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GoFour well datasets from a Saudi Arabian carbonate oil field were examined. These data helped to establish a rock physics transform between the P- and S-wave impedances and porosity. The key was finding appropriate elastic properties for the "zero-porosity" end member (i.e., pure mineral) for the field under examination. The resulting model was then used in synthetic seismic forward modeling, as well as seismic impedance inversion, to map porosity within the carbonate reservoir.

Presentation Date: Wednesday, October 19, 2016

Start Time: 11:35:00 AM

Location: 167

Presentation Type: ORAL

carbonate reservoir, complex reservoir, curve, elastic property, Exposition, Mavko, model, moduli, porosity, Reservoir Characterization, reservoir description and dynamics, rock physics, rock physics model, Saudi Arabia, seg seg international, seismic processing and interpretation, transform, Upstream Oil & Gas, well

Our goal is to accurately estimate attenuation from seismic data using model regularization in the seismic inversion workflow. One way to achieve this goal is by finding an analytical relation linking _{p}_{p}_{p}_{p}_{p}_{p}_{p}

Presentation Date: Wednesday, October 19, 2016

Start Time: 11:35:00 AM

Location: 161

Presentation Type: ORAL

attenuation, compressional modulus, equation, frequency, gas sand, image, model, porosity, property, quantification, relation, Reservoir Characterization, reservoir description and dynamics, rock, rock physics, rock property, saturation, seg seg international, seismic processing and interpretation, Upstream Oil & Gas

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

In this paper we demonstrate the use of the capillary pressure equilibrium theory (CPET) model to address the effects of partial saturation in order to estimate hydrocarbon saturation in a reservoir volume using acoustic impedances derived by seismic inversion. The data set used here has been donated by BHP Billiton, and is from an offshore oilfield called the Stybarrow field. The set comprises of a well with a 20-foot sandstone oil saturated pay section and 3D pre- and post-stack seismic volumes. Using the provided angle stacks and well log data, a statistical wavelet, and low impedance model, the final impedance model is computed. There are two final impedance models, derived from post-stack, and pre-stack data. The final impedance models are in agreement with one another at each of the well locations, with low impedance at the oil saturated well, and high impedance at the water saturated well. The corresponding CPET model is built based on the empirical porosity from the well log. The rock and fluid properties are available from the logs and petro physical reports provided by BHP Billiton. The CPET model has difficulty distinguishing between 0 and 30% water saturation. The impedances predicted by the CPET model are in good agreement at the two well locations (blind wells), predicting 98% oil saturation in the 97% oil saturated section, and 8% water saturation in the 5% water saturated section of the reservoir. Finally using the CPET workflow, a 3D distribution of saturation was computed from inversion derived acoustic impedance and the CPET model estimated from well log. Unlike conventional approaches of estimating saturation, our method is able to discriminate between patchy and uniform saturation. Our results on Stybarrow field data reveal that the Stybarrow field behaves in a manner very close to the uniform curve at low water saturation. However, starting at 30% water saturation or higher the distribution becomes slightly patchy.

Presentation Date: Wednesday, October 19, 2016

Start Time: 3:35:00 PM

Location: 167

Presentation Type: ORAL

Oilfield Places:

- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Stybarrow Oil Field (0.99)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Macedon Gas Field (0.98)

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

**Summary**

Laboratory permeability data from a wet sandstone reservoir (the Tubåen formation, Hammerfest Basin, located in the Barents Sea) subject to CO_{2} sequestration indicates an order of magnitude permeability variation at the same porosity. The velocity and density well data from the well, obtained prior to CO_{2} injection, show that at the same porosity, the samples with higher permeability have higher elastic moduli (both compressional and shear) as compared to the samples with lower permeability. To understand and quantify this effect, we fit the elastic modulus versus porosity well data with the theoretical constant-cement model theoretical curves. This theoretical rock physics analysis shows that the lower-permeability, softer samples have less contact cement that their high-permeability, stiffer counterparts. One interpretation of this meaning is that in the lower-permeability samples, part of the pore space is filled with fines that do not contribute to the grain-to-grain cementation thus reducing the stiffness (as compared to the well-cemented samples). This means, in turn, that in the softer samples, the fines partly clog the pores thus reducing the permeability. This logic is supported by the geological character of the Tubåen formation where the tidal and marine influence acts to worsen the grain sorting compared to well-sorted distributary channel sediment.

