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Joshi, Girija (Kuwait Oil Company) | Acharya, Mihira Narayan (Kuwait Oil Company) | Al-Azmi, Mejbel Saad (Kuwait Oil Company) | Dashti, Qasem M (Kuwait Oil Company) | Van Steene, Marie (Schlumberger Oilfield Eastern Limited) | Chakravorty, Sandeep (Schlumberger Oilfield Eastern Limited) | Darous, Christophe (Schlumberger Oilfield Eastern Limited)
The deep organic-rich calcareous Kerogen of North Kuwait, a continuous 50ft thinly alternating carbonate - organic-rich argillaceous sequence, is not only a source rock but has gained importance as potential reservoirs themselves of typical unconventional category. Kerogen characterization relies on quantifying total organic carbon (TOC) and estimating accurate mineralogy. This paper describes an attempt to directly measure TOC of the Limestone-Kerogen sequence.
For the present study, empirical estimations of TOC have been carried out based on various conventional log measurements and also nuclear magnetic resonance. The introduction of a new neutron-induced capture and inelastic gamma ray spectroscopy tool using a very high-resolution scintillator and a new type of pulsed neutron generator for the deep unconventional kerogen resources have provided a unique opportunity to measure a stand-alone quantitative TOC value using a combination of capture and inelastic gamma ray spectra. In this process, Inorganic Carbon Content (ICC) is estimated by using elemental concentrations measured by this logging tool in addition to measuring Total Carbon (TC). The difference between TC and ICC gives direct TOC.
The advanced elemental spectroscopy tool measurements were first used to determine accurately the complex mineralogy of the layered carbonate and organic-rich shale sequence. The petrophysical evaluation and heterogeneity seen on borehole image logs were calibrated with extensive laboratory measurements of core / cuttings data. The final results are considerably improved compared to conventional empirical estimation. Once the mineralogy is properly determined, the log-derived TOC matches very well with core measured TOC.
This technique has provided a new direct and accurate log-derived TOC for Kerogen characterization. The application has a potential to be used for CAPEX optimization of the coring in future wells. This technique can also be applied in HPHT and High-angle horizontal wells, which can overcome challenging coring difficulties in horizontal wells.
Acharya, Mihira Narayan (Kuwait Oil Company) | Al-Ajmi, Saad A. (Kuwait Oil Company) | Al-Azmi, Mejbel S. (Kuwait Oil Company) | Joshi, Girija K. (Kuwait Oil Company) | Dashti, Qasem M (Kuwait Oil Company) | Al-Anzi, Ealian H D (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger Oilfield Eastern Limited) | Darous, Christophe (Schlumberger Oilfield Eastern Limited)
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.
Pradhan, San Prasad (Kuwait Oil Company) | Acharya, Mihira Narayan (Kuwait Oil Company) | Fidan, Erkan (Kuwait Oil Company) | Rao, Narhari Srinivasa (Kuwait Oil Company) | Al-Awadhi, Mansour (Kuwait Oil Company) | Singh, J.R. (Kuwait Oil Company) | Dashti, Qasem M. (Kuwait Oil Company)
Deep HP-HT sour carbonate reservoirs in Northern Kuwait have varied matrix properties and fracture intensities. The wells are drilled with barite laden OBM with 1,000-2,000 psi overbalance. The intervals suffer substantial formation damage during drilling as is evident from the fact that the wells normally do not get activated, in spite of creating an underbalance of 5,000-6,000 psi by displacing mud with a lighter fluid.
During the early exploration phase of these reservoirs, long and/or multiple intervals were perforated and treated with conventional matrix stimulation using 28% retarded/ emulsified acid in stages with chemical diverter (gel based and visco-elastic surfactant based). Post stimulation PLT survey in these wells indicated, that only about 5-10% of the total perforated interval contributed to the production; concluding that the diverters were found to be ineffective leading to sub-optimal reservoir management due to poor zonal contribution.
As part of strategic reservoir management process selective bottom up approach in perforation with higher concentrations of HCl treatment and without diverter has been adopted in these reservoirs. To obtain a degree of diversion over the perforated interval, the acid was pumped at higher rate and with higher pressure. Adoption of this changed perforation and stimulation treatment has been proved to be the key enablers for improving zonal productivity.
Around 30 wells have been completed with this changed perforation strategy and treated with this new recipe and technique. Post stimulation test results are comparable to those wells treated with regular matrix stimulation. The PLT survey post acid wash treatment by this technique showed that zonal contribution has improved. This process in addition to being simpler is faster and cost effective. This paper presents the comparison between the two types of perforation and stimulation strategies vis-à-vis test results and also the QA/QC followed prior to pumping the acid.
