There are quantum literatures, technical papers, etc on water management in the oil and gas industry. It is a very wide issue and with significant interest due to cost and environmental implications. The focus of this paper is water management in relation to oil production with the purpose of given the industry professional an all-round understanding of life cycle water management. Since by nature the oil is layered above water and the most common reservoirs drive mechanism is underlying aquifer (water), water production is therefore inherent in exploitation of oil. The impact of water in oil production could be good, bad or even ugly. This paper will discuss the various water management techniques from the drilling phase, through completion, production, transportation and treatment at processing facilities. Though basic, this is substantially fundamental. An improper management during any of the phases could prove very costly down the road to the promised developed ultimate recovery for a well completion and even overall recovery from the reservoir. With water production, comes the associated cost of water processing and disposal. It is the view in this paper, that practices and technology should be deployed to delay and minimise water production where appropriate. In today's lower oil prices for longer world, the industry must always strive to reduce their UOC (Unit Operating Costs) to remain profitable and competitive. There are published estimates of water handling costs being as high as 50 cents per barrel of water produced. Reduction in this cost will surely impact the operating company bottom-line. Though there are extensive literature that addresses specific challenges with water management in discrete phases of operation, this paper will attempt to provide a life cycle view, hence its uniqueness. It also highlights practical solutions that are tried and tested.

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.

The importance of Wells, Reservoir, and Facility Management in the life of producing Oil and Gas assets cannot be overemphasized. Several authors in the past have highlighted the significant contributions WRFM practice and process have to the ultimate recovery of matured assets. WRFM serves as a stop-gap to redevelopment in areas of cash crunch, whereby active WRFM practice arrests severe natural decline in production. Onshore assets comprising of fields Alpha and Beta are operated by Shell Petroleum Development Company (SPDC). These assets have been operated for over 30 years, rising water cut & high gas-oil ratio production and facility downtime risks have impacted oil recovery. This work showcases the application of WRFM at the re-startup of production in these fields post shut-in for almost 5 years. Effective and deliberate application WRFM processes and practices woven together in the WRFM Plan not only ensure an efficient restart of the facility but the ability to ramp production while maintaining the intricate balance of good reservoir management. The paper will highlight the best WRFM practices which enabled the resumption of production at a lower water rate compared to when the field was shut and maintain this higher net oil for a prolonged time. Also highlighted are opportunity identification and implementation in-closed wells and effective collaboration across disciplines to ensure a safe and efficient restart of production facilities.

The benefits of credible data and data quality came to bear recently with the restoration of reservoir production in an SPDC field. The reference string produced dry at an average rate of 1500 bopd and Gas Oil Ratio (GOR) of 2000scf/bbl till June 2000 when water breakthrough occurred. GOR increased sharply by 2011 and the interval was closed-in in 2012 at GOR of 8Rsi (Rsi-initial solution gas oil ratio). A previous integrated review proposed water shut-off (WSO) as well as gas shut-off (GSO) to be executed so that this interval can be brought back on stream. In September 2015, an integrated review of Closed-in Wells was done in which all available data pertinent to this well was analysed and reviewed. Based on this comprehensive data, the review team arrived at a conclusion to open up and test the well rather than WSO/GSO proposed in the previous review. In making this decision, the team was convinced it had access to credible and reliable data set. This is enabled with the creation of The Asset Standard Well Reservoir and Facility Management (WRFM) Technical Data Management Plan (TDM) that clearly states data repositories, data owners and focal points. These data sets were easily retrieved from the various data repositories. The Asset Standard Well Reservoir and Facility Management (WRFM) Technical Data Management Plan (TDM) clearly states data repositories, data owners and focal points. The string was opened on October 25, 2015 and it was observed to be stable and flowing at 435 bopd, in line with the review forecast. Well testing of October 29, 2015 validated the production rate at 462bopd, 700scf/bbl (1.6*Rsi) at 27% BSW. The availability of credible and trusted data has therefore helped in optimising production of this well. There is also a cost saving typical of a water shut-off activity. Credible data that are easily accessible can make a difference on the business bottom line especially in optimising production, managing integrity and emergency repairs of an asset. These were demonstrated in the closed-in well review that has led to increased production and cost savings – the benefits of credible data.

The evaluation of hydrocarbon in-place volumes in any reservoir depends principally on structural uncertainty, fluid contact as well as rock and fluid properties distribution. This paper focuses on integrated approaches used to estimate hydrocarbon in-place volumes in a reservoir with very limited well spread. This study highlights the importance of carrying out further studies on our brown fields to re-evaluate the earlier estimated hydro-carbon Inplace volumes and its ultimate recovery by integrating historical information (performance data etc) and emerging development plan. About five wells have been drilled in the field and their penetrations are restricted to the eastern flank of the reservoirs. Well test data exist in some of the reservoirs and continuous BHP data were also taken in most of the producing reservoirs. The Mangu field reservoir ‘A’ has over 10 years of production (with limited well spread and few producers). It has produced more than the initially estimated ultimate recovery, over 85% of its initially estimated in-place volumes. Hence the integrated technical team decided to to re-evaluate the in-place using performance-based information and re-evaluation of the expected ultimate recovery (Buckley Leverett Approach). The determination of hydrocarbon in-place volumes in Mangu field was also premised on the re-estimation and prediction of rock and fluid properties variation away from area of well penetrations. In order to determine the average reservoir properties and their associated uncertainties as well as their use for in-place volumes estimation, multidisciplinary approaches have been applied and they include (a) evaluation of well by well logs & rock properties (b) generation of reservoir property maps (c) analysis of pressure and performance data and (d) Static/Dynamic modelling and (e) Determination of Recovery Factors using Buckley Leverett approach and use of Decline Curve Analysis. The result of this study highlights the significance and impact of limited well data spread and its associated uncertainties on reservoir in-place volumes estimation and ultimate recovery determination. An integrated approach has helped to significantly reduce the uncertainties associated with in-place volumes estimation in the Mangu field thereby leading to a commercially viable and timely Field Development Plan.