Abstract With the most recent down turn in the oil industry, there is an urgent need to optimize production from deepwater oil fields. Adopting a technically sound and cost-effective severe slug mitigation technique is very important. In this work, a sample deepwater oil field in West-Africa operating at over 1000m water depth, currently operating at over 150,000 bbl/d and with an oil API of 47 °, GOR of 385.91 Sm 3 / Sm 3 and a water-cut of over 10%; experienced slugging during it’s early life. This slugging scenario was modelled and subsequently fine-tuned to severe slugging by moderating the flow rates. Self-lift and Gas-lift were then separately applied to mitigate the severe slugging scenario. The results of this work highlighted that the self-lift technique proves effective for valve openings of 0.85, 0.65 and 0.35 for a 4 inch and 3 inch diameter bypass line. The gas lift technique proved effective with increased mass flow rate from 7kg/s and 12kg/s. Although both techniques mitigated the severe slug, the power consumption required by the gas lift technique for 12kg/s the best scenario proved to be huge at about 75,921,254.54 kw and at over $10,000,000 (USD) cost. This was not the case with the self-lift technique which required no external power source for its functionality.

The XK field is a mature offshore asset with post peak production characterized by rapid oil decline rate and steep water cut. Many wells have ceased flow prematurely over time and non-rig interventions to reactivate and restore the wells to production had typically been ineffective owing to consistent low tubing head pressures and well construction/completions. Furthermore, the plan to initiate gaslift operations in the field was challenged by the lack of gaslift separator, compressor unit and gas line coupled with the fact that many of the wells were completed without gaslift mandrels. The deployment of innovative inter well gaslift, utilizing Gas Liquid Cylindrical Cyclone (GLCC) separator saved the situation and enabled achievement of the gaslift objective. The result was the successful restoration of three (3) long shut-in wells and associated increased oil production in the field. This paper discusses the opportunities and challenges from inter well gaslift initiation and operations in XK field and the enormous potential as a low cost and efficient system for rejuvenating Brown Fields.

In challenging horizontal wellbores with subhydrostatic well conditions and the inherent uncertainties associated with mechanical bridge plug installation, the balanced cement plug concept becomes the appropriate method for cement packer installation. The balanced cement plug method requires creating a balanced U-tube with the hydrostatic pressure consisting of a column of brine, spacers, and cement slurry in the annulus of a tubing/drillstring equating the hydrostatic head in the drillstring/tubing and annulus. Fluid volumes are calculated, accounting for fluids both inside and outside the pipe at the given gradient/head, resulting in a hydrostatically "balanced system." Recently, this technology has been successfully deployed for cement packer design and installation using coiled tubing (CT) to place 813 ft of cement packer in the 3 1/2-in. tubing × 9 5/8-in.casing annulus from bottom of tubing punch at 5,913 to 5,100 ft MD (685 ft above shallowest perforations). The location of the production packer at a depth of 629 ft with 9.6-lbm/gal calcium chloride brine (cement accelerator) existing below the tubing punch interval in the tubing-casing annulus presents challenges with respect to the cement slumping through the brine. Detailed engineering design and execution is necessary to overcoming such inherent challenges. The zonal isolation of the existing subhydrostatic mature oil zone within the horizontal wellbore (793 ft blank liner and 1,698 ft predrilled liner) was achieved through placement of 575 ft of cement plug in the 3 1/2-in. tubing from 6,511 to 5936 ft MD. A rigless through-tubing balanced cement plug concept for cement packer installation and reperforations was deployed to access behind pipe oil reserves in a high-angle (69 to 72º) deviated well, Offshore Niger Delta. Design considerations were reviewed and precautions for placement through CT were discussed. The operation was successfully executed and the temperature log confirmed the TOC as proposed during the design phase. The HUD in the tubing was also tagged as expected with no cement U-tubing from the annulus. Post-job shut-in tubing and casing pressures, quantity of cement pumped, and flow tests have proven the success of the design and procedure implemented in challenging wellbores. The stable production post-hookup to the production line presents 212% incremental production without sand exclusion against the proposed well intervention objectives. This presents the advancement in cement packer installation in complex well trajectory with high potential of U-tubing attributed to failed retainer packer for accessing bypassed oil reserves. The balanced cement plug engineering design presents an interplay between 8.5-lbm/gal inhibited sea water, 8.33-lbm/gal spacer (drill water+surfactant), 8.5- and 9.7-lbm/gal brine, 15.8-lbm/gal neat cement slurry above the 9.6-lbm/gal existing completion calcium chloride brine, and pressures in the casing/tubing annulus and tubing to balance the fluid without a retainer packer.

