The economic decision to develop a new field depends heavily on the reservoir quality which, in turn, is based on two factors: the storage capacity and the flow capacity of the reservoir. The former is controlled by the porosity and hydrocarbon saturation and the latter is control by the permeability. This crucial information are computed using sets of logging measurement which is often supported by routine and advanced core analysis data. The process of comparing the log based interpretation with the core results can be time consuming and costly. New developments in logging technology especially in geochemical and dielectric logging are aiming to improve the log derived interpretation and reduce the uncertainties of the evaluation. This paper presents a case study where the integration of the advanced and standard logging tool is used to reveal the true potential of a gas reservoir.
For Chevron in Western Australia the standard formation evaluation is usually based on spectral gamma ray, resistivity, density, neutron, sonic and magnetic resonance logs. This logging suite has been proven successful in determining the reservoir quality in clean gas sand reservoirs. However in new frontier fields the uncertainty becomes larger due to complex mineralogy, the choice of saturation equation, unknown formation salinity and the paucity of SCAL data. In this case study, the standard logging suites does provide a reasonable result, however, the introduction of the geochemical log reveals the existence of iron-rich heavy minerals, which suggests a higher calculated porosity after mineralogy correction. The dielectric log being sensitivity to water permittivity was used to measure the irreducible water volume independent of the inputs needed by a typical conventional water saturation method. In oil base mud environments, the dielectric log can measure the irreducible water in the reservoir as it is not displaced by the oil base filtrate. This advanced formation evaluation shows an increase of 22% gas in place in a particular compartment.
A continuous permeability measurement can usually be inferred by the magnetic resonance log based on the free fluid and bound fluid ratio using the Timur-Coates equation. The bound fluid volume is determined by using a typical T2, 33 ms cutoff. However, the paramagnetic minerals in the formation are known to cause alteration in magnetic resonance relaxation time. In this example, the paramagnetic minerals caused a faster transverse relaxation time, hence a higher bound fluid will be computed if the T2 cutoff is not adjusted. This phenomenon has been a difficult challenge to solve in our industry. A new approach to compute the permeability was tried in this study where the irreducible water computed from the dielectric log was used as the bound fluid. The free fluid was computed by subtracting the total porosity with the dielectric irreducible water. The Timur-Coates permeability using these inputs is more consistent with offset data and confirmed by the mobilities from the formation pressure testing tool. The new approach reveals an almost 300% increase of flow capacity compared to conventional methods in the studied section.
A new dielectric dispersion tool delivers a highly accurate shallow resistivity measurement in a variety of borehole environments. This new-generation dielectric tool differs from previous tools by incorporating a new antenna array on a fully-articulated pad, thus avoiding many of the environmental effects that plagued dielectric logging in the past. A further enhancement is that the new tool makes measurements at multiple frequencies from approximately 20 MHz to 1 GHz with collocated transverse and longitudinal transmitter and receiver arrays.
The new tool was recently used for the first time in Australia in several wells drilled with oil-based muds. Results from the dielectric tool were compared with results from traditional methods in two of these wells. These wells tested Triassic-aged fluvial and deltaic sands and shales on the Northwest Shelf, offshore Australia. In high-resistivity pay zones with resistivity greater than 100 ohm×m, the shallow resistivity measurement from the dielectric tool was superior to standard shallow array induction measurements and, in some places, seemed more representative than even the deep array induction measurements.
Dispersion processing uses the data acquired at multiple frequencies to calculate water-filled porosity. In pay sands, by combining the water-filled porosity from dielectric dispersion measurements with total porosity from density-neutron, water saturation can be calculated that is independent of formation salinity and does not require special core analysis measurements of electrical properties. The salinity of the water in the formation can be determined from conductivity and permittivity dispersion when conditions are favorable. Pre-job planning is essential because not all borehole conditions allow for accurate evaluation of all applications. Results for water saturation are consistent with conventional calculations from mineral-based log analysis, magnetic resonance data, and Dean-Stark core-plug saturation measurements.
