Petroleum Engineering(Reservoir Engineering, Hydrocarbon Thermodynamics, Improved Oil Recovery Research Papers (original) (raw)

Nigeria is gradually advancing into the secondary stage of oil recovery, necessitating preparation for tertiary oil recovery especially enhanced oil recovery (EOR). Considering the high cost of EOR agents, it is imperative to investigate the performance of available local EOR agents against foreign agents when these agents (such as surfactants and polymers) are used in combination. Oil displacement experiments were thus conducted using foreign and local surfactant-polymer (SP) and alkaline-polymer (AP) agents on Nigerian crude and their results were compared. The experiments entailed using different percentage ratios of surfactants to polymers and alkaline to polymer. Four kinds of Alkaline were also used to displace residual oil from sand to find out what type of alkaline displaces oil better. The displacement efficiencies obtained from experimental results showed that the foreign EOR agents performed better than the local EOR agents. For the SP agents, the foreign SP displaced above 90% of both light and medium crude at about 45/55 percentage and 0/100 percentage respectively. The local SP displaced a maximum of about 35% of the light crude and 75% of medium crude at an SP ratio of about 20/80 for both cases. The use of Alkaline-Polymer results showed that the foreign agents performed better than the local agents. The maximum displacement efficiency of the foreign AP was 78.13% at a ratio of 40/60 while the maximum displacement efficiency of the local AP was 64% at a ratio of 60/40. The displacement of residual oil experiments performed using four kinds of alkaline showed that potassium hydroxide (KOH) enhances recovery better than NaOH, Na 2 CO 3 and Palm bunch ash (a local source of alkaline). It was also observed that oil displacement efficiency increased as pH value of the alkaline increased.

Geo-pressured gas reservoirs are reservoirs with high pressure gradient of about (0.5-1.0) psi/ft. The increase in pressures has been proposed by some authors to be caused by inability of excess fluids to leak-off after major tectonic events of compressional folding or rapid deposition of thick sediments in young sedimentary rocks. The limitation of the conventional method in estimating original gas in place (OGIP) in a geo-pressured gas reservoir is that the solution gas in connate water is habitually neglected in estimating the OGIP. As a result, its contribution of the total gas production is omitted in the MBE. This leads to an inaccurate estimation of OGIP and gas reserve. To eliminate this error, a new form of MBE is presented by this study. It includes the contribution of solution gas in connate water to the total gas production. A comprehensive compressibility term that includes the rock compressibility (Cf), water compressibility (Cw) and the gas solubility in water (Rsw) are introduced into the material balance equation and P/Z plots are formulated. The result of the formulation indicates a 5 -12% increase in the estimation of the OGIP as compared to some existing methods. This tells the importance of the solubility of gas in brine in the estimation of the OGIP and the importance of its inclusion in the Material Balance Equation.

- by Obielum Isaac
- •
- Geophysics, Supply Chain Management, Reservoir Engineering, Geothermal

Some studies about low salinity waterflooding (LSW) was carried out to observe the mechanisms of LSW and the response of each reservoir in a certain condition. The majority of topics about LSW are in a laboratory investigation and in a sandstone implementation. Although the benefits of LSW were reported, only a few studies discussed the LSW simulation process, especially in carbonates reservoir. Therefore, this research is deemed necessary to discuss the modeling process of LSW in carbonates reservoir for a comprehensive understanding of the simulation application. One of the primary mechanisms of LSW in carbonate is wettability alteration. The geochemistry software which is used provides the calculation of some reactions that affect the oil recovery mechanism. By developing a homogeneous cubic model with a 5-spot pattern, the simulation scenarios are arranged to compare the injection water using formation water (salinity is about 179,730 ppm) to lower salinity brine by diluting 10 and 20 times of formation water. The LSW process during 50 years improves oil recovery by about 4% higher than formation water injection. But it has the potential increasing oil recovery if we see the trend. It can be concluded that a low salinity waterflooding is an opportune method that is considered to be applied for increasing oil recovery in carbonates reservoir. Even though the process is not immediately visible because it needs time for reaction, it means the sooner LSW implemented is suggested.

- by Emad Aysha
- •
- Indonesia, Nanotechnology, Enhanced Oil Recovery, Iran

Calculate the bottom-hole flowing pressure after 4 hours by using: