Najmah-Sargelu Formations of Kuwait show considerable potential as a new unconventional hydrocarbon play and produces mainly from fractures. The key uncertainties which affect the productivity are the nature and distribution of permeable fracture networks, and the limits of oil accumulation.
This paper presents the results from whole-rock elemental analysis of three cored wells in UG field. The main objectives of this study are to use high-resolution elemental chemostratigraphy to gain a better understanding of the detailed stratigraphy and correlation of the Najmah-Sargelu Formations, to assess the chemo-sedimentology for determining the intervals of high organic content, to estimate the mineralogy of the sequence using an algorithm developed for an analog formation in North America; and to determine the most likely intervals to contain fractures, using a brittleness algorithm.
A clear chemo stratigraphic zonation is recognized within the Najmah-Sargelu Formation. The larger divisions are driven mainly by inherent lithological variation. The finer divisions are delineated by more subtle chemo stratigraphic signals (K2O/Th and Rb/Al2O3 ratios) and preservation of organic matter (high V, Ni, Mo, and U abundances). Zones of alternating brittleness and ductility are clearly identified within the interbedded limestones and marlstones of Najmah-Sargelu Formation.
Two unexpected but important features of the Najmah-Sargelu limestones were elucidated by the elemental data. Brittle, high-silica spiculites, with virtually no clay or silt, are more common than previously recognized from petrophysical logs and core descriptions in the upper Najmah limestones. In addition, the limestones adjacent to the spiculites tend to contain bitumen as pore-filling are recognized by the trace metal proxies. Ternary plots of V, Ni, and Mo differentiate the combinations of kerogen and bitumen present in the Najmah-Sargelu Formations.
The clarity and sensitivity of the chemostratigraphic signals are sufficient to enhance formation evaluation, and can also assist borehole positioning using the RockWiseSM ED-XRF instrument at wellsite.
It is found that in the deepest part of Cooper Basin (Permian section in Nappamerri Trough) in South Australia, two shale formations, Roseneath and Murteree have potential to be shale gas reservoirs. However, a comprehensive petrophysical evaluation has not been carried out so far. The free porosity among minerals, pore throat geometry, surface area and structure of micro pores for adsorption and diffusion of gas in these formations have not been well understood.
Two core samples from two wells (Della 4 and Moomba 46) were selected to evaluate mineralogy, free porosity and other petrophysical characterization. Since routine core analysis is not capable of petrophysical characterization of these very tight rocks, the latest technology of image scanning and processing of QEMSCAN (Quantitative Evaluation of Minerals using Scanning Electron Microscopy) and Computerized Tomography (CT) scanning have been used. QEMSCAN is a novel technology to process images from electron microscope to measure size and distribution of different minerals in a rock sample. QEMSCAN when combined with CT scanning can significantly enhance shale rock characterization and reservoir quality assessment. In this study, the main goal is the evaluation of total free porosity, micro pores and natural network of micro-fracture systems in our ultra fine samples.
Based on QEMSCAN analysis, it is found that the sample of Murteree shale has the mineralogy of quartz 42.78%, siderite 6.75%, illite 28.96%, koalinite 14.09%, Total Organic Content (TOC) 1.91 wt%, and pyrite 0.04%, while rutile and other silicates minerals were identified as accessory minerals. Total free porosity is found to be 2 percent. The free porosity is largely associated with clay minerals which shows intergranular linear, isolated and elongated wedge shaped pores. SEM images from the same core sample also show that the pores are mainly present in clay rich zone. QEMSCAN maps have revealed the location of lamination, high and low porosity zones as well as high and low sorption areas. In CT scanning, the porosity found in QEMSCAN, was not identified; however, a network of micro-fracture system in Murteree shale sample is identified.
Quirein, John Andrew (Halliburton Energy Services Group) | Murphy, Eric Eric (Halliburton) | Praznik, Greg (Halliburton) | Witkowsky, James M. (Halliburton Energy Services Group) | Shannon, Scott (Halliburton) | Buller, Dan (Halliburton Energy Services Group)
The Eagle Ford Shale hydrocarbon-fluid properties depend on the source rock maturity and, within the formation, occur in varying degrees of gas, gas condensate, and oil. Using conventional logs and pyrolysis data, several log-core regressions, such as delta log R, density, and uranium, can be derived to predict total organic carbon (TOC). The TOC can be used in conjunction with geochemical elemental measurements for a more accurate assessment of the formation kerogen and mineralogy, as well as hydrocarbon volumes. Nuclear magnetic resonance (NMR) porosity measures an apparent total porosity in the organic shale plays, measuring only the fluids present and excludes the kerogen. The complex refractive index method (CRIM) in conjunction with the mineralogy log data can be used to compute accurate dielectric porosities, which exclude both kerogen and hydrocarbon. Integrating the core TOC, predicted TOC, mineral analysis, NMR, and dielectric information, a final verification of the kerogen volume, hydrocarbon content, and mineral analysis can be assessed.
This paper will describe the integration of conventional logs, a geochemical log, an NMR log, and dielectric to predict TOC, kerogen volume, and hydrocarbon volume, as well as, total porosity and mineralogy. The data is compared to the actual core data from three Eagle Ford wells, and it will be shown how the proposed approach will eliminate some coring operations. Finally, it will be shown how these interpretation results can be rolled up to make decisions on where to drill the lateral.
The Eagle Ford Shale, as one of the most active unconventional reservoirs in the US, began heavy development in 2009. One of the attractive aspects of the Eagle Ford, which has heightened interest and helped to accelerate development, is substantial liquids production, along with solution gas. But the resultant multiphase fluid production, along with reservoir heterogeneity, typical of most unconventional reservoirs, adds complexity and risk to development, especially for the completion.
One technique that has the potential for reducing risk is learning from historical completion trends. Even though the Eagle Ford play is quite new, more than 3,000 horizontal wells have been drilled and all have been hydraulically fractured. The resultant large and growing data resource invites data mining to uncover trends and insights.
The ground work was laid in SPE 149258, which summarized 1,082 fracturing stages in 80 Eagle Ford well. This paper extends that analysis to more than 3,000 Eagle Ford fracturing stages in more than 200 wells. Metrics of completion types, volumes, and efficiencies are analyzed. In addition, the analysis is extended to production data and chemical fracturing additives. The entire data set is mapped in an effort to understand anomalies and trends. As the successful development of this reservoir has relied in the combination of horizontal drilling, multistage completions and hydraulic fracturing, the results should be valuable for understanding and optimizing completions in the Eagle Ford and similar shales.
Musharfi, Nedhal (Saudi Aramco) | Almarzooq, Anas (Saudi Aramco) | Eid, Mahmoud (Halliburton) | Quirein, John (Halliburton) | Witkowsky, Jim (Halliburton) | Buller, Dan (Halliburton) | Rourke, Marvin (Halliburton) | Truax, Jerome (Halliburton) | Praznik, Greg (Halliburton)
Radtke, R.J. (Schlumberger) | Lorente, Maria (Schlumberger) | Adolph, Bob (Schlumberger) | Berheide, Markus (Schlumberger) | Fricke, Scott (Schlumberger) | Grau, Jim (Schlumberger) | Herron, Susan (Schlumberger) | Horkowitz, Jack (Schlumberger) | Jorion, Bruno (Schlumberger) | Madio, David (Schlumberger) | May, Dale (Schlumberger) | Miles, Jeffrey (Schlumberger) | Perkins, Luke (Schlumberger) | Philip, Olivier (Schlumberger) | Roscoe, Brad (Schlumberger) | Rose, David (Schlumberger) | Stoller, Chris (Schlumberger)