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In spite of its complexities, foam underbalanced drilling has unique advantages such as reduced formation damage, improved rate of penetration, higher cutting-transport capacity, and lower circulation losses. Recent experimental studies in a wide range of experimental conditions show that foam flow in pipe can be represented by two different flow regimes: (i) the low-quality regime showing stable plug-flow pattern with fine-textured foams and (ii) the high-quality regime showing unstable slug-flow pattern with alternating free-gas with fine-textured foam segments. Such a new concept was successfully captured by a foam modeling technique with five model parameters, reproducing two distinct pressure contours.
This study, for the first time, constructs foam drilling hydraulics model with two foam-flow regimes handling both stable and unstable flow characteristics, and investigates how the model improves current foam drilling hydraulics modeling based only on stable foam flow behavior. The results from three different scenarios (scenario 1: a vertical well, scenario 2: a deviated well with relatively short horizontal section, and scenario 3: a deviated well with relatively long horizontal section) with the transition foam quality between the two flow regimes (fg*) around 75-85% showed that significant differences in drilling hydraulics calculations might occur when the conventional technique was replaced by this new technique. For example, a drilling scenario tested with 10,000 ft deep vertical well (scenario 1) was shown to have as much as 32%, 48%, and 25% deviations in foam density, total velocity, and pressure gradient, respectively, at the bottomhole. Examples from two other deviated well trajectories (scenario 2 and scenario 3) exhibited similar responses, showing even more deviations. These results clearly demonstrate why incorporating two foam flow regimes into the current drilling hydraulics calculations is a crucial step toward evaluating and designing foam drilling practice accurately and reliably.
As advanced drilling technology gains more popularity in the development of unconventional reservoirs and deepwater fields, the demand for an improved drilling hydraulics modeling escalates today. The situation is also true for foam applications that have long been used as a useful means of downhole cleaning and underbalanced drilling methods.
This study investigates how a new foam model, recently developed by
Restrepo, Alejandro (BP Exploration Colombia Ltd.) | Osorio, Gildardo (BP Exploration Co. Ltd.) | Duarte, Jorge E. (Saudi Aramco) | Lopera Castro, Sergio Hernando (U. Nacional de Colombia) | Hernandez, Julian (U. Nacional de Colombia)
Naturally fractured sandstone reservoirs are susceptible to drilling mud damage both at the fracture and matrix level. This problem becomes especially severe as reservoir pressure depletes due to: (i) the loss of backpressure preventing static and dynamic mud losses and; (ii) loss of energy for well clean up. Although several completion practices are covered by the experimental techniques described, of special interest in this study is cemented and perforated liners which can have some particular constraints if not properly designed and executed when drilling and completing mature naturally fractured sandstone reservoirs.
While drilling, the overbalance pressure exerted by the drilling mud on producing formations is a means for avoiding wellbore stability problems. When the reservoir pressure is close to its initial value, the near-wellbore region affected by mud losses and invasion is normally restricted to a few inches. Additionally, the reservoir often has enough energy to overcome filtrate damage within the rock matrix and inside natural fractures. This condition changes as reservoir becomes depleted, as a higher drilling overbalance occurs for the same mud weight, and reservoir energy for subsequent well clean-up is reduced.
The following study presents an experimental evaluation of synthetic oil-based mud (SOBM) drilling damage on naturally fractured reservoir cores. Two conditions were simulated: first, a condition in which mud invasion takes place into open natural fractures, followed by simulated under-balanced perforating and post draw-down stimulation. A second scenario is then considered in which simulates mud invasion into open fractures, but which is then followed by on-balance perforating and stimulation, and only after this is a draw-down imposed on the sample.
Results from the study indicate that very high levels of formation damage are caused when natural fractures get plugged and/or closed-over by mud filter-cake and lost circulation material (LNM) solids. Fluid pressure drawdown in the near-wellbore region and induced fracture closure pressures can, in the field, essentially create a compacted "new rock??, with very low permeability and very high tensile stress. In this particular case study, this last condition is evident in the very low injectivity of the stimulation fluid and the very low value of regained permeability. When natural fractures are stimulated before imposing a drawdown, very good return permeability is achieved with an even higher value after closing fractures and re-stimulating.
