Kalol Formation Research Articles

Assessment of reservoir heterogeneities and hydrocarbon potential zones using wavelet-based fractal and multifractal analysis of geophysical logs of Cambay basin, India

The scaling behaviour of physical properties of the earth's subsurface e.g. porosity, permeability, density, etc significantly influence reservoir characteristics. The characterization of the parameters, by analysing nonlinear geophysical logs using the application of linear and traditional empirical relations, is very tedious, complicated, and yields less accurate results. In this perspective, wavelet-based fractals and multifractals techniques provide effective insights into local and global characteristics of heterogeneity of reservoir parameters. The results from the numerical experiment on simulated synthetic data reveal that the wavelet-based fractal and multifractals are more useful to delineate the shorter fluctuations in signal and heterogeneities of the reservoir. The scaling exponent and fractal density, a component of fractal analysis, have been estimated for each sample from power law relationship that facilitates the understanding of the local characteristics of the subsurface formation. On the other hand, the multifractal spectrum, a generalization curve of the hurst exponents, provides the global nature of heterogeneities corresponding to reservoir parameters. We analyse gamma ray, density, and neutron logs of three wells (well-204, 203, and 172) of the Limbodara oil field of Cambay Basin, India. The fractal density curve of gamma ray log is found like the low-pass filtered version of the original signal, and map the lithologies by clustering their similar values while the scaling exponent curve on either side of 0.5 of scaling exponent demarcates the lithological boundaries at the intersection points. The scaling exponent curve highlights the finer variations embedded in the signal and is feasible to enhance the thin layers of the reservoir. The multifractal spectrum of gamma-ray logs across three wells encompasses three major formations emphasizing that the Kalol formation exhibits higher degree of heterogeneity than other formations (Tarapur and Olpad). The multifractal spectrum of neutron and gas corrected log for each well of Kalol formation shows the greater influence on well-203 and lowest influence on well-172, indicating the effective hydrocarbon bearing zones of the former well than the latter. This evidence that an increase in lithological heterogeneity enhances the quality of hydrocarbon reservoir as well as reduces the multifractality of porosity logs.

Characterization of thin bed reservoirs of Linch area, Cambay Basin using complex trace transform method to enhance temporal resolution of seismic data

In the last few decades, the interest in thin hydrocarbon reservoirs has grown progressively justifying the great effort spent on developing techniques for quantitative interpretation of thin bed seismic response. The detection and resolution of reflections from thin layers are major problems in reflection seismic. Many a times it is difficult to precisely estimate the vertical and lateral extensions of a significant portion of discovered hydrocarbon reservoirs due to the thin layer effect. In Linch area of Cambay basin, the sands which are dispersed especially within Older Cambay Shale (OCS) are thin and discrete in nature and are not properly discernible on seismic, in particular at deeper levels; some of these sands hold commercial oil and gas. Even within shallower Kalol formation most of the sands are quite thin to be delineated by conventional seismic interpretation. A small part of Linch area comprising of six wells, namely, LN-A, LN-B, LN-C, LN-D, LN-E, LN-F has been taken up for this study (Figure 1). Log characteristics and corresponding seismic response for well LN-A shows that the sands which are dispersed especially within Older Cambay Shale (OCS) are thin and discrete in nature and are not properly discernible on seismic surveys, in particularly at deeper levels. Sands being thin, the seismic response is of composite nature arising out of several sand-shale alterations (Figure 2). Rock physics analysis based on well logs indicates the porous sands to be having impedance within the range of shale impedance, mostly towards higher order (Figure 3). Inversion using conventional approach turns out to be of no practical use. In this study authors have investigated the approach for thin reservoir evaluation through complex trace transform (CTT) method.

“Attribute based Inversion” a tool for reservoir characterization: a case study-Kalol Field, Cambay Basin, India

With major oil and gas discoveries diminishing in number, industry is turning its attention to redevelop fields with reservoirs (Res) like silts which have otherwise been accorded lower priority earlier. It has always been a challenge to identify the locales with better Re facies development in un-drilled areas of a field and most often many development wells either go dry or turn out to be poor producers, significantly increasing the cost of production from a given field. Kalol Field, Cambay Basin, India is a several decade old discovery with a significant number of development wells. However, the oil recovery remained hardly around 10 %. Most often, the contributing factor for this low recovery is poor Re facies (tight silts) within the major producing sequences like Kalol IX and Kalol X. Hence identifying areas of better Re facies remained a challenging task before the geo-scientists. To overcome this challenge a workflow has been developed for Re characterization based on an “Attribute based Inversion” technique, in which 3D attribute volume of petrophysical properties are calculated through genetic inversion algorithm using a nonlinear correlation between seismic property and log property. Calculated 3D attribute volume of petrophysical properties are utilized further for Re classification and finally geostatistical modeling is performed for Re modeling. The adopted approach is operative even if the Re is very thin (beyond seismic resolution) and can provide a way to generate 3D attribute volumes of log property from seismic and well log data. This approach is also effective in determining the Re geometry and quality of Re, which may help in planning future drilling locations. The application of the workflow has been illustrated with a case study from Kalol Field, Cambay Basin. The obtained results shows that the proposed approach is effective enough in resolving 2–8 m thick Re within Kalol formation. It gives an idea about the Re quality (good or bad Re) and geometry of the Kalol Reservoir in the field. Volumetric calculation shows that there is still some potential remaining in the field. Hence suitably placing new wells, it is quite possible to increase the productivity of the field.

