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Abstract The foremost function of primary cementing is to achieve zonal isolation and ensure long-term cement integrity during the lifetime of the well. Current advanced drilling and cementing technologies enable the production of oil and gas in more complex and challenging conditions such as deep wells and unconventional wells either onshore or offshore. Understanding the mechanical performance of cement sheath under downhole conditions, therefore, is crucial for successful cementing operations. Unfortunately, most published mechanical data were still limited to the compressive and tensile strengths determined at ambient condition as well as Young's modulus. The result for tensile strength varies greatly due to the lack of API standard tensile strength testing. The purpose of this study is to evaluate the additive-additive interaction on cement mechanical properties. Individual additives and their combinations were mixed with class H cement at a density of 16 ppg and cured under elevated temperature and pressure. The mechanical properties tested at ambient and curing conditions include compressive, tensile and yield strength, Young's modulus, and Poisson's ratio. The cement mechanical performances measured at curing conditions, especially the tensile strength, were different from the results obtained at ambient conditions. The elasticity of cement was improved by fiber and polymeric additives tested in this work. This study provides comprehensive experimental data on how the slurry formulation, chemical characteristics of the additives, and additive-additive interactions can affect cement mechanical properties. This study also gives insights into the correlations among various mechanical properties, and the key parameters that could determine cement elasticity. The results can be used as direct guidance for future field applications.
- North America > United States > Texas (0.29)
- North America > United States > California (0.28)
Summary In 2014 we proposed a new technique that used well information to correlate anisotropy with velocity for localized lithology dependent anomalies (Birdus at al., 2014). It is based on the assumption that in appropriate geological settings localized variations in both velocity and anisotropy are caused by changes in the lithology. This results in some correlation between anisotropy and velocity anomalies. We used well information to establish such a correlation for tomographic PSDM imaging anisotropic velocity models. In this paper we extend our approach to high resolution FWI depth velocity modeling. We use a real 3D seismic dataset from the NW Australian shelf to illustrate how our technique produces more realistic anisotropic velocity models and reduces depth misties. Introduction Having an accurate anisotropy model is very important for depth-velocity modeling, in particular for correct positioning of seismic reflectors in depth. The effective seismic velocity V_seis (seismic moveout) in VTI media depends on the true vertical velocity V_vert and anisotropic parameter d (Thomsen, 2002): V _ seis =V _ vert* [not complete] 1+ 2d (1) The same effect is present in more complex models for anisotropy (TTI, orthorhombic etc). If we use only seismic data we are not able to separate the two factors in the right hand side of equation (1), i.e., we cannot unambiguously distinguish arrival time variations due to velocity and anisotropy. This leads to uncertainties in velocity/anisotropy estimations. In this paper, we focus on the elliptical component of anisotropy (d = e), which is responsible for the errors in depth estimation. We concentrate on small and medium-size anomalies when the major global trends are known. Uncertainties and depth misties in anisotropic depthvelocity modelling and imaging. We use seismic data, available well information and apriori geological knowledge to build imaging anisotropic depth-velocity models. The problem with uncertainties is resolved by creating the simplest model that satisfies all input data (Artemov and Birdus, 2014). Traditionally we put all detected small scale anomalies into the imaging velocities and set the anisotropy values using simplified smoothed models.
