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Bentonite is not typically used as the primary fluid-loss agent in normal-density slurries. In low-density slurries, where higher concentrations can be used, it may provide sufficient fluid-loss control (400 to 700 cm 3 /30 min) for safe placement in noncritical well applications. Fluid-loss control, obtained through the use of bentonite, is achieved by the reduction of filter-cake permeability by pore-throat bridging. Microsilica imparts a degree of fluid-loss control to cement slurries because of its small particle size of less than 5 microns. The small particles reduce the pore-throat volume within the cement matrix through a tighter packing arrangement, resulting in a reduction of filter-cake permeability.
Chiotoroiu, Maria-Magdalena (OMV E&P) | Clemens, Torsten (OMV E&P) | Zechner, Markus (OMV E&P) | Hwang, Jongsoo (University of Texas at Austin) | Sharma, Mukul M. (University of Texas at Austin) | Thiele, Marco (Streamsim)
Summary Waterflooding can lead to substantial incremental oil production. Implementation of water‐injection projects requires the project to fit into the risk (defined here as negative outcomes relative to defined project objectives) and uncertainty (defined here as the inability to estimate a value precisely) a company is willing to take. One of the key risks for water injection into a shallow reservoir is injection‐induced fractures extending into the caprock. If this risk is seen as “intolerable” in an as‐low‐as‐reasonably‐practicable (ALARP) analysis, a decision might be made not to proceed with the project. In this study, we evaluated caprock integrity by conducting simulations of long‐term water injection that include the effects of formation damage caused by internal/external plugging, geomechanical stress changes, and fracture propagation in the sandstone and bounding shale. The risk of fracture growth into the caprock was assessed by conducting Latin hypercube sampling considering a set of modeling parameters each associated with an uncertainty range. This allowed us to identify the range of operating parameters in which the risk of fracture‐height growth was acceptable. Our simulations also allowed us to identify important factors that affect caprock integrity. To cover the uncertainty in geomechanical reservoir evaluation, the operating envelope is identified such that the risk to the caprock integrity is reduced. This requires introducing a limit for the bottomhole pressure (BHP), including a safety margin. The limit of the BHP is then used as a constraint in the uncertainty analysis of water injectivity. The uncertainty analysis should cover the various development options, the parameterization of the model, sampling from the distribution of parameters‐ and distance‐based generalized sensitivity analysis (dGSA) as well as probabilistic representation of the results. The results indicate that the time to reach the BHP limit varies substantially, dependent on the chosen development scenario. Injection of water (1000 m/d), with total suspended‐solids content ranging from 0.1 to 0.5 ppm by volume (ppmv) and particle size from 1 to 5 µm, into long horizontal wells (2000 m) results in injection times of more than 10,000 days even for the P10 percentile. However, injection of poor‐quality water (injection rate 600 m/d, well length 600 m), with total suspended‐solids content ranging from 0.5 to 5 ppmv and particle size from 10 to 30 µm, leads to the BHP limit of 10 (P10) to 740 (P90) days. The dGSA can be used to determine which parameter has a stronger impact on the BHP and, hence, on the project, and should be measured if warranted by a value‐of‐information analysis. In the case reported here, dGSA showed that the filter‐cake permeability has a big impact on the results and, hence, will be determined by laboratory measurements. The final development option to be chosen depends on a traditional net‐present‐value analysis.
Summary This study proposes, through the coupling of a linear filtration formulation(laboratory configuration) and a radial single-phase formulation (well borevicinity), to predict fluid-invasion depth-of-drilling fluid filtrate in the reservoir rock. Modeling is validated with linear and radial laboratory tests, as well as with resistivity logs run in offshore wells from Campos basin, offshore Brazil. The proposed methodology is required for optimum drilling-fluid design to be used in the drilling of reservoir sections in both exploratory and developmental wells in Campos basin. Introduction Minimizing fluid invasion is a major issue when drilling reservoir rocks. Large invasion may create several problems in sampling reservoir fluids in exploratory wells. Unreliable sampling may lead to inaccurate reservoir evaluation and, in critical cases, to wrong decisions concerning reservoir exploitability. In addition, drilling-fluid invasion may also provoke irreversible reservoir damage, thereby reducing its initial and/or long-term productivity. Such problems can be critical in heavy-oil reservoirs in which oil and filtrate interaction can generate stable emulsions. Invasion in light-oil reservoirs is less critical because of good mobility properties.1Another critical scenario is low-permeability gas reservoirs in which imbibition effects may result in deep invasion. To avoid these problems, the drilling-fluids industry spends a lot of effort providing noninvasive systems (Reid and Santos2 and Luo et al.3, among several others). A common practice in the industry is to add bridging agents such as calcium carbonates into the drilling-fluid composition. Such products would form a low-permeability layer at the well walls, which would control invasion. Several authors present fluid-composition-optimization studies for specific situations (Krilov et al.4, among others). Field Evidence of Drilling-Fluid Invasion The evaluation and diagnosis of the cause of formation damage is a complex and important topic because it may define effective or noneffective stimulation methods. It is frequently difficult to define whether drilling-fluid invasion was or was not a cause for a bad productivity index result. Direct evaluation of filtrate invasion is also an important and complex issue. Logging-while-drilling (LWD) and wireline logging are the most effective tools available. LWD-resistivity responses establish the initial situation in the well, while logs provide semiquantitative invasion information regarding invasion at different distances from the well at the end of the drilling phase. Formation test results indicate invasion when the sampled fluid contains filtrate; however, it may be imprecise to use such data to predict radial invasion caused by permeability-anisotropy effects. In this case, filtrate could be migrating vertically from the reservoir directly to the sampling chamber.