A prolific gas producer in Sarawak waters was shut-in and idle due to a tubing leak resulting in a significant decline in the total hub production. The well remained idle and required immediate remedial action to meet the contractual sales target. Hence, an expandable tubing patch was proposed to isolate the leak and reactivate the well faster. This paper presents data gathered to identify leak location, tubing patch design, and installation using real-time coil tubing. Several logging surveys were performed to detect leak depth including caliper log, leak detection log (LDL), and downhole camera run; since no pressure build-up was observed post bleed-off tubing and casing, while SCSSV was in closed-state. Running caliper log could not indicate severe metal loss of 7-inch tubing, hypothesizing that the leak could be of a smaller dimension. Therefore, LDL was conducted, indicating temperature gradient and acoustic energy changes at a single depth location of 247 ft.THF, above SCSSV. Utilizing the leak depth marker from acoustic log, a downhole camera was staged to verify geometry of tubing leak. Root cause failure analysis (RCFA) was carried out for this tubing anomaly using diagnostics data to determine the possibility of UHP-17Cr-110 tubing failure. The likelihood of tubing failure is attributed to two main causes namely oxygen corrosion cracking and stress corrosion cracking. Based on RCFA outcome, Hastelloy C276, a nickel-molybdenum-chromium superalloy with the addition of tungsten was selected for the patch material, which is V0 rated, internal gas-tight qualification for temperatures up to 150 degrees Celsius and 5,000 psi. Moreover, this patch material satisfies the well conditions at approximately 20% CO2, 200 ppm H2S, 1000 mg/L salinity, and varying Hg concentrations from 800-2,000 ug/Nm3. The design of patch has been improved by adding AFLAS elastomer for the whole exterior of patch to eliminate contacts between the two metals: reducing the risk of galvanic corrosion. Real-time coiled tubing application was selected for setting the patch to ensure accurate depth-sensing control. Additionally, patch is a rig less intervention technique that will not disrupt the production from the existing wells sharing the same drilling platform. Generally, for high-rate gas wells, economic indicators seem lucrative with tubing patch application, where the payout can be achieved within a month of continuous production. The first step in ensuring the success of tubing patch is by running right diagnostics tools such as leak detection logging and downhole camera run, since multi-finger caliper analysis alone would not locate the leak depth and the leak geometry precisely. Valid design inputs are quintessential for the fitting recommendation of tubing patch design which includes accurate reservoir and fluid properties to ensure sustainability of the expandable tubing patch application.
PETRONAS has undertaken a large EOR project offshore Malaysia involving the use of Immiscible Water-Alternating-Gas (iWAG) wells for fluid injection. These iWAG injection wells will allow the alternate injection of both treated seawater and hydrocarbon gas. A significant concern for these wells is tubing corrosion resistance and integrity for over a 25-year injection life. The initial conceptual design for the iWAG injection tubing utilized Glass Reinforced Epoxy (GRE) & 25Cr tubing material due to the presence of dissolved oxygen in the injected water. The use of these materials present challenges due to limitations in downhole flow device installation with the GRE tubing and high cost of 25Cr tubing. The project team searched for alternative, fit for purpose materials to meet the project's requirements. Based on the recent PETRONAS success case of 17Cr utilization, the team examined the possibility of using 17Cr or lower grade CRA material for injection purposes. By pioneering the first application of 15Cr OCTG as an iWAG injection tubing material in the world, several risks had to be considered. Additionally, all risks had to be mitigated via various approaches ranging from detailed engineering planning to field execution and operation. The process of selecting this metallurgy involved criteria such as cost, performance, manufacturability and operational execution. The selection methodology included a comprehensive evaluation and recommendation process that consisted of: Evaluation of currently used metallurgical properties and limitations Identification of alternatives based on operating conditions, cost and manufacturing constraints Metallurgy qualification through comprehensive laboratory testing. Conducting tubing installation risk analysis Reviewing tubing operational, intervention and abandonment scenarios throughout the well life cycle The successful selection and installation of 15Cr was attributed to: The metallurgy selection, tubing procurement and installation process involving multidisciplinary and multifunctional groups both internal and external to PETRONAS. Rigorous testing at two separate laboratory facilities yielding test results which met and exceeded the required performance criteria. A 15Cr tubing make up efficiency of 100%. Impressive performance during operations resulting in a gross running speed of 371 ft/hr versus an average pipe running speed of 810 ft/hr. Use of low penetration dies to prevent slippage during tubing connection make up. This was critical since CRA material is very sensitive to scratching during contact with metal equipment. This potential metal scratching can lead to corrosion. On time delivery of 15Cr tubing from the OCTG provider ensuring sufficient time for preparation of completion accessories prior to offshore load out. Utilization of 15Cr as an alternative to Duplex and Glass Reinforced Epoxy (GRE) materials has also contributed a direct cost saving of 27% to the project.
