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Integrating Fractional Flow Into Reservoir Surveillance Improves GOM Production

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Integration of well and reservoir surveillance techniques—production measurements, reservoir fluid characterization, pressure transient analysis, production logging, relative permeability, and fractional flow—are critical to understanding well and reservoir performance for effective well and field management, particularly in high-cost intervention environments. The complete paper presents a case study in the deepwater Gulf of Mexico (GOM) in which pressure transient analysis (PTA), fractional flow (FF), and production logging tools (PLT) were integrated to identify correctly the cause of, and execute an effective remedy for, a well’s productivity deterioration.

Background

The level of integration achieved in this study is not common practice because most commercial software products do not consider multiphase interpretations in analytical PTA. These limitations leave out the actual effect of relative permeability in the estimated transmissibility values. In this case, integrating fractional flow analysis with a multilayer PTA curve and running a production-logging tool made it possible to separate relative-permeability effects from plugging effects. A coiled-tubing (CT) mud acid-stimulation treatment then enabled recovery of approximately 65% of the well’s lost transmissibility, decreased formation skin from 16 to 9, and instantaneously restored 7,000 STB/D of production. This analysis approach has been recommended to determine the potential production-optimization benefits of future intervention candidates. The complete paper discusses the geology and reservoir characterization of the well, its initial performance and subsequent deterioration, the surveillance tools used to evaluate the well’s performance and determine the intervention method and steps, a comparison between basic diagnostic PTA and multilayer PTA, the building of the multilayer model, the execution of the stimulation treatment, and the results and conclusions of the program.

Field Case

A subsea deepwater GOM well began production in 2009 with an initial rate of 35,000 STB/D with no water production and a gas/oil ratio (GOR) of 1100 scf/STB. The well was equipped with a downhole pressure gauge (DHPG) that worked for only 90 days, during which it was possible to adequately establish a baseline well performance and accurate determination of formation damage (skin) and transmissibility. In July 2013, the well was shut in because of a stuck-closed subsurface safety valve (SSV). The well was back on line in 2014 after replacement of the upper completion, which included a new SSV and DHPG. Fig. 1 shows aspects of the well history.

Fig. 1—Deepwater GOM well history, including acid stimulation. PBU=pressure buildup.

 

The oil rate was sustained at approximately 35,000 STB/D from 2009 until 2013. The first well performance question arose after the well came back online in 2014, when a production loss of approximately 10,000 STB/D was observed. Because of uncertainties in the estimation of downhole pressure between 2009 and 2013, the point at which the well began losing productivity was uncertain. Whether the well was operated at a higher drawdown before the intervention was not entirely clear. Efforts were made to fully understand this issue, but some uncertainties remained. Additional changes were introduced in the well’s completion during the SSV intervention in 2014.

The second well-performance investigation began after an additional production loss of approximately 15,000 STB/D in 2016. This production loss occurred at approximately the same time as water breakthrough (WBT), and it was hypothesized that the effective permeability to oil was the main reason for this additional loss. The potential to restore even a percentage of these two large losses inspired a more-detailed evaluation of the performance of this well.

Performance Diagnostics and Results

Well-productivity deterioration for the well was identified on the basis of production testing and well-performance nodal analysis. The productivity deterioration was then confirmed by means of PTA. Standard diagnostic derivative analyses suggested that permeability decrease was the main source of performance detriment as the result of an apparent transmissibility reduction of 60%. Because WBT took place before productivity impairment was acknowledged, the immediate reaction was to establish the hypothesis that effective permeability reduction caused by relative-permeability effects was the main reason for the impairment. A multilayer PTA-type curve model, together with fractional-flow analysis, did not support the relative-permeability premise as the primary cause, leaving the potential for severe plugging of the reservoir rock as the predominant hypothesis.

A PLT run confirmed that approximately 60% of the completed interval was not producing at the expected levels. It was possible to separate the relative-permeability effects from the plugging effects by integrating PTA, FF, and PLT. On the basis of relative-­permeability and fractional-flow analysis performed on data before the stimulation, transmissibility was most likely affected in an amount equivalent to 13 ft of the total perforated interval of 114 ft. On the basis of PLT interpretation, water and oil were produced from the lower 27 ft. This was the zone affected by relative permeability that equates to a maximum thickness loss of 16 ft. This result is consistent with fractional-flow analysis. Plugging effects contributed to approximately 43 ft of 123 ft of effective thickness losses, as per PLT before the stimulation. This result is very close to multilayer-type curve-modeling PTA.

On the basis of the results of the 2016 intervention and observed post-intervention performance, the most-likely source of the formation damage was fines migration from high-velocity flow. This is believed to have been primarily the result of screen plugging and near-wellbore damage that occurred during the 2014 workover to replace the upper completion.

Conclusions

  • Basic PTA diagnostic practice can deliver misleading results. In this study, it would have indicated permeability reduction, when in fact transmissibility reduction occurred mainly as a result of plugging (formation damage-skin) and, to a much lesser degree, a relative-permeability effect. Common industry practice is to overlay log-log plot and diagnose accordingly. Unfortunately this practice leaves behind many production-optimization opportunities.
  • Approximately 7,000 STB/D of production were added because of the acid stimulation. More importantly, a systematic surveillance approach and data-analysis technique has opened additional scenarios to identify production-optimization opportunities.
  • Multilayer PTA enables the prediction of selective plugging in a single-layer producing interval when analyzed as multilayer.
  • A PLT confirmed the results from the revised PTA. There was very close agreement between the PLT and the revised PTA results.
This article, written by JPT Technology Editor Judy Feder, contains highlights of paper SPE 192843, “A Success Story of Production Improvement in a Deepwater GOM Field Based on Integration of Surveillance Techniques,” by Fabio Gonzalez, SPE, Doris Gonzalez, Steve Carmichael, SPE, Carlos Stewart, SPE, Marney Pietrobon, and Francisco Garzon, SPE, BP America, prepared for the 2018 Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, 12–15 November. The paper has not been peer reviewed.

Integrating Fractional Flow Into Reservoir Surveillance Improves GOM Production

01 September 2019

Volume: 71 | Issue: 9

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