This paper will discuss a game-changing and innovative technology that enabled cementless annular isolation (liner to borehole) across the reservoir, removing the risk of previous experienced cost and time overrun from complex cement operations and securing the full economical return on the wells. The technology has been deployed in four Moho North Albian wells, drilled through a complex reservoir with highly laminated lithology requiring efficient zonal isolation for both acid treatment and water shut off. During the earlier field development, many cementing challenges were encountered that increased risk and cost and the ability to deliver effective isolation across the reservoir. Poor isolation leads to poor matrix acid stimulation, higher skin and a higher risk of water production. To address this the operator sponsored an industry challenge to achieve reservoir isolation with cost and risk reduction and to deliver overall efficiency gains. Through dialogue between the Operator and a leading service provider in Open Hole Zonal Isolation, a solution was identified that would effectively replace the cement across the reservoir with a metal expandable annular sealing system. Time for delivery was a key driver to meet the drilling schedule and materialize the cost and risk reductions on the remaining wells. A scope of work was completed that included extensive qualification, manufacture and field deployment. The solution has proven to deliver benefits that address several fundamental aspects which were associated with the cemented liners: Substantial reduction in risk and cost associated with drilling the extended rat hole (shoe track) into the highly pressurized water zone (+/- 100mMD)Removed the risk and cost for the additional run to under ream the 6 ½″ hole to 7 ¼″ (low-ROP)Provided more certainty for zonal isolation whilst delivering effective acid stimulation and maintaining the low skin values. The technology has many different applications within wells where conventional cement is challenged beyond its capabilities and inherently not fit for purpose, due to factors such as well trajectory, hole geometry, reservoir uncertainty, downhole environment (pressure, Temp, ECD) etc. Within these environments, the technology developed for Moho North adds a proven solution to the Operators toolbox, a technology that is already finding alternate applications and planned deployments.

This paper presents the development, qualification and field trial of a novel well flow valve that delivers unlimited zonal selectivity in single skin lower completion without the use of control lines. Control lines have limitations and risks due to complexity during deployment, restrictions on the number of zones, complications with liner hanger feed thru and associated wet connects. It is desirable to remove the control lines whilst maintaining the functionality of multi zone, variable choke flow control. The well flow valve is a full-bore, reliable and robust mechanically operated sleeve, qualified in accordance with ISO14998 including multiple open/close cycles, at a sustained unloading pressure of 1,500 psi, with highly customizable flow ports. The need for such a solution was identified by an operator in West Africa. The well objective was elevated from a gas producer to a well that required the flexibility to produce gas or oil with gas lift capability. The well flow valve was selected and required on site variable choke capability for both oil and gas production, with choke position verification, ability to handle dirty gas production without risk of plugging, compliant with a high rate and high pressure proppant frac along with ease of operation and long term reliability. The field trial included a high pressure proppant frac in the oil zone. In the shallower gas zone, three well flow valves were used to deliver variable choking capability from maximum gas flow rate with minimal delta P adjusting down to a choke size suitable for gas lift. The well flow valves were operated using a high expansion shifting key conveyed on eline through the 3 ½" production tubing. The shifting key expanded in the 4 ½" lower completion to open/close individually all the well flow valves in a single trip. Incorporating this new product overcame the challenges presented and met the objective of commingled production of oil and gas. The well flow control valve demonstrated flexibility through design, supply chain, manufacturing, and operations. This paper will also outline the future road map covering further developments of the well flow valve and its incorporation into an enhanced flexible lower liner solution aimed at lowering well completion costs and risks.

The field is developed within a complex environment, located within deep water and operated from a TLP / FPU facility. The wells are targeting 2 reservoir structures at 4000m TVD, requiring long and deviated wells to achieve field coverage. The reservoir is highly laminated with complex lithology requiring approximately 3:2 producers to injectors. Existing lower completion design utilizes a combination of cement and metal expandable annular sealing technology, to ensure zonal isolation and annular sealing (liner to formation) during the high-pressure stimulation and to ensure sealing over the life of well for zonal water shut off requirements. The oil reservoir is located approximately 20m TVD above a highly-pressurized water zone, making the oil producers challenging to drill and cement. Existing wells were drilled with a long shoe track into the water zone creating a possible flow path for the water to migrate along the annulus if annular sealing is not achieved. As part of a global efficiency drive, the operator issued a challenge to the service industry, to reduce the DRILLEX of these wells whilst maintaining the beneficial productivity index that has been achieved within the highly heterogeneous carbonate field, being prone to asphaltenes. One of the implemented solutions was cement replacement across the reservoir. The benefits of this solution impacted several areas; it removed the need for drilling 100m of rat hole, under reaming of the 6 ½″ hole, clean out of the 6 ½″ hole and most significantly, eliminating cementing of the 4 ½″ liner. This led to a substantial cost savings and reduction of rig time and because it simplified the operations, the operational risks were also reduced. The scope of work to deliver the solution included the design, development and qualification of the metal expandable annular sealing system. The project included validation of both sealing and anchoring of the cement-less liner within the open hole. The solution was also required to maintain the synergies with the perforation, acid stimulation and diversion techniques to achieve the required Productivity Index (PI) and Injectivity Index (II). The first deployment was within a well that was converted from producer to water injector. This would help validate the technology for further deployment on oil producers. The lower liner with the metal expandable annular sealing system was deployed from the rig whilst the activation (expansion) and subsequent acid stimulation were completed offline. Production and injectivity data were analysed and compared to the PI / II to the prior cemented and perforated well designs. This paper will discuss the project scope of work, first deployment of the metal expandable sealing system, data analysis and an estimate of the risk and cost reduction delivered.

A producing well located offshore Congo was equipped with a TRSCSSV which failed to open. A velocity valve, with a stem beneath, had been installed to keep the flapper open. This condition, apart from restricting the production, was a temporary solution as defined in Eni's (the operator) well integrity policy; for this reason, the SSV had to be replaced. In order to do so, the completion needed to be removed, which implied cutting the cut-to-release packer. A lock open tool needed to be run in the SSV to allow the cutter to reach the packer. The lock open tool was too big to pass the tubing hanger. Eni issued a challenge to the service industry, to come up with a solution to enlarge the hardened tubing hanger while preserving its mechanical integrity. The solution also had to be deployable quickly as the drilling unit could incur costly standby. The retained solution used a wireline deployed milling toolstring equipped with a diamond coated bit. The benefits of this solution impacted several areas: the surface read out system allowed for fine control of the milling operation, the combinability of the tools allowed for adequate planning of potential fish recovery while retaining well barriers on a live well and the size of the equipment allowed for a rapid overseas mobilization. The milling operation was completed in a single run, with a total milling time of 1hr 47min. The paper will discuss the project scope of work, equipment preparation and job execution, an estimate of the risk and cost reduction delivered, and an estimate of the added production enabled by removing the failed SSV.