Development options in marginal fields are sometimes limited, driven primarily by economics, license period, size of asset and regulatory constraints. The Operators objective is to economically develop the reserves from multiple zones with fewer wells, whilst maintaining mandatory reservoir surveillance and accounting. Intelligent or smart completions are at various level of maturity, depending on the well architecture, application, and measurement & control devices. The concept of using smart completions within the marginal field environment has historically been limited. The conventional completion practices in marginal fields with stacked reservoirs are mostly multistring or selective designs. A strong driver for smart wells in a marginal field is the desire for simultaneous exploitation of multiple reservoirs, lower capex (fewer wells), reduced opex, smaller footprints and effective zonal control. Remote zonal control is desirable, due to the locations accessibility, which makes intervention prohibitive and with increased health, safety, and environmental (HSE) risks. This paper will focus on the application of an intelligent completion technique in Okporhuru, a partially appraised field in the Niger Delta area of Nigeria comprising stacked reservoirs. The field is classified marginal due to limited data, low first pass initial oil volume and remoteness from production facilities, amongst others. This paper will detail the modelling technique, flow control valve (FCV) design philosophy, and requisite monitoring to meet target zonal flow contributions. Application of a compact, modular, multi-zonal smart completion solution (IZC), pre installation design, deployment considerations and production allocation methodology will highlight the considerations for selection of a unique sand control technique in this partially appraised field.

As the oil production of mature reservoirs declines and budget constraints continue to limit rig-based well interventions and infill drilling, the need for practical and cost effective methods of identifying and recovering remaining resources become increasingly essential. The Reservoir Surveillance Mapping (RSM) method, also referred to as ‘the poor engineer's simulator’, provides a result-oriented means of identifying and accelerating oilrecovery. This paper describes practical aspects of RSM efforts in a Niger Delta asset, that involved an integrated reservoir-wide management process with the objective of not only understanding subsurface dynamics during production but also delivering a future work programme for the asset's reservoir blocks.

This well was drilled and completed as a Frac & Pack oil producer with subsea wellhead in 3300 ft water depth. Despite all the care taken to maintain cleanliness during completion, initial performance on starting up the well indicated that it was severely impaired during the drilling phase with drawdown as much as 2300 psi observed. The well initially failed to reach the Hydrate Dissociation Temperature (HDT) of 35C within the specified period of 1 hour. The well was eventually successfully started and some performance improvement was observed as the well was cleaned up gradually over the next few months but the potential of the well had to be revised down from the planned 30kbpd to 12kbpd to honour drawdown limit of 350psi. This paper documents the effort made to restore the well's planned production of 30kbpd by acid stimulation treatment by bullheading from the rig. From the well history, the source of impairment was attributed to drilling fluids. Thus, a half-strength mud acid was chosen as the treatment fluid and the placement was by high-rate bullheading from the rig connected to the subsea Xmas tree via a riser and EDP/LRP. The risk of flowing unspent acid through subsea flowlines and topsides equipment on the FPSO was assessed. Corrosion simulation studies showed the subsea flowlines can withstand the possible unspent acid with proper dilution by flowing high water cut wells at high rate through the same bulk flowlines being used to unload the just treated well. The dilution also helped protect the topsides equipment while further protection was provided by injecting diluted sodium hydroxide into the flow stream as it enters the topsides. The result of the treatment was that productivity index increased by a factor of 3 from 27 bpd/psi to ca. 90 bpd/psi and the well is now producing at 30 kbopd.