A major cause of increase in the number of well abandonments in small heterogenous formations with high geological complexities is early water breakthrough into completions which leaves pockets of bypassed oil that ultimately affects the overall recovery from such formations. This paper highlights some reservoir management strategies adopted to improve reserves from a Niger Delta formation with an API of 22 Deg. Reservoir management strategies adopted included the use of down hole gauges, inflow control devices, and detailed production/injection surveillance. Updated 3D simulation model and material balance analysis were also used for evaluation of waterflood recovery efficiency and real time Reservoir management decisions. Other Reservoir management practice helped in stimulating gas cap expansion that increased daily oil rate from this reservoir and field gas rate that helped in gas lifting wells in other heavy oil reservoirs with high BSW.

The installation of dummy valves with the initial well completion for gas lifting wells has been a popular practise in the industry. These dummy valves provide a barrier between the annulus and the tubing during the well completion phase to the test the tubing and annulus independently after the well is flanged up. These dummy valves are later changed out for live valves in preparation for lift gas injection when the reservoir energy becomes too low for the wells to flow or when the desired production rate is greater than the reservoir energy can deliver due to water production. Whereas this completion method has endured, it has escalated the clean-up cost, and maintenance cost of these wells because the intervention operations for gas lift changeout are often time consuming and costly. To minimise the above costs due to the installation of these dummy valves during the initial completion phase, Addax Petroleum Development Company adopted the use of live valves during the initial completion. After completing the well with brine, it requires to be underbalanced to unload the brine and clean out before producing to the sales line. For under saturated reservoirs and depleted reservoirs, coil tubing with Nitrogen injection had been used to initiate the underbalance for the well clean up because of its low density and high-pressure characteristics. Today to further reduce the well clean-up cost, Addax Petroleum Development Company now pumps Nitrogen or lift gas through the casing-tubing annulus and the live gas lift valves to under balance and off load the well. Also, with the introduction of live gas lift valve installation, the cost of the dummy valve changeout, with consequent production deferment during the intervention process has been eliminated. This paper highlights the benefits Addax Petroleum Development Company has derived from the installation of live gas lift valves with the initial completion by reducing the completion and clean-up cost in each well completed, and the consequent elimination of well intervention cost for a gas lift changeout.

Wax precipitation along oil well tubing causes deferment in production while being produced from the formation through production facilities. Existing formulations for inhibiting wax formation include, chemical injection at different dosages and depths, mechanical inhibiting forms and thermal methods used in overcoming wax formation temperature. A well in one of the Niger Delta offshore field suffered down hole wax deposition after each field shut down. A triplex pump which serves six fields was used to provide a remedial solution after an average well downtime of seven days. In order to control this challenge, crude oil pour point was determined from historical production and temperature profiles and a hot reservoir fluid circulation strategy was developed with the objective of optimizing production through reduced well downtime and minimized expenditures. The technique used shall be discussed in this work. This formulated strategy saved over a five million US dollar per annum.

Managed by a joint operating team tagged the Asset Management Team (AMT), the OML 26 Asset has undergone a total transformation in all ramifications of the oil and gas operations. Within the space of three years, the Asset has recorded a 122% cumulative annual growth (CAGR) for reserve base increase, a 43% CAGR in production rate increase without drilling new wells, and a 38% CAGR in total production offtake. The direct unit operating cost also improved significantly averaging 31% year on year improvement. From Q4 of 2018, the Asset witnessed breakthrough performance attaining a peak production of ca 18,000 bopd in 2019 from existing drainage points. The rate is the highest rate ever recorded in the long history of the Asset. This is an excellent achievement for a mid-sized E&P company. This paper aims to share the techniques deployed to attain such a sterling production boost in a 45-year-old field.

