In a vertically transverse isotropic (VTI) medium, accurate prediction of the vertical and horizontal Young's moduli (E) and Poisson's ratios (ν) is crucial to predicting minimum horizontal stress (σhmin) and hence selecting drilling mud, cement weights, and perforation locations. Fully characterizing geomechanical properties of VTI shale requires five independent stiffness coefficients: C33, C44, C66, C11, and C13. In a vertical well, C33 and C44 are directly calculated from the velocity of the vertically propagating P- and S- waves, while C66 is estimated from the Stoneley wave velocity. To obtain C11 and C13, an empirical model must be employed. This study integrates laboratory mechanical and sonic measurements to evaluate the ANNIE and modified-ANNIE models and extend the dynamic-to-static conversion equation. Laboratory static and dynamic geomechanical methods were applied to multiple core materials extracted at different depths from a target shale play. The dynamic elastic moduli were measured using a laboratory sonic scanner; velocities were measured in different directions to obtain C33, C44, C11, C66, and C13. The dynamic data were then applied in the ANNIE and modified-ANNIE models for estimating the dynamic elastic moduli, including dynamic Young's modulus and Poisson's ratio. The static elastic moduli were measured using axial compression experiments; horizontal and vertical core plugs were tested to account for anisotropy. Static and dynamic results illustrated horizontal Young's moduli were predominantly higher than vertical Young's moduli, which suggested a horizontal layered structure. Vertical Poisson's ratios can be greater or smaller than horizontal Poisson's ratios, which is consistent with the prediction of the modified-ANNIE model. Conversely, the ANNIE model always predicts ν(vert) ≥ ν(horz). Static and dynamic data illustrated the anisotropic σhmin was predominantly higher than the isotropic σhmin. This implied that using an isotropic model to predict laminated shale will underestimate σhmin. It was noticed that the static Young's modulus increased with decreasing porosity for the target interval. The elastic moduli measured from the dynamic method were consistently higher than those measured from the static method. The dynamic and static data were used to fit the widely-used dynamic-to-static conversion equations—the Canady and Morales equations. The Canady equation was extended to the "very hard" (greater than 70 GPa Young's modulus) regime, while the Morales equation was extended to the regime of porosity < 10%. Finally, σhmin predicted by different models was compared with the measurements, showing that modified-ANNIE improved the prediction by solving the stress underestimation issue of the ANNIE and isotropic models.
In a deepwater environment, testing of wells can be an expensive process coupled with safety concerns. Properly characterizing a well has a significant impact on asset management. Wells are routinely stimulated to remove formation damage, but subsequent testing to determine the skin after stimulation is rarely performed. This paper discusses a case study where multirate multizone (MRMZ) pressure-transient testing and production logging was performed in a deepwater well in the Gulf of Mexico (GOM) to determine the effectiveness of the stimulation treatment. MRMZ production logging was performed across the targeted pay intervals. The process was to flow the well at three different flow rates followed by a shut-in period. During these different rates, production logging was performed by three up and three down passes at each choke setting, followed by a stationary measurement at a predetermined depth for 10 to 15 minutes. Following the last production logging run, the tool was parked between the two pay zones, and the well was shut in for a pressure buildup until radial flow was fully established. After that, the tool performed the final routine production logging passes while the well was still shut in. Although the oil production almost doubled after the initial stimulation treatment with xylene, the high skin observed in real time from the MRMZ pressure-transient analysis prompted the operator to change the formation damage removal program and stimulate with hydrochloric acid (HCl) by coiled tubing rather than only xylene. This resulted in an immediate fourfold improvement of productivity index with a potential of further doubling. MRMZ testing is a relatively low-risk, low-cost method for acquiring valuable formation data. This paper additionallydiscusses best practices that should be performed while attempting MRMZ and how deviating from these practices can lead to increased uncertainty in the acquired data.
Reservoir relative permeability and capillary pressure, as a function of saturation, is important for assessing reservoir hydrocarbon recovery, selecting the well completion method, and determining the production strategy because they are fundamental inputs to reservoir simulation for predicting lifetime production of a well. Estimation of relative permeability and capillary pressure curves at reservoir conditions is also an important task for successful planning of waterflooding and enhanced oil recovery. The relative permeability and capillary pressure data estimated from core analysis might cause concern regarding representativeness, and adjustments are typically necessary for successful production forecasting. This paper proposes a new method to obtain relative permeability and capillary pressure curves with downhole pressure-transient analysis (PTA) of mini-drillstem tests (miniDSTs) and well log-derived saturations. The new approach was based on performing miniDSTs in the free water, oil, and oil-water transition zones. Analyses of the miniDST buildup tests provided absolute formation permeability, endpoints of relative permeability to both oil and water, and curvature of the relative permeability data. Additionally, resistivity, dielectric, and nuclear magnetic resonance (NMR) logs were used to determine irreducible water, residual oil, and transition zone saturations. Combining these downhole measurements provided the relative permeability and capillary pressure curves.
Flow assurance is a vital challenge that affects the viability of an asset in all oil producing environments. A proper understanding of asphaltene precipitation leading to deposition lends itself to reliable completions planning and timely remediation efforts. This ultimately dictates the production life of the reservoir. The Wireline Formation Tester (WFT) has traditionally aided the understanding of asphaltene composition in reservoir fluids through the collection of pressurized fluid samples. Moreover, the use of Downhole Fluid Analysis (DFA) during a fluid pumpout has augmented the understanding of soluble asphaltenes under in-situ flowing conditions. However, an accurate and representative measurement of Asphaltene Onset Pressure (AOP) has eluded the industry. Traditionally, this measurement has been determined post-acquisition through different laboratory techniques performed on a restored fluid sample. Although sound, there are inherent challenges that affect the quality of the results. These challenges primarily include the need to restore samples to reservoir conditions, maintaining samples at equilibrium composition, and the destruction of fluid samples through inadvertent asphaltene precipitation during transporting and handling. Hence, there is a need for WFT operations to deliver a source of reliable analysis, particularly in high-pressure/high-temperature (HP/HT) reservoirs, to avoid costly miscalculations. A premiere industry method to determine AOP under in-situ producible conditions is presented. Demonstrated in a Gulf of Mexico (GOM) reservoir, this novel technique mimics the gravimetric and light scattering methods, where a fluid sample is isothermally depressurized from initial reservoir pressure; simultaneously, DFA monitors asphaltene precipitation from solution and a high-precision pressure gauge records the onset of asphaltene precipitation. This measurement is provided continuously and in real time. An added advantage is that experiments are performed individually after obtaining a pressurized sample in distinct oil zones. Therefore, the execution of this downhole AOP experiment is independent of an already captured fluid sample and does not impact the quality of any later laboratory-based analysis. Once the measurements are obtained, these can be utilized in flow assurance modeling methods to describe asphaltene precipitation kinetics, and continuity of complex reservoirs. For the first time in literature, this study applies these modeling methods in combination with the AOP data acquired from a downhole WFT This approach has the potential to create a step change in reservoir analysis by providing AOP at the sand-face, along with insight that describe performance from asphaltene precipitation. The results of which have tremendous economic implications on production planning.
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