Converting data to actionable information through continuous oil production monitoring is a fundamental part of any production optimization strategy. The development of Intelligent Field technology has remarkably contributed to the upgrading of production surveillance framework and provided an extended access to real-time data. This same technology is still in its infancy when it comes to multiphase mass metering and field practicality issues. As for conventional fields where the unavailability of continuous data flow is not considered out of norm, the high uncertainty in oil production rate estimation and allocation is very well expected. The main source of this uncertainty is the reliance on sporadic welltest data and empirical multiphase flow correlations to allocate liquid production rate.Critical and subcritical multiphase flow choke performance is predicted using well-known correlations that are based on specific datasets characterized by a specific field or hydrocarbon type. Case studies where those correlations are matched with different production data and used later to predict the choke performance are present in the literature. Yet, the oil industry is faced with many challenges because of the limited accuracy of those predictions. The complexity of multiphase flow behavior and the irregularities in operational conditions can explain such low capability of those correlations particularly on field data.Artificial intelligence (AI) tools and techniques for so-called artificial neural networks, fuzzy logic and functional networks were employed to develop data-driven oil flow rate computational models for both critical and subcritical flow conditions. These AI models were trained and tested exploiting 595 production rate tests from 31 different wells. The prediction results showed a strong correlation with actual field data and promised a reliable tool/methodology to estimate oil flow rate as a function of operational conditions and choke size. This paper presents an engineering look at the inclusion of AI data-driven models in the production surveillance system to enhance welltest data validation and reduce the uncertainties in production allocation.
This paper will outline the results of a field feasibility study to utilize hydraulic turbine applications for power recovery in water injection systems. The working principle of hydraulic turbine includes recovering excessive and unutilized energy in liquid flow systems. This is achieved through converting unexploited injection system pressure to electrical power generated by rotating turbines. The powered water injection systems are often restricted to meet injection targets as part of the reservoir injection strategy to support oil production. Pressure losses in powered water injection systems take place at surface chokes that regulate injection target rates. Expected pressure losses in an injection flowline was determined through the analysis of frictional and gravitational pressure losses. The injection pump performance curves were also factored in as part of this rigorous evaluation. The feasibility study has been conducted with flexibility in mind to account for future changes in reservoir injection/production strategies. Field-A candidates were explored and vetted to ascertain the achievability of applying this innovative power recovery concept on existing injection systems. A systematic candidate selection roadmap was established. The objective of this conceptual roadmap is to provide a means for conducting the primary assessment of candidate injection systems in Field-A. Several suitable injection systems were selected after a prudent evaluation of possible power recovery turbines candidates in Field-A. The expected power saving realized from applying hydraulic turbines was quantified in terms of net present value and return on investment. The economic impact from converting this pressure to power a hydraulic turbine was established, bearing in mind: The initial capital investment.Payback period.The projected inflation rate.The equivalent gas sales required to generate this power.
The paper outlines operational challenges during the well securement of a Power Water Injector (PWI) completed in the reservoir oil-water contact (transition zone). Surface integrity issue arose in Well-A necessitating the installation of adequate downhole barriers to carry-out surface remedial repairs safely. Well isolation shut-offs were not successful in eliminating surface pressure to meet the minimum stipulated operational requirements for this field. Well operator's barrier philosophy mandates the presence of two shut-offs; one of which is mechanical, to allow removing surface control equipment during rigless operations in power water injection wells with positive wellhead pressure. Water flooding strategy in Field-A calls for drilling water injectors at the flanks and maintaining a peripheral injection scheme. However, as more wells are placed towards the crust of the reservoir to sweep the remaining oil behind the flood front, this well placement strategy leaves behind a transitional zone where more than one fluid phase is present. Formation evaluation logs conducted on Well-A indicated that the completed reservoir interval lies within the oil-water-contact. Typical well completions for PWIs in Field-A use large casing sizes up to 9-5/8 in. of outer diameter. Bullheading pumping technique is conventionally sought as the primary securement method for water injectors. However, hydrocarbon displacement with kill fluid in such types of completions is challenging given that the hydrocarbon displacement velocity is often surpassed by its segregation velocity. Attempts to eliminate the persistent wellhead surface pressure build-up in Well-A were unsuccessful. Fluid circulation was then, applied to Well-A. Heavy fluid was forward-circulated against a blank mechanical plug installed below the wellbore oil-water interface which was detected by a wireline gradient survey. Accordingly, compromised wellbore fluid was displaced. This technique has set the pace for future well securement operations in PWIs completed in the reservoir transition zone.
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