Abstract Reliable gas well tests provide valuable data for production optimization and maximizing ultimate recovery of gas reserves. Poor data quality, heightened process safety risks and elevated OPEX are inherent limitations in the methods undertaken by operators to measure Condensate Gas Ratio (CGR) during Multi-Rate Tests (MRT) and routine production. This paper describes the steps undertaken by the team in BERA to overcome this challenge by utilizing the density-measuring capability of the Coriolis meter. A density-based algorithm was setup using a designed decantation procedure and encoded in the control system for real-time measurements and made available in the office domain. This technique provides improved data quality, ease of well surveillance and a long-term cost avoiding option while simultaneously increasing the flexibility and ease of executing MRTs. It eliminates the need for manual sampling with its associated process safety concerns.

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.

Abstract Flow equations are necessary for the estimation of flow rate in pipelines. Several flow equations exist and so do conventions for their application. Their range of applicability are delineated in literature such as D. W. Schroeder, Jr. and GL Noble Denton (2010) . These works record the limited range of applicability of the Weymouth Equation compared to other existing flow equations. This failing of the Weymouth Equation is most prominent in large diameter pipelines. Fully turbulent flow predominates in large diameter pipelines like trunk lines and the use of Weymouth Equation for calculation of flow rate in such scenarios results in significant discrepancies. This work extends the range of applicability of the Weymouth to fully turbulent flow regimes in large diameter pipelines. In particular, the Weymouth friction factor is corrected by introducing a term accounting for internal pipe roughness. Friction factors for different flow scenarios were calculated and plotted against the Reynolds Number and the Flow Rate to reveal the transition to fully turbulent flow regime. Python programming language was used to compute a table of friction data using both the Colebrook-White Equation and the Weymouth Friction Factor equation. A correction factor was introduced into the Weymouth friction factor that takes into consideration the variation of pipe roughness. Further, the new friction factor relationship was used to modify the existing Weymouth equation. The Modified Weymouth Equation obtained predicted well for fully turbulent flow scenarios. Compared against the Weymouth Equation, it maintained an appreciable efficiency as pipe roughness was varied from standard values obtainable with new pipelines. This study achieved its set objectives of improving the efficiency of the Weymouth Equation for large diameter pipelines. It will find application in the accurate estimation of flow rate as technologies evolve for non-intrusive determination of internal pipe roughness.

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.

Salting-out effect during CO 2 storage in deep saline aquifers can have severe consequences during carbon capture and storage operations in terms of CO 2 injectivity. The impact and physical mechanisms of salt precipitation in the vicinity of injection area is not fully clear. Core flooding experiments were conducted to investigate the effects of different brine-saturated sandstones during CO 2 injection. The reported findings are directly relevant for CO 2 sequestration operations as well as enhanced gas and oil recovery technologies (EGR, EOR). The characterisation and core analysis of the core samples to validate the petrophysical properties (Porosity, Permeability) of the core sample was carried out before core flooding using Helium Porosimetry. The brine solutions were prepared from different salts (NaCl, CaCl 2 , KCl, MgCl 2 ), which represent the salt composition of a typical deep saline aquifers. The core samples were saturated with different brine salinities (5, 10, 15, 20, 25, wt.% Salt) and core flooding process was conducted at a simulated reservoir pressure of 1500 psig, temperature of 45°C, with a constant injection rate of 3 ml/min. The salting out effect was greater in MgCl 2 and CaCl 2 as compared to monovalent salt (NaCl and KCl). Porosity decreased by 0.5% to 7% while permeability was decreased by up to 50% in all the tested scenarios. CO 2 solubility was evaluated in a pressure decay test, which in turn affects injectivity. The results from this study showed that the magnitude of CO 2 injectivity impairment is dependent on both the concentration and type of salt. The findings provide basic understanding of the different salt concentration inducing salt precipitation during CO 2 injection into core samples completely saturated with the formation brine. The insight gained in this study could be useful in designing an operating condition for CO 2 sequestration in deep saline aquifers and minimising injectivity problems.

