Advanced surface logging technology for unconventional plays: well-site applications in tight reservoirs

Recently, significant improvements in Surface Logging technology have led to new methodologies for characterizing reservoirs. Such characterizations add significant value in both drilling and modelling activity and provide highly cost-effective well-site solutions: e.g. the chemical variations within rock sequences can be a powerful tool backing up or even replacing well logs used for well orientation. In addition, rock facies definition, through trace elements and mineralogy, integrated with mud gas chromatography, LWD/WL logs and production tests, can provide faster and better reservoir understanding. Such data integration and interpretation can expedite the learning curve, permitting faster and better decision making and allowing more rapid validation of investment decisions. In the following study, the petroleum provinces of three different sedimentary basins have been characterized through the combination of several techniques, embracing services from basic surface logging technology to on-site geochemistry. The first basin (Basin-A) is a complex system of depocentres bounded to the north by a major fault zone and constitutes an important unconventional tight gas province. Most of the Basin-A filling ranges from the Early Eocene to the late Oligocene era, where the origin of sedimentary material varied owing to the combination of tectonic subsidence and global eustasy, has resulted in mostly siliciclastic and volcaniclastic sediments, e.g. basin-plan turbidites. It has a thickness of around 600 m, as shown by a dense network of seismic sections and by hydrocarbon exploration wells. The main deposits (Oligocene), recently tested with encouraging reservoir quality sands, are interpreted as prograding delta front/pro delta deposits, deposited on to a submarine ramp within a wave dominated delta complex that pro-graded into a sub basin sea. The main target of two exploration wells, Pilot-1 and Lateral-1 was to prove hydrocarbon charged sands in deep sections that could produce either conventionally or by stimulation. When clastic sediments are homogeneous and drill cutting texture is destroyed by the cutting action of PDC bits, XRF-XRD data can be used to identify the most terrigenous sections and, correlated to mud gas data, can reveal potential sweet spots located along the well path and also allow for optimisation of the stimulation strategy. Furthermore, XRF trace elements used as anoxic proxies, have identified the most organic rich-layers overlaying the Oligocene clinoforms. These were responsible both for hydrocarbon generation and for the pinch-out closure; such characterization became of crucial importance during Lateral-1 geo-steering activity, as a result of GR tool failure (the GR response on Pilot-1 was compromised owing to the presence of radioactive sand layers). The second basin (Basin-B) is composed of a substantial thickness of sedimentary rocks, consisting of between 20,000 and 40,000 ft of Palaeozoic marine sediments overlaying a Precambrian granitic/rhyolitic basement.The basin is partially deformed and displaced by orogenic uplifts formed mainly during the Carboniferous period. The Mississippian age strata, the object of the study, consists of proximal ramp limestones, shales and siltstones in most parts of the basin. All show evidence of thermal pulses, suggesting several hydrothermal fluid flow episodes related to the tectonic valving. These hydrothermal events primarily impacted the diagenesis of the carbonates rather than the siliciclastics and have led to reservoir development and hydrocarbon entrapment. To better understand diagenesis and interstitial interactions with hydrothermal fluids, an appreciation of the inorganic elemental composition becomes essential, especially regarding trace elements. Once generated, the hydrothermal fluids, as well as the hydrocarbons, followed the fracture systems and precipitated within this system. The primary goal of two development wells, Pilot-2 and Lateral-2, was to detect fracture systems and porous/permeable zones for optimization of a hydraulic fracturing programme. The integration of several techniques, including XRF-XRD, mud gas chromatography, mud delta flow and image logs were able to identify open and closed fractures, refining the target. The third basin, (Basin-C) lies on the flanks of a mountain chain. During the Mesozoic, Basin-C was characterized by numerous relative sea-level changes, resulting in a complex distribution of sedimentary deposits that include both marine and continental successions. Basin-C has been targeted for both conventional and unconventional production. The unconventional targets are of Late-Jurassic marine organic-rich shales developed in a back-arc embayment, where TOC values range from 1 to 8%, and kerogen is mostly of type I/II (locally II-S) or II/III. Basin-C provides opportunities for both shale-oil and shale-gas exploitation owing to its kerogen variability in terms of maturity and type. Additionally, such variability can change within a few kilometres, thus its estimation is of extreme importance both for basin modelling and for selecting the optimum well completion and geo-steering technologies. To allow assessment of the organic matter characteristics, source rock potentials and inorganic composition of the Late-Jurassic deposit, two geochemical (XRF, XRD, TOC and Pyrolysis) and isotopic mud gas (δ13C1 - C3) datasets were analysed. The samples were collected during the drilling of two exploration wells, Pilot-3 and Lateral-3, and analysed at a lab built within the exploration field (to remove Oil Based Mud OBM contamination, the geochemical samples had to be treated with specialised solvent and glassware not allowed at the rig site).