In viscous oil reservoirs, Polymer flooding is often used to improve oil recovery either after a short period of waterflooding or as a tertiary recovery process following extensive period of waterflood. After six years of water flooding in a major reservoir in Sultanate of Oman having viscous oil (90cp), a field development plan was developed to implement polymer flooding in this reservoir with anticipated incremental oil recovery of around 10% over and above that of waterflood. Necessary facilities were constructed, injection and production wells were drilled, completed, converted and the polymer flood project was initiated and ongoing since the last three years through 27 polymer injectors. By implementing proactive Well and Reservoir Management (WRM) strategies, the actual oil recoveries have been better than predicted levels so far. It is demonstrated here that proactive well and reservoir management through proper well and reservoir surveillance and dynamic adjustment of injection and production rates play a very important role in improving the performance of polymer floods as in waterfloods. Well and Reservoir Management (WRM) principles in case of a polymer flood are similar to that of high mobility ratio waterfloods with some additional aspects that are specific to a polymer flood scenario. Polymer chemical costs, its higher viscosity and non Newtonian fluid flow behavior all create unique conditions that are nonexistent in normal waterfloods. This, in turn, dictates the strategies and methods employed to optimize polymer flood performance. This paper details successful implementation of proactive WRM strategy that has played a key role in sustaining production from this polymer flood field to date. It describes the pattern management processes to optimize pattern wise polymer injection and oil recoveries, conformance control measures implemented to increase sweep and oil recovery, innovative surveillance techniques to monitor fracture growth in polymer injection wells and for evaluation and optimization of production/injection profiles. Production wells and facilities issues arising from polymer breakthrough are being addressed to mitigate any adverse effects.
The first field scale Polymer flood project in the Middle East region is under operation in an oil field of The Sultanate of Oman since early 2010. The oil field discussed here contains viscous oil (90 cp) was discovered in 1956 and is located in eastern part of South Oman Salt basin. First commercial production started in 1980 from this field. The field has gone through different development phases in its 30 years of history prior starting tertiary recovery phase by polymer flooding. This Polymer flood project comprises of 27 patterns coversing about one third of the total field IOIP (initial oil in place). It is worth mentioning that whole field is under water flooding and water injection was going on prior to initiation of Polymer flood in 27 injectors. So far, this project has been running successfully with good performance contributing to significant oil gain. During this successful journey of about 4 years, the project has passed through many expected and unexpected challenges. The well and reservoir management team has been working actively in all those challenges with novel approaches to increase efficiency of this project. One of the key challenges encountered is reduction in productivity of producer wells in comparison to earlier water flood with same injection volume. In a few polymer wells production rates even dropped by more than 50%. The main challenges for these wells seeing higher drop in liquid rate is that there is no or minimal oil gain in-spite of reduction in water cut due to disproportionate decline in liquid rate. This reduction in production rate smay be attributed to decrease in producible fluid mobility, high fluid density with polymer slug and skin formation near wellbore. At the same pressure drawdown of the artificial lift pump withdraws less fluid due to increase in fluid density with polymer breakthrough. There are also possibilities of plugging as a result of moving solid fines from the more viscous fluids near the well bore. These caused more drawdown and less fluid produced and resulted in high gross reduction in some wells. In order to overcome these gross decline, chemical treatment using mutual solvent has been carried out in a few wells as trial and has given good result. A detailed analysis is going on to investigate possible causes and accordingly design suitable remedial actions. This paper describes briefly about the principles involved in this solvent stimulation jobs and results of field implementation with real field examples.
PDO is a major operator in the Middle East with long production history for many of its oil fields. Due to the increased gas supply requirements, it is considering options for blowing down the gas caps of some selected oil fields to cater for the gas demand for achieving sustainable oil production. The key challenge for these gas blow down is to maximize gas production plateau while simultaneously minimise associated oil recovery losses. This Case Study illustrates the Gas Blowdown optimisation of a saturated clastic oil reservoir. During the Blowdown Study, optimum gas production rates from each of the Upper and Middle Gharif reservoirs are targeted to meet a given gas production plateau rate. A fit-for-purpose assessment for the impact of subsurface parameter uncertainties on the proposed development demonstrated robustness of the gas production plateau period. This analysis resulted in a Gas production Plateau period ranging from 4 years (Low case) to 7 years (High case) with an expectation case of 6 years. Multiple Subsurface & Surface development scenarios have been evaluated including lowering pressure ratings for the Separator inlet pressure. The oil & gas production profiles thus generated have been evaluated for robust economics and used for final concept selection & field implementation. Furthermore to minimise oil losses various optimisation efforts have been identified during pre and post blow down phases in terms of re-perforations, gas lift implementation and blow down oriented well and reservoir management practices. This case study proposes an optimised Gas Blowdown field development by maximizing gas plateau period while minimizing associated oil loss. The Study resulted in selecting the appropriate surface development concept, operating specifications and provided an optimised field management plan during the Blowdown phase. The methodology adopted in this case study should find wider applicability in the industry.
Controlling and monitoring steam injection into heavy oil reservoirs are important elements of heat management. Static chokes with tapered-bean inserts are the most reliable and cost-effective means of controlling wellhead steam injection rates. However, adjustable steam chokes are often used because 1. Rate changes can be made without interruption of steam supply to the well.2. An inventory of bean inserts is not required.Adjustable or multiple orifice valve (MOV) chokes have two disks, each with a pair of holes (orifices). The size of the choke opening is adjusted by rotating one disk causing the two pairs of holes on each disk to overlap by differing amounts. This paper presents the results of field tests conducted to assess the flow control and monitoring capability of MOV steam chokes. Topics include adjustment precision and reproducibility, critical and subcritical flow conditions, and comparison of calculated and measured flow rates.
Controlling and monitoring flow rates at continuous and cyclic steam injection wells are important elements of reservoir heat management. For nearly 30 years, critical flow chokes have proven to be the most reliable and cost-effective means of controlling steam injection into heavy oil reservoirs. Flow control efficiency has been further improved with tapered-bore bean inserts to achieve critical flow with only 10% to 15% pressure loss across the choke.For the past 10 years, the standard steam choke assembly has consisted of a 1-inch outer diameter (O.D.) by 6-inch long bean with 6° tapered-bore inserted in a 2-inch O.D. cage nipple or housing. Larger diameter cage nipples and bean inserts have been required for steam injection rates exceeding 500 b/d. More recently, a cost-cutting practice has been employed using shorter tapered-beans inserted in standard choke assemblies. This paper presents the results of field tests conducted to evaluate the effectiveness of shorter tapered-bean length for controlling steam injection rates. Transition from subcritical to critical flow and overall pressure loss for different taperedbean lengths are presented. A modified Thornhill-Craver flow rate equation is provided for critical and subcritical flow regions. Calculated and measured rates are compared and their relative uncertainties are assessed.
scite is a Brooklyn-based organization that helps researchers better discover and understand research articles through Smart Citations–citations that display the context of the citation and describe whether the article provides supporting or contrasting evidence. scite is used by students and researchers from around the world and is funded in part by the National Science Foundation and the National Institute on Drug Abuse of the National Institutes of Health.
hi@scite.ai
10624 S. Eastern Ave., Ste. A-614
Henderson, NV 89052, USA
Copyright © 2024 scite LLC. All rights reserved.
Made with 💙 for researchers
Part of the Research Solutions Family.