The giant Albian upper Burgan reservoir in northern Kuwait is a major productive interval in both the Raudhatain and Sabiriyah fields. It is planned to increase production from the upper Burgan by over 300 percent through the application of field-wide waterflood. Phase 1 of seawater injection was started in 1999. A comprehensive geological study of the upper Burgan has included reviews of all core data, biostratigraphic information, and geochemical and petrographic analyses. The results indicate that the reservoir sandstones were laid down in a complex series of paralic environments ranging from shallow-marine to valley-fill channels. The resultant layering scheme was integrated with all available dynamic data to best define the reservoir architecture and flow units, and to construct a fine-grid 3-D geological model. The geological analysis has had a significant impact on reservoir development, influencing waterflood strategy, pattern orientation and expected performance. In the Raudhatain field, where reservoir connectivity is relatively high, a peripheral waterflood will be implemented (at least initially), whereas the complex structure and stratigraphy of the Sabiriyah field dictate a pattern flood.
The characterization of the unconventional reservoirs is a challenge. Though the Jurassic formation, Najmah-Sargelu, in North Kuwait fields have been tested and found to be a prolific source-rock as well as a producer of gas, condensate and volatile oil in several wells, but raised the flagged issue as regards to its characterization and predictability for success. The drill stem test (DST) results at some wells are quite successful without any stimulation, while at other wells the DSTs are unsuccessful in spite of advanced and repeated stimulations. Thus resulting a success rate at 50% and categorizing the Najmah-Sargelu as a geologically-complex, naturally-fractured, tight gas and condensate reservoir. The Najmah kerogen member, formally known as Najmah shale, the source-reservoir composed of highly organic rich argillaceous and calcareous clay, represented by very high total gamma ray values associated with high uranium on spectral gamma logs. The Sargelu limestone, underlying the Najmah kerogen and overlying Dhruma shale, is generally tight and occasionally fractured. Conventional characterization by multi disciplinary data integration and model could not explain the test results, suggesting the key factor making these kerogen reservoirs to producer lies outside our scanned parameters such as structural position, fractures and formation damage etcetera. Conventional petrophysical interpretation and integrated formation evaluation method fell short to explain the unique behavior of such reservoirs. This paper illustrates the new parameter, organic richness of Najmah kerogen sub-units and the pattern relationship between the success as flowed and unsuccessful as no-flow DSTs from the well data. Thus characterizing the Najmah reservoir based on their organic richness, derived from wireline density logs. This approach has successfully predicted our recent Najmah completed wells. Understanding this critical factor will navigate the 3D model building workflow steps for seismic reservoir description and future development strategy of Najmah in north Kuwait and other regions as well. Introduction The Jurassic formations in North Kuwait have proven hydrocarbon potentials and prospectivity for gas, condensate and volatile oil from composite Najmah-Sargelu and Marrat reservoirs in different fields of North Kuwait such as North-west Raudhatain, Raudhatain, Sabriyah, Umm Niqqa, Dhabi and Bahra (Figure 1). The Najmah formation has two informal members; generally known as lower, Najmah shale and upper, Najmah limestone. The lower member, represented by high total gamma ray values associated with high uranium on spectral gamma ray logs, is composed of highly organic-rich argillaceous and calcareous clay, is called the Najmah shale or Najmah kerogen. The term Najmah kerogen in this work is used interchangeably with Najmah shale. This Kerogenous unit is believed to be one of the main source rocks for the shallower and younger Cretaceous in most major oil reservoirs in Kuwait, as well as the deeper reservoirs. However the results of drill stem tests highlighted the problem of how to identify productive zones and sweeter areas in these unconventional reservoirs, challenged with their geologically complex and naturally fractured, tight nature. To date, 29 wells have been drilled in these six fields and 14 of them tested in composite Najmah-Sargelu reservoir, with a 50% success rate.
Exploration activity during the last eight years, targeting Jurassic carbonate reservoirs in North Kuwait, has culminated in the discovery of six major tight gas fields, encompassing an area of about 1,800 sq km with a reservoir gross thickness of about 2,200 ft. These fields are the first free-gas fields in Kuwait, which were put on early production during 2008. The reservoirs are characterized by dual porosity, dominated by low porosity and permeability, in deep HP/HT conditions, with wide variety of hydrocarbon fluids ranging from black oil to gas condensate with sour gas. Typical per well production rates are up to 5,000 BOPD/BCPD and 10 MMSCFPD, making them an excellent commercial success. Despite the limited number of 38 well penetrations to date in this large Jurassic complex, understanding of the depositional model has improved over time through careful integration and detailed interpretation of log, core, and seismic data. Based on these studies, a depositional model incorporating sabkha, tidal flats, lagoon, backshoal, shoal, shoreface inner shelf, outer shelf, and slope/basin depositional environments has been built. Hypersaline brines were generated in the lagoon and seeped downward, selectively dolomitizing the underlying strata, creating secondary porosity and permeability, and significantly improving the reservoir characteristics in some of these fields. From the early phases of exploration, the role of natural fractures in enhancing the production from these reservoirs was recognized. Accordingly, well data acquisition is designed to maximize reservoir understanding. Delineation and development well placement are optimized to penetrate the most heavily fractured corridors, through a combination of seismic attributes and Discrete Fracture Network modeling, constrained by available well data.
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