Effective mudcake removal is essential to restore the optimal well productivity/injectivity after different drilling operations. Typically, this objective is achieved by using harsh chemical treatments such as hydrochloric acid (HCl), organic acids and oxidizers. However, these methods have been limited due to associated high corrosion rates, high operation cost, and un-even mudcake removal. This task becomes even more difficult and very challenging in horizontal/multilateral wells. Organic acids and acid precursors have been also used to clean long horizontal wells following drilling operations. However, in long multilateral horizontal wells, fluid placement is considered one of the main challenges with chemical mudcake removal treatments due to accessibility to each lateral and reaching its TD. Additionally, the use of these treatments has poor health, safety and environmental (HSE) footprints. This work provides a workflow and illustrates the use of an in-house designed zero-flaring flowback system to clean up recently drilled multilateral horizontal wells with water-based mud. The system consists of two upstream solid management systems, namely de-sander (cyclone), and sand catcher (filter). Downstream, the choke manifold, 4-phase separator, a downstream solid management equipment, and 3-phase separator are also included. Additionally, there is also a surge tank, as a backup flowback vessel to be used if needed to revive the well and offload any heavy fluids. This tank is used to initially help the well to gain the pressure momentum to naturally flow and offload heavy fluid present in production tubular. The cleanup campaign was successfully and safely completed for effective cleanup of more than 30 openhole horizontal multilateral wells without the use of any chemical treatments. The duration of cleanup operations was optimized using several techniques to effectively and efficiently remove existing mudcake. This paper provides the operational criteria to achieve effective and adequate mudcake removal for horizontal/multilateral wells and restore its optimal performance. Different design parameters and tailored flowback programs will be discussed, which led to effective drawdown pressure to reach optimized natural cleanup of each well. The well simulated flow model was also considered and used as input to design each well specific flowback program and minimize the risks of erosion, solids settlement in pipeline and downstream facilities. As a result, each well cleanup duration was reduced to an average of 1-2 day, while achieving the maximum potential production rate of each treated well.
This paper will present a dedicated field case study that shows effective optimization of injection facilities obtained by hydraulic simulation. Water Injection Plants (WIPs) in the fields under study are operated as a secondary oil recovery method by means of peripheral injection. Field production strategy dictates water injection requirements in a given field. A core area of Field-A was identified with a need for increased injection pressure support. However, existing injection facilities could not meet the demand of increased injection rates. The injection capacity constraints were discerned by conducting a selective injection system capacity test. The feasibility of future improvements to the injection system using hydraulic simulation forecasts provided valuable and vital inputs. Accordingly, the most reliable and cost effective option was implemented in the field. Hydraulic simulation along with network pipeline modelling was utilized on this case study with the objective of debottlenecking the overall injection system. Well performance models for the water injection wells to represent the reservoir inflow performance relationships (IPRs) were built. The most recent injectivity indices and static bottomhole pressures were used to construct the IPRs. Calibrations were then performed using current injection rates and wellhead pressures to history match the data and produce representative individual wells IPRs. On the other hand, piping network simulation incorporates surface injection lines sizes and ground elevation to account for pipe friction losses and gravitational pressure differences. Additionally, data from WIPs pump performance curves were inputted into the simulator to integrate surface and subsurface flow and capture the working mechanisms of the injection systems in this case study. Surface piping network optimizations were achieved using the outputs of the hydraulic simulator runs and sensitivity analysis based on proposed corrective scenarios. The effect of these scenarios to the existing system was forecasted in terms of the ability to achieve the required individual wells injection targets. The simulated options were conceived on the following basis: Utilizing an identified extra injection capacity from one of the WIPs. Looping the injected water through pipelines network connecting different WIPs. Constructing new injection lines to the field flanks that need additional injection.
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