Mature fields typically require a considerable amount of attention and manpower to keep their production going. Typical daily operational challenges include identifying wells that quit, reactivating such wells and gathering wellhead/casing pressure data that are used for well integrity, surveillance and optimization studies. These challenges are further compounded for mature assets that have a significant number of wells spread across wide geographical areas, leading to a never-ending cycle of data gathering while reactively chasing wells that have quit to minimize lost-production opportunities (LPO). One way to manage these challenges is to install sensors that leverage on the Industrial Internet of Things (IIoT) on wells to achieve remote well monitoring. The sensors are used to monitor critical well parameters (pressures, temperatures) remotely, thereby reducing Opex incurred via helicopter trips to diagnose well problems. The solution was also configured to report shut-in wells via email/texts helping to narrow down the culprit well, reduce reaction time and minimize LPO. More value can be derived beyond gathering surveillance data and reducing LPO reaction time. The data can be delivered real-time to the Asset Engineers in the office to drive engineering analysis on wells. Such analysis could lead to proactive solutions such as optimizing wells that are already on gas-lift or quicker decision-making to initiate gas-lift on a well just before it quits. In this paper we demonstrate the value that was created by implementing remote well monitoring in mature fields using case-studies that capture the daily field operational challenges and how they were resolved leading to significant cost savings.

This paper evaluates the profitability of developing a Nigerian marginal oil field in a low oil price environment. The undeveloped asset is located offshore, and remains undeveloped due to field size and remote location. Recent seismic interpretation suggested that the field could be larger than previous estimates, and this triggered re-evaluation for development. Subsurface and economic assessments were completed to evaluate the profitability of developing the field, and the NPV, profit to investment ratio, DCFR, payback period, and breakeven oil price indicators are presented. The base case development scenario was unattractive, and additional sensitivities were completed to transform the marginal field into an attractive investment. The paper presents standard working practices used to evaluate the profitability of petroleum upstream assets. It also shows why economics is the bottom line of petroleum assets, recommends guidelines for selecting upstream investment projects and participating in petroleum licensing bid rounds, and illustrates how hydraulic fracturing has transformed low permeability oil fields in the USA into economic projects.

Gas lifted oil wells contributed substantially worldwide during the production life of the oil reservoir. The intermittent gas lift optimization process leads to an overall reduction of OPEX and increases the NPV from the asset. When the reservoir pressure is insufficient to produce the desired rate, consequently the oil well productivity declines and the percentage of water cut increases. The well level optimization is one of the practical strategies employs to optimize well parameters especially surface injection pressure of intermittent gas lift. A sensitivity study was implemented on surface injection pressure using IPM Prosper. Gas lifted oil rates were analyzed at several surface injection pressures from 1000-5400psi. The optimum surface injection pressure of 1300psi at an oil rate of 140 STB/day was achieved with 6 injection valves (4 operating valves and 2 safety valves) at a depth of total valves of 7316ft producing 80% water cut.

New Technology implementation brings intrinsic value to well delivery projects with enhanced capabilities for exploitation of hydrocarbon reserves. However, the planning of wells with new technology applications, especially in remote operating locations, comes with unique challenges of compatibility of existing equipment and unavailability of equipment required for the new technology system's deployment. This paper presents a case study of an engineered approach to equipment modification and retrofitting of wellhead equipment to achieve the required compatibility with a new technology solution identified for a well as a pilot. The limiting conditions encountered in the new technology implementation as presented in the case study are discussed together with the analysis of available concepts to resolve the ensuing gaps and the engineering design of the retrofit solution. The approach not only resulted in significant cost savings but has attendant value creation benefits. The methodology and thought process presented can be deployed to solve challenges that engineers are confronted with while planning, especially with new technology applications in remote operating environments as was used by OML 26 Asset in the installation of the first ESP artificial lift in the Ogini field.

