TY - JOUR
AU - Farooqui, M, Y
AB - Abstract Unconventional reservoirs such as fractured basalts, shale gas and tight sand are currently playing an important role in producing a significant amount of hydrocarbon. The Deccan Trap basaltic rocks form the basement of the Cambay Basin, India, and hold commercially producible hydrocarbon. In this study two wells drilled through fractured basalts are chosen for evaluating the lithology, porosity and oil saturation of the reservoir sections. Well logs, such as gamma ray, high resolution resistivity, litho density, compensated neutron and elemental capture spectroscopy, have been used in cross-plotting techniques for lithology and mineral identification. Formation micro imagery log data have been analysed to quantify the fractures and porosity in the fractured reservoirs for a well in the south Ahmedabad block of the Cambay Basin. The results of the analysis of two wells are presented and discussed and they are found to be in good agreement with geological and production data. Cambay Basin, fractured basement, basaltic reservoir Introduction In petroleum exploration and development, formation evaluation, including porosity, permeability and water saturation measurements, is a very important stage in reservoir characterization and hydrocarbon reserve estimation. Oil has been obtained from many volcanic naturally fractured reservoirs around the world such as the Jatibarang field in Indonesia, where production has been obtained from Eocene and Oligocene lavas, the Jatibonico pool in Cuba, where more than 1200 wells were drilled in fractured serpentines, the Pina reservoir in Cuba, where production has been achieved in Upper and Lower Cretaceous tuffites, the Hilbig pool in Texas, which produced from Cretaceous palagonites, the McArthur River field, Cook Inlet in Alaska, which produced oil from Jurassic tuffites and volcanic sands and the Kora oil field in New Zealand, which found producible oil in an Upper Miocene volcanic zone (Aguilera 1995, Bergman et al1992, Kalan et al1994). In recent years, a few volcanic gas reservoirs have been found in the Songliao Basin, north-east China, such as the Wangjiatun, Changde, Shengping, Xingcheng and Changling reservoirs (Ran et al2006). The Deccan Trap basalts, laid down by multiple lava flows during the Paleocene to Upper Cretaceous, are extensive in the western part of the Cambay Basin. In recent years, the basaltic basement has become a proven hydrocarbon producer in some fields such as Padra and Gamji of the Cambay Basin (Kumar et al2002, Kumar 2006). The Cambay Basin, a rich hydrocarbon-producing province, is a narrow elongated rift extending N–S on the western margin of India (figure 1). The basin has over 30 years of exploration history. The total area of the basin is 51 000 sq km including 2500 sq km in the shallow water of the Gulf of Cambay. The entire basin is divided into five tectonic blocks based on transverse fault systems, namely Narmada and Jambusar–Broach in the South Cambay Basin and Cambay–Tarapur, Ahmedabad–Mehsana and Patan–Tharad–Sanchor in the North Cambay Basin (Biswas 1982, 1987). The study area containing the two exploratory wells (A 1 and A 2) is located at the southern part of the Ahmedabad–Mehsana block. The basin is filled with Tertiary and Quaternary sediments laid down on the irregular surface of the Deccan Trap. Exploration for hydrocarbons in this basin was started by ONGC (Oil and Natural Gas Corporation Ltd) around 1956. The generalized stratigraphy of the Cambay Basin (figure 2) exhibits rocks from Cretaceous to recent. The Deccan basalts constitute the basement rock for the major part of the Cambay Basin and are overlain by a thick sedimentary succession of clastic reservoir rocks and shale barriers including the Cambay shale-–the major source rock and the coal beds. Hydrocarbons are produced from the entire Tertiary sequence and are mainly structurally controlled. Important producing zones are located within Middle Eocene and Oligocene sequences. However, the presence of oil in late Early Eocene rocks is not uncommon. Some indications of oil have also been noted in Miocene rocks. This paper presents the results of an integrated study carried out to identify and evaluate the hydrocarbon-bearing intervals of the basaltic basement which are being used as unconventional reservoirs in this part of the study area. Figure 1. Open in new tabDownload slide The study area location in the Cambay Basin, India, with distribution well location in the south Ahmedabad–Mehsana block. Figure 1. Open in new