Application of nuclear magnetic resonance logs for evaluating low-resistivity reservoirs: a case study from the Cambay basin, India

Low-resistivity pay sands have been identified in four wells, namely: AM-7, AM-8, TA-1 and TA-5, which penetrate the Eocene pay-IV (EP-IV) sand unit of the Kalol formation in the Cambay basin. These wells are located near the Dholka and Kanwara oilfields in the Cambay basin. The main objective of this paper is to evaluate nuclear magnetic resonance (NMR) logs of the low-resistivity reservoirs from these four wells and to determine the petrophysical properties more accurately than conventional logs have done. The thickness of low-resistivity sand varies from 5 to 17?m in the wells under the study area. The formation has been characterized by a high surface area; thus irreducible water saturation (Swi) is high. The resistivity of these pay zones varies from 1 to 8 ?m and the total NMR porosity ranges from 15% to 50%. The free fluid porosity ranges from 2% to 5% in wells TA-1 and TA-5 and 12?20% in wells AM-7 and AM-8. The Timur?Coates/SDR model derived that the permeability of the low-resistivity reservoir ranges from 0.8 to 1.5 md in wells TA-1 and TA-5 and 10?110 md in wells AM-7 and AM-8.

Biostratigraphy and palaeoenvironmental analysis of subsurface Palaeogene sediments in western part of Ahmedabad Block, North Cambay Basin

The western part of Ahmedabad Block is among the thrust areas for hydrocarbon exploration in Cambay Basin. Palynological studies of the Palaeogene sediments of Ahmedabad Block between Detroj and Wasnalava have been carried out to evaluate the palynostratigraphy and infer depositional environment to help in basin modelling for exploration of hydrocarbons. Based on palynofloral association three assemblage zones, viz. Polybrevicolporites cephalus Zone (Palynozone-I), Proxapertites cursus- Polycolpites flavatus Zone (Palynozone-II) and Palmaepollenites kutchensis Zone (Palynozone-III) have been identified. These zones are dated Early, Middle and Late Eocene in age. The sediments corresponding to Olpad Formation (?Palaeocene) exhibited poor palynofloral contents.
 The interpretation of depositional environment is based on the absolute pollen frequency and palynofloral associations. In Cambay and Kadi formations the coastal and back mangrove elements are common with sporadic occurrence of marine elements, suggestive of near shore environment of deposition. The overlying Kalol Formation has yielded rich back mangrove floral assemblage along with moderate occurrences of coastal elements and is suggestive of Littoral conditions. The dominance of marine phytoplankton in Tarapur Formation is indicative of shallow marine conditions of deposition.

Estimation of effective porosity using geostatistics and multiattribute transforms: A case study

The middle Eocene Kalol Formation in the north Cambay Basin of India is producing hydrocarbons in commercial quantity from a series of thin clastic reservoirs. These reservoirs are sandwiched between coal and shale layers, and are discrete in nature. The Kalol Formation has been divided into eleven units (K‐I to K‐XI) from top to bottom. Multipay sands of the K‐IX unit 2–8 m thick are the main hydrocarbon producers in the study area. Apart from their discrete nature, these sands exhibit lithological variation, which affects the porosity distribution. Low‐porosity zones are found devoid of hydrocarbons. In the available 3D seismic data, these sands are not resolved and generate a composite detectable seismic response, making reservoir characterization through seismic attributes impossible. After proper well‐to‐seismic tie, the major stratigraphic markers were tracked in the 3D seismic data volume for structural mapping and carrying out attribute analysis. The 3D seismic volume was inverted to obtain an acoustic impedance volume using a model‐based inversion algorithm, improving the vertical resolution and resolving the K‐IX pay sands. For better reservoir characterization, effective porosity distribution was estimated through different available techniques taking the K‐IX upper sand as an example. Various sample‐based seismic attributes, the impedance volume, and effective porosity logs were used as inputs for this purpose. These techniques are map‐based geostatistical methods using the acoustic impedance volume, stepwise multilinear regression, probabilistic neural networks (PNN) using multiattribute transforms, and a new technique that incorporates both geostatistics and multiattribute transforms (either linear or nonlinear). This paper is an attempt to compare different available techniques for porosity estimation. On comparison, it is found that the PNN‐based approach using ten sample‐based attributes showed highest crosscorrelation (0.9508) between actual and predicted effective porosity logs at eight wells in the study area. After validation, the predicted effective porosity maps for the K‐IX upper sand are generated using different techniques, and a comparison among them is made. The predicted effective porosity map obtained from PNN‐based model provides more meaningful information about the K‐IX upper sand reservoir. In order to give priority to the actual effective porosity values at wells, the predicted effective porosity map obtained from PNN‐based model for the K‐IX upper sand was combined with actual effective porosity values using co‐kriging geostatistical technique. This final map provides geologically more realistic predicted effective porosity distribution and helps in understanding the subsurface image. The implication of this work in exploration and development of hydrocarbons in the study area is discussed.

