Predicting and assuring well deliverability is often an important concern during the development of gas-condensate reservoirs, especially offshore fields. In addition, production of gas is usually bound with long-term contracts where it is necessary to assure well deliverability for a long period. Undesirably, well deliverability in gas-condensate reservoirs can be impaired by the formation of a condensate blockage once the bottomhole flowing pressure drops below the dewpoint pressure. In this case, the relative permeability of the gas phase can be significantly reduced due to this condensate accumulation around the wellbore. Therefore, quantifying this negative effect is essentially required to obtain reliable predictions of well deliverability in gas-condensate reservoirs. The evaluation of condensate blockage phenomenon requires an appropriate understanding of flow characteristics of both gas and condensate liquid through reservoir rocks. In this study, the impact of condensate blockage on gas well deliverability was investigated by examining a number of flow parameters such as absolute permeability (K), critical condensate saturation (Scc), relative permeability shape and end-points (krgmax, kromax). A single well radial and cartesian models were both used in different simulators (modified black-oil and compositional). The outcomes of this study showed that the condensate blockage can have a severe negative impact at low permeability reservoirs (K≈5md), while the impact can be small at moderate permeability (k≈50md) and diminishable at high permeability reservoirs (k≈200md). This negative impact can double at high critical condensate saturation (Scc>30%). It was found out that the relative permeability curves applied in the model define the magnitude of the blockage, especially in low permeability reservoirs, whereas relative permeability end-points (krgmax and kromax) affect mainly the overall gas recovery. Previous lab measurements showed that gas-condensate relative permeabilities are sensitive to flow velocity only in low permeability reservoirs. This effect was modeled using a compositional model through the capillary number. Velocity-dependent relative permeability model applied in this case showed that the plateau period can be improved by a factor of two in low permeability. On the other hand, no positive effect was observed at moderate and high permeability since the blockage effect was already small or dimensionless. Finally, the benefit of methanol injection was investigated for improving well deliverability at low permeability reservoirs. Based on this analysis, methanol treatment can improve gas well deliverability and substantially prolong the plateau period by a factor of 2-3.

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For two wells, performing continuous N2 lifting in an offshore environment for weeks to produce a large quantity of aquifer water that had crossed into oil-bearing zones during a long shut-in period would involve high operational and logistical risks and require a large capital investment, which was not proven economical. As an alternative, a Rigless coiled tubing (CT) gas lift system, which uses gas cap energy, was chosen as an efficient, reliable, and cost-effective technique to revive oil production from the two offshore wells. The technique involved running CT inside the production tubing. The CT was then hung up on an additional tubing hanger installed on the production tree. The injection rate and injection pressure were supplied by a choke manifold connected to a gas well that had high wellhead pressure. The gas was injected down continuously through CT, which lifted the standing water in the production tubing annulus to surface. Production logging tools, simulation models, and flow performance applications were used to Estimate the volume of water crossed into oil-bearing zones Identify the time needed to revive the wells The CT gas lift system was found to be the most efficient and cost-effective way to revive production from dead wells. In this application, the free available energy of the only gas well in the field, which was drilled in the gas cap, was used to supply the required gas rate and injection pressure. The following steps were completed with the collaboration of all parties: Successful installation of CT in production tree via additional retrievable tubing hanger Gas pressure and gas rate supplied and controlled by a choke manifold Real-time support to guide the operation towards success Successful retrieval of CT when the operation was over As expected, each well took nearly 45 days of continuous lifting to reach the pre-estimated water cut for the wells to be self-lifting. CT was then successfully retrieved, and the wells continued flowing naturally with considerable rates. The oil rate gain for both wells was around 4,000 BOPD. This methodology has been approved and adopted by the operator for future similar cases as a cost-effective method to revive oil production from dead wells. The novelty of the technique comes from the utilization of gas cap energy in the form of high wellhead pressure of the only gas well in the field, which was drilled in the gas cap, as a source of injection pressure and injection rate. This innovative technique made reviving dead wells possible without changing wellhead configuration or investing in weeks of costly N2 kickoff operations.

Recompleting the wells with an artificial lift system requires a large capital investment in addition to rig intervention, a capital which was not made available due to worsening security condition in Libya in the period between 2014 − 2017, therefore, rig-less gas lift system via Coiled Tubing was chosen as the most efficient, reliable and cost-effective technique to revive oil production from 12 dead wells. The results of this pilot project were very satisfactory. The technique involves running coiled tubing inside the production tubing of a dead oil well, the coiled tubing is then hung over an additional special tubing hanger, made specifically for this project, fixed on the Xmas Tree. The gas is injected down continuously through a single point at the end of coiled tubing which is mixed with the oil in the production tubing annulus and helps lifting the liquid to the surface. Since compression system was not made available, due to cost cutting procedures implemented by MOG, the injection rate and injection pressure were supplied through a 2″ pipe connected to a gas well which had high wellhead pressure. Since the wells had been dead for a couple of years, there was a high uncertainty in the design due to the lack of fresh data, therefore, N2 lifting with downhole slickline gauges and surface testing were utilized to obtain reliable and fresh data for the final design. Since, the Coiled Tubing Gas Lift System CTGL technique was implemented in Libya for the first time, two wells among 12 dead wells only were selected for the Pilot project. The results of the two wells were satisfactory. Oil production from the first two wells increased significantly from 0 BOPD to 4500 BOPD, which increased the overall total field oil production by 100% from 4500 BOPD to 11,000 BOPD. Since the reservoir communication is extremely high, nearby wells’ production was positively impacted as well, and overall field production increased from 4500 BOPD to nearly 11000 BOPD in two months. The novelty of the technique comes from the utilization of the wellhead pressure of nearby gas wells as a source of injection pressure and injection rate which made reviving dead wells possible without investing in compression systems, seen as uneconomic for a pilot project.