Dashti, Qasem M. (Kuwait Oil Company) | Al-anzi, Ealian H.D. (Kuwait Oil Company) | Al- Doheim, Aref (Kuwait Oil Company) | Kabir, Mir Md Rezaul (Kuwait Oil Company) | Acharya, Mihira Narayan (Kuwait Oil Company) | Al-Ajmi, Saad (Kuwait Oil Company)
Robustness of measurement while drilling (MWD) and logging while drilling (LWD) tools is laboratory-tested and rigorously field-tested for the expected operating and measurement specifications. Such tools have been used in the industry for decades with proven track record of stability. However, a typical tool string deployed as a part of bottom-hole assembly (BHA) has recently failed to withstand the unexpected BH conditions during drilling of the pilot hole using potassium formate mud (KFM), a heavy water based mud. The failure occurred within a deep-fractured calcareous kerogen section (CKS).
The tools had multiple surface communication failures; the first one was resolved as debris was found obstructing the rotor-starter part before drilling the CKS. The second failure occurred in the back-up tools, after drilling into the CKS and remained unexplained throughout drilling with the expectation of BH data recorded on memory. Inspection of the tool components, once the drilling was completed, revealed two major findings: First, some parts of the BHA, specifically the components of the CuBe tool had "vanished??. Secondly, the recovered tool parts had further damage due to corrosion and pitting. In addition, an unexpected color change in metal body parts was observed.
In the paper, the authors explain the unique mystery of tool eating "down-hole ghost??. Similar tools were previously used without an issue at comparable high pressure and temperature conditions and in geological sections alike in Kuwait in drilling with oil-based mud. The service provider's operational experience elsewhere has failed to explain the bizarre outcome, as they had not encountered similar incidents of vanishing tool parts and down-hole color change. The claim was that similar tools were successfully operated in water-based mud drilling including KFM. This claim was confirmed prior to the field execution with metallurgical compatibility tests carried out by the mud supplier.
Al-Anzi, Ealian H.D. (Kuwait Oil Company) | Rao, Narhari Srinivasa (Kuwait Oil Company) | Al-Ashwak, Samar (Kuwait Oil Company) | Kidambi, Vijay Kumar (Kuwait Oil Company) | Al-Ajmi, Neema Hussain (Kuwait Oil Company) | Rao, Jonna Dayakar (Kuwait Oil Company) | Al-Ateeqi, Khalid Abdullatif (Kuwait Oil Company) | Al-Mayyas, Rawan Hussain (Kuwait Oil Company) | Al-Anzi, Abdullah Motar (Kuwait Oil Company) | Olderman, Allan Stefanic (Kuwait Oil Company) | Acharya, Mihira Narayan (Kuwait Oil Company) | Chakravorty, Sandeep (Schlumberger) | De Keyser, Thomas Lee (consultant)
Deep, tight carbonate reservoirs of Pliensbachian, Sinemurian, and Hettangian Stages of the mid-Mesozoic Era are becoming very important in the continued pursuit of hydrocarbon prospects in North Kuwait. At present, a total of 21 wells have penetrated the targeted reservoir zones. Of these, 12 have been tested for hydrocarbon production covering a large area of about 1700 sq km. Further, six wells have produced oil and gas, with two deemed commercially successful.
The entire workflow to characterize these reservoirs is focused on delineating faults and associated fractures in individual wells. Detailed seismic study and volume curvature maps, revealed the existing fault and fracture corridors. Sub-seismic faults and subtle reverse faults with fractures were detected by log correlations and borehole image. Due to paucity of cores in these zones, descriptions of cuttings samples were used to identify faults and fracture zones, based on the presence of large euhedral crystals in the midst of cryptocrystalline dolomite, suggesting the percolation of hydrothermal fluids through fractures.
Many of the wells were drilled with an overbalanced mud system, leading to near-borehole porosity and permeability damage to the rock matrix and to the fracture system. Damage to natural fractures intersecting the well can prevent their detection, leading to missed potentially productive intervals. Mobility of hydrocarbons in these tight, fractured carbonate reservoirs depends upon (i) wells intersecting a natural fracture system that is sufficiently permeable and connected to a large volume of reservoir rock and (ii) the near-borehole area not having suffered irreversible damage due to overbalanced drilling. In summary, the proposed reservoirs are very tight carbonates (average 3 pu porosities) and a fracture play is considered to be the key factor in production. Acid stimulation produced multifold increases in productivity. Most of the wells were drilled overbalanced, which has negative impact on the producibility due to formation damage.
Discrepancies in terms of hydrocarbon initially in place volumes (HIIP) between static and dynamic models might take place because of nonlinear dependency of the saturation height function (SHF) versus porosity and averaging of height above free water level. Upscaling tends to eliminate the high and low porosity values in favor of the average porosity, which might lead to substantial changes in the resulting water saturation. Furthermore, pressure and compositional variation with depth in the dynamic model might lead to substantial contribution to the discrepancies, independent of upscaling.
We present a procedure to address the above issues and provide full consistency between static and dynamic models in terms of HIIP, without the use of capillary pressure (Pc) scaling by the reservoir simulator. A "preprocessing?? workflow is used to slightly reassign the Pc curve of each grid block so that a very close match is obtained between the two models in terms of HIIP.
Results show that HIIP obtained from the dynamic model through equilibration using the proposed procedure are within 1% of those obtained using the static model without having to use Pc scaling in the reservoir simulator which warranties realistic and physically valid Pc curves in the reservoir dynamic model initialization process.