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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.

Kuwait Oil Company is currently engaged in an early phase development of deep sub-salt tight naturally fractured carbonate reservoirs. These reservoirs has been tested and found to be gas bearing. They are uniquely characterized by dual porosity nature where natural fracture network systems are the primary flowing mechanism. The foremost challenge to produce from these reservoirs is the wellbore interaction with the natural fracture network systems. Despite drilling around 85 vertical and slightly deviated wells in this large challenging HP/HT reservoir complex, understanding and characterization of fractures is a challenge in the absence of horizontal wells, though fracture understanding has improved over time through careful integration and interpretation of logs, core, and seismic data. To achieve the dual objective of characterizing the fractures and to boost production, asset team recently embarked on the strategy to drill horizontal wells targeting these challenging tight reservoirs. As a fit for purpose solution to address these challenges, ЉHigh Definition Deep Directional Multi Boundary Detecting TechnologyЉ was incorporated in the drilling plan so that horizontal producers could be geosteered in the desired target intersecting as much fractures as possible. This technology, an advancement on the 1st generation ЉDistance to BoundaryЉ technology is characterized by its extended capability to detect multiple bed boundaries based on resistivity contrast up to 20ft around the wellbore. The significantly improved new multilayer stochastic inversion also solves for structural dip along the wellbore azimuth (longitudinal dip). In the lateral section, this technology successfully mapped the reservoir roof as well as multiple thin intra layers inside the target reservoir along with information on longitudinal dips which helped immensely to optimize trajectory inclination and spatially position the wellbore across different layers as per plan. Apart from detecting reservoir boundaries, the inversion also mapped conductive and resistive fractures cutting wellbore at high angle for the first time, while trajectory was drilling across a fracture corridor. This further added confidence to geo-steering while drilling as wellbore cutting through such a fracture corridor was highly anticipated in predrill planning. Drillpipe conveyed borehole images acquired after drilling the well confirmed the presence of large swarms of fractures detected through inversion.The effective integration of data from different fields in a single platform, like LWD logs, boundary information, dip information, drill cuttings information and decisions taken based on the interpreted information paved the way for the successful drilling of this well and achieve the predrill objectives.

The deep, sub-salt reservoir complex is tiered with fractured tight carbonate at bottom and top, with the two sub-units of "upper unconventional kerogen" and "lower inter-bedded kerogen-carbonate" in the middle. This depositional setting is challenging for horizontal well placement where the thicknesses of respective sub-units are about 50 and 30 feet with varying geomechanical and petrophysical properties. Additionally, this complexity poses limitations in completions and effective stimulation of the Kimmeridgian-Oxfordian reservoirs in several gas fields at development stage in Kuwait. A horizontal well is placed in the lower sub-unit of the laminated complex of unconventional kerogen and fractured carbonate reservoir as a Maximum Reservoir Contact (MRC) type well. A pilot mother-bore was drilled and logged to identify the lithological properties across the entire vertical domain - facilitates the optimization of horizontal drain-hole placement within the targeted reservoir units. No wellbore stability issues in drilling were predicted based on the geomechanical understanding where core-calibrated logs from offset vertical wells were considered. However, this modeling method did not have the functionality to integrate the impact of drawdown on the laminated formation which became unstable and collapsed during the short open-hole drill-stem test (DST) plugging the tubing prior to the final completions. An alternative "book-shelf" geomechanical model was considered at pre-drill stage for predicting the wellbore stability. Once the drilling was completed, the time-lapsed multi-arm caliper indicated the validity of the alternative methodology in predicting the unstable stack of laminations in kerogen-rich strata. The paper discusses an optimization methodology to enhance the understanding of static and dynamic geomechanical stability through the use of BHI data. Objective of the proposed method is to help improve the effectiveness of completions where wellbore stability due to geomechanical complexity in stacked-pay reservoirs is a primary wellbore challenge in deploying the completions and executing a subsequent stimulation and testing campaign.

The tight deep carbonate reservoirs of Oxfordian age in North Kuwait consist of tight limestone interbedded with organic rich shale layers. The overall matrix porosity is generally very low and the production is mainly from fractures in the crestal part of main structures. Borehole images are routinely acquired in vertical to moderately deviated wells drilled with oil-base mud for fracture characterization.For detailed fracture property evaluation, a highly deviated pilot hole was drilled with water-base potassium formate mud for the first time across the reservoir section and drill-pipe conveyed high-resolution electrical borehole image data was acquired. The upper half of the interpreted interval showed potential open fractures sets, NE-SW striking fracture set was most abundant. An advanced fracture segment extraction workflow was used to determine porosity and aperture of different fracture sets.The first horizontal well was then drilled as a lateral in the target reservoir with oil-base mud restricting direct computation of fracture properties. The electrical and acoustic images in OBM indicated fracture concentrations at quite a few places along the horizontal well trajectory, the most conspicuous occurring at the zones where heavy mud losses were encountered while drilling. A 2D litho-structural model was constructed along the well trajectories using the dip data and open-hole logs to correlate finer carbonate and organic shale layers and fracture distribution across the layers. This workflow permitted extending fracture properties along horizontal well as well.Finally, a high-resolution 3D structural model was constructed using outputs from previous workflows and data from two nearby vertical / less deviated wells. The final model showed a folded structure, which was absent in the existing model of the field. Thus the innovative workflow provides a means to generate an accurate structural and fracture model for the reservoir, integrating the fracture characteristics of the individual sub-layers with the main fracture corridors.