tabDownload slide The study area location in the Cambay Basin, India, with distribution well location in the south Ahmedabad–Mehsana block. Figure 2. Open in new tabDownload slide The generalized stratigraphy of the Cambay Basin (after Banerjee et al (2002) and Kundu et al (1997)). Figure 2. Open in new tabDownload slide The generalized stratigraphy of the Cambay Basin (after Banerjee et al (2002) and Kundu et al (1997)). Methodology for evaluation of basaltic reservoirs Through fractures and weathering, basaltic basement rocks form important hydrocarbon reservoirs in a number of oil fields all over the world (P'an 1982, Landes et al1960, North 1985). The development of reservoirs in basaltic rocks is delicate due to their mineralogy and the way they are affected by weathering. The fractures in basalts are likely to be filled up by precipitation released by the leaching of the mafic and Ca-rich plagioclase present in the basaltic rock. As per core studies provided by previous authors (Kumar et al2002, Kumar 2006), Deccan basalts can be classified into three categories: slightly altered to fresh basalt, moderately altered basalt and highly altered basalt depending on the degree of alteration. The moderately altered basalts showing presence of spheroidal weathering host effective porosity and permeability and are the probable reservoir rock. In this study fractured and weathered basalts are the hydrocarbon producing reservoir in wells A 1 and A 2 in the south Ahmedabad block of the Cambay Basin. The well data in general comprise the following: gamma ray; spontaneous potential (SP); micro spherical focussed log (MSFL); lateral log deep (LLD), deep resistivity tool; lateral log shallow (LLS), shallow resistivity tool; formation density and compensated neutron logs. The logs are first depth matched with respect to the resistivity log. The raw logs are then corrected for the environmental effects as mentioned below. LLD and LLS for borehole effects. MSFL for the mud-cake effect. Neutron porosity (NPHI) for temperature, pressure, salinity and borehole effects. Density and gamma ray for the borehole size. The hole and bed thickness corrected resistivity log is used to determine true resistivity (Rt) of the uninvaded zone, flushed zone resistivity (Rxo) and the invasion diameter. The gamma ray log is used to determine the lithology of the reservoir and non-reservoir rocks. Resistivity logs are analysed for hydrocarbon saturation. Porosity is calculated by both density and neutron logs. Porosity is obtained from the density log and then corrected by clay volume and hydrocarbon fluid content. Water saturation (Sw) is calculated from the following formulae (Setyowiyoto and Samsuri 2008). Determination of porosity: 1 where ΦD is the porosity from the density log (%), Rhoma is the matrix density, Rhob is the bulk density and Rhof is the fluid density. Determination of porosity, corrected by Vsh content: 2 where ΦDc1 is the corrected porosity by Vsh (%), Φ is the porosity (%), Vsh is the shale volume (%) and ΦDsh is the log-density-derived porosity in the shale zone (%). Determination of porosity, corrected by hydrocarbon fluid content: 3 where ΦDc2 is the hydrocarbon fluid corrected porosity (%), ΦDc1 is the Vsh-corrected porosity (%), Shr is the residual hydrocarbon saturation, Sxo is the water saturation in the flush zone, Rxo is the water resistivity in the flush zone, Vsh is the shale volume, Rsh is the resistivity in the shale zone, a is the cementation constant and Rmf is the resistivity of the mud filtrate. Determination of water saturation (Sw)/hydrocarbon saturation (Sh): 4 5 where Rt is the true resistivity and Rw is the water resistivity. Interpretation for well A 1 Well A#1 has been drilled down up to the fractured basaltic formation where oil was encountered in the fractured reservoir. Well log data for the selected depth intervals from 1650 to 1950 m for well A#1 are shown in figure 3. To further know the lithology, cross-plots between density and neutron porosity have been used for three depth intervals, namely 1652–1780 m 1780–1834 m and 1834–1950 m (figures 4–6). The lithology interpretations for these depth intervals are given in table 1. Figure 3. Open in new tabDownload slide The processed logs at the reservoir interval of well A#1 in the Cambay Basin. Figure 3. Open in new tabDownload slide The processed logs at the reservoir interval of well A#1 in the Cambay Basin. Figure 4. Open in new tabDownload slide Density versus neutron porosity: the cross-plot colour coded with gamma ray indicates that the interval