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Largest WAG Pilot in Giant Al-Shaheen Field Reveals Optimization Methods

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This paper discusses the operation of the largest offshore high-pressure water-alternating-gas (WAG) injection pilot using hydrocarbon (HC) gas, with a gas-injection capacity of approximately 100 MMscf/D, in the giant Al-Shaheen field offshore Qatar. The paper also analyzes the current HC-WAG pilot and optimizes future development scenarios for extending HC-WAG injection to the field scale.

Al-Shaheen WAG Background

As part of the field-development plan, a comprehensive enhanced oil recovery (EOR) screening study was performed that explored the range of available EOR techniques. On the basis of these studies, WAG injection was identified as one of the more-promising EOR options for the field.

Additional studies performed in 2006 and 2007 indicated a large full-field potential for WAG in Al-Shaheen, with an estimated recovery of hundreds of millions of barrels over and above waterflood recovery. Data analysis and intensive simulation work, including both a history match and several forecast sensitivities, were conducted to understand and to estimate WAG potential on Al‑Shaheen reservoirs.

The Al-Shaheen WAG process is largely an immiscible process with some multi­contact miscibility effects between injectors and producers. Overall, WAG has been a success in the field in terms of seeing incremental oil gains on several patterns. Although physically successful, the project had been challenging operationally. In spite of incremental gains, a number of operational challenges were encountered during the execution of the WAG pilot. These challenges mostly were related to WAG-cycle conversions and operational efficiency of gas-compression systems.

WAG Recovery Optimization

WAG will be a major part of the development of the mature-flank and heavy-oil areas of the field. The areas proposed for WAG are undersaturated with gas at reservoir conditions. Incremental recovery from WAG could be affected by thermodynamic effects caused by large variations in permeability, viscosity, and saturation pressure in the field along with several other variables described in the complete paper.

To analyze the effect of these optimization parameters on incremental oil recovery from WAG, a sector model with varying static and dynamic properties was built (Fig. 1). The properties of the sector model were based on the history-matched model of the neighboring areas. The well spacing was 700 ft, which lies in the middle of the well-spacing ranges of the ongoing WAG pilot wells (500 to 1,000 ft). The WAG sector model was initialized with a range of fixed oil API gravities. Different thermodynamic effects of gas injection have been examined on the sector model. The model is also simulated for different WAG cycle lengths (1/1, 3/3, 6/6, and 12/12), ratios (1:2, 2:1, and 1:3), and slug sizes (1–30 years of WAG). The effects of choking production wells and changes in injection gas composition were also tested on the sector model.

Fig. 1—Sector model showing API gravity. The red line is the cut-out sector used for conceptual modeling.

Recovery Efficiency of WAG Process

The simulation sensitivities on WAG duration and timing indicate the need for finding an optimal WAG duration on the basis of recovery efficiency of the WAG process. Comparing a conceptual drawing with the results from the sector model shows that, after 10 years of 6/6 WAG, sufficient gas has been injected in this pattern and continuing gas injection improves recovery only slightly. Ideally, such an analysis is required for deciding the total WAG duration for the areas where WAG must be implemented.

From the realizations of the sector model, two additional effects were noted that require further investigation. During the WAG cycle, some oscillation in the oil rate is observed, which is not seen in the waterflood, and, at the end of the WAG slug, the oil production declines for a period of time before increasing again. The sector model was also used to investigate ways to reduce the oscillation and to improve production at the end of the slug.

To investigate the effect of varying the cycle length and the WAG ratio, the sector model with a fixed API gravity of 28 was used. First, varying the cycle length showed that reducing the cycle length increased the overall oil recovery. Comparing the oil-production rate from a 1/1 WAG with that of a 6/6 WAG revealed that the smaller cycle length reduces the oscillation in oil-production rate during the WAG slug. By reducing the cycle length, the pressure oscillations near the production well can be reduced.

