The paper provides a case history of the application of 3D imaging and Pore Network Modeling (PNM) technology to establish a direct relationship between rock micro-structure parameters from 3D via micro-tomographic images, and the simulation of petrophysical properties of clastic tight gas reservoir rocks in Oman. Tight gas reservoirs exhibit storage and flow characteristics that are intimately tied to the depositional and diagenetic processes. In particular, cores have significant primary and secondary porosity often dominated by clays and slot like pores. Accurately mapping the pore and grain structure and mineralogy in 3D and the interconnectivity of primary and secondary porosity illustrates the role 3D imaging plays in a comprehensive reservoir characterization program. The computed petrophysical properties (e.g. porosity, permeability, formation resistivity factor, hydraulic radii and drainage capillary pressure) are compared with routine and special core analysis results measured on conventional core samples. The use of 3D micro-tomograms at different scales and PNM provides a quick complimentary method to characterize the distribution and nature of different pore types and matrix components to characterize the static, elastic and dynamic rock properties even on rock fragments (2mm to 1cm diameter) that are not suitable for conventional core analysis techniques. The presented case history demonstrates that the new 3D PNM technologies can also be successfully applied to the challenging tight gas reservoirs with low porosities and very low permeabilities for comprehensive reservoir characterization to optimize the development scenarios.
Located offshore Malaysia, Field A is a highly complex elongated anticlinal structure with hundreds of faults. It includes over 70 hydrocarbon bearing sands deposited in a lower coastal plain environment. Producing since the late 1970s, Field A has gone through several asset rejuvenation plans. The latest one aimed at appraising and draining several untapped fault blocks. Although no major surprises were expected in terms of lithologies, uncertainties remained on fluids’ nature in multiple sands and on the possible isolation of the fault blocks. This paper illustrates how an operating company introduced a new while-drilling downhole formation fluid data acquisition workflow to successfully de-risk and address these challenges. Conventional formation evaluation is challenging in these fluvial environments, as it includes laminated reservoir, variable permeability, and presence of light, potentially saturated, hydrocarbons. Lessons learned from the previous rejuvenation campaign highlighted the importance of formation testing and downhole fluid analysis (DFA). The planned campaign required drilling two complex 3D profile wells (80-degree tangent followed by 35-degree drop through the targets). Pre-drill discussion raised various concerns: potential well control issues due to pumping light hydrocarbons in the borehole; sticking risk due to complex well trajectory and potential depletion; in-situ evaluation of CO2 for well deliverability analysis; and the number of logging runs, wiper, and post-drilling cleaning trips. In addition, the financial constraints on infill development called for the need of early, real-time enabled decisions for perforation and completion optimization. The selected drilling bottomhole assembly consisted of an integrated multi-physics logging-while-drilling toolstring including fluid mapping-while-drilling (FMWD) technology to de-risk the fluid acquisition program. The integration of pressures and DFA measurements with petrophysical data helped to identify and understand the distribution of fluids and fault blocks connectivity. The campaign proved to be very successful. All sand horizons were pressure tested, providing a fluid pressure profile description yielding gradients where applicable, differential pressure estimation, and connectivity information. The uncertainty associated with petrophysical fluid identification was addressed, and the use of FMWD showed no free gas in the tested zones. Fault block isolation was proven. Reservoir fluid and mobility profiling helped to optimize the well perforation and completion strategy and assess the producibility of the wells. The acquisition sequence was safely performed in one trip from bottom to top with no overpull observed. No wiper or post-drilling cleaning trips were required due to continuous mud circulation during data acquisition. This paper describes how this operating company successfully introduced a new while-drilling downhole formation fluid data acquisition workflow in a brown field. The workflow positively impacted the field development decisions. The FMWD de-risked data gathering operation under tight economical constraints and addressed formation evaluation and drilling and completion challenges during the evaluation of untapped blocks in Field A.