of 1650–1780 m contains mostly shales/carbonaceous shales. Figure 4. Open in new tabDownload slide Density versus neutron porosity: the cross-plot colour coded with gamma ray indicates that the interval of 1650–1780 m contains mostly shales/carbonaceous shales. Figure 5. Open in new tabDownload slide Density versus neutron porosity: the cross-plot colour coded with gamma ray indicates that the interval 1780–1834 m contains shales/silty shales. Figure 5. Open in new tabDownload slide Density versus neutron porosity: the cross-plot colour coded with gamma ray indicates that the interval 1780–1834 m contains shales/silty shales. Figure 6. Open in new tabDownload slide Density versus neutron porosity: the cross-plot colour coded with resistivity indicates that the interval 1834–1950 m contains weathered basalt and serves as the main fractured reservoir. Figure 6. Open in new tabDownload slide Density versus neutron porosity: the cross-plot colour coded with resistivity indicates that the interval 1834–1950 m contains weathered basalt and serves as the main fractured reservoir. Table 1. Results from the cross-plots and from well logs for well A#1. Sl no . Interval (m) . Interpretation . Remarks . 1 1650–1780 This interval is marked by the presence of shale/carbonaceous The entire interval is not interesting shale layers. The resistivity of shale is 2–4 Ω m and that of from a hydrocarbon point of view. carbonaceous shale is 8–20 Ω m. 2 1780–1834 Shale and siltstone with some limestone are reported in this This interval also appears not to be interesting interval. The resistivity of shales is around 3–4 Ω m and from a hydrocarbon point of view. However that of silty layers is 10–20 Ω m. The maximum effective a few isolated porosity patches have been porosity of the layers is around 10% and water saturation noted in between the impermeable layers. (Sw) is 100%. Considering Cambay shale as the source rock, the depth interval of 1811.5 to 1818 m has been put to the test. 3 1834–1950 This section is mainly basalt/weathered basalt. A few limestone The following intervals appear to be (calcareous) and laterite layers are also observed. The resistivity hydrocarbon bearing: of basalt varies over a wide range (10–100 Ω m). The 1837–1841.5 m, computed effective porosity is 5–22%. The average Sw for the 1849.5–1889.5 m, hydrocarbon intervals is ∼50%. 1895.5–1921.5 m and 1932–1943 m. Sl no . Interval (m) . Interpretation . Remarks . 1 1650–1780 This interval is marked by the presence of shale/carbonaceous The entire interval is not interesting shale layers. The resistivity of shale is 2–4 Ω m and that of from a hydrocarbon point of view. carbonaceous shale is 8–20 Ω m. 2 1780–1834 Shale and siltstone with some limestone are reported in this This interval also appears not to be interesting interval. The resistivity of shales is around 3–4 Ω m and from a hydrocarbon point of view. However that of silty layers is 10–20 Ω m. The maximum effective a few isolated porosity patches have been porosity of the layers is around 10% and water saturation noted in between the impermeable layers. (Sw) is 100%. Considering Cambay shale as the source rock, the depth interval of 1811.5 to 1818 m has been put to the test. 3 1834–1950 This section is mainly basalt/weathered basalt. A few limestone The following intervals appear to be (calcareous) and laterite layers are also observed. The resistivity hydrocarbon bearing: of basalt varies over a wide range (10–100 Ω m). The 1837–1841.5 m, computed effective porosity is 5–22%. The average Sw for the 1849.5–1889.5 m, hydrocarbon intervals is ∼50%. 1895.5–1921.5 m and 1932–1943 m. Open in new tab Table 1. Results from the cross-plots and from well logs for well A#1. Sl no . Interval (m) . Interpretation . Remarks . 1 1650–1780 This interval is marked by the presence of shale/carbonaceous The entire interval is not interesting shale layers. The resistivity of shale is 2–4 Ω m and that of from a hydrocarbon point of view. carbonaceous shale is 8–20 Ω m. 2 1780–1834 Shale and siltstone with some limestone are reported in this This interval also appears not to be interesting interval. The resistivity of shales is around 3–4 Ω m and from a hydrocarbon point of view. However that of silty layers is 10–20 Ω m. The maximum effective a few isolated porosity patches have been porosity of the layers is around 10% and water saturation noted in between the impermeable layers. (Sw) is 100%. Considering Cambay shale as the source rock, the depth interval of 1811.5 to 1818 m has been put to the test. 3 1834–1950 This section is mainly basalt/weathered basalt. A few limestone The following intervals appear to be (calcareous) and laterite layers are also observed. The resistivity hydrocarbon bearing: of basalt varies over a wide range (10–100 Ω m). The 1837–1841.5 m, computed effective porosity is 5–22%. The average Sw for the 1849.5–1889.5 m, hydrocarbon intervals is ∼50%. 