Carbon dioxide (CO2) geological storage is considered in many large "greenfield?? developments. The requirements for long-term injection operations have put a premium on obtaining the right information early, constraining engineering solutions and costs before major investment decisions are reached. Information such as long-term field pressure evolution and local fracture gradient alteration may have major impacts on development cost forecast. Reservoir heterogeneity and compartmentalization may result in continuous reservoir pressure escalation as injected CO2 amount increases. Maintaining rate is essential to avoid venting. However, this requires proportionate injection pressure increases—an option bounded by formation integrity, seal capacity, and well interference limits. When operating conditions approach these limits, one may avoid compromising rate by, albeit costly, drilling more injection wells over time. We investigate the impact of mean reservoir parameter and boundary condition assumptions on project economics. The potential impact of injection temperature on formation integrity and in-field power needs is also explored. Well injection rate is estimated analytically using a Darcy law's approximation. Taking high seal entry pressures as a given, the study defines allowable injection pressure in terms of fracture gradient. Upward fracture gradient adjustment is modeled for escalating reservoir pressure, allowing mitigation of injection rate reduction. We later analyze the variation of fracture gradient with injection temperature to account for thermal fracture limitation. Ultimately, the study presents pre-tax break-even CO2 unit technical costs in dollar per tonne injected, providing comparison of relative economic performance among the investigated scenarios. The results demonstrate the importance of reservoir quality in suppressing cost-intensive injection well and CO2 heating requirements. The range of costs indicates the value of early appraisal information before making development decisions. The application of geologically-constrained engineering analysis in economic modeling is useful in providing insight on value of information as well as supporting decisions for CO2 storage site development.
In CO2 storage applications, an ideal reservoir with good injectivity may be exemplified by a combination of good permeability, formation thickness, and large fracture gradient. Injection rate is directly proportional to the product of permeability and thickness as well as, in the context of typical storage conditions, the difference between injection and reservoir pressures. In an environment where fracture pressure governs the maximum allowable injection pressure, large fracture gradient allows the application of large injection pressure, enhancing the injection/reservoir pressure difference.
The impact of restricted reservoir boundary or limited storage capacity may be translated into the build-up of reservoir pore pressure as the amount of stored CO2 increases. It is generally true that, for a given injection rate, the smaller the storage capacity or the more restricted the reservoir boundary, the greater the rate of pore pressure increase. The importance of increasing reservoir pressure is two-fold: 1) the fracture gradient is increased, allowing higher injection pressure to be applied; 2) given that its rate of increase is greater than the rate of fracture gradient increase, it reduces the injection/reservoir pressure difference, reducing the maximum injection rate a single well could accommodate. This may result in increasing total injection well requirements with time.
Iran’s petroleum industry with a great potential and need for production enhancement, valued about $100 billion is in necessity of international cooperation by absorbing IOCs’ technology and investment through new Iranian petroleum contracts. This study compares the financial aspects of new Iran's oil fields development and production enhancement framework, called IPC, with the former Iran’s upstream contracts based on Buyback scheme. In this study, a financial analysis was performed aiming to compare the efficiency of fiscal regime of Buyback with IPC by applying cash flow model on three oil field sizes, as case studies. For this purpose, some influential indices such as IRR, NPV, DPP, PVR, and GT have been selected under three scenarios of base, high and low price. The conceptual investigation shows that IPC covers all costs and expenses incurred for the benefit of better reservoir recovery factor, as per best E&P practices and reservoir behavior in production period. Therefore, the expenses are Open Capex and will be chargeable as Petroleum Costs fully recoverable based on Field Development Plan estimations, tender results or authorized yearly budgets. Furthermore, the financial analyses results demonstrate that IPC is not only more eligible for the contractors compared to the Buyback contracts, but also supports adequate and noticeable, however reduced, Government Take. Nevertheless, this might not happen in small and big fields with low price scenario. It is notable that out of the discussed variables that affect GT in IPC, contractual agreed Fee/bbl plays the most crucial role. This study, as the first public analysis that compares the efficiency of fiscal regimes of Buyback and IPC for all types of oil fields from both IOC’s and HG’s viewpoints, can help to simultaneously meet both IOC/contractor and GT expectations by optimizing Fee/bbl which is one of the most important negotiable term in IPC.