Barent Sea, cement, color, contact cement, curve, Dvorkin, flow in porous media, Fluid Dynamics, grain, injection, laboratory, model, permeability, physics, porosity, Reservoir Characterization, reservoir description and dynamics, rock, Snøhvit Field, Tubåen, Tubåen Formation, Upstream Oil & Gas, well

Oilfield Places:

- Europe > Norway > Norwegian Sea > Hammerfest Basin (0.99)
- Europe > Norway > North Sea > Central North Sea > Grane Oil Field (0.99)
- Europe > Norway > Barents Sea > Tubaen Formation (0.99)
- (3 more...)

SPE Disciplines:

**Summary**

Modeling the effect of fluid saturation in reservoir rocks is essential for hydrocarbon reservoir characterization and monitoring of CO_{2} during a sequestration experiment. Here we use the capillary pressure equilibrium theory to relate the saturation to the elastic properties of the host rock. This theory is based on the fact that natural rock is heterogeneous essentially at all scales. It requires that we break a volume of rock under examination into a number of subsamples, each with its own porosity, permeability, and elastic constants; vary the capillary pressure in the volume and observe how each subsample is saturated at fixed capillary pressure. Because the subsamples are different, the saturation will vary among them at each capillary pressure step. We compute the elastic properties of each subsample and then recombine them to obtain the effective elastic properties of the original volume. We also introduce the frequency dependence of the effective elastic properties. The example given includes a high-porosity sand dataset. Because this theory accounts for heterogeneity, it allows us to predict the mean as well as standard deviation of the elastic properties at given saturation. The results are always contained within the upper (patchy saturation) and lower (uniform saturation) bounds and allow us to narrow the range of anticipated responses.

bulk modulus, capillary pressure equilibrium theory, dependence, diffusion, elastic property, equation, fluid substitution, frequency, frequency effect, permeability, porosity, Reservoir Characterization, reservoir description and dynamics, reservoir geomechanics, rock, saturation, seismic processing and interpretation, subsample, theory, uniform, Upstream Oil & Gas, water

SPE Disciplines:

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SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (0.97)

The common properties of bitumen are: high specific gravity, low hydrogen to carbon ratios, high carbon residues, and high contents of asphaltenes, heavy metal, sulphur and nitrogen. Since it is very viscous, it does not flow so easily. Bitumen has gravity of about 10.3 API which translates into its density about 1.3 g/cc.

Bitumen deposits mostly found at very shallow depth, where temperature doesn’t exceed 15°C. Therefore in-situ bitumen acts as a solid, since bitumen properties depend on temperature. The less temperature is in a formation the more viscous bitumen is. Hence velocities and modulus of bitumen will also depend on temperature.

SPE Disciplines:

Well logs from deepwater Angola are texturally interpreted using a combination of petrophysical and rock physics models. The Thomas-Stieber model predicts the porosity resulting from various modes of sand-shale mixing. The Yin-Marion-Dvorkin-Gutierrez model predicts the associated P-wave velocities. Together, they offer a higher degree of constraint of formation properties.

clean sand, Deepwater Sediment, Dvorkin, formation evaluation, lithology, log analysis, Marion, model, point, porosity, Reservoir Characterization, reservoir description and dynamics, rock physics, rock physics analysis, sand, seismic processing and interpretation, shale, structural geology, Upstream Oil & Gas, well logging, West Africa

SPE Disciplines:

- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (0.90)

The main objective of this work is to present a new methodology for seismic reservoir characterization that provides fine-scaled reservoir models of facies and reservoir properties, such as porosity, net-to-gross, and, possibly, fluid saturation. The proposed iterative methodology is based on sequential simulations of discrete variables, namely sequential indicator simulation, and a stochastic optimization technique called probability perturbation method. At each step of the optimization we generate a facies model, distribute reservoir properties, calculate the corresponding elastic attributes through a rock physics model, compute synthetic seismograms and, finally, compare these synthetic results with the real seismic amplitudes. The stochastic optimization technique perturbs the probability distribution used to generate the initial model and obtains the most probable facies model through a relatively small number of iterations. The method is applied to a real well profile, where three facies have been identified, and finally extended to a real 2D seismic section.

Artificial Intelligence, facies, inversion, iteration, machine learning, model, physics, probability, probability perturbation method, property, Reservoir Characterization, reservoir description and dynamics, reservoir property, seismic processing and interpretation, sequential simulation, Simulation, stochastic optimization technique, Upstream Oil & Gas, well

SPE Disciplines: Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)

Modeling the effect of fluid saturation in reservoir rocks is essential for hydrocarbon reservoir characterization and monitoring of CO

bulk modulus, capillary pressure theory, distribution, elastic property, equation, fluid substitution, patchy saturation, permeability, porosity, reflection coefficient, Reservoir Characterization, reservoir description and dynamics, rock, sand, saturation, seismic processing and interpretation, structural geology, theory, Upstream Oil & Gas, water

Thank you!