In Q4 2017, the first extended-reach horizontal oil producer was completed in S-Field, with the horizontal section designed with nine isolation compartments with swellable packers. Each compartment was configured with an inflow control device (ICD) and an integral sleeve (on/off function) attached to the ICD’s joint. This paper discusses the effectiveness of the ICD technology in terms of sustaining incremental cumulative oil production by delaying water-breakthrough and subsequently reducing undesired water cut after water-breakthrough. An extensive post-job evaluation on production performance was conducted to evaluate the performance of the installed ICDs. The workflow was divided into three stages: history matching, forecasting, and post-job ICD evaluation. During history matching, the horizontal well with the ICDs was modeled using a high-resolution numerical simulator, and the reservoir model was calibrated with production data from a well test. Actual production rates and the water-breakthrough time were matched by revisiting key subsurface uncertainties from the sector model, such as aquifer strength, oil/water-contact, and relative permeability using the Corey correlation. The history-matched model was then used for the forecasting stage to predict cumulative production on a longer-term basis. Lastly, the performance of the ICDs was quantified after 4 years of production by comparing the oil increment from the ICD completion to the non-ICD case as baseline that would have been a miss of additional oil cumulative. Over the past 4 years, this horizontal well produced more than expected, with approximately 2–4 times more oil production than the estimated rate provided in the field development plan (FDP), whereby the lower completion is design optimally based on real-time ICD modeling updates. There were few uncertainties in the subsurface parameters such as fluid contact, fluid characterization, and the nature of an aquifer, were incorporated in the history-matching stage using sensitivity analysis and uncertainty range estimation. On the basis of actual and history-matched production performance, the well with the installed ICDs is projected to produce more than the non-ICD OH case with an improved cumulative oil production gain of as much as 6% and an 8% water reduction over 12 years of production. In addition, the ICD enables downhole influx balancing to delay the water breakthrough by 4 months compared to the OH case. The reduction or delay of water production is beneficial to the field to enhance oil recovery from the well. This case study demonstrates a successful ICD deployment under uncertainties, where during a real-time study in 2017, similar uncertainties were incorporated in high-resolution ICD modeling conditioned with real-time petrophysical data from logging while drilling (LWD) measurements. The use of ICD technology in this well demonstrated that zonal control efficiency could be achieved across the horizontal section and increased oil production over time. The ICDs were designed to deter early water breakthrough supported by well tests and manual fluid sampling indicating the water production only occur after 4 years of production and sand-free till to-date.
The first horizontal oil well was drilled through an anticline structure in the Block-7E of East Flank, S-field, penetrating three production sands Sand I, Sand II and Sand III. Based on a comprehensive pre-drill study through steady-state and 3D dynamic time lapse simulation, Inflow Control Device (ICD) with integral sleeve (on/off function) attached to the ICD's joint is the optimum development of the fault block that maximizes zonal control for contrasting water encroachments. Due to the unconsolidated nature of the target reservoir, this well is designed for Open-Hole Gravel Pack (OHGP) with specialty 3D filtration screen to manage sanding issue. This paper highlights 2-in-1 application of ICD with enabled zonal shut-off sleeves and the OHGP completions with external screen. A pre-drilled ICD dynamic modeling is constructed to evaluate the well performance with ICD configuration. The design criteria for an optimum ICD design configuration is based on number of compartments and size, packer placement, ICD nozzle sizes and numbers. This dynamic single well model was used to justify the technology value which resulted in production improvement (maximizing oil and minimizing/delaying water). However, during the drilling of this well, the pre-drilled model is then updated in real time with the input of actual petrophysical data from Logging While Drilling (LWD) measurements along the OH section. Actual well trajectory and structure adjustment encountered while drilling were also co-utilized to determine the final optimum ICD design for the field run-in-hole (RIH) completion. Target fault block in S-Field East Flank requires optimum development strategy for its economic viability (Kumaran, P. N et al. 2017). Only one open-sea discovery well proved the oil bearing sands to-date, but a lot of uncertainties remains: geological structure, fluid contacts, fluid characterization, existence and nature of an aquifer, etc. Hence, all these uncertainties are incorporated in the ICD optimization through sensitivity analysis and uncertainty range estimation. Oil production improvement with water reduction while delaying water encroachment are key in the optimization of the ICD design, which is achieved by evaluating the impact of ICD's influx balancing throughout the horizontal section. Study shows that water encroachment is effectively controlled with 9 compartmentalization zones along the horizontal section, each one separated using oil swellable packer. After 7 months of stable flow, well test is showing zero-water and zero-sanding to surface with well controlled production rate that can produce more if required. This is the testimonial of the deployment success from its initial conceptual design to its ultimate completion.
