Total Organic Carbon (TOC) is a critical parameter to determine reservoir quality of any source rock play. Carbon is present in all organic components of a rock, namely, kerogen, bitumen and hydrocarbons. However, properties like maturation of the organic matter and hydrocarbon type influence TOC measured on both core or determined from logs. TOC in a gas-bearing source rock play mostly denotes carbon associated with kerogen as carbon density of gas is generally too low to be detectable. In an oil bearing source rock play, TOC is a mix of kerogen, bitumen and liquid hydrocarbon. In this paper, we investigate TOC as a combination of 1) Kerogen Hosted Carbon, and 2) Extractable Organic Matter (EOM). The value of using individual organic matter components in petrophysical modeling and its impact on results is presented using examples from an oil window source rock play in the Middle East. A critical examination is carried out of the different log-based TOC methods and their sensitivities to different organic carbon constituents. With a focus on oil window plays, recommendations are provided on core-log calibration. Simple qualitative methods utilizing rock pyrolysis results and log-based TOC estimation methods to evaluate reservoir quality are presented. Such an analysis is particularly useful to source rock plays in the oil window. Rock-Eval pyrolysis is commonly used to estimate maturity in unconventional plays. However, for plays in the oil window, maturity estimation can be hampered due to Tmax suppression in the presence of bitumen (e.g., Snowdon 1995; Souza et al. 2014). Results of a source rock oil play from the Middle East are presented along with recommendations on removing the effects of Tmax suppression to achieve a representative maturity assessment.
Archie’s empirical resistivity-saturation relation of 1942 is widely applied in the petroleum industry. Despite its shortcomings, Archie’s equation is the basis for inferring water saturation, even in carbonates with complex pore structure, albeit with empirical tuning of cementation and saturation exponents. Industry literature is replete with examples of why this approach leads to erroneous estimates of the water saturation, and methods have been proposed where the range of saturation present in the reservoir has been subdivided into segments, each having a different set of exponents. Here, based on a homogenization methodology, we propose an effective resistivity model of an inter- and intragranular vuggy carbonate, when the pore sizes in the subsystems are well separated. The model is applied both for water-wet and mixed-wet rocks with appropriate modifications. Methodologies for apportioning pore fractions and their sizes depend on the openhole logs and/or core data. Computed results show significant deviations from Archie correlations in microporous or vuggy intervals. Results are verified on several Middle East carbonate formations against core and evidence from nuclear logs.
ADCO started its unconventional exploration campaign in 2012 targeting the tight carbonate sequences known as Wasia Group, onshore Abu Dhabi. A front-end loaded data gathering strategy was employed to acquire extensive latest generation logging data tailored for unconventional reservoirs. In a number of wells the entire reservoir section was cored, often up to 800 ft per well, leading to more than 3000 ft of core retrieved to date. ADCO applied unconventional core analysis technologies, such as retort analysis, to generate the optimal core results. Key parameters such as effective porosity, pore size distribution, TOC, source rock maturity, mineral compositions and fluid saturations were determined from logs and core data (where available). This paper will focus on the petrophysical challenges during the evaluation of the Wasia Group. We will demonstrate that conventional core analysis techniques have only limited applicability, whereas core analysis techniques designed specifically for unconventionals provide more relevant results. A log analysis methodology centered on the application and importance of NMR in unconventional liquid plays is presented. Porosity data measured through retort analysis provide an excellent fit to NMR log-based porosity measurements. Conventional core analysis results generated a poor fit to log porosity, and the resulting values exhibited scatter with a large standard deviation. T2 distribution from NMR log data suggests the presence of large pores with good fluid mobility, which requires confirmation through formation testing or production. Log data-derived rock typing was performed. It is based on principal component analysis of the reservoir section. Rock classification may help in selecting suitable zones for hydraulic fracture initiation. Lessons learned from the initial wells for core recovery and analysis techniques are summarized below and have been implemented in later wells: –Preserve part of the core for robust saturation measurements.–Stop acquisition of conventional poro-perm data–Focus on unconventional-specific retort-based techniques for core petrophysics–Focus on pulse decay permeabilities–Use scratch test to aid in core analysis sample selection process, especially for rock mechanics–Add core T1/T2 NMR and MICP to future core analysis programs The complete integration of core and log data has allowed for a thorough assessment of the unconventional hydrocarbon potential within the ADCO concession.
Exploration drilling for gas potential in Khuff Formation started more than 40 years ago and wells across multiple assets in offshore Abu Dhabi showed the presence of sizeable reserves. With increasing recent importance on gas production, there is a plan for moving towards development for those Permian tight gas structures to address the nation's gas needs. This paper will try to address the lessons learned from the recent appraisal wells in Khuff, the uncertainties and the success criteria. There have been multiple wells drilled through the Khuff Formation in Offshore UAE in the last two years and have yielded a wealth of information from downhole well logs, mud logs, well test results and core data. The downhole logs acquired in these wells ranged from basic triple-combo and mud logs to image and dipole sonic logs, along with formation testing and sampling measurements, followed by well tests across the zones of interest. Interpretation of all these data have revealed some interesting lessons learned. The shallow marine sequence of the Khuff Formation is generally characterized by poor porosity and low matrix permeability; however, the diagenetic overprint has resulted in a significant heterogeneity development, which controls the present-day porosity and permeability development at the wells. The well test results show variations in terms of 2 or 3 orders of magnitude at the same interval, which highlights potentially problematic development strategies. We have observed significant differences in terms of lithology, porosity and other reservoir quality indicators between wells, located a kilometre apart. Optimization of logging suite to minimize petrophysical evaluation uncertainty will be discussed. Characterising this heterogeneity is key for future economic success of this play. Possible role of fractures influencing flow from the Khuff have been discussed in older publications, however no conclusions were arrived at, with certainty. Presence of fractures and faults beyond the immediate vicinity of the well might be something to look at, in terms of understanding the potential productivity of those intervals. A big step for developing Khuff Formation might be in terms of deciding the optimal stimulation strategy and this is something, which remains to be studied extensively in UAE. Closing the loop of interpretation of the acquired logs with the final well-test results and production logs gives us the advantage of hindsight and helps us in separating out the key productivity indicators as well as bring out the uncertainties in formation evaluation, which affect these tight gas reservoirs.
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