IRANIAN JOURNAL OF PETROLEUM GEOLOGY
Year:2014 | Volume:3 | Issue:7|Papers Count:6

The giant oil and gas fields in the northern Persian Gulf correspond to reservoir intervals which comprise Surmeh and Dalan formations. The main production units in these formations are their upper carbonates with typically ooid grain stone to dolostone lithofacies. As a comparative study the petro physical characteristics of these formations were considered based on core logging, well logging and petrography of thin sections. The upper carbonate unit of the Surmeh Formation was studied in the Tabnak Field and the Dalan Formation in the South Pars Field. The average porosities were 17.15% and 8.50% for the Surmeh and Dalan reservoirs respectively. Their permeability’s were 308 md for the Surmeh and 30 md for the Dalan reservoirs. This contrast in porosity-permeability data of the studied reservoirs correspond to their depositional and diagenetic history. The high reservoir potential of the Surmeh Formation correspond to its interparticle primary porosity partly remained after partial early cementation and its intercrystalline porosity due to dolomitization. This is different in the Dalan Formation which had a different diagenetic history and its porosity mainly reduced during compactional processes during the burial as well as burial cementation. However, although the Surmeh reservoir has a higher porosity and permeability, it has a lower production yield, because of its limited source rock and migration pathways.

In order to characterize the features of facies and depositional environment conditions of the Asmari Formation in southeast flank of the Khami anticline with a thickness of 270 m has been studied. the Field and laboratory studies, led to the identification 12 microfacies (nummulitidae lepidocyclina pack estone/rode stone, corallinacea benthic foraminifera (perforate) packstone, bioclast neorotalia pack estone, ooid grain stone, bioclast grain stone, miliolid neorotalia nummulitidae pack estone, miliolid corallinacea coral float stone/grain stone, bioclast benthic foraminifera (imperforate) pack stone/grain stone, miliolid pack stone/grain stone, sandy mudstone, intraclast mudstone) that deposited in continental slope, shoal, lagoon and tidal flat. In three different salinity facies environment from 34 psu to over 50 psu in oligoophotic to euphotic environment and oligotrophy-weak mesotrophy to eutrophy conditions in a homoclinal carbonate ramp platform recognized for the Asmari Formation at this study area. Correlation of the Asmari Formation in 3 section, A water salinity environmental correlation of the Asmari Formaion from Firozabad to east and north of Gachsaran reveals that 1- during Rupelian the Asmari Formation deposited in a normal water salinity environment, 2- while normal salinity water condition prevailed in Gachsaran area during Chattian, the Fars area was under higher marine salinity environment. Higher salinity environment developed during Aquitanian and Burdigalian in Gachsaran area.

Dalan and Kangan Formations are major gas reservoirs in the Persian Gulf and surrounding area. Several supper giant gas fields has been found in the region. In this study reservoir rock types were identified and were divided into four lithostratigraphic zones: K1 to K4. Each of the four succeeding zones have been divided into different subzone.This Studies identified different facies-types on the Dalan and Kangan formation in this region.Petrophysical & Petrographycal studies indicate that the best reservoir unites are found in: Dolo-grainstones, Dolowakestones/Packstones and Grain stones.Isopach maps and Depth maps show variations in thickness and depth of different zones in this region.Depth map on top of Kangan formation shows this formation getting deeper toward north- west and south east in the Persian Gulf. Continuity of marker beds in Permian/Triassic sediment and paleontological evidence support diachroneity of these sediments.

In order to study of Cretaceous/ Paleogene (K/Pg) boundary in the Izeh zone-Chahardeh section, 100m of sediments at the top of Gurpi Formation are collected during geological sampling. These sediments mainly consist of green shale and marl of Gurpi Formation. On the basis of the identified planktonic foraminiferal assemblages, six biozones are recorded:- Plummerita hantkenoides Zone (CF1), (Late Maastricht ian)- Guembelitria cretacea Partial-range Zone (P0), (Danian)- Parvularugoglobigerina eugubina Taxon-range Zone (Pα), (Danian)- Eoglobigerina edita Partial-range Zone (P1), (Danian)- Praemurica uncinata Lowest-occurrence Zone (P2), (Danian)- Morozovella angulata Lowest-occurrence Zone (P3), (Danian-Selandian)Based on above mentioned biozones, the Cretaceous/ Paleogene (K/Pg) boundary in this section located on 79m lower than Pabdeh/Gurpi Formations boundary. The bio stratigraphic correlations based on planktonic foraminiferal zonations showed a comparison between the bio stratigraphic zones established in this study and other equivalents of the commonly used planktonic zonal scheme around the Cretaceous/ Paleogene boundary in Tethys.

Oil reservoirs are one of the important sources of energy due to which is caused by specific rock mechanical properties, the ability to maintain hydrocarbon fluids. One of the major problems that are occurred during drilling a well is instability of the wellbore. In order to prevent this difficulty its need to predict stability of the rocks by using geomechanical properties and in-situ stresses. A lack of accurate wellbore stability analysis brings many problems such as borehole washout, breakout, collapse, stuck pipes and drill bits. In the present research work the stability of an oil well located in Asmari reservoir of Ahwaz oil field was stimulated by using numerical software FLAC3D and information obtained from well log curves were evaluated and analyzed in two parts and the results were presented. Mud pressure and mud weight in outset of wellbore plastic flow and also outset of shear failure in wellbore were obtained for 7.5 meter of formation which mainly consists of limestone, marl. Well stability analysis was performed in vertical direction, minimum horizontal stress and maximum horizontal stress. Due to plastic movement and shear failure in wellbore, in first stage the mud pressure occurred is 33 and 26.4 Mpa and the second stage it reaches to 45 and 30 Mpa, respectively. It indicates that tensile failure is in direction of maximum horizontal stress and shear failure in direction of minimum horizontal stress. Subsequently, the result shows that the analysis due to the low mechanical properties of the sandstone layer indicates the maximum amount of displacement and loss. The safe mud window is small in this layer.

Nowadays because of the increase in both price and demand for fossil fuel, the unconventional resources are becoming more important in most countries. Gas shale is one of the important unconventional reserves. Gas shale is fine grain rocks, and has economic gas reserves. Gas shale formations have very low porosity and for have, economic production fracturing is essential. In this study, investigate Garue formation shales in Lorestan district (case study of Babaghir 1 well-cutting samples) as unconventional reservoir. Garue formation is consisting of alternation of black clay limestons bearing radiolar and blackbituminousshale bearing. Plankton and radiolars show deep marine basin, and microfossils show thatGarue formation age is Neocomian to Knyasyn.Geochemical data show that Garue shale formation is good quality (profit area of Toc). In addition, kerogen in Garue shale formation is type III, and show gas sources rock for Garaue shale. In addition, this data confirm deep marine facies for Garue formation. Mineralogy studies show that, Garu formation consist of the clay content less than 4% (4-3%), and the brittleness index is sutable.