Intelligent Completion in Water-Injector Well Improves Field Development
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The operator piloted a new well-completion design combining inflow-control valves (ICVs) in the shallow reservoir and inflow-control devices (ICDs) in the deeper reservoir, both deployed in a water-injector well for the first time in the company’s experience. The objectives were to improve reservoir management, reduce well-construction complexity, and achieve cost optimization. This paper covers the overall aspects of well performance in commingled injection mode.
The offshore field was discovered in 1971 in the Arabian Gulf. On the basis of results from exploratory wells, three main reservoirs were proposed for further development (A, B, and C). The commercial phase of the field started successfully, with first oil in 2015 provided by the two first wellhead towers as part of the Phase I development plan.
The completion design described in this paper is aligned with an optimized field-development plan (FDP) resulting from a study initiated in 2017. The main objectives of the study were integrating new acquired data to upgrade static and dynamic reservoir models to identify any opportunity for extra production and cost optimization.
Early water breakthrough caused by the initial elected well pattern and the associated oil-producer-to-water-injector spacing is a significant risk. Therefore, accessibility and selectivity to control inflow are strongly recommended for the upper reservoir (A) to mitigate the breakthrough risk and secure long well life and maximize reserves. The initial dual completion, with two horizontal laterals targeting Reservoirs A and B, and a nonaccessible upper drain was removed, and a single controlled completion was placed.
Pattern. The FDP consisted of two phases. Phase 1 consisted of an early production scheme from two wellhead towers and export of untreated crude to nearby facilities. This phase contained an intensive data-gathering program to reduce reservoir uncertainties and identify future risks and opportunities clearly. Phase 2 is the full field development, containing the bulk of the oil producers and water-injector (WI) wells drilled from new wellhead towers and newly installed offshore treatment facilities.
The overall reservoir performance of Reservoir A was significantly better compared with the original basis of assumption. Consequently, the original line-drive development scheme between oil producers and WIs had to be revised in order to avoid early water breakthrough. As a response, the injector wells were placed outside the oil pool.
The behavior of Reservoir B met expectations; for that reason, the line-drive well pattern was maintained in this reservoir.
Well-Completion Design. The completion design considered in the original FDP for all WI wells consisted of dual lateral drains of approximately 3,500‑ft individual drain length, with either dual-flow assembly (DFA) with inaccessible upper drain or a multilateral tieback system (MLTBS) allowing access to the upper drain and reservoir control by ICDs. The drawback of the MLTBS completion is the increase of complexity and increased well cost.
The initial objective was to complete the first wells as dual laterals with DFA and openhole in the upper section while building the learning curve to implement MLTBS completions. With this goal in mind, the plan was set out to install MLTBS completions in 37 WI wells in the field. In addition to the need for full access to the upper laterals in Reservoir A, segmented controlled injection was required for each of the three flow units.
Well Cost and Completion-Design Optimization. Production performance in Reservoir A is far better than anticipated. Therefore, the reservoir model had to be updated and history matched. Subsequently, a first pilot was proposed earlier in a new development well where the openhole drain length was shortened by approximately 50% (1,500 ft) to test the effect on well productivity. The production results showed that drilling a shorter drain gave a similarly high productivity index compared with longer drains considering the same completion configuration.
A newly proposed completion approach aims to reduce well complexity and to improve reservoir management by achieving the following:
- Removing the requirements of setting whipstock at high angle
- Avoiding drilling one lateral horizontal drain
- Incorporating accessibility to all sublayers in the deviated section
- Allowing surface-controlled injection per segment without well intervention
- Providing ways to determine the allocation of the water injected per sublayer in the upper zones equipped with pressure and temperature gauges
Completion Design of Proposal Well SWI-01. The capabilities of the completion design deployed in Well SWI-01 were limited by the available equipment in stock. Therefore, some drawbacks were present from a completion perspective even at the beginning of design evaluation. Nevertheless, mitigation actions were identified whenever possible. A single 3½-in. tubing with three ICVs covering the upper zone (Reservoir A) and 14 ICDs in the lower drain (Reservoir B) was proposed. A well model was created for the entire well using commercial software for well-completion design.
