Kasymkhankyzy Aкerke

Master of the Kazakh-British Technical University

ANALYSIS OF NEW IMPROVEMENT METHODS IN ENHANCEMENT OIL RECOVERY

Kazakh-British Technical University, Almaty, Kazakhstan

Review

This given scientific article is devoted to a new methods of oil discoveries on the oil fields also the author touched the aspect of enhanced oil recovery. You can find the information regarding to description of a new methods of oil recovery.

Improved Oil Recovery methods encompass Enhanced Oil Recovery methods as well as new drilling and well technologies, intelligent reservoir management and control, advanced reservoir monitoring techniques and the application of different enhancements of primary and secondary recovery processes. Chemical and thermal EOR projects have been used for a long time. (Figure 1) With the decline in oil discoveries during the last decades it is believed that EOR technologies will play a key role to meet the energy demand in years to come.

Figure1. Evolution of EOR projects

One of the new approved methods of EOR, termed ASPaM, has been developed and applied to a sector simulation using some of the data from the South Slattery Field, Minnelusa A reservoir. The new method, termed ASPaM, combines features of CO₂ miscible flooding with Alkaline – Surfactant – Polymer (ASP) flooding to produce an enhanced WAG flood. A numerical pre – processor program had to be developed to produce the required mixing zone properties of a CO₂ front, which are input to the CMG simulator, STARS. STARS is a chemical flood simulator, but cannot accommodate the solvent model. The pre – processor calculates oil and solvent properties based on the Todd – Longstaff procedure. Sensitivity analysis showed this new method can give a much better recovery in comparison to ASP or CO₂ WAG flooding for different depositional environments. Carbon dioxide has been used for enhanced oil recovery purposes since the 1950`s. Research on the use of CO<sub>2</sub> for EOR continues with ever growing interest; however, research concerning terrestrial sequestration of CO<sub>2</sub> for environment purposes is relatively recent . The CO<sub>2</sub> can make up multi – contact and first contact miscibility with oil at reasonable reservoir pressures while other miscible gases may not reach this point for up to a couple of thousand psi more. WAG injection has been applied with success in most field trials. The majority of the fields that have been WAG flooded, are located in Canada and the U. S., but there are also some fields in the former USSR. WaG injection has been employed since the 1960`s. Both miscible and immiscible injection have been used with many type of gas . The terminology of miscible WAG, here, means the gas/oil miscibility may be attained by multiple – contact.

However, the WAG mobility control is not feasible in high or medium viscosity oil; but it can be upgraded by using polymer to raise the aqueous phase viscosity. Moreover the microscopic seep efficiency of the water slug can be improved, if the interfacial tension(IFT) of the water/oil interface is reduced. Atkaline-Surfactants are typical additives offering considerable IFT reduction and consequently oil recovery improvement. The alkali converts naphthalic acids in the crude oil to soaps. The combination of the soaps and a suitably chosen injected surfactant reduced the interfacial tension to ultra low values, where residual oil can be mobilized and oil trapping prevented and it also reduces surfactant adsorption. Soaps are usually too lipophilic to produce ultra low interfacial tension at reservoir conditions. Effective, hydrophilic, injected surfactants can be injected in an alkaline-surfactant process at salinities below their optimal salinities for oil recovery when used absence of alkali.

This is investigated in application to the South Slattery Field in Wyoming, which has been previously studied by Sheppy (1986), Towler (1991) and Gao and Towler (2009).The South Slattery Field is a small Minnelusa field in the Poweder River Basin with about 12 MMSTB oil in place. Different chemical flooding scenarios have been investigated in addition to the new methodology, ASP alternating with miscible CO₂ (ASPaM) to improve recovery. Simulation of a sector of the field was carried out using STARS, the advanced chemical flood simulator from CMG. The historical water flood data has been matched and a chemical flood model was investigated, which included accounting for chemical adsorption, the residual resistance factor, surface tension as a function of the chemical concentration and interpolation of relative permeability based on capillary number and solvent concentration. Theoretically, the South Slattery Field contains all of the conditions that CO₂ flooding needs; depth, temperature, oil gravity, porosity, permeability, etc. A continues CO₂ injection was used for comparison in the simulation research. The existence of a density difference causes the CO₂ to distribute unevenly. The CO₂ flooding is a well recognized and tested enhanced oil recovery method because the microscopic sweep efficiency of CO₂ flooding is very high. The CO₂ dissolves easily in oil and reduces the oil viscosity, swells the oil and extracts the light components.

