Wrya Jihad Jabbar Mamaseni

Summary

This study covers two main objectives; the first one is source rock evaluation of the Chai Gara, Garagu, Sarmord and Qamchuqa formations. The second is to determine petrophysical evaluation based on well logs data to delineate the reservoir characteristics for the Garagu, Sarmord and Qamchuqa formations along Atrush-1, Shaikhan-8 and Mangesh-1 wells in the Duhok area of Northern Iraq.

Six main types of palynofacies (P.F.) were recognized within the studied formations. The palynofacies distinguished in Chia Gara Formation are palynofacies one (P.F.1) and palynofacies two (P.F.2). They are characterized by dominant amorphous organic matters (AOM), especially in palynofacies two which reaches 90% and moderate palynomorphs content ranges between 5-59%, whereas the phytoclasts have relatively low percentages (1-5%). The identified palynofacies were plotted on the Tyson ternary diagram indicated that the paleodepositional environment of the Chia Gara Formation is distal suboxic-anoxic basin (IX) to dysoxic–anoxic shelf (VII). The Garagu Formation is represented by palynofacies three (P.F.3) and palynofacies four (P.F.4). The former one is characterized by abundant palynomorph, ranging between 41-85% (comprised mainly of spores, foraminifera test lining and few dinoflagellates), while the latter palynofacies is rich in amorphous organic matter which is between 55-63%, and low (7-19%) to moderate phytoclasts content (3-35%). The paleodepotional environment of the Garagu Formation is oxic shelf (V, VIII). The Sarmord Formation is represented by palynofacies five (P.F.5), this palynofacies is characterized by high percentage of phytoclasts up to 74%, with moderate palynomorphs and amorphous organic matter ranging between 11-31%, 12-38% respectively. This facies is located in IV field on the Tyson ternary diagram, which is an indicator for shelf to basin transition. The Qamchuqa Formation is represented by palynofacies six (P.F.6), this facies is also distinguished by a high percentage of phytoclasts but higher than P.F.5, ranged from 48-85%, moderate percentage of palynomorphs content (12-43%) and low percentage of amorphous organic matter (3-15%). The Qamchuqa Formation was deposited under proximal oxic shelf.

Determining petroleum potentiality of the studied formations were based on Rock-Eval Pyrolysis and Biomarker (GC-MS) analyses. The Chia Gara Formation can be considered as a good to excellent source rock; its TOC content ranges from 1.14-8.5wt% with an average of 1.85, 3.91, and 6.94wt% in the Atrush-1, Mangesh-1 and Shaikhan-8 wells respectively. The samples of the Chia Gara Formation contain kerogen Type I-II and II indicating oil prone marine organic matter. The low oxygen index (average 20.73mg CO2/g TOC) and high hydrogen index (average 637.6mg HC/g TOC) indicate that the formation was deposited under anoxic condition. While the Garagu, Sarmord and Qamchuqa formations could not be considered as a source rock because their total organic carbon contents are less than 0.5wt% (ranges between 0.19-0.47wt%).

The extracted bitumen samples from the Chia Gara Formation have low pristane/phytane (Pr/Ph) ratios (average 0.61) and according to the percentage of C27, C28 and C29 regular sterane the formation was deposited in anoxic marine environment. Furthermore, the ratios of C29/C30, C31/C30 hopane and gammacerance index also imply marine depositional environment for this formation. The average value of the carbon preference index (CPI) is one with Tmax values more than 430 ºC (average 434.7 oC). These indicate an early mature stage-early peak of oil window for the selected samples in the Chia Gara Formation. Overall, the 20S/(20S+20R), ββ/(ββ+αα)C29 steranes and 22R/(22R+22S)C32 homohopane, with Ts/(Ts+Tm), and moretane/hopane ratios pointedout to mature organic matter and ability of the Chia Gara Formation to generate oil. The second part of this study was a petrophysical evaluation of the rocks of Qamchuqa, Sarmord and Garagu formations. The petrophysical evaluation is based on well logs data to delineate the reservoir characteristics. Neutron-density crossplot was used to determine reservoir properties of the Early Cretaceous formations. The Qamchuqa Formation in three studied wells consists of dolomite with dolomitic limestone, the average clay volume was about 10%, while the Sarmord Formation is composed of limestone and dolomitic limestone, the average clay volume in this formation is about 17%. Also the Garagu Formation consists mainly of limestone and dolomitic limestone in addition to sandstone and claystone with average clay volume 20%. Pickett plot method was used to calculate formation water resistivity (Rw), the values are 0.075, 0.065 and 0.090 ohm.m respectively in the Atrush-1, Shaikhan-8 and Mangesh-1 wells. The porosity (Ø) of the Qamchuqa Formation ranges between 3-17%, which indicates that the lower part has poor porosity, while the upper part of the formation has good porosity. The porosity value decreases toward the Sarmord Formation, especially in its lower part, it has poor porosity (0-5%), whereas this value reaches to 19% (ranges between 6-19%) in the upper part. The Garagu Formation has  good porosity, reaching 16%, while in the upper part this ratio decreases to 0-3%. Water saturation (Sw and Sxo) ranges between 8-54%, 15-73% respevtively, The majority of the hydrocarbon in the porous region of the studied formations in the Atrush-1 well is residual oil, whereas in the Shaikhan-8 and Mangesh-1 wells the porous areas are charectrized by movable hydrocarbon; in the Early Cretaceous formations at the Atrush-1 well the pay zone was  230m from 442m while at Shaikhan-8 well the recorded pay zone was 178m from 480m the rate of total thickness, while in the Mangesh-1 well only 9m pay zone was recorded from 409m.

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