One role of the petrophysicist is to characterize the fluids encountered in the reservoir. Detection of a change in fluid type in the rocks while drilling is usually straightforward with the use of gas and chromatographic measurements. Gas shows and oil shows while drilling are time-honored indicators of zones that need further investigation through logs, testers, and cores. In the rare case of gas-bearing, high-permeability rock drilled with high overbalance, gas will be flushed from the rock ahead of the bit, will not be circulated to the surface in the mud, and will not produce a gas show. Because hydrocarbons are not always part of a water-based-mud formulation, sophisticated analytical chemical techniques can be used on the oil and gas samples circulated to the surface and captured to determine the properties of hydrocarbons in a given zone penetrated by the drill bit.

Abstract Mesozoic age Golapalli sands are found in the Krishna Godavari Basin, located in the East coast of India. These sands are highly prospective for hydrocarbon exploration and development. They comprise of syn rift sediments, often, exhibiting low permeability. In general, these reservoirs do not flow naturally without hydraulic fracturing. Oil presence in Golapalli sands has already been proven in the basin from the exploratory wells. However, conventional saturation modeling using basic petrophysical logs has proved futile in establishing a definite oil water contact (OWC). This adds further complexity in the reserve evaluation and the hydraulic fracturing design. Moreover, the field is divided into multiple fault blocks with localized OWCs. During the initial appraisal phase, wells that were hydraulically fractured produced oil with high water cut. This prompted re-evaluation of saturation modelling with 3 further appraisal wells. All new wells were selected at different fault blocks within the field and were to be drilled as slim holes of 5-7/8in diameter in reservoir section. Potential intervals with natural fractures were successfully evaluated using advanced sonic data. Zones of interest were selected integrating the fractures network identified with advance sonic measurements and high porosity values obtained from basic neutron-density logs. To constrain inversion resistivity-based saturation modelling, a new workflow was adopted to determine reservoir fluid movements prior to hydraulic fracturing in less than 0.05mD formation. Through this approach, fluid saturations were successfully evaluated using a deterministic downhole fluid identification which helped in reducing saturation uncertainties while demarking the transition zone between oil and water in 0.05mD formation. With known oil zone identified, advanced sonic measurements were used to design effective hydraulic fracture models. A successful hydraulic fracture was initiated with excellent oil production with significantly reduced water cut compared to previous wells. In this paper, a novel workflow will be presented that will help in characterizing fluids in tight sands (permeability less than 0.05mD). This workflow integrates the basic openhole logs and formation testing with conventional resistivity-based saturation modeling to accurately pinpoint the OWC in the tight sands. This workflow has applicability in unconventionally tight reservoirs where there is uncertainty in fluid saturations or fluid contacts. Through this methodology, the propagation of hydraulic fracture into the water zone can be prevented which will greatly help in reducing the water cut in such conditions.

Formation testing has been widely prevalent in the industry for critical information, such as reservoir pressure, gradient analysis, and fluid identification, that aids formation evaluation. This paper focuses on the successful evaluation of low-mobility reservoirs using the 3D radial probe as compared to the conventional probe in a comprehensive study of 60 wells (most of them offshore) across India. One of the major challenges in formation evaluation, fluid flow from any interval is not certain. Prospective zones are encountered that lie in unconsolidated sands where critical drawdown pressure cannot be exceeded because of formation integrity issues or there are zones that have low mobility and thus cannot be tested. Reliable pressure results cannot be obtained from these formations, nor can the fluids in these zones be identified because of poor flow potential. To overcome this major challenge, different probe (tool inlet) configurations are used that increase the flow area and help test tight formations (e.g., the 3D radial probe). In this study, 1754 stations were analyzed across several heterogeneous formation types and multiple operators to verify the diverse applicability of the 3D radial probe. The analysis was conducted in two phases. Formation testing results from the first phase showed that 47% and 68% of the points of interest in 2018 and Q1, Q2 of 2019, respectively, across all wells remained unevaluated with the conventional probe. Even among the points that gave valid results, there were low-mobility points where downhole fluid analysis (DFA) was not possible because of poor flow potential. Upon introducing the 3D radial probe in six wells, the shortfall of the conventional probe was overcome, which ultimately contributed to 35% additional evaluation success in 2018. In a comparison of the performance on the same wells and same formations, 3D radial probe fluid identification success in 2019 was 93% compared to 2% success in conventional probe evaluation in these tight reservoirs. Through this study, the uncertainty of fluid typing in the tight reservoir was resolved. Accurate interval permeability values were determined and were input to well deliverability estimates. The 3D radial probe results also help the drillstem test (DST) design, saving significant well cost because wet intervals are avoided using downhole fluid characterization, which revolutionizes formation testing in tight reservoirs.