A brown field, offshore Sarawak, Malaysia, with multiple sub-layered laminated sands of varied pressure regimes and mobility ranges, was challenged by depletion, low mobility and uncertainty in the current fluid types and contacts. Optimal dynamic fluid characterization and testing techniques comprising both Wireline and Logging While Drilling (LWD) were applied in nine development wells to acquire reliable formation pressure data and collect representative fluid samples including fluid scanning. Some of the latest technologies were deployed during the dual crises of falling oil price and the Covid-19 pandemic. The S-profile wells were drilled using oil-base mud (OBM) with an average deviation of 60 degrees. Formation Pressure While Drilling (FPWD), Fluid Sampling While Drilling (FSWD) and wireline formation testing, and sampling were all utilized allowing appropriate assessment of zones of interest. Various probe types such as Conventional Circular, Reinforced Circular, Elongated, Extra-Elongated and Extended Range Focused were used successfully, ensuring that the right technology was deployed for the right job. Formation pressure and fluid samples were secured in a timely manner to minimize reservoir damage and optimize rig time without jeopardizing the data quality. As a classified crisis due to the pandemic, rather than delaying the operations, a Remote Operations Monitoring and Control Center was set-up in town to aid the limited crew at rig site. A high success rate was achieved in acquiring the latest formation pressure regimes, fluid gradients, scanning and sampling, allowing the best completion strategy to be implemented. With the selection of the appropriate probe type at individual sands, 336 pressure tests were conducted, 44 fluid gradients were established, 27 fluid identification (fluid-id / scanning) pump-outs were performed, and 20 representative formation fluid samples (oil, gas, water) were collected. Amongst the Layer-III, Layer-II and Layer-I sands, Layer-I was tight, with mobility < 1.0 mD/cP. Wireline focused probe sampling provided clean oil samples with 1.4 to-3.7 wt. % OBM filtrate contamination. The water samples collected from Layer-II during FSWD proved to be formation water and not injection water. The wells were thus completed as oil producers. Reliable fluid typing and PVT quality sampling at discrete depths saved rig time and eliminated the requirement of additional runs or services including Drill Stem Testing (DST). This case study has many firsts. It is the first time where latest fluid characterization and testing technologies in both Wireline and LWD were deployed for an alliance project in Malaysia and that too during dual crises of falling oil price and the pandemic aftermath. Overcoming various challenges including limited rig site manpower, there was no delay in completing the highly deviated wells with tight formations in a single drilling campaign and provided rig time savings. For the purpose of this case study, two wells have been discussed. First well used the wireline focused sampling technology and the second used the FSWD technology.
Uncertainties in fluid typing and contacts within Sarawak Offshore brown field required a real time decision. To enhance reservoir fluid characterisation and confirm reservoir connectivity prior to well final total depth (TD). Fluid typing while drilling was selected to assure the completion strategy and ascertain the fluvial reservoir petrophysical interpretation. Benefiting from low invasion, Logging While Drilling (LWD) sampling fitted with state of ART advanced spectroscopy sensors were deployed. Pressures and samples were collected. The well was drilled using synthetic base mud. Conventional logging while drilling tool string in addition to sampling tool that is equipped with advanced sensor technology were deployed. While drilling real time formation evaluation allowed selecting the zones of interest, while fluid typing was confirmed using continually monitored fluids pump out via multiple advanced sensors, contamination, and reservoir fluid properties were assessed while pumping. Pressure and sampling were performed in drilling mode to minimise reservoir damage, and optimise rig time, additionally sampling while drilling was performed under circulation conditions. Pressures were collected first followed by sampling. High success in collecting pressure points with a reliable fluid gradient that indicated a virgin reservoir allowed the selection of best completion strategy without jeopardising reserves, and reduced rig time. Total of seven samples from 3 different reservoirs, four oil, and three formation water. High quality samples were collected. The dynamic formation evaluation supported by while drilling sampling confirmed the reservoir fluid type and successfully discovered 39ft of oil net pay. Reservoir was completed as an oil producer. The Optical spectroscopy measurements allowed in situ fluid typing for the quick decision making. The use of advanced optical sensors allowed the sample collection and gave initial assessment on reservoir fluids properties, as a result cost saving due to eliminating the need for additional Drill Stem Test (DST) run to confirm the fluid type. Sample and formation pressures has confirmed reservoir lateral continuity in the vicinity of the field. The reservoir developed as thick and blocky sandstone. Collected sample confirmed the low contamination levels. Continuous circulation mitigated sticking and potential well-control risks. This is the first time in surrounding area, advanced optical sensors are used to aid LWD sampling and to finalize the fluid identification. The innovative technology allowed the collection of low contamination. The real-time in-situ fluid analysis measurement allowed critical decisions to be made real time, consequently reducing rig downtime. Reliable analysis of fluid type identification removed the need for additional run/service like DST etc.
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