To make an equivalent comparison of varying the WAG ratio, different scenarios were simulated with the same amount of cumulative gas injected as for the 10 years of 6/6 WAG. Varying the WAG ratio did not show a significant increase in oil production. Increasing the WAG ratio (prolonging the WAG) yielded the same volume of oil, but it took longer to produce. Reducing the WAG ratio showed an increased oil-production rate during the WAG period, but the cumulative recovery was slightly reduced.

Several different strategies were evaluated in an attempt to eliminate the reduced production rate at the end of the WAG. The reduced production rate is caused by a loss of reservoir energy (pressure) in the vicinity of the production well.

Optimizing WAG Timing and Cycle (Without Production Constraints)

In managing a WAG project, the WAG cycle length, ratio, and project lifetime for each pattern have to be determined properly. This can be achieved after carrying out a number of simulations in which each of the variables are changed. To determine the best WAG strategy for the undeveloped areas of the field, six cases are simulated with varying WAG strategies for each polygon:

  • 3 months gas/3 months water (3:3)
  • 6 months gas/6 months water (6:6)
  • 12 months gas/12 months water (12:12)
  • 3 months gas/6 months water (3:6)
  • 6 months gas/3 months water (6:3)
  • 9 months gas/3 months water (9:3)

Optimizing WAG Timing and Cycle (With Production Constraints)

Additional simulations were performed to identify optimal WAG cycles under production constraints. The WAG cycles were evaluated with a gas-production-rate constraint on producers, which was achieved by imposing a gas-rate constraint of either 3 or of 6 MMscf/D gas production per production well. The simulations show that WAG patterns suffer if 3-MMscf/D-gas-rate constraints are used, whereas 6-MMscf/D-gas-production constraints actually help to increase the incremental oil produced slightly.

Also, to determine the effect of running with a gas/oil ratio (GOR) constraint, a series of simulations was performed for the sector models. In these simulations, WAG was stopped if both producers adjacent to an injector reached a specific GOR limit. The results show that reducing the GOR limit can have a significant effect on the recovery.

Effect of Choking Production Wells on Oil Recovery

To further investigate the effect of choking back the production wells, a series of simulations was run in which production wells were constrained to a specific maximum GOR. The results show that choking back the production wells modestly in some cases increases production slightly, with a slightly more-efficient gas usage. Additional simulations were run to examine closely why the incremental recovery in some cases was higher if the production wells were choked back. Results show that choking the producing wells reduces production rate during the time that the well is being choked. However, the model does not have the usual drop in production rate at the end of WAG. For this reason, the model was run again without choking the production wells until the first adjacent injection well was switched to chase waterflood after completion of the WAG. Results show that all of the future WAG-development areas could potentially benefit from this production strategy.

Conclusions

  • Running equal ratios (a WAG ratio of 1) reduces the oscillation and variation in production rates. An incremental oil gain is observed when the cycle length is reduced.
  • A WAG duration of at least 5 years is required on the basis of standard industry guidelines for net and gross gas-usage factors.
  • The patterns suffer if 3 MMscf/D is used as a gas-rate constraint or if a low GOR limit is used.
  • No significant increase in cumulative oil production was observed from choking production wells during WAG.
  • Increased cumulative oil production was observed from choking production wells at the end of the WAG project.
  • The gas concentration was varied by changing the methane contents ±10 mol%. If the injected gas is leaner, it will reduce the incremental recovery from the WAG flood significantly. If the injected gas is richer, it will increase the incremental recovery from the WAG flood proportionally.
  • Richer gases can use a larger total gas slug size effectively.
  • With 6/6 WAG and base-case economic assumptions, the WAG flood is economical for a maximum lifetime between 6 and 15 years for the different polygons.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 190343, “Challenges and Learnings From Operating the Largest Offshore WAG in the Giant Al-Shaheen Field and Ways To Optimize Future WAG Developments,” by M. Pal, S. Furqan Gilani, and G. Tarsauliya, North Oil Company, prepared for the 2018 SPE EOR Conference at Oil and Gas West Asia, Muscat, Oman, 26–28 March. The paper has not been peer reviewed.

Largest WAG Pilot in Giant Al-Shaheen Field Reveals Optimization Methods

01 June 2019

Volume: 71 | Issue: 6

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