The changing landscape of global energy and fluctuations in commodity prices have driven companies to get more efficient means to sustain their businesses. With companies seeking more from their assets via rigless interventions, the trend has been that the low-hanging opportunities have been executed. The opportunities left are either too complex for rigless interventions or the expected production is too small to make major-rig workovers economic. We discuss such complex opportunities that were revisited to ensure sustained production from mature fields. The first case study discusses a gas-lift opportunity that was suspended when tubing leaks were discovered. The three holes posed a challenge since they were quite shallow and not suitable to be used as the injection-point of the gas. The work-around was to use a tubing patch to cover the holes without significantly reducing tubing ID as much as a pack-off would to allow for future well re-entry. The second case study discusses a well with a tubing restriction that prevented perforation addition. The job stalled when a gauge cutter (similar OD as the available gun) barely passed through the restriction during a dummy run. Even if the gun passed through and was detonated, the expended gun would be swollen and irretrievable due to the restriction. A modified perforating gun that disintegrated upon detonation was used, eliminating the need to retrieve the expended gun. The third case study was a well completed with mud five decades ago. The mud had caked; preventing any chance of executing a poor boy gas lift. The solution was to adapt the cement-bond-log technique to identify regions of moveable mud in the annulus with the mud subsequently displaced out by pumping. The lesson learned is that opportunities that have stalled due to their complexity can still be executed via rigless workovers by leveraging on existing technologies with slight adaptations to create well-specific solutions.

Liquid loading in gas well has been an interest in the Oil and Gas sector due to the reduction of ultimate recovery and also the reduction of production from such wells. Several authors have presented various models for predicting the beginning of liquid loading in a gas well, yet there are regular errors in the model outcomes. Turner et al. based his critical model on a presumption that liquid droplet is spherical and stays that way throughout the wellbore. Li’s model developed later on based on his postulation that droplets are flat in shape and stays that way throughout the wellbore. In reality, when producing in a gas well, under pressure variation, the liquid droplets alternate between sphere-shape and flat shape. Hence there is a need to incorporate the liquid droplet deformation coefficient in the liquid loading governing equation. The newly presented model considered deformation coefficient to justify irregular changes in liquid droplet due to pressure variation during the simultaneous flow of gas and liquid droplet in gas wells, therefore, predict the critical flowrate correctly as the droplet fluctuates between spherical and flat shape. The results from the newly developed model of the critical flowrate using test data provided by Coleman et al. show that the modified critical flowrate is closer to the test flow rate than the other existing models as the error obtained is -9.12688%.

With the most recent down turn in the oil industry, there is an urgent need to optimize production from deepwater oil fields. Adopting a technically sound and cost-effective severe slug mitigation technique is very important. In this work, a sample deepwater oil field in West-Africa operating at over 1000m water depth, currently operating at over 150,000 bbl/d and with an oil API of 47 °, GOR of 385.91 Sm 3 / Sm 3 and a water-cut of over 10%; experienced slugging during it’s early life. This slugging scenario was modelled and subsequently fine-tuned to severe slugging by moderating the flow rates. Self-lift and Gas-lift were then separately applied to mitigate the severe slugging scenario. The results of this work highlighted that the self-lift technique proves effective for valve openings of 0.85, 0.65 and 0.35 for a 4 inch and 3 inch diameter bypass line. The gas lift technique proved effective with increased mass flow rate from 7kg/s and 12kg/s. Although both techniques mitigated the severe slug, the power consumption required by the gas lift technique for 12kg/s the best scenario proved to be huge at about 75,921,254.54 kw and at over $10,000,000 (USD) cost. This was not the case with the self-lift technique which required no external power source for its functionality.

