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Abstract The key objective of this study was to develop a high resolution wellbore stability model for planned highly inclined development wells of an ultra-deepwater field through integrating geological, geophysical, petrophysical and drilling data to design optimized drilling mud weight window. This study describes a customized high resolution wellbore stability modelling process for development wells in ultra-deepwater setting, where shale and sandstone have different pore pressure and stress magnitudes. Un-calibrated and calibrated seismic velocities along with offset well data were used to generate the high resolution pore pressure model for the overburden shale section. Laboratory based geo-mechanical tests, petrophysical logs and offset well events were integrated for the estimation of sub surface stresses and rock mechanical properties for overburden shale and sandstone. Subsequently, separate wellbore stability model was built to estimate the shear failure gradient for overburden shale and sandstone. This study suggests that the mud weight (MW) window in the overburden is primarily governed by two parameters – (i) sand-shale pressure equilibrium state, and (ii) stress anisotropy. The intervals where the sand and shale are not in pressure equilibrium state (i.e. shale pressure > sand pressure), the minimum MW requirement is defined by either pore pressure or shear failure gradient (SFG) of shale formation. Whereas, maximum limit is marked by fracture gradient of relatively less pressured sand formation. Therefore, in such intervals mud weight window becomes much narrower (~1 ppg) than those intervals where sand and shale is in pressure equilibrium (~1.6 ppg). This study also highlights the increase of minimum MW requirement (SFG) in some intervals having relatively higher stress anisotropy. The minimum MW requirement within the main reservoir section having thin intra-reservoir shale is controlled by the SFG of the sand formation, as strength is lower in the reservoir sand than intra-reservoir shale. Results show the importance of high resolution modelling in order to capture pressure uncertainty, thin sands, sand/shale pressure equilibrium state, stress anisotropy and its effects in defining the optimum mud weight window. Based on analysis, further risk zonation was done to highlights intervals prone to wellbore collapse and mud loss. This paper illustrates how the integrated high resolution wellbore stability modeling would help in optimum mud weight planning for highly deviated / horizontal wells to minimize the drilling risks and non-productive time (NPT), especially for challenging field development settings (deepwater, ultra-deepwater, high stress, High pressure High temperature).
Abstract A major challenge facing the oil and gas drilling operations is mitigating the encountered wellbore instability issues. Those can vary from loss circulations up to having stuck pipes or tools that may jeopardize well integrity and potentially lead to total loss of wells and assets. These problematic situations are even much more complicated in fractured reservoir environments where predicting the fracture density is important. Analyzing such problems is critical for companies especially in developing offshore fields where one day lost time is in hundreds of thousands of dollars. The field of rock mechanics emerged to connect those phenomena to reservoir rock properties and stress profiles. Coupling this with an intensive analysis of drilling parameters, logging, core testing and other existing wells data builds a work frame that helps in understanding the reasons behind wellbore failures and providing solutions to them. The field under investigation is a highly geo-pressured offshore gas field. The field development called for drilling vertical and deviated wells. During the field increment sever loss circulation were encountered that resulted in lost drilling times estimated in millions of US dollars with rig cost up $ 200,000/Day. Other drilling failures includes, stuck drill pipe and difficulties with logging response and log interpretation. The objective of this study is to investigate the wellbore instability during drilling operations as function of rock properties, in-situ earth stress and drilling parameters. Emphasis on the role of natural fractures density will be highlighted and included in modeling inputs as well as characterizing its density across the field. During the course of the study, existing field's and drilled wells available data will be analyzed and a simulation models will be utilized to simulate the stress profiles in the field. Based on the results, the factors behind the instability issues in the field will be identified and recommendations will be made for future wells drilling programs.
Celis, Eduardo (GeoMechanics Intl. Inc.) | Garcia-Hernandez, Jesus (Pemex) | Morales-Ramirez, Jose Manuel (Pemex) | Cabrera-Toledo, Crescencio (Pemex) | Sheridan, Judith (GeoMechanics International Inc.) | Ward, Christopher D. (GeoMechanics Intl. Inc.) | Wiprut, David J. (GeoMechanics Intl. Inc.)
