Perveiz Khalid

A modified rock physics model for analysis of seismic signatures of low gas-saturated rocks

In seismic applications, the bulk modulus of porous media saturated with liquid and gas phases is often estimated using Gassmanns fluid substitution formula, in which the effective bulk modulus of the two-phase fluid is the Reuss average of the gas and liquid bulk moduli. This averaging procedure, referred to as Woods approximation, holds if the liquid and gas phases are homogeneously distributed within the pore space down to sizes well below the seismic wavelength and if the phase transfer processes between liquid and gas domains induced by the pressure variations of the seismic wave are negligible over the timescale of the wave period. Using existing theoretical results and low-frequency acoustic measurements in bubbly liquids, we argue that the latter assumption of “frozen” phases, valid for large enough frequencies, is likely to fail in the seismic frequency range where lower effective bulk modulus and velocity, together with dispersion and attenuation effects, are expected. We provide a simple method, which extends to reservoir fluids a classical result by Landau and Lifshitz valid for pure fluids, to compute the effective bulk modulus of thermodynamically equilibrated liquid and gas phases. For low gas saturation, this modulus is significantly lower than its Woods counterpart, especially at the crossing of bubble point conditions. A seismic reflector associated to a phase transition between a monophasic and a two-phase fluid thus will appear. We discuss the consequences of these results for various seismic applications including fizz water discrimination and hydrocarbon reservoir depletion and CO2 geological storage monitoring.

Discrimination of fizz water and gas reservoir by AVO analysis: a modified approach

Amplitude versus offset response is analogous to variation in P-wave velocity resulting from different pore fluid saturations. However, the input parameters of fluid mixtures such as fluid modulus and density are often estimated using volume average method, and the resulting estimates of fluid effects can be overestimated. In seismic frequency band, the volume average method ignores the heat and mass transfers between the liquid and gas phases, which are caused by pore pressure perturbations. These effects need to be accounted for the interpretation of the seismic events and forward modeling of fizz water reservoirs. The conventional model is corrected in present study by considering the thermodynamic properties of the fluid phases. This corrected model is then successfully applied on a gas producing field in the North Sea. AVO response, based on the corrected model is highly affected by pressure related variations in bulk modulus of multi-phase formation fluid. Velocity push down effect appears, as the free gas saturation generates stronger AVO response than obtained by a conventional AVO model. The, present research reveals that such response is helpful to discriminate fizz water from commercial gas, to detect primary leakage of gas (CO2 or CH4) from geological structures and to model free gas effects on seismic attributes.

Modulus defect, velocity dispersion and attenuation in partially-saturated reservoirs of Jurassic sandstone, Indus Basin, Pakistan

Partially saturated reservoirs are one of the major sources of seismic wave attenuation, modulus defect and velocity dispersion in real seismic data. The main attenuation and dispersion phenomenon is wave induced fluid flow due to the heterogeneity in pore fluids or porous rock. The identification of pore fluid type, saturation and distribution pattern within the pore space is of great significance as several seismic and petrophysical properties of porous rocks are largely affected by fluid type, saturation and fluid distribution pattern. Based on Gassmann-Wood and Gassmann- Hill rock physics models modulus defect, velocity dispersion and attenuation in Jurassic siliclastic partially-saturated rocks are studied. For this purpose two saturation patterns - uniform and patchy - are considered within the pore spaces in two frequency regimes i.e., lower frequency and higher frequency. The results reveal that at low enough frequency where saturation of liquid and gas is uniform, the seismic velocity and bulk modulus are lower than at higher frequency where saturation of fluid mixture is in the form of patches. The velocity dispersion and attenuation is also modeled at different levels of gas saturation. It is found that the maximum attenuation and velocity dispersion is at low gas saturation. Therefore, the dispersion and attenuation can provide a potential way to predict gas saturation and can be used as a property to differentiate low from high gas saturation.

AVO-derived attributes to differentiate reservoir facies from non-reservoirs facies and fluid discrimination in Penobscot area, Nova Scotia