ABSTRACT

Running Pulse Neutron logs in Malaysia has previously been plagued by high uncertainties, especially in brown fields with complex multi stacked clastic reservoirs. Together with a wide range of porosities and permeabilities, the acquired logs quite often than not, tend to yield inconclusive results. In addition, the relatively fresh aquifer water (where salinity varies from 5k to 40k ppm) makes reservoir fluid typing and distinguishing between oil and water even more challenging. Again, the inconsistencies and uncertainties of the results tends to leave more questions than answers. Confidence in utilizing pulse neutron logging, especially to validate fluid contacts for updating static and dynamic reservoir models decreased to very low levels within the study teams. Due to this fact, the Petrophysics team took the initiative to conduct a 3-tool log-off in one of their wells with the objective of making a detailed comparison of 3 pulse neutron tools in Malaysia’s market today. The main criteria selected for comparisons were consistency of the data, repeatability and statistical variations.

With recent advancement in Pulse Neutron (Multi Detector) tool technology, newer tools are being equipped with more efficient scintillation crystals, improving the repeatability of the measurements as well as the number of Gamma Ray (GR) count rates associated with the neutron interactions. In addition, the newer tools have now up to 5 detectors per tool, with the farthest detector from the supposedly being able to “see” deeper into the formation, albeit at a lower resolution. With these new features in mind, the log-off was conducted in a single well with a relatively simple completion string (single tubing, single casing), logged during shut-in conditions only, and the logs were acquired directly one after the other (back-to-back) to avoid bias to any particular tool.

Both Sigma and Spectroscopy measurements acquired to compare the capabilities of each tool. Due to the relatively fresh water salinity, the Carbon-Oxygen ratio from the Spectroscopy measurements used to identify the remaining oil located in the reservoirs, while the Sigma measurements determine the gas-oil or gas-water contact, if present.

This paper will illustrate the steps taken by Petronas Carigali Sdn Bhd (PCSB) to compare the raw data and interpreted results from the 3 pulse neutron tools. A comparison from all the tools is discussed in length, and consequently compared to the current understanding of the reservoir assessed. The points from these comparisons will then show why one of the tools is favored than the rest.

ABSTRACT Fluid factors play an important role in reservoir fluid identification. Previous fluid factors generally based on reflectivity or impedance information, which effectively highlight the fluid-related anomalies and possess the ability to identify hydrocarbon bearing sandstones from others. However, they are largely dependent on porosity, which may lead to multi-results of fluid identification in heterogeneous reservoirs. Here we proposed a porosity-insensitive normalized fluid factor (PIF) based on the constructed rock physics template of S-wave impedance versus the ratio of bulk modulus to shear modulus. We demonstrate the proposed fluid factor can provide more reasonable estimation of hydrocarbon content compared with others by the application on well log and seismic inversion data from Sulige Gas field of Ordos Basin. Presentation Date: Tuesday, September 17, 2019 Session Start Time: 9:20 AM Presentation Start Time: 11:00 AM Location: Poster Station 5 Presentation Type: Poster

Layered flow often occurs in high-angle wells (i.e., a water layer in the lower part of the wellbore cross-section, an oil layer above the water, and a gas layer at the upper part of the cross-section). While the tools used in vertical wells have proven effective in high-angle wells on most occasions, special tools have been developed for studying two- and three-phase flow. These tools make use of arms to position electrodes across the casing diameter. Consequently, they are "blind" to flow outside a screen or perforated liner. The brief descriptions of these tools that follow are based on the limited published information and personal discussions with suppliers.

