This work addresses the challenging task of history matching a fractured basement reservoir. Habban field, south-western part of Yemen, produces from two different horizons: the Kuhlan sandstone overlaying the fractured basement. The fractured basement reservoir is characterized by two types of fracturing: background fractures with very low effective permeability of less than 0.001mD and fracture corridors with an effective permeability ranging from 0.01 up to 10 mD, and a total porosity of 1.3% only. Two sets of fracture corridors, with N-S and NW-SE mean orientation, contribute to production whereas background fractures act as storage feeding in those corridors. The large contrast in properties between Kuhlan and Basement adds-on further challenges: Kuhlan possesses good reservoir properties but moderate storage (~10m thick), whereas fractured basement has extremely poor reservoir properties but significant storage (~700m thick). Habban field has produced since end 2006 by depletion through 30 slanted wells. To optimally assess different production strategies, a simulation model was built. Dynamic data (MDT, PLT, BHP, production rates) were used to constrain the dynamic model on well by well basis. Due to this extremely challenging setting, a very high focus was put on a history matching process that integrates geology and reservoir simulation work to result into an enhanced understanding of field mechanisms. One main conclusion of this integrated history matching approach is that water comes to wells from neighborhood formations through main faults, explaining then the erratic water production (no crest to flank correlation). Second highlight concerns the major contribution of N-S main fractures. Finally understanding of the communication mechanism between basement and Kuhlan was enhanced, showing that despite basement poor properties, basement oil feeds in Kuhlan, as Kuhlan is produced. This synergized understanding of Habban mechanisms is a clear milestone for further well location planning and oil recovery optimization under uncertainty.
Well bore stability management is key to HSSE and cost effectiveness while drilling. This work focuses on the role of Geosciences to understand, explain and better predict the occurrence of well bore stability issues during onshore drilling operations in Block S2, central Yemen.To reach the primary reservoir target, the fractured Basement, development wells must penetrate a complex stratigraphic column, characterized by ten key formations and approximately 2000 meters thick. Lithologies vary from sandstones to carbonates, including salt layers with clay intercalations. Severe mud losses are often encountered in poorly consolidated sands of the Lower Tawilah formation where well inclinations are vertical or sub-vertical. At their most severe, they can translate to a complete loss of drilling mud returns on surface. Severe mud losses are not only a threat to borehole stability but they can have a serious impact on the drilling budget and timing.In order to improve drilling efficiency and speed-up the decision-making process associated with mud losses management and well stability, a detailed Geoscience study has been carried out. This work focuses on identifying three critical factors to explain the occurrence of severe losses:-the lithological variability of the Lower Tawilah, -the formation pore pressure -the local stress regime.Despite the challenging working environment and the interaction of geological heterogeneity, pore pressure and stress across the development area, the prediction and prevention of mud losses has been greatly improved while drilling new wells.The main objective of this paper is to highlight the role these three major elements play during drilling by illustrating with case study examples. Finally, mitigating actions and strategies implemented to prevent and/or deal with severe drilling mud losses are presented.
In the Sab'atayn Basin of Yemen hydrocarbons were generated from pre-salt Upper Jurassic source rocks during the Cenozoic and the salt provides the ultimate seal for the pre-salt and intra-salt traps. Therefore the proper understanding of salt tectonics is critical for ongoing hydrocarbon exploration efforts in the Sab'atayn Basin. A variety of distinct salt tectonic features are present in the Sab'atayn Basin. Based on the regional interpretation of 2D seismic and locally available 3D seismic reflection data calibrated by exploration wells in the central part of the basin, an Upper Jurassic evaporite formation ("salt" from this point on) produced numerous salt rollers, pillows, reactive, flip-flop, active and falling diapirs. Due to regional extension, halokinetics began by formation of salt rollers, as soon as the early Cretaceous, within just a few million years after the deposition of the Tithonian Sab'atayn Formation. The salt locally formed salt pillows which evolved to salt diapirs and diapiric salt walls as the result of renewed extension in the basin. As the result of a prominent extensional episode at the end of the Cretaceous most of the diapiric walls in the basin are controlled by large normal faults on their updip flanks. Some of the diapiric walls even evolved into falling diapirs due to ongoing extension. As the post-Cretaceous sedimentary cover is largely missing in the study area, the assumed reactivation of salt structures during the Cenozoic remains poorly constrained. As the Sab'atayn Formation has typically several massive salt intervals in it, it defines post-, intra- and pre-salt play types in the basin. However, other than just providing traps and seals in the basin, salt tectonics is also very important for source rock maturation in the basin. As there are many salt diapirs in the study area, their cooling effect on the the pre-salt hydrocarbon kitchens appears to be quite significant, based on our preliminary basin modelling efforts.
This paper presents a cost versus knowledge-gained appraisal strategy for reducing uncertainty in a tight sandstone reservoir within a short timeframe. More uncertainty should not necessarily demand more data acquisition, rather an approach that focuses on answering the big questions first.In the Shabwah Basin of central Yemen, sands from the Upper Jurassic Lam Member form fine-grained turbidite lobes. These tight sands, encountered while drilling to the Block S2 Basement reservoir, are currently undergoing appraisal as a potential unconventional oil resource. The presence of oil on surface correlates well with direct and indirect indications of natural fractures during drilling and wireline logging. In contrast, fluid sampling of thin hydrocarbon-bearing sands identified by magnetic resonance tools have so far been unsuccessful. Two possible production mechanisms have been identified in this sandstone reservoir: production from natural fractures and/or production from tight sands by hydraulic fracturing.The carefully risked appraisal strategy will target the key reservoir uncertainties, productivity and production mechanism, using three kinds of well re-completions: testing production from a well with natural fractures (with or without frac'ing), frac'ing and flowing a well with hydrocarbon-bearing tight sands and, drilling a slanted sidetrack well to increase exposure to natural fractures, with or without frac'ing.The appraisal approach is objective driven, not a wide-ranging data acquisition programme. There are many unknowns in the reservoir but this project focuses on reducing uncertainty efficiently by prioritising answers to the key objectives which are productivity and the production mechanism.A decision-tree based appraisal strategy has been developed with clearly defined exit points to control the cost of appraisal versus the value of information gained from the re-completion and drilling activities. This innovative, business-driven approach to reservoir appraisal maximises early uncertainty reduction by the most cost effective methods and can be used as a model for appraisal and early development projects in the industry.
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