The discrimination of hydrocarbon (gas or oil) facies from non-hydrocarbon (wet sands) facies is an important goal in quantitative seismic interpretation and reservoir estimation. The differentiation of hydrocarbon facies from non-hydrocarbon in Mississauga Formation of early Cretaceous in Penobscot area is a difficult task due to smaller net pay thickness and shaly sand intervals. Based on seismic interpretation and wireline logs, five sand plays are identified in the middle of Mississauga Formation. Four sands have hydrocarbons while top of sand 5 represents hydrocarbon water transition zone. Among these four, the pay sand 4 is analyzed for hydrocarbon facies. Wireline logs and seismic data are used to derive various amplitude versus offset (AVO) based attributes such as: acoustic (IP) and shear (IS) impedances, Poisson ratio (σ) etc. Further, the combined attributes e.g., product of Lamé parameters (μ, λ) with density (ρ), their ratio (λ/μ), difference between bulk modulus (K) and shear modulus (μ), Δμρ/μρ, Δ(λ/μ + 2)(λ/μ + 2) and the pore space modulus (KP) are also analyzed to find out the best attribute as a hydrocarbon facies discriminator from non-hydrocarbon facies in the shale imbedded pay sand 4 of Mississauga Formation. First, petrophysical parameters such as P and S wave impedances, Lamé’s parameters etc. are extracted from log data. Then, appropriate pairs of seismic attributes are crossplotted so that the hydrocarbon and non-hydrocarbon facies cluster together for quick identification and interpretation. Gamma ray index is crossplotted against spontaneous potential log to mark sand and shale facies. Fluid substitution modeling for various fluid types and saturation is also done which demonstrate that the cross-plots between different rock physics parameters can be used to distinguish between reservoir fluids. Our analysis reveals single P-wave based attributes are not sufficient to discriminate fluids thus the use of multi-attributes such as KP, λρ and K-μ is more effective to discriminate the hydrocarbon and non-hydrocarbon facies. The analysis of these cross-plots was done to map the reservoir sands and the hydrocarbon-water contact.

An application of rock physics modeling to quantify the seismic response of gas hydrate-bearing sediments in Makran accretionary prism, offshore, Pakistan

Naturally occurring gas hydrates are potential future energy source. A significant amount of gas hydrates is interpreted through seismic reflection data in the form of bottom simulating reflector (BSR) present in the sediments of the convergent continental margin of Pakistan. However, the seismic character of these hydratebearing unconsolidated sediments is not properly investigated. Since no direct measurements are available for quantitative estimation of gas hydrate and free gas in these sediments, therefore detailed knowledge of seismic velocities is essential. Seismic velocities of the gas hydrate-bearing sediments in the study area are estimated by using the effective medium theory and the fluid substitution modeling. The results show that the presence of gas hydrates increases the stiffness of the unconsolidated sediments; whereas the presence of free gas decreases the stiffness of these sediments. It is noted that seismic velocities and density of hydrate-bearing sediments are highly affected by saturation and distribution pattern of gas hydrates. The hydrate-bearing sediments seem to be characterized not only by high P-wave velocity (about 2800 m/s) but also by anomalously low S-wave velocity (about 850 m/s). As pure gas-hydrates have much higher seismic velocities than those of host sediments, presence of gas-hydrate increases the seismic velocities, whereas free-gas below the hydrate-bearing sediments decreases the velocities. Seismic reflection from the BSR exhibits a wide range of amplitude variation with offset characteristics, which depend upon the saturation and distribution of hydrates above and free gas below the BSR. We have also demonstrated that some attributes like acoustic and shear impedances, and AVO can be used as important proxies to detect gas hydrate saturation.

AVO forward modeling and attributes analysis for fluid’s identification: a case study

Since the four decades amplitude versus offset (AVO) analysis is used extensively in hydrocarbon exploration to discriminate the hydrocarbon fluids from background geology. Conventionally AVO analysis involves calculation of intercept and gradient from a linear fit of compressional wave reflection coefficient to the sine square of the angle of incidence. Mississauga formation of early cretaceous is the reservoir rock in the study area, contains hydrocarbons and condensates in the middle part. It is very difficult to discriminate hydrocarbon fluids from non pay zones due to small thickness and low quality of pay zone. AVO forward modeling is done to estimate and analyze various AVO derived attributes for the discrimination of hydrocarbon from background sand. After calculating the AVO attributes, appropriate pairs of these attributes are crossplotted so that the hydrocarbon and non-hydrocarbon facies cluster together for quick identification and interpretation. In intercept/gradient crossplot the top of the gas zone falls in quadrant II and show clear deviation from background trend. The analysis reveals that oil and gas sand attributes are strongly different from water sand attributes. Among various attributes, the fluid factor and intercept are more promising attribute for fluid discrimination.

An integrated petrophysical and rock physics analysis to improve reservoir characterization of Cretaceous sand intervals in Middle Indus Basin, Pakistan

The sand intervals of the Lower Goru Formation of the Cretaceous age, widely distributed in the Middle and Lower Indus Basin of Pakistan, are proven reservoirs. However, in the Sawan gas field of the Middle Indus Basin, these sandstone intervals are very deep and extremely heterogeneous in character, which makes it difficult to discriminate lithologies and fluid saturation. Based on petrophysical analysis and rock physics modeling, an integrated approach is adopted to discriminate between lithologies and fluid saturation in the above-mentioned sand intervals. The seismic velocities are modeled using the Xu–White clay–sand mixing rock physics model. The calibrated rock physics model shows good consistency between measured and modeled velocities. The correlation between measured and modeled P and S wave velocities is 92.76% and 84.99%, respectively. This calibrated model has been successfully used to estimate other elastic parameters, even in those wells where both shear and sonic logs were missing. These estimated elastic parameters were cross-plotted to discriminate between the lithology and fluid content in the target zone. Cross plots clearly separate the shale, shaly sand, and gas-bearing sand clusters, which was not possible through conventional petrophysical analysis. These data clusters have been exported to the corresponding well for the purpose of interpolation between wells and to analyze the lateral and vertical variations in lithology and fluid content in the reservoir zone.