1895.5–1921.5 m and 1932–1943 m. Sl no . Interval (m) . Interpretation . Remarks . 1 1650–1780 This interval is marked by the presence of shale/carbonaceous The entire interval is not interesting shale layers. The resistivity of shale is 2–4 Ω m and that of from a hydrocarbon point of view. carbonaceous shale is 8–20 Ω m. 2 1780–1834 Shale and siltstone with some limestone are reported in this This interval also appears not to be interesting interval. The resistivity of shales is around 3–4 Ω m and from a hydrocarbon point of view. However that of silty layers is 10–20 Ω m. The maximum effective a few isolated porosity patches have been porosity of the layers is around 10% and water saturation noted in between the impermeable layers. (Sw) is 100%. Considering Cambay shale as the source rock, the depth interval of 1811.5 to 1818 m has been put to the test. 3 1834–1950 This section is mainly basalt/weathered basalt. A few limestone The following intervals appear to be (calcareous) and laterite layers are also observed. The resistivity hydrocarbon bearing: of basalt varies over a wide range (10–100 Ω m). The 1837–1841.5 m, computed effective porosity is 5–22%. The average Sw for the 1849.5–1889.5 m, hydrocarbon intervals is ∼50%. 1895.5–1921.5 m and 1932–1943 m. Open in new tab Interpretation for well A 2 Well A#2 has been drilled in the mid-Cambay Basin and also reached the fractured basement where hydrocarbon was encountered. Potential reservoirs are identified in well A#2 which is located in the middle of the Cambay Basin. The stratigraphic sequence encountered in this well is given in table 2. Similar to the previous interpretation, we have considered well logs of gamma ray, shallow resistivity, deep resistivity and flushed zone resistivity, density, neutron porosity, along with elemental capture spectroscopy (ECS) and photoelectric factor (PEF) log (figure 7). Figure 7 indicates the presence of minerals within the reservoir sections. The mineral model at this depth interval comprises quartz, calcite, coal, pyrite, siderite, a special mineral (ferruginous oolite) kaolinite, and montmorilonite. The lithology and well log interpreted results are provided in table 3. The cross-plots for the depth interval of 1205–1855 m between density and neutron porosity colour coded with depth, gamma ray, dry weight of silicon content and dry weight of iron content are shown in figures 8–11, respectively. The various density–neutron cross-plots shown in figures 8–11, the ECS log and the cuttings report indicate that the dominant lithology is shaly sand and shale. The main clay minerals found from the x-ray powder diffraction (XRD) experiment are kaolinite and montmorilonite. The cuttings report also indicates the presence of ferruginous oolites for certain intervals in the Kalol formation. Figure 7. Open in new tabDownload slide Processed log at the reservoir interval of well A#2 in the Cambay Basin. Figure 7. Open in new tabDownload slide Processed log at the reservoir interval of well A#2 in the Cambay Basin. Figure 8. Open in new tabDownload slide Density (RHOZ)–neutron porosity (TNPH) cross-plot with colour-coded depth. Figure 8. Open in new tabDownload slide Density (RHOZ)–neutron porosity (TNPH) cross-plot with colour-coded depth. Figure 9. Open in new tabDownload slide Density (RHOZ)–neutron porosity (TNPH) cross-plot with colour-coded gamma ray response. Figure 9. Open in new tabDownload slide Density (RHOZ)–neutron porosity (TNPH) cross-plot with colour-coded gamma ray response. Figure 10. Open in new tabDownload slide Density (RHOZ)–neutron porosity (TNPH) cross-plot with colour-coded dry weight silicon percentage from the ECS tool. Figure 10. Open in new tabDownload slide Density (RHOZ)–neutron porosity (TNPH) cross-plot with colour-coded dry weight silicon percentage from the ECS tool. Figure 11. Open in new tabDownload slide Density (RHOZ)–neutron porosity (TNPH) cross-plot with colour-coded dry weight iron percentage from the ECS tool. Figure 11. Open in new tabDownload slide Density (RHOZ)–neutron porosity (TNPH) cross-plot with colour-coded dry weight iron percentage from the ECS tool. Table 2. Stratigraphic sequence encountered in well A#2. Age . Formation (Fm) . Depth (m) . Post–Miocene Guj. Alluvium 0–175 Jambusar Fm 175–292 Broach Fm 292–421 Miocene Jhagadia Fm 421–639 Kand Fm 639–871 Babaguru Fm 871–1064 Up. Eocene–Oligocene Tarapur Fm 1064–1142 Lr To Md Eocene Kalol Fm 1142–1249 Lr To Md Eocene Cambay Shale Fm 1249–1736 Dholka Middle Pay (DMP)–member 1441–1475 Paleocene Olpad Fm 1736–1775 Up Cretaceous to Paleocene Deccan Trap 1775–1896 Age . Formation (Fm) . Depth (m) . Post–Miocene Guj. Alluvium 0–175 Jambusar Fm 175–292 Broach Fm 292–421 Miocene Jhagadia Fm 421–639 Kand Fm 639–871 Babaguru Fm 871–1064 Up. Eocene–Oligocene Tarapur Fm 1064–1142 Lr To Md Eocene Kalol Fm 1142–1249 Lr To Md Eocene Cambay Shale Fm 1249–1736 Dholka Middle Pay (DMP)–member 1441–1475 Paleocene Olpad Fm 1736–1775 Up Cretaceous to Paleocene Deccan Trap 1775–1896 Open in new tab Table 2. Stratigraphic sequence encountered in well A#2. Age . Formation (Fm) . Depth (m) . Post–Miocene Guj. Alluvium 0–175 Jambusar Fm 175–292 Broach Fm 292–421 Miocene Jhagadia Fm 421–639 Kand Fm 639–871 Babaguru Fm 871–1064 Up. Eocene–Oligocene Tarapur Fm 1064–1142 Lr To Md Eocene Kalol Fm 1142–1249 Lr To Md Eocene Cambay Shale Fm 1249–1736 Dholka Middle Pay (DMP)–member 1441–1475 Paleocene Olpad Fm 1736–1775 Up Cretaceous to Paleocene Deccan Trap 1775–1896 Age . Formation (Fm) . Depth (m) . Post–Miocene Guj. Alluvium 0–175 Jambusar Fm 175–292 Broach Fm 292–421 Miocene Jhagadia Fm 421–639 Kand Fm 639–871 Babaguru Fm 871–1064 Up. Eocene–Oligocene Tarapur Fm 1064–1142 Lr To Md Eocene Kalol Fm 1142–1249 Lr To Md Eocene Cambay Shale Fm 1249–1736 Dholka Middle Pay (DMP)–member 1441–1475 Paleocene Olpad Fm 1736–1775 Up Cretaceous to Paleocene Deccan Trap 1775–1896 Open in new tab Table 3. Results from the cross-plots and from well logs for well A#2. Sl no . Interval (m) . Observations . Remarks . 1 1205–1250 The ferruginous oolite is present across this section. Hydrocarbon-bearing zones, but not The depth interval 1246–1249 m shows a commercially viable. resistivity of 10 Ω m. Hydrocarbon saturation of 40–60% is observed across this section. Hydrocarbon saturation of 40–60% is observed at 1208–1214 m. 2 1630–1728 This interval is silty with relatively high clay content Hydrocarbon-bearing zones, but and is capped by carbonaceous shale. The depth not commercially viable. interval 1635–1728 m is hydrocarbon bearing with an average hydrocarbon saturation of 30%. Effective porosities are low in the range of 8–10%. The depth interval 1662–1686 m is relatively cleaner with a slight increase in effective porosity which is in the range of 12–13%. 3 1736–1775 The main hydrocarbon-bearing zone lies between The hydrocarbon-bearing zone from 1761.8–1775 m 1761.8 and 1775 m. A hydrocarbon saturation of is commercially viable. The average 60–80% is observed in this interval. The effective oil flow rate is 150 m3 d-1 and the porosity is approximately 25%. Minor hydrocarbon average gas flow rate is 3300 m3 d-1. saturation of 10–20% is observed between 1740 and The other zones are not 1745 m and between 1748 and 1761 m. commercially viable. 4 1802–1850 The main hydrocarbon-bearing zone Viscous oil of 2 m3 d-1 lies between 1804 and 1825 m. is observed. Testing is ongoing. A hydrocarbon saturation of 60–80% is observed in this interval. The effective porosity ranges from 10% to 12%. The depth intervals of 1838–1840 m and 1845–1850.5 m show hydrocarbon saturation of 20–40%. The effective porosity for the depth intervals of 1838–1840 m and 1845–1850.5 m range from 20% to 22%. Sl no . Interval (m) . Observations . Remarks . 1 1205–1250 The ferruginous oolite is present across this section. Hydrocarbon-bearing zones, but not The depth interval 1246–1249 m shows a commercially viable. resistivity of 10 Ω m. Hydrocarbon saturation of 40–60% is observed across this section. Hydrocarbon saturation of 40–60% is observed at 1208–1214 m. 2 1630–1728 This interval is silty with relatively high clay content Hydrocarbon-bearing zones, but and is capped by carbonaceous shale. The depth not commercially viable. interval 1635–1728 m is hydrocarbon bearing with an average hydrocarbon saturation of 30%. Effective porosities are low in the range of 8–10%. The depth interval 1662–1686 m is relatively cleaner with a slight increase in effective porosity which is in the range of 12–13%. 3 1736–1775 The main hydrocarbon-bearing zone lies between The hydrocarbon-bearing zone from 1761.8–1775 m 1761.8 and 1775 m. A hydrocarbon saturation of is commercially viable. The average 60–80% is observed in this interval. The effective oil flow rate is 150 m3 d-1 and the porosity is approximately 25%. Minor hydrocarbon average gas flow rate is 3300 m3 d-1. saturation of 10–20% is observed between 1740 and The other zones are not 1745 m and between 1748 and 1761 m. commercially viable. 