The MN field is a multi$-$fault$-$block field that is located within the development block with edge and bottom water. Two main hydrocarbon$-$bearing reservoirs were encountered from bottom to top in the field area that have different characteristics for each bed. They are A and B with $34$ sub$-$layers and $2$ blocks. Characteristics of sand layers are as follows:

$(1)$ Gross thickness of sand layers ranges from $1\mathrm{.}0$ m to $67\mathrm{.}5$ m$,$ most typically from $10\mathrm{.}8$ m to $40\mathrm{.}5$ m$.$ Net thickness of sand layers ranges from $0\mathrm{.}5$ m to $36\mathrm{.}9$ m$,$ most typically from $3\mathrm{.}6$ m to $18\mathrm{.}7$ m$.$

$(2)$ Porosity of reservoir sandstone is mainly in the range of $15\mathrm{.}3\%$ to $30\mathrm{.}7\%$ Permeability ranges from $21\mathrm{.}5$ md to $839\mathrm{.}3$ md$,$ most typically from $195$ md to $250$ md$.$ According to reports of well history, there were $12$ wells drilled and $9$ producers and $3$ injectors $($including producers that were converted to injectors$)$ put into production with large well spacing $(400$m $900$m$).$ Only $5\%$ oil recovery was obtained for the whole oil field with the nature water drive. $1\mathrm{.}2$ Reservoir and Fluid Properties

$1\mathrm{.}2\mathrm{.}1$ Reservoir quality and porous structure.

For FB to FA formations, reservoir rocks are composed of fine to coarse sandstones and conglomeratic sandstones. Their characteristics are high resistivity with low SP values. Silts and very fine sandstones are not oil reservoirs in the unitized area. Most sandstone is subarkosic arenites and wackes. An aquifer on the bottom of formation B $($FB$)$ about $10$ m deep with a bottom$-$hole$-$temperature of $170\backslash$deg C$.$ The rock composition of reservoir is dominated by detrital grains, ranging from $60\%$ to $70\%.$ It accounts for about $55\%$ to $73\mathrm{.}4\%$ of rock components. Matrix in rock component accounts for $3\mathrm{.}4\%$ to $10\mathrm{.}3\%,$ it ranges from $0\%$ to $43\%.$ The others are authigenic clay cement, heavy minerals and porosity. Among of them, porosity occupies $10\mathrm{.}7\%$ to $25\%$ of rock components. It ranges from $2\%$ to $35\%.$ The variation tendency of porosity is as follows: FA$>$ FB$.$ Pores of the reservoirs are dominantly primary intergranular, locally secondary micro$-$intragranular or moldic due to partial or total dissolution of feldspar. Capillary analysis data show that the pore throat size is larger, being more than $0\mathrm{.}77\backslash$mu m when Hg saturation equals to $50\%.$ When pore throat size is more than $3\backslash$mu m$,$ it occupies about $22\mathrm{.}4\%$ to $80\%$ of all pore throats. Swi ranges from $6\mathrm{.}5\%$ to $55\mathrm{.}8\%,$ mostly in the range of $15\%$ to $35\%.1\mathrm{.}2\mathrm{.}2$ Fluid properties

Based $20$ oil samples that were collected from $10$ wells in the MN field, the reservoir

temperature ranges from $80\backslash$deg C to $102\mathrm{.}2\backslash$deg C and the reservoir pressure from $17\mathrm{.}36$ MPa to $25\mathrm{.}15$ MPa. The GOR of the reservoir oil is very low, just between $0\mathrm{.}18$ m $3/$m and $334\mathrm{.}99$ m $3/$m$3$ ; and the bubble point pressure is also very low, just between $0\mathrm{.}28$ MPa and $1\mathrm{.}51$ MPa. The oil formation volume factor $($FVF$)$ is small and distributed in the range of $1\mathrm{.}04$ to $1\mathrm{.}069.$ Very low bubble point pressure means that no gas will be released during depletion period. The lab data of fluid samples are summarized in Table $1-1.$

Field$-$wide in Block MN$-1,$ the fluid viscosity in the upper FA formation is relatively high, ranging from $12\mathrm{.}5$ mPa.s to $16\mathrm{.}2$ mPa.s$.$ In contrast, the fluid viscosity in the lower reservoirs $($A formation and B formation$)$ is relatively low, in the range of $4\mathrm{.}5$ mPa.s to $9\mathrm{.}2$ mPa.s with an average of around $5\mathrm{.}0$ mPa.s$.$ Six samples from MN field were obtained for water property tests, and mineral analysis was made for these samples. Total dissolved solids $($TDS$)$ of wells excluding water source wells vary from $1354$ mg$/$L to $2890$ mg$/$L$,$ with an average of $2021\mathrm{.}4$ mg$/$L$.$ The average content of Ca $2+$ and Mg $2+$ in the formation is about $20$ mg$/$L and $4$ mg$/$L$.$

Additionally, the component of C$5$ to C$12$ in the oil is greater than $96\%($mol based$)$ for a well next to Block MN$-2($from a laboratory report$).$ Based on EOR process screening criteria, we want to select co$2$ injection as a suitable method and the possible EOR approaches for the field. And also here are summary of PVT data for assumptions: Items

EX$-01,$EX$-01$

Layer FAA $,$FAH

Reservoir Temperature, $\backslash$deg C $78\mathrm{.}59,85\mathrm{.}45$

Initial reservoir Pressure, MPa $26\mathrm{.}07,24\mathrm{.}73$

Bubble Point Pressure, MPa $3\mathrm{.}35,0\mathrm{.}33$

GOR $($m$3/$m$3)20\mathrm{.}83,9\mathrm{.}59$

BO $($rb$/$stb$)1\mathrm{.}03,1\mathrm{.}08$

Vo at Reservoir Condition, cp $1\mathrm{.}33,2\mathrm{.}30$

Compressibility at Reservoir Condition, $(1/$MPa$)1\mathrm{.}20$E$-03,1\mathrm{.}03$E$-02$

Density of Oil g$/$cm$30\mathrm{.}81,0\mathrm{.}82$

API $43\mathrm{.}60,41\mathrm{.}48$

Gas Gravity $2\mathrm{.}30,$NA

Pour Point, $\backslash$deg C $32\mathrm{.}22,37\mathrm{.}79($Questions: calculate : $1.$ CO$2$ Compatibility $($o Assess the compatibility of the injected CO$2$ with the reservoir fluids and rock. This would typically require laboratory tests but can be estimated from the chemical composition of the oil and rock mineralogy.$)2.$Sweep Efficiency $($o Evaluate the volumetric sweep efficiency using the geometry of the reservoir, the placement of the wells, and the heterogeneity of the reservoir, which can be calculated using reservoir simulation models.$)3.$Reservoir Capacity for CO$2$ Storage$)$