Several other applications were tested, even though prejob planning indicated only a low-moderate chance of success. Determination of shale porosity, assumed to be water-filled, was tested against two types of core analysis which showed the tight sand and shale porosities to be in the 2 to 5 p.u. range. Dielectric dispersion results in shale intervals were generally close to the core plug porosity in one well and the total magnetic resonance porosity in the other.
In a gas reservoir where significant oil-based filtrate invasion took place, the water-filled porosity was very similar to the bound-fluid volume measured by the magnetic resonance tool. This observation reveals a new application for the tool as an alternative for faster bound-fluid logging.
Another application was formation water salinity determination. Pre-job planning suggested a moderate chance of success only for reservoir-quality sandstones. In clean sands, the dielectric results showed a fair match compared to in-situ salinity measurements from core plugs. However, in shaly sand and shale, the results are possibly affected by the high conductivity of clay-bound water. Further work has been proposed to improve the salinity inversion in shale.
Acharya, Mihira Narayan (Kuwait Oil Company) | Kabir, Mir Md Rezaul (KOC) | Al-Ajmi, Saad Abdulrahman Hassan (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company) | Al-anzi, Ealian H.D. (Kuwait Oil Company) | Kho, Djisan (Schlumberger Pty Ltd) | Darous, Christophe (Schlumberger Oilfield Eastern Limited) | Chakravorty, Sandeep (Schlumberger Oilfield Eastern Ltd)
Flow capacity evaluation in carbonate reservoirs is known to be challenging because of heterogeneity in the rock matrix. The original depositional texture and resulting pore structure is often altered by secondary diagenetic processes such as dissolution, leaching, cementation, and dolomitization, creating complicated pore systems with varying porosity to permeability relationship. Dolomitization in particular is known to be an important diagenetic process in carbonate reservoirs, typically enhancing porosity and permeability development and making the rock less susceptible to porosity reduction due to increasing effective stress during burial. Core data taken in deep carbonate reservoirs reveal a strong correlation between degree of dolomitization and reservoir quality.
Neutron-induced gamma-ray spectroscopy logging has proven to be a powerful tool for the evaluation of dolomite content, especially in wells drilled with barite-weighted mud where PhotoElectric Factor (PEF) is not reliable. Using methods developed on a core database, reservoir rock types can be identified and matrix permeability can be estimated from a combination of porosity and dolomite content derived from neutron-induced gamma-ray spectroscopy data and other common logs measurements. Predicted flow profiles and flow capacity of the reservoirs can be calculated from the estimated matrix permeability and can be verified by comparison with available production logs and test data.
Several examples will highlight the comparison between the predicted synthetic flow profiles and the flow profiles measured by production logs, as well as the comparison of estimated flow capacity with pressure transient analysis data. Such comparisons can be used to diagnose stimulation effectiveness, identify zones dominated by fractures, confirm solid bitumen effects, and identify zones with significant formation damage. Another important application is the selection of perforation and stimulation zones to achieve optimum production based on the expected permeability contrast. This integrated approach to flow capacity prediction is proving to be an effective tool in understanding the behavior of complex carbonate reservoirs
There are two important questions that are always the sustainability foundation of any oil and gas reservoirs development. They are: a) how much hydrocarbon is present or what is the storage capacity? The answers are related to the knowledge of porosity, saturation, area, and thickness of the reservoirs. b) can it be produced economically or later, how can it best be produced to achieve the highest economy benefits? The answers are related to the flow capacity of the reservoir which is a function of permeability.
Porosity, saturation and reservoir thicknesses can generally be derived at the wells from different techniques and logging tools, such as neutron, density, sonic, resistivities and magnetic resonance. On the other hand the flow capacity evaluation which is a dynamic property is known to be challenging, especially in carbonates. Carbonate rocks are chemically unstable and prone to dissolution, leaching, cementation, dolomitization and overburden compaction. These natural processes generally occur after the original deposition creating heterogeneity in carbonate matrix and especially impacting the rock's permeability.
