There is a continuous need to improve hydrocarbon recovery efficiency especially from a brown asset, with a view to extending the life of the asset with reasonable operating cost in order to deliver sustained profit to the business. This is made even more imperative due to the dwindling crude oil prices and an operating environment with ever increasing challenges especially in the area of security, asset integrity, frequent deferment due to export line vandalism and crude theft, and community disturbances. All these factors result in most companies operating within the Niger Delta environment and by extension the country at large not being able to create robust production forecasts to support their annual business plans. In the end, actual annual average crude production ends up much lower in most cases than the projected plan. The big question however is: How do we build robust forecasting models that can better predict our business outcomes in the Niger Delta? This paper seeks to demonstrate the possibilities available within the Nigerian space, all driven and developed with indigenous capabilities, of how this problem was successfully solved for a major asset, operated by a leading indigenous Exploration and Production company through active collaboration with another leading indigenous Petroleum Engineering software solutions provider.

OML 18, operated by Eroton Exploration and Production Company (EROTON E&P) and located within the Coastal Swamp of Eastern Niger Delta contains several producing fields. As a brown asset with over 50 years historical production and ageing infrastructure, rapidly declining oil production caused by rising water cut and depleting reservoir pressure has become a normal feature for most of the reservoirs in the block. There arises therefore, urgent need to maximize the value of these mature fields by deploying fit for purpose and cost-effective technologies and methods. Thus, we deployed artificial lift technique using the abundant associated gas resources within the asset as one method of managing the rapid decline in oil production. Gas lift is a robust and inexpensive artificial lift solution which can be deployed at any period in the life-cycle of a well. The natural reservoir energy to move liquids to the surface through a well at expected rates declines with production time. Changing well and reservoir conditions, such as declining pressure, increasing gas liquid ratios and rising water cut can make consistent and predictable oil production a challenge. A review of the entire wells portfolio within the asset enabled an identification of all potential candidates with potential to benefit from gas lift installation. This was followed by feasibility studies to establish a connection between the magnitude of expected oil resources to be added, the oil rate potential, the existing completion status and surface facility equipment availability such as compression, gas lines and scrubbers etc. Screening of identified opportunities, often conducted in multi-disciplinary review sessions, yielded ranked list of opportunities for further maturation through design, execution and operation. Three (3) fields with over 60 wells and 38 developed reservoirs were selected for the review. The screening criteria included but not limited to reserves to be added, ease of execution, economics and regulatory approval requirements. Since these wells were not originally equipped with gas lift mandrel, alternative means of deploying gas lift equipment downhole had to be designed and implemented. Considering the advanced age of most of the wells, due consideration was given to well integrity in the final execution decision. Despite inherent challenges, EROTON was able to successfully deploy in-house technical knowledge and experience to embark on rigless well intervention campaign to restore production using retrofit gas lift equipment in existing wells, which have ceased to flow due to vertical lift issues, thus extending the life of the wells. We have successfully performed a safe and commercially viable production restoration exercise, returning a total of twelve (12) wells back to full production potential and achieving the well intervention objectives. The operation has accelerated production adding over 5,000 bopd. This paper will discuss the concept of brown field life extension through retrofit gas lift, the workflow utilized and results from select field examples. Well BAKU-07 in RAMA field is further discussed as one of the candidates successfully restored via this method.

With global Oil prices still recovering from the down cycle and coupled with high cost of drilling new wells, EROTON E & P has devised strategies to manage declining oil production, increase oil production from her existing assets and add new reserves through team integration and improved subsurface data management by using fit-for-purpose technology (cement packer) and other collaborative tools. Cement packer technology is a relatively fast-to-deploy and cost-effective rig-less intervention technique that allows easy access to hydrocarbon reserves behind pipe which are located above and between production packers in wells where the existing completion intervals have reached their economic limit. This technology can be used to separate a new zone earmarked for completion from other intervals including non-hydrocarbon zones. The cement plug is pumped into the allocated space to serve as an effective production packer. This becomes viable and economic option when the interval is above an existing parker. Cement packer activity can be carried out using a rigless unit with the benefit of significant cost savings while achieving seamless isolation of the production intervals. One example from the strings of successful cement parker operation, among a few others, is the CAAK-040 well in CAAK field. The well was drilled in 1988 and completed on X3050B and Y4050B reservoirs. Both intervals quit in 2001 at BSW above 80%. After the integrated subsurface evaluation using all available data including CO logging acquired across the existing and proposed completion intervals, CAAK-040 was proposed for a zone change. A rigless workover intervention of the well was executed and the production interval switched from Y4050B to C8000B reservoir on the new short string using cement packer technology to isolate Y4050B completion and recomplete in the new target sand. CAAK-040 did not flow after the cement packer and perforation operations were successfully executed and the well had to be lifted to production using a temporary gaslift system. Currently, the well is performing above the planned potential of 1500bopd from C8000B reservoir. This paper will discuss the lessons learnt and best practices from the cement packer and re-perforation of CAAK-040 using a rigless workover unit. There is continuous monitoring to ensure all approved company procedures and minimum standards are strictly adhered to. To date, we have a total of five (5) wells that have been recompleted and reserve added using cement packer. This activity has accelerated the production system unlocking of short-term oil generation (STOG) production of over 5,000 b/d of oil in one-year target. The average total cost of this operation is about 20-30% of a conventional workover. Thereby saving the company over $20m with added rewards of reactivating shut-in wells and producing reserves that were previously sub-economical and inaccessible.