This paper discusses the smart Drill Stem Test (DST) string, run for a Deep Water (DW) well test operation, which enabled considerable saving of rig time, reduced risks, and provided best reservoir data quality, while performing a commingled DST in a single run. Evaluation of the zones was made without any wireline intervention runs such as Production Logging Tool (PLT) or Surface Read Out (SRO). Acoustic telemetry provided seamless access to downhole data, including production profiles from both zones, throughout the DST operations. This paper will help the well testing fraternity conduct well test operations efficiently and safely in a deep-water environment using new technology tools and innovative methods. Well testing costs and risks can be reduced significantly. The smart DST string, run in hole (RIH) for the DW well test, consisted of a combination of conventional DST tools, a new generation packer and below packer, acoustically operated tools including: Acoustically Operated Sliding Side Door (SSD) - provided access to the reservoir for Well Kill Operations after the standalone screens became plugged with unconsolidated sand and Loss Control Material (LCM) pills.Multiple Discrete Temperature Sensor Array - Eliminated the requirement of running a conventional PLT to evaluate the commingled flow of two zones, provided valuable production logs, and resulted in unexpected, additional information evident from the thermal transient data.Acoustically Activated Bottom Hole Samplers - collected bottom hole samples selectively, at different drawdowns, without wire line intervention or without applying annulus pressure.Wireless Gamma (GR) Depth Correlation Tool - Provided accurate TCP gun placement, without running a conventional wireline GR/CCL, by using a tubing conveyed Gamma Ray logging tool; results were collected wirelessly in less time than a conventional wireline run.New Generation Packer -The large size 9-5/8" Hydraulic Set Retrievable seal bore type packer was used for the first time by the company. This is a most suitable packer for DW DSTs, which eliminated the requirement for slip joints, drill collars and safety joints or the running of a permanent packer, which would have required multiple trips and restricted the gun size.
Challenges associated with horizontal wells production in a barefoot or only standalone screen are well documented in the industry. Inflow control devices have been around for years and have been the answer to mitigate the challenges typically associated with heterogeneity in horizontal wells, as was applied in an offshore brown field in East Malaysia, Field S. However, as the field gets more mature, increasing production challenges posed by the reservoir leads to conventional passive inflow control device solution becoming less effective. Over time, as water production from the reservoir increases due to the rise of aquifer column, new infill wells have to be completed shallower and closer to gas oil contact to maximise recovery leading to risk of high gas production. The risk is further compounded by uncertainty in the fluid contacts in a complex dipping reservoir. In order to mitigate these challenges, Autonomous Inflow Control Device (AICD) was selected for Field S infill wells to control excessive gas production anticipated due to the wells placement. AICD's ability to choke production based on the fluid properties allows for improved flow control together with influx balancing from segmentation into compartments by swellable packers. In total, seven (7) horizontal wells were completed in an infill drilling campaign in Field S, with the wells placed at around 5 m from prognosed gas oil contact. AICD was installed with premium sand screen and swellable packers in the wells’ lower completion and has managed to control excessive gas production while enabling production at the targeted oil rate. This paper describes the implementation of AICD in Field S infill drilling campaign with challenges of complex dipping reservoir and fluid contact uncertainty. The workflow to investigate the feasibility of the candidate and the completion design process will be discussed. Well modelling (nodal analysis) using production data was performed to characterise the well performance and to understand the impact of AICD in controlling gas and inflow of producing fluid into the producing horizontal section.
Field development for brownfields nearing their economic thresholds is always challenging, especially in offshore environments. As an operator, innovative approaches are necessary to reduce capital expenditures (CAPEX) and create attractive projects. A marginal cluster consisting of three fields, namely PN, NL, and PR, is expected to reach its economic limit in the next 2 years. This paper elaborates on single-trip completion technology as a catalyst for drilling one infill well in the PR field development project. In 2017, one appraisal well was drilled in a western area of PR field to validate the presence of oil. The scope of work included evaluating reservoir productivity and acquiring bottomhole fluid samples. A drillstem test with four multirate tests was executed for this reservoir. A horizontal development well named PA-02 was proposed and categorized as an extended-reach drilling well because of the drilling complexity. Most offshore wells in shallow-water environments are completed with a conventional well completion run that takes two or more trips, which normally takes more than between 5 and 8 days. Given expensive daily rig rates, the ability to reduce completion installation time was deemed vital to the economics of the project. If the installation incurs additional unnecessary project costs, it can cause the project to be economically unattractive. Using a collaborative approach, an interventionless, single-trip sand control system was designed and selected as the optimal completion solution to meet project demands. Radio-frequency identification (RFID) technology is one of the key enablers for the single-trip completion as it offers the utmost flexibility in both activation and contingency methods to deliver the necessary project cost reduction. At a time of uncertain global crude oil prices, the RFID-enabled single-trip completion concept discussed in this paper has become a beacon of light for operators in an otherwise dark period by allowing previously marginal or sub-economic projects to become viable. This technology has resulted in operational time savings of at least 27% compared to typical conventional two-trip completions in Malaysia offshore environments. Minimizing operational risk is also foreseen by reducing installation to a single integrated upper and lower completion trip. Selecting this RFID-enabled completion facilitated full deployment in one trip in the high-angle well, which eliminated the deployment of a tractor service for a 67% cost savings in this aspect alone. This method represented a paradigm shift in operational efficiency and will now be the operator’s strategic completion methodology when developing marginal fields. The deployment represents the first application of a single-trip completion in an economically challenging brownfield in the Malaysian offshore environment. The reduction in operational time and resultant savings in CAPEX proves that a single-trip completion offers an exceptional alternative to conventional methods in the shallow-water offshore environment.
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