The ENI Nigerian subsidiary operates a subsea field located in the north western sector of the Nigerian offshore deep-water, is an oil and gas producing field. The production is from subsea wells which are directed to a Floating Production, Storage and Offloading vessel (FPSO). All the wells in this field require sand control measures in the reservoir section from the onset to prevent sand production. Sand control in the field is challenging and various methods (gravel pack, frac pack and expandable sand screens) have been used. Conventional sand control integrity has failed in one of the wells, compromising production rate and exposing subsea asset to risks related to sand production. Compared to heavy workover required for primary sand control application, an advancing chemical treatment bullheaded through the subsea flowline and the production tubing provided a unique, highly economical, and effective solution to this challenging problem. The product effect creates an ionic attraction between the sand grains and fines, using non-damaging water-based fluid. The chemistry mitigates sand production, reduces or stops fines migration and increases the Maximum Sand Free Rate (MSFR). After pumping chemical treatment through a 4.2 km flow line in the failed frac packed completion, well returned to production with minimal sand presence, less than 24 hours NPT and eliminating the need for re-completion. This was the first time the chemical had been pumped from an FPSO and through subsea flow line. This paper discusses the planning, execution, post job analysis and lessons learned.

Batch drilling and completion improve field development efficiency in deepwater subsea environments, but well completion operations may be suspended for a long time while waiting for a subsea production system to be installed. An Angola deepwater field development plan called for five oil producers, two water injectors, and two water-alternate-gas injectors. Using a fast-track approach, the drilling campaign started in parallel with the subsea production system manufacturing. Seven of the nine wells were drilled and completed with reservoir isolation valves (RIVs) that were expected to suspend the wellbore for several months and then remotely open the wellbore without intervention. However, the RIV remote opening mechanism was compromised due to well conditions and compatibility issue in two wells, prompting contingency operations including coiled tubing and electric-line interventions and a redesign of the upper completions for the remaining wells. The lower completion strings were designed to be isolated with an RIV equipped with a remote opening system based on a nitrogen precharged spring chamber and tubing-applied pressure cycles. After pressure cycles not trigging the remote opening mechanism to reopen the valves in two wells, root cause analysis determined that the combination of bottomhole temperature (120°C), fluid (CaCl2 brine), and long suspension time (12 to 22 months) prematurely aged the RIV elastomers, causing the nitrogen section to loose pressure integrity. As a contingency, intervention operations were performed in the two wells with compromised nitrogen section RIVs, and engineering designs were modified to optimize the upper completion strategy for the five remaining wells. The RIVs in the first two wells were successfully opened using coiled tubing milling (first well) and electric-line mechanical shifting intervention (second well)—the first such operations in the world for the full-ball type of RIV. The paper explains the tool selection and testing processes for the intervention operations, compares the economics of the different intervention approaches, and describes how engineers optimized the new completion design on the remaining wells. By sharing lessons learned from root cause analysis, intervention operations, and new completion design, this paper adds critical experience to a relatively limited body of work related to engineering completions and contingencies for long-term well suspension and reentry for completion.

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This paper describes the novel experience of running Corrosion-Resistant Alloy (CRA) 25% chrome tubing with Dope-free connections in triple joint stands to reduce online running-in-hole (RIH) time. To achieve this, an international operator of a deepwater field development in Angola, defined a special set-up for the make-up and handling equipment, along with connections featuring Dope-free technology. 5 V2" production tubing strings were run in triple joint stands in 2 deep water wells offshore Angola. Well "A" had 14 triples while Well "B" had 67 triples installed. Running highly alloyed CRA tubing with Dope-free technology in stands, in conjunction with using the special handling equipment resulted in faster and safer installations, thus reducing operational risk and saving rig time for the operator. Furthermore, the thread compensator performed the make-up with the neutral point at thread pin thus minimizing stress at the thread's metal seal zone. Several other benefits recorded include savings in jet-wash water, zero dope discharge, reduced personnel exposure to risk, reusability of non-contaminated thread protectors and improved well productivity. The notion of installing highly alloyed CRA tubular in oil and gas wells initially considered too sensitive to be run in triples has been shown to be conservative. This paper shows that from field experience, running highly alloyed CRA tubulars with Dope-free connections in triples is achievable with demonstrable operational improvement and increased reliability.

Sand accumulation occurs in subsea infrastructure and pipelines, also called sealines, when the fluid carrying capacity isn't sufficient. Once this situation degenerates, the maximum achievable production rate decreases till complete stop: a sand blockage is formed and production lost. The first worldwide subsea application for a plastic coiled tubing for sand removal demonstrates the opportunity to think for alternatives and use an innovative technology to avoid expensive pipeline replacement and to restore the production in a quicker and cheaper way. With space upon FPSO units inherently limited, a complex engineering solution involving workover rig or intervention vessel is typically required to support the removal of sand plug or line section replacement. Those options, are inherently expensive, and could shut down the production for a long period and generate additional HSE risks. A preliminary analysis is necessary to identify the sand plug dimension and plan the proper remedial job. In 2014, Operator decides to think for alternatives and performed a smart intervention using an innovative Plastic Coiled Tubing directly from FPSO, washing down the riser and the subsea flowline till complete sand blockage removal. The use of a standard coiled tubing unit isn't an applicable solution for severe limitations in transport and rig/up operations; so the decision is to select and develop a customized ultra-lightweight, highly flexible pipe compared to conventional coiled tubing. On board of the FPSO unit, a continuous improvement process is necessary to optimize equipment layout and configuration. Adjustments in operative procedures and some troubleshooting actions maintain higher the efficiency during the washing and cleaning job through riser and subsea flowline. The final result is the complete sand blockage removal and the hydraulic continuity re-establishment inside the pipeline. The overall process successfully validates the so performed analysis, screening and equipment selection, demonstrating that plastic coiled tubing is a valid and innovative tool for sealines washing and production restoration in a quicker way.