The surge in the worldwide demand for hydrocarbons has resulted in considerable interest in drilling for unconventional resources. The Drilling Engineering Team has reduced the duration and cost of drilling wells by 80% in drilling days and 73% in well delivery cost while targeting more precise sand-channel targets in the Unconventional Field presented in the paper, during a time period of about 10 years. Optimizing the casing design (moving from seven casing strings to four casing strings), drilling practices (maximizing drilling parameters), and completion practices (moving towards 4-½-in cemented longstring instead of lower/upper completion), resulted in reducing the number of days and the associated drilling cost. The improvements include: Modifying hole sizes (slimming wells starting from 34-in section to 22-in section). Combining sections that were previously isolated (for example, combining the targeted sand-channel reservoir with a long shale interval above it in one section). Eliminating drilling liners and completion tiebacks (moving towards 4-½-in cemented longstring instead). Improving the drilling fluids program (moving towards high salinity NaCl polymer drilling fluid system for the shallower sections, and reducing mud weights needed to stabilize the long shale interval from 100+ pcf toward 70-80 pcf by utilizing OBM), Increasing top-hole rate of penetration by strategically moving all the directional nudging into the 8-½-in/8-⅜-in OBM drilled hole section, and decreasing cost of top hole bottomhole assemblies. Introducing new technology 8-½-in/8-⅜-in PDC bits that drilled the entire hole section with one bit. Introducing an updated combined logging program.
This paper presents a detailed study on how to detect the presence of light-oil in a low-resistivity and interbedded sandstone-shale environment. Based on the basic log response (high GR readings, 45-55 API, low resistivity values, 3-5 ohm.m, low-to-moderate porosity), the studied interval was considered a non-oil bearing zone. The interval was re-evaluated by adding some advanced technologies and the results showed the zone to be oil bearing. Fluid sampling has confirmed that the zone is oil bearing zone. The advanced logging technologies were magnetic resonance, mineralogy and high-resolution borehole electrical imaging. The mineralogy tool was logged to identify and quantify the formation minerals and also the clay typing. The magnetic resonance tool was used to identify the different fluids inside the pores and also to measure the fluids saturations. The high-resolution borehole electrical imaging was used to analyze the sedimentary facies and the formation structures. At last a sample of the formation fluid was successfully taken after flushing out the filtrate from the formation for about 10 hours and pumping out about 40 liters. The NMR technology played an important role in detecting and quantifying the oil over the interbedded sandstoneshale zone. The fluid typing analysis of magnetic resonance measurements identified up to 50% oil saturation with permeability index ranging from 10 to 20 mD. As the tool can only read between 2 and 4.2 inches inside the formation, the saturation analysis is affected by the mud filtrate. This means that the actual oil saturation might be much higher than 50%. The mineralogy tool showed 25-35% volume fraction of clay, mainly illite, kaolinite, smectite, and the remaining volume is quartz. These fractions indicate that the interval is shaley. Because of its low vertical resolution, it was not possible to see any interbeds with the mineralogy tool. However, the high resolution borehole electrical imaging showed clearly the formation sedimentary structures which are interbedded sandstoneshale. The fluid sampling has confirmed that the low resistivity pay in the interbedded sandstone-shale interval is an oil bearing reservoir. This type of reservoirs is usually underestimated when evaluated with only the standard logging technologies, because of the effect of the shale laminations on the measured formation resistivity. So, in such environment, the use of different technologies is required to first understand the nature of the environment and also to overcome the impact of the laminations in identifying the presence of oil and also quantify it. The combination of the NMR, mineralogy, high resolution imaging and fluid sampling technologies has proven its successfulness over interbedded sandstone-shale reservoirs.
A heterogeneous and complex carbonate reservoir consists of many sub-layers. Each layer has unique characteristics. To enable comprehensive reservoir characterization, logging while-drilling technologies comprising high-resolution electrical imager, magnetic resonance and formation pressure tester were deployed. The integration of logging data had delivered detailed interpretation and proposes of a new workflow for best practice to advance reservoir performance and to optimize completion design. Magnetic resonance was acquired with dual-wait time enabled T2 polarization to differentiate between moveable water and hydrocarbon. After acquisition, standard deliverables were porosity and permeability index. Porosity was divided into clay-bound water (CBW), bulk-volume irreducible (BVI) and bulk-volume moveable (BVM). Following good test results from the formation pressure tester, the permeability index from magnetic resonance was calibrated to mobility. Then rock quality was interpreted based on Lorenz Plot and permeability-calibrated to effective porosity ratio. The ratio was classified to high, low and no flow unit zones. The classification based on gradient of the ratio. Steeper gradient inferred high flow, lower gradient inferred low flow and flat gradient inferred no flow. To advance reservoir characterizations, flow unit zones were integrated to sedimentary facies interpretation. The interpretation was conducted based on high-resolution electrical imager. The analyzed reservoir was divided in 23 flow units. The flow units were useful to identify reservoir compartments. Similar flow units were combined into one compartment. There are 3 intervals of high flow, 3 to 4 intervals of low flow and 4 intervals of no flow. The interval definition was used to design the completion. For best point of the completion within the intervals, high resolution electrical imager interpretation had added valuable input. Categories for best point in this particular study were homogeneous and less-cemented facies. The interval for best point would be varies based in completion strategy. The expectation result of the integrated logging data was to deliver maximum and stable flow rate with efficient completion design and advance the understanding of reservoir characterization. In addition, sedimentary facies interpretation was being correlated with the fluid flow behavior. In high-density cement intervals, permeability is low. In porous high-resistive sedimentary facies, the permeability is high. This inferred, the matrix and cement in the formation were affecting the fluid flow behavior. The integration of logging data had resulted comprehensive reservoir characterization. The integration lead to completion optimization to advance reservoir performance and develop a comprehensive workflow. The workflow had combined petrophysical analysis, reservoir information and geological interpretation. This workflow would be best practice to be implement to advance complex carbonate reservoir and optimize completion strategy.
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