consist of a composition of hexadecane, which is benign to foam stability, and oleic acid (OA), which can destroy foam. Varying the concentration of OA in the model oil allows one to examine the effect of oil composition on steady-state foam flow. Experimental results show that oil affects both high- and low-quality regimes, with the high-quality regime being more sensitive to oil. In particular, oil increases the limiting water saturation (S*w) in the high-quality regime and also reduces gas-mobility reduction in the low-quality regime. Unevenly spaced pressure-gradient contours in the high-quality regime suggest either strongly shear-thinning behavior or an increasingly destabilizing effect of oil. In some cases, the pressure gradient in the low-quality regime decreases with increasing Uw at fixed gas superficial velocity (Ug), either with or without oil. This might reflect either an effect of oil, if oil is present, or easier flow of bubbles under wetter conditions. Increasing the OA concentration extends the high-quality regime to lower foam qualities, indicating more difficulty in stabilizing foam. Thus, oil composition plays as significant a role as oil saturation (So).
A model fit assuming a fixed S*w and including shear thinning in the low-quality regime does not represent the two regimes when the oil effect is strong enough. In such cases, fitting S*w to each pressure-gradient contour and excluding shear thinning in the low-quality regime yield a better match to these data. The dependency of S*w on So is not yet clear because of the absence of oil-saturation data in this study. Furthermore, none of the current foam-simulation models captures the upward-tilting pressure-gradient contours in the low-quality regime.
In the subsea environment, inspection/repair/maintenance (IRM) services have traditionally relied on vessel-based, ROV, or diver operations. In the longer term, the drive to continually identify significant incremental savings in these operations is not sustainable and a more innovative approach, deploying digital technologies, is being investigated. With the aim of significantly reducing OPEX costs as well as minimizing environmental impact, industry leaders are embracing the future value of autonomous subsea vehicles. These underwater drones can potentially be the resident eyes and ears on the seabed, reducing the need for a field support vessel to oversee all IRM activities. For more than 2 decades, i-Tech Services (a Subsea 7 company) has been actively developing its autonomous subsea inspection vehicle capability to support and maintain the integrity of subsea production assets.