Oil reservoirs developed under a natural depletion scheme usually leave behind a significant portion of the discovered oil and while in-fill drilling is a logical choice to recovering more oil from these reservoirs, there is always the challenge of locating the remaining oil and optimally placing new wells within these ‘sweet spots’. 3-Dimensional (3-D) dynamic modelling and 4-D seismic are well developed methods of establishing post-production saturation distributions and a combination of both methods further increase the confidence of the post-production saturation distributions predicted. Even then however, these methods are not infallible. Experimental design methods when integrated into dynamic modelling enable a logical and systematic interpretation/utilisation of all available data to understand the extent and impact of uncertainties, an understanding which can help make robust decisions about these re-developments. The reservoir of interest (Level 1X) is an oil rim reservoir with a 36-year production history from 6 wells. All the existing completions in the reservoir were used to develop the oil-rim. To evaluate the option of developing the gas cap of the reservoir, a technical review of the oil rim had to be carried out to assess the existing developments and evaluate the possibility of further development opportunities in the oil rim prior to the gas cap blow down. Over the area of this field, 4-D seismic was not available and while the traditional dynamic reservoir modelling method could be used to plan further development, the oil rim nature of the reservoir coupled with reservoir uncertainties (such as oil-water and gas-oil contacts) meant a second method would give further credence to any analyses of the reservoir and the proposals resulting from such analyses. This paper demonstrates how experimental design, incorporated into dynamic simulation, has been applied to the reservoir study to achieve the following: Integration of practically all data into the study (not a pre-selected value for each uncertainty) Allowing available data to guide the history match of the reservoir (History matches evolve/drop out of data) thus increasing confidence in the calibrated (low, mid and high case) models. Allowing a selection of a high confidence case re-development strategy.

Well A (offshore field) was drilled in June 2002 to provide horizontal drainage point on the reservoir. It was completed as a Single String Single (SSS) Producer with 3 ½" tubing string. The sand face was completed with 5 ½" slotted liner (SL) with screen size of 300μm for sand control across 1, 505ft horizontal drain hole since the reservoir is unconsolidated. The interval started production in May 2003 and was closed-in for about a year for pipeline changeout due to pressure integrity before it was shut-in for security concerns. Thereafter the well produced uneventfully until sand production in excess of 10pptb (Pounds per thousand barrel) was observed. Various mitigation efforts were deployed however, all proved abortive. The platform tripped due to the rupture of the well choke body and this was traced to be caused by excessive sand production. The interval was subsequently closed in due to high sand production. Various options were looked into to determine the best solution that could be used to eliminate the sand production challenges, this ranged from insitu reservoir sand consolidation, horizontal gravel packing, rig re-entry to workover the completion and Thru-Tubing Sand Screen Insert to restore the completion integrity. However after various review sessions, Thru-Tubing Sand Screen Insert was recommended as the best option for the well because it was the most cost effective option, there are good premium screens and in-house expertise exists to aid its deployment. This was followed up with detailed sieve analysis of the produced formation sand and ditch cuttings for proper screen design. Furthermore, well modelling was done to predict the new well potential after the screen insert and was estimated at 2, 250bopd. In this paper, we present the technique utilized for rejuvenating a horizontal completion in July 2013. 500ft Techdaer-ENFORCER Premium Screens (230micron) was successfully spaced out with 900ft blank tubing and installed inside the top section of the 5 ½" SL and hung off on the production tubing with the Paragon Packer. This was achieved using a Coil Tubing mounted on an offshore Self Elevation Workover Platform (SEWOP) after the well was cleaned up and killed, making it a first in Shell Nigeria. Thereafter, production was restored at low sand cut of < 2pptb, at an average oil rate of 2, 400bopd since August 2013 till date, thereby safe guarding 2.5MMbbls of reserves and 2, 400bopd potential at acceptable sand production. Using a conservative oil price of $85/bbl, the total project cost which was $1.8Mln was recovered in 9days. So far the well has been on production since August 2013 with a cumulative oil production of 0.6MMbbl to date.