TA is an over-pressurized well in the field development project located Offshore Peninsular Malaysia. Although the well was drilled as a development well, it also had an exploration objective as it was the first to penetrate the over pressured zones across a fault in the TA field. An initial attempt to drill conventionally resulted in severe gain and loss scenarios across the first of three sands 80 m below the 7" casing shoe, primarily due to weak coal formations. After many attempts to control losses, it was decided to plug-abandon the 6" open hole and to temporarily suspend the well due to insufficient operating window to drill ahead. After a year of suspension, a new drilling approach using a statically underbalanced mud weight (MW) in combination with an Automated Managed Pressure Drilling (MPD) system was introduced as the best solution for drilling into the well objectives. During the planning stage, different scenarios were analyzed based on the formation fracture gradient (FG) and pore pressure (PP) estimations. MPD plans were designed based on statically underbalanced mud while drilling, running the liner, and during the cementing job. During drilling, Dynamic Flow Checks (DFC) and Dynamic Formation Integrity Tests (DFIT) were performed using the MPD system to identify and confirm operating window. The target total depth was successfully reached with mud weighted within the narrow 0.35 ppg drilling window (17.8–18.1 ppg). Decision was then made to top kill the well at 1200 m-MDDF with 18.30 ppg mud, providing an overbalanced condition of 85 psi. Open hole logging operations were then successfully executed. The well was then displaced to a 16.30 ppg mud prior to performing Managed Pressure Cementing (MPC). This technical paper aims to discuss all of the MPD - MPC challenges faced and best practices developed during both the planning and execution stages of the program.
Today, natural fracture and/or connected vuggy systems in carbonate reservoirs contribute significantly to hydrocarbon production.Combining concepts from normal distribution with normalization and soft computing techniques improves quantification of actual shale volumes for a reservoir with complex stratigraphy and natural fractures. This is especially important for cases when very few log curves are available to solve a high number of unknown lithologic variables. We applied our new methodology successfully in the Cretaceous formation, Lake Maracaibo, which is composed primarily of limestones with some dolomites and siliciclastics (glauconitic sandstones, siltstones, and shales). It is common to use the standard gamma ray log (SGR) or total contribution from all three elements-uranium (U), potassium (K), thorium (Th)-as an indicator of shale content. The presence of highly radioactive black organic material and/or natural fractures in the formation results in a big difference from the X-ray diffraction data. This causes an overestimation of shale volume and therefore affects the original oil in place (OOIP) and reserves. We present a novel methodology that combines normal distribution and normalization to predict CGR from SGR and deep resistivity, Rt. We applied the cross correlation technique to validate our methodology, and the model CGR matches the actual CGR very well. Next, we used the elemental capture spectroscopy (ECS) logs to quantify the actual clay volume (Vsh). Then, we used soft computing techniques to develop a shale volume model using CGR and Rt as independent variables and the Vsh from ECS as the dependent variable. Running the model for validation in three wells with ECS achieved a correlation coefficient of 0.9. The average shale volume using our model is 12.5%, much lower than the former linear shale-volume model, which averaged 28.4%. This has had a great impact on the OOIP and reserves of our reservoir, as it would for other complex carbonate reservoirs.
TTD-1 has been identified as the deepest HPHT well ever drilled by PCSB in Malaysia. Managed Pressure Drilling (MPD) enabled the Operator to drill and explore new sands and confirm new hydrocarbon reservoirs at 325 degrees F with an undisturbed bottom hole pore pressure of nearly 15,000 psi. The MPD technique in conjunction with the best HPHT practices was able to overcome challenges while drilling this exploration well. Challenges included: Abnormal pressure ramp-up (greater than 17 psi/ft) High pore pressure steps in new sands Identifying and controlling wellbore breathing Controlling losses on the HPHT tight window zone Technology and practices, including well control, HPHT drilling practices, pore pressure prediction and MPD, were integrated by the Operator during the planning and execution stages. The focus was to integrate MPD and HPHT procedures as well as optimize the available tools to maximize daily drilling footage and maintain the integrity of the well at all times. Annular friction losses (greater than 800 psi) were offset by Surface Back Pressure (SBP) to maintain constant bottomhole pressure (BHP) at all times, except instances when the annular backpressure was reduced for short periods to perform dynamic flow checks. Dynamic flow checks were performed every 45 feet measured depth to map the pore pressure. One of the dynamic flow checks identified one pressure step increase (greater than 1.0 ppg) and a 0.5 bbls gain on the trip tank at the same time. The dynamic formation integrity test (FIT) was successfully implemented to identify the upper limit of the operating window. Proper application of these MPD procedures identified the minimum operating window as 1.0 ppg and guided the Operator to call for TD of the well. The well was drilled to a depth of 4,830 m, and thus penetrated vast gas bearing reservoirs. This technical paper aims to share a case study of HPHT drilling practices combined with Automated MPD successfully adopted to explore new sands with minimal offset geological and petrophysics information.
A new sigmoidal function from polar transformation enables more accurate identification of pore types in fractured/vuggy reservoirs. The function is based on a polar transformation that separates the pore systems into two regions-matrix systems and fracture/vug systems-on the basis of hydraulic properties, reservoir quality index (RQI), flow-zone index (FZI), and normalized porosity. The polar transformation exhibits a hyperbolic distribution for intergranular/intercrystalline pore sample types at the point where they deviate from the trend so that we can identify pore types more accurately. Our new function has been validated from image log data from wells of Lagomar and/or Lagomedio fields and core data from different fields around the world, and we are certain that it will be of great help to the geoscientist when doing a reservoir characterization.
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