Well placement is a critical aspect of Field development planning in order to fully understand the extent of the field to further effectively develop and drain the field. In most cases, the structure of the formation is initially unknown, in addition to other geologic and petrophysical properties that will aid in calculation of GIIP and EUR. The use of analogy alongside decline curve analysis have been great starting points to drill the first few wells while additional data are being collected to enable the use of more advanced tools like reservoir simulation for full-field development study. This paper presents a study on the production of a gas field and the contributions from seven vertical wells that had been drilled. These seven wells are designated wells p1 to p7. Wells p1, p2 and p6 are located on the anticlines, p3 and p7 are located on the front edge of the reservoir, and p4 and p5 are placed at the center between the two domes. Contour, isopach, isopermx, isopermy and isoporosity maps were used for grid generation, while other modeling software were used for reservoir simulation and visualization. Four base cases were simulated to study the effects of grid sizes and use of local grid refinement (LGR). Four additional "experimental" cases were studied to explore alternative well placement and potential benefit for horizontal and hydraulically fractured wells. The two poor performing wells (p3 & p7) were considered as good candidates for hydraulic fracturing. Unfortunately, the results were not promising as both wells showed less than 1% improvement in gas recovery and hence may not justify the investment. The use of alternative well placements scenarios for these wells resulted in about 9% incremental recovery while conversion to horizontal wells added a further 3% in recovery. This last investment will be further justified if a dual lateral is considered rather that two separate wells.

Subsurface uncertainties in reservoir characterization remains a challenge in decision making in the development phase of hydrocarbon maturation process due to geological complexity and limitations in reservoir data to provide sufficient understanding of the subsurface. This study focuses on identifying, managing, narrowing these uncertainties and generating reservoir realizations and optimum development concept consistent with available data. Hence, the objective of this study is to generate a technically feasible & economically viable development plan for X1, X2W and X2E reservoirs in KOCA field. The methodology deployed on this study is a multi-disciplinary integrated approach in a parallel setting with early focus on uncertainty identification, quantification, management and iterations amongst the team. Sensitivity analysis was used to evaluate the respective impact of the identified uncertainties on in-place and recoverable volumes and realizations were constrained by the most impacting uncertain parameters to generate a low case, base case and high case valid realizations of the subsurface. Development concepts were selected to optimize recovery using the base case realization with preliminary economic evaluations used to determine concepts economic viability. The result of this study identifies Structure, Net-to-Gross, and Permeability as the top three uncertainties with most impact on volumes. Deterministic low, base and high case GIIP volumes computed are 354Bscf, 681Bscf and 1.1Tscf, while recoveries were 261Bscf, 546Bscf and 913Bscf respectively. Deterministic low, base and high case STOIIP volumes computed are 0.4MMSTB, 1.5MMSTB and 3.4MMSTB, while recoveries were 0.1MMSTB, 0.2MMSTB, and 0.02MMSTB respectively. Optimum subsurface development concept is two vertical gas well, no horizontal well is needed to develop the thin (12ft) oil rim and finally quick look project economics revealed that the project would be economically viable even for the Low-Case outcome: NPV (10%) is $150M and VIR (10%) is 3.92.

Inflow control devices (ICD) have been used to balance flux around completions and also delay break-through of unwanted water into completions. Inflow-control devices (ICDs) were provided to curtail water production from heterogenous reservoirs with strong aquifer systems and/or supported with water injection. The model for the ICD consists of pressure-drop equations from the reservoir, through the screen, the flow conduit, the ICD nozzle, and into the production tubing, along with pressure drop through the lower-completion system. This additional pressure drop does not contribute to additional fluid inflow into the wellbore and this is seen to be an impairment to the productivity of horizontal wells. Pressure losses from horizontal wellbores which do not contribute to increased production is seen as skin and consequently, a new equation was derived to estimate skin due to ICD in horizontal completions. In this paper, a horizontal well equipped with inflow control device which was drilled in one of the off-shore fields of the Niger Delta region was used as a case study in evaluating the performance of an ICD completion. The new equation was used to estimate the skin due to ICD of this completion and the result obtained is compared with the skin obtained using pressure transient analysis and the results obtained from both approach are similar. This paper shares how the new equation was used to estimate skin due to ICD and the result comparison with that of a pressure transient analysis.