The effective source rocks in the Cambay basin, India

We evaluated the source potential of three Paleogene formations, identified the effective source rocks, and determined their maturation histories to derive exploration leads and inputs for petroleum system study. Kinetics-derived hydrocarbon expelled (HCE) values are 0-0.4, 4-16, and 16-32 t hydrocarbons (HC)/m2 for the Kalol (middle Eocene), Cambay Shale (middle Eocene-upper Paleocene), and Olpad (lower Paleocene) formations, respectively. Values are high in the south for the Kalol and Cambay Shale formations and in the north for the Olpad. Source rock (SR) data reveal six laterally extensive potential sources (PS) with kerogen type II/III in the middle Eocene-lower Paleocene. The PSs are SR4 at the base of the Kalol Formation; SR5 and SR6 at the top and middle, respectively, of the Cambay Shale Formation; SR7 and SR8/9 at the top of the Olpad Formation; and SR11/12 at the base of the Olpad Formation. In the north, SR11/12, SR8/9, and SR7 attained peak oil generation (vitrinite reflectance [Ro] ~0.75%) at 45, 5, and 1 Ma, respectively. The SR6 and SR5 attained generation threshold (0.5% Ro) recently. In the south, SR11/12, SR8/9, SR7, and SR6 attained 0.75% Ro at 50, 8, 7, and 3 Ma, respectively; SR5 and SR4 attained 0.5% Ro at 7 and 6 Ma, respectively. Chromatographic and isotope data of 108 oils and 43 PS samples show that SR7 and SR8/9 initially charged the Paleocene-middle Eocene reservoirs across the basin. Subsequently, SR6 and SR5 in the central Cambay and SR6, SR5, and SR4 in the south charged the reservoirs in their respective drainage areas. Conventional and basin-centered accumulations in the strata between SR7 and SR8/9 that contain free hydrocarbons under pressure are likely. Hydrocarbons generated in SR11/12, possibly lost in axial areas, may exist at margins.

Dinoflagellate cyst biostratigraphy and age of the Middle Eocene Kalol Formation in the Kalol-109 well, north Cambay Basin, Western India

Three dinoflagellate cyst assemblage zones are recorded from the Kalol Formation, Kalol-109 well, North Cambay Basin, Western India. A Lutetian-Bartonian (Middle Eocene) age is suggested.

Chemico-petrographic studies of some lignite core samples from Kalol oilfield, Cambay Basin, Gujarat, Western India

The Kalol oilfield in the Cambay graben, Gujarat. western India, is known to contain thick seams of lignite in the Kalol Formation (Middle Eocene), overlying the oil-bearing Cambay Black Shale (Lower Eocene), at depths between 1110 m and 1500 m. The Kalol Formation occurs in the northern portion of the Cambay Basin as a wedge-shaped sequence of regressive and transgressive marine environments, the lignite being confined to the former phase. Chemically, the Kalol lignite is characteristically low in moisture (4.45–4.64%), quite low in ash (1.67-10.82%) and high in volatiles (43.56–55.25%). C is 72.39–77.18%, H is 4.47–5.93%, N is 1.16–1.58%, O is 15.73–18.62%, and S is 0.32–0.86%. According to Seyler's classification, the Kalol lignite can be classified as belonging to rank (a) lower than lignitous, (b) perlignitous, (c) ortholignitous, (d) metalignitous, and (e) bituminous. According to North American (ASTM) classification, utilising data on volatiles and R m oil, the lignite belongs to lignite, sub-bituminous C and low volatile bituminous rank. Petrographically, the Kalol lignite is composed of huminite (50–81%), liptinite (1–16%), and inertinite (6–32%). Inertinite comprises mainly sclerotinite as plectenchyma, fusinite being absent. Exsudatinite is quite common. On the basis of microlithotype, the lignite comprises textile (1–13%), detrite (19–69%), liptitextite (1–10%), liptidetrite (4–16%), inertidetrite (1–25%), detrinertite (3–21%), and inertite (5–26%), with shale (5–12%). R m oil varies from 0.30 to 0.40. The bituminous coal sample is high in shaly matter (53%) and composed of vitrinite (16%) and sclerotinite (29%), the former showing R m 1.80. These studies indicate that the chemical and petrographic constitution of the lignite is favourable for underground gasification.

