![]() Drilling time was reduced significantly by over 50%, and fluid cost for this operation was reduced to almost zero. Well was drilled to TD successfully, and all the primary objectives of the well were achieved. No kicks or well control issues were experienced and well barrier policy was accomplished by maintaining the annulus with overbalanced fluid at all times using this method. One of the wells penetrated carbonate zone with total losses (injecting up to 1200 gpm). Seawater was continuously injected down the annulus and the drill pipe at rates allowed by the LOT and injection test values. Compared to the conventional MCD method utilizing oil-based Light Annular Mud (LAM), decision of utilizing seawater as the sacrificial fluid and LAM was made due to sub normal nature of the reservoir. In followup operations, the team decided to use MCD-continuous annular injection method-to drill and develop this marginal carbonate field with efficient and low cost wells. A total of 17 days was spent to mitigate the losses. TD was called early and losses were cured only with cement plugs. The offset well encountered total fluid losses equated to approximately 25,000 bbls. Due to highly fractured nature of limestone and the existence of karst, the amount of losses that occurred in the offset wells was tremendous where situation of losing the primary barrier-hydrostatic column-was highly possible which could have lead to catastrophic well control incident/loss gain scenario. did a case study of carbonate reservoir drilling. From Kinik, K., Gumus, F., and Osayande, N., 2015, Automated Dynamic Well Control WithManaged-Pressure Drilling: A Case Studyand Simulation Analysis, SPE Drilling and Completion, 110–118. Automatic detection and control of the kick: mud-flow-rate-in and mud-flow-rate-out data. experience, the assumption used here is that this multiplier in developing countries is 1.3 for onshore projects and 1.6 for offshore projects.įigure 5.5. For the United States, that multiplier ranges from 1.16 to 1.84 (Alaskan offshore). To arrive at total exploration costs per foot of exploratory drilling, it is necessary to use a multiplier on top of drilling costs to allow for expenditure on geological and geophysical studies. This rough method suggests that the cost of exploration drilling in developing countries is about $125 per foot onshore and about $300 per foot offshore, with a considerable range of uncertainty (not treated here) around both numbers. costs per foot of exploratory drilling in 1978 1 in less unfavorable environments were averaged, then escalated to 1980 price levels, then extrapolated to approximate developing country cost conditions through use of the indexes in Chemical Engineering and the Engineering News Record. As a substitute for direct information, data on U. There is very little publicly available data on exploratory drilling costs in developing countries. ![]() PLUMMER, in Energy, Resources and Environment, 1982 Costs of Exploration Total cost of drilling and casing and etc in period i X i j k lġ if we select rotary speed in k state and bit weight in l state for bit type j in section i of well, otherwise is 0 Y i j kġ if we select casing type j in section i with coupling type k, otherwise is 0 ![]() Safety factor for burst defined as burst strength/burst load T C i Pore pressure at the bottom of next openhole section considered constant P w fįracture pressure below casing shoe is considered variable as the casing depth is not fixed P w h Length of casing in section i P b u r s t Height of reservoir gas entering wellbore i ![]() D w hĭepth to wellhead at seabed from drill floor h a Pressure gradient at shoe when casing top is loaded to burst d w Relative density of reservoir fluid d s h o e Total well depth from drill floor D c a s Drilling cost per foot for bit type j in rotary speed k and bit weight l in section i of well C F tĬasing cost per foot for casing grade j with weight coupling k in section i of well D
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