U-Pb zircon systematics of the Mansehra Granitic Complex: implications on the early Paleozoic orogenesis in NW Himalaya of Pakistan

Mansehra Granitic Complex (MGC) lies in the NW Himalaya of Pakistan. The MGC magmatic rocks are peraluminous, calc-alkaline S-type granitoids. Prior to this study the Mansehra Granite had produced ages of 83 Ma by K/Ar, 215 Ma using Ar/Ar on biotite, and 516 ± 16 Ma, using the whole rock Rb/Sr method. The Susalgali Granite Gneiss, a sheared facies of the Mansehra Granite previously regarded as older than the Mansehra Granite, was dated at 79 Ma using K/Ar on biotite. Hakale Granite, which is intrusive into the Mansehra Granite, had yielded K/Ar muscovite age of 165 Ma. The age of the leucogranites was not reported before this contribution. We have presented the revised geochronology of the MGC magmatic bodies, employing SHRIMP and LA-ICP-MS U-Pb zircon chronometry, to constraint precise crystallization ages and tectonic setting of the NW Himalaya, Pakistan. Dates of emplacement of the Mansehra Granite, leucogranites and Hakale Granite are ca. 478, 475 and 466 Ma, respectively. These new ages are comparable to U-Pb zircon and Rb/Sr dates of other granites and granite gneisses in the Lesser Himalaya to the east, in India, Nepal, south Tibet and SW China. The age components of ca. 1900–1300, 985–920, 880–800 and 690–500 Ma are interpreted as inherited grains. Geochronological and field evidence suggest that the MGC of the NW Himalaya are the product of an Andean-type Cambro-Ordovician accretional orogenesis with continental-continental settings along the northen margin of east Gondwana. On the basis of new age data of the MGC plutonic rocks it is inferred that Cambro-Ordovician accretional event commenced from SW China and extends at least up to NW Pakistan along the northern margin of east Gondwana. However, granitic rocks of Pan African affiliation prevail in central Iran and Turkey along northern and western margins of Gondwana.

Physio-mechanical and aggregate properties of limestones from Pakistan

Physical characterization study was carried out on limestones from Samana Suk Formation, Shekhai Formation, Kawagarh Formation, Margala Hill Limestone and Lockhart Limestone to explore their potential for utilization as aggregate sources. Laboratory tests were performed in accordance with BS and ASTM standards to determine specific gravity, water absorption, total and effective porosities, Flakiness Index, Elongation Index, Los Angeles Abrasion value and Aggregate Impact values of these limestones. The evaluated physical properties were compared with standard specifications for their qualification as construction material. Mutual relationships between physical parameters have been described by simple regression analysis. Significant direct correlation of water absorption with Los Angeles abrasion value was noted. Direct relationship of total porosity with Aggregate Impact Value and Los Angeles abrasion value was also revealed. However, negative trends of Aggregate Impact Value with Flakiness Index and Los Angeles abrasion value with Elongation Index were observed. Petrographic study reveals that micrite and bioclasts contents vary directly while dolomite has an inverse relation with Los Angeles Abrasion values. However, calcite contents do not seem to affect mechanical properties of these limestones. The study indicates that the limestones of Samana Suk Formation, Kawagarh Formation, Lockhart Limestone and Shakhai Formation fall within the standard specification limits and can be utilized as aggregate sources for indigenous construction industry.

Reservoir characterization of basal sand zone of lower Goru Formation by petrophysical studies of geophysical logs

The lower Indus basin is one of the largest hydrocarbon producing sedimentary basins in Pakistan. It is characterized by the presence of many hydrocarbon-bearing fields including clastic and carbonates proven reservoirs from the Cretaceous to the Eocene age. This study has been carried out in the Sanghar oil field to evaluate the hydrocarbon prospects of basal sand zone of lower Goru Formation of Cretaceous by using complete suite of geophysical logs of different wells. The analytical formation evaluation by using petrophysical studies and neutron-density crossplots unveils that litho-facies mainly comprising of sandstone. The hydrocarbons potentialities of the formation zone have been characterized through various isoparameteric maps such as gross reservoir and net pay thickness, net-to-gross ratio, total and effective porosity, shaliness, and water and hydrocarbons saturation. The evaluated petrophysical studies show that the reservoir has net pay zone of thickness range 5 to 10 m, net-togross ratio range of 0.17 to 0.75, effective porosity range of 07 to 12 %, shaliness range of 27 to 40 % and hydrocarbon saturation range of 12 to 31 %. However, in the net pay zone hydrocarbon saturation reaches up to 95%. The isoparametric charts of petrophysically derived parameters reveal the aerial distribution of hydrocarbons accumulation in basal sand unit of the lower Goru Formation which may be helpful for further exploration.