Patacchini, Leonardo (Abu Dhabi Marine Operating Company) | Mohmed, Farzeen (Abu Dhabi Marine Operating Company) | Lavenu, Arthur P. C. (Abu Dhabi Marine Operating Company) | Ouzzane, Djamel (Abu Dhabi Marine Operating Company) | Hinkley, Richard (Halliburton) | Crockett, Steven (Halliburton) | Bedewi, Mahmoud (Halliburton)
The classic method for initializing reservoir simulation models in the presence of a transition zone, based on primary drainage capillary-gravity equilibrium, is extended to account for partial reimbibition post oil migration. This tackles situations where structural events, such as trap tilting or caprock leakage, caused the current free-water level (FWL) to rise above deeper paleo-contacts. A preliminary primary drainage initialization is performed with zero capillary pressure at the paleo (or deepest historical) FWL, to obtain a minimum historical water saturation distribution. From a capillary pressure hysteresis model, it is then possible to determine the appropriate imbibition scanning curve for each gridblock, which are used to perform a second initialization with zero capillary pressure at the current FWL. With the proposed method, log-derived saturation profiles can be honored using a physically meaningful capillary pressure model. Furthermore, when relative permeability hysteresis is active, it is possible as a byproduct of the initialization to assign the correct scanning curves at time zero to each gridblock, which ensures that initial phase mobilities (hence reservoir productivity) and residual oil saturation (hence recoverable oil to waterflood) are modeled correctly. This is demonstrated with a synthetic vertical 1D model. The method was implemented in a commercial reservoir simulator to support modeling work for a giant undeveloped carbonate reservoir, where available data suggest that more than 3/4 of the initial oil in place could be located between the current FWL and a dome-shaped paleo-FWL. This work is used as a case study to illustrate the elegance of the proposed method in the presence of multiple (or tilted) paleo-FWLs, as only one set of capillary pressure curves per dynamic rock-type is required to honor the complex logderived saturation distribution.
While history matching of a reservoir simulation model principally aims at reproducing past shut-in pressure and fractional flow observations, transition from history to forecast further requires honoring the productivities (or injectivities) of wells, and implementing the current field operational strategy to avoid unwanted reallocation of rates. Well-level matching is particularly lengthy for giant oilfields with several hundreds to thousands of completions, hence sometimes not refined enough to warrant using observed flowing pressures as forecast constraints. Furthermore, breakthrough times are not necessarily replicated in all wells; this strongly increases discrepancies between measured and simulated flowing pressures, and can cause spurious shutting of wells infringing on reservoir management guidelines. Short-term forecast confidence can be improved by compensating well-level mismatches observed at the end of history for production and injection control purposes only, without solving the inherent model problems. The purpose of this paper is to describe a workflow followable with most commercial reservoir simulators to achieve such objective, forcing production and injection continuity at the onset of forecast while keeping the choked margin of wells producing below capacity. A successful application of the workflow is illustrated using the model of a giant Middle Eastern carbonate oilfield with more than 150 active production strings, using an eight-year (2015-2023) drilling schedule followed by no further activity. In this example, confidence in long-term field-level forecasts does not deteriorate after applying the proposed well-level compensations.
Su, Shi Jonathan (Schlumberger) | Patacchini, Leonardo (Abu Dhabi Marine Operating Company) | Mohmed, Farzeen (Abu Dhabi Marine Operating Company) | Farouk, Magdy (Abu Dhabi Marine Operating Company) | Ouzzane, Djamel (Abu Dhabi Marine Operating Company) | Draoui, Elyes (Abu Dhabi Marine Operating Company) | Torrens, Richard (Schlumberger) | Amoudruz, Pierre (Schlumberger)
Coupling is performed periodically at the wellhead, using a reservoir simulator in which the field manager controls the reservoir models by supplying well constraints and controls the network models by supplying well performance curves. Allocation strategies and pressure and flow constraints are imposed by the field manager, for which the different sub-models are black boxes; the models themselves are controlled hydraulically without embedded production or injection constraints. This explicit approach has been selected for its flexibility. In particular, by expressing rates at the surfacesubsurface interface at standard conditions, it is possible for the two reservoir models to have different equations of state and different treatments of injected water salinity, while the surface models use a blackoil fluid description. This project required ensuring rate continuity at the transition from history to forecast for over 600 active production and injection strings, even when the reservoir and network models are not perfectly historymatched. This was achieved by introducing pressure shifts in each vertical flow performance curve to ensure continuity of the choking margins (i.e., differences between wellhead pressures and backpressures) and by overriding the default guide rate flow allocation method of the field manager to prevent abrupt changes in the production split of wells currently producing below potential. The use cases described here are based on an eight-year (2015-2023) drilling schedule followed by no further activity. We focus on assessing the impact on production and injection arising from: replacing pipelines or changing network topologies; relaxing the constraint of producing at initial solution gas-oil ratio with and without reduction of separator pressures; and redistributing or increasing the water injection capacity. 2 SPE-183153-MS