4 1802–1850 The main hydrocarbon-bearing zone Viscous oil of 2 m3 d-1 lies between 1804 and 1825 m. is observed. Testing is ongoing. A hydrocarbon saturation of 60–80% is observed in this interval. The effective porosity ranges from 10% to 12%. The depth intervals of 1838–1840 m and 1845–1850.5 m show hydrocarbon saturation of 20–40%. The effective porosity for the depth intervals of 1838–1840 m and 1845–1850.5 m range from 20% to 22%. Open in new tab Table 3. Results from the cross-plots and from well logs for well A#2. Sl no . Interval (m) . Observations . Remarks . 1 1205–1250 The ferruginous oolite is present across this section. Hydrocarbon-bearing zones, but not The depth interval 1246–1249 m shows a commercially viable. resistivity of 10 Ω m. Hydrocarbon saturation of 40–60% is observed across this section. Hydrocarbon saturation of 40–60% is observed at 1208–1214 m. 2 1630–1728 This interval is silty with relatively high clay content Hydrocarbon-bearing zones, but and is capped by carbonaceous shale. The depth not commercially viable. interval 1635–1728 m is hydrocarbon bearing with an average hydrocarbon saturation of 30%. Effective porosities are low in the range of 8–10%. The depth interval 1662–1686 m is relatively cleaner with a slight increase in effective porosity which is in the range of 12–13%. 3 1736–1775 The main hydrocarbon-bearing zone lies between The hydrocarbon-bearing zone from 1761.8–1775 m 1761.8 and 1775 m. A hydrocarbon saturation of is commercially viable. The average 60–80% is observed in this interval. The effective oil flow rate is 150 m3 d-1 and the porosity is approximately 25%. Minor hydrocarbon average gas flow rate is 3300 m3 d-1. saturation of 10–20% is observed between 1740 and The other zones are not 1745 m and between 1748 and 1761 m. commercially viable. 4 1802–1850 The main hydrocarbon-bearing zone Viscous oil of 2 m3 d-1 lies between 1804 and 1825 m. is observed. Testing is ongoing. A hydrocarbon saturation of 60–80% is observed in this interval. The effective porosity ranges from 10% to 12%. The depth intervals of 1838–1840 m and 1845–1850.5 m show hydrocarbon saturation of 20–40%. The effective porosity for the depth intervals of 1838–1840 m and 1845–1850.5 m range from 20% to 22%. Sl no . Interval (m) . Observations . Remarks . 1 1205–1250 The ferruginous oolite is present across this section. Hydrocarbon-bearing zones, but not The depth interval 1246–1249 m shows a commercially viable. resistivity of 10 Ω m. Hydrocarbon saturation of 40–60% is observed across this section. Hydrocarbon saturation of 40–60% is observed at 1208–1214 m. 2 1630–1728 This interval is silty with relatively high clay content Hydrocarbon-bearing zones, but and is capped by carbonaceous shale. The depth not commercially viable. interval 1635–1728 m is hydrocarbon bearing with an average hydrocarbon saturation of 30%. Effective porosities are low in the range of 8–10%. The depth interval 1662–1686 m is relatively cleaner with a slight increase in effective porosity which is in the range of 12–13%. 3 1736–1775 The main hydrocarbon-bearing zone lies between The hydrocarbon-bearing zone from 1761.8–1775 m 1761.8 and 1775 m. A hydrocarbon saturation of is commercially viable. The average 60–80% is observed in this interval. The effective oil flow rate is 150 m3 d-1 and the porosity is approximately 25%. Minor hydrocarbon average gas flow rate is 3300 m3 d-1. saturation of 10–20% is observed between 1740 and The other zones are not 1745 m and between 1748 and 1761 m. commercially viable. 4 1802–1850 The main hydrocarbon-bearing zone Viscous oil of 2 m3 d-1 lies between 1804 and 1825 m. is observed. Testing is ongoing. A hydrocarbon saturation of 60–80% is observed in this interval. The effective porosity ranges from 10% to 12%. The depth intervals of 1838–1840 m and 1845–1850.5 m show hydrocarbon saturation of 20–40%. The effective porosity for the depth intervals of 1838–1840 m and 1845–1850.5 m range from 20% to 22%. Open in new tab Fracture identification from the FMI log Reservoirs have been identified in fractured basalts along with the presence of other minerals for two wells in the study area. The foregoing logs are incapable of indicating fractures in this reservoir. To identify the fractures in the identified reservoir of well A#2, a formation micro imagery (FMI) log has been chosen for the selected depth interval 1761.5 to 1824.5 m and is shown in figure 12(a). Recent studies of fractured reservoir indicate that the performance of fractured reservoirs is controlled by the in situ state of stress and by the distribution and orientation of natural fractures and faults. Local variations in effective stress can significantly impact on reservoir production (Tezuka et al2002). Fluids prefer to flow along fractures that are orientated parallel to the maximum in situ horizontal stress direction (Rogers 2003). The fracture orientation direction (NE–SW) matches well with the regional maximum horizontal stress direction (Farooqui et al2011). Four types of fractures are identified in these Deccan basalts: (a) conductive, (b) partially conductive, (c) resistive and (d) drilling-induced fractures. Well A#2 encounters various facies, namely vesicular basement with fractures, volcaniclastics, vesicular basement, fractured basement and weathered basement. The most dominant facies in this well is the fractured basement with lots of conductive and resistive fractures. A detailed facies description is shown in figure 12(b). These fractures enhance the porosity in this fractured basement reservoir. The fracture porosity is defined as the percentage of the borehole wall which is represented by the fracture. This porosity is derived from the fracture aperture, trace length and the borehole coverage of the images. It is noted that the fracture porosity value is applied only to the facture void space not the matrix porosity. A summary of the detailed fracture properties of well A#2 is mentioned in table 4. The depth interval 1762–1767 m containing conductive fractures produces more hydrocarbons than the weathered basaltic depth interval 1767–1774 m for which the FMI log has not indicated any fractures. Figure 12. Open in new tabDownload slide (a) FMI log of well A#2 in the Cambay Basin indicating four types of fractures and (b) the analysis of the FMI log in relation to hydrocarbon production. Figure 12. Open in new tabDownload slide (a) FMI log of well A#2 in the Cambay Basin indicating four types of fractures and (b) the analysis of the FMI log in relation to hydrocarbon production. Table 4. Fracture property analysis for well A#2. Fracture porosity = width × trace length × 1/coverage. Well . Fracture density (m-1) . Fracture aperture (mm) . Fracture porosity (%) . A#2 Low fracture density. The maximum fracture Medium fracture aperture. In the perforated Low fracture porosity. In the perforated density in the perforated section zone (1762–1774 m) it is 0.3 mm. zone (1762–1774 m) it is 0.05–0.13%. (1762–1774 m) is 7. The maximum value in the study well is 10. The maximum value in the study well The maximum value in the study well is 5 mm (1845–1856 m). is 0.2–1.18% (1845–1856 m). Well . Fracture density (m-1) . Fracture aperture (mm) . Fracture porosity (%) . A#2 Low fracture density. The maximum fracture Medium fracture aperture. In the perforated Low fracture porosity. In the perforated density in the perforated section zone (1762–1774 m) it is 0.3 mm. zone (1762–1774 m) it is 0.05–0.13%. (1762–1774 m) is 7. The maximum value in the study well is 10. The maximum value in the study well The maximum value in the study well is 5 mm (1845–1856 m). is 0.2–1.18% (1845–1856 m). Open in new tab Table 4. Fracture property analysis for well A#2. Fracture porosity = width × trace length × 1/coverage. Well . Fracture density (m-1) . Fracture aperture (mm) . Fracture porosity (%) . A#2 Low fracture density. The maximum fracture Medium fracture aperture. In the perforated Low fracture porosity. In the perforated density in the perforated section zone (1762–1774 m) it is 0.3 mm. zone (1762–1774 m) it is 0.05–0.13%. (1762–1774 m) is 7. The maximum value in the study well is 10. The maximum value in the study well The maximum value in the study well is 5 mm (1845–1856 m). is 0.2–1.18% (1845–1856 m). Well . Fracture density (m-1) . Fracture aperture (mm) . Fracture porosity (%) . A#2 Low fracture density. The maximum fracture Medium fracture aperture. In the perforated Low fracture porosity. In the perforated density in the perforated section zone (1762–1774 m) it is 0.3 mm. zone (1762–1774 m) it is 0.05–0.13%. (1762–1774 m) is 7. The maximum value in the study well is 10. The maximum value in the study well The maximum value in the study well is 5 mm (1845–1856 m). is 0.2–1.18% (1845–1856 m). Open in new tab Discussion This paper describes the utilization of recent logging techniques to successfully