Production wells normally experience different phases of life, starting with the initial ramp-up phase after drilling and completion, through the plateau period and finally to the decline phase. The tail-end of the decline phase often present with intermittent production behaviors requiring ‘tender-loving care’ to maximize production performance. Wells normally quit in this phase of production and may require a period of pressure build-up before being re-opened to production. Primary reason for this behavior is increase in watercut or decrease in reservoir pressure or a combination of both. Typically, intervention actions on intermittent wells are based on initiation of artificial lift, water shut-off or production in a cyclic manner if there is no scope for these. The typical production cycle of a cyclic well goes from normal production through unstable production (fluctuating wellhead pressures) to eventually quitting. Whereas every naturally producing well eventually quits, paying close attention to operating conditions of cyclic wells can enhance their availability and unlock significant production volumes for the asset. SPDC, a Joint Venture Organization in Nigeria with oil and gas wells spread across the Niger Delta, has about 64 intermittent producers; 54 oil wells and 10 gas wells. These producers are approaching the tail-end of their lives and therefore produce in a cyclic manner-with uptime and downtime cycles. Driven by the desire to improve integrated production system capacity (IPSC), there has been a renewed focus on this category of wells towards improving their uptimes. An approach deployed to improve the uptime (availability) of these wells involved the optimization of well operating envelopes. This implied moving the operating points of the wells to the stable region of inflow/outflow performance curves after challenging the basis for the current operating envelopes. This led to the adjustment of choke sizes, increase/decrease of gaslift injection rates and relocation of chokes from wellhead to the manifold. Five pilot wells were selected for this project with operating envelope reviews carried out and adjusted based on detailed well performance analysis. The result is cumulative average uptime of 256 days versus historical cumulative average of 91 days (more than 100% improvement in uptime) for the 5 wells. The production gains achieved within a period of 3 months was over 50,000 bbls at no extra operating cost and no additional technical risk.

Maple Field was discovered in 1965 and started production in 1968. Peak production was attained in 1979 but has since been declining due to various factors such as funding challenges, ageing infrastructure, pending waterflood for reservoir pressure maintenance and inadequate artificial lift sources which constitutes a significant challenge with many wells "pre-maturely" quitting production on low tubing head pressure (LTHP) as water cut increases and reservoir pressure declines. The main source of artificial lift in Maple Field and other Chevron JV Fields is "Gas Lift". The Gas Lift capability in the Maple field is essentially based on an unconventional approach of using highly pressured wells with high gas to oil ratio (GOR) to serve as "gas source" wells to gas lift producing wells that have vertical lift performance challenges. It should be noted that this methodology constitutes a "fortuitous" scenario at best given that the gas source wells were not initially planned for such purposes but were producers that experienced early gas breakthrough or gas coning and were later converted to "gas source" wells. This has proven to be a workable solution but inadequate in meeting the overall gas lift demand for the Field largely due to the limited number of highly pressured/ high GOR wells and the usually low volume of gas that they produce. Other challenges to this system include the hydrated nature of the gas injected as the injected gas is essentially untreated off water and tend to reduce the gas lift efficiency. The alternative option of installing a conventional gas lift network system with associated surface equipment such as compressors and dehydration units has proven to be economically challenged due to the huge investment required for the installation and running of such systems when compared to the expected "prize" of marginal reserves development from a matured asset as the Maple Field. These issues provided both a challenge and an opportunity for the Maple Field project team consisting of both subsurface & facilities engineers to come up with cost effective and pragmatic solutions that is geared towards providing a more sustainable and adequate gas supply for the Field for gas lifting purposes. These efforts resulted in the production increase of ~ 2,000 BOPD in the Field.

Production sustainability from oil and gas wells could be an uphill task when there is a need to constantly monitor Subsurface safety valves for optimal functionality. It's always a standard practice that surface safety valves are tested on specific periods safe enough to ensure well's safety is not compromised. Surface controlled subsurface safety valves are also tested with same objective. Many Production Engineers are ignorant of the fact that the subsurface safety valve affect well productivity through drop in hydrostatic pressure across valve for Surface Controlled Subsurface Safety Valve (SCSSV) and the Sub-Surface Controlled Subsurface Safety Valves (SSCSV) additionally causes drop in fluid flow across valves in the process of sensing fluid velocity across valve. In this Paper, A case by case analysis was performed on the various sub-surface safety valves for producing wells with the view of minimizing friction to flow of well fluids which affects performance which in turn minimizes production restriction. Efficiency of different type of subsurface safety valves where evaluated and compared and business cases where made on the most attractive option. Periodic testing or inspection of valves was analyzed, and best routine testing time proffered with reasons to wells performance. The advantages and disadvantage of different valve options were also discussed to recommend a workable valve option for Uninterrupted well flow. Flow assurance and flow stability considerations were also made to ensure no unwanted valve closure occurs. A Stable and uninterrupted production was realized for five wells using this analytical method and the total productivity increase was about 1,200 BOPD for the five wells. Addressed wax blockage valve/sticky flapper problems to enable the SCSSV four wells function. The SSCSV of the last well caused flow assurance challenges which was addressed by surface choke bean optimization.