Early Eocene Subaerial Erosional Valleys in Cambay Basin, India

Anomalous thickness of the Kalol Formation, a clastic wedge of middle Eocene age, have been traced on the topographic high reflecting the Mehsana horst in the central part of the north Cambay basin. Subsurface data and isopach studies indicate that the Kalol sequence occupies ancient erosional valleys in the Cambay Shale bedrock. These erosional valleys trend north-south, are more than 15 km long, 1 to 1.5 km wide, and up to 120 m deep. Downslope, the stream channel bifurcates and the width of the anastomosing channel system is 3.5 km. The slope of the walls of the valley ranges from 3 to 18° and is generally steep in the south. A major factor contributing to the formation and deep excavation of the erosional valleys is thought to be the slow uplift of the fault-controlled Mehsana horst which is situated in the middle of the basin floor. As a result of the uplift a structural depression, roughly circular in outline, was formed around the slopes reflecting the horst along which the major rivers of the basin started flowing. In one of the river systems, where sand input was limited, freshwater flood basins and lagoonal swamps were formed in which coal-forming vegetation flourished. These basins and marshes, in turn, acted as sand traps. As a result of reduced sediment-carrying competence of the river system, some of the river flow was diverted along new distributaries. Deep erosion on the slopes reflecting the orst is believed to have been caused by one of the tributaries of the major river system. This erosion was aided by the slow uplift and initial declivity of the Mehsana topographic high. The tributaries may have cut across the slowly rising horst as antecedent drainage. The stream-channel distributary system, which excavated the erosional valleys during the early Eocene, deposited deltaic Kadi sediments in a shallow sea south of the North Kadi area. The erosional valleys, which were in the nature of estuaries of Cambay Gulf, were filled with sandstone, siltstone, shale, and coal of the Kalol Formation during the middle Eocene. Geometry, age of gorge erosion and sedimentary fill, thickness of the channel fill, and the presence of the regional blanket which can be correlated with the channel fill are similar to other ancient submarine valleys. However, the cross section and slope of the walls of the valley and the sandstone to coal lithology of the channel fill characterize the channels on an emergent surface and are in contrast with other submarine valleys.

Stratigraphic Analysis of Kadi and Kalol Formations, Cambay Basin, India

The Kadi and Kalol Formations of early to middle Eocene age are thick clastic wedges in the northern part of the Cambay basin, India. Southward these formations intertongue with and grade into the marine Cambay Shale. The Kadi Formation has been divided into the Mandhali and Mehsana Members. The formation is restricted areally to the northern part of the Ahmedabad-Mehsana block and was deposited in fluvial, lagoonal, and deltaic environments. Unlike the Kadi, the Kalol Formation is present in a large area from Mehsana in the north to the Dadhar River in the south. The Kalol Formation has been divided into four members. The upper three (Sertha, Kansari, and Wavel) were deposited in an extensive area and the lowermost Chhatral Member is restricted areally. Along the basin a is, shallow-marine, intertidal, fluvial, and paludal to eolian environments were established during the deposition of the Sertha and Wavel Members. These environments shifted in response to oscillations of the basin floor. Delta building during deposition of the Kadi Formation was influenced by a steep paleoslope, which became gentle during Kalol deposition. The gentle slope created conditions favorable for the formation of extensive coastal plains. Vertical lithologic variations were, however, controlled by epeirogenic movements in the source area and mild oscillations of the depositional floor. The gentle paleoslope which existed during deposition of the Kalol created large areas of favorable source-reservoir facies, although the reservoir sands generally are dirty because of the presence of trap basalts in the provenance area. Sand facies with better petrophysical properties are present only in a narrow zone paralleling the strandline. Winnowed sands were localized on some of the positive features such as the Kalol, Sanand, Nawagam, and Dholka highs. Variations in the physicochemical properties of the oil in Kalol Formation are controlled both by evolutionary and secondary alteration processes. The presence of waxy oils trapped beneath coal seams suggests that the coals exercised some control in localizing such pools.