characterize the volcanic fractured reservoirs in the Cambay Basin. Well data from the south Ahmedabad–Mehsana block highlight the formation evaluation from oil-bearing fractured reservoir combining conventional logging measurement with FMI, PEF and ECS logs. The reservoir consists mainly of fractured and weathered basalt. The ECS tool provides a continuous lithology description. Three main facies, namely vesicular basalt, nonvesicular basalt and volcanicalstic rocks, have been identified previously from the FMI log and hand specimens of basalt from this block of the Cambay Basin (Farooqui et al2009). The target section in well A#2 shows a variety of facies along with different sets of fractures, including conductive as well as resistive fractures. Textural information from the FMI log provides the basis for distinguishing rock types and correlating with that from other wells. The PEF log gives additional information to complete the lithology classification. The presence of open fractures and vesicles (figure 12) creates a good quality reservoir with a dual porosity system (fracture porosity of 1.18%) and a fracture network enhances permeability. The orientation of conductive fractures towards the NE–SW direction can play a major role as fluid conduits and a detailed analysis to determine the orientation of the fractures is of utmost importance. Clay usually consists of one (or more) of the following minerals: chlorite, illite, kaolinite and smectite. In contrast to sand, these materials are electrically conductive and resistivity will be lowered relative to the ‘clean sand’ value and thereby give rise to a pessimistic Sw (Archie). The presence of clay will also affect the porosity determination, and the composite correction for effects on both porosity and saturation. The corrected porosity has been used in reservoir sand in different intervals. The low-permeability structure and the response to overburden stress have a strong impact on the low-permeability structure and the relative permeability relationships. In low-permeability reservoirs there can be a broad range of water saturations in which neither gas nor water can flow. In some very low-permeability reservoirs, there is virtually no mobile water phase even at very high water saturations (Gonfalini 2005). In this kind of reservoir the following analysis will reduce the risk for hydrocarbon exploration. Strong diagenetic effects and clay filling by chlorite and illite need to be studied by means of ad hoc petrophysical models and specialized lithology logs. Low resistivity contrasts affect water saturation evaluation. Good total porosity determination using density, neutron and sonic. NMR logging: good Φ estimation, poor K estimation. Extensive laboratory analysis of the Archie parameters (especially n) is required. The study has been conducted only in the fractured basement, considering the two wells which are producing hydrocarbon. The main depth intervals which are producing hydrocarbon are all located in the fractured basement. Conclusions The fractured basaltic basement in the south Ahmedabad–Mehsana block of the Cambay Basin is acting as a reservoir rock and shale/silty shale is acting as cap rock. In this fractured basaltic reservoir, the density ranges from 2.4 to 2.6 gm cc-1 and the neutron porosity log indicates a porosity of 20%. The resistivity varies from 25 to 30 Ω m and the PEF log shows a value of 6 in these two wells. Good self potential has been developed for this reservoir. It is possible to estimate porosity and saturation through well logs using conventional empirical relationships. The cross-plots and ECS tool provide the mineralogical composition of the reservoir in well A#2. The main hydrocarbon zones are in the intervals 1834–1950 m in well A#1 and 1761.8–1774.5 m in well A#2. The FMI log clearly indicates the fractures in the basaltic basement and the fracture porosity which in turn serve as a good hydrocarbon-producing reservoir. The results are also found to be in good agreement with well test data. Acknowledgments We gratefully acknowledge the Gujarat State Petroleum Corporation Ltd, Gandhinagar, regarding the various data support and analysis. 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TI - Formation evaluation of fractured basement, Cambay Basin, India
JF - Journal of Geophysics and Engineering
DO - 10.1088/1742-2132/9/2/162
DA - 2012-04-01
UR - https://www.deepdyve.com/lp/oxford-university-press/formation-evaluation-of-fractured-basement-cambay-basin-india-GPIoq0C9zD
SP - 162
VL - 9
IS - 2
DP - DeepDyve
ER -