Gas condensate reservoirs below dew point pressure have been the subject of many studies in the petroleum literature. These studies investigated the impact of the resulting liquid condensate drop-out on well performance and concentrated mainly on reservoirs with homogeneous behaviors. This paper focuses on the effect of condensate drop-out in naturally fractured carbonate reservoirs with double porosity behaviors and on the changes in well test responses due to changing oil/gas relative permeabilities. Specifically, this paper examines the impact on the storativity ratio (?) and the interporosity flow coefficient (?) below the dew point pressure as the radius of the condensate bank increases away from the wellbore. By generating well test responses under different operational well conditions below the dew point pressure, the paper shows that ? decreases due to two-phase flow in the reservoir, whereas w shows very little change. The condensate bank appears as an additional skin effect, as in reservoirs with homogeneous behavior. This skin can be removed temporarily by hydraulic fracturing. Conclusions of the paper are verified with well test data from a carbonate formation in the Middle East and compositional simulation models. Introduction and background Condensate drops out around the wellbore in gas condensate reservoirs when the well bottomhole pressure falls below the dew-point pressure. This has a negative impact on well productivity. Many mega-reservoirs worldwide are affected, such as the Karachaganak field in Kazakhstan, the Cupiagua field in Colombia, the North Field in Qatar, and the South Pars field in Iran. Consequently, many studies have been conducted since the 1950's to understand the behavior of gas condensate reservoirs below the dew point pressure and to identify the main controlling parameters. Reservoirs are usually depleted under isothermal conditions as shown in Figure 1. In gas condensate reservoirs, this changes the fluid from single phase to multiphase in the near-wellbore region, creating three different mobility regions in the reservoir as schematically represented in Figure 2. Away from the well, where the pressure is still above the dew point pressure, only gas is present, with the initial condensate saturation (Region 3). Closer to the well, in Regions 1 and 2, the pressure is below the dew point pressure and the condensate drops out of the gas phase. In Region 2, the condensate saturation is below a critical value and the condensate is not mobile. In Region 1, on the other hand, the condensate saturation is above critical and both gas and condensate are mobile and flow together into the wellbore. Regions 1 and 2 are referred to as the condensate bank, and the decrease in gas effective permeability resulting from the existence of this condensate bank can have a significant impact on the well performance. The condensate saturation actually decreases and gas mobility increases in the immediate vicinity of the wellbore, due to capillary number effects (also called velocity stripping, velocity coupling, or positive coupling), which creates a forth mobility region. These four mobility zones create a three-region composite behavior in a well test (Gringarten et al., 2000). This composite behavior is superposed on the well reservoir behavior above the dew point pressure (Gringarten et al. 2006).

Well placement and trajectory planning is a critical and challenging task in any Oil & gas field development plan. This has always been a task that requires a strong team effort to ensure the best predictions and estimations are performed to penetrate the desired reservoir development zones and achieve the expected production rates. Numerous iterations with a high level of interaction between Reservoir Management, Reservoir Simulation, Reservoir characterization, Geology and Geophysics are expected when planning a new well or a difficult sidetrack. Each member of the well planning team has his/her own environment along with dedicated standalone software tools. Today, with the introduction of the Intelligent Field center to provide the collaboration environment for the involved expertise along with the proper tool to offer a strong integration of different data sources in a single software environment that allows a team of field geologist, geophysicist, reservoir and simulation engineers to evaluate the best prospects available in planning any new drilling opportunity, furthermore the team is able to choose the best well azimuth and inclination based on reservoir properties and performance. This paper discusses a newly integrated well planning process utilizing a collaboration environment to review seismic, well log cross sections, historical production and simulation predictions enabling the well planning team to place their gas wells using a reservoir 3D viewer, incorporating the reservoir simulation model, and run various cases and sensitivities. In This paper, full examples illustrate how effective software integration can optimize the time required to plan a new well without overlooking any important aspect. In addition, the paper discusses the lessons learned from this experience and how this approach changes the mechanism of an integrated well planning team working together.

Well placement and trajectory planning is a critical and challenging task in any Oil & gas field development plan. This has always been a task that requires a strong team effort to ensure the best predictions and estimations are performed to penetrate the desired reservoir development zones and achieve the expected production rates. Numerous iterations with a high level of interaction between Reservoir Management, Reservoir Simulation, Reservoir characterization, Geology and Geophysics are expected when planning a new well or a difficult sidetrack.Each member of the well planning team has his/her own environment along with dedicated standalone software tools. Today, with the introduction of the Intelligent Field center to provide the collaboration environment for the involved expertise along with the proper tool to offer a strong integration of different data sources in a single software environment that allows a team of field geologist, geophysicist, reservoir and simulation engineers to evaluate the best prospects available in planning any new drilling opportunity, furthermore the team is able to choose the best well azimuth and inclination based on reservoir properties and performance.This paper discusses a newly integrated well planning process utilizing a collaboration environment to review seismic, well log cross sections, historical production and simulation predictions enabling the well planning team to place their gas wells using a reservoir 3D viewer, incorporating the reservoir simulation model, and run various cases and sensitivities. In This paper, full examples illustrate how effective software integration can optimize the time required to plan a new well without overlooking any important aspect. In addition, the paper discusses the lessons learned from this experience and how this approach changes the mechanism of an integrated well planning team working together.

During 2008-2009, Saudi Aramco recorded two major nonassociated gas field discoveries in the Arabian Gulf. The initial plan was to develop both fields with deviated extended reach 7" completion wells, which will be drilled from multi-well platforms. Based on the challenging subsurface conditions of the problematic highly fractured shallow horizons, in addition to the thick, highly fractured, and excellent carbonate Khuff reservoir quality, the decision was carefully made to develop both fields with vertical large bore wells completed as monobore with 9⅝" pre-perforated uncemented liner across the pay zone and 9⅝" production tubing to the surface. The large bore wells are planned to be drilled from single-well platforms that can be strategically located around the two fields to allow efficient spacing and depletion to produce initial gas rates up to 300 MMscfd per well.The large bore well design has a potential for maximizing the gas production from each well and reducing the overall field development costs down by 45% by minimizing the number of wells and facilities required without jeopardizing the production, safety or integrity of the development projects.The shallow horizons in the newly discovered fields, along with the targeted Khuff reservoir, are considered to be highly faulted structures with many associated fractures that can continuously cause drilling problems with lost circulation and differential sticking. The newly planned vertical large bore wells tend to reduce drilling problems. Nevertheless, those planned vertical large bore wells are still capable of producing the required high gas rates.The intent of this paper is to highlight the multiple challenges faced during the early exploration and delineation phase of the fields and to share the experience of planning new offshore field development strategies for large bore wells with high reservoir temperature and pressure (T&P). Transforming from the original development plan to the optimized large wellbore completion plan, takes advantage of the excellent reservoir quality and high flow capacity, allowed for many optimization efforts. Such optimizations have changed the entire project strategy to accelerate the official onstream startup date without any compromises.

No abstract