Abstract Injection of low salinity brines can improve oil recovery (IOR) in carbonate reservoirs by changing the rock wettability from oil-wet to more water-wet. Existing numerical simulation models for low salinity flooding use empirical relationships that do not properly capture important processes for wettability alteration, such as aqueous species concentrations, oil acidity, and rock mineralogy. In our previous research on modeling spontaneous imbibition with tuned water (SPE170966), we developed a process-based and predictive model that explicitly includes the chemical interactions between crude oil, brine, and the carbonate surface. In this research, we extend the previous model for low salinity water flooding to both chalk and limestone cores. We examine the role of mineralogy in low salinity waterflooding by developing a mechanistic model for wettability that includes surface complexation, aqueous reactions, and dissolution/precipitation of calcite and anhydrite. The reactions coupled with the equations of multiphase flow and transport are solved simultaneously using an IMPEC in-house simulator, PennSim. Relative permeability functions and residual oil saturation during flooding are adjusted dynamically according to the concentration of oil acids attached to the mineral surface. Core flooding experiments from the Stevns Klint (SK) chalk (Fathi et al. 2010), a limestone with small amount of anhydrite (Austad et al. 2012), and a Middle Eastern carbonate with 6% volume fraction anhydrite (Yousef et al. 2011) are used to tune the reaction network and make recovery predictions. Simulation results give remarkable agreement with the effluent concentrations of SO4, Ca and Mg reported from chromatographic wettability tests and the recoveries for injection of various brines into chalk and limestone cores of differing compositions. For SK chalk without anhydrite, reducing the Na and Cl concentration of seawater, while keeping SO4 (sulfate) leads to improved oil recovery (IOR) by as much as 6% OOIP. The presence of anhydrite, which provides a natural source of sulfate, also significantly increased oil recovery for injection of diluted formation water and seawater. Simulations of 2D five-spot patterns using tuned reaction networks demonstrated that IORs from 5% to 20% OOIP can be obtained at reasonable values of pore volumes injected (2.0 PVI). These IORs depend greatly on the aqueous chemistry of the injected fluid, and sweep. The results highlight the critical importance of understanding the mineralogy and including a mechanistic reaction model in the simulation of low salinity water floods.
- Asia (0.68)
- North America > United States > Texas (0.28)
- Geology > Mineral > Sulfate > Anhydrite (1.00)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock > Limestone (0.69)
Evaluating Wellbore Accessibility and Productive Performance for a Long-Reach Multilateral Tight Gas Well in Changbei Block
Li, Li (Shell) | Zhi, Guo Hong (Southwest Petroleum University, Schlumberger) | Millan, Hilarion (Shell) | Qiang, Zhang (PetroChina) | Tao, Zhang (Schlumberger) | Lei, Cui (Schlumberger) | Sheng, Li Yin (Schlumberger)
Abstract Changbei gas field is on the north edge of the Mauwusu desert in the Ordos basin in north-central China. The game-changing dual-lateral well concept is used in this tight gas reservoir. The typical well completion is kicked off at about 1700 m, and the hole is built to an inclination of 85° at the top of the reservoir with the 12¼-in. section. The first leg of the 8½-in. reservoir section is drilled for 2000 m. The second leg is drilled with an openhole sidetrack from leg 1. More openhole sidetracks are drilled from legs 1 and 2 if unstable intervals are penetrated. Upon reaching total depth (TD), a 7-in. slotted liner is run to protect any unstable claystone intervals. As part of the well and reservoir surveillance activities and with the aim of improved understanding of the reservoir and well behavior, production logging is required to obtain the gas-contribution profile along the horizontal wellbore; the profile is used to confirm the size of the sand bar, facies distribution, wellbore condition, and production contribution from each leg. Previous attempts with wheel-driven tractors and conventional production logging tools (PLTs) were unsuccessful because most of the PLT runs encountered bad downhole conditions, such as water/mudcake, which led to failure of the tractors and PLT centralizers. The mudcake and debris could not be cleaned from wellbores, even though the wells had been produced at high rate. To collect needed data, an advanced PLT consisting of an array of minispinners and optical and electrical holdup sensors was conveyed by an electrically powered tractor operating on the inchworm principle to successfully log a long-reach multilateral well. A workflow was followed to obtain wellbore accessibility and perform flow profile evaluation for the complex downhole conditions at Changbei. This was the first time a flow profile was obtained in Changbei block.
- Asia > China > Shanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changqing Field (0.99)
- Asia > China > Shaanxi > Ordos Basin > Changbei Field (0.99)
- (3 more...)