The primary focus of a wells, reservoir and facilities management team is to guaranty shareholders value by improving production and optimize recovery. Several best practices abound in the industry to achieve this goal. Some screening criteria are used during integrated field reviews to benchmark identified opportunities and rank/select viable candidates for execution. This screening criteria includes: economic ranking, reserves, doability and regulatory policies. The resulting unconventional study allows for a better reservoir management plan. This paper presents an integrated methodology utilized to restore oil production for a brown field via gaslift project. This was applied in the NAMUB Field case and the information obtained can be applied on other fields with similar scenarios. In the case of NAMUB field, the estimation of the incremental oil resource volume was estimated using Material Balance models that are calibrated with pressure data and history matched. The field did not meet up with conventional screening criteria for Gaslift Project. This is due to technical, non-technical and economic reasons. The field studied is composed of stacked reservoirs that have not had oil production for about ten years. Therefore, it was pertinent that a project had to be executed to restore/ carry out oil rim development. This was further made expedient due to the gas cap blowdown of the reservoirs. The continuous gas development impacted on the recovery of oil and further eroded oil resource volume. This integrated study comprised of Surface Engineering disciplines, Petroleum Engineering/ Geoscience disciplines, Economists and Business Planners. The outcome of inter-reservoir communication studies and sensitivity analyses was integrated to manage uncertainties leading to robust outcomes. The results obtained were not benchmarked against any previous one, as this was a unique step out scenario the company had to deal with. The performance of the 5 wells will be monitored against actual production to validate the methods and processes adopted in this study. The integrated approach used in the study across the diverse disciplines allowed for seamless delivery of the project.

Oil metering is the determination of the quality and quantity of well effluent produced, transferred, delivered or sold. This volume of oil must be measured accurately since it determines the amount paid for oil and gas transaction, royalties and taxes. Measurement of oil and gas, purchases and deliveries is made on a flowing well effluent stream. Hence, flow measurement is paramount in the oil and gas industry. Engineers always check to ensure that the well effluent production rate corresponds with a good reservoir management by flowing the oil and gas well through a choke size that would prevent gas cuspling; this is usually done by monitoring the hydrocarbon well stream flow rate at the flow station after well stream fluid separation. To ensure that the volumetric and flow rate readings obtained from meters are accurate and do not impact negatively on the overall economics and operation of a company, meters have to be proved regularly. This is a procedure required to determine the relationship between the true volumes of well effluent measured by a meter and the volume indicated by the meter. For example an error of only 1.0 % in the measurement of well effluent in a pipeline delivering 300MMcfd of gas and 400 barrels of oil at $1million per year can lead to many losses to either the seller or to the purchaser. Therefore, this study is aimed at modeling a meter factor for proving and calibration of on-line meters. . The developed meter factor model will enhance effective meter factor computation to compensate for temperature, pressure and volume of well effluent and steel in custody transfer units(CTU) based on API standard. inaccurate measurement of well effluent will exposed a company not only to the risk of large financial losses, but also manpower constraints.

Production system optimization is one of the key ways to derive value from existing assets and ensure optimal field development, by integrating all aspects of the production system from the subsurface to the surface networks. Over the years, various tools have been developed in the industry to aid complete system performance analysis and optimization. In most cases, the scope of optimization is limited to the as built fixed assets which often has limited scope for economic modification in the late life of the asset. Additionally, commingling compatible reservoir fluids using intelligent wells has been identified as a viable means of developing marginal stacked reservoirs, which are otherwise uneconomical if conventional development options are considered. Cosby field which is a prolific field in its late life, had been closed in for over 10 years due to asset integrity and subsequent flowline vandalization. The wells are completed mostly as Two String Dual or Multiple producers to target the stacked reservoirs. Field re-entry campaign provided an opportunity to optimize the approach to field development and bring in the wells which had been closed-in. However, the prevailing completion philosophy required each string to have dedicated flowlines ranging from 3000- 9000 ft. This is to convey the fluids from the well to the flow station; hence each interval had to meet an economic criterion to ensure competitiveness. This paper posits a "beyond blind spot" concept identified for the late life re-entry and optimization of the Cosby field oil wells; by identifying suitable candidates for surface fluid commingling using well and reservoir performance reviews and Integrated production system model as tools. This concept, which aligns with the competitive drive within the E&P industry, delivers a facility cost savings of ca. $2.24 million, and allows an economic potential addition of ca 1.5Mbopd and resource volume of ca. 5.2 MMstb to be safeguarded.

This paper documents the results from a SPEI survey that was distributed in October 2017 to gauge the members’ Softskills needs and preferences. We received approximately 1100 responses from 72 countries. This paper shows the survey statistics and shares the actions the SPEI Business Management and Leadership Committee (BML) (previously known as the Softskills committee) will consider in response to the survey results.

Often, the production of oil and gas from underground reservoirs is accompanied by produced water which generally increases with time for a matured field, attributable to natural water encroachment, bottom water ingress, coning effect due to higher production rates, channeling effects, etc. This trend poses a production challenge with respect to increased OPEX cost and environmental considerations of treatment/handling and disposal of the produced water considering the late life performance characterized by low reward margins. Hence, produced water management solutions that reduce OPEX cost is key to extending the field life whilst ensuring a positive cash flow for the asset. SK field is located in the Swamp Area of the Niger Delta, with a capacity of 1.1Bcf gas plant supplying gas to a nearby LNG plant. Oil and gas production from the field is evacuated via the liquid and gas trunk lines respectively. Due to the incessant tampering with oil delivery lines and environmental impact of spillage, the condensate is spiked through the gas trunk line to the LNG plant. Largely, the water/effluent contained in the tank is evacuated through the liquid line. Based on the availability of the liquid line (ca. 40%-60%), the produced water is a constraint to gas production with estimated tank endurance time (ca. 8 days at 500MMscfd). This leads to creaming of gas production and indeed gas deferments due to produced water management, making it difficult to meet the contractual supply obligation to the LNG plant. An interim solution adopted was to barge the produced water to the oil and gas export terminal, with an associated OPEX cost of ca. US$2Mln/month. Upon further review of an alternate barging option, this option was considered too expensive, inefficient and unsustainable with inherent HSSE exposure. Therefore, a produced water re-injection project was scoped and executed as a viable alternative to produced water management. This option was supported by the Regulators as a preferred option for produced water management for the industry.