This paper highlights efforts to eliminate wax production, by deriving a permanent flow assurance solution for a producing well and mitigate frequent downtime and expensive remediation operation. In two case studies, the efficacy of a Paraffin dispersant was compared with that of a Paraffin inhibitor, with respect to a producing well's wax formation tendencies and characteristics with the view of optimizing well performance subject to chemical injectivity. In the first case, well fluid was continuously treated with Paraffin dispersant to prevent wax deposition and subsequent blockage on the flowline but this effort proved ineffective because of periodic remediation. There was no significant performance improvement in this case. In the Paraffin inhibitor case, an appreciable increase in pressure differential across choke was observed as well as significant production increase which improved with the treatment time of the well fluid with the paraffin inhibitor. It was evident that Paraffin Inhibitor Injection was not just a flow assurance solution but also a production optimization tool. The project also saved the company about a million dollars annually, used for remediation of wax blockage on the flowline and sometimes sectional replacement of the flow line. Hence operation was a cost-effective method to achieve flow assurance and optimal production performance.
Engineering a gas field that is more than 15 years old comes with its own challenges especially when there is a need to redesign production rules to meet Management objective functions based on the current need of the Company. The basic requirement is to continually Demonstrate commitment to Nigerian environmental stewardship while optimizing every other objective functions. This paper reviews the performance of a Gas field taking into cognizance the dynamics of operational needs and challenges encountered in the daily operations and provides solution. An Integrated Production model sensitive to thermodynamic conditions was developed to interpret daily operations to Production Engineering which formed a framework to forecast future production. The model also characterizes flow in the pipe and predicts daily fluid (gas and oil) production. Additionally, the model enables investigation of Flow Assurance (hydrate formation, Pipeline Corrosion, Pipeline Erosion etc.) and integrity of subsurface safety valves to ensure uninterrupted flow. Interconversion of hydrocarbon gas to Liquid is then reviewed in the model before execution. Results from the Integrated production model were used to investigate historical events (well trips, facilities shut in etc.) and advise on how best to prevent such emergencies. Planning with this model enables striking a balance between Condensate needs versus gas production targets given the Economics of production and funds within the Environmental design. Reoccurring Flow Assurance and Well integrity challenges were flagged to be addressed and eliminated. A total gain of about 20 MMSCFD and 1,000 BPD of condensate was achieved with options to re line network arrangement to improve results.
Two reservoirs, the saturated Main area and the under-saturated Horn area, were discovered in 1965 and 1966, respectively. The original oil-water contact of the Main area is 6761 ft ss, while that of the Horn area is likely between 6994 and 7133 ft ss. Production started from both reservoirs in 1968 with almost same initial reservoir pressures, but significant pressure differences were observed when waterflood was initiated in 1991. Material balance can only be achieved with combined model of the two reservoirs and not with separate models of the Main or the Horn area. The purpose of this study is to optimize oil recovery from the Horn area reservoir by optimizing waterflood performance and/or drilling infill wells to drain the identified remaining reserves. A black-oil simulation model was used to simulate the two reservoirs in a single model. Aquifer pore volume and aquifer transmissibility for both reservoirs are uncertain along with transmissibility for the fault separating the two reservoirs. These and other uncertain parameters were studied in a systematic manner to achieve a high-quality history-match. Water cut, GOR and pressure matches were obtained by constraining simulated oil production to that of the historical. Oil net flux rate and oil cumulative net flux for each reservoir were derived from the simulation making it possible to calculate the recovery factor of each reservoir as a function of time. Also, since much of the oil has migrated over time from the Main to the Horn area, forecasts were made to evaluate future opportunities in the Horn. Material balance calculation to reduce the uncertainty range in OOWC for the Horn area was carried out. A systematic evaluation of impact of uncertain parameters like aquifer pore volume and aquifer transmissibility for the Main and Horn areas along with fault transmissibility on history-match quality was deployed.
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.
Gas lift technology involves the introduction of gas in the tubing to improve vertical lift performance and over all well productivity. However, when wax is deposited in the tubing, the pressure drop across tubing is increased and vertical lift performance is adversely impacted. This paper reviews the performance of two wells known to have wax deposition issues leading to sub-optimal production, thus necessitating intermittent paraffin inhibition /hot oiling which have associated costs. A Fluid Thermodynamics model which demonstrated that production from the two wells can be optimized by gas lifting wells at points deeper in the tubing than the nucleating points at a threshold gas lift temperature was developed. The minimum gas lift temperature at any given pressure required to attain this flow assurance solution was simulated from the model developed. The model illustrates that a thermodynamic state can be attained without the use of an inline heater. This was due to the high discharge of thermal energy from the lift gas supplied from the gas lift manifold. Results from model application to the two case study wells showed improvement of flow rates from sub-optimal values to steady rates of total increments of about 1,000 Barrels of Oil Per Day. In addition, wax deposition ceased as confirmed from the laboratory re-estimation of the Wax Appearance Temperature (WAT) of the wellbore fluids. This model application eliminated yearly remediation operations such as hot oiling operations that was in place to manage and ensure that the wells produced continually, resulting in an annual cost saving of about $30,000 per well. This Thermal inhibition method can be applied in all wax producers to eliminate or reduce wax in tubing and hence the flow line.
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