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ДОДАТОК

Petrophysical analysis of well logs from Manitou Lake, Saskatchewan

Maria F. Quijada and Robert R. Stewart

ABSTRACT

This report presents the log analysis results from three wells in the Manitou Lake area, in west central Saskatchewan. A 3C-3D survey was acquired in the area by CALROC Energy LTD. in February 2005, with the Colony sand and Sparky members as exploration targets. The log analysis indicates that the Colony and Sparky members have very high porosities, up to 37 % and very low water saturation. The water resistivities calculated from the 3 different water zones give consistent values, between 0.12 and 0.15Ùm, which is consistent with resistivities from the catalog for that area. Extremely high permeabilities were obtained in the Colony interval, probably due to the lack of calibration of certain parameters in the formula with core data, especially for the CPERM parameter which can take on a wide range of values. Future work involves the calibration of the log analysis with core, test and production data from nearby wells.

INTRODUCTION

This paper shows the results from the interpretation of three sets of logs from the Manitou Lake area in west central Saskatchewan (Figure 1). The log analysis is intended to support reservoir evaluation; as well as help interpret a 3C-3D seismic survey acquired by Kinetec Inc. in the area in February 2005 for Calroc Energy Ltd. The Colony and Sparky members of the Mannville Group are currently producing oil in the area, and are the main exploration targets of the survey. The general purpose of well log analysis is to convert the raw log data into estimated quantities of oil, gas and water in a formation (Asquith and Krygowski, 2004). A review of the general stratigraphy of the area is presented, focusing on the two target formations, followed by the petrophysical analysis of logs from three wells in the area. Permeabilities, productivity and reserves are calculated for several zones of interest.

STRATIGRAPHY OF THE AREA

Deposition in the Western Canada Sedimentary Basin can be divided into two successions, based on two different tectonic settings affecting sedimentation. The Paleozoic to Jurassic platformal succession, dominated by carbonate rocks, was deposited on the stable craton adjacent to the ancient margin of North America. The overlying mid- Jurassic to Paleocene foreland basin succession, dominated by clastic rocks, formed during active margin orogenic evolution of the Canadian Cordillera, with the emplacement of imbricate thrust slices progressively from east to west . The exploration targets in the area are the Colony sand member of the Pense Formation, and the Sparky member of the Cantuar Formation, both part of the Cretaceous Mannville Group. In the area, the Mannville Group lies unconformably on Paleozoic strata, and its sedimentary pattern consists of an interplay of marine, estuarine and fluviatile agents acting in a setting controlled by paleo-topographic relief and eustatic and tectonic changes in relative sea-levels (Christopher, 1997). The Sparky member is informally grouped into the middle Mannville, which is dominated by sheet sandstone development, with narrow, channel sandstones and shales also present (Putnam, 1982). These units have been interpreted as a delta-front facies with associated tidal-flat, tidal-channel, and beach environments (Vigrass,1977). In the case of the Sparky member, the sheet sandstones are commonly 6-9 m thick, and can be traced laterally for several tens of kilometers; however, they are commonly broken by thick ribbon-shaped deposits or sandstone pinchouts (Putnam, 1982) The Colony sand member consists of shales, siltstones, coals and sandstones. Deposition of this member occurred in an extensive complex of anastomosing channels sandstones, encased within siltstones, shales, coals and thin sheet sandstones (Putnam and Oliver, 1980). Figure 2 shows a schematic depositional model for the Colony sands, including the three distinct facies: channel, crevasse splay and interchannel wetlands. The Colony sand member is unconformably overlain by the Joli Fou marine shale, representing the basal unit of the Colorado Group, which is dominated by marine shales encasing generally thin but extensive sandstones, such as the Viking, Dunvengan and Cardium formations (Leckie et al., 1994).

WELL LOG DATA

A suite of logs from three wells in the area was provided by CALROC Energy Ltd. for this study. Three wells were available for this study (A11-17-44-27, C07-16-44-27 and C10-17-44-27) with a suite of logs, including gamma-ray (GR), spontaneous potential (SP), density (RHOZ), neutron and density porosity (PHIN and PHID), caliper, and resistivity, among others. A P-wave sonic log is available in wells C07-16 and A11-17, which also has an S-wave sonic. All wells are located within sand channels of the Colony, but only A11-17 is producing oil from this interval, while the other two produce oil from the Sparky B. In all wells, there is a sharp decrease in the GR and SP curves at the top of the Mannville, indicating clean and permeable zones. The photoelectric factor is around 2 for most of the Mannville section (See Figure 4), indicating that sandstone is the dominant lithology. At the top of the Colony there is some crossover between the neutron and density porosity, possibly indicating the presence of gas. This crossover is very thin in wells A11-17 and C10-17, but significantly more evident in well C07-16. This well also shows a much thicker Colony channel, saturated with gas, oil and water. The contacts between these fluids were interpreted based on the porosity cross-over (gas/oil) and the resistivity curve (oil/water). Another interesting effect is seen at the top of the Colony sand, where there is a sharp increase on the S-wave velocity but almost no change on the P-wave velocity (Figure 4), probably due to the lithologic change between sand and shale, which is seen by the S-wave but not the P-wave.