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.

Gas lift is one of the most common and economical methods of artificial lift deployed in mature oil fields in the Niger Delta. Availability of lift gas on the oil production jacket or platform is a critical enabler for gas lift initiation. Most mature fields do not have the luxury of gas lift supply on its jackets either because gas flowlines were not laid at inception or the gas flowlines are out-of-service due to integrity issues. Jacket X had four active oil well streams producing on natural flow at inception. In early 2017, these wells stopped production one after the other due to low tubing head pressure (LTHP) because of increasing watercut and declining reservoir pressure. The wells were producing at a combined rate of over 1,000 barrels of oil per day (BOPD) prior to stopping production. Well diagnostic and preliminary Nodal Analysis revealed the need to place the wells on gas lift to improve the vertical lift performance. However, this could not be executed as jacket X was not on the field gas lift flowline network. Without conventional lift gas on Jacket X, it was imperative to source for the most economic means of getting gas on the jacket. This paper highlights the processes and methodology of sourcing lift gas through an existing idle wellbore. During the bi-anual field review, the team of Operations personnel, Facilities Engineering and Asset Management reviewed and mapped out low cost strategy to restore production of the shut-in wells. Since most of these wells stopped production due to LTHP, improving vertical lift performance became the critical success factor. To address this issue economically, the asset team developed an ingenious method of sourcing the required lift gas on the same Jacket X through rigless well intervention on one of the existing idle wellbores. The innovative approach deployed involved identification of gas bearing reservoir in one of the idle wellbores, cement squeeze operations to provide zonal isolation, oriented perforation of identified gas reservoir, topside modification of existing wellhead configuration and eventual supply of lift gas to the casing of the shut-in wells. Utilizing the lift gas, the wells were placed on gas lift with 1,100 barrels of oil and 3.5 MMScfd of gas restored to production. Significant cost savings were realized during the execution of this project through the application of rigless interventions which eliminated the requirement of laying new flowlines to deliver required lift gas to Jacket X. Finally, this paper will share some of the challenges, lesson learned, and best practices adopted while executing this project.

Gas injection is used as an improved recovery mechanism to provide reservoir pressure maintenance, oil swelling and sweeping. This mechanism offers a high microscopic recovery comparing to water injection thanks to a lower residual oil saturation to gas. However, its macroscopic recovery tends in general to be smaller due to a lower sweep efficiency - a direct consequence of high gas to oil mobility ratio. The case of Akpo Z represents a success story where gas injection led to a significant increase in the condensate ultimate recovery higher than 70%, as a result of the combination of both high microscopic and macroscopic recoveries. Akpo Z is a light condensate-bearing turbidite reservoir deep offshore Nigeria and has been developed using two gas injectors located at the crest of the structure with four oil producers at the flanks. The key success factors of gas injection in Akpo Z are linked both to a favorable subsurface environment, in particular, a large structure, good horizontal connectivity and a near critical light fluid, but also to appropriate reservoir development choices. These elements are detailed in this paper. This paper also shows the challenges linked to daily reservoir management and monitoring from an operator point of view, in particular, the impact of gas injection availability on condensate production shortfalls and the uncertainties linked to gas production and injection metering. Throughout the field life, several monitoring tools such as Intelligent Well Completion (IWC) and 4D seismic have been leveraged to take appropriate reservoir management decisions that led to a delay in gas and water breakthrough and sustain field condensate potential.