Kho, Djisan (Schlumberger) | Grau, Jim (Schlumberger) | Khan, Badruzzaman (Kuwait Oil Company) | Ammar, Heyam (Kuwait Oil Company) | Al-Anzi, Ealian H. (Kuwait Oil Company) | Acharya, Mihira (Kuwait Oil Company)
Potassium formate based mud has gained wide-spread acceptance over the past decade, as its unique physical and chemical properties make it an ideal drilling and completion fluid for high-temperature and high-pressure wells. A formate based mud system using manganese tetra-oxide (Mn3O4) as the weighting material was selected to be evaluated in a pilot well in Kuwait, replacing the oil base mud that has been traditionally used in these fields. The main objectives of the pilot include obtaining higher quality of resistivity-based borehole images, retrieving pressure-volume-temperature (PVT) quality formation fluid samples, and minimizing formation damage. Formate mud has drilling and completion advantages compared with oil base mud, such as stable mud density, low equivalent circulation density, low gas solubility, and reduced formation damage. However, log data interpretation encounters serious challenges because of its unique mud properties, including high gamma ray radioactivity, low hydrogen index, high density, and high thermal neutron cross section. Efforts have been made by logging service providers to characterize their tools and to compensate for the effects of potassium formate mud. Most of the efforts were focused on improving borehole environmental correction algorithms. However, formation evaluation using these borehole corrected logs remains difficult, primarily because of mud invasion effects on the nuclear logs, which prevent the use of traditional petrophysical models for porosity determination. The neutron induced gamma ray spectroscopy log is also affected by the mud properties, particularly the effect of potassium and manganese contents. However, their signatures in the gamma ray energy spectrum can be stripped out leaving the formation elemental yields intact. The application of potassium formate mud in future development wells is encouraged, as all of the primary objectives of the pilot project were achieved and the challenges of the formation evaluation have been successfully overcome.
Characterizing reservoirs of northern Kuwait fields is complicated by the type of drilling mud. A heavy mud weight is usually required to ensure safe drilling operations in the fields with high H2S concentration and high reservoir pressure environment. Oil base mud with barite as a weighting agent is the current mud type used to drill the wells. The mud properties affect logging tools measurements and accordingly complicate the formation evaluation process. Hence, additional data are required to reduce the uncertainty of the evaluation results.
Reservoir quality is defined by two main factors, the porosity and the permeability of the rock. The reservoir quality index or rock typing is known to be an important input for field static and dynamic models. Core analysis data in the carbonate reservoirs across the fields reveals a strong correlation between dolomitization and the reservoir quality. The dolomitization process increases the reservoir porosity (storage capacity) and permeability (flow capacity). Hence, the quantification of dolomite content becomes important in classifying the rock quality. However, the estimation of dolomite content from conventional logs (density, neutron, and sonic) is complicated by several factors such as barite mud effects, oil base mud filtrate invasion, complex lithologies (clays, heavy minerals, anhydrite nodules, and pyrite), sensitivity of the tools’ measurements to dolomite, as well as differences in the tools’ vertical resolutions and depths of investigation.
Recent developments in the neutron capture spectroscopy tool improve the quantification of the dolomite as well as that of the other minerals. Using the measured spectroscopy data as inputs to multi mineral solver software provides more accurate lithology output, consequently yielding better porosity and water saturation calculation. Another application is to map the dolomite facies trends in the fields in order to select new wells’ location.
This paper describes the application of the magnesium yield measurement derived from neutron capture spectroscopy data to formation evaluation and characterization of northern Kuwait fields. The formation evaluation results were validated by cores.
Evaluation of porosity and lithology has always been done through a combination of density, photoelectric factor (PEF), neutron, gamma ray, and sonic measurements. None of these gives porosity or lithology directly. Therefore, common practice includes building petrophysical models to extract these reservoir properties. Geoscientists involved in petrophysical analysis using multi mineral solvers are aware of the difficulty and the uncertainty of the process; for example, changing a fluid property in the model will change the lithology as well as the porosity. The logs themselves are also known to have their own measurement uncertainties. The density log, for example, is affected by bad hole, lithology, barite, and light hydrocarbons. The neutron log is affected by lithology, fluid hydrogen index, and the borehole properties (temperature, pressure, hole size, stand-off, mud cake, mud weight, etc.). The interpretation is also complicated by the fact that different neutron tools from different logging companies have different sensitivities to lithology change. The PEF curve is commonly used as an additional tool to solve for the lithology.