Reservoir Model and Production Strategy of Mishrif Reservoir-Nasryia Oil Field Southern Iraq

Nasryia oil field is located about 38 Km to the north-west of Nasryia city. The field was discovered in 1975 after doing seismic by Iraqi national oil company. Mishrif formation is a carbonate rock (Limestone and Dolomite) and its thickness reach to 170m. The main reservoir is the lower Mishrif (MB) layer which has medium permeability (3.5-100) md and good porosity (10-25) %. 
Form well logging interpretation, it has been confirmed the rock type of Mishrif formation as carbonate rock. A ten meter shale layer is separating the MA from MB layer. Environmental corrections had been applied on well logs to use the corrected one in the analysis. The combination of Neutron-Density porosity has been chosen for interpretation as it is close to core porosity. Archie equation had been used to calculate water saturation using corrected porosity from shale effect and Archie parameters which are determined using Picket plot. 
Using core analysis with log data lead to establish equations to estimate permeability and porosity for non-cored wells. Water saturation form Archie was used to determine the oil-water contact which is very important in oil in place calculation. PVT software was used to choose the best fit PVT correlation that describes reservoir PVT properties which will be used in reservoir and well modeling. 
Numerical software was used to generate reservoir model using all geological and petrophysical properties. Using production data to do history matching and determine the aquifer affect as weak water drive. Reservoir model calculate 6.9 MMMSTB of oil as initial oil in place, this value is very close to that measured by Chevron study on same reservoir which was 7.1 MMMSTB. [1] 
Field production strategy had been applied to predict the reservoir behavior and production rate for 34 years. The development strategy used water injection to support reservoir pressure and to improve oil recovery. The result shows that the reservoir has the ability to produce oil at apparently stable rate equal to 85 Kbbl/d, also the recovery factor is about 14%.

No.28-(9) 2020 Journal of Petroleum Research & Studies (JPRS) E55 initial oil in place, this value is very close to that measured by Chevron study on same reservoir which was 7.1 MMMSTB. [1] Field production strategy had been applied to predict the reservoir behavior and production rate for 34 years. The development strategy used water injection to support reservoir pressure and to improve oil recovery. The result shows that the reservoir has the ability to produce oil at apparently stable rate equal to 85 Kbbl/d, also the recovery factor is about 14%.

2-Introduction:
Geological Model "Static Modeling" is the first and the most important stage in the reservoir modeling process. In this step the model will be created to meet all structural, stratigraphically and petrophysical features.
The data from seismic, drilled well formation tops, well logging and cores are used to define the reservoir tops, thickness, porosity, water saturation and net to gross maps. As there is more and more data, the model structural and stratigraphically maps will be more accurate and as a result the model will be highly effective especially on original oil in place (OOIP) calculations.
The model should be fed with the required data to build the Dynamic Model with the dynamic data such as Pressure-Volume-Temperature (PVT) properties, special core analysis (SCAL), production data and pressure. At the end, the model will be initialized to calculate OOIP and if it is accepted, the model will be simulated for a certain time as a history match with actual production data to approve the dynamic performance of the model is true as actual reservoir. [2]

3-Area of Study:
Nassriya oil field is located about 38km in the North-West of Nassriya city. The field is discovered in 1975 after applying sismic technology by Iraqi National Oil Company. The field dimensions are about 34 Km long and 13 Km width in the direction of North-West to South-East, the trap is anticline. [3] Lower Mishrif is considering as the main pay zone due to its good rock properties such as: 1. Good porosity: (9-24) % for MB1 and (21-26.2) % for MB2 according to core analysis and well logs measurement.

4-Well logging Interpretation:
Well logging software (Interactive Petrophysics V3.5) was used to analysis the well logs for ten wells available in this study.

i. Environmental corrections of Well Logs
Schlumberger Environmental Corrections had been applied for used well logs as most of these well logs had been recorded by Schlumberger Co. Figure (

ii. Determination of formation Water Resistivity
From water sampling laboratory report, the concentration of pure Nacl in well NS-2 is 190788 ppm, so this NaCl value will be used as a fixed salinity for all Mishrif reservoirs.
Equation (1) is used to calculate Rw @ 75℉ which equal to 0.0455 ohm meter using NaCl in ppm. then, it is corrected to the bottom hole temperature by using equation (2). Table (1) presents Rw values for all the studied wells.

iii. Shale volume Estimation
As the shale rock is pours but it has no permeability so it will not consider as reservoir and because of that shale volume should be eliminate from total volume and reservoir thickness No.28-(9) 2020 Journal of Petroleum Research & Studies (JPRS) E59 calculation. There is more than one method to eliminate shale volume from porosity calculation but the most used one is Gamma Ray method which will be used in this study.  The measured porosity from well logging such as sonic log, density log, neutron log and neutron-density averaging log are compared with the core porosity values for cored wells. is then applied to determine the total and effective porosity which is used to calculate reservoir net pay thickness after corrects it for shale effect by using equations (3 and 4).

vi. Estimation of Archie's Parameters for Sw Calculation
Saturation of water in the reservoir could be determined using Archie's equation (5). As rock parameters depend on carbonate properties of the rock and heterogeneities of carbonate reservoir, the applying of the equation will be relatively hard. It had been noticed that the saturation of water is more effecting on Archie's parameter than the resistivity (Rt & Rw) [8]. and Table (2) shows Archie's parameters for all the studied wells.
As Mishrif reservoir is a carbonate (Limestone and Dolomite), so a and n parameter will be used to be 0.85 and 2 respectively while m parameter is normally from 1.8 to 2.5 depending on connected which is normally found in carbonate rock [9].

vii. Fluid Analysis
To calculate water saturation in Mishrif reservoir / Nassriya Oil Field, Archie equation (5) had been used in un-invaded zone by it OOIP could be determine. Another important parameter is Sxo, calculated by equation (6), is used to calculate movable hydrocarbon.
Estimation of flushed zone water saturation and then determine the ratio Sw/Sxo is very useful to identify movable hydrocarbon. No moveable hydrocarbon indication when Sw/Sxo equal to 1. An indication of movable hydrocarbon in place could be shown when Sw/Sxo is equal or less than 0.7 [10].

viii. Bulk Volume Analysis
The volume of rock porous media which filled with water is known as water bulk volume.