The Young’s modulus and Poisson’s ratio are the important elastic parameters of tight reservoir and the Fluid term is commonly used in fluid identification as a fluid factor with high sensitivity. The pre-stack seismic inversion is an effective way to obtain such parameters. However, the common pre-stack seismic inversion methods cannot invert such parameters directly. It must first invert other elastic parameters and then transform them into the Young’s modulus, Poisson’s ratio and Fluid term by some formula. The errors will be accumulated in the second step and will lead to a large deviation of the inversion results. We derive a new reflection coefficient equation in terms of Young’s modulus, Poisson’s ratio and Fluid term, which can establish the direct relationship between the reflection coefficient and the Young’s modulus, Poisson’s ratio and Fluid term. By using the new equation, we can invert the sensitive parameters of tight reservoir directly. Application shows that the direct inversion method can be used to predict the distribution of tight reservoir and identify the type of internal fluid simultaneously.

Presentation Date: Thursday, October 18, 2018

Start Time: 8:30:00 AM

Location: 206A (Anaheim Convention Center)

Presentation Type: Oral

The phenomenon of velocity dispersion and amplitude attenuation will occur when seismic wave propagates in oil and gas reservoir. To make full use of amplitude and frequency responses contained in angle-stacking seismic data, the viscoelasticity of underground media is introduced to simulate the attenuation and dispersion effects of seismic waves. First, the frequency-dependent viscoelastic fluid indicator is constructed to characterize the dispersion magnitude quantitatively of seismic waves caused by pore fluids. Then the frequency-dependent viscoelastic F-AVA approximation is deduced based on Futterman constant Q-model and the accuracy of the proposed approximation is verified by one double-layer theoretical model. Besides, the mapping equation and objective function of F-AVA inversion are proposed by jointing continuous wavelet multiscale decomposition, Bayesian estimation framework and priori model regularizations together. Finally, one field case was studied carefully to demonstrate the practicability of frequency-dependent viscoelastic fluid indicator (FDVFI) estimated from pre-stack F-AVA. Compared with the conventional frequency dependent fluid indicator, the proposed FDV-FI indicator can describe the fluid properties in the pores of reservoir more effectively.

Presentation Date: Tuesday, September 26, 2017

Start Time: 10:10 AM

Location: 370D

Presentation Type: ORAL

Abstract The Upper Urho Sandy Conglomerate Reservoir in Xinjiang oilfield features complex lithology, low porosity and low permeability, and a majority of secondary pores with poor connectivity. Due to those characteristics, the log responses are complicated and it is difficult to determine the oil saturation with conventional resistivity method. In this paper, the reservoir heterogeneity was studied based on image logs and nuclear magnetic data, and oil saturation was calculated using array dielectric data. An integrated reservoir evaluation and fluid identification approach was established and applied in five wells located in different fault blocks. The testing results from four of them have proved the effectiveness of the proposed method. This is the first time to use array dielectric tool to identify fluid type in conglomerate reservoir with volcanic matters, and it has been introduced to similar oil reservoirs in other oilfields, which also obtained good application effect.

Abstract Guantao oil reservoir of the Bohai Bay, is characterized by low formation water salinity, high pore structure heterogeneity and flooding, which complicates the logging response, especially the low contrast of resistivity response. Traditional methods by resistivity fail to estimate reservoir parameters accurately and cannot determine producible fluid type. In this study, the reservoir heterogeneity was investigated with advanced nuclear magnetic resonance data, and oil saturation was calculated using array dielectric data. Combining the two aspects, a special reservoir evaluation and fluid identification method was established.