As part of the enhanced oil recovery (EOR) field development plan (FDP), four immiscible water alternating gas (iWAG) wells with intelligent well completions were successfully completed. Inflow control valves (ICV) with dual-permanent downhole gauges (PDG) in each zone were installed to allow remote injection control and monitoring. Each well has three zones. One of the iWAG wells was installed with the DTS cable behind casing. This enabled the injection profile monitoring across each sand in order to optimize the injection rate distribution and representatively amongst the four wells. The paper further discusses the injection strategy to meet the required zonal injectivity and reservoir zonal voidage replacement over field production life. Downhole water injection conformance is critical for managing thin oil rim reservoirs. The injection plan considered several factors including uneven zonal split injection, short-circuiting injector to producer issues, and unfavourable zonal water-front propagation and changing injection scenarios over time. Hence, zonal control with optimal valve design is critical in achieving the EOR reservoir management plan. Injectivity and conformance modelling was performed on four iWAG wells across three reservoir zones to ensure optimal valve-sizing configuration for comingled injection multizone. A base case simulation assuming no downhole zonal control (all zones fully open) was first performed to understand the zonal injection performance and distribution contrast for both water and gas injection. This subsequently served as a guide for the zonal injectivity control strategy. This was followed by modelling valve sizes across a variety of injection scenarios. This was done to ensure the design working range for balancing future zonal injection selectivity under expected uncertainty range. Post deployment ICV modelling was performed with cross-reference to actual petrophysical data, reservoir properties, and well trajectories. Petrophysical evaluation showed some zones are having lower permeability with low fracture pressure. Step rate injection test data was used to calibrate the model and to further validate whether the valve sizes were within the design ranges prior to the injection phase. Based on the simulation using surface injection rates and PDG pressure data, most of the zones were able to meet the target injection rate within the set fracture pressure. The model will then be further updated with the zonal injection data in the future as the iWAG injection program is implemented.
Candidate screening for matrix acidizing has gained attention in recent years due to the importance in driving towards acidizing success rate and efficiency improvement. This paper presents a comprehensive workflow featuring a simple step-by-step method utilizing mainly production and basic reservoir data. The objective of the workflow was to ensure the right candidates were selected, standardized checklist of information being reviewed and time saving to shortlist wells with formation damage issues. Basic production data such as liquid rate (oil and water rates), water cut, gaslift rate and sandcount along with basic reservoir data such as permeability and height were powerful parameters that drive the workflow. Formation Damage Indicator (FDI) and Heterogeneity Index (HI) concepts were introduced to provide the initial screening of the wells. Other subsequent parameters were evaluated according to specific cut-off values. These cut-off values have made the workflow standardized and practical to speed-up the screening of candidates. Once the wells have passed through the workflow, the shortlisted candidates were matured by performing nodal analysis, studying on the detailed formation damage type and skin evaluation, formulating the remedial solution and quantifying the potential gain. This workflow was tested throughout selected fields in the Malaysia region operated by PETRONAS Carigali, which proved to be efficient in identifying the acidizing candidates. The ultimate aim of the work was to automate the selection of wells with productivity issues using real-time data. The workflow was then brought into an Integrated Operations (IO) environment using the same step-by-step method whereby the required data used for the screening process were pulled from corporate database. The IO environment retrieves data from master and asset databases to perform calculations using various parameters with its cut-off values. Using this method, candidate screening processes were shortened from two weeks to one day. In total, 750 strings were analyzed using this workflow, which resulted in 101 strings shortlisted as stimulation candidates. Twenty-eight strings have been executed from year 2017 until 2018 with a total 6500 bopd gain. Success rate has improved from 55% to 73%. The additional benefit of the workflow was also the ability to group wells with lifting issues, water production problems and sand production issues. The unique digitalized workflow is now a one-click exercise, which enables engineers to increase their operational efficiency resulting in huge cost and time saving opportunities.
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