Abu Butabul Field is located within onshore Oman Block 60 in the Western region of the Central Oman Desert (Figure 1). Gas-condensate was discovered in the field in 1998. The main reservoir is the Cambro-Ordovician clastic Bank formation, which is buried over 4200 m below sea level with very low porosity and permeability. Wellbore instability related drilling problems were encountered while drilling most of the appraisal wells in the field. The problems were mainly in the shallower Natih and Nahr Umr formations, Gharif formation and deeper Safiq, Ghudun and Mabrouk formations. A geomechanical modeling study was conducted in the field to understand the causes of the wellbore instability problems and to provide recommendations for drilling new wells. Data from nine wells were analyzed and used for the construction of 1-D mechanical earth models. Rock mechanical testing data on core samples and pressure and stress memasurement were integrated in the models. Wellbore stability analysis of those wells provided insight into the causes of the wellbore instability problems. To predict wellbore stability at any location in the field more efficiently and capturing the lateral formation property variation as indicated by the seismic data, a 3-D geomechanical model was constructed and subsequently used for predicting wellbore stability for new wells to be drilled in the field and hydraulic fracturing pressures for fracturing stimulation of horizontal wells. This paper describes the process of constructing the 1-D mechanical earth models, performing wellbore stability analysis for the appraisal wells, Integeration of 3D seismic Inversion, constructing the 3-D geomechanical model, predicting wellbore stability for new wells using data contained in the 3-D model and post-drill wellbore stability analysis of the planned wells.
For a tight reservoir, assessment of zonal production contribution is often possible only after the reservoir has been hydraulically fractured. Spinner survey is commonly the tool of choice for diagnosing relative production contribution across perforated interval in a cased-hole and by extension, minimum productive fracture height at the wellbore. However, its limited radial resolution renders such tool unreliable in evaluating flow characteristic within fracture body and across fracture planes. The acquired data is generally insufficient for resolving relative contribution of various productive horizons intersected by the fracture. As the measurements are focused on flow characteristics inside the wellbore, fracture height diagnosis is limited by the extent of perforation interval. Alternatively, radioactive tracing and microseismic survey allow one to see through the casing wall albeit at the expense of heightened cost and operational complexity. Thermal logging, being a cheaper alternative, is time-sensitive and not deployable immediately following proppant placement due to restricted wellbore access. Most importantly, hydraulic and propped fracture heights diagnosed by these methods may not necessarily coincide with effective fracture height that contributes directly to well productivity. Integrating acoustic logging to conventional production logging measurements may, in addition to increasing resolution for low flow measurement, significantly extend the investigation radius beyond casing wall. Different acoustic characteristics potentially exhibited by flow of different fluid phases may also validate conventional log-derived reservoir fluid types. The paper describes the application of acoustic logging in diagnosing zonal production contribution, fracture height, and reservoir fluid type across hydraulically fractured tight gas condensate and oil reservoirs. In four naturally flowing wells, zonal production contribution derived from acoustic wave analysis and conventional production log data were both in good agreement. The analysis of depth-specific acoustic wave amplitude provided useful insight in the diagnosis of zonal production contribution and by extension, productive fracture height. In one well, acoustic-derived fracture height could be closely corroborated with that of radioactive tracer data. In addition, one may also observe distinct shape of maximum amplitude of first sound wave arrival in a gas well compared to that in an oil well.
Tight unconventional reservoirs have become an increasingly common target for hydrocarbon production in Oman. Exploitation of these resources requires a comprehensive reservoir description and a characterization program to estimate reserves, identify properties that control production, and account for fracturability. It is becoming evident, however, that any single technology by itself is unable to address all the key challenges, and the integration of technologies is crucial to answer all the questions to reduce key subsurface uncertainties. This paper discusses in detail a case study in which the integration of advanced petrophysical logs has enabled successful downhole sampling and provided a comprehensive reservoir and fluid characterization despite the very challenging lithologies and very tight formation. The comprehensive logging suite included advanced measurements of dielectric dispersion, nuclear magnetic resonance (NMR), and spectroscopy. The reservoir fluids and dynamic properties were also characterized by a series of formation testing measurements. Dielectric dispersion logs clearly identified the hydrocarbon-bearing zones despite the characterless resistivity profile, taking advantage of its resistivity-independent saturation approach. The accuracy of the measurement was key to estimating water- filled porosity down to 0.5 p.u. regardless of the formation water salinity and changes in the rock electrical parameters. The integration of dielectric and NMR measurements, reflecting the pore structure, has played a major role in identifying the "best" reservoir intervals and indicating the type of fluid (hydrocarbon or water) filling the free pore space. The NMR unimodal and bimodal T2 distributions revealed the pore structure along with polarization effects on light hydrocarbons, helping to gain insight on the reservoir quality. The NMR was also combined with the microimaging measurements to indicate pore connectivity and formation heterogeneity. This integrated approach was applied to a deep tight-gas exploration well and has contributed to achieving successful formation sampling that provided an in-situ fluid characterization despite the tightness of the rocks, with only 4 p.u. average porosity. Integrated logging measurements along with fluid sampling resulted in both enhanced formation and fluid characterization in this exploratory well, shedding light on the hydrocarbon potential over the region.
