fax 01-972-952-9435. AbstractGeoscientists and reservoir engineers are very well acquainted with the terms "net-to-gross (NTG)" and "petrophysical cut-offs" or just "cut-offs". The significance of these terms is ultimately to define productive zones in the reservoir for hydrocarbon exploitation. However, there has been marked misunderstanding surrounding the usage of the term, net-to-gross and implicitly, the derivation of cut-offs which are limiting values used in expressing the netto-gross ratio. While the geologist may be concerned with the pay for evaluating hydrocarbon-in-place and the ultimately the estimation of economically producible reserves, the simulation engineer is more concerned with fluid flow for pressure support in the reservoir 1 . The significance of this paper is to consider the different cut-offs selection methods, the varying interpretation of net-to-gross ratios and the implications inherent in such methods. A case study from a field in the NigerDelta is also carried out to reveal the impact of such selection criteria especially in rocks with congenital weak hydraulic properties which cannot be excluded at geologic correlation stage 2 . The effect of cut-off parameters on oilinitially-in-place (OIIP) calculation was also investigated and a sensitivity analysis carried out on the petrophysical parameters to reveal the impact of the dynamically conditioned cut-offs selection on the petrofacies. Multiple Monte Carlo realizations were also employed to obtain probabilistic OIIP estimates rather than a single deterministic result.

In order to make effective decisions for oil field management, well and reservoir surveillance data needs to be utilized to better understand how the subsurface and surface systems in a field interact. This can be done at the reservoir, well and surface facility level, but is most effective when considering the entire production or injection system. IPM (Integrated Production Modeling) is now being used more often and, has demonstrated its usefulness in many oil and gas field applications. The use of integrated production modeling methodologies for improving production, identifying and eliminating bottlenecks and improving production allocation for wells from multiple reservoirs from both onshore and offshore oil fields are presented. Methods for coupling the surface and subsurface are reviewed and its usefulness for identifying bottlenecks at both the well and surface facility level are demonstrated. Field examples are presented where issues were identified and overcome by operational means and, found to increase production. Prioritization of wells and production intervals can also be incorporated to improve production/system uptime and field life. The use of artificial lift for oil wells and additional compression for gas wells can be effectively modeled by reasonably calibrated IPM models. Without proper calibration, these models can yield results that lead to inadequate decisions that have a significant impact on project economics. The use of IPM models as a tool to better allocate field production data has proved to be very reliable and has resulted in better field management. This approach requires both reservoir and surface facility information gathered on a regular basis in order to be reliable and accurate. Reservoir, well and surface models require occasional calibration or updates of inflow type curves. Application of these methods are discussed and presented for some field cases for oil reservoirs some under waterflood and others with active water drive.

Summary Maximizing oil recovery in thin and ultrathin (less than 30 ft) oil columns is a challenge as a result of coning or cresting of unwanted fluids into the wellbore in both vertical and horizontal wells. There is considerable oil left behind, above the well completion in the reservoir. This may also occur in horizontal wells when bottom- or edgewater encroachment or invasion takes place. The development of the gas resources from these reservoirs is a major challenge because regulators want an optimal development plan for the oil rim before project approval is made. This can delay upstream gas supply to liquefied-natural-gas (LNG) projects and grind down project value. A smart development strategy has been proposed for the development of these challenging reservoirs. This involves the use of intelligent multilateral wells in simultaneous oil and gas development; the first (top) horizontal-lateral-well legs of the multilateral well will be completed at the crest of the reservoir in the gas cap. The second (lower) horizontal-lateral-well leg will be completed just above the gas/oil contact (GOC). Extensive numerical reservoir-flow simulation has been used to demonstrate the ability and possibility of using a single wellbore for simultaneous oil and gas production. This proposed development strategy will provide high impact on the asset of such oil and gas reservoirs by providing a cost-effective-technology solution. The numerical-simulation results show that the intelligent multilateral well will significantly improve the overall cumulative production of gas and oil from a thin oil reservoir with a large gas cap compared with conventional wells and also provide the opportunity for automatic gas lift for low-gravity crude (°API). This paper (1) presents the use of intelligent multilateral wells to produce oil and gas from the same wellbore simultaneously in the thin oil reservoir and (2) provides information on the delay and reduction of excess production of unwanted fluids (water) during oil and gas production from thin oil reservoirs using intelligentwell technology, including cost effectiveness.

Maximising oil recovery in thin and ultra-thin (<30ft) oil columns is a challenge as a result of conning or cresting of unwanted fluids into the wellbore in both vertical and horizontal wells. There is considerable oil left behind, above the well completion in the reservoir. This may also occur in horizontal well when bottom or edge water encroachment or invasion takes place.The development of the gas resources from these reservoirs is a major challenge as regulators want optimal development plan for the oil rim before project approval is made. This can delay upstream gas supply to LNG projects and grind down project value. A smart development strategy has been proposed for the development of these challenging reservoirs. This involves the use of intelligent multilateral well in simultaneous oil and gas development; the first (top) horizontal lateral well legs of the multilateral well will be completed at the crest of the reservoir in the gas cap. The second or lower horizontal lateral well leg will be completed, right above the gas-oil contact.Extensive numerical reservoir flow simulation has been used to demonstrate the ability and possibility of using a single wellbore for simultaneous oil and gas production. This proposed development strategy will provide high impact on the asset of such oil and gas reservoir by providing a cost effective technology solution. The numerical simulation results show that the intelligent multilateral well will significantly improve the overall cumulative production of gas and oil from a thin oil reservoir with large gas cap as compared to conventional wells and also provide opportunity for auto gas lift for low API gravity crude. This paper presents; i) the use of intelligent multilateral wells to simultaneously produce oil and gas from the same wellbore in the thin oil reservoir and ii) provide information on the delay and reduction of excess production of unwanted fluids (water) during oil and gas production from thin oil reservoir using intelligent well technology including cost effectiveness.

Production ramp-up from aging assets poses several challenges, substantial oil gains and attendant learnings. The scenario for OML-42 was complicated by prolonged production shutdown, associated wells and facility vandalization occasioned by over nine (9) years shutdown by the former operator. Most wells were illegally operated and mis-managed by oil saboteurs during the nine years shutdown. On acquisition of OML-42, the new investor conducted sequential field Re-entry activities, facilities repair, wells revamp and aggressive production ramp-up campaigns in the fields within OML-42, to minimize Re-entry cost, optimize production and profit. This paper focuses on production ramp-up initiatives deployed in OML-42 fields to grow production from a pre-reentry rate of50kbopd to 70kbopd, without any rig-based activity. It also elaborates unfamiliar difficulties and learnings derived from the ramp-up campaigns.