The hydrocarbon potential of the Fika shale in parts of the Bornu basin is severely constrained by extreme geothermal gradients with dire consequences on rock elastic properties and subsurface interpretations of both reservoir and source rock evaluations. This paper investigates the potency of tingeing formation temperatures with rock elastic properties by deriving, validating and characterizing geoseismo-thermal variations from six wells. Mathematical inversion principles and assumptions was used to derive new models by tingeing seismic velocity and time as the first case (T 1 ) while bulk and shear moduli was treated as the second case (T 2 ). Sagacious astute analysis of results of computed average geothermal and geoseismo-thermal gradients within the Fika shale showed some degree of convergence particularly in wells Kinasar, Krumta, Masu and Ziye when a detailed robust test of equality of means of both average gradients was investigated suggesting appreciability with seismic properties. Results of a paired sample T-test of T 1 and T 2 gave mean standard error, standard deviation, covariance, skewness and kurtosis of 0.01537, 0.03764, 0.07, -0.7 and 0.817 for T 1 and 0.85217, 2.08739, 0.07, 0.512 and -1.487 for T 2 . A revalidation of the new model with Emujakporue (2017) (T EMU ) and Ola et al. (2017) (T OLA ) showed that Emujakporue (2017) gave appreciable degrees of convergence for both geoseismo-thermal gradients due to seismic velocity and time (T GST1 ) and due to bulk and shear moduli (T GST2 ) with respect to T EMU but it was observed that T GST2 showed increasing divergence with depth. This result showed similar pattern with the computed data in the study area. Paired sample test correlation validated results of T EMU and T GST1 gave a combined correlation factor, standard deviation and standard error of mean results of 0.992, 3.41474 and 0.94708 while T EMU and TGST2 gave a combined correlation factor, standard deviation and error of mean of 0.989, 11.82514 and 3.27970. Results of covariance gave 738.833 for T EMU with T GST1 and 437.545 for T EMU with T GST2 . This means better approximations of T GST1 with T EMU than T GST2 . Results of the Pearson's correlation gave 1.0 for T EMU with T GST1 and 0.992 for T EMU with T GST2 . This means better correlation of T GST1 than T GST2 with respect to T EMU . Results of paired sample test of correlations, standard deviation and standard error of mean for Ola et al. (2017) gave 0.976, 16.51011 and 4.57908 for T OLA with respect to T GST1 while T OLA with respect to T GST2 gave 0.966, 4.64432 and 1.28810. Covariance results gave 579.301 for T OLA with T GST1 and 302.539 for T OLA with T GST2 . Results of Pearson's correlation gave 1.0 for T OLA with T GST1 and 0.988 for T OLA with T GST2 . This signifies T GST1 has a better correlation pattern than T GST2 . Conclusively, the vacillational attributes of geoseismo-thermal models due to seismic properties performed better than geoseismo-thermal models due to rock elastic properties. Comparison of the computed models showed relatively good match for T GST1 and T GST2 . This novel concept perhaps may open up new challenges on the earlier perceived geothermal gradients of the Bornu basin and similar basin in the world. Sequel to this research, the theoretical basis of this model may be investigated further to incorporate other relevant formation properties sensitive to geothermal gradients.

A hydraulic scenario was created for a 125,000 BPSD Crude Distillation Unit (CDU) by blending varying ratios of two crudes; A (33.62 API) and B (25.77 API) while investigating the product yield. The product specifications were implemented using the ASTM D86 95% volume cut point. The maximum allowable blend ratio of A and B for which the CDU process simulation converged was 78/22 vol%. Under this condition, the top and bottom section experienced weeping & weir overloading respectively while maintaining process conditions. To improve column performance, top pump around flowrate was decreased by 25% to mitigate weeping while the furnace outlet temperature was increased from 367.4° C to 370° C to decrease weir loading. This paper shows that refiners can meet the increased demand for heavy ends while keeping naphtha within limits to meet demand in downstream units. Existing columns can also utilize the Aspen Hysys Hydraulic tool for troubleshooting and plant optimization.