Simulation

The advanced process chemical flood simulator, STARS, was used to simulate the different chemical scenarios. STARS has the ability to simulate all aspects of ASP flooding but it cannot handle the miscible phase. No commercial simulator can accommodate both ASP and miscible flooding. Consequently we calculated the oil and solvent properties separately using the Tod and Longstaff (1972) method described below. The following features were applied to simulate the required fluid-fluid and fluid-rock interactions:

· IFT reduction for up to two components.

· Modification of the relative permeability from in capillary number.

· Water viscosity increased by adding polymer.

· Adsorption of chemical components.

· Residual resistance factor due to adsorption.

· Alteration of oil relative permeability owing to miscible flooding.

· Oil density reduction due to swelling.

· Reduction of oil viscosity by dissolution of CO₂ in oil.

· Alkaline consumption by carbonic acid.

A key feature in the modeling by STARS is: it interpolates different sets of relative permeability curves based on capillary calculated by:

Where N_ca is the capillary number is the velocity of the fluid is viscosity is IFT between oleic and aqueous phases.

The injection of chemicals which decrease the IFT, increase the capillary number, which translates into a change in relative permeability and a reduction in the residual oil saturation.

Here, eight components have been used to properly model the complex IFT change, chemical adsorption, miscible and dissolution phenomenons. The multiple alkaline consumption reactions such as; formation brain, cation exchange, hydrogen ion exchange reaction with petroleum acids, silica dissolution and kaolinite transformation are lumped to the adsorption of alkaline to the rock, except for the reaction with the carbonic acid. This helps us to keep accuracy, reduces simulation time and numerical failure. The liquid-gas k-value tables were not required for dead oil but are necessary for dissolution of carbon dioxide in aqueous solutions containing Na, Ka, Ca, Mg, Cl and SO in a wide temperature, pressure and ionic strength range.

He offered an equation to calculate as a function of temperature and pressure.

Table 1 lists the parameters for equation 3. The dissolution of carbon dioxide is simulated in an authors’ program which produces an adequate feed for STARS.

In addition, the value of the adsorption of polymer, alkaline, surfactant, accessible pore volume and residual resistance factor were considered in the simulations. The relative permeability shirts from purely immiscible to miscible as the capillary number changes from Log=6 to 0,5.

The miscible displacement was modeled in a separate program which produced the mixing zone data for application in STARS and compares the result of this adapted STARS model with a miscible simulator to make sure the required accuracy is achieved. The Todd and Longstaff miscible model was used to calculate the four component version of miscible displacement, which has already been proved for linear and radial displacement.

The following equations show how the miscible zone properties were calculated. The relative perm abilities of the miscible oil and gas might be determined as follows:

One of the interesting features of ASPaM is that ASP and CO₂ have a positive coupling effect on each others displacement, especially the injectivity. However this positive effect has not yet been formulated and can not be implemented in this simulation. The carbon dioxide also has a positive effect on ASP flooding. However, even in our simulation experiment, the infectivity in the linear pattern was raised 14 times, due to some of the effects listed above. Figure 2 shows the water breakthrough can be postponed by more than 8% pore volume water injection by the use of a 4% PV CO₂ slug at the front of ASP, which simply impies a piston like up to 55% for a 11% CO₂ slug.

