In this paper we demonstrate the advantages of a new multicomponent induction wireline instrument to measure true horizontal and vertical resistivities utilizing a field data example. These data were incorporated in an enhanced shaly sand tensor resistivity petrophysical analysis and resulted in an approximate 20% increase in calculated gas-in-place reserves over the previously used methodologies. Petrophysical results agreed well with conventional routine core analysis and production well test data. 3DEXSM Rh and Rv and conventional wireline log data were acquired in a deep marine turbidite sequence. The example well contained significant volumes of thinly bedded, laminar silty shales and high porosity gas sands that were deposited over very high quality massive channel and turbidite fan complex sands. A high anisotropy ratio, Rv/Rh, indicated the presence of high quality laminar sand pay in a 37-meter interval above the more massive gas-bearing sands. This was qualitatively confirmed by resistivity and acoustic imaging logs. The initial results of effective porosity, and effective water saturation (Indonesian) petrophysical analysis utilizing Array Laterolog deep resistivity (SFR 50–inch depth) data resulted in anomalously high water saturations and poorer apparent reservoir quality in these thinly bedded shaly sand intervals. A second analysis was performed utilizing both horizontal and vertical resistivities in a tensor resistivity model. The laminar shale volume calculated from the 3DEX resistivity data agreed well with NMR-derived shale volume from clay bound water (CBW) data. These results were used in a Thomas-Stieber volumetric model to determine the final laminar-dispersed shale distribution and laminar sand total porosity. Laminar sand resistivity was also calculated from the 3DEX horizontal and vertical resistivity data and used in a Waxman-Smits water saturation model to determine the true laminar sand water saturation. This analysis indicated that the laminar sands were generally of similar quality as the more massive sands. The tensor resistivity analysis indicated a low water saturation in the laminar sand section and is consistent with a capillary water saturation model in a dry gas reservoir. The increase in hydrocarbon saturation resulted in a significant increase in the initial GIP (Gas-In-Place) estimates. Two subsequent production well tests, comparable on a roughly equal net sand basis, choke size, and flowing tubing pressure, confirmed that the laminar sand section was capable of flowing gas at rates similar to the more massive sands without significant pressure draw down. The addition of true vertical resistivity combined with horizontal resistivity in a tensor petrophysical model provides additional new information about laminar shale volume and laminar sand resistivity in thinly bedded, hydrocarbon-bearing reservoirs. Utilizing a true volumetric petrophysical model and determining the laminar-dispersed shale distribution results in a more accurate shaly sand reservoir characterization and, as demonstrated in this example, resulted in a significant increase in hydrocarbon volume evaluated.

The Harding Field was discovered in 1988 and lies within Block 9/23b, 320 km NE of Aberdeen, on the western flank of the Crawford Ridge. Appraisal drilling found a series of Tertiary accumulations along the Crawford Ridge, and, though most have an apparent element of stratigraphic trapping, a larger structural closure is possible. The present development comprises two heavy oil accumulations, Central and South, reservoired in massive sands of the Eocene Balder Formation. Deposited by mass flow processes, these clean and well-sorted sands have been further homogenized by post depositional remobilization and injection. There are seven horizontal producers in Central and three in South, with pressure support by water injection. Reservoir quality is exceptional, with permeability in excess of ten darcies and Pi's for the horizontal producers in excess of 1000 STB/psi. Production started in April 1996 achieving a plateau rate in excess of 90 MMSTBPD with 40% of the estimated 200 MMSTB reserves recovered in the first three years.Four smaller Tertiary satellite pools are presently under appraisal and development by extended reach drilling from the platform.

TX 75083-3836, U.S.A., fax 01-972-952-9435.Where tensor resistivity data is available it can significantly improve the geological models used for geosteering. Incorporation of this data can predict anomalies not seen on simple models, which may be interpreted incorrectly resulting in unnecessary wellbore deviations, and loss of reservoir penetration. Examples of these effects, and their magnitude, will be used to demonstrate the importance of incorporating electrical anisotropy in the models.

No abstract

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractWhile drilling wells in the Total operated Franklin, Elgin and Shell operated Shearwater HPHT fields of the UK central North Sea, gas was often encountered over intervals in the Upper Cretaceous Hod Formation. In addition, gas continued to bleed occasionally into the well until the section TD. During the completion phase of a Franklin well, the annulus pressure started to rise and a temperature and gamma ray survey indicated that fluid was bleeding into the annulus from a thin zone within the Hod Formation. Given the common issues, the so-called "Hod Geohazard" was identified for further shared study between the two operators.The key to these improvements was the collaboration of operators sharing experiences. It resulted in improved drilling and completion practices for both companies during their projects. The lessons learned can be applied by other operators in similar challenging HPHT environments.