Analysis of potential acid gas leakage from wellbores in Alberta, Canada (original) (raw)
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2013
Noncondensible gas is a major factor affecting the reservoir pressure in the deep liquid-dominated Kizildere geothermal reservoir which is currently being developed by ZORLU ENDÜSTRİYEL VE ENERJİ TESİSLERİ İNŞ.TİC.A.Ş.(Zorlu Enerji) as the Kizildere II Geothermal Power Project. Under static conditions, the pressure within the production zone ranges from 130 to 230 bar at 1700 to 2500m. Reservoir temperatures range from 219 to 242 o C and under static conditions, the reservoir fluid is entirely in the liquid phase. Based on gas pressures estimated from applying Henry's law, approximately 60 bar (at 0.024 kg NCG/kg reservoir brine) to 100 bar (at 0.0415 kg NCG/kg reservoir brine) is dissolved noncondensible gas pressure. The noncondensible gas is over 98% carbon dioxide. The reservoir fluids at Kizildere are known to produce calcite scale in the wellbores at the depth of gas breakout. The gas breakout pressures (or bubble point) is the pressure below which the fluid will begin to transform from 100% liquid to two-phase. Gas breakout pressure is the sum of the gas pressure and water pressure at the reservoir temperature. These values can be estimated using Henry's Law and the steam tables. In the deep reservoir at Kizildere, bubble points are between 80 bar (at 0.024 kg NCG/kg reservoir brine) and 128 bar (at 0.0415 kg NCG/kg reservoir brine). At the flow rates (<250 tph) that the dynamic surveys are run, measured pressure in the well falls below this gas breakout pressure between 900 and 1800 m. Wellbore simulation is used to estimate the depth of gas beakout at higher flow rates. Since the gas breakout occurs at greater depths at higher flow rates, it is important to estimate the depth of gas breakout at multiple mass flow rates to manage the potential effect of scaling in the feed zone as well as the depth of scale inhibitor injection.
Quantifying the Risk of CO2 Leakage Through Wellbores
SPE Drilling & Completion, 2011
SummaryLeakage through new or existing wellbores is considered a major risk for carbon dioxide (CO2) geological storage. Long-term effective containment of CO2 is required, and the presence of millions of suspended or abandoned wells exacerbates the potential risk in mature hydrocarbon provinces. Accurate estimates of risk profiles can support the acceptance of geological storage and the adoption of economically effective risk-prevention and -mitigation measures.Reliable data about long-term containment of CO2 are almost nonexistent, so wells that exhibit a similar risk profile (such as gas storage, gas production, and steam injection) should be used as a proxy to assess failure rates and consequences for cemented wellbores.Statistical data about occurrence of leaks and their consequences are analyzed to determine the risk profile of CO2 leaks. A smaller sample of data about leak rates is also analyzed to provide their statistical distribution. Rates and consequences are then compar...
PVT Fluid Sampling, Characterization and Gas Condensate Reservoir Modeling
When reservoir pressure decreases in gas condensate reservoirs, there is a compositional change which makes the system difficult to handle. This type of system requires an Equation of State (EOS) to ensure proper fluid characterization so that the Pressure Volume Temperature (PVT) behavior of the reservoir fluid can be well understood. High quality and accurate PVT data will help reservoir engineers to predict the behavior of reservoir fluids and facilitate simulation studies. The aim of this study is to determine what to do on reservoir fluid before carrying out reservoir modeling. PVT data were obtained from a reservoir fluid in the Niger Delta which was sampled following standard procedures. Then the laboratory experiments were critically examined to ensure accuracy, consistency and validity before PVT analysis. Finally, the results from the PVT experiments were imported into PVT software and subsequently in a reservoir simulator for simulation studies. These processes generate the EOS model for reservoir modeling of gas condensate reservoirs. 2 the consistencies of the data were ascertained and the composition added up to 100%. The pattern of the CCE/CVD comparison plot was observed to reflect that less liquid dropout was experienced later in the depletion process of the CVD experiment than in the CCE experiment. PVT validation checks help to confirm the Gas oil ratio of the system and the richness of the gas condensate fluid. It is imperative to obtain representative reservoir fluid samples and carry out reliable laboratory experiments to generate PVT data for fluid characterization. PVT fluid characterization and consistency checks will ensure that accurate results are obtained from reservoir simulation models leading to proper reservoir management. NOMENCLATURES A 1 = Slope of the Hoffman et al Plot A o = Intercept of the Hoffman et al plot BIP = Binary Interaction Parameter CCE = Constant Composition Expansion CVD = Constant Volume Depletion C f = Characteristic factor correlation EOS = Equation of State F = Total moles of Feed Fi = Hoffman Factor FVF = Formation Volume Factor F/V = Intercept of Mass Balance Plot GOR = Gas Oil Ratio K-Value = Y/X L = Total moles of separator Liquid L/V = Slope of Mass Balance Plot Mi = Molecular weight of Heptane plus Pc = Critical Pressure P D = Dew Point Pressure PR = Peng-Robinson PT = Patel and Teja Psc = Pressure at standard conditions PVT = Pressure Volume Temperature RK = Redlich Kwong SRK = Soave Redlich Kwong T = Separator Temperature Tb = Normal Boiling Temperature TBP = True Boiling Point Tc = Critical Temperature V = Total moles of separator Vapour VLE = Volume Liquid Equilibrium Xi = Moles fraction of component i in Liquid Yi = Mole fraction of component i in Vapour Zi = Mole fraction of component i in feed ZJ = Zudkevitch and Joffe i = Specific Gravity
The Prediction of Bubble-point Pressure and Bubble-point Oil
Up to now, there has not been one specific correlation published to directly estimate the bubble-point pressure in the absence of pressure-volume-temperature (PVT) analysis. Presently, there is just one published correlation available to estimate the bubble-point oil formation volume factor (FVF) directly in the absence of PVT analysis. Multiple regression analysis technique is applied to develop two novel correlations to estimate the bubble-point pressure and the bubble-point oil FVF. The developed correlations can be applied in a straightforward manner by using direct field measurement data. Separator gas oil ratio, separator pressure, stock-tank oil gravity, and reservoir temperature are the only key parameters required to predict bubble-point pressure and bubble-point oil FVF.
Sequestration of CO 2 in geologic reservoirs is one of the promising technologies currently being explored to mitigate anthropogenic CO 2 emissions. Large-scale deployment of geologic sequestration will require seals with a cumulative area amounting to hundreds of square kilometers per year and will require a large number of sequestration sites. We are developing a system-level model, CO 2 -PENS, that will predict the overall performance of sequestration systems while taking into account various processes associated with different parts of a sequestration operation, from the power plant to sequestration reservoirs to the accessible environment. The adaptability of CO 2 -PENS promotes application to a wide variety of sites, and its level of complexity can be increased as detailed site information becomes available. The model CO 2 -PENS utilizes a science-based-prediction approach by integrating information from process-level laboratory experiments, field experiments/observations, and process-level numerical modeling. The use of coupled process models in the system model of CO 2 -PENS provides insights into the emergent behavior of aggregate processes that could not be obtained by using individual process models. We illustrate the utility of the concept by incorporating geologic and wellbore data into a synthetic, depleted oil reservoir. In this sequestration scenario, we assess the fate of CO 2 via wellbore release and resulting impacts of CO 2 to a shallow aquifer and release to the atmosphere.