|Theme||Visible||Selectable||Appearance||Zoom Range (now: 0)|
Fadjarijanto, A. (Carigali-PTTEPI Operating Company) | Rachmadi, A. (Carigali-PTTEPI Operating Company) | Setiawan, A. S. (Carigali-PTTEPI Operating Company) | Praptono, A. (Halliburton) | Suriyo, K. (Carigali-PTTEPI Operating Company) | Simatupang, M. H. (Carigali-PTTEPI Operating Company) | Pakpahan, O. (Carigali-PTTEPI Operating Company) | Costam, Y. R. (Carigali-PTTEPI Operating Company) | Zakaria, Z. U. (Carigali-PTTEPI Operating Company)
Abstract Fluid identification is a key component of formation evaluation and becomes one of the important parameters that underlie economic decisions in field development. The combination of high clay content in the thinly laminated shaly-sand reservoir, together with unknown water salinity, increases the complexity in the accurate quantification of hydrocarbon-bearing reservoirs. The inherent clay distribution affects the log data response of high gamma and low resistivity analyses. Those responses can lead to incorrect interpretations unless other log data responses are considered. The low resolution of a common oil-based resistivity tool often fails to capture structurally complex, thinly laminated sand-shale formations. The low resistivity response results from high resistivity sand layers suppressed by low resistivity shale layers, which can result in misinterpretations of calculating high water saturation. Observations of other conventional well log data can provide early qualitative identification of the low contrast zone. Data from the Thomas-Stieber method, resistivity anisotropy, and high-resolution micro-imaging are available to reconstruct conventional log data to provide an enhanced vertical resolution for final interpretations. A field study was performed in the North Malay basin. Geologically, the field has three-way dip closure, bounded by a west-dipping fault to the west. The early evaluation of the DS2-B layer was interpreted as shale zones following a high gamma and low resistivity reading. Further observation of the density, neutron, and shear sonic trend do not provide the same shale indication. The decision was made to run a formation tester tool and to investigate any possible hydrocarbon indication. Real-time fluid identification and sampling proved the DS2-B layer to be gas-bearing and indicated that the conventional petrophysics-calculated water saturation was too high. Three petrophysics re-evaluation approaches were performed to define the reservoir challenges, including deterministic, Rv/Rh methods, and high-resolution data approach to obtain a better definition. All available data were used on the methodologies, based on the data required for each method, particularly the use of high-resolution imaging and core data for conventional logs to define the high-resolution of porosity, clay volume, and water saturation. As a result of these analyses, the DS2-B layer was proven to be a pay zone with a lower water saturation, which correlated with the formation sampling and core analysis results. The methodology has a proven capability to identify low contrast zones and can provide better interpretation in the field study through providing more a precise and accurate net-to-gross calculation. The correlation and calibration of the conventional well log data to high vertical resolution image log, core data, and fluid sampling have provided a means of better visualizing and understanding the features of thinly bedded reservoirs in the field study. All methods were performed to calculate the final fluid saturation in highly laminated reservoirs. The new interpretation has proved a significant contribution to the NM field economic value.
Kyi, Ko Ko (PETRONAS Carigali Sdn Bhd) | Jin Wang, Arthur Goh (PETRONAS Carigali Sdn. Bhd.) | Quirein, John (Halliburton Energy Services Grp) | Najm, Ehab (Halliburton Energy Services (M) Sdn Bhd) | Roy, Dipanka (Halliburton Energy Services (M) Sdn Bhd) | Lee, Chung Yee (Halliburton Energy Services (M) Sdn Bhd)
Micro and macroscopic-anisotropic reservoir characterization has, recently, been performed using two main approaches:applying the Thomas-Stieber technique on uniaxial resistivity or applying the tensor model technique using multicomponent induction measurements. The output from either technique is the sand resistivity, RSand, and sand volume, VSand, with accurate water saturation, Sw, as a result of overcoming the effect of laminated shale on the resistivity measurement, which eventually will translate into enhanced hydrocarbon recovery and optimized reservoir development. Some of the key challenges in both techniques are the proper understanding of the total porosity and volume and the distribution of shale in the reservoir in terms of laminated and dispersed forms, which, if in error, will drastically increase the uncertainty of processing results. Additionally, the dependence of fluid density on the saturation and the dependence of the saturation and cementation exponents, m and n, on the total porosity, as well as the silty nature of the sand, all contribute to the complexity. Oil mud resistivity imager and nuclear magnetic resonance (NMR) logs, as well as elemental analysis (if available), were used to confirm the lamination nature of the shale in the reservoir, minimizing uncertainty on total porosity estimation and clay bound water (CBW) calculation. They were also used to help account for the presence of silt-sized sand. This paper provides a complete rock model and a comprehensive workflow that takes into account all of the necessary stages required to estimate water saturation in a thinly bedded sand-shale sequence, where both laminated and dispersed shale types can exist. Also, the paper presents a simple sensitivity analysis performed to understand the uncertainty on the processing parameters and estimated volumetrics on the results when using different techniques compared to the proposed technique in this study. Data used in this paper are from a well drilled in the Malay basin, offshore Malaysia.
Gomes, R.M. (Petrobras E&P) | Denicol, P.S. (Petrobras E&P) | da Cunha, A.M.V. (Petrobras E&P) | de Souza, M.S. (Petrobras E&P) | Kriegshiuser, B.E (Baker Atlas) | Payne, C.J. (Baker Atlas) | Santos, A. (Baker Atlas)
Page, Geoffrey C. (Baker Atlas) | Fanini, Otto N. (Baker Atlas) | Kriegshäuser, Berthold F. (Baker Atlas) | Mollison, Richard A. (Baker Atlas) | Yu, Liming (Baker Atlas) | Colley, Nick (BG Energy Holdings Ltd.)
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.