5-Permeability Estimation:
The accurate procedure to measure the permeability is Lab measurement by using cores from drilled wells. It was found that no all drilled wells are cored due to high cost so correlations depended on porosity measurement from wire line is used to find permeability for non-cored wells.  (7) and (8).
Porosity cut off for MB1 equal to 8.5% and for MB2 equal to 10%. An average cut-off equal to 9% porosity unit was used in CPI to determine reservoir net pay thicknesses.
Another required approach is to find relationship between porosity from cores and porosity from log as shown in Figures (9) and (10). This correlation is used to convert the log porosity of non-cored wells to its equivalent of porosity core then it used to find permeability as explain previously.

6-Oil Water Contact and Water Saturation Cut off:
OWC depth is very effective parameter on calculation of original oil in place. The water saturation which is determined from well logging for each well had been drawn with depth and an average depth 2070m was chosen to be used in reservoir model as shown in Figure   (  To find water saturation cut off, a plot between porosity and water saturation is used and depending on porosity cut off, the value of water saturation cut off could be found. Figure   (12) shows water saturation cut off of MB1 layer which is about 0.71 %. In CPI an average value of 70% water saturation was used as cut-off for both MB1 and MB2 layers to calculate net pay thickness.

7-PVT Properties:
PVT reports of four wells are available on this study. A PVT software (PVTp) was used to get all required PVT properties using the best correlation which matching the actual PVT from reports. Second step is to calculate wells' PVT properties at one reference temperature equal to 75 °C as shown in Table ( 4). Then an average of the PVT properties was used in reservoir model and well model.

8-Capillary Pressure, Relative Permeability and Rock Compressibility:
Special core analysis is taken from a previews study. Figure (18

9-Reservoir Physical Model:
Geological Model "Static Modeling" is the first and the most important stage in the reservoir modeling process. In this step the model will be created to meet all structural, stratigraphically and petrophysical features.
The data from seismic, drilled well formation tops, well logging and cores are used to define the reservoir tops, thickness, porosity, water saturation and net to gross maps. As more input data are used, the structural model and stratigraphical maps will be more accurate and it will be highly effective on model results especially on original oil in place (OOIP).
Permeability maps will be depending on both actual permeability from core data and correlations which are mainly based on log porosity for wells.
After that, the model will be fed with the dynamic measurements like PVT properties, special laboratory core analysis reports (SCAL), Production data, Pressure values and relative permeability.
At the end, the model will be initialized to calculate OOIP and if it is accepted, the model will be run for a certain time as a history match with actual production data to approve the dynamic performance of the model is true as actual reservoir.
Reservoir simulator (Rubis-KAPPA Workstation 5.20) was used to create reservoir model

10-Reservoir Grid System:
Hexagonal cell with optimal well up scaling were used to define grid system for the reservoir in this study. The Hexagonal cell is more accurate than square or rectangular cell

11-Initialization and History Matching:
Reservoir model initialization required to be fed with the required data such as PVT, Pc, Free Water Level FWL (2070m) and reference pressure (3700 psi) and Temp (75°C) at datum level of 3040m as presented in Table (5). For history matching, another data are required such as relative permeability, rock compressibility, absolute permeability and porosity. Also the vertical permeability was assumed to be 0.1 from horizontal permeability. The history matching was split into two stages; the first one was for production data (field production rate) as these data was After many run and modification on reservoir permeability, the history matching of production rate reach to accepted values and has minimum difference between the actual (measured) data and simulated data for a reservoir model. The production history match was accepted and could be dependable as shown in Figure (25). In Figure (25), the points in black circle represents a measured data in which the production rate was measured less than 24 hr, so that the rate is less than expected.
The pressure history matching results show that pressure data from simulator are very close to measured data and this with production data confirm that the reservoir model is near to actual reservoir behavior.

12-Reservoir development strategy:
Production strategy will use a production rate value equal to 85 Kbbl/d to evaluate field performance and to monitor production stabilization to the end of prediction period. As it was clear from the history matching, there is weak aquifer supporting the reservoir, so that water injection was used to support field pressure.
Seventeen wells were initially drilled until 2015, then twenty well will be added (four wells each year), therefore the total producing wells will be thirty seven wells at the end of Twenty injector wells will be added to the field started from 2015 (four wells added each year). The injection strategy was to be as line drive with the maximum injection rate and maximum bottom hole pressure equal to 10k BPD and 4500 psi respectively as the fracture pressure of Mishrif formation equal to 5000 psi.The water injection had been designed to inject water in oil zone through the middle of MB1 unit and the top part of MB2 unit.
The new drilled wells are located to cover reservoir area with about 400 meter drainage area radius for each oil producer well (about 800 meter distance from well to another) and to allow a line drive injection between oil producers and water injector wells. Figure ( The strategy results are field maximum production rate reached up to 85 Kbbl/d in 2020, then the production rate get stable for about ten years after that it started to decrease till the end of the period to amount of 65 kBPD. The water cut percent increase gradually until it reached at the end of the prediction to 33%. Field cumulative oil, cumulative water injected and recovery factor are 930 MMSTB, 1124 MMSTB and 13.5% respectively. Reservoir pressure was stable as the injection rate and production rate are nearly stable asshown in Figure (