The use of engineered water (EW) nanofluid flooding in carbonates is a new enhanced oil recovery (EOR) hybrid technique that has yet to be extensively investigated. In this research, we investigated the combined effects of EW and nanofluid flooding on oil-brine-rock interactions and recovery from carbonate reservoirs at different temperatures. EW was used as dispersant for SiO2 nanoparticles (NPs), and a series of characterisation experiments were performed to determine the optimum formulations of EW and NP for injection into the porous media. The EW reduced the contact angle and changed the rock wettability from the oil-wet condition to an intermediate state at ambient temperature. However, in the presence of NPs, the contact angle was reduced further, to very low values. When the effects of temperature were considered, the wettability changed more rapidly from a hydrophobic state to a hydrophilic one. Oil displacement was studied by injection of the optimised EW, followed by an EW-nanofluid mixture. An additional recovery of 20% of the original oil in place was achieved. The temperature effects mean that these mechanisms are catalytic, and the process involves the initiation and activation of multiple mechanisms that are not activated at lower temperatures and in each standalone technique.
Nano particle-assisted engineered water is one of the newest hybrid methods of Enhanced Oil Recovery (EOR) that is gaining attention in the oil and gas industry. This is attributed to the low cost of the technique and environmental friendliness of the materials involved. Low salinity and ions adjustment of the injection brine has been reported to be very useful for improving oil production in carbonates, and application of nanoparticles (NPs) to improve oil recovery via different mechanisms such as wettability alteration, interfacial tension reduction, disjoining pressure and viscosity modification. This paper therefore investigates the combined effects of these two techniques on oil-brine-rock (OBR) interactions in carbonate reservoirs. Caspian Sea Water salinity of 13000 ppm was synthesized in the laboratory, potential determining ions such as Mg2+, Ca2+ and SO42- were adjusted to obtain the desired engineered waters used as dispersant for SiO2 nanoparticle. A series of experiments were performed ranging from zeta potential, interfacial tension, contact angle, electron scanning environmental imaging, pH analysis and particle size to determine the optimum formulation of engineered low salinity brine and nanoparticle. The salinities and concentration of NP considered in this experimental study ranges between (3,250 - 40,000) ppm and (0.05 - 0.5) wt.%, respectively. It was observed that optimum homogenization time for achieving stability of the chosen nanofluid without using stabilizer is 45 minutes. Four times sulphate and calcium ions in the engineered water reduced the contact angle from 163 to 109 and 151 to 118 degrees respectively. However, in the presence of NP, the contact angle further reduced to a very low values of 5 and 41 degrees. This confirms the combined effects of EW and that of nanofluid (NF) in altering wettability from the hydrophobicity state to hydrophilicity one that rapidly improves oil recovery in carbonate reservoir. IFT measurements were made between oil and formation brine as well as between oil and different EWs at room temperature. The Formation water has the least value of interfacial tension- 15mN/m. Four times diluted sea water spiked with four times sulphate is denoted as 4dsw4S. The zeta potential values showed dsw4S-NF to be the most stable, whereas EW-NF spiked with 4 times Mg2+ show detrimental effects on NF stability. The nanoparticles sizes were measured to be less than 50 nm. Rheological studies of the EW-NF at different temperatures (25, 40, 60 and 80 degrees Celsius) shows similar trend of Newtonian and non-Newtonian behavior at shear rate less than 100 and above 100 per seconds respectively. We conclude that spiking calcium ion and sulphate ion into the injected brine in combination with 0.1wt% NP yielded the wettability alteration in carbonate rock samples. The significant reduction in wettability is attributed to the combined effects of the active mechanisms present in the hybrid method and is considerably better than each standalone technique.
In a natural gas field development plan, determining the life of the field and deciding the best-optimized production strategy as well as meeting the economic viability are the most important considerations to sustain gas production. Development optimization can increase the net present value by maximizing the hydrocarbon recovery and reducing the operating cost. Optimizing gas condensate bearing reservoirs below dew point exhibit complexities due to the hydrocarbon condensation and many times, an in-situ oil phase may result to reduce gas well productivity. Liquid loading can be a serious problem in gas-bearing condensate wells near the end of their production life. As the pressure in the drainage area is depleted below the dew point, the condensate will start to build up and the gas velocity in the production tubing falls below the critical rate resulting in inadequate energy to lift the entire condensate hydrocarbon out of the wellbore. The condensate liquid migrates down the tubing and accumulates at the bottom of the completion, increasing the bottom hole flowing pressure, thereby, reducing the production rate. Liquid loading phenomenon can be encountered in low productivity gas condensate wells. Preventive actions need to be considered for predicting and monitoring of liquid loading issue before it becomes a serious problem in production system form a reservoir to the surface facilities. This study focuses on optimizing gas production strategy in a field development plan of gas condensate well. Sensitivity analysis was implemented on the Bara well-1 through optimizing the operating parameters such as tubing sizes, wellhead pressures, skin factors, condensate gas ratio, water gas ratio and surface chokes sizes by using Niger-Delta field data and PROSPER dynamic simulator in order to select best well model construction that promote high gas deliverability and low condensate production. The reservoir GIIP has been estimated to 370 Bscf from both geological and dynamic simulation models. From the dynamic nodal analysis result, 5.5in tubing size promotes the highest optimum gas rate and low erosional velocity based on the investigated operating conditions.
This research attempted to optimize petroleum production system of well X in Field Y in Niger Delta region of Nigeria located in Gulf of Guinea by adopting Nodal analysis technique. A non-commercial software known as Nodal Analysis Program was used for the analysis. The dataset available from offset well were used as the input parameters to the software for the selection of the most economical production string for the new well. The production system has two adjustable components: vertical tubing and nearly horizontal flowline. The flowline inclination is -3.0 degree to the horizontal. The productivity index of the well was obtained in order to know the deliverability of the well. Several combinations of the tubing and flowline have been used in the analysis of the production system. The optimal configuration of the production system components is selected by the maximum operating flow rate of 1118 stb/day. The stable operational region is determined with the assumption that the system will be stable above the flow rate corresponding to the minimum on the outflow performance relation (OPR) curve. The introduction of the gas lift into the optimal system configuration increased the operating oil rate from 1118 stb/day to production rate of approximately 1287 stb/day, but the operating oil rate decreased with higher gas injection rate to 1115 stb/day. The optimal gas injection rate is selected by highest operating oil rate. The fluctuations in the oil price did not change the selection of the optimal configuration and gas injection rate. The investigation of the flow regime in the system before and after gas lift has revealed that the effect of gas injection on the flow regime is minor, probably due to low injection rate. Disperse flow was the flow regimes investigated and established for vertical flow (tubing) before and after gas injection. While on the other hand, elongated bubble was established to be the flow regime in flowline before gas injection and slug flow after gas injection in the flowline.
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