Numerous simulations have been done to compare different EOR mechanisms: WAG, CO₂, ASP,WF (water flooding) and PASP (pure ASP flooding, no chase water) flooding against ASPaM for different depositional environments. The sequence in ASPaM is 10% ASP chased by water, preceded by a 10% CO₂ slug size and finally followed by continuous CO₂ injection. While in the WAG that 10% ASP slug is substituted by water. The first depositional system is an isotropic and homogenous reservoir. The recovery of ASPaM is definitely more than the other schemes especially if time is considered as shown in figure 3 a-b. Moreover ASPaM displays less water cut, shown in figure 3c. Although PASP, which stands for pure ASP injection, shows better recovery but is not economically feasible as the production life is too long for the same recovery and cost of injection materials is very high.

The alkaline consumption by carbonic acid is an important issue but, since ASP and CO₂ are being injected alternatively, they don’t mix entirely and consequently the alkaline consumption and gas/liquid mass transfer is expensive. Nevertheless this complex system is simulated for a 2-D model, a diagonal of the sector model. Figure 4 reveals no considerable change in ultimate recovery may happen if the alkaline consumption were to be considered.

The recovery of ASPaM was investgated in three heterogenous systems: coarsening upward, fining upward and random-heterogeneity. The absolute permeability ratio of the overlaying stratas in the coarsening upward system is 1/2/3 while in fining upward it is 3/2/1. ASPaM in both fining upward and coarsening upward shows better recovery than ASP and CO₂ flooding alone while WAG almost has the same performance with ASPaM in the fining upward deposition. However the recovery of both is much more than the homogenouse system, figure5. The difference between the WAG and ASPaM performance increases in coarsening upward in comparison with a perfectly homogenous system and it is attributed to better micro sweep efficiency of the bottom layer in ASPaM, while in W_AG, the miscible zone, CO₂ front, is redirected to the upper layers, figure6, thus the bottom layer displacement is immiscible. In the fining upward deposition, the miscible zone of CO₂ is redirected to bottom layers and improves the recovery of WAG. Therefore the difference between them reduces.

The random heterogeneity is more complicated as the average permeability is changing with respect the path chosen by the fluid. Two faces were chosen for this system, where the low permeability faces has 7% of the high permeability faces permeability within the same porosity. The stochastic program was written to calculate the average permeability for any arbitrary pass, in addition to the average permeability in the diagonal heterogeneity is the Lohrenz coefficient. But the Lohrenz coefficient may not be the authors employed the described methodology, which is based on flow direction, and represents better effect of permeability heterogeneneity on fluid flow.

The results for ASPaM were unexpected; the recovery of ASPaM increased in these random-wise heterogeneities while the recovery of WAG reduced. Maps of the solvent saturation in the random system, reveals its saturation in the deeper layers increases, which improves the recovery. At the same time the saturation of the trapped oil in the WAG process in heterogenous systems is increased, due to the fact that it interferes with the positive effect of miscible displacement by CO₂. In fact heterogeneity has two effects; it increases the saturation of trapped oil due to local trapping of the oil phase, which is a negative effect of heterogeneity. In addition it may have a positive effect redirecting the solvent zone to the non-swept area.

Based on this vision it was expected that CO₂ flooding would give better results since less oil would be trapped by water. Figure 7 shows the recovery of ASPaM, WAG and CO₂ for the homogenous and two randomly heterogeneouse systems. The recovery by CO₂ flooding, in the heterogenous cases, shows a sudden rise after 4 PV injection and overtakes the ASPaM after 9 PV for Case-2, and for Case-1 it happens after another 3 PV of injection (12PV).

Conclusion: This EOR scheme which is a combination of the two favorable commercial schemes, ASP and CO₂ flooding, shows a significant improvement in incremental recovery. In addition it has less injectivity problem as the well has less water cut. Furthermore, heterogeneity did not affect recovery significantly and even may have a positive effect on recovery especially for a fining upward deposition and a randomly heterogeneous system.