The correlation between the produced water cut and average water saturation around the perforation obtained from Cased-Hole Saturation Tool (CHST) measurements is evaluated in this paper. The motivation for this study is to enable significant financial savings which would accrue by the need for less CHST logging runs for effective Reservoir Fluids Management provided average water saturation can be quantified in terms of produced water cut, the water perforation coverage and the wellbore completion string parameters such as perforation thickness, and deviation angle. Average water saturation and perforation water coverage, was determined by analyzing CHST logs block by block obtained using CHST tools in two different petroleum provinces (Nigeria Joint Venture Area and North Sea Basin). For each well logged, well test data or Production Logging Tool data, wellbore deviation survey and the completion schematic were obtained. The datasets from each region were split in two categories – well shut-in for less than four months prior to CHST log measurements and wells shut-in for more than 4 months. Regression analysis was used to investigate the correlation between CHST log determined parameters and other flowing and static wellbore parameters for wells without any history of damage or complex water production mechanisms. The results obtained indicate that for wells in the Niger Delta with large perforation intervals (> 30 ft), produced water cut strongly correlates with average water saturation while for wells in the North Sea Basin with short perforation intervals (10 - 30ft) the average water saturation correlates strongly with both water cut and the perforation interval thickness. It was apparent that for the wells shut-in for periods exceeding four months no empirical relationships could be established. Heterogeneity in petrophysical property distribution and borehole reinvasion are suspected to be responsible for deviation from the correlation between produced water cut and average water saturation.

Alteration of thermodynamic equilibrium conditions, most especially, temperature, during production and transportation of crude oil could cause destabilization, precipitation, and deposition of wax. This could affect the flow properties of the crude oil including the viscosity, pour point, and may eventually cause total blockage of the flow lines. In this investigation, synthetic waxy crude oil (containing different concentrations of dissolved paraffin wax (5 – 20% wt./wt.) was doped with selected plant seed oils, namely, Castor oil, Moringa oil and Coconut oil (0 – 1.5% v/v). The efficiency of each of the additives to improve the flow properties was compared with those of commercial flow improver, Triethanolamine (TEA). In addition, similar process was modelled and simulated using HYSYS process simulator. It was found that Moringa and Castro oils show good results to improve the pour point. On the other hand, the Coconut oil was observed to have negative effect by increasing the pour point of the oil. Ultimately, experimental studies reveal the potential of the plant oil to improve the flow properties of the waxy oil, while the simulation studies confirm the potential of the plant oil to reduce wax deposition volume and thickness, viscosity, and total pressure drop.

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.

When a reservoir is bounded, well productivity is affected in the long time according to the nature of the boundary. The length of time for oil production is strongly affected by well location with respect to the boundary, whether the boundaries are single, paired and vertical or paired and inclined. It therefore becomes important that well location is guided to achieve prolong oil production. The guide may be achieved from solution to a specific flow equation describing pressure distribution. The solution prescribes rates and well location for available reservoir system properties. In this paper, dimensionless pressure derivatives of a vertical oil well are studied to search for optium well location that can guarantee satisfactory oil production without premature influence of the external boundaries. The external boundaries are sealing and are considered to be inclined. The solution to this dimensionless diffusivity equation is utilized. The derivatives are computed from the total dimensionless pressure expression summing all the image wells by superposition principle. The Python and Excel softwares were deployed to compute all the dimensionless pressures for the different well designs. Larger magnitudes of dimensionless pressure derivatives would indicate higher oil production for any well design and inclination of the sealing faults. The optimum well location from the sealing faults is inversely proportional to the inclined angles. This implies that nearer wells to faults produce optimally at a given time of production. Furthermore, the relationship between well distance and productivity has no maximum or minimum points. Therefore there is no particular optimum location distance from the faults for optimum productivity. Optimum well location for sealing boundaries depends on many factors, such as production profile, well design, faults angle, fluid type and lease size. Furthermore, it was also observed that the wellbore radius has no significant effect on the dimensionless pressure derivative, optimum well location and the optimum time of production.