Interpretation of logs from an exploration pilot well and a lateral drilled from the pilot in the Late Cretaceous Natih formation in the Sultanate of Oman was used for designing a multistage hydraulic fracturing treatment. A high-tier logging suite including borehole image, advanced dipole sonic, geochemical, and triple combo data was acquired in both wellbores. The objective of the pilot hole was to select the best landing point in terms of reservoir quality (RQ) and completion quality (CQ) so that a horizontal well could be drilled and multistage stimulations performed in the organic-rich Natih B source rock. In contrast to much of North America, significant tectonic forces are frequently present in this region. The geomechanical setting might thus strongly affect hydraulic fracture initiation, propagation and proppant placement. It therefore plays an important role in lateral landing point selection. Borehole images, integrated with petrophysical and geomechanical log properties, were used to identify the optimum landing zone. Breakouts as well as longitudinal and transverse drilling-induced fractures were identified on the pilot borehole images over the Natih Formation, indicating a large horizontal stress anisotropy and a compressional tectonic setting. An interval from which vertical hydraulic fractures would initiate at low initiation pressure and grow vertically to contact intervals with good RQ was selected as the target lateral landing point. Image and dipole sonic data were acquired in the horizontal well, and both longitudinal and transverse induced fractures were identified. Those data were used to selectively place hydraulic fracturing stages. Diagnostic injection tests on each stimulation treatment confirmed low fracture initiation pressures and the creation of vertical hydraulic fractures, thus validating the selection of both the landing point and the location of the hydraulic fracture initiation points. All treatments were successfully placed to completion. This paper demonstrates that a workflow based on the combination of image and dipole sonic logs in both a pilot well and a lateral drilled from the pilot enables the creation of vertical hydraulic fractures at moderately low initiation pressures and successful placement of stimulation treatments in the lateral. This technique shows promise for effective hydraulic fracturing in regions where significant tectonic forces are present.
In deep tight shaly-sand reservoir, with complex hydrocarbon charge and structural growth history, it is difficult to characterize reservoir zones with high water cut from others with low water cuts and high hydrocarbon production rate, due to high resistivity readings of tight reservoirs. Deep reservoir "B" in Abu Butabul Field, NW Oman has been charged via two genetically and chronologically different hydrocarbon phases (oil then gas); during a complex deep burial digenesis and structural trap history. Due to the variation of Hydrocarbon properties of such tight reservoir, it has been difficult to analysis such a reservoir using conventional petrophysical evaluation methods. In this study, a modified version of the approach published by Ibrahim, Abd_Elmoula, Said Hasani, Sultan, Jahwari in SPE 130261 in which Ro (Resistivity of Rock saturated with Formation water) and SWirr (irreducible water saturation) used to distinguish water from hydrocarbon zones has been taken a step further in order to predict water cut in tight reservoirs (illustrated in the workflow below). After calculating wireline logs derived permeability, there are two elements to be calculated: KHw (Permeability of sands units filled with water * thickness of these sand units), and KHhc (Permeability of sands units filled with hydrocarbon *thickness of these sand units). The ratio of KHw/(KHhc+KHw) provides a mean of estimating percentage of the expected water production. This approach has been validated with actual water cut from production data. Using mathematical product of KHhc*Phie (effective porosity)*(1-SW) provides a mean to rank the wells in terms of expected Hydrocarbon productivity, which then can be contoured and utilized for reservoir fracturing program of the reservoirs in promising wells.
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