A steam chamber generally rises steadily in the channel sands of Athabascaoil sands during a SAGD operation. It is commonly known that steam chambergrowth rate is mainly dependent to permeability. Once the steam chamberreaches the upper boundary, it starts to expand laterally. This is thebasic concept of steam chamber growth of SAGD process in fine sands. However, the growth of steam chamber measured through the analysis oftemperature changes from observation wells behaves different in many instancesthan the commonly accepted steam chamber growth concept, explainedabove. In these observation wells, the steam chamber deviates from theusual behavior; sometimes stops and then resumes rising or shrinking, or evendisappears during SAGD process. This can be caused by the specific natureof steam fingering phenomenon during SAGD operation. Many simulation studies have been conducted to understand the steam risingphenomenon during SAGD operations. At the top of the steam chamber, steamfingers seemed to be created where steam flows through and the steam chamberexpands vertically. If steam fingering actively develops, steam chambergrows steadily as expected. However, activity of fingering can bedisturbed under certain conditions, which can result in various alterations inthe growth of steam chamber. In this paper, the steam fingering phenomenon during SAGD process isdiscussed with actual measured field data from four SAGD projects; UTF Phase A, UTF Phase B, Hangingstone and Surmount. Introduction SAGD performance can be evaluated whether the steam chamber reaches theexpected vertical growth for given reservoir parameters. Generally, whenthe steam chamber rises to the expected height in expected time, SAGD processis determined to be successful. Otherwise, it should be terminated inextreme cases. It is commonly accepted that steam chamber growth rate highly depends onpermeability. Figure 1 illustrates the relationship between the height ofrising steam chamber above the injector and the horizontal permeability fromthe simulation results, and in this case the ratio of horizontal to verticalpermeability was set to 2. Horizontal permeability versus the growth rateof the steam chamber at 15 m above the injector is shown in Figure 2. FromFigures 1 and 2, it is confirmed that steam chamber growth is proportional topermeability. Solution gas effect on the steam chamber growth is includedin Figure 3. Similar steam chamber growth is observed for the cases withand without solution gas. Figure 4 illustrates the height of steam chamberat various operating pressures. As the operating pressure increases thegrowth rate of the steam chamber increases. In the field, rise of the steam chamber, in other words, vertical growth ofthe steam chamber during SAGD process is extremely influenced by thedevelopment of steam fingers at the top of the steam chamber. It isobserved that any type of distraction to the development of the fingering atthe top of steam chamber can sometimes result in the deviation from theexpected behavior of chamber growth, such as shrinking or disappearing; causingunsuccessful SAGD process in extreme cases. In this paper, steam fingering phenomenon at the top of the steam chamberduring SAGD process is discussed for the first time through the review ofnumerical history matches of the real field observation data.

No abstract

No abstract

Hydrocarbon bearing shaly formations can be detected using cation exchange capacity (CEC) shaly sand models. Most CEC shaly sand models still depend on the laboratory measurement of CEC value. In addition, these models use one value of formation resistivity factor, which is a function of the rocks's cementation exponent. Using one formation resistivity factor in shaly sand reservoir can result in overestimation of the water saturation which in turn results in overlooking formations with hydrocarbon potential. This paper introduces a new CEC shaly sand model, lpekBassiouni (I-B) model that improve the definition of the formation resistivity factor used in shaly sand formations. This model can also calculate the CEC value directly from the well log data.Ipek-Bassiouni (I-B) Shaly Sand Model considers that electric current follows two type of path in shaly sand. One path represents current flow in free water and another path in bound water. The differentiation between these two paths is accomplished by using two different formation resistivity factors in free water and in bound water. The two formation resistivity factors are expressed using two cementation exponents for free water and bound water as well.The validity of the model was checked using the cation exchange capacity measured from core samples and drill cuttings. Calculated CEC values display a good agreement with the measured CEC values. The estimated water saturations from the model indicate a better hydrocarbon potential in the zone of interest.

Temperature logs can be used to identify entry and exit points of underground blowouts. The magnitude of the flow can be estimated using relationships that are applicable after a flow time of several days. However, the ability to estimate the flowrate as soon as the blowout is detected is critical for the selection and design of a kill method. A model relating underground blowout rate and the flowing fluid temperature that is valid for short flow-time was derived. The model uses transient radial heat transfer conditions from the wellbore to the surrounding rock and constant heat transfer coefficient inside the well. Application of the method is illustrated for several hypothetical and two real field examples. Introduction Temperature logging is conventionally used to locate fluid flow in the casing or in the annulus surrounding the casing. It is used during injection and production to locate points of entry or exit of fluids. The temperature profile depends on the fluid type. Figure 1 shows a schematic of a temperature log in a well producing liquid. The temperature of the produced liquid at the point of entery is the reservoir temperature. Above the point of entry the fluid temperature decreases as heat is transferred to cooler surrounding formation. After some distance equilibrium is reached and the fluid temperature approaches an asymptote parallel to the geothermal gradient. The temperature anomaly, i.e. the offset between the asymptote and the geothermal gradient, depends on the well geometry, the flowing fluid thermal properties, flow rate and flow duration. A similar profile, illustrated in figure 2, is observed in a flowing gas well, except initially the gas entering the well is cooler than the surrounding formation due to a phenomenon known as the Joule-Thompson effect.5 Relationships exist which can be used to predict temperature responses in producing wells as a function of mass flow rate, duration of production, geothermal gradient and various thermal coefficients2. These relationships can also be used to estimate flow rate if the temperature is measured. These relationships assume that heat transfer in the wellbore is steady state, while heat transfer to the earth is governed by transient radial conduction3. These assumptions limit the application of current methods to production times greater than 10 days. Temperature measurement can also detect flow between subsurface intervals such as in the case of an underground blowout. Figure 3 schematically shows temperature profiles in cases of upward liquid and gas flow between two zones. Temperature logs are used in underground blowout detection because of their simple operation, low cost, and applicability to both cased and open holes. In order to estimate the magnitude of the underground blowout, a wellbore heat transmission model is needed for the specific heat transfer problem of underground blowouts. Aspects unique to underground blowout situation include:temperature measurement performed through drillpipe,presence of drilling fluid in the wellbore, andtemperature measurement performed after possibly a short flow time.