LOG ANALYSIS

The first step in a log analysis is to identify the zones of interest (clean zones with hydrocarbons), and define clean and shale baselines on the logs. The top of the Colony sand is clearly identified in all wells by a significant deviation to the right in the GR, SP and porosity logs, as we pass from the marine shales of the Joli Fou formation to the channel sands of the Colony member. The depth of this top varies between 547.5 m and 554 m in the three wells. The Sparky B member is thinner and shalier than the Colony in these particular wells, with lower resistivities but similar porosities. The zones of interest for the petrophysical interpretation were defined in terms of clean zones with hydrocarbon saturation (low GR and high resistivity), as well as two water zones used to calculate water resistivity at formation temperature, which is necessary to calculate water saturation and permeability. Areas shaded in red in figures 3-5 indicate gas zones, interpreted from crossover of the porosity logs, green shaded areas correspond to oil zones, based on high resistivity values, and blue shaded areas correspond to water zones (very low resistivities). After picking clean and shale lines on the logs, the next step is shale volume estimation. In this study, shale volume (Vsh) was calculated by the three common methods (Equations 1 to 3), which use values from the gamma ray (GR), spontaneous potential (SP), and neutron (PHIN) and density (PHID) porosity logs, with the minimum of the three being selected as the shale volume GR, SP, PHIN and PHID are the picked log values, while clean and shale indicate values picked in the clean and shale base lines, respectively. Porosity from logs is considered total porosity (PHIt), which includes the bound water in the shale; to obtain effective porosity (PHIe) it must be corrected for shale volume. When both the neutron and density porosity curves are available, as in this case, the best method for correcting porosity is the Complex Lithology Density Neutron crossplot. First, porosity is corrected for shale volume by ( ) PHIxc = PHID − Vsh × PHI shale (4), where x will be n for neutron or d for density porosity. This method works equally well in quartz sands as in mixtures, except in areas with bad hole conditions which affect the density reading (Crain, 2006). The density and neutron porosity logs show cross-over at the top of the Mannville, suggesting the presence of gas. For this reason, the porosity in the uppermost interval was corrected using the equation for neutron-density porosity in a gas zone (Asquith and Krygowski, 2004) To calculate water saturation, most methods require a water resistivity (Rw) value. In this case, an obvious clean water zone is present in two of the wells in the area and the water resistivity was calculated from the porosity and resistivity in this zone, using the Ro method, given by the following equation: Finally, the productivity and reserves of the intervals of interest are estimated, along with an estimated flow rate. These values are a useful way of comparing the quality of wells from similar reservoirs, even when results are not calibrated (Crain, 2006).

RESULTS

The previous methodology was applied to the 4 zones of interest defined in each well

(See Table 1). The first zone in all wells corresponds to gas saturated sands in the Colony member, while the second zone corresponds to oil saturated sands within the same formation. A water zone was also interpreted in each well, and was used to calculate water resistivity. Wells A11-17 and C10-17 are located very close to each other within the same sand channel (Figure 6), and the log analysis results in very similar values for the different parameters in both wells. The Colony channel has a thickness of approximately 8 m in both wells, with a gas cap of 2 m, and the remaining 6 m being saturated with oil. The Sparky B member shows a thickness of 3 m. Porosities are very high in all the interpreted zones, ranging from 0.3 to 0.38. The difference between neutron and density porosity is small in all zones, except where there is gas present and significant cross-over occurs. This, coupled with the low shale volumes, results in effective porosities very similar to the total, except in the gas bearing zones, where a corrected equation for effective porosity is used and results in lower porosity values. The three water zones used to calculate water resistivities at formation temperature give consistent results, between 0.13 and 0.15 Ùm. Permeabilities calculated within the oil zone in the Colony sand are extremely high (between 8000 and 30000 mD) due to the very high resistivities and porosities of the interval. This probably implies that the default values of CPERM, EPERM and DPERM used are not appropriate for this area, and calibration with core is necessary to obtain better parameters. However, other studies in the Pikes Peak heavy oil field (Zoue et al., 2006) show similar results for the Waseca channel facies, with oil saturation of 80 %, porosities around 34 % and permeabilities of 5000 md.

CONCLUSIONS

The log analysis performed shows that Colony sand contains significant accumulations of oil. The sand channel has an average thickness of 7 m, and effective

porosity in the order or 0.35. The Sparky interval in these wells is very thin, with an average thickness of 3 m, it has a higher shale volume and lower resistivities, as well.

However, the wells used are specifically located within the interpreted trend of a Colony channel, which doesn’t coincide with interpreted channels in the Sparky member. Further calibration of the log analysis parameters with core, test and production data is necessary to verify the calculated values, as the permeabilities for the Colony member are extremely high. Logs from wells A11-17 and C10-17 provide very similar results, which are expected due to their proximity and their location within the same interpreted sand channel. However, well C07-16 shows a Colony interval which is considerably thicker than in the other wells, with a log character which is different from the other wells, suggesting the well could be located on a different channel. This well shows higher reserves; however, the reservoir appears to be of lower quality, as the permeabilities and flow rates are lower than the other wells.