The ICD design for the lower completion was based on a responsive design approach. This responsive technique achieves optimal well rate without choking back injection during early production life, which means that, at early stage, the completion will perform similarly to an openhole case.
The lower completion consists of 14 ICDs spaced with blank liners and five swell packers for compartmentalization. The design is adjusted to avoid erosional limits (830 BWPD).
Well Planning. Drilling and Completion. The well was planned to be drilled with the following phases: 36-in. hole (30‑in. casing), 16-in. hole (13⅜-in. casing), 12¼-in. hole (9⅝-in. casing), 8½‑in. hole (7-in. liner), and 6-in. lateral drain (4½-in. liner with ICDs).
The team revised the zonal-isolation requirements during the production-logging-tool (PLT) operation, which was planned for 3 weeks after the date of the completion of the well. Selection of the packers was made at this stage to achieve this requirement. The hole was displaced with low-salinity brine (5%) to ensure enough packer swelling and proper isolation within the selected timeframe. Once well total depth was reached, the hole was displaced with low-salinity viscous brine to reduce the friction factor while running the lower completion with ICDs.
An open-end system with ICDs in an open position was proposed. A caliper log was run to determine where to set the openhole packers.
Well Integrity. Cement-evaluation logging was required to confirm the good quality of cement behind the casing and between each interval. A cement-bond log was planned inside the 7-in. liner to confirm zonal isolation between the three perforated zones of Reservoir A.
Results and Way Forward
Well Construction. Drilling and completion operation was performed per best practices 5 days ahead of schedule. The well was deemed as a success from a reservoir-management perspective, and overall well-construction time was reduced by 3 weeks from the original plan.
The achievements of the deployed well-completion design include:
- Full accessibility to both reservoirs including all sublayers
- Surface control for three upper zones in Reservoir A
- Improved overall stimulation efficiency
- Reduction of drilling complexity by elimination of one lateral drain
- Continuous monitoring of the flow (fewer PLT interventions)
- No effect on slot allocation at the wellhead tower
Well Performance. A PLT acquisition was conducted during the initial testing campaign. PLT interpretation showed that all ICVs were functioning properly and no issues were found.
The three sublayers covered by ICVs were not stimulated individually because of time constraints. During PLT surveys, ICVs were closed and injection was stopped. Thanks to dual gauges in the upper and lower ICVs, zonal-pressure-falloff data were recorded and interpreted. Two important results should be highlighted:
- The upper sublayer had 300-psi overbalance compared with the lower sublayer.
- The upper zone showed very low skin factor, while the lower zone had very high skin factor (Fig. 1).
The reason is the difference in static pressures between sublayers: The upper sublayer, with lower reservoir pressure, received most of the stimulation fluid, while the lowest sublayer, with higher reservoir pressure, was poorly stimulated.
The allocation approach itself was not used in the pilot well in commingled mode because of the limited number of dual gauges (equipment-availability limitation). In a similar configuration as the pilot well with three ICVs and ICDs, four gauges in the tubing are required to obtain accurate zonal ICV allocation as well as flow rate. In the case that water will be injected in three zones only, three gauges in the tubing, plus the wellhead-pressure gauge, are enough to allocate injection per zone accurately.
- The completion design installed in Well SWI-01 has demonstrated fulfillment of high injection rates in a slanted perforated section.
- The pilot design implemented was found to be an adequate solution to be used on the injector wells proposed in the center of the reservoir, where the risk of early water breakthrough is considerably higher.
- The completion has full accessibility to all reservoirs in conjunction with flow control over the flow units.
- Commingled injection is governed by the injectivity index per zone and wellhead-injection pressure and does not show the sacrifice of inflow rates between single or commingled mode.
- Flow-allocation issues in commingled injection can be resolved with the presence of surface-controlled ICVs and permanent downhole pressure and temperature gauges.
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Intelligent Completion in Water-Injector Well Improves Field Development
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