Gas tolling is a business model where the owner of the tolling plant (a gas processing plant) receives raw gas from multiple suppliers, processes the gas and returns the products to the suppliers of the raw gas for a fee. This study investigates the effect of hydrocarbon commingling on the output products quantities of a conceptual gas tolling plant. The study also compared three allocation methods, namely, proportional, shrinkage factor and composition-based allocation method. In a situation where there are multiple suppliers, the raw gas composition and flowing conditions would vary considerably. In the processing plant, the gas undergoes phase change due to varying physical properties and plant operating conditions. The proportional and shrinkage factor method requires fewer measurement data but do not obey the principle of equitability in the allocation of the products streams. The composition-based allocation, which was carried out using the UniSim Design Production Allocation Utility, allocates the products streams equitably by tracking the phase changes in response to any changes in flowing conditions of the contributing sources.

The focal point of this project is to investigate and assess the potentiality of an enhanced waterflooding process by a naturally generated surfactant (Protein-Enzyme bio-surfactant). The effect of low salinity (LSW), and LSW combined with a bio-surfactant (Protein-Enzyme) in a tertiary mode flooding comparatively. A high salinity water (HS) (0.75 M) was used to flood in the secondary mode after aging the crude saturated core with an initial water saturation of 19%, a recovery of 68.15% oil initially in place (OIIP) was recovered until no further recovery. Upon flooding with a LSW (90% dilution of HS), a further incremental recovery of 11.1% OIIP was produced. Enhancing the LSW with bio-surfactant in a third flooding sequence, an additional 3.75% OIIP was recovered. Analysing the mechanism of LSW bio-surfactant with fractional flow, a high recovery of 0.583 PV (pore volumes) at breakthrough was estimated. Thus, an alteration in ionic strength (salinity) by a 90% dilution and combination of bio-surfactant, saw an incremental recovery, which indicates the potential of LSW bio-surfactant on recovery of residual oil saturation.

Key criteria such as initial skin, permeability, scaling, water quality and temperature are the typical considerations employed by most injectivity or formation damage investigations, however it is our belief that this is simply not enough. Other mechanisms and their combined or secondary effects are typically underestimated, which leads in many cases to the application of mitigation and remediation techniques, which, although initially effective, are short lived due to an inadequate understanding of the formation damage/well communication impairment mechanisms present. The cause(s) of injectivity decline may be numerous; and are frequently interlinked. This paper examines the considerations of a holistic workflow for defining the potential cause(s) of injectivity decline. Standard considerations of the workflow include physical and chemical water treatment process, water quality and its degradation between process and sand face, flow assurance, physical and chemical interactions with the sandface and near wellbore, mineralogical interactions, microbiological influences and completion architecture. Such approaches have found value in defining potential causes of injectivity decline, and appropriate remediations or mitigations throughout Sub-Saharan Africa, and Europe.

Pressure gradient (PG) is vital in the design/operation of process equipment e.g. in determining pumping requirements and has direct effect on capital and running costs. Here, we report a gas–liquid experimental study using a large diameter pipeline system. Pressure was measured at two locations of each section of the upward and downward flowing sections. PG was then determined for a wide range of superficial velocities: u sg = 0–30 m/s and u sl = 0.07–1.5 m/s. We found varying trends in pressure gradient behaviour between upward and downward flow under similar conditions: from bubbly to annular flow. We give a theoretical account due to the different physical mechanisms. PG values based on prevailing conditions and flow direction were compared. We show that the satisfactory prediction of PG is highly dependent on flow direction and limits of experimental conditions. These factors can have important implications for the design and operation of fluid pipelines in the process, nuclear and oil and gas industries.

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.