Abstract Petróleos Mexicanos (PEMEX E&P) and GeoMechanics International Inc. (GMI) worked together to define the potential for fault leakage in the Sihil and Frontal faults of the Cantarell and Sihil Fields, Mexico. Water production with a low salinity content in the northern area of the Akal block in the Field seems to be derived from neighboring blocks of Tertiary age and not from the water leg of the reservoir. Pore pressures in the reservoirs from the Akal block have depleted significantly since production started in the late seventies. Nitrogen injection started in the late nineties and has contributed to pressure maintenance since then. Overpressures in the shale layers above the reservoirs have been identified. A number of studies have shown that shear failure along reservoir-bounding faults can increase fault permeability and compromise fault trap integrity. The orientation of a fault and the magnitudes of the present-day stresses and pore pressure acting on the fault will determine whether the fault has the potential for shear failure and therefore a potential for leaking. The analysis of fault leakage potential was based on a geomechanical model covering the northern area of the Cantarell Field and its changes with time due to reservoir depletion and nitrogen injection. Information from wireline logs, downhole tests and drilling events from eight wells drilled between 1979 and 2005 were used to build the geomechanical models that change with time. The principal effective stress model (the magnitudes and orientation of the principal stresses), and the mechanical properties model were defined and validated with image logs, caliper logs and drilling experiences before their use for fault leakage potential analysis. Specific sectors of the two faults appear to be tectonically active during the production history and therefore had potential to leak. Fault leakage potential may explain water production with low salinity content in the northern area of the Akal Block in the Cantarell field. Introduction The Cantarell complex, the second largest oilfield in the world, is located in the Gulf of Mexico, offshore from the Campeche State in Mexico (see Figure 1Figure 1). With more than four hundred wells, the field reached its maximum production rate of 2.2 MMbopd, 22° API oil in 2002. The field is comprised of three allochthonous fault-bounded blocks, in order of importance: Akal, Nohoch and Kutz. During the early Miocene, compressive stresses generated the thrusted Cantarell structure and preexisting Jurassic normal faults were reactivated during the Pliocene recent extension . The reservoir is an Upper Cretaceous calcareous breccia overlain and in contact to the north by a thrust fault with a terrigenous Tertiary sequence (see Figure 2Figure 2 and Figure 3Figure 3). Recently, the production of low salinity water (30,000 ppm) has increased in some wells located in the northern part of the field with high economical impact. This salinity is similar to the Tertiary brine outside the thrust fault, while the water salinity in the Cretaceous in the underlying water leg is about 60,000 ppm. PEMEX wanted to evaluate, using geomechanics, the leakage potential of two faults: the "Frontal" fault, the northern boundary of the Akal block and the "Sihil" fault. The idea was that this may explain the low salinity water encountered in some wells, flowing from the Tertiary sequence to a currently depleted Cretaceous reservoir. Geomechanical models, including pore pressure changes, rock mechanical properties and principal stresses, were created in order to evaluate the leakage potential of these two faults during production.
Parotidis, Miltiadis (BG Group plc, Royal Dutch Shell plc) | Hummel, Nicolas (BG Group plc, Royal Dutch Shell plc) | Graham, Jordan (BG Group plc, Royal Dutch Shell plc) | Wheeler, Josephine (BG Group plc, Royal Dutch Shell plc) | Pritchard, Tim (BG Group plc, Royal Dutch Shell plc)
Abstract Three onshore basins (called henceforth A, B, and C) in eastern Australia are discussed in this paper with the focus on geomechanics. Basin A is a coal seam gas play with a few thousand wells already drilled, and reservoir layers in the depth range of 300 to 1000 m, inter-bedded with impermeable clastics. Stress determination has been a key challenge as initial minifrac interpretations showed significant scatter in stress and pore pressure results. But with more consistent processing and interpretation constant effective stress ratios could be defined over large areas and depth sections. This helped also in interpreting microseismic data related to hydraulic fracturing – essential for economic production in areas of lower coal permeability - as reactivation of existing natural fractures seems to take place during injection. Basins B and C with tight formations as reservoir targets, in depths of about 4000 to 4600 m show overpressures that are difficult to directly measure and could only be constrained to lower values than mini frac test interpretations, after iteratively calibrating the geomechanical model and considering drilling data. This allowed a better understanding of thermal effects on progressing shear failure in openhole sections, due to increasing drilling mud fluids temperature with time; an effect that has to be considered in defining safe mud windows for drilling and operations phases. Although gradually a better understanding has been achieved, above unconventional fields still pose challenges, and current results will have to be considered as work in progress and not final. The key outcome of the geomechanics studies to date is: that a strike-slip stress regime applies, regionally and vertically; several depth intervals show constant effective stress ratios for both horizontal stresses, with some changes depending on location, and probably due to the structural differences.