Field A begun water injection in 2016 via four water injector smart wells, which were equipped with Permanent Downhole Gauges and Inflow Control Valves. The water injection module was housed on a rented MOPU due to space limitation. Amidst the study to revamp the reservoir management plan, the team found multiple discrepancies in the reservoir zonal allocation dating back to start of injection. Inherently, this affects the Voidage Replacement Ratio tracking. Hence, the question remains: How efficient is the water injection in Field A? As Field A injects from a rented facility, the long term RMP strongly influences annual OPEX. This paper explains the journey of reallocating Field A water injection volumes from 2016 until today, and how it affects the outcome of the RMP study. PETRONAS has an offshore monitoring system which visualizes historical pressure and temperature trends at any tagged equipment. Field A water injectors consists of multi-zones completed with ICVs and PDGs. ICVs allow choking and zone changes to happen without intervention, and PDGs show downhole pressure and temperature changes over time. Coupled with the manual database which tracks ICV changes and water injection rates, the team re-modelled the injected volume allocation changes to each zone by anchoring the model on PDG trends, ICV size and choke coefficient, and water injection rates via an advance nodal analysis software. For reservoir characteristics calibration, properties from past FBUS interpreted results were used as a basis. From the modelling journey, at the same injection scheme, results showed that zonal allocation with small PDG pressure changes of less than 5% during stable injection conditions does not significantly affect allocation ratio in the well. Overall, the allocation would change between 0 - 3% in total. As one of the objectives of the exercise was also to gauge expected injected volume allocation to a specific zone when there were obvious pressure changes but no records of changing ICV sizes, this could be achieved via a calibrated model. Once a good anchor was made on reservoir pressure, formation gas-oil ratio, permeability and skin, devoid periods in the past could be modelled for expected ICV sizes by varying the choke size openings till the pressure differential between tubing and annulus pressure was achieved. Hence, modelling the expected zonal allocation during that period. This improved VRR tracking for the injection reservoirs and aided to in the efforts to revamp the reservoir management plan. This paper will explain the lessons learnt of having proper surveillance data as the impact on long term reservoir management plan is significant. In future, fields with smart wells but disorganized data can utilize this alternate method to reallocate production/injection volumes without the need for intervention.
Multiphase flow meters (MPFM) have been known save costs for new installations, are compact and as effective as a test separator. Field "F" is a green field with 2 wells and has been producing since 2018 from the same reservoir. The test facilities consist of an MPFM, and F flows to a hub called Field "G". Towards Q2 of 2019, there was a significant increase in production rates from both wells without any changes to surface choke size and without enhancement jobs performed. Added to that, reservoir pressure showed steady depletion. Daily production allocation for F showed lower than usual reconciliation factor when combined with G hub production. This suboptimal allocation raised doubts about the MPFM well test readings which launched a full investigation into the accuracy of the meter. From the offshore remote monitoring system, the first suspect was the increased inlet pressure causing parameters to be out of the MPFM operating envelope range. However, after further checking, there were other pressing issues such as faulty transmitter, and low range sensors. As these issues were being dealt with amidst the COVID-19 pandemic, the process to fix the meter was longer than usual. Rectification involved troubleshooting the MPFM post performing Multi Rate Tests, back allocation check to hub production and PROSPER/GAP model matching to check on the credibility of the well tests. These efforts were made due to budget cuts, as there was no advantage to bring onboard an entire well test package (separator) to test the F wells. Post several rectifications, the liquid, gas and oil rates were within 10% difference from allocation meter back allocation and PROSPER model calculation. Reconciliation factor for field G has also increased to normal range of 0.92 to 0.95. However, the rectification also showed a significant drop in metered rates, proving that the MPFM was indeed generating incorrect well tests since Q2 2019. The drop was higher than 30% in gross production rates which lead to a better understanding of the reservoir, and corrections to be made to dynamic models for any future development projects. This hence proves that even with the similar reservoir properties in both wells, the MPFM well tests still require vigorous checking and should not be treated in the same way as a test separator. This paper will describe the efforts by surface and subsurface faculties to ensure the quality of well tests from the MPFM. For future projects considering the MPFM installation, best to frequently quality check the MPFM well test figures with a test separator. However, if that option is not feasible, the efforts in this paper can act as a guide for the field.
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