Gas-condensate reservoirs suffer losses in well productivity due to near wellbore condensate dropout when the flowing bottomhole pressure declines below the dew point pressure. To alleviate the problem, pressure maintenance and gas cycling are common practices for developing gas condensate reservoirs. A study has been conducted to investigate the applicability of one-time produced gas injection in removing the condensate bank around the wellbore and thereby restoring well productivity. The study focused on two major issues: the optimum time of commencing gas injection and the optimum volume that will remove the condensate bank permanently and restore well productivity. The practice will accelerate the production rate per well and maximize the ultimate hydrocarbon recovery. Three gas-condensate fluid samples with maximum liquid dropout in the range of 6 %, 11 %, and 21 % were used. The benefit of the method was investigated using a full-field compositional reservoir simulation model of a gas condensate field. Reservoir simulation results indicated that, for the lean gases, the best time of starting the gas injection was when the average reservoir pressure around the producing well fell below the maximum liquid dropout pressures. For the rich gas, however, gas injection starting at average reservoir pressure above the maximum liquid dropout pressure resulted in better recovery. The study showed that one-time gas injection not only restored the well productivity and increased reserves but also accelerated the recovery process. These findings bring a different perspective to the development and management of gas condensate reservoirs. Introduction The productivity of wells in gas condensate reservoirs often decreases rapidly as the reservoir is depleted. The decrease is ascribed to a ring of condensate around the wellbore that grows with production time. The ring develops because the flowing bottom hole pressures drops below the dew point pressure of the reservoir gas1. Simulation studies and laboratory studies have indcated condensate saturation near the wellbore as high as 70%. A number of independent investigations have consistently shown that liquid dropout around the wellbore has been the primary reason for losses in well productivity. The presence of liquid around the wellbore reduces the effective permeability to gas2–5. The condensate occupies the gas flow channels and thus impedes gas flow6. The aim of this study has been to assess the impact of a once-off injection of gas in removing the condensate bank and reclaiming well productivity. Whilst condensate dropout translates into losses of revenue due to valuable hydrocarbon components being left in the reservoir, the main focus of the well intervention method is to restore productivity and increase recovery of gas. Single well models have been useful in understanding the phenomenon of condensate dropout or, indeed, in assessing the impact of remedial actions. Nevertheless, they still come short of accurately predicting behaviour on a full field scale. Most single well models are homogeneous or have simplistic reservoir properties and dimensions, in exchange for short simulation time and less complexity in setting them up. In this study, the proposed method was tested on a full field model of a North Sea field. Key questions pertain to timing of the initiation of the gas injection in the life of the reservoir and to determining the gas volumes to achieve maximum benefit. The study was also aimed at establishing the range of applicability of the method by investigating gas condensate fluids with a range of maximum condensate dropouts.
This multi-disciplinary study involved the use of parallel simulation using the same grid size as the geological model. Various production technology options for the remaining wells in a field development were investigated and the benefits of gas cycling were examined. A geological model covering an area of 40 km2 was simulated using two approaches; one using 3 levels of nested LGR's and the other using an areal upscaling, both had nearly the same number of active grid cells. The 12-component Equation-of-State ("EoS") was substituted by 5-component to optimise the run speed of the simulation, 12-component was used for investigating gas cycling. The final engineering model had 320,000 active cells and completed 1.5-year history-matching runs in 1 hr 27 min using 16 parallel 400MHz processors with 1GB RAM each. Both methods worked well and the history was matched with minor changes to the geological model. The primary match parameters were the relative permeability curves since relative permeabilities from special core analysis at reservoir conditions were not available. Correlations from the literature were used for the original relative permeability curves. These were modified to capture the effects of near-well velocity stripping by ‘straightening’ the curves and moving the end points. Through a combination of local grid refinement (LGR) and relative permeability modifications, the effects of the condensate dropout near wellbore and the transient effects were captured. These effects reduce the wells' productivity by 40% in the first weeks of production. In the prediction phase the full field model was used to examine, holistically, the effects and interaction of various options chosen by analytical screening. The main solutions compared were high angle (near horizontal) reservoir penetrations and hydraulically fractured wells. Hydraulic fractures were modelled using LGR to capture the behaviour of the condensate in the fractures. The high angle wells were surrounded by LGR. A large number of prediction cases were run, optimising the development scenario using stochastically derived drilling schedules. Considerations of capital allocation led to the final recommendation from the group of optimal solutions. Introduction The Field consists of two main areas; the subsea gathering centre producing from two layers, and the platform area producing from a further three main layers. The wells in the platform area suffer from a considerable loss of productivity, up to 40%, during the first few months of their producing lives. This loss is attributable to the transient effects and the formation of a condensate bank around the wellbore. At the beginning of the study 14 platform wells were on production; two had been hydraulically fractured and one high angle well (HAW) had been drilled. The fractured wells had not been produced due to facilities constraints and the HAW expressed lower productivity than expected. The subsea area was not included in the study as it is of generally better reservoir quality and consequently does not suffer from the loss of productivity in the early production life. The objective of the study was to develop productivity improvement solutions for four type wells representing the Platform Area. The well types are as follows:the main area: good permeability, three layers; no gas water contactwestern well: low permeability, one layer, far away from the platformnorthern well: two main layers, low permeability, overlaying a high pressure shaleeastern well: one better layer; one lower quality layer with GWC. Previous work had concentrated on well level solutions; in this study the overall impact of the solutions on the field was investigated. Before embarking on massive reservoir simulation, an analytical screening study was performed to identify the future well types. The idea was to perform minimum simulation runs to optimise the field performance.
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