TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractPore Volume Compressibility (PVC) is one of the most important parameters for proceeding with project sanctioning. An accurate estimation of pore volume compressibility of reservoir rocks is essential for compaction evaluation, reservoir drive determination, reserves estimates, reservoir pressure maintenance, casing collapse analyses, and production forecasting. This information is then used in modeling the reservoir and calculating the economic value of the project. Thus, obtaining credible indications of this value early in the well evaluation process is invaluable. Unfortunately, this data is usually required long before a conventional core can be obtained and mechanical rock properties measured. Furthermore, cores are only available at discrete points along the wellbore requiring the data to be extrapolated to the missing sections.To accommodate the need for this data early in the project and to circumvent the short comings of core-based information gaps in the wellbore, a cost effective approach that utilizes common wireline data is used to obtain a continuous profile of the pore volume compressibility with depth shortly after wireline logging operations have concluded. The method employs a log-based mechanical property program that simulates triaxial loading to obtain static elastic moduli as well as rock strength. The resulting rock mechanical properties are then converted into their uniaxial strain equivalents and used to determine the pore volume compressibility. The process is repeated for several drawdown stages with the condition that the deformations are contained within elastic limits. This yields the complete reservoir compaction trend as a function of reservoir depletion.The log-based model was recently validated by comparing with lab-derived results from an offset well in deepwater Gulf of Mexico. The results indicate that the uniaxial pore volume compressibility obtained from the log-based method matches well with the results obtained in the laboratory. This fact suggests that the log-based approach should be utilized with a high degree of confidence to determine the PVC in the absence of core data, insufficient depth coverage of the cores, and/or to validate the core results.
Analysis and prediction of geomechanical problems is important for the success of drilling, completion, and production operations, and requires knowledge of rock strength, pore pressure and in-situ stress. Geomechanical problems encountered while drilling include wellbore stability and fracturing of the formation, and may lead to financial loss due to loss of drilling fluid, well control events (kicks), stuck pipe, extra casing strings and sidetracks. Examples of geomechanical problems due to reservoir stress changes occurring during production include reservoir compaction, surface subsidence, casing deformation and failure, sanding, etc. The information needed to assess the impact of geomechanical problems on field development can be captured by building a Mechanical Earth Model (MEM) that includes details of the in-situ stresses, rock failure mechanisms, rock mechanical parameters, geologic structure, stratigraphy and well geometry. The workflow for building a Mechanical Earth Model (MEM) along a well trajectory based on logs and drilling data is illustrated for the case of a deviated well drilled through deepwater Gulf of Mexico channel sands. Once constructed, a MEM can be used to identify geomechanical problems and formulate contingency plans for mitigation before future wells are drilled. The stress field in the vicinity of a well is perturbed by the physical operation of drilling the well. This process may result in formation damage or alteration of the rock properties resulting in changes in acoustic velocity in the vicinity of the well. The constructed MEM uses the variation in the fast and slow shear wave velocities as functions of the distance from the borehole to determine the variation in rock strength along the well. The results of mechanical rock properties measured from cores in an independent study are found to be in good agreement with the rock strength determined from the sonic log measurements.
Drilling expensive and challenging wells in deepwater requires significant prewell planning to mitigate risks. Understanding the regional drilling hazards that nearby operators have encountered and correlating them to the current project must be done to gain a clear appreciation of potential problem hole sections. This paper describes a deepwater well drilled by Agip where significant efforts were taken to fully evaluate the potential for a shallow water flow in the top-hole section.Another operator in a nearby block had recently lost well to a shallow water flow. This heightened the concern of the Agip asset team so an extensive pore-pressure analysis of the surface seismic data was undertaken. The results of this analysis indicated that there was also a strong potential for a shallow water flow on this well. In order to build the best possible understanding of the pore pressure profile the surface seismic pressure analysis was taken much deeper than what is customary, in this case to the top of the salt. Prewell pore pressure models confirmed Agip's surface seismic pore pressure assessment. As a result, real-time pore pressure monitoring services were deemed essential to closely monitor the progress of the well and, with that information, make real-time adjustments to the drilling parameters (i.e. mud weight) as they became necessary.An extremely important and sometimes overlooked aspect of real-time interactivity is the definition of the role each team member has and how each team member interacts with the others. Assembling a team and defining each member's roles and responsibilities in the planning phase streamlines the time-critical decision-making process and allows for a decisive, unambiguous, work flowpath. Figure 1 shows the communication and workflow organization assigned by Agip before the well was drilled. Rig-based personnel are highlighted in green and office-based personnel in blue. The operations geologist was the decision-making focal point and received multiple inputs of data and assessments from the rig. The operations geologist had, as well, responsibility for managing input from other members of the asset team and from partners in the well. It was his responsibility to make a final interpretation of the pore pressure assessment and to communicate any changes in the drilling plan to the company man on location.Because a flow of real-time information was critical in the pore pressure/hazard avoidance interpretation, Agip ran LWD tools that provided gamma ray, propagation resistivity, borehole annular and internal pressures (PWD = pressure while drilling), and sonic compressional ∆t measurements. This particular well was the first successful use of any 9 1 ⁄ 2-inch sonic logging-while-drilling tool in a 30-inch hole. This paper will discuss the operational aspects and lessons learned in acquiring and interpreting LWD compressional ∆t data in large boreholes.Logging tool selection and description. The 9 1 ⁄ 2-inch LWD sonic tool was run in combination with 9 1 ⁄ 2-inch directional, annular and b...
Accurate reserve volume determination is crucial in the early stages of a project since planned subsurface capacity is dependent on reserve expectations. The fundamental method of calculating reserves uses bulk formation resistivity and bulk porosity to determine water saturation. This approach cannot accurately quantify reserves in laminated sand-shale sequences where the sensor resolution is insufficient to characterize the fine laminae. A tensor petrophysical model can determine laminar shale volume and laminar sand-fraction conductivities reducing the problem to a single dispersed shaly sand model. Combining this with sand-fraction porosities can lead to accurate reserve quantification.Identification and quantification of hydrocarbons within low-contrast, low-resistivity formations can be difficult when using conventional log data. This is primarily due to the presence of laminar shale and the inherent vertical resolution of measurements acquired by wireline and logging while drilling (LWD).A Gulf of Mexico deepwater example is used to demonstrate this novel approach in quantifying hydrocarbons in laminated sand-shale sequences. Real-time shear slowness is used in conjunction with LWD triple-combo data to identify potentially productive low-contrast reservoirs. Then, advanced resistivity post processing extracts the vertical component of resistivity, enabling calculation of sand-fraction resistivity. Sand-fraction resistivity, combined with normalized sand-fraction porosity, yields sand-fraction water saturation. Shale volume, porosity and water saturation cut-offs determine the net hydrocarbon volume. The LWD-calculated hydrocarbon volumes in place are then compared to results obtained from a wireline logging suite.This approach demonstrates that the use of conventional empirically derived bulk-volume porosity and saturation methods in laminated sand-shale sequence formations results in underestimation of the reservoir producibility and hydrocarbon reserves. Vertical resistivity, derived from LWD-acquired propagation resistivity and electrical anisotropy sensitivity, can be used to quantify reserves in these environments.
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